From: Higgins, Cortney [mailto:Cortney_Higgins@omb.eop.gov] 

Sent: Thursday, May 15, 2014 3:38 PM 

To: Wayland, Robertj 

Cc: Culligan, Kevin 

Subject: RE: Redline Versions of Preamble, GHG Abatement TSD Chapters 

Thank you! 

From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov] 

Sent: Thursday, May 15, 2014 3:32 PM 

To: Higgins, Cortney 

Cc: Culligan, Kevin 

Subject: Redline Versions of Preamble, GHG Abatement TSD Chapters 

Importance: High 

Cortney – 

Attached are redline-strikeout and clean versions of the preamble, and Chapters 1 and 2 of the 

GHG Abatement TSD. Please let either Kevin or me know if you have any questions/concerns. 

thanx! 

bob 

Robert J. Wayland, Ph.D. 

Leader, Energy Strategies Group 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

Mail Code D243-01 

Research Triangle Park, NC 27709 

Office: (919) 541-1045 

Cell: (919) 306-2290 

Fax: (919) 541-5450 

Email: wayland.robertj@epa.gov 

************************************* 

 DRAFT/Deliberative Document - FOIA Exempt 

************************************* 
<< Redline changes since 032814_EO12886_EGU GHG 2060-AR33 Proposal.docx >> 

<< EO12866_EGU GHG Existing Source 2060-AR33 Proposal_May 15 2014.docx >> 

<< GHG Abatement Measures - Chapter 1 05-15-2014.docx >> 

<< GHG Abatement Measures - Chapter 1 05-15-2014_clean.docx >> 

<< GHG Abatement Measures - Chapter 2 05-10-2014_InteragencyCommentsunderEO12866_ 

EPA Edits Responses_05-15-2014.docx >> 

<< GHG Abatement Measures - Chapter 2 05-10-2014_InteragencyCommentsunderEO12866_ 

EPA Edits Responses_05-15-2014_clean.docx >> 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

6560-50-P 

EO12866_GHG EGU ExistingSources 2060-AR33 Proposal_20140328 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

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

RIN 2060-AR33 

Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from 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 usefollow 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 

usefollow in developing plans to attainachieve the statespecific goals. This rule, as proposed, would set in motion 

actionswould continue progress already underway to reduce carbon 

dioxide emissions from the electric power sector in the United 

States.

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

received on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE].
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 2 of 639

Comments on the information collection request. Under the 

Paperwork Reduction Act (PRA), since the Office of Management 

and Budget (OMB) is required to make a decision concerning the 

information collection request between 30 and 60 days after 

[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. Public hearings will be held on [INSERT 

DATES HERE], at [INSERT LOCATIONS HERE]. The hearings will 

convene at [INSERT TIME] and end at [INSERT TIME]. Please 

contact [add name] at [phone#] or at xxx.xxx@epa.gov] to 

register to speak at one of the hearings. The last day to preregister in advance to speak at the hearing will be [INSERT DATE 

HERE]. Additionally, requests to speak will be taken the day of 

the hearing 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 hearing will provide interested parties the opportunity 

to present data, views or arguments concerning the proposed 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 3 of 639

action. The EPA will make every effort to accommodate all 

speakers who arrive and register. Because this hearing is 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 

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. Written comments on the proposed rule must 

be postmarked by [INSERT DATE HERE]. Commenters should notify

[ADD NAME] if they will need specific equipment, or if there are 

other special needs related to providing comments at the 

hearing. The EPA will provide equipment for commenters to show 

overhead slides or make computerized slide presentations if we 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 4 of 639

receive special requests in advance. Oral testimony will be 

limited to 5 minutes for each commenter. The EPA encourages 

commenters to provide the EPA with a copy of their oral 

testimony electronically (via email or CD) or in hard copy form. 

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 hearing to 

run either ahead of schedule or behind schedule. Information 

regarding the hearing (including information as to whether or 

not one will be held) 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: 

At the website http://www.regulations.gov: Follow the 

instructions for submitting comments. 

At the website http://www.epa.gov/oar/docket.html: Follow 

the instructions for submitting comments on the EPA Air and 

Radiation Docket website. 

Email: Send your comments by electronic mail (email) to aand-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. 

Facsimile: Fax your comments to (202) 566-9744, Attn: 

Docket ID No. EPA-HQ-OAR-2013-0602. 
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Page 5 of 639

Mail: Send your comments to the EPA Docket Center, U.S. 

EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. Please include 

a total of two copies. 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 Delivery or Courier: Deliver your comments to the EPA 

Docket Center, William Jefferson Clinton Building West, Room 

3334, 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 

Information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 
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Page 6 of 639

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 

should send a copy of the comment that does not contain the 

information claimed as CBI or otherwise protected. 
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Page 7 of 639

 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 

are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 
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Page 8 of 639

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) through the Technology Transfer Network (TTN). 

Following signature, a copy of the proposed rule will be posted 

on the TTN’s policy and guidance page for newly proposed or 

promulgated rules at the following address: 

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

FOR FURTHER INFORMATION CONTACT: [ADD CONTACTS] 

SUPPLEMENTARY INFORMATION: [INSERT TEXT, AS APPROPRIATE]

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 

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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 

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 oxidesOxides

NRC National Research Council 

NSPS New Source Performance Standard 

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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 

S&L Sargent & Lundy 

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 

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 

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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. V.Authority to Regulate Carbon Dioxide and EGUs, Affected 

Sources, and CombiningTreatment of Categories

A. A. Authority to Regulate Carbon Dioxide 

B. Authority to Regulate EGUs 

C. Affected Sources 

D. B. CombiningCombined Categories and Codification in the Code 

of Federal Regulations

VI. Building Blocks for Setting State Goals and Considerations 

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.E. Overview 

B.F. Approach 

C.G. Criteria for Approving State Plans 

D.H. State Plan Components 

E.I. Process for State Plan Submittal and Review

F.J. State Plan Considerations

G.K. Additional Factors That Can Help States Meet Their CO2

Emission Performance Goals

H.L. 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. Implications forInteractions with Other EPA Rules 

X. Impacts of the Proposed Action 

A. What are the air impacts? 

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B. Comparision of Building Block Approaches 

C. Endangered Species Act 

B.D. What are the energy impacts? 

C.E. What are the compliance costs? 

D.F. What are the economic and employment impacts? 

E.G. What are the benefits of the proposed goals? 

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 use in 

developing plans to address greenhouse gas (GHG) emissions from 

existing fossil fuel-fired electric generating units (EGUs). 

Specifically, the EPA is proposing state-specific rate-based 

goals for carbon dioxide (CO2) emissions from the power sector, 

as well as guidelines for states to use in developing plans to 
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Page 13 of 639

attain the state-specific goals. This rule, as proposed, would 

set in motion actions to lower the carbon intensity of power 

generation in the United States.In this summary, we broadly 

outline the proposal; discuss its purpose; summarize its major 

provisions, including its approach to determining goals; 

describe flexibilities available to states, including timing 

requirements both for states to submit plans and for EGUs to 

meet obligations 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. The proposal incorporates critical elements 

that reflect the information and views shared during the 

unprecedented effort that the EPA has undertaken, beginning in 

the summer of 2013, to interact directly with and solicit input 

from a wide range of states and stakeholders. This effort 

encompassed several hundred meetings across the country with 

state environmental and energy officials, public utility 

commissioners, system operators, utilities and public interest 

advocates, as well as members of the public. A great many 

participants submitted written material and data to the EPA as 

well. 

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Nationwide, by 2030, this rule would achieve CO2 emission 

reductions from the power sector of approximately 30 percent 

from CO2 emissions levels in 2005. This goal is within reach 

because innovations in the production, distribution and use of 

electricity are already making the power sector more efficient 

and sustainable while maintaining a diverse energy mix. This 

proposed rule would reinforce and continue this progress. The 

EPA projects that, in 2030, this rule will lead to meaningful 

reductions in harmful carbon pollution resulting in net climate 

and health benefits of $47 billion to $78 billion. At the same 

time coal and natural gas will remain the two dominant sources 

of electricity generation in the U.S. with each providing more 

than 30 percent of the projected generation. 

The proposed guidelines also reinforce the steps already 

being taken by states and utilities to upgrade aging electricity 

infrastructure with 21st century technologies and ensure that 

these trends continue in ways that are consistent with the longterm planning and investment processes already used in this 

sector. The proposal provides flexibility for states to build 

upon their progress in addressing GHGs and allows them to pursue 

policies to reduce carbon pollution that: 1) continue to rely on 

a diverse set of energy resources, 2) ensure electric 

reliability, 3) provide affordable electricity and, 4) recognize 
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Page 15 of 639

investments that states and power companies are already making. 

The proposal has two main elements: 1) state-specific 

goals for reductions from power plants and 2) guidelines 

for the elements needed for a state plans to be approved 

when they are submitted to the EPA for review as required 

under section 111(d). To set the state-specific 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 low 

emitting and renewable power sources, and programs that 

help homes and businesses use electricity more efficiently. 

While this proposal lays out state-specific goals, it 

does not prescribe how a state should meet those goals. The 

Clean Air Act and EPA’s implementing regulation authorize 

the EPA to set these goals, and rely on states to take the 

lead on meeting them by creating a plan that is consistent 

with the EPA’s guidelines. This approach ensures that each 

state will have the flexibility to design a program to meet 

its goal in ways that reflects its particular circumstances 

and policy objectives. Each state can do so e alone or can 

collaborate with other states on multi-state or regional 
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Page 16 of 639

plans that may provide additional opportunities for cost 

savings and flexibility. 

To facilitate the state planning process, this 

proposal lays out the components of a state plan to meet 

the goal, the latitude states have in developing compliance 

strategies, the flexibility they have in the timing for 

submittal of their plans and the flexibility states have in 

determining the schedule by which their sources must 

achieve the reductions required under state plans. 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 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 

flexible manner that accommodates a diverse range of state 

approaches. This proposal also gives states considerable 

flexibility with respect to the timeframes for plan 

development and implementation, providing up to two or 

three years for submission of final plans after the 

proposed emission rate guidelines are finalized and 
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Page 17 of 639

providing up to fifteen years for full implementation of 

all emission reduction measures. 

The EPA believes that this proposal, which employs the 

flexibilities inherent in CAA section 111(d), will provide 

states with ample opportunity to design plans that use 

innovative, cost-effective regulatory strategies and that 

take advantage of the investments already being made in 

programs and measures that lower the carbon intensity of 

the power sector and thus reduce GHG emissions that cause 

harmful climate change. 

a. Policy context and industry conditions 

This proposal is an important step toward achieving the 

emissions reductions needed to address the serious threat of 

climate change. GHG pollution threatens Americans'the health 

and welfare of the American public by leading to potentially 

rapid butand long lasting changes in our climate that can have a 

range of severe negative effects on human health and the 

environment. CO2 is the primary GHG pollutant, accounting for 

nearly three-quarters of global GHG emissions and 84over 77

percent of U.S. GHG emissions. 
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Fossil fuel-fired EGUs The President’s Climate Action Plan,1

 issued 

in June 2013, recognizes that climate change comes with farreaching 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. While much of the To accomplish this goal, President Obama issued 

a Presidential Memorandum2 directing the EPA to complete carbon 

pollution standards, regulations or guidelines, as appropriate, 

for new, modified, reconstructed and existing U.S. fleet of fossil fuel-fired 

EGUs began operations in the 20th century, advancements, innovation and changes power 

plants, and to build on state leadership to move toward a 

cleaner power sector. 

Advancements in economics ininnovative power sector 

technologies, fuel sources and production,in the availability 

 

1

 The President’s Climate Action Plan, June 2013. 

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

climateactionplan.pdf 

2

 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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and cost of low carbon fuel, and in energy efficient demand-side 

management, and energy efficiencytechnologies, as well as 

economic conditions, are leading to changes inalready changing

the way power is produced, distributed and used. The EPA 

believes that this confluence of factors in the electricity 

sector provides the basis for a rule 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 under way between now and 2030, a CAA section 111(d) 

by which states can rulemaking for CO2 emissions can inform 

current and ongoing decision making by states and utilities 

while prompting states to develop and implement plans tothat 

will reduce GHG emissions and lower the carbon intensity of the 

power sector by: 1) taking advantage of these changes, while 

ensuring a reliable supply of power at a reasonable cost; and 2) 

by mobilizing state leadership in developing any of a variety of 

sustainable . The proposed guidelines are designed to build on 

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Page 20 of 639

and reinforce progress by states and companies on a growing 

variety of sustainable strategies to reduce power sector CO2

emissions. At the same time, the EPA believes that this proposal 

provides flexibility for states to develop plans that can be 

crafted for their individual and unique circumstances and that 

can be aligned with their other environmental policy and energy 

strategies already being used by a number of States and 

companies in and economic goals. All states will have the 

flexibility to shape compliance plans as they believe 

appropriate for meeting the CO2 goals set forth in this proposal. 

proposed CO2 reduction goals. This includes states such as 

Kentucky, West Virginia and Wyoming, with long-established 

reliance on coal-fired generation, as well as states such as 

Washington and Oregon 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 AB 32, and 

Colorado’s “Clean Air, Clean Jobs Act”.

In moving forward with those actionsTo make plans to reduce 

CO2, states can rely on and extend plansprograms they may already 

have underwaycreated to continueaddress the development of their 

energy systemspower sector. Those states committed to Integrated 
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Page 21 of 639

Resource Planning (IRP) would be able to establish their CO2

reduction plans within that framework to meet the CO2 goals 

proposed here.. Similarly, states with a more deregulated power 

sector system can develop CO2 reduction plans within that 

framework. At the same time, states would also be able to 

address the economic interests of their utilities and 

ratepayers, by reducing costs and avoiding stranded asset risks 

by using the flexibilities in this proposed action: 1) to reduce 

costs and working in concertminimize stranded assets, and 2) to 

work with other states to put in place regional approaches 

reflecting theon multi-state approaches that reflect the 

regional structure of electricity operating systems already that 

exists in most parts of the country and is critical to ensuring 

a reliable supply of affordable energy. The proposed rule 

provides a broad range of compliance options for a wide and 

diverse range of companies that own and operate fossil fuelfired EGUs, including vertically integrated companies in 

regulated markets, independent power producers, rural 

cooperatives and municipally-owned utilities. 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.

b. CAA section 111(d) requirements 

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Under CAA section 111(d),)3

 state plans must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” that, taking into account the cost 

of achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated (BSER).45

 Consistent 

with CAA section 111(d), the EPA is proposing state-specific 

goals that reflect the EPA’s calculation of the emission 

reductions that a state can cost-effectively achieve through the 

application of BSERthe states can achieve through the 

application of BSER. 

 

3

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

4

 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; and the state is 

authorized to identify the standard(s) 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. 

5

 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; and the state is 

authorized to identify the standard(s) 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. 

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 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 to the affected EGUs in each state. . A CAA 

section 111(d) state plan will differ from a state 

implementation plan (SIP) for a criteria air pollutant national 

ambient air quality standard (NAAQS) in several respects, 

reflecting the significant differences between CAA sections 110 

and 111. A CAA section 110 SIP must be designed to meet a 

specific ambient air quality level -- the NAAQS for the criteria 

air pollutant -- for a particular area (not for a source 

category) within a timeframe specified in the CAA, and the 

NAAQS, in turn, is based on the current body of scientific 

evidence and, by law, does not reflect consideration of cost. A 

CAA section 111(d) state plan must be designed to meet a level 

specific to emissions from 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. 

While the EPA must establish BSER and is proposing goals 

that reflect BSER, CAA section 111(d) also provides the EPA with 
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Page 24 of 639

the flexibility to design guidelines that recognize, and can be 

tailored to, the uniqueness and complexity of the utility power 

sector and CO2 emissions and that build upon the types of 

strategies many states and companies are already using today to 

reduce emissions of GHGs. At the same time, and importantly, CAA 

section 111(d) allows the states flexibility in designing the 

measures for their state plans in response to the EPA’s 

guidelines. 

We emphasize that the purpose of the EPA’s determination of 

the BSER is simply to calculate the degree of emission 

limitation that the state plan must achieve. Each state may 

select any measure or combination of measures to achieve that 

emission limitation. States are not To determine 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. These 

measures fall into four main categories or “building blocks.” 

Overall, the BSER proposed here is based on a range of measures 

that comprise improved operations at EGUs, dispatching loweremitting EGUs and zero-emitting energy sources, and end use 

energy efficiency, all of which have been amply demonstrated via 

their current widespread use by utilities and states. 
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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 BSER or use to apply any 

one of those measures to the same degree of stringencyextent that the EPA determines 

is achievable and cost-effective. with respect to that measure. 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 BSER measure encompassed by BSER and less from another, or useit 

could choose to include measures that were not part of the EPA’s BSER determination, as long 

as the state achieves the CO2 reductions necessary to meet its goal.

This As explained in further detail in Sections VI, 

VII and VIII of this preamble sets forth the EPA’sregarding 

the agency’s determination of BSER, the EPA is offering the 

opportunity via this proposal for BSERto comment on the key 

assumptions, the methodology, and the specific data used to 

calculate the state-specific CO2 goals, and on the broad 

flexibilities provided to meet the goals and ensure states 

the necessary tools to address any distinctive 

circumstances (such as the remaining useful life of certain 

EGUs) without adjusting the underlying targets. 

This proposed rule sets forth the state goals that 

reflect BSER and guidelines for states to use in developing 

their plans. to reduce CO2 from fossil fuel-fired EGUs. The 

preamble describes the EPA’s approach to determining BSER 

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and setting state goals and lays out proposed proposed 

expectations for state plans, along with discussion of 

other and discusses options that the EPA has considered. It 

also explains the EPA’s authority to define BSER, as well 

as state goals and the states’ responsibility to develop 

and implement standards of performance consistent with 

BSER. Additional detail on various aspects of the proposal 

is included in several technical support documents (TSDs), 

which are available in the rulemaking docket. The proposal 

was substantially informed by the extensive input from 

states and a wide range of stakeholders that the EPA sought 

beginning inand has received since the summer of 2013. The 

EPA invites comment on all aspects of this proposal. 

2. Summary of the major provisions 

a. Approach 

In developing this proposed rulemaking, the EPA is 

implementing provisions of the CAA that have been in place since 

Congress first enacted the modern CAA in 1970 and that have been 

implemented pursuant to regulations promulgated in 1975 and 

followed in previous CAA section 111(d) rulemakings since then. 

These provisions ensure that, in concert with the provisions of 

CAA sections 110 and 112, new and existing major stationary 

sources address all majorsignificant air pollutants. In this 

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rulemaking, the EPA is following the regulatory requirements

that have been in place since 1975 and that the EPA has followed 

in its previous CAA section 111(d) rulemakings for the past 

almost 40 years.are harmful to public health and the 

environment. These requirements call on the EPA to develop 

emission guidelines, which include determining reflect EPA’s 

determination of BSER. In general, the , for states mustto

follow these guidelines, including adhering to their stringency 

in requiring emissionformulating compliance plans to implement 

standards of performance to achieve emissions reductions, in 

developing state plans. These requirements authorize the EPA to 

develop emission reduction goals based on the application of 

consistent with BSER to the states... 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 in the power sector.67 

 

6

 [Insert example of allowing gas clean up instead of flaring for 

landfills emission guidelines. This strategy was already being 

used before we promulgated the rule).]

7

 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), allow either of two approaches for controlling 

landfill gas – by recovering the gas as a fuel, for sale, and 

removing from the premises, or by destroying the organic content 

of the gas on the premises using a control device. Recovering 

the gas as a fuel source was a practice already being used by 

some affected sources prior to promulgation of the rulemaking. 

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The CAA, as interpreted by the courts, identifies 

theseveral factors for the EPA to consider in a BSER 

determination and, for this rulemaking, the following factors 

are key: technical feasibility, costs, size of emission 

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

implementation and further development of technology). To 

determine BSER, the EPA considered the reductions achievable 

through the two basic types of approaches to reducing measures 

that reduce CO2 emissions from existing fossil fuel-fired EGUs: 

making either by reducing the CO2 emission rate improvements at 

affected EGUs (e.g., by improving heat ratesthose units or 

switching to lower carbon fuels) and limiting emissions ofby 

reducing the fossil fuel—fired EGU category as a whole 

(e.g.,units’ CO2 emission total by shifting dispatchgeneration

from higher carbon-emitting fossil fuel-fired EGUs to lower

carbon- or zero-emitting EGUs and by employing options 

(including both low- or zero-emitting generation and demand-side 

energy efficiency strategies that provide the same services with 

less electricity). As the EPA has done in making BSER 

determinations in the past, the agency considered the types of 

strategies that states and companiesoperators are already 

employing to reduce the covered pollutant (in this case, CO2

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fired EGUs.). For this pollutant and source category, many 

states and companies are already taking action to reduce GHGs.

For example, currently 10 states have market-based GHG emission 

programs, 29 states have implemented renewable portfolio 

standards, and utilities in 48 states run demand-side energy 

efficiency programs. Many individual companies also have 

significant voluntary GHG 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 beare undertaken, in ways that accommodate 

reductions in both pollution emissions rates and total 

emissions. Specifically, electricity production, at least to 

some extent, takes place interchangeably between and among 

multiple generation facilities and different types of 

generation. , a fact that Congress, the EPA and the states have 

long since relied on in enacting or promulgating 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 (and 

the states in devising plans to meet those goals) can assess, 

assessed what combination of electricity production, or energy 

demand reduction, across generation facilities can offer the 

most cost-effective approach to achieving GHGCO2 emission 

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reductions. States, in turn, canwill 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 reduced utilization 

as a method for reducing CO2 emissions from individual existing 

EGUs, to the extent that those measures help meet the 

goalsrenewable energy standards and demand-side energy 

efficiency programs, and the proposal details how such existing 

state programs can be incorporated into state plans. 

To determine BSER for reducing CO2 emissions at 

affected EGUs, and to establish the numerical goals that 

reflect BSER, the EPA considered numerous measures that can 

and are being implemented to improve emission rates and to 

reduce or limit overallmass CO2 emissions from fossil fuelfired EGUs. These measures can be groupedencompass two 

basic approaches: 1) reducing the carbon intensity of 

certain affected EGUs by improving the efficiency of their 

operations, and 2) addressing affected EGUs’ mass emissions 

by varying their utilization levels. For purposes of 

expressing BSER as an emissions limitation, in this case in 

the form of state-level goals, we propose to group these 

measures into four main categories, or “building blocks,” 

both for formulating state goals and”., These building 

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blocks can also be used as a guide to states for 

constructing broad-based, cost-effective, long-term 

strategies to reduce CO2 emissions on the part of the 

states.. The EPA believes that the application of measures 

from each of the building blocks represents a method of can 

achieve CO2 emission reductionreductions at fossil fuelfired EGUs such that, when combined with the 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. Lowering1. Reducing the carbon intensity of 

generation at individual affected EGUs (e.g., through 

heat rate improvements);.

2. 2. Reducing emissions offrom the most 

carbon-intensive affected EGUs toin the extentamount

that this can be accomplished cost-effectively by 

shiftingresults from substituting generation to at 

those EGUs with generation from less carbon-intensive 

existing fossil fuel-firedaffected EGUs, (including 

NGCC units that are under construction;).

3. 3. Reducing emissions of carbon-emittingfrom 

affected EGUs to the extent that this can be 

accomplished cost-effectively by expandingin the 

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amount of new, lower (or no) carbon-intensitythat 

results from substituting generation; and, at those 

EGUs with expanded generating low- or zero-carbon 

generation.

4. 4. Reducing emissions of carbon-emittingfrom 

affected EGUs toin the extentamount that this can be 

accomplished cost-effectively by increasing results 

fromthe use of demand-side energy efficiency that 

reduces the amount of generation required. 

The four building blocks are described in detail in 

Sections VI and VII of this preamble. 

TheThe four building blocks are described in detail in 

Sections VI and VII of this preamble. As those sections 

explain, while the EPA found that each of the building 

blocks met the attributes of BSER, combining all four 

blocks best represents BSER because it achieves greater 

emission reductions, is more cost effective and takes 

better advantage of the wide range of measures already in 

use at the state and company level to reduce CO2 from EGUs. 

Those sections also explain how the EPA considered more 

aggressive application of measures in each block. This 

includes consideration of options in some blocks that the 

EPA determined not to represent BSER for existing sources 

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(such as the inclusion of retrofit carbon capture and 

storage or sequestration (CCS) on existing units), as well 

as consideration of more aggressive application of measures 

that the EPA determined do represent a component of BSER 

(such as more aggressive application of demand-side 

measures). While the EPA made these determinations by 

applying the BSER factors to each measure, the EPA also 

considered the impacts of combining each of the measures 

into a unified BSER. 

As part of the BSER determination, the EPA considered 

the impacts that implementation of the emission reductions 

required by the combination of the blocks would have on the 

cost of electricity and on system reliability. As the 

preamble details, the EPA believes that, both individually 

and in combination, the costs associated with the BSER we 

are proposing today are reasonable. Importantly, the 

proposed BSER, expressed as a numeric goal for each state, 

provide states with the flexibility to determine how to 

achieve the reductions (i.e., greater reductions from one 

building block and less from another) and to adjust the 

timing in which reductions are achieved, in order to 

address key issues such as cost to consumers, reliability 

and “remaining useful life.” 
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In sum, the EPA believes that the BSER for purposes of 

CAA section 111(d), as applied to the sources in the power 

sector, is a combination of measures that reduce CO2

emissions and CO2 emission rates and which reflect or 

encompass all four building blocks. A range of amounts of 

reductions can be achieved by application of each building 

block; in. In determining BSER, we have considered these 

ranges, in light of statutory factors, and we have 

identified goals that we feelbelieve best satisfy those 

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 BSER is 

consistent with strategies, actions and measures that 

companies and states are already takingundertaking 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 meaningful, costeffective, and technically feasible reductions of CO2, and 

promotes at a reasonable cost, while also promoting

technology and approaches that are important for achieving 

further reductions, all while providing the states with a 

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balance of flexibility and direction. Finally, the EPA 

believes that the inherent flexibility of the measures 

encompassed in the four building blocks reinforces the 

inherent flexibility of the current electricity system 

operations and the system’s capacity to deliver affordable 

and reliable electricity because these measures rely on the 

flexibility of the electricity system itself. 

RecognizingIn addition to proposing the four building 

blocks as the basis for BSER, the EPA is also soliciting 

comment on application of only the first two building 

blocks as BSER, while noting that application of only the 

first two building blocks achieves fewer CO2 reductions at a 

higher cost. 

The EPA recognizes that states differ in important ways, including in their mix of 

existing EGUs, and consequently thatin the policy priorities that they are pursuing. 

Consequently, opportunities to reduce EGUs’ emission rates and limit each 

EGU’s overallpreferences for reducing emissions, as reflected in each of the building 

blocks, vary across states, the EPA has applied the elements of BSER to 

the circumstances of individual states by considering statespecific data in order to determine. While the state-specific goals. 

This use that the EPA is proposing in this rule are 

based on consistent application of building blocks aligns 

witha goal setting methodology across all states, they are 

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designed to account for these key messagesdifferences. The 

state-specific CO2 reduction requirements and CO2 rate-based 

goals derived from stakeholders provided 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). 

This approach and incorporation of the measures in 

each of the building blocks reflect information provided 

and priorities expressed during the EPA’s recent, extensive 

public outreach process, notably. These ranged from the 

desirestates’ desires for flexibility and recognition of 

varying state circumstances. The state-specific approach 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 

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 

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relevant to its specific circumstances and policy 

preferences. They may also identify technologies and/or 

strategies that are not explicitly spelled outmentioned in 

any of the four building blocks and may use those 

technologies and/or strategies as part of their overall 

plan. ThisFurther, this approach also allows regional 

compliance strategies. The agency also recognizes the 

important functional relationship between the timingperiod

of time over which measures are deployed and theirthe

stringency. of emission limitations those measures can 

achieve. Because, for its primary proposal, the EPA is 

proposing a 10-year period over which to achieve the full 

required CO2 reductions, a period that begins more than five 

years from the date of this proposal, a state could take 

advantage of this relationship in the design of its program 

by using relevant combinations of building blocks to 

achieve its state goal in a timely and cost-effective 

manner. 

b. State goals and flexibilities 

In this action, the EPA is proposing state-specific 

rate-based goals to guide states in the development of 

their plans. These state-specific goals are based on an 

assessment of the amount of emissions that can be reduced 

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at high-emitting facilities through application of BSER, as 

contemplated and required under CAA section 111. For this 

purpose, we used the most recent available information, 

including data on generation capacity and availability at 

existing generation facilities and those generation 

facilities currently being built. The agency is proposing 

state-specific interim and final goals that must be 

achieved by no later than the year 2030. The proposed final 

goals reflect the EPA’s quantification of state-average 

emission rates from affected EGUs that could be achieved by 

2030 and sustained thereafter. The proposed interim goals 

would apply over a 2020-2029 phase-in period. The proposed 

final goals reflect the EPA’s quantifications of adjusted 

state-average emission rates from affected EGUs that could 

be cost-effectively achieved cumulatively or on average 

over the respective plan period achieved at reasonable cost 

by 2030 through implementation of the four building blocks 

described above to achieve reductions in overall CO2 

emissions at affected EGUs.. The proposed statespecificinterim goals are intended to demonstratewould 

apply over a 2020-2029 phase-in period. They reflect the 

level of reductions in CO2 emissions and emission rates and 

the level of stringencyextent of the application of the 
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building blocks that would be presumptively approvable in a 

state plan during the ramp-up to achieving the final goal. 

A state must submit a plan documenting how it will achieve 

an emission performance level equivalent to the state-specific 

goal set by the EPA. The state may choose the measures to 

achieve its goal. If the state determines that the application 

of certain measures yields fewer reductions than the EPA’s 

approach, then it may use other or additional measures to 

achieve the required reductions. 

The EPA is proposing to allow each state flexibility 

with regard to the form of the goal. Under this proposal, a 

state would not be obligated to adopt the rate-based form 

of the goal established by the EPA. A state plan submittal 

reflecting a mass-based form of the goal or a regional 

approach based upon either rate or mass would be approvable 

based upon a demonstration that the submittal is 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 state plans is responsivestates 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 

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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, in the context of the diverse and highly 

interconnected electric industry, between two competing 

objectives grounded in CAA section 111(d) –- a need for 

rigor and consistency in calculating the amount of required 

emission reductions, and a need for flexibility in 

establishing and implementing the standards of performance 

that reflect those emission reductions. The importance of 

this balance is heightened by the fact that the operations 

of the electricity system itself rely on the flexibility 

made available and achieved through dispatching between and 

among multiple interconnected EGUs, demand management and 

end use energy efficiency. We view the proposed goals as 

providing this rigor where rigor is required by the statute

with respect to the amount of emissions reductions, while 

providing states with flexibility where flexibility is 

permitted by the statute. , particularly with respect to 

the development and implementation of performance standards 

and the overall compliance plans. 

This approach is also responsive to the CAA’s 

recognitionrecognizes that state plans for emission 

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reductionreductions can, and must, be consistent with a 

vibrant and growing economy and supply of reliable, 

affordable electricity to support that economy. It further 

reflects and is based on the growing trend, as exemplified 

by many state and local clean energy policies and programs, 

to shift our energy production away from carbon-intensive 

fuels to a more sustainable system that puts greater 

reliance on renewable energy, and energy efficiency, and 

demand-side management. 

c. State plans 

i. Approach 

Each state wouldwill determine, and include in its 

plan, an emission emissions performance levellevels for its 

affected EGUs that isare equivalent to the state-specific 

CO2 goalsgoal in the emission guidelines., as well as the 

measures needed to achieve those levels and the overall 

goal. As part of determining this level, the state 

wouldwill decide whether it will adopt the rate-based form 

of the goal established by the EPA or translate the ratebased 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. 

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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 reductions. The plan must 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 emission 

guidelines that,for states to use in addition to 

establishing the state-specific goals,developing their 

plans. These guidelines include approvability criteria, 

requirements for state plan components, the process and 

requirementstiming for state plan submittal and the process 

and timing for state plan submittal anddemonstrating

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 

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range of state approaches. The emissionplan 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-onlyspecific or regional 

approaches that can be achieved on either a rate or mass 

basis. They also address several key policy considerations 

that states will have to addresscontemplate 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 

the portfolio approach. In view of legal issues concerning state 

plan structure, under CAA section 111(d)(1), discussed below, 

the EPA is soliciting comment on a different approach for state 

plans, which is that CO2 emission limits that apply directly to 

the affected EGUs must assure achievement of the entire amount 

of the emission performance level.that state plans that take 

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this portfolio approach would be approvable, provided that they 

meet other key requirements such as achieving the required 

emission reductions over the appropriate timeframes. Plans that 

do directly assure that affected EGUs achieve all of the 

required emission reductions (such as the mass-based programs 

being implemented in California and the RGGI states) would also 

be approvable provided that they meet other key requirements, 

such as achieving the required emission reductions over the 

appropriate timeframes. 

ii. State plan components 

The EPA is proposing to evaluate and approve each of 

the ten components of a state planplans 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 C.F.R. 60.23 – 60.29 and include the 

following twelve components for the EPA to evaluate and 

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approve the plan. 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 emissionsemission standards 

• Demonstration that each emissionsemission standard is 

quantifiable, surplusnon-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 

In accordance with the President’s Climate Action 

Plan,8 the EPA expects to finalize this rulemaking by June 

1, 2015. The Climate Action Plan 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, which is about one year after 

promulgation of the final emission guidelines, instead of 

rather than the 9 months specified in the EPA framework 

 

8

 The President’s Climate Action Plan, June 2013, available at 

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

climateactionplan.pdf

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regulations at 40 C.F.R. 60.23. However, the EPA recognizes 

that some states may need more than one year to develop a 

final state plan in order to provide sufficient time for 

technical work, state legislative and rulemaking schedules, 

coordination with third parties, and coordination among 

states involved in multi-state plans. Therefore, the EPA is 

proposing aan optional two-phased submittal process for 

state plans as an option. Each state would be required to 

submit its plan by June 30, 2016. However, if a state needs 

additional time to submit a complete plan, then the state 

may submit must notify the EPA by letter of such intent by 

no later than April 1, 2016. In this 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 plansubmittal by June 30, 2016. 

ThisTo be approvable, the initial plan must meetinclude

specific criteria for approvalcomponents, including a 

justification for why more time is needed, a 

requirementdescription 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, and an 

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explanation of the path to completion., as described in 

Section VIII.E of this preamble. 

If the initial plan includes those components, the EPA 

will approve the initial plan and provide an extension of 

time to submit a complete plan. In this case, theIf given 

an extension, 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. However, if the state develops a 

plan that includes a multi-state approach, then 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, and the potential 

complexity of the plans the EPA anticipates receiving, the 

EPA is proposing to extend the period of the EPA review of 

plans from the 4-four month period provided in the EPA 

framework regulations to 6 monthsa six month review and 

approval period. 

v. Timing of compliance 

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 The agency is proposing that states must begin to make 

reductions by 2020 and achieve compliance with the CO2 emission 

performance level in the state plan 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 would best support the 

optimization of overall CO2 reductions. The agency is also 

requesting comment on two alternative options fully described in 

section VIII of this preamble. . The first alternative option 

includes the addition of a required second submittal by each 

state in 2025 showing whether its plan measures would maintain 

the final emission performance level after 2030. The second 

alternative option is 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. 

The EPA is also proposing that measures that a vi. Key 

considerations for state plans 

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There are a number of considerations with which states will 

be faced in developing their plans and ensuring that they meet 

the general approvability criteria. Each state will have to make 

decisions, for example, on: 1) whether it will use the statespecific rate-based goal established by the EPA or will instead 

use an equivalent mass-based form of the goal; 2) which type of 

state plan approach best fits the state’s circumstances; 3) 

which types of measures will be included in its plan; 4) what 

types of demand-side reduction measures should the state put in 

place; and, 5) when various measures will yield reductions. 

 The EPA addresses these and other considerations in this 

proposal and is seeking comment on the options presented, as 

well as alternatives. 

vii. 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 emission goal. Thus, 

states with existing programs and policies, and states that put 

in place new programs and policies early, will be better 

positioned to achieve the goals. 

vi. 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. 

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Department of Energy and other federal agencies, as well as 

states, has collectedis collecting and developing available 

resources and is making thesethose resources available at an EPA 

website.9to the states..10 

3. Projected national-level emission reductions 

Under the proposed ruleguidelines, the EPA projects 

annual CO2 reductions of 2526 to 30 percent below 2005 

levels (ranges reflect ongoing evaluation. These guidelines 

will also result in important reductions in emissions of 

building block 3 alternatives,criteria air pollutants, 

including sulfur dioxide (SO2), nitrogen oxides (NOx) and 

the rest of the preamble is being modified to reflect these 

ranges). directly emitted fine particulate matter (PM2.5). 

4. Costs and benefits 

Actions taken to comply with the proposed guidelines 

will reduce CO2 emissions of CO2 and other air pollutants, 

including SO2, NOx and PM2.5, from the electric power 

industry, as well as other fossil-fuel-fired EGU emissions 

including directly emitted fine particulate matter (PM2.5), 

sulfur dioxide (SO2) and nitrogen oxides (NOX).. States will 

make the ultimate determination as to how the emission 

 

9

 [Add address for the EPA website]

10 www2.epa.gov/carbonpollutionstandardstoolbox 

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guidelines are implemented, thus. Thus, all costs and 

benefits reported for this action are illustrative 

estimates. 

The EPA estimates that, in 2020, this proposal will yield 

monetized climate and air pollution health co-benefits of $20 to 

$40 billion (2011$). The annual compliance costs of this 

proposal range from $5 to $10 billion (2011$) in 2020. It will 

achieve emission reductions of approximately 25% to 30% between 

2020 and 2030. These estimates are preliminary and subject to 

change. 

It isAssuming 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.11 The air pollution health co-benefits 

 

11 The EPA has used the U.S. government’s social cost of carbon 

(USG 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 USG 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 by the USG: the model average at 3 percent discount 

rate. 

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associated with reducing exposure to ambient PM2.5 and ozone 

through emission reductions of precursor pollutants in 2020 are 

estimated to be $15 billion to $34 billion using a 3 percent 

discount rate and $13 billion to $31 billion (2011$) using a 7 

percent discount rate relative to the 2020 base case. The annual 

compliance costs are estimated using the Integrated Planning 

Model (IPM) and include demand-side energy efficiency program 

and participant costs as well as monitoring and reporting costs. 

Total compliance costs of this proposal are approximately $5.4 

billion (2011$) in 2020. The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2020 are estimated to be $26 billion to $46 billion (2011$) 

using a 3 percent discount rate (model average). 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 $24 to $55 

billion (3 percent discount rate) and $21 to $50 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 $47 billion 
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to $78 billion (3 percent discount rate model average, 2011$) 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), rather than collaboratively the climate 

benefits in 2020 are expected to be approximately $18 billion (3 

percent discount rate, model average, 2011$). Health co-benefits 

are estimated to be $15 to $36 billion (3 percent discount rate) 

and $14 to $33 billion (7 percent discount rate). Net benefits 

are estimated to range from $26 to $46 billion (3 percent model 

average discount rate, 2011$). Climate benefits are 

approximately $31 billion in 2030 using a 3 percent discount 

rate (model average, 2011$) relative to the 2030 base case 

assuming a state compliance approach. Health co-benefits are 

estimated to be approximately $25 to $58 billion (3 percent 

discount rate) and $23 to $53 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 $47 to $80 billion (3 percent discount rate, 

2011$) assuming a state compliance approach. 

There are additional important to also note that there 

are benefits that the EPA could not monetize. The EPA could 

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not monetize important benefits. UnquantifiedThese 

unquantified benefits include climate benefits from 

reducing emissions of non-CO2 greenhouse gases (e.g., 

nitrous oxide and methane)12 and co-benefits from reducing 

direct exposure to SO2, NOx, and hazardous air pollutants 

(e.g., mercury and hydrogen chloride), as well as from 

reducing ecosystem effects and visibility impairment. 

Based upon the foregoing, it is clear that the monetized 

benefits of this proposal are substantial and far outweigh the 

costs. 

B. Organization and Approach for this Proposed Rule 

This action presents the EPA’s proposed emission guidelines 

for states to consider in developing plans to reduce GHG 

emissions from the electric power sector. Section II provides 

background on climate change impacts from GHG emissions, GHG 

emissions from fossil fuel-fired EGUs, and the utility power 

sector and CAA section 111(d) requirements. Section III presents 

a summary of the EPA’s stakeholder outreach efforts, key 

messages provided by stakeholders, state policies and programs 

 

12 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

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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, followed by identification of affected 

sources and the proposed treatment of source categories in 

Section V. 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 

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, and impacts. Impacts of the proposed 

action are then described in Section X. A, followed by a

discussion of statutory and executive order reviews is provided 

in Section XI, and the statutory authority for this action is 

provided 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 newnewly constructed affected sources13, and the 

rulemaking for modified and reconstructed sources that the EPA 

is proposing at the same time as the presentthis rulemaking. 

Each of these three rulemakings is independent of the other two, 

 

13 79 FR 1430

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and each has its own rulemaking docket. Accordingly, commenters 

who wish to comment on any aspect of this rulemaking, including 

anythinga topic that overlaps an aspect of one or both of the 

other two related rulemakings, should make those comments on 

this rulemaking. 

II. Background 

 In this section, we discuss climate change impacts from GHG 

emissions, both on public health and public welfare, present 

information about GHG emissions from fossil-fuel fired EGUs, and 

summarize the statutory and regulatory requirements relevant to 

this rulemaking. 

A. Climate Change Impacts from GHG Emissions

In 2009, the EPA Administrator issued the document we refer 

toknown as the Endangerment Finding under CAA section 

202(a)(1).14 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. 

 

14 “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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1. Public health impacts detailed in the 2009 Endangerment 

Finding15

AnthropogenicClimate change caused by human emissions of 

GHGs and consequent climate change threatenthreatens public 

health in multiple aspectsways. By raising average temperatures, 

climate change increases the likelihood of heat waves, which are 

associated with increased deaths and illnesses. While climate 

change also leads toincreases the likelihood of reductions in 

cold-related mortality, evidence indicates that the increases in 

heat mortality will be larger than the decreases in cold 

mortality. Climate in the United States. Compared to a future 

without climate change, climate change is expected to increase 

ozone pollution over broad areas of the country,U.S., including 

large populationin the largest metropolitan areas with already 

unhealthy surfacethe worst ozone levelsproblems, and thereby 

increase the risk of morbidity and mortality. Other public 

health threats also stem from projected increases in intensity 

or frequency of extreme weather associated with climate change, 

such as increased hurricane intensity, increased frequency of 

intense storms, and heavy precipitation. Increased coastal 

storms and storm surges due to rising sea levels are expected to 

 

15 “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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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 

Finding16

AnthropogenicClimate change caused by human emissions of 

GHGs and consequent climate change also threatenthreatens public 

welfare in multiple aspectsways. Climate changes are expected to 

place large areas of the country at serious risk of reduced 

water supplies, increased water pollution, and increased 

occurrence of extreme events such as floods and droughts. 

Coastal areas are expected to face increased risks from storm 

and flooding damage to property, as well as adverse impacts from 

rising sea level, such as land loss due to inundation, erosion, 

wetland submergence and habitat loss. Climate change is expected 

to result in an increase in peak electricity demand, and extreme 

weather from climate change threatens energy, transportation, 

and water resource infrastructure. Climate change may exacerbate 

ongoing environmental pressures in certain settlements, 

particularly in Alaskan indigenous communities. Climate change 

also is very likely to fundamentally rearrange U.S. ecosystems 

 

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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over the 21st century. Though some benefits may balance adverse 

effects on agriculture and forestry in the next few decades, the 

body of evidence points towards increasing risks of net adverse 

impacts on U.S. food production, agriculture and forest 

productivity as temperature continues to rise. These impacts are 

global and may exacerbate problems outside the U.S. that raise 

humanitarian, trade, and national security issues for the U.S. 

3. New scientific assessments 

As outlined in Section VIII.A. of the 2009 Endangerment 

Finding, the EPA’s approach to providing the technical and 

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

assessments by the U.S. Global Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies. These 

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. Since the 

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 
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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 Working Group I contribution to the 20132013-2014

Fifth Assessment Report (AR5), the USGCRP’s 2014 “Climate Change 

Impacts in the United States” (Climate Change Impacts), and the 

NRC’s 2010 “Ocean Acidification: A National Strategy to Meet the 

Challenges of a Changing Ocean” (Ocean Acidification), 2011 

“Report on Climate Stabilization Targets: Emissions, 

Concentrations, and Impacts over Decades to Millennia” (Climate 

Stabilization Targets), 2011 “National Security Implications for 

U.S. Naval Forces” (National Security Implications), 2011 

“Understanding Earth’s Deep Past: Lessons for Our Climate 

Future” (Understanding Earth’s Deep Past), 2012 “Sea Level Rise 

for the Coasts of California, Oregon, and Washington: Past, 

Present, and Future”, 2012 “Climate and Social Stress: 

Implications for Security Analysis” (Climate and Social Stress), 

and 2013 “Abrupt Impacts of Climate Change” (Abrupt Impacts) 

assessments. 

The EPA has reviewed these new assessments and finds that 

the improved understanding of the climate system they present 

strengthens the case that GHGs are endangeringendanger public 

health and welfare. 
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In addition, these assessments highlight the urgency of the 

situation as the concentration of CO2 in the atmosphere continues 

to rise. Absent a reduction in emissions, a recent National 

Research Council of the National Academies assessment projected 

that concentrations by the end of the century would increase to 

levels that the Earth has not experienced for millions of 

years.17 In fact, that assessment stated that “the magnitude and 

rate of the present greenhouse gas increase place the climate 

system in what could be one of the most severe increases in 

radiative forcing of the global climate system in Earth 

history.”18

What this means, as stated in another NRC assessment, is 

that: 

Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe. Therefore, 

emission reductions choices made today matter in 

 

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

1.

18 Ibid,Id., p.138.
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determining impacts experienced not just over the next 

few decades, but in the coming centuries and 

milleniamillennia.19 

Moreover, due to the time-lags inherent in the Earth’s 

climate, the NRCClimate 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 increase 

and more severe changes across a wide range of peoples, sectors, 

and ecosystems. 

These assessments underscore the urgency of reducing 

emissions now: today’s emissions will otherwise lead to raised 

atmospheric concentrations for thousands of years, and raised 

Earth system temperatures for even longer. Emission reductions 

 

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. 

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

AtIn 2009, the timeyear of the 2009 Endangerment Finding, the 

average concentration of carbon dioxide as measured on top of 

Mauna Loa was 387 parts per million.21 As of the date of 

signature of this proposed rulemaking, the The average 

concentration is [XX – likely higher than 398]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, 

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 1 below, which presents total U.S. 

anthropogenic emissions and sinks24 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2012. 

Table 1. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))25

SECTOR 1990 2005 2012 

Energy 5,256.5260.1

6,239.4 

243.5 5,489.6498.9

Industrial Processes 316.1 330.2334.9 319.6334.4

Solvent and Other 

Product Use 4.4 4.4 4.4 

Agriculture 473.9 512.2 526.3 

 

23 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2012”, Draft Report EPA 430-R-14-003, United States 

Environmental Protection Agency, FebruaryApril 15, 2014. 

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

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, Draft Report EPA 430-R-14-003, United 

States Environmental Protection Agency, FebruaryApril 15, 2014. 

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

Formatted: Indent: First line: 0"
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Land Use, Land-Use 

Change and Forestry 13.7 25.5 37.8 

Waste 165.0 133.2 124.0 

Total Emissions 6,229.6233.2 7,244.9253.8 6,501.5525.6

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.43)

Net Emissions (Sources 

and Sinks) 5,398.5402.1 6,214.2223.1 5,522.1546.3

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.97 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 2 below presents total CO2 emissions from fossil fuel-fired 

EGUs, for years 1990, 2005 and 2012. 

Table 2. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2 Eq.))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. 
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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. Currently, the majority of 

power in the U.S. is generated from the combustion of coal, 

natural gas, and other fossil fuels. In recent years, though, 

the proportion of new renewable generation coming on line has 

increased dramatically. For instance, one-third of new 

generating capacity built in 2013 used renewable power 

generation technologies (EIA, 2014). 

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 

GHG EMISSIONS 1990 2005 2012 

Total CO2 from fossil fuel 

combustion EGUs 1,820.8 2,402.1 2,023.6022.7

 - from coal 1,547.6 1,983.8 1,512511.2

 - from natural gas 175.3 318.8 492.2 

 - from petroleum 97.5 99.2 18.8 

Formatted: Tab stops: Not at 0.5"
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scale, power sources operate in a complex, interconnected grid 

system that typically is regional in scale. In addition, the 

U.S. economy depends on this sector for a reliable supply of 

power at a reasonable cost. 

In the U.S., much of the existing power generation fleet in 

the infrastructure is aging. There has been, and continues to 

be, technological advancement in many areas, including energy 

efficiency, solar power generation, and wind power generation.

Advancements and innovation in power sector technologies provide 

the opportunity to address CO2 emission levels at affected power 

plants while at the same time improving the overall power system 

in the U.S. by lowering the carbon intensity of power 

generation, and ensuring a continued reliable supply of power at 

a reasonable cost.

D. Statutory and Regulatory Requirements 

Clean Air Act section 111, which Congress enacted as part 

of the 1970 Clean Air Act Amendments, establishes mechanisms for 

controlling emissions of air pollutants from stationary sources. 

This provision requires 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 
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health or welfare.”29 EPA has listed more than 60 stationary 

source categories under this provision.30 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. 31 These standards are 

known as new source standards of performance (NSPS), and they 

are national requirements that apply directly to the sources 

subject to them. 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to prescribe regulations for states to submit 

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

(HAP). CAA section 111(d)’s mechanism for regulating existing 

sources differs from the one that CAA section 111(b) provides 

for new sources because CAA section 111(d) contemplates states 

submitting plans that establish “standards of performance” for 

the affected sources and that contain other measures to 

implement and enforce those standards. 

 

29 CAA §111(b)(1)(A). 30 See 40 CFR 60 subparts Cb – OOOO. 31 CAA §111(b)(1)(B), 111(a)(1). 
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“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.” 32 If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for that state.33 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. In the case of a tribe that 

has one or more affected EGUs onlocated in its landsarea of 

Indian country,34 the tribe would have the opportunity, but not 

 

32 CAA section 111(d)(2)(A). 33 CAA section 111(d)(2)(A). 34 The EPA is aware of at least threefour affected sources 

located in Indian Country located in Indian Country,: two on 

[Navajo] lands – the Navajo Generating Station and the Four 

Corners Generating Station – and; one on [Ute] lands – the 
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the obligation, to establish a CO2 performance standard and a 

plan for its tribal lands. 

The EPA issued regulations implementing CAA section 111(d) 

in 1975,35 and has revised them in the years since.36 (We refer to 

the regulations generally as the implementing regulations, and 

we refer to the 1975 rulemaking as the framework regulations.) 

These regulations provide that, in promulgating requirements for 

sources under CAA section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish 

binding requirements that states must address when they develop 

their plans.37 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,38

and the EPA must take final action on the state plans within 4 

 

Bonanza Generating Station. All three; 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.

35 “State Plans for the Control of Certain Pollutants From 

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

36 [Cites] 37 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. 

38 40 CFR 60.23(a)(2). 
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months of the due date for those plans,39 although the EPA has 

authority to extend those deadlines.40 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 

pulp plants (total reduced sulfur), and municipal solid waste 

landfills (landfill gases)).41 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.42 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 towards the pollutants and industries 

regulated. Similarly, in the present rulemaking, in defining CAA 

section 111(d) goals and guidelines for the states, the EPA 

believes it is necessary to take into account the particular 

 

39 40 CFR 60.27(b). 40 See 40 CFR 60.27(a). 41 [Cites] 42 [Cites] 
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characteristics of carbon pollution and the interconnected 

nature of the power sector, especially and the factmanner in 

which EGUs are currently operated such that operators themselves 

treat increments of generation areas 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. 

In this action, the EPA is proposing emission guidelines 

for states to use in developing their plans to reduce emissions 

of CO2 from the electric power sector. 

III. Stakeholder Outreach and Conclusions 

A. Stakeholder Outreach 

1. The President’s call for engagement 

Following the direction of the President in aPresidential

Memorandum to the Administrator (June 25, 2013),43 this proposed 

 

43 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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rule was developed after extensive and vigorous outreach to 

stakeholders and the general public. The Presidential Memorandum 

instructed the Administrator to inaugurate the process for 

developing standards through direct engagement with the states 

and a full range of stakeholders: 

“Launch this effort through direct engagement with States, 

as they will play a central role in establishing and 

implementing standards for existing power plants, and, at 

the same time, with leaders in the power sector, labor 

leaders, non-governmental organizations, other experts, 

tribal officials, other stakeholders, and members of the 

public, on issues informing the design of the program.” 

2. Educating the public and stakeholder outreach 

To carry out this stakeholder outreach, the EPA embarked on 

an unprecedented, pre-proposal outreach effort. From consumer 

groups to states to power plant owner/operators to technology 

innovators, the EPA sought input from all perspectives. 

The EPA began the outreach efforts with a webinar and 

associated teleconferences to establish a common understanding 

of the basic requirements and process of CAA section 111(d). The 

August 27, 2013 overview presentation was offered as a webinar 

for state and tribal officials, “Building a Common 
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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 

February 2013, the presentation had been viewed more than 4,400 

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 – a new email account: 

carbonpollutioninput@epa.gov; and a web-based form: 

http://www2.epa.gov/carbon-pollution-standards/forms/carbonpollution-standards-contact-us. These links, along with policy, 

program, and technical information about this rulemaking effort, 

are available on the EPA’s website at: 

http://www2.epa.gov/carbon-pollution-standards. The EPA has 
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received more than 2,000 emails offering input into the 

development of these guidelines. 

These emails and other materials provided to the EPA are 

posted on line as part of a non-regulatory docket, EPA Docket ID 

No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. All of the 

documents on which this proposal is based are available at 

Docket ID No. EPA-HQ-OAR-2013-0602, at www.regulations.gov.

However, while the information collected through extensive 

outreach helped the agency formulate this proposal, we are not 

relying on all of the documents, emails, and other information 

included in the informational docket that was established as a 

part of that outreach effort, nor will the EPA be responding to 

specific comments or issues raised during the outreach effort. 

Rather, we have included in the docket for this proposal all of 

the information we relied on for this action. 

The agency has encouraged, organized, and participated in 

hundreds of meetings about CAA section 111(d) and reducing 

carbon pollution from existing power plants. Attendees at these 

various meetings have included states and tribes, members of the 

public, and representatives from multiple industries, labor 

leaders, environmental groups and other non-governmental 

organizations. The direct engagement has brought together a 

variety of states and stakeholders to discuss a wide range of 
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issues related to the electricity sector and the development of 

emission guidelines under CAA section 111(d). The meetings 

occurred in Washington, DC, and at locations across the country. 

The meetings were attended by the EPA Regional Administrators, 

managers and staff and who are playing or will play key roles in 

developing and implementing the rule 

Part of this effort included the agency’s holding of 11 

public listening sessions; one national listening session in 

Washington, DC and 10 listening sessions in locations in the EPA 

regional offices across the country. All of the outreach 

meetings were designed to solicit policy ideas, concerns and 

technical information from stakeholders about using CAA section 

111(d). 

This outreach process has produced a wealth of information. 

The EPA which has taken information from these meetings and used 

it to informinformed this proposal significantly. The preproposal outreach efforts far exceeded what is required of the 

agency in the normal course of a rulemaking process, and the EPA 

expects that athe 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 
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clear and common understanding of the role the states will play 

in addressing carbon pollution from power plants. 

3. Public listening sessions 

More than 3,300 people attended the public listening 

sessions held in 11 cities across the country. Holding the 

listening sessions at the EPA’s regional offices offered 

thousands of people from different parts of the country the 

opportunity to provide input to EPA officials in accessible 

venues. In addition to being well located, holding the sessions 

in regional offices also allowed the agency 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. 
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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 

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 
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 The EPA conducted significant outreach to tribes, who are 

not required to – but may – develop or adopt Clean Air Act 

programs. The EPA is aware of three coal-fired power plants and 

one natural gas-fired EGU located in Indian country but is not 

aware of any power plantsEGUs 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 
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December 19, 2013. In those teleconferences, the EPA provided 

background information on the GHG emission guidelines to be 

developed and a summary of issues being explored by the agency. 

In addition, the EPA held a series of listening sessions 

prior to development of this proposed action. Tribes 

participated in a session on September 9, 2013 with the state 

agencies, as well as in a separate session with tribes on 

September 26, 2013. 

6. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in scores of 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. Due toBecause 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 
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to help understand the issues related to large industrial users 

of electricity. 

7. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations. The meetings focused on the 

importance of the utility industry in reducing carbon emissions 

from power plants. Power plant emissions are central to this 

rulemaking. The EPA encouraged industry representatives to work 

with state environmental and energy officers. 

The electric utility representatives included private 

utilities or investor owned utilities. Public utilities and 

cooperative utilities were also part of 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 
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and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

Regional Offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

9. Representatives from non-governmental organizations 

Agency officials engaged with representatives of 

environmental justice organizations during the outreach effort, 

including outreach tofor example, we engaged with the National 

Environmental Justice Advisory CommitteeCouncil members in 

September 20142013. 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. 
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 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. 

 Public health groups discussed the need for protection of 

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

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low cost carbon reductions. 

10. Labor 

A number of labor unions invited EPA officials to their 

meetings to give presentations and engage in discussions about 

reducing carbon pollution using CAA section 111(d). EPA senior 

officials and staff met with union representatives that included 

the United Mine Workers of America, SMART, the International 

Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, 

Forgers and Helpers, United Association, the International 

Brotherhood of Electrical Workers, the Utility Workers Union of 

America have participated in meetings at the EPA.. In addition, 

agency leaders participated in a meeting of the Presidents of 

several unions at the AFL-CIO. 

Formatted: Highlight
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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 

onlyvia 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 

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 
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EGUs legallylegal responsibility for the full amount of required 

CO2 emissions reductions, and instead, the EPA should authorize 

the state plans to include requirements on entities other than 

the affected EGUs that would have the effect of reducing 

utilization and therefore emissions, from the affected EGUs. 

Views on the form and stringency of the goal or guidelines 

varied. Some stakeholders preferred a rate-based form of the 

goal, while others preferred a mass-based form. In addition, 

some stakeholders recommended that the EPA let the states have 

the flexibility to either choose among multiple forms of the 

goals or to set their own goals. With regard to the stringency 

of the goal, some stakeholders recommended that the stringency 

of the goals vary by state, to account for differences in state 

circumstances. 

Many stakeholders recognized the value of allowing states 

flexibility in implementing the goals the EPA establishes. For 

example, states highlighted the importance of the EPA 

recognizing existing state and regional programs that address 

carbon pollution, including market-based programs, and allowing 

credit for prior accomplishments in reducing CO2 emissions. Many 

states and other stakeholders noted the importance of the EPA 

allowing flexibility in compliance options such that states 
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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 due tobecause of

the state legislative schedule and/or regulatory process. In 

some cases, approval of a plan through a state’s legislative or 

regulatory process could take one year or more after the plan 

has already been developed. Additional time would also allow and 

encourage multi-state and regional partnerships and programs. 

Many stakeholders also supported flexibility in the timing 

of implementation of the state plans and power sector compliance 

with the goals in the state plans. Such flexibility, some 

stakeholders asserted, would accommodate the diverse GHG 

mitigation potential of states and support more cost-effective 

approaches to achieving CO2 reductions. 

During the outreach process, some stakeholders raised 

general concerns that the rulemaking could have a negative 

impact on jobs and ratepayers. Some stakeholders also expressed 
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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 there were, a number of ideas that were put forward 

that are not fully reflected in this proposal. We invite public 

comment on thethese ideas. These ideas include those 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 

program for its plan. One group suggested the model rule should 

include a provision to allow the state to compensate merchant 
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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 archivedachieved by the federal approach; or a market 

price-based equivalency, via a demonstration that the program 

reflects a carbon price comparable to or greater than the costeffectiveness benchmark used by the EPA in designing the 

program. The EPA is proposing a way to demonstrate equivalency 

and that is discussed in Section VIII.

3. Power plant-specific assessment 

Other stakeholders suggested that an “inside the fence” 

plant- or unit-specific assessment linked to the availability of 

control at the source such as heat rate improvements. should be 
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considered. They indicateindicated 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 

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 

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Presidential Memorandum,44 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 2009.45 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 

of affected EGUs. A price signal for CO2 emissions also allows 

 

44 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 

45 The nine states include Connecticut, Delaware, Maine, 

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

and Vermont.
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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.46 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.47 Through 2012, for example, 

the RGGI states invested approximately $460 million of proceeds 

into energy efficiency programs.48 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.49

Between 2005, when an agreement to implement RGGI was 

announced, and 2012, power sector CO2 emissions in the RGGI 

 

46 Regional Greenhouse Gas Initiative 2013 Allowance Allocation 

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

allocation. 

47 Regional Investments of RGGI CO2 Allowance Proceeds, 2012 

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

Investment-Report.pdf 

48 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 

49 IbidId.
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participating states fell by more than 40 percent.50 RGGI was not 

the primary driver for these reductions but the reductions led 

RGGI-participating states to adjust the CO2 emission limits.51 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.52 

 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.53 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 

 

50 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).

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

CO2 emission limits for EGUs, began on January 1, 2009. 52 RGGI Press Release, January 13, 2014, 

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

pdf. 

53 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. 54 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.55 

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 

 

54 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, 

http://www.georgetownclimate.org/sites/default/files/EPA_Submiss

ion_from_States-FinalCompl.pdf 

55IbidId.
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emission rate of either 1450 pounds CO2/MWh (based on output) or 

160 pounds of CO2/MMBtu (based on input).56 

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.57 

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 

 

56 6 New York CoCodes, Rules & Regulations. Part 251 (Adopted 

June 28, 2012) 

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

Wash SB 6001 (2007) 
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foreseeable federal CAA requirements.58 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 2020.59 

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.60 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 

 

58 Colorado Clean Air Clean Jobs Act, HB1365 59 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. 

60 http://www.dsireusa.org/ 
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located outside of the state. They reduce utilization of fossil 

fuel electricity generating units,-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.61 The 2012 requirement increased to 18 percent of 

total retail sales for Xcel Energy and 12 percent for all other 

 

61 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.62 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.63

 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 

loadOregonload 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

 

62 IbidId. 63 HF 729, 

https://www.revisor.mn.gov/laws/?id=85&doctype=Chapter&year=2013

&type=0#laws.10.3.0 , Minnesota Statutes 2013, Section 

216B.1691, Subdivision 2f. Solar Energy Standard 

https://www.revisor.mn.gov/statutes/?id=216b.1691 
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for the state, each had achieved the five percent target as of 

the end of 2012.64 

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. These 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 

 

64 Eugene Water Electric Board Oregon Renewable Portfolio 

Standard 2012 Compliance Report and 2013 – 2030 Implementation 

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

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

Renewable Portfolio Standard Compliance Report, June 1, 2013. 

Formatted: Indent: First line: 0.5"
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surcharge on customer electricity bills, but can also be funded 

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 $5.9 billion in 20102012.65

Based on Lawrence Berkeley National Laboratory (LBNL) 

projections, spending is projected to reach $8.1 billion in 

2025.66 

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.67 

California has been advancing energy efficiency through 

utility-run demand-side energy efficiency programs for decades 

 

20 American Council for an Energy-Efficient Economy (ACEEE) 2013 

State Energy Efficiency Scorecard, available at 

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

ports/e13k.pdf.61 Consortium for Energy Efficiency Annual 

Industry Report: 2013 State of the Efficiency Program Industry – 

Budgets, Expenditures and Impacts, 2014. 

http://library.cee1.org/sites/default/files/library/11350/CEE_20

13_Annual_Industry_Report.pdf

66 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) 

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

State Scorecard 

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

ports/e13k.pdf 

Formatted: Indent: First line: 0.5"
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and considers energy efficiency “the bedrock upon which climate 

policies are built.”68 It requires its investor-owned utilities 

to meet electricity load “through all available energy 

efficiency and demand reduction resources that are costeffective, reliable and feasible.”69 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..”70 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.”71 Between 2010 

and 2011, California estimates that their demand-side energy 

efficiency programsthese programs are estimated to have reduced 

CO2 by 3.8 million tons.72 

 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy.

69 Cal Pub. Utility Code §454.5 (a)(9)(C). 70 Cited in December 27, 2013 Letter from Mary D. Nichols, 

Chairman of California Air Resources Board, to EPA Administrator 

Gina McCarthy.

71 IbidId. 72 IbidId.
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 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.73 Vermont law requires that the energy efficiency utility 

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.74 In 20122013, Efficiency Vermont, the PSB-appointed 

energy efficiency utility, achieved annual savings of 1.966

percent of the state’s electricity sales, at a cost of 3.54.1

cents per kilowatt‐hour, lower than the cost of comparable 

electric supply in the same year, which was 8.64 cents per kWh.75

Efficiency Vermont projects a net lifetime economic value to 

 

73 State of Vermont Public Service Board, Energy Efficiency 

Utility Creation and Structure. 

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

creationandstructure

74 [Insert link to Law] 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 

75 Efficiency Vermont Annual Report 2012, 

http://www.efficiencyvermont.com/About-Us/Oversight-ReportsPlans/Annual-Reports-amp-Plans 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. 
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Vermont of more than $10060 million from the 20122013 energy 

efficiency investments.76 

6. Energy efficiency resource standards 

 More than 20 states have energy efficiency resource 

standards (EERS) that require utilities to save a certain amount 

of energy each year or cumulatively.77 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-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.78

The rule required utilities to achieve 1.25 percent electricity 

savings in 2011 compared to electricity sales in the previous 

 

76 IbidId. 77 State Energy Efficiency Resource Standards: Policy Design, 

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

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

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

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf
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year, ramping up the savings each year until 2020 according to a 

designated timetable.79 In 2012, for example, investor-owned 

utilities were required to achieve energy savings equivalent to 

1.75 percent of the 2011 sales, leading to a cumulative savings 

requirement of 3 percent by the end of 2012 (an average of 1.5% 

annually over the 2 year period).80 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.81 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.82

E. Conclusions 

States have taken a leadership role in mitigating GHG 

emissions and have demonstrated the potential for national 

 

79 Id. 80 Arizona Corporation Commission, Docket RE-OOOOOC-09-0427, 

August 2010., Available at 

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

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

August 2010., Available at 

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

82 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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application of a number of approaches. Throughout the 

development of this proposed rule, the EPA considered the 

states’ experiences and lessons learned regarding the design and 

implementation of successful GHG mitigation programs. The agency 

also fully considered input from stakeholders during the 

development of this proposed rulemaking. 

Considering all input from stakeholders, the agency 

recognizes that the most cost-effective approach to reducing GHG 

emissions from the power sector under CAA section 111(d) is to 

follow the lead of numerous states and not only improveto 

identify improvements in the efficiency of fossil fuel-fired 

EGUs as a component of BSER, but also reduce their utilization 

through taking advantage of include in the BSER determination 

the EGU-emissions-reduction opportunities forthat states have 

already demonstrated to be successful in relying on lower- and 

zero-emitting generation and reduced electricity demand across 

the electricity system. .

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 theeach 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 
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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 

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 
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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 

emission reductions that a state can achieve through the costeffective application of 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 the emission performance level it will include in its 

plan by deciding whether it will adopt the rate-based CO2 goal 

set by the EPA or translate the rate-based goal into a massbased goal. The state would then establish a standard of 

performance or set of standards of performance (known as 

emission standards under the existing 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 the following four sets of measures, or building blocks: 
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1. LoweringReducing the carbon intensity of generation at 

individual affected EGUs (e.g., through heat rate 

improvements)..

2. Reducing utilizationemissions of the most carbonintensive affected EGUs toin the extentamount that this can 

be accomplished cost-effectively by shiftingresults from 

substituting generation toat those EGUs with generation 

from less carbon-intensive existing fossil fuelfiredaffected EGUs, (including NGCC units that are under 

construction.).

3. Reducing emissions of affected carbon-emitting EGUs toin

the extentamount that this can be accomplished costeffectively by expanding the amount of new, lower (or no) 

carbon-intensityresults from substituting generation at 

those EGUs with expandedlow- or zero-carbon generation. 

4. Reducing emissions offrom affected carbon-emitting EGUs 

toin the extentamount that this can be accomplished costeffectively by increasing results from the use of demandside energy efficiency that reduces the amount of 

generation required. 

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 
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six percent; block 2, displacing coal-fired steam and oil/gasfired steam generation in each state by increasing generation 

from existing NGCC capacity in that state up totoward a 70 

percent target utilization rate; block 3, including some amount 

of generation from nuclear units under construction, avoiding 

retirement of about eight percent of existing nuclear capacity, 

and increasing renewable electricity generation over time 

through the use of state-level renewable generation targets 

consistent with renewable generation portfolio standards that 

have been established by states in the same region; and block 4, 

increasing state demand-side 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 amount of emission limitation 

achievable through application of the BSER in that state. For 

each state, the EPA is proposing an interim goal for the phasein 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 
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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 emissionplan

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. This would either be a complete plan or, 

if justified, an initial plan that describes why additional time 

is needed and documents the state’s progress in preparing a 

complete plan. 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 

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. 
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The EPA is further proposing, as part of the emission 

guidelines, to allow the states the option of translating the 

EPA-determined 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 thein their plans, whether 

single state or multi-state, states may not adjust the 

stringency of the goals set by the EPA.

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

regulations, with the state emission performance level in place, 

the state must adopt a state plan that establishes a standard of 

performance or set of standards of performance, along with 

implementing and enforcing measures, that will achieve that 

emission performance level. The EPA is further proposing, as 

part of the emission guidelines, to authorize the state to 

submit either of two types of measures to achieve the 

performance level: (i) emission limitations that apply directly 

to the affected sources, and (ii1) 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 

as well asand other measures that have the effect of limiting 

generation by, and therefore emissions from, the affected 
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sources.; or 2) solely emission limitations that apply directly 

to the affected sources.

The EPA is also proposing, as part of its emissionthe 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, surplusnon-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 

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.
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 The EPA is also proposing, as part of its emissionplan

guidelines, requirements for the process and timing for 

implementation and demonstrating achievement of the required 

level of 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 

ultimatefinal CO2 emission performance level by 2030 and maintain 

it thereafter. 

 If a state with affected EGUs does not submit a plan, or if 

the EPA does not approve a state’s plan, then, under CAA section 

111(d)(2)(A), the EPA must establish a plan for that state. 

 A state that has no affected EGUs must document this in a 

formal letter submitted to the EPA by June 30, 2016. In the case 

of a tribe that has one or more affected EGUs onin its landsarea 

of Indian country,83 the tribe would have the opportunity, but 

 

83 The EPA is aware of at least threefour affected sourcesEGUs

located in Indian Country located in Indian Country,country: two 

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not the obligation, to adoptestablish a plan for its tribal 

lands that establishes CO2 emission performance standardsstandard 

and a CAA section 111(d) plan for its area of Indian country. 

B. Summary of Legal Basis 

The EPA believes that today’s proposed action is consistent 

with the requirements of CAA section 111(d) and the framework 

regulations. As an initial matter, the EPA reasonably interprets 

the ambiguous provisions concerning the air pollutants covered 

under CAA section 111(d) to authorize the EPA to regulate CO2

from EGUs. Moreover, althoughWe recognize that CAA section 

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

would be covered under a CAA section 111(b) rule, the. The EPA 

intends to complete the CAA section 111(b) rulemaking regulating 

CO2 from new EGUs, and that rulemaking 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 framework 

regulations, the EPA explicitly stated that it is authorized to 

 

on [Navajo] lands –, the Navajo Generating Station and the Four 

Corners Generating Station – and; one on [Ute] lands –, the 

Bonanza Generating Station. All three; 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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determine BSER, and the EPA is not re-opening that 

interpretation in this rulemaking. Accordingly;84 ccordingly, in 

this rulemaking, the EPA is determining BSER. 

The four building blocks include two types of measures 

that, together, comprise BSER for fossil-fired EGUs. Building 

block 1 provides the basis for identifying carbon intensity 

improvements as a component of BSER. Building blocks 2, 3, and 4 

provide the foundation for applying limitations in utilization 

to limitthe achievability of mass emissions limits at these 

EGUs. The EPA reasonably identified both types of measures as 

components of BSER based on the factors that the EPA is required 

to consider and the EPA’s authority to weigh those factors. 

In addition, the measures in building blocks 2, 3, and 4 

may be viewed as separate measures that reduce emissions by 

replacing the demand for generation at coal-fired EGUs. Because 

of the integration of the electricity system and the fungibility 

of electricity, these measures must be considered part of the 

system of emission reduction for fossil-fired EGUs. 

Moreover, the measures in each of the building blocks are 

“adequately demonstrated,” including as being technically 

feasible and reasonable in terms of cost. Heat improvement 

 

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

rulemaking. 
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measures are well-recognized as feasible within the industry. 

The measures that entail dispatch changes from coal-fired EGUs 

to NGCC units, investments in renewable energy, and demand-side 

energy efficiency 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. Further, all 

of the measures achieve an important degree of emission 

reduction. In addition, they are not unreasonably costly, 

particularly when considered on the level of the nation’s 

electricity system. Importantly, the measures encourage the 

development and expansion of technology and practices to reduce 

CO2 and are consistent with current trends in the electricity 

sector. 

After determining BSER, the EPA is authorized under the 

framework regulations, as an integral component to setting 

emission guidelines, to apply the BSER to each state and 

determine the resulting emission limitation for each state. 

 With the promulgation of the emission guidelines, each 

state must develop a plan to achieve its emission performance 

level. The state plans must establish standards of performance 

and include measures that implement and enforce those measures. 

Based on requests from stakeholders, the EPA is proposing 

that states be authorized to submit state plans that do not 
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impose legal responsibility on the affected EGUs for the 

entirety of the emissionsemission performance level, but instead 

impose requirements on other affected entities – for 

requirements, such as renewable energy and demand-side energy 

efficiency measures -, that would reduce utilization of, and 

thereforeavoid CO2 emissions from, the affected EGUs. It could be 

argued that thoseThe EPA solicits comment on whether such

requirements on other affected entities may be authorized as 

standards of performance or implementing measures, but the EPA 

acknowledges the legal uncertainty. As a result, the in a 

state’s CAA section 111(d) plan. The EPA also solicits comment 

on whether state plans must impose all of the legal 

responsibility for achieving the emissionsemission performance 

level on the affected EGUs. If soWe note that even if as a legal 

matter states would be required to impose responsibility in such 

a way, the state plan could – and state policy – nevertheless 

still could include the requirements on other affected entities 

in order to facilitate the reduced utilization, as a practical 

and economic matter, implementation of, measures that avoid CO2

emissions from, the affected EGUs. We emphasize that the states 

have discretion as to the form of the standards of performance 

and may include emission trading programs. 
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 To comply with the applicable standards of performance, 

sources may rely on any 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 

deadlines vary from those in the framework regulations. 

V. Authority to Regulate Carbon Dioxide, Affected Sources, 

Treatment of Categories

A. Authority to Regulate Carbon Dioxide 

The EPA has the authority to regulate, under CAA section 

111(d), CO2 emissions from EGUs, under the Agency’s construction 

of the ambiguous provisions in CAA section 111(d)(1)(A)(i) that 

identify the air pollutants subject to CAA section 111(d). The 

ambiguities stem from apparent drafting errors that occurred 

during enactment of the 1990 CAA Amendments, which revised 

section 111(d). 

During the 1990 CAA Amendments, the House of 

Representatives and the Senate each passed an amendment to CAA 

§section 111(d)(1)(A)(i). The two amendments differed from each 

other, and were not reconciled during the Conference Committee 

and, as a result, both were enacted into law. As amended, §CAA 

section 111(d)(1) requires states to submit standards of 

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performance for existing sources “for any air pollutant (i) for 

which air quality criteria have not been issued or which is not 

included on a list published under [CAA] section 108(a)... [or 

emitted from a source category which is regulated under section 

112]85 [or 112(b)]86... ” The bracketed and emphasized provisions 

set forth the House and Senate versions, respectively. 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 

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 Issues 

Memorandum.

 

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

1990).

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

1990).
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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 

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 
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technologically and economically feasible to meet the applicable 

standards. 

 Under CAA section 111(d)(1), in order for existing sources 

to become subject to that provision, the EPA must promulgate 

standards of performance under CAA section 111(b) to which, if 

the existing sources were new sources, they would be subject. 

Those standards of performance may include ones for sources that 

undertake new construction, modifications, or reconstructions. 

The EPA is in the process of promulgating two rulemakings under 

CAA section 111(b) for CO2 emissions from affected sources. The 

EPA proposed the first, which applies to affected sources 

undertaking new constructions, by notice dated January 8, 2014, 

which we refer to as the January 2014 Proposal. The EPA is 

proposing the second, which applies to affected sources 

undertaking modifications or reconstructions, concurrently with 

this CAA section 111(d) proposal. The EPA will complete one or 

both of these CAA section 111(b) rulemakings before or 

concurrently with this CAA section 111(d) rulemaking, which will 

provide the requisite predicate for applicability of CAA section 

111(d). 

B.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 
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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 1429; 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; (3) sells the greater of 219,000 MWh per year 

or one-third of its potential electrical output to a utility 

distribution system; and (4) was not in operation or under 

construction as of January 8, 2014 (the date the proposed GHG 

standards of performance for new EGUs were published in the 

Federal Register). The minimum fossil fuel consumption condition 

applies over any consecutive three-year period (or as long as 

the unit has been in operation, if less). The minimum 

electricity sales condition applies over rolling three-year 

periods (or as long as the unit has been in operation, if less). 

The rationale for the proposalsthis proposal concerning 

applicability areis the same as that for the January 8, 2014 
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proposal, sections V.A-B. See 79 FR at 1,459/1 – 1,461/2. We 

incorporate that discussion by reference here. 

BD. Combined Categories and Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is co-proposing 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 co-proposing 

codifying all of the proposed requirements for the affected EGUs 

new subpart UUUU of 40 CFR part 60. 

As discussed in the January 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 
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pollutants from those sources. In addition, the EPA co-proposed 

combining the two categories into a single category solely for 

purposes of the CO2 emissions from new construction of affected 

EGUs, and codifying the proposed requirements in a new 40 CFR 

part 60 subpart TTTT. The EPA solicited comment on whether 

combining the categories for new sources wasis 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 co-proposing to combine 

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 preexisting 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 
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boilers and combustion turbines – that the EPA has already 

listed under that provision. Thus, the EPA would not be required 

to make a finding that the combined category causes or 

contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare. 

In addition, the EPA is co-proposing two options for 

codifying the emission guidelines for affected sources. Under 

the first option, the EPA is proposing to codify the standards 

of performance for the respective sources within existing 40 CFR 

part 60 subparts: subpart Da, electric utility steam generating 

units, which includes steam electric utility boilers and IGCC 

units, and subpart KKKK, stationary combustion turbines, which 

includes both simple cycle and combined cycle stationary 

combustion turbines. Emission guidelines for electric utility 

steam generating units would be included in subpart Da and 

emission guidelines for stationary combustion turbines would be 

included in subpart KKKK. 

Under the second option, 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 
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appropriate because the emission guidelines the EPA is 

establishing do not vary by type of source. 

We solicit comment on the relative merits of each approach. 

In particular, we seek comment on whether the co-proposal to 

combine the categories and codify the GHG emission guidelines 

for all existing affected sources in subpart UUUU would offer 

any additional flexibility in the ways described above. 

VI.Building Blocks for Setting State Goals and Considerations 

A. Introduction 

Based on the states’ experiences of states and the industry 

and the EPA’s outreach with stakeholders as described above, the 

EPA has identified themultiple measures underlying its BSER 

determination encompassing carbon intensity improvements and 

limitations on utilization that can meaningfully reducecurrently 

in use for achieving CO2 emissions from affected EGUs, with 

minimal adverse impacts on the reliability of the electricity 

system,existing fossil fuel prices, assets already improved with 

other control technology,-fired EGUs. For purposes of 

determining the “best system of emission reduction ... 

adequately demonstrated” (BSER) and existing CO2 reduction 

programs. We group these developing state emission performance 

goals, we have screened the measures, which reflect current and 

projected practice and trends relevantgrouped those we are 

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proposing to the industry,consider further at this time into 

four categories, which we considercall “building blocks” for 

developing state emission performance goals..” We provide an 

overview of these building blocks in subsection VI.B. and more 

detailed discussion of each block in subsection VI.C. In 

subsection D,VI.D. we discuss possible combinations of the 

building blocks, and in subsection VI.E., we explain why as a 

legal matter theseall four building blocks, taken together, 

constitute the “best system of emission reduction . . . 

adequately demonstrated” (BSER), whichbasis for 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, we are mindful of numerous and 

varied stakeholder concerns. Many of these, including the need 

to achieve meaningful CO2 emission reductions and to recognize 

and take advantage of the progress already made by existing 

programs. Like stakeholders, we are attentive to the need to 

maintain electric 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 applying the building blocks, as discussed more in 
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Section VII, and we consider several of these to be key 

principles in this application. As discussed in Sections VII and 

VIII, we acknowledge and appreciate the advantages of allowing 

and promoting flexibility for states in crafting their programs. 

We recognize the knowledge that states have about their specific 

situations and their ability to evaluate and leverage existing 

and new capacity and programs to ultimately reduce EGU CO2

emissions. 

Similarly, we recognize and appreciate that states have 

different operate with differing circumstances. and policy 

preferences. For example, states have differing access to 

specific fuel types, and proportionsthe variety of EGU 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 regional and multi-state reduction strategies. 

Some states already participate in a regional program that 

reduces CO2 emissions, the RGGI, and we have noted the success of 

that program. for those states. 

Another key consideration in application of these building 

blocks, as discussed more in the following sections, is the 

relationship between the timing of measures and their 
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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 longer-termsustained implementation of other

actions, such as demand-side energy efficiency programs, may 

achieve over time. 

B. Building Blocks for Setting State Goals

In the system of supplying energy, it is clear that a variety of 

approaches are available and being used to reduce CO2 emissions. 

Emission controls for certain air pollutants depend on an add-on 

technological device. For CO2, carbon capture and storage (CCS) 

technology is available but for reasons discussed below cannot 

at this time be looked to on a national basis for controlling 

emissions from currently operating EGUs. Accordingly, to reduce 

CO2 emissions from existing EGUs, the EPA considered the other 

available approaches: (i) making emission rate improvements at 

affected EGUs (e.g., by improving heat rates, maximizing supplyside energy efficiency, or switching to lower-carbon fuels) and 

(ii) addressing emission levels at affected CO2-emitting EGUs 

(e.g., by shifting dispatch from higher CO2-emitting EGUs to 

lower CO2-emitting EGUs or by reducing the overall demand for 

electricity).Best System of Emission Reduction

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The latter approach is based on the electric power sector’s 

unique nature – its large size, the diversity of fuel sources, 

and the fungibility of its product: electrons and electricity 

services. Limiting affected EGUs’ emissions reflects the 

recognition both that, at least to some degree in all states, 

electricity production is interchangeable among generation 

facilities – production at higher-emitting EGUs can be replaced 

by generation at lower-emitting facilities – and that reducing 

electricity demand generally will reduce CO2 emissions from 

affected EGUs. Not only is generation generally interchangeable, 

but the product – electrons – is as well. The agency recognizes 

that a combination of approaches that lower the carbon intensity 

of electricity production and reduce demand across generation 

facilities offers the most effective – and cost-effective – 

approach to achieving CO2 emission reductions from affected EGUs. 

 From its extensive examinationThis subsection 

summarizes the EPA’s analytic approach to determining the best 

system of emission reduction (BSER) for CO2 emissions from 

existing EGUs. Further discussion of particular measures and how 

they form the basis of the BSER is provided below in subsections 

VI.C and VI.D, respectively. 

1. Overview of approach 
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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 of increased demand-side energy 

efficiency (“building block 4”). 

As described in the remainder of this section, the EPA 

concluded that while certain strategies within the first 

grouping clearly should be part of the BSER, it was not 

appropriate to limit consideration of the BSER to this first 

grouping, for several reasons. First, we determined that some 

strategies available in the other two groupings can reduce 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 
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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.87 These 

factors reinforced the appropriateness of our considering 

strategies from all three groupings for purposes of determining 

the BSER. 

2. CO2 reductions achievable through improvements in individual 

EGUs’ emission rates 

The first grouping of CO2 emission reduction options that 

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 electricity88

 

87 The potential for efficiency improvements to lead to increased 

utilization is generally described as a “rebound effect.” 

88 For simplicity, in this subsection we 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. 
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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. Specifically, our analysis 

indicated that average CO2 emission reductions of 1.3 to 6.7 

percent could be achieved by coal steam EGUs through adoption of 

best practices, and that additional average reductions of up to 

four percent could be achieved through equipment upgrades.89 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 

 

89 These estimated ranges are averages applicable to the fleet of 

coal steam EGUs as a whole. Potential improvements at individual 

EGUs could be higher or lower. 
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nation’s fleet of coal steam EGUs for net costs in a range of $6 

to $12 per metric ton.90

The EPA also examined application of CCS technology at 

existing EGUs. CCS offers the technical potential for CO2

emission reductions of over 90 percent, or smaller percentages 

in partial applications. In the recently proposed Carbon 

Pollution Standards for new fossil fuel-fired EGUs (79 FR 1430), 

we found that partial CCS was adequately demonstrated for new 

fossil fuel-fired steam EGUs and integrated gasification 

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. 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 

 

90 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”). 
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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,91 the EPA is not proposing and does not expect to 

finalize CCS as a component of the BSER for existing EGUs in 

this rulemaking.92

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 instead the 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 

 

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

EGUs, as noted in the discussion of CCS later in the preamble. 

92 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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natural gas conversion or co-firing is likely to be the 

incremental cost of natural gas relative to the cost of coal. 

Using Energy Information Administration (EIA) fuel price 

projections, we estimated that the CO2 reductions achieved 

through natural gas conversion or co-firing at an average coalfired steam EGU would have costs ranging from approximately $83 

to $150 per metric ton.93 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, 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 

 

93 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. 
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alternative to substituting natural gas for coal at individual 

steam EGUs through conversion or co-firing is instead to use 

natural gas to generate electricity at a different affected EGU 

with a better heat rate – notably a natural gas combined cycle 

(NGCC) unit – and to substitute that electricity for electricity 

from the coal-fired steam EGU, thus resulting in lower emissions 

from the coal-fired steam EGU and lower emissions from the set 

of affected EGUs overall.94 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 BSER for 

reducing CO2 emissions from existing EGUs. 

 

94 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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NGCC units can produce as much as 46 percent more 

electricity from a given quantity of natural gas than steam 

EGUs,95 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. 

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 2012.96 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 

 

95 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. 

96 EIA Form 860. 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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approximately 10 percent of NGCC plants operated at annual 

utilization rates of 70 percent or higher, and 19 percent of 

NGCC units operated at utilization rates of at least 70 percent 

over the summer season. Average reported availability generally 

exceeds 85 percent. We recognize that the ability to increase 

NGCC utilization rates may also be affected by infrastructure 

and system considerations, such as limits on the ability of the 

natural gas industry to produce and deliver the increased 

quantities of natural gas, the ability of steam EGUs to reduce 

generation while remaining ready to supply electricity when 

needed in peak demand hours, and the ability of the electric 

transmission system to accommodate the changed geographic 

pattern of generation. However, these considerations have not 

limited past rapid increases in NGCC generation levels, as 

indicated by a 20 percent increase in natural gas consumption 

for electricity generation from 2011 to 2012.97 Further, 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 subsection VI.C.2, the above facts 

support our assessment that an average NGCC utilization rate in 

a range of 65 to 75 percent is a reasonable target for the 

 

97 EIA Form 923. 
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amount of additional NGCC generation that could be substituted 

for higher carbon generation from steam EGUs as part of the 

BSER.98 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 AB32, shifting 

generation from more carbon-intensive EGUs to less carbonintensive 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 encompassed 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 

reducing CO2 emissions, it was apparent that relevant factors for 

 

98 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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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, at least potentially for the 

purpose of compliance with CO2 emission reduction requirements. 

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 the reduction of CO2 emissions at EGUs. 

Again, many instances were observed as taking place incidental 

to the ongoing operation of the electricity system as well as 

taking place in response to specific CO2 emissions limits in 

place in states that have been implementing CO2 emissions 

reduction programs affecting the power sector. We concluded 

that there are two principal types of such potential options for 

measures that result in CO2 emission reductions at EGUs affected 

under this proposal: ongoing development and use of low- and 

zero-carbon generating capacity, and ongoing development and 

application of demand-side energy efficiency measures. 

Low-and zero-carbon generating capacity provides 

electricity that can be substituted for generation from more 

carbon-intensive EGUs. More than half the states already have 

established some form of state-level renewable energy 

requirements, with targets calling on average for almost 20% of 
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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. 

Demand-side energy efficiency programs reduce the demand 

for generation from existing fossil fuel-fired EGUs, and 

therefore eliminate the CO2 emissions associated with the avoided 

generation as well, by producing electricity-dependent services 

with less electricity. More than 40 states already have 

established some form of demand-side energy efficiency polices, 

and individual states have avoided up to 13% of their 

electricity demand. Again, policies that encourage demand-side 

energy efficiency could be useful elements of CO2 reduction 

strategies and are consistent with current industry behavior. 

Using conservatively high estimates of the costs of demand-side 

energy efficiency, the EPA estimates that the costs of CO2 
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emission reductions achievable consistent with such policies 

would be in a range of $16 to $24 per metric ton. 

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 mainprincipal categories – 

“building blocks” – of measures undergirdingthat provide the 

applicationfoundation of carbon intensity improvements and 

limitingour BSER determination for CO2 emissions atfrom existing

EGUs: 

1. Lowering1. Reducing the carbon intensity of generation 

at individual affected EGUs (e.g., through heat rate 

improvements).

2. 2. Reducing emissions offrom the most carbon-intensive 

affected EGUs toin the extentamount that this can be 

accomplished cost-effectively by shiftingresults from 

substituting generation toat those EGUs with generation 

from less carbon-intensive existing fossil fuelfiredaffected EGUs, (including NGCC units that are under 

construction).

3. 3. Reducing emissions offrom affected carbon-emitting 

EGUs toin the extentamount that this can be accomplished 

cost-effectively by expanding the amount of new, lower (or 

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no) carbon-intensityresults from substituting generation at 

those EGUs with expanded low- or zero-carbon generation.

4. 4. Reducing emissions offrom affected carbon-emitting 

EGUs toin the amount that results from the extent that this 

can be accomplished cost-effectively by increasing use of 

demand-side energy efficiency that reduces the amount of 

generation required.

Each of the above Since they result either in improved 

operating efficiency or in reductions in mass emissions at 

existing EGUs, each of the four building blocks represents a 

demonstrated approach to addressing either carbon intensity 

improvements or the limitation offor reducing CO2 emissions at 

existingfrom affected EGUs that is already being pursued in the 

power sector. In the next subsection, we discuss each of 

thesethe 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 section we discuss each of the building blocks in 

turn. For each building block, we provide our proposed 

assessment of the technical potential and cost effectiveness of 

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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 state 

goals. described in section VII. We also discuss certain 

measures that we are not proposing to consider part of the best 

system of emission 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, but 

rather have flexibility to establish plans to meet their goals 

using their own preferred combinations and stringencies of 

measures. 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 aggressively, 
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and others less aggressively, than is reflected in the goal 

computations, according to each state’s needs and preferences. 

1. Building block 1 - heat rate improvements 

 The first basic category of approaches to reducing CO2

emissions fromat affected fossil fuel-fired EGUs consists of 

measures that reduce the carbon intensity of generation at 

individual coal-fired steam EGUs99 by improving heat rate.100 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 

 

99 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). 

100 The EPA’s evaluation of potential CO2 reductions achievable 

through heat rate improvements focused on coal-fired steam EGUs 

because those are the units where heat rate improvements would 

have the greatest potential CO2 reduction impact due to coalfired steam EGUs’ greater carbon intensity. 
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lowering the amount of CO2 produced as a byproduct of fuel 

combustion. Heat rate improvements yield important benefits to 

affected sources by reducing their fuel costs. 

The EPA is aware of the potential for “rebound effects” 

from improvements in heat rates at individual EGUs. In this 

context, a rebound effect would occur where, because of an 

improvement in its heat rate, an EGU experiences a reduction in 

variable operating costs that makes the EGU more competitive 

relative to other EGUs and consequently raises the EGU’s 

generation output. The increase in the EGU’s CO2 emissions 

associated with the increase in generation output would offset 

the reduction in the EGU’s CO2 emissions caused by the decrease 

in its heat rate and rate of CO2 emissions per unit of generation 

output. The extent of the offset would depend on the extent to 

which the EGU’s generation output increased (as well as the CO2

emission rates of the EGUs whose generation was displaced). The 

EPA considers the rebound effect to be a potential concern if 

heat rate improvements were the only approaches being considered 

for the BSER, but believes that the effect can be addressed by 

establishing the BSER as a combination of approaches that 

includes not only heat rate improvements but also approaches 

that will prevent or discourage increases in generation output 

from coal-fired steam EGUs on average. The topic of potential 

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rebound effects is discussed further in section VI.B above and 

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 

coal-fired steam EGUs than for other EGUs, and for purposes of 

determining the best system of emission reduction EPA has 

therefore conservatively based its estimate of CO2 emission 

reductions from heat rate improvements on coal-fired steam EGUs 

only.101 The remainder of this section focuses primarily on the 

EPA’s analysis of potential heat rate improvements from coalfired steam EGUs. In the final subsection below we discuss our 

analysis of potential heat rate improvements from other types of 

affected EGUs. 

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 

 

101 States and EGUs would also be able to rely on CO2 emission 

reductions achieved through heat rate improvements at other 

types of EGUs. 
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of cogeneration units).102 The current weighted-average annual 

heat rate of U.S. coal-fired EGUs in the range of 400 to 600 MW 

is approximately 10,450434 Btu per net kWh.103 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.104

 Several studies have examined the opportunities to employ 

heat rate improvements as a means of reducing CO2 emissions from 

coal-fired power plants.105 Among these, a 2009 study by the 

engineering firm Sargent & Lundy (S&L) used bottom-up 

engineering approaches evaluating potential heat rate 

improvements from specific best practices and equipment 

upgrades, including upgrades to boilers, steam turbines, and 

 

102 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.

103 See NEEDSv.5.13 at 

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

104 A small portion of some fossil fuel-fired EGU’s CO2 emissions 

may come from sources other than fuel, such as lime or limestone 

reagentor 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 tend to decrease when the 

amount of fuel used decreases. 

105 See chapter 2 of the GHG Abatement Measures TSD for details. 
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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 

installimplement the subset of the identifiedbest practices or

upgrades that were applicable to their specific designs or fuel 

types and that had not already been installedimplemented.) 

 In addition to the S&LSargent & Lundy study, which looked 

generically at the types of improvements that can be made at 

specific types of EGUs, historichistorical 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 thisthese data and have 

identified a number ofseveral “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 
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EPA analysis of hourly data summarized below, the individual EGU 

heat rate histories providesprovide a strong basis for 

considering heat rate improvementsimprovement as a meaningful 

potential approach to reducing the carbon intensity of 

generation at individual affected fossil fuel-fired EGUs. 

b. Amounts of heat rate improvements 

 In order to estimate the technical potential of heat rate 

improvement opportunities at existing fossil fuel-fired EGUs 

suggested by the discussion above, the EPA pursued two principal 

areas of analysis. The first area concerned the heat rate 

improvements that could be achieved by reducing heat rate 

variability at individual coal-fired EGUs through adoption of 

best practices for operation and maintenance. The second area 

concerned heat rate improvement opportunities that could be 

achieved through further equipment upgrades. Both analyses are 

summarized below along with our conclusions, and are discussed 

in greater detail in the GHG Abatement Measures TSD. 

 For the best practices analysis, the EPA worked with the 

heat ratehourly 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 MWh generation, making it 

possible to compute hourly gross heat rates. We used the hourly 
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data to assess variability in the hourly gross heat rates of 

approximately 900 individual coal-fired steam EGUs over the 

period from 2002 to 2012. Specifically, the EPA evaluated the 

consistency with which individual EGUs maintained their hourly 

heat rates over time. We expected that a certain degree of 

short-term heat rate variability was caused by factors beyond 

operators’ control, notably variation in hourly ambient 

temperature and hourly load., and preliminary analysis confirmed 

our expectation. We therefore controlled for variation in those 

factors by grouping the observed hourly heat rate data for each 

EGU into subsets corresponding to ranges of hourly ambient 

temperatures and hourly load levels.106 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 

 

106 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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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 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.107 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 

 

107 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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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 

6.7six percent, reflecting elimination on average of 50 percent 

of the deviation from top-decile performance. 

 For the equipment upgrade analysis, we evaluated potential 

opportunities to improve heat rates at affected EGUs through 

specific upgrades identified in the 2009 S&LSargent & Lundy

study. In that study, S&LSargent & 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 are non-overlapping and 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 S&L’sthe 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 
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because some EGUs may already have already implemented some of 

these upgrades. We therefore propose to use as a data input for 

purposes of developing state goals an estimate that, on average 

across the fleet of affected EGUs, only half of the full 

equipment upgrade opportunity just described remains – i.e., 

that for the fleet of affected EGUs as a whole, the technical 

potential for heat rate improvements from equipment upgrades 

incremental to the 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 more than fivefrom 4 to 12 percent of gross 

MWh generation. at a coal-fired steam EGU.108 The analysis of 

 

108 Electric Power Research Institute 2011 Technical Report – 

Program on Technology Innovation: Electricity Use in the 
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technical potential to reduce heat rate variability discussed 

above was based on gross heat rate data. Like gross heat rate, 

parasitic load can be addressed both through adoption of best 

practices and through equipment upgrades, and some measures 

undertaken at EGUs may affect parasitic load as well as gross 

heat rate. Because the hourly generation data reported to the 

EPA represent gross generation, we have less data available to 

directly analyze potential net heat rate improvements than gross 

heat rate improvements. We have therefore not included any 

separate estimate of parasitic load reductions achievable 

through best practices in our 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 cost effectively.109 

 The total of the estimated potential heat rate improvements 

from adoption of best practices to reduce heat rate variability 

 

Electric Sector (Opportunities to Enhance Electric Energy 

Efficiency in the Production and Delivery of Electricity). 

109 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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and implementation of equipment upgrades as discussed above is 

six percent. Because of the close relationship between an EGU’s 

fuel consumption and its CO2 emissions, a six percent heat rate 

improvement would be associated with a reduction in CO2 emissions 

of approximately six percent. We believe that this represents a 

reasonable estimate of the technical potential for CO2 emission 

reductions that would be achievable from affected coal-fired 

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 we have used an 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 EGUs. 

 It should be noted that we have not evaluated the technical 

and economic potential for analogous heat rate improvements at 
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types of EGUs other than coal-fired steam EGUs. We have 

therefore not identified such improvements as part of this 

building block. 

c. Costs of heat rate improvements 

 By definition, any heat rate improvement made for the 

purpose of reducing CO2 emissions will also reduce the amount of 

fuel the EGU consumes to produce its electricity output. The 

cost attributable to CO2 emission reductions therefore would be 

at most 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, makingwith the result that 

the net costs of heat rate improvements a highly cost-effective 

approach forassociated 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 S&LSargent & Lundy study discussed above. The

S&L 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 
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kW. To correspond to the average heat rate improvement of six 

percent 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 S&LSargent & 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 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 kWyear,110 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.111 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 

 

110 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. 

111 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.
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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.112 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 

most cost-effectiveleast expensive ones, the average cost of CO2

reductions would fall to $5.81 per metric ton.113 

 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, on average, the majority of the investment 

required to capture the technical potential for CO2 emission 

 

112 $7.75 per metric ton of CO2 * 6% / 4% = $11.63 per metric ton 

of CO2. 113 $11.63 per metric ton of CO2 * $50 / $100 = $5.81 per metric 

ton of CO2.

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reductions from heat rate improvements would be offset by fuel 

savings, makingand that the net costs of heat rate improvements 

a highly cost-effectiveas an approach to reducing CO2 emissions 

from existing fossil-fueled fuel-fired EGUs are reasonable. 

 Based on the analyses of technical potential and cost 

effectiveness summarized above, we propose to find that a six 

percent reduction in the CO2 emission rate of the coal-fired EGUs 

in a state, on average, is a reasonable estimate of the amount 

of heat rate improvement that can be cost-effectively 

implemented at a reasonable cost.114 

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 

6.7six percent and 4four percent, respectively, particularly in 

light of the reasonable cost-effectiveness of heat rate 

 

114 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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improvements. We also solicit comment on approaches for 

estimating an additional amount of the quantitative impacts on 

the net heat rate improvement due to efficiency-based reductions 

in parasitic loadrates of coal-fired steam EGUs of operation at 

loads less than the rated maximum unit loads. 

d. Assessment of heat rate improvement opportunities at 

gas- and oil-fired steam EGUs and NGCC units 

The EPA also 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/gas-fired 

steam EGUs, NGCC units, and combustion turbine units. For these 

non-coal technologies, the EPA concludes that the total 

additional potential CO2 reductions are very small compared to 

the potential CO2 reductions achievable at coal-fired steam EGUs. 

For this reason, the EPA does not propose to include heat rate 

improvement opportunities at oil/gas-fired steam EGUs or NGCC 

units as an element of the BSER for CO2 emissions from affected 

EGUs. However, the EPA expects that for some individual oil/gasfired steam EGUs, NGCC units, and combustion turbine units, 

attractive heat rate improvement opportunities will exist. We 
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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. 

2. Building block 2 – dispatch changes among affected EGUs 

 The second basic category of approaches to element of the 

foundation for EPA’s BSER determination for reducing CO2

emissions fromat affected fossil fuel-fired EGUs consistsgoes to 

the achievement of measures that limit utilization, and 

thereforereductions in mass emissions, of high carbon-intensity 

at certain affected EGUs – in particular, fossil fuel-fired 

steam EGUs - by replacing demand for and entails an analysis of 

the extent to which generation at such facilitiesthe 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. These interconnections provide 

flexibility for EGU owners and grid operators, subject to 

various reliability and operational constraints, use the 
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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. Treating 

increments of generation as 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. Electricity demand varies 

across geography and time in response to numerous conditions, 

such that EGU owners and grid operators are constantly 

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

demand in the most reliable and cost-effective manner possible. 

With appropriate signals and incentives, owners and operators 

can consider EGUs’ CO2 emission rates when selecting the order in 

which EGUs will be dispatched; indeed, operatorsOperators of 

EGUs subject to existing market-based programs to limit 

emissions of pollutants such as SO2 and NOx have for many years 

factored directly into dispatch decisions the costs associated 

with the EGUs’ emission rates of those pollutants because each 

ton of emissions requires an emission allowance that has an 

economic cost. Operators of EGUs subject to CO2 emissions limits 

in RGGI have also relied on replacing generation at higheremitting EGUs with generation from lower-emitting sources to 
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reduce emissions at the former. Reducing or limiting 

utilization, and therefore emissions, at high carbon-intensity 

EGUs by replacing demand for generation at those EGUs with 

generation at less carbon-intensive EGUs clearly has the 

technical capability to reduce overall power sector CO2

emissions. 

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 higheremitting EGUs with generation at lower-emitting EGUS as a 

technically feasible CO2 emissions reduction strategy, we turn 

in our BSER determination to the quantity of replacement 

generation that may be relied upon at reasonable costs. The 

U.S. electric generating fleet includes EGUs employing a variety 

of generating technologies. EGUs using technologies with 

relatively low variable costs, such as nuclear units, are for 

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economic reasons generally operated at their maximum output 

whenever they are available. Renewable EGUs such as wind and 

solar units also have low variable costs, but in any event are 

generally operated when wind and sun conditions permit rather 

than at operators’ discretion. In contrast, fossil fuel-fired 

EGUs have higher variable costs and are also relatively 

flexible. Fossil fuel-fired EGUEGUs are therefore generally the 

units that operators use to respond to intra-day and intra-week 

changes in demand (along with some hydroelectric units)..

Because of these typical characteristics of the various EGU 

types, the primary re-dispatch opportunities among existing 

units available to EGU owners and grid operators generally 

consist of opportunities to shift generation among various 

fossil fuel-fired units, in particular between coal-fired EGUs 

(as well as oil- and gas-fired steam EGUs) and NGCC units. In 

the 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 coalfired EGUs to NGCC units that takes place as a result of this 

competition is highly relevant to overall power sector GHG 

emissions, because a typical NGCC unit produces less than half 
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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 costeffective opportunity to reduce power sector CO2 emissions 

through re-dispatch 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% for some groups.115 

 We also researched historichistorical 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 

 

115 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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historichistorical 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.116 These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal.117 The, in addition to 

lower overall demand for electricity. Although the relative fuel 

prices vary by location, as do the recent patterns of redispatch. However, in, this trend holds across broad regions of 

the U.S. In 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 historichistorical 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 

 

116 Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990). 117 Natural gas prices have fallen because of advances in 

production methods that have increased available supplies. 
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higher.118 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. ThusFor example, on a seasonal basis, a 

significant number of NGCC units have achieved utilization rates 

between 50 and 80 percent, and; 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 thethese entire season.seasons.119 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 

 

118 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. 

119 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 
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part of a comprehensive approach to reducing CO2 emissions from 

existing high carbon-intensity EGUs, would be technically 

feasible. 

For purposes of establishing state goals, historical (2012) 

electric generation data was used to apply each building block 

and develop each state’s goal (expressed as an adjusted CO2 

emission rate in lbs per MWh).120 In 2012, electric generation 

from existing NGCC units was 959 TWh.121 After the application of 

NGCC re-dispatch toward a 70 percent target utilization rate, 

these existing sources were calculated to collectively generate 

1,390 TWh. Adding in the existing sources that were under 

construction in 2012 but not yet in operation increases total 

NGCC generation calculated in the goal setting to 1,443 TWh. 

Although states may choose to comply with state goals 

through a variety of abatement measures and achieving upwards of 

1,400 TWh of NGCC generation in 2020 is therefore not actually 

required, the EPA nevertheless believes that producing this 

quantity of generation is feasible for this set of NGCC units. 

As a reference point, NGCC generation increased by approximately 

430 TWh (an 80% increase) between 2005 and 2012. The EPA 

calculates that NGCC generation in 2020 could increase by 

 

120 See section VII for further explanation of how goals were 

computed. 

121 For covered sources. 
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approximately 50 percent from today’s levels. This reflects a 

smaller ramp rate in NGCC generation than has been observed from 

2005 to 2012. We also regard these changes as not impairing 

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 emissions reduction from 

existing power plants.122

 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 system is already supporting national average NGCC 

utilization rates of 60 percent or higher during peak hours, 

which are the hours when constraints on pipelines or electricity 

transmission networks are most likely to arise. NGCC unit 

 

122 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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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).123 Fleet-wide combined-cycle average 

monthly utilization rates have reached 65 percent,124 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 

reasonconsideration supporting our view that gas and electric 

system infrastructure would be capable of supporting increased 

NGCC unit utilization rates is the flexibility of the emission 

guidelines. The state goals do not require any particular NGCC 

unit utilization rate to be achieved in any hour or year of the 

initial plan period. Thus, even if isolated gas or electric 

 

123 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).

124 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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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 reasonconsideration

supporting a conclusion regarding the adequacy of infrastructure 

is that pipeline and transmission planners have repeatedly 

demonstrated the ability to methodically relieve bottlenecks and 

expand capacity.125 FurtherNatural gas pipeline capacity is 

regularly added in response to increased gas demand and supply, 

such as the addition of large amounts of new NGCC capacity in 

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 use by electric utilities about ten years ago, 

increases of up to 30 percent in total deliverability out of the 

 

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

in Energy; INGAA Foundation, Pipeline and Storage 

InfrastrucureInfrastructure 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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pipeline system were judged to be possible by the pipeline 

industry.126 There have also been notable capacity expansions 

over the past five years, in response to increased natural gas 

supply estimates and advances in drilling techniques.127 Further, 

as discussed below in section VII.D on state flexibilities and 

section VIII on state plans, we believe the flexible nature of 

the goals provides time for infrastructure improvements to occur 

should they prove necessary in some locations. 128 Combining 

these factors of currently observed utilization rates of up to 

65 percent on a monthly basis and time flexibility to address 

existing infrastructure limitations, it is reasonable to 

conclude that the natural gas supply system can reliably deliver 

sufficient supplies to allow average annual NGCC utilization 

rates of 65 percent, and, given the flexible compliance 

potential, to move beyond this level to 70 percent utilization 

rates. 

 We recognize that re-dispatch does contemplate an 

associated increase in natural gas production. The EPA expects 

the growth in NGCC generation assumed in goal setting to be 

 

126 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. 

127 Energy Information Administration, 

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

128 See section VII.D and section VIII below for discussion of 

timing flexibility. 
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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, natural gas proved reserves have doubled 

between 2000 and 2012. Domestic production has increased by 32 

percent over that same timeframe (from 19.2 TCF to 25.3 TCF). 

EIA’s Annual Energy Outlook for 2014 projects that production 

will further increase to 29.1 TCF, as a result of increased 

supplies and favorable market conditions. For comparison, NGCC 

generation growth of 450 TWh (calculated in goal setting) would 

result in increased gas consumption of roughly 3.5 TCF for the 

electricity sector. 

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 
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and emission impacts of prospective environmental policies. To 

fulfil its purpose of producing projections related to the 

electric power sector and its related markets - including least 

cost capacity expansion and electricity dispatch projections – 

that reflect industry conditions in as realistic a manner as 

possible, IPM incorporates representations of fuel supply, 

transmission, dispatch, and reliability constraints. The model 

includes a detailed representation of the natural gas pipeline 

network and the capability to project economic expansion of the 

network based on pipeline load factors. At the EGU level, IPM 

includes detailed representations of key operational limitations 

such as turn-down constraints, which are designed to account for 

the cycling capabilities of EGUs to ensure that the model 

properly reflects the distinct operating characteristics of 

peaking, cycling, and base load units. 

As described in more detail below, the EPA used IPM to 

assess the costs of requiring increasing levels of 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.129 By the nature of IPM’s 

 

129 See Chapter 3 of the Regulatory Impact Analysis for more 

detail.
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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 

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 in our BSER 

determination to the question of cost. The cost of the power 

sector CO2 emission reductions that can be achieved through redispatch among existing fossil fuel-fired EGUs depends on the 

relative variable costs of electricity production at EGUs with 

different degrees of carbon intensity. These variable costs are 

driven by the EGUs’ respective fuel costs and by the 

efficiencies with which they can convert fuel to electricity 
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(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 analysis of the 

opportunity to reduce CO2 emissions through re-dispatch. The 

first set was a dispatch-only set that provided a framework for 

understanding the broader economic and emissions implications of 

shifting generation to NGCC units from more carbon-intensive 

EGUs without consideration of emission reduction measures 

reflected in the other building blocks. The second set included 

additional refinements and more closely reflected all the 

characteristics of the proposed goals that were used as the 

basis for assessing the costs and benefits of the overall 

proposal.130 Both sets of analyses were conducted using the 

Integrated Planning Model (IPM), 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 

 

130 See Regulatory Impact Analysis for more detail.
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evaluate the economic and emission impacts of prospective 

environmental policies. 

 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. In the most restrictive scenarios, redispatch was simulated only between EGUs located in the same 

state. The purpose of analyzing these scenarios was to 

understand and demonstrate, even under a restrictive 

interpretation of the degree of re-dispatch that might 

constitute a component of the best system of emission reduction 

under CAA section 111(d), to what extent existing NGCC units 

could increase their dispatch cost-effectively and without 

extremesignificant 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 
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specified annual utilization rate.131 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 constraints and requiring re-dispatch to 

occur exclusively within a state’sregion’s existing fleet.132 

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 and a constraint prohibiting interstate redispatch opportunities, comparison to the business-as-usual case 

indicates that the average cost of the CO2 reductions achieved 

ranged from [$xx] to [$xx]over the 2020-2029 period was $30 per 

 

131 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. 

132 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.
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metric ton of CO2.133 We view these estimated costs as not 

unreasonable and therefore as supporting the use of a 70 percent 

utilization rate target for purposes of quantifying the costeffective emission reductions achievable 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. This is becauseOne reason 

for this is that the 70 percent utilization rate in the scenario 

exaggerates the stringency with which building block 2 is based 

on the assumption that there will be no cost-effective redispatch opportunities among EGUs in differentactually reflected 

in the state goals: while the goal computation procedure uses 70 

percent as a target NGCC utilization rate for all states, 

contrary to the realityfor only 29 states do the goals actually 

reflect reaching that interstate flows of electricity routinely 

change in response to economic conditions. As atarget NGCC 

utilization, with the result, this case assumes no use of 

interstate electricity trading as a cost reduction mechanism. As 

discussed below, utilizing cost-effective interstate re-dispatch 

opportunities significantly reduces cost. It should also be 

 

133 The analogous costs for the scenarios with 65 and 75 percent 

NGCC utilization rates were $21 and $40 per metric ton of CO2, 

respectively. 
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noted that that the average NGCC utilization rate reflected in 

the computed state goals is only 64 percent.134 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 redispatch in particular, and as a result, they reflect an 

assumption that even in a state where re-dispatch might be 

relatively expensive compared to other available CO2 reduction 

measures that are part of the BSER, the state would seek to meet 

its emission reduction obligations using re-dispatch to the same 

extent as 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 

employing re-dispatch to the maximum extent. 

 The EPA also analyzed dispatch-only scenarios where 

shifting of generation among EGUs was not limited by state 

boundaries. In one set of analyses, re-dispatch was simulated to 

occur across the multi-state regions overseen by independent 

system operators (ISOs) and other regional transmission 

organizations (RTOs), while in another set of analyses, national 

 

134 For further explanation of the state goal computation 

methodology, see section VII of the preamble and the Goal 

Computation TSD. 
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re-dispatch was simulated (subject to other constraints 

specified in the model, including transmission limits). In these 

scenarios with greaterlimited 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% was notably 

lower. $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, which we believe reflect a more realistic 

representation of how re-dispatch would actually occur among 

EGUs located in multi-state regions, 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 their costs, than the cases in which the analysis 

of re-dispatch opportunities was limited according to state 

boundaries.costs. 

 We also conclude from our analysis that the extent of redispatch estimated in this building block can be achieved 

Formatted: Indent: First line: 0.5"
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without causing significant economic impacts. For example, in 

both of the 70 percent NGCC unit utilization rate 

scenarioscenarios – with restrictions on interstate re-dispatch, 

limited to regional and state boundaries, respectively – 

delivered natural gas prices were projected to increase by a 

rangean average of from [x]no more than ten percent to [x] 

percentover the 2020-2029 period, which is well within the range 

of historichistorical natural gas price variability.135 Projected 

wholesale electricity price increases ranged from [x] to [x] 

percentover the same period were less than seven percent in both 

cases, which similarly is well within the range of 

historichistorical electric price variability.136 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 

 

135 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. 

136 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, described above for are 

overstated compared to the most restrictive scenario to be 

considerably larger thanimpacts that would actually occur in 

real-world compliance with this rule’s proposed goals. Operating 

on an interstate basis is expected to reduce costs and, as noted 

above, at least some states may have available less expensive 

reductions among the BSER measures. Consistent with this 

expectation, the comprehensive analyses used to assess the 

compliance costs and benefits of this proposal, which reflect 

the greater geographic extent of actual re-dispatch 

opportunities and a more complete representation of the 

additional flexibility available to states, show significantly 

smaller economic impacts. These analyses are discussed below in 

section X on the regulatory impacts analysis. 

 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 cost-effectively 

implemented is at reasonable cost such that electricity 

generation could be shifted from more carbon-intensive EGUs to 

less carbon-intensive EGUs within the state up to the point at 
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which. 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 would 

have annual utilization rates of 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 

estimatetarget of a 65 percent average utilization rate for NGCC 

units. In 2012, approximately 1816 percent of existing NGCC 

unitsplants 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 lowerbound estimate of an achievable average NGCC utilization rate, 

and we would expect the costs and economic impacts from redispatch associated with a 65 percent NGCC utilization target to 

be lower than the costs and impacts associated with the 70 

percent utilization target. 

We also specifically invite comment on raising the NGCC 

utilization rate target to 75 percent.a level higher than 70 

percent, and in particular 75 percent. As noted above, six 
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percent of NGCC plants operated at or above a 75 percent 

utilization rate in 2012.137

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 – expanding theusing an expanded amount of 

new, less carbon-intensive generating capacity 

 The second basic category of approaches that create a basis 

for incorporating limiting emissions as an third element of the 

foundation for EPA’s BSER determination for reducing CO2

emissions fromat affected fossil fuel-fired EGUs consists of 

measures that reduce electricity demand at affected carbonemitting 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 expanding the 

using an expanded amount of lower-carbon generating capacity 

available to produce replacement generation. The opportunity 

discussed above to re-dispatch from higher-carbon to lowercarbon EGUs within the affected fossil EGU fleet may be limited 

by the amount of underused less carbon-intensive capacity 

 

137 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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available to accommodate shifting of generation from more 

carbon-intensive EGUs. This limit can be relieved by adding new 

lower carbon-intensity generating capacity to the electric 

system or preserving existing low-carbon generating capacity, 

and measures that would do so constitute the third building 

block. Below we discuss several differenttwo types of generating 

capacity that couldcan play this role: new renewable generating 

capacity, and new and preserved nuclear capacity, and new NGCC 

capacity. . 

a. New renewableRenewable generating capacity 

Renewable electricity (RE) generating technologies are a 

well-established part of the U.S. power sector. In 2012, 

fiveelectricity generated from renewable technologies, including 

conventional hydropower, represented 12 percent of total U.S. 

electricity generation was produced by renewable technologies, , 

up from two9 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.138 Production of 

this renewable generation displaces predominantly fossil fuelfired generation and thereby avoids the CO2 emissions from that 

 

138 Database of State Incentives for Renewables & Efficiency 

(DSIRE), 

http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0. 
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displaced generation. EPA believes that renewable electricity 

generation is a proven and cost-effective way for states to 

reduce CO2 emissions at affected EGUs. at a reasonable cost.139

To estimate the CO2 emission reductions from affected EGUs 

achievable through increases in renewable generation, EPA has 

estimated a “best practices” scenario for renewable capacity 

development 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 

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 regional contexts.140 

 

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

state plans, see section VIII below. 

140 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 cost-effective RE 

generation potential within the same region. 

Formatted: Subscript
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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 does not establishneither 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 

effectiveness. 

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.141 By 

comparing each state to a set of neighbors rather than to a 

single national standard, we are able to take regional variation 

 

141 Given their unique locations, Alaska and Hawaii are not 

grouped with other states into these regions. As a conservative 

approach to estimating cost-effective 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. 
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into account while still maintaining a level of rigor for the 

scenario’s targets. The grouping of states into theseThe 

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.142 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 3 below. 

Table 3: Regions for Development of Best Practices RPS 

Scenario 

Region States 

East Central Delaware, District of Columbia*, Maryland, New 

Jersey, Ohio, Pennsylvania, Virginia, West 

Virginia 

North Central Illinois, Indiana, Iowa, Michigan, Minnesota, 

Missouri, North Dakota, South Dakota, Wisconsin 

Northeast Connecticut, Maine, Massachusetts, New 

Hampshire, New York, Rhode Island, Vermont* 

 

142 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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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 

growing annual levels of RE generation143 estimated based on 

application of an annual RE growth factor to the state’s 

historichistorical RE generation, subject to a maximum RE 

generation target. The annual RE growth factors and maximum RE 

generation targets were developed separately for each of the six 

regions. Our procedure for determining these elements is 

described in the Greenhouse Gas Abatement Measures TSD and 

summarized below. 

 

143 The bulk of hydropower is excluded from this approach to 

quantify BSER-related RE generation potential because state RPS 

requirements typically exclude the historical output from preexisting hydropower projects from qualifying. 
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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. Most hydropower generation is excluded from 

this existing 2012 generation for purposes of quantifying BSERrelated RE generation potential because state RPS requirements 

typically exclude the historical output at pre-existing 

hydropower facilities from qualifying. Additionally, building 

the methodology from a baseline that includes large amounts of 

existing hydropower generation could distort goals for states 

with large amounts of existing hydropower capacity as well as 

for their regional neighbors lacking that existing capacity. 

(The exclusion of pre-existing hydropower generation from the 

baseline of this goal-setting framework does not exclude it as 

an option for state compliance.)

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 

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 
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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, this amount is that already have RPS requirements in 

place, these amounts are less than itstheir RPS targettargets

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,144

and continues through 2029. This regional growth factor is the 

growth factor used for each state in that region to develop the 

best practices scenario. 

Finally, we developed the annual RE generation levels for 

each state. To do this, we applied the appropriate regional 

growth factor to that state’s initial RE generation level, 

starting in 2017, but stopping at the point when additional 

growth would cause total RE generation for the state to exceed 

the state’s maximum RE generation target. For computation of the 

proposed state goals discussed in section VII.C below, we used 

 

144 See Section VIII below for further discussion of timing 

requirements for state plan submittals. 
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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 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 4. 

 Table 4: State RE Generation Levels for State Goal 

Development (Percentage of Annual Generation)145

State 2012 Proposed Goals Alternate Goals 

Interim 

Level 

Final 

Level 

Interim 

Level 

Final 

Level 

 Alabama 2% 6% 9% 4% 5% 

 

145 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 

Formatted Table
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 Alaska 1% 52% 102% 21% 31% 

AlabamaArizona 2% 63% 93% 42% 53% 

 Arkansas 3% 5% 7% 4% 5% 

 Arizona 2% 3% 3% 2% 3% 

 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% 910% 10% 

 Iowa 25% 15% 15% 15% 15% 

 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% 

 Maryland 2% 10% 16% 6% 8% 
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 Maine 28% 25% 25% 25% 25% 

 Michigan 3% 6% 7% 5% 6% 

 Minnesota 18% 15% 15% 15% 15% 

 Missouri 1% 2% 3% 2% 2% 

 Mississippi 3% 8% 10% 6% 8% 

 Missouri 1% 2% 3% 2% 2% 

 Montana 5% 8% 10% 7% 7% 

 North Carolina 2% 7% 10% 5% 6% 

 North Dakota 15% 15% 15% 15% 15% 

 Nebraska 4% 8% 11% 6% 7% 

 Nevada 8% 15% 19% 12% 14% 

 New Hampshire 7% 19% 25% 15% 19% 

 New Jersey 2% 8% 16% 5% 7% 

 New Mexico 7% 12% 16% 10% 12% 

 Nevada 8% 15% 19% 12% 14% 

 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% 20% 

 Pennsylvania 2% 9% 16% 5% 7% 

 Rhode Island 1% 4% 6% 3% 3% 
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 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% 6% 4% 5% 

 Virginia 3% 12% 16% 9% 12% 

 Washington 7% 12% 16% 10% 12% 

 West Virginia 2% 8% 14% 5% 6% 

 Wisconsin 5% 8% 11% 7% 8% 

 West Virginia 2% 8% 14% 5% 6% 

 Wyoming 9% 15% 20% 13% 15% 

We note that the RE generation levels represent total 

amounts of RE generation, rather than incremental amounts. 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 to deploy 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 that have already achieved a higher 

proportion of their generation from renewable resources are 

assumed to have less additional renewable generation to deploy 
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as part of the BSER framework informing state goals, in 

comparison to states in that region that have not achieved as 

high a share of RE generation to date. 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. 

Several studies have found the costThe 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 displace 

emissions through RE ranges from $10 to $40 per metric ton of 

CO2.146 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" 

foundprojected the median change in retail electricity price to 

be $0.0004 per kilowatt-hour (only a 0.7 percent increase), the 

median monthly bill impact to be between $0.13 and $0.82, and 

 

146 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.
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the median CO2 reduction cost to be $3 per metric ton.147 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.148 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.149

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 

 

147 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. 

148 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.

149 NREL, “Renewable Electricity Futures Study”, NREL/TP-6A20-

52409, 2012, http://www.nrel.gov/analysis/re_futures/.

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through 2035 would require approximately 4 to 4.5 GW of new 

renewable capacity per year. Average deployment of RPS-supported 

renewable capacity from 2007-2012 has exceeded 6 GW per 

year.150 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 - 

2011) from 92.1 percent to 95.2 percent despite a 40 percent 

increase in RPS obligations during this period.151 

We invite comment on this approach to treatment of new 

renewable generating capacity as an emission limitation 

component of the best system of emission reduction and a basis 

for part of the quantification of state goals. 

[PLACEHOLDER FOR SOLICITATION OF COMMENT ON AN ALTERNATIVE 

METHOD OF QUANTIFYING BSER RE GENERATION THAT IS CURRENTLY UNDER 

DEVELOPMENT WITH INTERAGENCY REVIEWERS] 

b. New and preserved nuclear capacity 

 

150 Galen Barbose, “Renewables Portfolio Standards in the United 

States: A Status Update,” Lawrence Berkeley National 

LabLaboratory, November 2013. 151 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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 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 for reducing 

CO2 emissions from affected fossil fuel-fired EGUs. 

 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 new 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 

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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 a highly cost-effective opportunity to reduce CO2

emissions from affected fossil fuel-fired EGUs. For this reason, 

we are proposing that the emission reductions achievable at 

affected sources due toas a result of the generation provided at 

the identified new nuclear units should be factored into the 

state goals for the respective states where these new units are 

located. However, the EPA also realizes that reflecting 

completion of these units in the goals has a significant impact 

on the calculated goals for the states in which these units are 

located. If one or more of the units were not completed as 

projected, that could have a significant impact on the state’s 

ability to meet the goal. We therefore take comment on whether 

it is appropriate to reflect completion of these units in the 

state goals and on alternative ways of considering these units 

when setting state goals.

 Another way to increase the amount of available nuclear 

capacity is to preserve existing nuclear EGUs that wouldmight

otherwise be retired. The EPA is aware of six nuclear EGUs at 

five plants that have retired or whose retirements have been 
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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 believesrecognizes that increaseda host 

of factors – increasing fixed operation and maintenance costs, 

relatively low wholesale electricity prices, and additional 

capital investment associated with unit age play a role, 

particularly as the units approachensuring plant security and 

emergency preparedness – have altered the point of deciding 

whether to applyoutlook for renewal of their initial operating 

licenses (which have 40-year terms). Of the existing fleet of 

nuclear EGUs, units with 7.8 GW of capacity, representing 

approximately eight percent of total existing the U.S. nuclear 

generatingfleet 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 in the 

existing nuclear fleet. EIA describes the projected capacity, 

have reductions – which are not yet submitted applications for 

license renewaltied to the projected retirement of any specific 

unit – as necessary to the Nuclear Regulatory Commission. 

Withoutrecognize the “continued economic challenges” faced by 
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the higher-cost nuclear units.152 Likewise, without making any 

judgment about the likelihood that any individual EGU will 

retire, we view this eight5.7 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 for reasons including, but not limited to, additional 

fixed costs related to age and relicensing. 

We believehave determined that, based on available 

information regarding the cost and performance of the nuclear 

fleet, preserving the operation of this existing, at-risk 

nuclear capacity is likely to be a relatively cost-effective 

approach to achieving CO2 reductions from affected EGUs. 

RetainingFor example, retaining the estimated eightseven percent 

of at-risk nuclear capacity could avoid 175200 to 250300 million 

metric tons of CO2.153 over an initial compliance phase-in period 

of ten years.154 According to a recent report, nuclear units may 

be experiencing up to a $6/MWh shortfall in covering their 

 

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

accelerated power plant retirements,” (April 2014). 

153 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/MWh (average 2020 power sector emissions 

intensity as projected in EPA’s IPM Base Case). 

154 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). 

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operating costs with electricity sales.155 Assuming that such a 

revenue shortfall is representative of the incentive to retire 

the estimated eight percent of at-risk nuclear capacity, one can 

estimate the value of offsetting the revenue loss at these atrisk nuclear units to be aboutapproximately $12 to $17 per 

metric ton. EPA views this cost as reasonable. We therefore 

propose that the emission reductions achievable by retaining in 

operation eightsix percent of each state’s existing nuclear 

capacity should be factored into the state goals for the 

respective states. 

 For purposes of goal computation, generation from new and 

preserved nuclear capacity is based on an estimated 90 percent 

average utilization rate for U.S. nuclear units, consistent with 

long-term average annual utilization rates observed across the 

nuclear fleet. The methodology for taking this generation into 

account for purposes of setting state emission rate goals is 

described below in section VII on state goals and in the Goal 

Computation TSD. 

 We invite comment on all aspects of the approach discussed 

above. In addition, we specifically request comment on whether 

we should include in the following questions: Should we 

 

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

Suisse, February 2013 
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estimatestate goals an estimated amount of additional nuclear 

capacity whose construction is sufficiently likely to merit 

evaluation for potential inclusion in the goal-setting 

computation? If so, how should we do so – for example, according 

to EGU owners’ announcements, the issuance of permits, 

projections of new construction by EPA or another government 

agency, or commercial projections? What specific data sources 

should we consider for those permits or projections?. 

c. New NGCC capacity 

 In subsection 2 above, we discussed the opportunity to 

limit CO2 emissions by replacing generation at high carbonintensity affected EGUs with generation from lower-carbon 

generation from existing NGCC units.156 From a technical 

perspective, the same potential would exist to replace highemitting generation with generation from additional NGCC 

capacity that may be built in the future; the analysis above 

regarding the feasibility of policies to increase utilization 

rates of existing NGCC units on average to 70 percent applies 

equally to new NGCC units.157 We view the opportunity to reduce 

 

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

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

157 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 more carbonintensive existing EGUs. Because the proposed state goals also 
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CO2 emissions at affected EGUs by means of addition and operation 

of new NGCC capacity as clearly feasible.

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 could be 

somewhat more costly. Some amount of new NGCC capacity (beyond 

the units that were already under construction as of January 8, 

2014 and are “existing” units for purposes of this proposal) 

would likely be built to meet perceived electricity market 

demand or to replace less economic capacity regardless of this 

proposal. The costs of achieving CO2 emission reductions through 

re-dispatch to these new NGCC units and through re-dispatch to 

existing NGCC units would be comparable. 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 might also be attributable 

to the CO2 reduction opportunity, increasing to some uncertain 

extent the cost of the CO2 reductions at affected EGUs achieved 

through re-dispatch to those new NGCC units.

 

reflect the opportunity to reduce utilization of high carbonintensity EGUs by shifting generation to less carbon-intensive 

EGUs, we believe that in the context of a comprehensive state 

plan, the necessary incentives would likely exist, in which case 

adding new NGCC capacity would tend to reduce CO2 emissions. 
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It is also worth noting that, unlike generation from other 

types of potential new generating capacity such as wind, solar, 

and nuclear capacity, NGCC generation does produce CO2 emissions. 

Because of this distinction it is less apparent that addition of 

new NGCC capacity, as opposed to those other types of capacity, 

should be a primary building block of a strategy for reducing CO2

emissions from the power sector. 

We therefore do not propose any “best practices” quantities 

of new NGCC capacity to include in state goals at this time. 

However, we invite comment on whether new NGCC capacity should 

be reflected as an emission limitation component of the best 

system of emission reduction, recognizing the potential 

effectiveness of adding and operating new NGCC capacity as a 

means of reducing CO2 emissions from affected EGUs. Further, if 

we were to reflect quantities for new NGCC capacity in the state 

goals, how should we determine those quantities – for example, 

according to the issuance of permits, a conservative percentage 

of historic state additions of NGCC capacity, projections of new 

NGCC construction by EPA or another government agency, or 

commercial projections? 

4. Building block 4 – demand-side energy efficiency 

 The third basic category of approaches that create a 

basis for incorporating limiting utilization, and therefore 

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limiting emissions, as anThe fourth element of the foundation 

for EPA’s BSER determination for reducing CO2 emissions fromat

affected fossil fuel-fired EGUs consists ofalso reduces mass 

emissions at all affected EGUs, and entails an analysis of the 

extent to which generation at the affected EGUs can be reduced 

by reducing the demand for generation at those EGUs through

measures that reduce the demand for generation at those sources 

by reducing the overall quantity of generation demanded by endusers.158 

a. Benefits of demand-side energy efficiency 

 Reducing demand for generation at affected EGUs through 

policies to improve demand-side energy efficiency is a proven 

method of reducing CO2 emissions at those EGUs. More than 40 

states haveEvery 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 

 

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

throughout this section includes the residential, commercial and 

industrial sectors. 
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efficiency programs.159 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 

generationsystem costs.160

 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 displaced 

when demand is reduced. Consequently, reductions in fossil fuelfired utilization may be achieved cost-effectively by reducing 

electricity consumption and, by the same token, reductions in 

electricity consumption generally cause reductions in the amount 

of fossil fuel-fired generation, thereby avoiding the CO2

emissions associated with the avoided generation. In this 

manner, in 2011, state demand-side energy efficiency programs 

 

159 Energy Information Administration Form 861, 2012, available 

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

160 See, e.g., McKinsey & Company, Unlocking Energy Efficiency in 

the U.S. Economy (2009), 

http://www.mckinsey.com/client_service/electric_power_and_natura

l_gas/latest_thinking/unlocking_energy_efficiency_in_the_us_econ

omy); Electric Power Research Institute, Assessment of 

Achievable U.S. Energy Efficiency Potential from 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 Economic-Engineering Analysis (Energy Efficiency

and Demand Response Programs in the U.S. (2010–2030): Executive 

Summary (2009, 2014). 
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are estimated to have reduced CO2 emissions by 75 million metric 

tons.161 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 

further reduce carbon intensity. This potential effect 

reinforces the appropriateness of incorporating demand-side 

efficiency improvements in a comprehensive approach to address 

power sector CO2 emissions. In addition to reducing the CO2 

emissions and carbon intensity of the power sector, because it 

drives reductions in fossil fuel usage at EGUs, demand-side 

energy efficiency also reduces 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 

 

161 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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 To estimate the potential CO2 reductions at affected EGUs 

that could be achieved through 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 cost-effective demand-side energy efficiency 

technologies and practices. It does not represent an EPA 

forecast of business-as-usual impacts of state energy efficiency 

policies or an EPA estimate of the full potential of end-use 

energy efficiency available to the power system, but rather is 

intended to representrepresents a feasible policy scenario 

showing the reductions in fossil fuel-fired electricity 

generation resulting from accelerated use of energy efficiency 

policies in all states consistent with a level of performance 

that has already been demonstratedachieved 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, 
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municipal and cooperative electric utilities as well as state 

agencies and third-party administrators. These include energy 

efficiency programs,162 building energy codes, state appliance 

standards (for appliances without federal standards), tax 

credits, and benchmarking requirements for building energy 

use.163 Energy efficiency programspolicies are activities

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 standards164

 

162 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.

163 See the Existing State Actions TSD for descriptions of the 

full array of demand-side energy efficiency policies currently 

employed by states. 

164 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 
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(EERS) to drive investment in energy efficiency programs; some 

have relied on other strategies. According to data and analyses 

from sources including EIA and the American Council for an 

Energy Efficient Economy (ACEEE), as well as the EPA’s own 

analysis; 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.165 The 1.5 percent savings rate is inclusive of, not 

additional to, existing state energy efficiency requirements. 

These savings levels are realized exclusively through the 

adoption and implementation of energy efficiency programs. The 

energy savings and cost data underpinning these analyses are 

derived from energy efficiency program reports required by state 

public utility commissions. and other entities with a similar 

 

efficiency, have been the most impactful state energy efficiency 

strategies in recent years.

165 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 

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

Greenhouse Gas Abatement Measures TSD for more information.

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oversight role.166 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.167 

While EM&V data reflect documented electricity savings from 

energy efficiency programs, they typically do not account for 

potential electricity savings available from additional stateimplemented policies for which EM&V protocols are less 

consistently required or applied, such as building energy codes. 

Thus, we consider the 1.5 percent annual incremental savings168

rate to be a reasonable estimate of the energy efficiency policy 

performance that is already achieved or required by leading 

 

166 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. 

167 See the EM&V section of the state Plan TSD for more 

information on EE program evaluation. 

168 This incremental savings rate and all others discussed in 

this section 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. 
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states and that can be achieved cost-effectively 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 with more limited EE program experience, 

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 rate169 to a 

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

(Thus, the goal for each state differs to reflect the assumption 

that a state already close to a 1.5 percent annual incremental 

savings rate can expand its energy efficiency programs to reach 

that rate more quicklysooner than 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 

 

169 2012 is the most recent year for energy efficiency program 

incremental savings data reported using EIA Form 861.
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leading states.170 For states already at or above the 1.5 percent 

annual incremental savings rate, (based on 2012 reported data),

we estimate that they would sustainrealize a 1.5 percent rate in 

2017 and maintain that rate through 20302029. For all states we 

assume the initial savings rate (the lower of their 2012 value 

or 1.5 percent) is realized in 2017 and increases each year by 

0.2 percent until the target rate of 1.5 percent is achieved.171

and is then maintained at that level through 2029 The savings 

from energy efficiency programs are cumulative, meaning that, in 

simplified terms, a state implementing a sustained program with 

a 1.5 percent annual incremental savings rate could expect 

cumulative annual savings of approximately 1.5 percent after the 

first year, 3.0 percent after the second year, 4.5 percent after 

the third year, and so on. Savings from the first year would 

drop off at the end of the average life of the energy efficiency 

program portfolio (typically about ten years). Accordingly, we 

have projected the cumulative annual savings for each state that 

would be achieved for the period 2020 to 2029 based on the 

 

170 See the Greenhouse Gas Abatement Measures TSD for more 

information. 

171 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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state’s reaching and then sustaining the best practices annual 

incremental savings rate through 2029. To determine the avoided 

MWh quantities of generation thatThese values, for each state 

and for each year (2020-2029), are used in the procedure for 

computing the state goals described above, the cumulative 

percentages for each state are multiplied by the state’s 2012 

historical electricity sales reflected in EIA’s detailed state 

data.172in section VII.C below. 

 As indicated abovediscussed in section VII.E below, the EPA 

is also taking comment on a less stringent alternative for goalsetting state goals. Under this approachalternative, the demandside energy efficiency requirement is relaxed by using 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 historichistorical levels is relaxed 

slightly to 0.15 percent per year (rather than 0.2 percent). The 

1.0 percent rate of savings is a level of performance that has 

been achieved - or that established state requirements will 

 

172 EIA, Retail Sales of Electricity by State by Sector by 

Provider, Nov. 12, 2013, available at 

http://www.eia.gov/electricity/data/state/. The data are 

adjusted to reflect transmission and distribution losses.

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cause to be achieved - by 20 states.173 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 5. 

Table 5: Demand-Side Energy Efficiency State Goal Development: 

Cumulative Annual Electricity Savings (Percentage of Annual 

Sales) Resulting from Best Practices Scenario174

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% 

 

173 See the Greenhouse Gas Abatement Measures TSD for more 

information.

174 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 programspolicies as reflected in the best practices 

scenario to be a highly cost-effectiveachievable at reasonable 

costs and believes that this represents a technically feasible

approach to reducing greenhouse gas emissions from the existing 

fossil fuel-fired EGUs. 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, EPA’s analysis of the power sector 

indicates that the costs are reasonable. 

The processes by which states develop funding for 

theseenergy efficiency programs typically require the 

application of cost-effectiveness tests to ensure that adopted 

program portfolios lead to lower costs than the use of 

generation sources that would otherwise be required to meet the 

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associated electricity service demands. Indeed, a major reason 

for the widespread presence and rapid growth of demand-side 

energy efficiency programs is the strong evidence of their costeffectiveness even before the additional benefit of CO2

reductions is considered.175 Federal and independentIndependent

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.176 In our view, theThese factors mentioned above

indicate that the cost of CO2 reductions achieved through 

implementation of demand-side energy efficiency at the levels 

reflected in the best practices scenario isare likely to be very 

low and may even be less than $0 per metric tonreasonable, 

 

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

their evaluations of cost effectiveness.

176 E.g., Electric Power Research Institute, Assessment of 

Achievable Potential from U.S. Energy Efficiency and Demand 

Response Programs in the U.S. (2010-2030) (Jan. 2009), available 

at 

http://www.epri.com/abstracts/pages/productabstract.aspx?Product

ID=000000000001016987;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/.
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typically resulting in reductions in average electricity bills 

across all end-use sectors.177

 Another approach to evaluating the cost 

effectivenessreasonableness of demand-side efficiencythe costs 

associated with this building block is to compare its cost 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 historical studies 

ofdata and analysis of the factors that impact energy efficiency 

program costs. Specifically, cost estimates were developed by 

applying a uniform levelized average cost per kWh of saved 

energy across the life of the energy efficiency investments. The 

cost per kWh 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 

 

177 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 be a highly cost -effective approach to 

reducing CO2 emissions even for a state whose own affected EGUs 

achieve only part of the CO2 emission reduction benefit from the 

state’s demand-side energy efficiency efforts. 
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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, EPA has included a cost 

escalation factor to represent the possibility of increased 

costs associated with higher levels of incremental energy 

savings rates and the national scope of the best practices 

scenario. 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 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. Because we did not attempt to estimate the energy 

savings that could be achieved through state-implemented 

policies incremental to energy efficiency programs, such as 

building energy codes or state appliance standards, we did not 

consider those policies in our cost estimates. 

 The estimated cost per kWh was selected based on several 

previous reviews of studiesThese costs are levelized across the 

measure lifetimes of a full portfolio of energy efficiency 
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Page 226 of 639

program costs using engineering-based, bottom-up estimates of 

the average cost of saved energy under various programs.178 For 

example, an EPA review conducted in 2009 found a This analysis 

provides a levelized cost of saved energy (LCOSE) range of 

annualized costs between $12 and $52 per MWh of electricity 

saved,179 while a more recent review from $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 

derived a cost of $51 per MWh of electricity saved.(ACEEE) 

surveyed program and participant cost results across seven 

states and found a comparable LCOSE value of $54/MWh (2011$).180 

We have evaluated cost effectiveness of To estimate the 

reductions in power system costs and CO2 emissions associated 

 

178 All states that implement ratepayer-funded energy efficiency 

programs (more than 40) employ engineering-based, bottom-up 

estimation methods as their primary basis for analyzing the 

associated costs and benefits.

179 U.S. EPA, Energy Efficiency as a Low-Cost Resource for 

Achieving Carbon Emissions Reductions (Sept. 2009), available at 

http://www.epa.gov/cleanenergy/documents/suca/ee_and_carbon.pdf.

180 American Council for an Energy-Efficient Economy, Saving 

(ACEEE), The Best Value for America’s Energy CostEffectivelyDollar: A National Review of the Cost of Energy Saved 

Through Utility-Sector Energy Efficiency Programs (Report No. 

U092, Sept. 2009), available at 

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

ports/U092.pdf.U1402, March 2014).

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with the best- practices level of demand-side energy efficiency 

scenario using a cost range of $71 to $88 average cost per MWh 

of electricity saved. This is a conservatively high estimate 

based on the literature,described above, EPA analyzed a scenario

incorporating cost escalation over time to account for possible 

effects of the substantial level of national demand reductions 

reflected in the best-practices scenario. Even at this 

conservatively high cost, the EPA believes that the bestpractices demand-sidethe 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 scenario would represent a cost-effective approach to 

reducing GHG emissions from affected fossil fuel-fired EGUs. 

This cost is comparable to the estimated levelized cost of 

building and operating a new NGCC unit, at $64 to $83 per MWh 

(as estimatedcost estimates associated with the best practices 

scenario, EPA derived net cost impacts for 2020, 2025, and 2030. 

Dividing these net cost impacts by the EPA using data inputs 

similar to those of the IPM 5.13 base case, dependent on gas 

price), even before the benefit of lower CO2 emissions is 

considered. 
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 Recognizing this associated CO2 reductions for each year, 

EPA found that the average cost of the CO2 reductions achieved 

ranged from $16 to $24 per metric ton of CO2. EPA views these 

estimated costs as reasonable. Together with the history of 

demonstrated successful state implementation of cost-effective 

demand-side energy efficiency programs, discussed above, this 

analysis supports the EPA proposes to find that for purposes of 

establishing state goals, a reasonable estimatereasonableness 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 costeffectively achieved is the amount resulting from implementation 

of a comprehensive setconsistent with achievement of that level

of demand-side energy efficiency programs at a level consistent 

with the best practices scenario discussed above.. 

 Further details regarding the data and methodology used to 

evaluate the potential for demand-side energy efficiency 

programs to cost-effectively reducesubstitute 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 
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Page 229 of 639

practices suitable for inclusion inrepresentation 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 incremental annual 

electricity savings, and 3) alternative approaches and/or data 

sources for evaluating costs associated with implementation of 

state demand-side energy efficiency policies.

5. Potential emission reduction measures not used to set 

proposed goals 

 There are twothree additional potential measures for 

reducing GHG emissions from EGUs that the EPA does not propose 

to consider part of the best system of emission reduction for 

existing EGUs at this time and therefore has not used for goalsetting purposes, but that merit discussion here: fuel switching 

at individual EGUs, and carbon capture and storage (CCS).), and 
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Page 230 of 639

reducing emissions at affected fossil fuel-fired steam EGUs by 

using expanded amounts of less carbon-intensive new NGCC 

capacity to provide replacement generation. 

 a. Fuel switching at individual units 

 One technically feasible approach for reducing CO2 emissions 

per MWh of generation from an EGU designed for coal-fired 

generation is to substitute natural gas for some or all of the 

coal. Most existing coal-fired steam EGU boilers can be modified 

to switch to 100 percent gas input or to co-fire gas with coal 

in any desired proportion. For certain individual EGUs, 

switching to or co-firing with gas may be an attractive option 

for reducing CO2 emissions. 

 Changing the type of fuel burned at a steam EGU typically 

requires certain plant modifications (e.g., new burners) and may 

have some negative impact on the net efficiencies of the boiler 

and the overall generation process. If the plant lacks existing 

gas pipeline infrastructure capable of delivering the necessary 

quantities of natural gas to the boiler, installation of a new 

pipeline lateral would also be required. 

 The capital costs of plant modifications required to switch 

a 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 
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new pipeline laterals is approximately $1 million per mile of 

pipeline built. Offsetting these capital costs, conversion to 

100 percent gas input would typically reduce the EGU’s fixed 

operating and maintenance costs by about 33 percent due mainly 

to certain equipment retirements and a reduction in staffing, 

while non-fuel variable costs would be reduced by about 25 

percent due to reduced maintenance and waste disposal costs. 

However, in most cases, the most significant cost change 

associated with switching from coal to gas in a coal-fired 

boiler is likely to be the difference in fuel cost. Using EIA’s 

projections of future coal and natural gas prices, switching a 

steam EGU’s fuel from coal to gas typically would more than 

double the EGU’s fuel cost per MWh of generation. 

 The CO2 reduction potential of natural gas co-firing or 

conversion is due largely to the different carbon intensities of 

coal and natural gas and is directly related to the proportion 

of gas burned. Greater reductions in the CO2 emission rate are 

achieved at higher proportions of gas usage. For example, at ten 

percent gas co-firing, the net emission rate (e.g., pounds of CO2

per net MWh of generation) of a typical steam EGU previously 

burning only coal would decrease by approximately four percent. 

At 100 percent gas burn, the net emission rate of a typical 
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Page 232 of 639

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 $6783 per metric ton to $109150 per metric 

ton. The low end of the range of CO2 reduction costs represents a 

100 percent switch to gas, because in instances where a 

combination of coal and gas is burned, the EGU would continue to 

bear the fixed costs associated with equipment needed for coal 

combustion, raising the cost per ton of CO2 reduced. 

 The EPA’s economic analysis suggests that there are more 

cost effective opportunities for coal-fired utility boilers to 

reduce their CO2 emissions than through natural gas conversion or 

co-firing. As a result, the EPA has not proposed at this time to 

include this option in the BSER and has not incorporated 

implementation of the option into the proposed state goals. 

However, the EPA believes that there are a number of factors 

that warrant further consideration in determining whether the 

option should be included. First, the EPA is aware that a number 

of utilities have reworked some of their coal-fired units to 

allow for some level of natural gas co-firing (and in some cases 

have converted the units to fire entirely on natural 
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gas). Second, the EPA is aware of several possible reasons 

beyond reduction of CO2 emissions that may make natural gas cofiring economic in some circumstances. One example is that 

natural gas reburn strategies that involve co-firing with 10 to 

20 percent natural gas can be an effective control strategy for 

NOx emissions and, thus, can offset operational (and in some 

cases, capital) costs associated with other NOx controls such as 

SCR or SNCR. A second example suggested by some vendors is that 

the capability to burn natural gas in a coal-fired boiler can 

improve economics because it allows the boiler to operate more 

effectively at lower loads. A third example, applicable to units 

that run infrequently but may be needed for reliability 

purposes, is that converting to or co-firing with natural gas 

may be more economic than either installing non-CO2 emission 

controls or taking other measures, such as transmission 

upgrades, that could be associated with retiring the 

unit. Finally, beyond the reasons just described 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 
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Page 234 of 639

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 storage181 technology (CCS). In the recently 

proposed standards of performance for new fossil fuel-fired EGUs 

(79 FR 1430), the EPA proposed to find that the best system of 

emission reduction for new fossil fuel-fired boilers and IGCC 

units is partial application of CCS. In that proposal, the EPA 

found that, for new units, partial CCS has been adequately 

demonstrated; it is technically feasible; it can be implemented 

at costs that are not unreasonable; it provides meaningful 

emission reductions; and its implementation will serve to 

promote further development and deployment of the technology. 

The EPA also noted in the proposal that most of the relatively 

few new boiler and IGCC EGU projects currently under development 

are already planning to implement CCS; and, as a result, the 

proposed standard would not have a significant impact on 

nationwide energy prices. 

 

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

sequestration.”
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In contrast, the EPA noted that identifyingdid not identify 

full or partial CCS as the BSER for new natural gas-fired 

stationary combustion turbines would likely result in higher 

nationwide electricity prices and could adversely affect the 

supply, noting technical challenges to implementation of 

electricity, because the majority of new CCS at NGCC units as 

compared to implementation at new solid fossil- fuel -fired 

generating capacity issources. The EPA also noted that, because 

virtually all new fossil fuel-fired power projects are projected 

to consistuse NGCC technology, requiring full or partial CCS 

would have a greater impact on the price of electricity than 

requiring CCS at the few projected coal plants, and the larger 

number of NGCC projects would make a CCS requirement difficult 

to implement in the short term.

 Partial CCS has been demonstrated at existing EGUs. It has 

been demonstrated at a pilot-scale at Southern Company’s Plant 

Barry; it is being installed for large-scale demonstration at 

NRG’s W.A. Parish facility; and it is expected soon to be 

applied at commercial-scale as a retrofit at SaskPower’s 

Boundary Dam plant in Canada. However, the costs of integrating 

a retrofit CCS system into an existing facility would be 

expected to be substantial. For example, some existing sources 

have a limited footprint and may not have the land available to 

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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, but does not expect to finalize CCS as a 

component of BSER in this rulemaking. It should be noted, 

however, that in light of the fact that several existing fossilfired EGUs are currently being retrofitted with CCS, the 

implementation of partial CCS may be a viable GHG mitigation 

option at some facilities, and as a result, emission reductions 

achieved through use of the technology could be used to help 

meet the emission performance level required under a state plan.

Additional discussion can be found in the Greenhouse Gas 

Abatement Measures TSD. We invite comment on this proposed 

finding. 

c. New NGCC capacity 

 In subsection 2 above, we discussed the opportunity to 

reduce CO2 emissions by replacing generation at high carbon-
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Page 237 of 639

intensity affected EGUs with generation from lower-carbon 

generation from existing NGCC units.182 From a technical 

perspective, the same potential would exist to replace highemitting generation with generation from additional NGCC 

capacity that may be built in the future; the analysis above 

regarding the feasibility of policies to increase utilization 

rates of existing NGCC units on average to 70 percent applies 

equally to new NGCC units.183 We view the opportunity to reduce 

CO2 emissions at affected EGUs by means of addition and operation 

of new NGCC capacity as clearly feasible.

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 could be 

somewhat more costly. 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 

 

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

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

183 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 more carbonintensive existing EGUs. Because the proposed state goals also 

reflect the opportunity to reduce utilization of high carbonintensity EGUs by shifting generation to less carbon-intensive 

EGUs, we believe that in the context of a comprehensive state 

plan, the necessary incentives would likely exist, in which case 

adding new NGCC capacity would tend to reduce CO2 emissions. 
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demand or to replace less economic capacity regardless of this 

proposal. The costs of achieving CO2 emission reductions through 

re-dispatch to these new NGCC units and through re-dispatch to 

existing NGCC units would be comparable. 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 might also be attributable 

to the CO2 reduction opportunity, increasing to some uncertain 

extent the cost of the CO2 reductions at affected EGUs achieved 

through re-dispatch to those new NGCC units.

Moreover, unlike generation from other types of potential 

new generating capacity such as wind, solar, and nuclear 

capacity, NGCC generation does produce CO2 emissions. Because of 

this distinction it is less apparent that addition of new NGCC 

capacity, as opposed to those other types of capacity, should be 

a primary building block of a strategy for reducing CO2 emissions 

from the power sector. units.

 Partial CCS has been demonstrated at existing EGUs. It has 

been demonstrated at a pilot-scale at Southern Company’s Plant 

Barry; it is being installed for large-scale demonstration at 

NRG’s W.A. Parish facility; and it is expected soon to be 

applied at commercial-scale as a retrofit at SaskPower’s 

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Boundary Dam plant in Canada. However, the costs of integrating 

a retrofit CCS system into an existing facility would be 

expected to 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, but does not expect to finalize CCS as a 

component of BSER in this rulemaking.

It should be noted, however, that in light of the fact that 

several existing fossil-fired EGUs are currently being 

retrofitted with CCS, the implementation of partial CCS may be a 

viable GHG mitigation option at some facilities, and as a 

result, emission reductions achieved through use of the 

technology could be used to help meet the emission performance 

level required under a state plan.
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Additional discussion can be found in the Greenhouse Gas 

Abatement Measures TSD. We invite comment on this proposed 

finding. 

DWe therefore do not propose any “best practices” 

quantities of new NGCC capacity to include in state goals. 

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 is comprised only 

of building blocks 1 and 2 with the merits of a BSER that is 

comprised of 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 the BSER 

follows in section VI.E.) 

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 
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substituting generation at those EGUs with generation from 

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 comprised of only 

strategies within building block 1. As described earlier in 

subsection 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 
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measures that improve heat rates at coal-fired steam EGUs in 

building block 1 are implemented in isolation, without 

additional measures that reduce overall electricity demand or 

encourage substitution of less carbon-intensive generation for 

more carbon-intensive generation, the resulting increased 

efficiency of coal-fired steam units would provide incentives to 

operate those EGUs more, leading to smaller overall reductions 

in CO2 emissions. Further, in listening sessions and other 

outreach meetings, the EPA learned that states and other sources 

were already implementing and pursuing strategies in the other 

building blocks for the purpose, at least in part, of reducing 

CO2 emissions. 

2. A combination of building blocks 1 and 2 as the Best System 

of Emission Reduction 

We considered a BSER that is comprised of 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 comprised of 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 subsection 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 it fails to 

encompass the additional measures – building blocks 3 and 4 – 
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that we and stakeholders have identified as already in use and 

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 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 comprised of 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 subsection VI.C above, each of 

the four building blocks is a proven way to support either 

improvements in emissions rates at affected EGUs or reductions 

in EGU mass emissions; each is in widespread use and is 

independently capable of supporting significant CO2 reductions 

from affected EGUs, either on an emission rate or mass-emissions 

basis, at a reasonable cost consistent with ensuring system 
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reliability. As discussed in subsection 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 electric system, where 

electricity is fungible and the demand for electricity services 

can be met in many ways (including through demand-side energy 

efficiency), states and the industry have long pursued a wide 

variety of strategies for ensuring that the demand for 

electricity services is met reliably, at reasonable costs, and 

in a manner consistent with evolving constraints, including 

environmental objectives. These strategies have long extended to 

the measures in all four building blocks. We believe the 

combination of all four building blocks fairly represents the 

range of measures that states and the industry will consider 

when developing state plans and strategies for reducing CO2

emissions from affected EGUs while continuing to meet demand for 

electricity services reliably and affordably. As such, we 

believe it is appropriate to consider that same combination as 
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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 

 The EPA is proposing that the measures in the 4four

building blocks, taken together, constitute described in the 

preceding subsections are essential features of the “best system 

of emission reduction ... adequately demonstrated” (BSER) for 

the standards of performance that the section 111(d) state plans 

must apply to affected EGUs. There are two Specifically, the EPA 

is proposing alternative, but complementary, approaches to 

explaining how the building blocks provide the basis of the 

proposed determination of formulations for the BSER.

Both approaches are based on the fact that the measures 

described in the four building blocks meet the criteria 

specified in the statute and are currently used by owners of 

EGUs across the country to reduce CO2 emissions. 

 The first Under one approach is that the building blocks 

encompass two sets of measures that the affected EGUs may apply 

to their own operations to reduce their emissions: (i) 

undertaking equipment and process changes that improve 

efficiency (building block 1 -- heat, emission rate 

improvements), and (ii) reducing and mass emission reductions 

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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 an alternate 

approach, BSER consists of building block 1 coupled with reduced 

utilization to the extent of the availability of lowerin 

specified amounts from higher-emitting fossil-generation, zeroemitting generation, and demand reduction by means of end use 

energy efficiencyEGUs. Under this latter approach, the measures 

(in building blocks 2, 3, and 4, respectively). The second 

approach treats building block 1 serve to justify those amounts 

and the same as under“adequate[] demonstrat[ion]” because they 

are proven measures that are already being pursued by states and

the first approach, but treats building blocks 2, 3, and 4 as 

parts ofindustry, at least in part for the integrated 

electricity system that have the effectpurpose of reducing 

utilization at theCO2 emissions from affected EGUs.

 The remainder of this discussion is organized into nine 

subsections. Subsection 2 contains a summary of relevant 

considerations for the BSER as defined in the statute and 

further interpreted in court decisions. Subsection 3 discusses 

characteristics of the electricity industry relevant to 
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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. In 

subsection 6, we describe and seek comment on the alternate 

interpretation that the BSER includes, in addition to one or 

more of the building blocks, a component consisting of reduced 

generation from 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 7 we discuss the discretion that the case law gives 

us in weighing the various criteria to determine the BSER. The 

final three subsections address the topics of combining source 

categories, severability, and certain other specific issues on 
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which we are seeking comment. Additional discussion is provided 

in the Legal Memorandum available in the docket. 

2. Statutory and regulatory provisions as well as EPA 

interpretationrelated to determination and application of the 

BSER

 The EPA’s explanation for this BSER proposal begins with 

the statutory definition of a “standard of performance”: 

The term “standard of performance” means a standard for 

emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of 

the best system of emission reduction which (taking into 

account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy 

requirements) the Administrator determines has been 

adequately demonstrated. 

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

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

Circuit or Court) has handed down case law over a 40-year period 

that interprets this CAA provision, including its component 

elements.184 Under this case law, the EPA determines the BSER 

 

184 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. 

Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 

(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 

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based on the following key considerations, among others: 

 The system of emission reduction must be technically 

feasible. 

 The EPA must consider the amount of emissionsemission

reductions that the system would generate. 

 The costs of the system must be reasonable. The EPA may 

consider the costs onat the source level, the industry-wide

level, and, at least in the case of the power sector, on

the national level in terms of the overall costs of 

electricity and the impact on the national economy over 

time.185 

 The EPA must also consider that CAA section 111 is designed 

to promote the development and implementation of 

technology. 

Other considerations are also important, including that the 

 

1981); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. Cir. 

2011). 

185 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 427, 433 (D.C. Cir. 1973), see Lignite 

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

“greater than the industry could bear and survive,” Portland 

Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or 

“excessive” or “unreasonable.”,” Sierra Club v. Costle, 657 F.2d 

298, 343 (D.C. Cir. 1981). In the January 2014 Proposal, the EPA 

stated that “these various formulations of the cost standard ... 

are synonymous,” and, for convenience, EPAwe used 

“reasonableness” as the formulation. EPA takesWe take the same 

approach in this rulemaking. 

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EPA must also considerAnother consideration particularly 

relevant to this rulemaking is energy impacts, andwhich, as with 

costs, EPA may consider them onat the source level, the industry 

level, and on the nationwide structure of the power 

sectornational level over time. In the context of the 

electricity industry and this proposal, 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. 

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. 

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 in this rulemaking. 

 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. 
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Because electricity is costly to store, 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 (ISO/RTOs), and market mechanisms. The electricity 

sector is both critical to the nation’s economy and the source 

of more than 30 percent of U.S. greenhouse gas emissions, 

predominantly in the form of CO2. 

The integrated electricity system allows increased 

generation from less carbon-intensive NGCC units to substitute 

for generation from more carbon-intensive steam EGUs (building 

block 2), thereby lowering CO2 emissions from the group of 

affected EGUs as a whole. The electricity system similarly 

allows increased generation resulting from expansion of the 

amount of available low- or zero-carbon generating capacity 

connected to the electric grid (building block 3), as well as 

avoided generation resulting from reductions in electricity 

demand (building block 4), to substitute for fossil fuel-fired 

generation, thereby reducing CO2 emissions from affected EGUs. 
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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 

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 
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programs that states could use as a compliance option.186 Each of 

these programs was designed to take advantage of the fact that 

in an integrated electricity system, some EGUs can reduce 

emissions more cost-effectively than others, and that by 

allowing the industry to determine through market mechanisms 

which EGUs to control, and potentially operate more, and which 

to leave uncontrolled, and 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 electricity 

demand can be reliably met. It is worth noting that adoption by 

affected EGUs of any of the measures in the building blocks 

could be (or could have been) used to facilitate compliance with 

each of the programs just described. 

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.187 California 

 

186 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. 

187 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 
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and Colorado provide two examples of how statewide targets (or 

company-wide targets within a state) can be designed with 

consideration of the wide range of CO2 mitigation options and 

affected EGUs’ flexibility to use those options. 

California enacted its Global Warming Solutions Act (also known 

as AB32) in 2006, requiring the state to reduce its GHG 

emissions to 1990 levels by 2020 and 80 percent below 1990 

levels by 2050.188 According to California, “the integrated 

nature of the 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.”189 In the 

framework regulations, the EPA interpreted CAA section 111(d) as 

giving the agency the authority to determine the required 

 

Austin Energy, 

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

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 

188 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.pdfhttp://www.leginfo.ca.gov/

pub/05-06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdf. 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy. Formatted: Font: (Default) Courier New
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stringency of the standards of performance established for 

affected existing sources and, as noted, we are not re-opening 

that interpretation in this rulemaking. Under the framework 

regulations, each guideline document is to contain an emission 

guideline that reflects the application of the BSER to affected 

sources. 40 CFR 60.22(b)(5). 

3. Heat rate improvement and reduction in utilization approach 

The first approach EPA is proposing as the basis for 

determining that the 4 building blocks constitute the “best 

system of emission reduction ... adequately demonstrated” is 

that they consist of two sets of measures that the affected EGUs 

may apply to their own operations to reduce their emissions – 

equipment and process changes that improve heat rate, and 

reduction of utilization – and each of those sets of measures 

meets the criteria to qualify as a component of the BSER. 

The measures in building block 1 (heat rate improvements) 

entail improvements in the efficiency of the affected EGU’s 

equipment or processes. The measures in the building block 2 

entail reductions in generation by the fossil-fired steamgenerating EGUs, with the amount of reduced generation 

corresponding to the amount of increased generation available at 

natural gas combined cycle units. The measures in building 

blocks 3 and 4 entail reductions in generation by the fossil-
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fired EGUs, with the amount of reduced generation corresponding 

to the amount of new low- or zero-carbon generation and 

increased demand-side energy efficiency that is available. 

Each of these sets of measures is technically feasible. As 

the above discussion of the building blocks indicates, the 

measures that result in heat rate improvements are wellestablished. Reducing generation of higher emitting units either 

by shifting generation to lower, or zero emitting units or by 

using demand side strategies that provide the same underlying 

services with less electricity is also technically feasible and 

widely used, as discussed below. 

In addition, as noted in the above discussion of the 

building blocks, each of the sets of measures results 

ineffective in reducing emissions. Moreover, their costs and 

energy impacts 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 cap-and-trade program, along with 

other programs.190 The California plan has put in place 

 

190 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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mechanisms that through market dynamics affect both companies’ 

longer-term planning decisions and their short-term dispatch 

decisions. The need to hold emissions allowances and the reduced 

demand from demand-side energy efficiency programs impact 

longer-term decisions companies make about investment in both 

existing and new EGUs. The price of emission allowances also 

impacts hourly dispatch decisions; where emission allowance 

requirements are in effect, EGU owners routinely recognize the 

costs of emission allowances as components of the variable 

operating costs that are relied on for these decisions.191 In 

this manner, allowance prices constitute market signals 

encouraging reduced use of higher-emitting EGUs and increased 

use of lower-emitting EGUs. 

The Colorado Clean Air Clean Jobs Act (CACJA), signed into 

law on April 19, 2010, required each investor-owned utility with 

coal-fired EGUs to submit to the state a multi-pollutant plan 

for meeting current and foreseeable EPA standards for emissions 

of NOx, SO2, particulates, mercury, and CO2. Rather than fully 

prescribing specific control technologies, the law provided 

flexibility for each utility to select the best set of measures 

 

191 The requirement to hold allowances covering their CO2

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

2013. 
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to achieve the emission reductions.192 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 

efficiency measures.193 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. 

Regional mechanisms with analogous impacts on both longerterm planning decisions and short-term dispatch decisions have 

also been put in place. For example, nine northeastern and MidAtlantic States194 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 

 

192 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. 

193 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. 

194 Participating states include Connecticut, Delaware, Maine, 

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

and Vermont. 
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in each compliance period - through purchases or by allocation 

from the state – and must surrender the allowances at the end of 

the period. The RGGI program offers flexibility to regulated 

parties through provisions for multi-year compliance periods, 

allowance banking, offsets, an auction reserve price, and a 

cost-containment reserve of allowances, and further encourages 

emission allowance market development by authorizing trading 

between regulated and non-regulated parties.195 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 electric 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 electricity demand in a costeffective 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 

 

195 See RGGI website at http://www.rggi.org/rggi. 
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(RTOs) or independent system operators (ISOs) ensure the 

adequacy of future generation supplies by administering auctions 

for forward capacity. In these auctions, owners of existing EGUs 

(with consideration of building blocks 1 and 2),196 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. 

Importantly, experience has shown that because the grid is 

interconnected, CO2 emissions reductions can be achieved through 

several different mechanisms, which differ primarily in their 

 

196 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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timing and in the extent of their advance planning: (i) 

Establishing and implementing a plan in advance under which a 

specific amount of generation from higher-emitting fossil fuelfired EGUs is substituted for the same amount of generation 

from, or avoided from, specific measures in building blocks 2, 

3, and 4. (ii) Instituting measures in building blocks 2, 3, and 

4, which, because of the interconnected nature of the grid, 

result in drawing utilization away from higher-emitting fossil 

fuel-fired EGUs, even in the absence of a plan in advance that 

targets those EGUs. (iii) Reducing utilization from higheremitting fossil fuel-fired EGUs, which because of the 

interconnected nature of the grid and its operation in the 

regulated markets, leads to the measures in building blocks 2, 

3, and 4 that develop or utilize replacement generation or 

demand-side energy efficiency, even in the absence of a plan in 

advance that includes those measures. The existence of these 

mechanisms supports what we propose in this rulemaking as the 

two alternative “best system[s] of emission reduction ... 

adequately demonstrated,” as discussed below. 

4. Evaluation of individual building blocks against the BSER 

criteria 

In this section we explain why (i) the individual building 

blocks meet the criteria to qualify as components of the “best 
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system of emission reduction ... adequately demonstrated” and 

(ii) why, under the alternative formulation of BSER as including 

reduced utilization of higher-emitting generating capacity 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 

BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable through heat rate improvements are discussed in 

section VI.C.1 above. We consider heat rate improvement to be a 

common and well-established practice within the industry. 

 Other BSER criteria also favor building block 1 as a 

component of 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 
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the adverse impacts associated with disposal of coal combustion 

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 considered whether enhanced maintenance 

practices leading to heat rate improvements might also lead to 

electric reliability improvements, but does not expect there 

would be any negative impact on reliability. 

 As noted above, the EPA is concerned about the potential 

“rebound effect” associated with building block 1 if applied in 

isolation. More specifically, we noted that in the context of 

the integrated electricity system, absent other incentives to 

reduce generation and CO2 emissions from coal-fired EGUs, heat 

rate improvements and consequent variable cost reductions at 

those EGUs would cause them to become more competitive compared 

to other EGUs and increase their generation, leading to smaller 

overall reductions in CO2 emissions (depending on the CO2

emission rates of the displaced generating capacity). However, 

we believe that this concern can be readily addressed by 

ensuring that the BSER also reflects other CO2 reduction 

strategies that discourage overall increases in coal-fired 

generation or fossil fuel-fired generation, thereby allowing 
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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 (including NGCC units under construction) – is a 

component of the BSER because the shifts in generation that it 

involves demonstrate that reducing mass CO2 emissions at higheremitting EGUs is technically feasible, will not jeopardize 

system reliability, is of reasonable cost, and meets the other 

requirements for a component of the BSER. 

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 
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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. There is a long-term industry trend away from 

coal-fired generation and toward NGCC generation. States can 

encourage this trend in a variety of ways. First, a state could 

use its permitting authority to impose limits on the hours of 

operation (or emissions) of individual steam generating units 

over a given time period. Second, a state could change the 

relative costs of generation for more carbon-intensive and less 

carbon-intensive generating units by imposing a cost on carbon 

emissions. A state could do so through any of several marketbased 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 
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incentive for the most carbon-intensive affected sources to 

reduce emissions as much as possible so as to reduce their need 

to purchase allowances (or to allow them to sell 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. 

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.197 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. 

 

197 Some NGCC units use air rather than water for cooling 

purposes. 
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It should be observed that, by the building block’s 

definition, the shifts in generation taking place under building 

block 2 occur entirely among existing EGUs subject to this 

rulemaking.198 Through application of this building block 

considered in isolation, some affected sources – mostly coalfired steam EGUs - would reduce their generation and CO2

emissions, while other affected sources – NGCC units – would 

increase their generation and CO2 emissions.199 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 

 

198 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. 

199 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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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. 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, reduced 

generation from fossil fuel-fired steam EGUs is a component of 

the BSER. The potential to use increased generation from less 

carbon-intensive NGCC units would serve as a basis for 

quantifying the amounts of generation reductions and CO2 emission 

reductions at more carbon-intensive 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.6 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 
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amounts of low- and zero-carbon generating capacity – is a 

component of the BSER because the expansion and use of renewable 

generating capacity, completion and use of new nuclear capacity, 

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 BSER. 

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 can 

and do establish targets for procurement of renewable generating 

capacity. Moreover, a market for renewable energy certificates, 

which facilitates investment in renewable energy, is already 

well-established. In addition, 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 by substituting for their generation with 

generation from renewable energy. In addition, owners of 

existing nuclear units and new nuclear units under construction 
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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, 

as discussed above renewable generation has grown quickly in 

recent years, and the EPA has seen no evidence that operators 

will be less able to cope with future growth than they have with 

rapid past growth. Further, if a state were concerned that 

increasing the use of NGCC capacity might create risks to 
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reliability in the form of potential inadequacies in natural gas 

infrastructure, use of expanded renewable generation capacity 

could help address that concern. 

The EPA believes that the performance of the nuclear 

measures in building block 3 against the other BSER measures is 

acceptable. With respect to encouragement of technological 

innovation, incentives for completion of new nuclear capacity 

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. Use 

of expanded nuclear capacity would be another way for a state to 

address any concern that increasing the use of NGCC capacity 

might create risks to reliability in the form of potential 

inadequacies in natural gas infrastructure. New nuclear units 

would have closed-cycle cooling systems with lower cooling water 

usage than some existing fossil fuel-fired EGUs; existing 

nuclear units may use amounts of cooling water comparable to the 

amounts used by those fossil fuel-fired steam EGUs. The EPA 

recognizes that nuclear generation poses unique waste disposal 

issues (although it avoids the solid waste issues specific to 

coal-fired generation). However, we do not consider that 
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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 under 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.6 below. 

d. Building block 4 – increased demand-side energy 

efficiency 

Building block 4 – reducing CO2 emissions at and reducing 

generation from affected EGUs by promoting demand-side energy 

efficiency that reduces the amount of generation required from 

affected EGUs – is a component of the BSER because the demandside energy efficiency is technically feasible and of reasonable 

cost, and meets the other requirements for a component of the 

BSER. 
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The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the 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. States can and do 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 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 
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energy efficiency is also consistent with the goals of 

encouraging technological innovation in energy efficiency and 

encouraging deployment of current advanced technologies. For all 

these reasons, the measures in building block 4 qualify as a 

component of the “best system of emission reduction ... 

adequately demonstrated.” 

The EPA notes that the alternative BSER discussed later 

would include a component consisting of reduced generation from 

affected EGUs, with demand-side energy efficiency serving as a 

basis for quantifying the amounts of generation reductions and 

consequent CO2 emission reductions that can be achieved while 

continuing to meet the demand for electricity services in a 

reliable and affordable manner. This alternate interpretation of 

the BSER is discussed in section VI.E.6 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 
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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 noted earlier. 

That concern is the potential for the heat rate improvements in 

building block 1, if implemented in isolation, to make coalfired steam EGUs more competitive compared to other EGUs and 

cause them to increase their generation, creating a “rebound 

effect” that would make building block 1 less effective at 

reducing CO2 emissions. As discussed above, building blocks 1 and 

2 each appear attractive or neutral with respect to each of the 

other BSER criteria. 

With respect to most of the BSER criteria, there is no 

reason to expect that the combination of building blocks 1 and 2 

would be evaluated differently than 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 
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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 on 

average be accompanied by a reduction in CO2 emissions 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. 

By reducing overall generation from coal-fired EGUs, the 

combination of building blocks 1 and 2 also has the potential to 

raise the cost of emission reductions achievable through heat 

rate improvements relative to the cost if building block 1 were 

implemented in isolation.200 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 substantially 

 

200 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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increased. Second, although under the combination of building 

blocks 1 and 2 the volume of coal-fired generation would 

decrease, that decrease is unlikely to be spread uniformly among 

all coal-fired EGUs. It is more likely that some coal-fired EGUs 

would decrease their generation slightly while others would 

decrease their generation by larger percentages or cease 

operations altogether. Some coal-fired EGUs could increase their 

generation. We would expect EGU owners to take these changes in 

EGU operating patterns into account when considering where to 

invest in heat rate improvements, with the result that there 

would be a tendency for such investments to be concentrated in 

EGUs whose generation output was expected to decrease the least 

(or to increase). This enlightened bias in spending on heat rate 

improvements 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 

comprised of 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 like each 

of the building blocks, the combination must be considered a 
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“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 it is well-established. 

Further, because the combination of all four building blocks 

would achieve greater CO2 emission reductions at a lower cost 

than the combination of building blocks 1 and 2 described above, 

and would also perform better against other BSER criteria, we 

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.201 

 Because the measures in building blocks 2, 3, and 4 involve 

the interconnected electricity grid, evaluating them against the 

criteria for the BSER involves certain considerations. The EPA 

discusses these in the Legal Memorandum, and summarizes them 

briefly below. 

 

201 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2 

applies to the combination of all four building blocks as well. 

The EPA believes that 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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The EPA’s proposal that the “system of emission reduction” 

includes the measures in building blocks 2, 3, and 4 is grounded 

in the EPA’s interpretation of the key CAA provisions: section 

111(d)(1), which 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), which 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 system that reduces the 

affected sources’ emissions. As discussed in the Legal 

Memorandum, the EPA is justified in adopting this interpretation 

under the first step of the framework for administrative 

agencies to construe statutes that the U.S. Supreme Court 

established in Chevron U.S.A. Inc. v NRDC, 467 U.S. 837, 842-844 

(1984) (Chevron), which we refer to as Chevron step 1. 

Specifically, the term “system,” which is not defined in 

the CAA, is broad: “a set of things working together as parts of 
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a mechanism or interconnecting network.”202 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 

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 

 

202 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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Act, and described it as “the reduction or elimination, through 

any measures, of the amount of pollutants produced or created at 

the source.”203 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.204 Further support is found in Title 

IV of the CAA, in which Congress established the program that 

regulates fossil fuel-fired power plants to reduce their 

emissions of SO2 and NOx, the precursors to acid deposition. In 

designing Title IV, Congress recognized the integrated nature of 

the electricity sector and how that integration could be 

harnessed to reduce air pollutant emissions; and, in fact, 

Congress included provisions to encourage re-dispatch to lower-

 

203 CAA §101(a)(3), (c). 204 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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emitting sources, renewable energy, and demand-side energy 

efficiency, all of which are measures in those building 

blocks.205 All this supports the reasonableness of interpreting 

“system of emission reduction” in 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 section 111(d) standards of performance 

on measures such as re-dispatch, renewable energy, and demandside energy efficiency.206 Some stakeholders have as well.207

 

205 CAA §401(b), 404(f)-(g). 206 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 

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 .... 
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 As described earlier with respect the individual building 

blocks, the measures in each of building blocks 2, 3, and 4 

qualify as components of the “best system of emission reduction 

... adequately demonstrated.” The evaluations above of the 

individual building blocks against the criteria for the BSER 

generally apply to the combination of all four building blocks 

as well. 

In addition, the measures in building blocks 2, 3, and 4 

are “adequately demonstrated” because, as discussed, due 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, some 

utilities, states and regions are already relying on these 

 

According to this reasoning, emission reductions are occurring 

within the source category, because of changes in generation at 

the power plant.”). 

207 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). 
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measures for the specific purpose of reducing CO2 emissions from 

EGUs. 

 Further, measures in building blocks 2, 3, and 4 may be 

undertaken by the affected EGUs themselves, which confirms that 

these measures are “adequately demonstrated.” 

Each state’s electric utility sector has unique 

circumstances, and 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. For instance, while 

the EPA’s BSER 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. 
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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 EPA also 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 compliance time-frame, owners can consider 

longer-term options such as implementing energy efficiency 

programs or replacement of older generating resources with more 

modern types of generation, as well as 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. 
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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.208 Within the 5-to-15-year planning horizon 

established in this proposal to begin in June 2015, most of 

these companies are likely to be investing in new generation and 

can consider options such as increased reliance on new renewable 

generating capacity. They also run energy efficiency programs 

for their customers. 

Municipal utilities and rural cooperatives that own their 

own generation also have multiple options for reducing CO2

emissions, particularly generation and transmission cooperatives 

and larger municipal utilities. The can implement unit-specific 

improvements, re-dispatch to lower emitting resources, employ 

 

208 http://online.wsj.com/article/PR-CO-20140508-915605.html. 
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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 shortterm dispatch strategies and longer-term capacity planning 

strategies to reduce GHG emissions. 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 multistate compliance strategies to increase the flexibility and 

cost-saving opportunities that would be available to the covered 

EGUs. 

Municipal utilities and rural cooperatives can face other 

challenges as well. In deregulated areas, even though they 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 where 

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 
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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.209

Independent power producers (IPPs) may also face unique 

challenges but nevertheless have options. Most IPP generating 

units are natural gas-fired, but IPP owners with coal-fired EGUs 

can implement efficiency improvements as well as other unitlevel 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 do long-term business planning and 

therefore 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. In addition, many IPPs 

participate in markets that allow both generating resources and 

demand-side resources to compete, so even though they do not 

directly serve customers, they have opportunities to participate 

in demand-side energy efficiency programs. 

 

209 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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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. 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 loweremitting generation, and in some markets that treat demand-side 

resources on par with supply side resources, energy service 

companies would likely see opportunities. 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. 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 well-accepted 

CO2 reduction methods in the eyes of various stakeholders, as was 

clear from views expressed in our outreach process. 
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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.210 

As has also been discussed in earlier portions of the 

preamble, the costs and energy impacts of each of the four 

building blocks individually are not unreasonable when viewed 

either onat the individual source level or through the lens of 

 

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

section and elsewhere in the preamble. 
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the electricity system as a whole. As noted, , a conclusion that 

holds for the combination of the building blocks as well. 

Moreover, the flexibility available to states and regulated 

entities will have flexibility when developing complianceto rely 

more extensively in their plans and strategies to emphasizeon

whichever measures best suit their particular circumstances, and 

that flexibility will further improve cost-effectiveness. The 

analysis the EPA has performed to assess the costs, benefits,

and other impacts of the proposed goals reflects this compliance 

flexibility, along with transmission and pipeline capabilities 

and constraints, fuel market and electricity dispatch dynamics, 

and seasonal electricity load requirements. As described below 

in section XI of the regulatory impacts analysisX, the results 

indicate that the proposed state goals (discussed in section 

VII) are readily achievable with no adverse impacts on 

powerelectric 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. MoreoverFurther, the costs tend 

to decline over time as states and regulated entities take 

advantage of the available flexibility and deployexpand 

deployment of more cost-effective measures (notably demand-side 

energy efficiency). The EPA considers this analysis strong 
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confirmation of the cost effectiveness of the measures in the 

four building blocks in combination as the best system of 

emission reduction. 

 In addition, the improvements in heat rate through the 

building block 1 measures and the limitations on utilization in 

association with the measures in building blocks 2, 3, and 4 

provide a broad range of options for compliance which encourages 

the innovation or development of technology or other practices 

We note that reduce emissions. 

With respect to the remaining BSER criteria, the EPA 

believes some stakeholders have argued that the measures in the 

building blocks would not cause adverse non-air health and 

environmental impacts or increase energy requirements; indeed, 

the most likely such impacts would be co-benefits. Heat rate 

improvements cause fuel resources to be used more efficiently, 

reducing adverse impacts associated with fuel extraction and 

disposal of combustion waste products. Addressing emissions 

levels at affected EGUS through reduced utilization associated 

withsection 111(a)(1) does not authorize the EPA to identify redispatch to less carbon-intensive units, replacement by, low- or 

zero-carbon emitting generation, or demand-side energy 

efficiency would generally result in lower emissions of other 

pollutants because less carbon-intensive EGUs also tend to have 
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lower emissions of other pollutants and because less overall 

fossil-fired generation reduces emissions of other pollutants. 

It should also be emphasized that the measures in each 

building block are consistent with actions currently being taken 

in the power sector measures (building blocks 2, 3, and 4) as 

well as with future trends, which confirms our view that they 

comprise the BSER. 

4. Components of electricity system 

The second approach EPA is proposing as the basis for 

determining that the 4 building blocks constitute the components 

of the “best system of emission reduction ... adequately 

demonstrated” is that they consist of four sets of measures that 

result in reduced CO2 emissions from the affected sources. The 

measures in building block 1 are a component of BSER because, to 

reiterate, they reduce emissions by improving affected-source 

efficiency. Each of the measures in the other building blocks 

(blocks 2,3 and 4) are components of the BSER because of the 

nature of the electricity system. As discussed above, the 

electricity system is an integrated system through which 

fungible products – electricity and electricity services – are 

produced and delivered by a diverse group of EGUs operating 

within networks connecting them to each other and to their 

product purchases and users. This electricity system allows 
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generation by the affected sources, and therefore emissions from 

those sources, to be reduced in association with increasing 

generation at less carbon-intensive EGUs and expanding the 

amount of low- or zero-carbon generating capacity connected to 

the electric grid, as well as by reducing the demand for 

electricity. As discussed above, this integrated nature of the 

electricity system has long been central to efforts to reduce 

costs in general, assure reliability, and implement pre-existing 

pollution control requirements in the least cost manner. As also 

noted above, some states, including the members of RGGI, are 

already relying on the integrated nature of the electricity 

system to reduce CO2 emissions from EGUs. 

In particular, under this approach, increased generation 

from NGCC units, in accordance with building block 2, is viewed 

as a component of a system that reduces generation at fossilfired steam generating units, and thereby reduces overall CO2

emissions from fossil-fired EGUs. Similarly, under this 

approach, increased low- or zero-carbon generation, in 

accordance with building block 3, and decreased demand, in 

accordance with building block 4, are each viewed as other 

components of the same system that reduce generation at fossilfired EGUs, and thereby reduce CO2 emissions from those EGUs. 
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Viewed in this manner, all of the measures in the building 

blocks qualify as components of the BSER. Each of the building 

blocks’ sets of measures is technically feasible and is already 

being widely implemented. The heat rate improvements (building 

block 1) are technically feasible, for the reasons discussed in 

the earlier part of this section. The re-dispatch (building 

block 2), increased low- and zero-carbon intensity generation 

(building block 3), and demand-side energy efficiency (building 

block 4) are technically feasible for the reasons described in 

the above discussion of those building blocks. The evaluation of 

the rest of the factors concerning BSER are the same as 

discussed in the earlier part of this section. It bears 

reiterating that the EPA’s proposed conclusions that .” 

According to these measures qualify as BSER are confirmed by 

both the extensive practice within the electricity sector of 

relying on the same measures to reduce costs and implement 

pollution control requirements, while maintaining reliability, 

and the current practice of some states of relying on the same 

measures to reduce EGU emissions of CO2. 

It should be noted that all of the measures in the building 

blocks that are needed to achieve the requisite emissions 

reductions stakeholders, as a legal matter, the BSER is limited 

to measures that may be undertaken by the affected EGUs. That 
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is, the affected EGUs may undertake the equipment and process 

changes that result in heat rate improvements, as described in 

building block 1. The affected fossil-fired steam-generating 

EGUs may reduce generation, and the affected NGCC units may 

increase generation, to achieve the re-dispatch described in 

building block 2. The affected EGUs may invest in the new lowor zero-carbon intensive generation described in building block 

3, and the affected EGUs may also invest in many of the demandside energy efficiency measures described in building block 4. 

(These measures are described as the “utility portfolio” 

measures elsewhere in this preamble). The fact that the affected 

sources may themselves implement or invest in measures that 

reduce their emissions supports treating those measures as 

components of the BSER.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” 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. 

In fact, there are many cases in which companies have 

reduced emissions through shifting generation away from higher 

emitting units to lower or zero emitting units, or through 

reducing overall electric demand through DSM). In some cases 
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this has occurred in response to goals set at the company level, 

in others at the state level and in others at the regional 

level. Companies’ choices and policies implemented by states may 

impact decisions about dispatching of lower instead of higher 

emitting generating units both as part of the short term 

dispatch process and as part of longer term business planning 

processes. We believe that the flexibilities the proposed 

emission guidelines provide a variety of mechanisms and temporal 

flexibility will allow states to implement a variety of 

mechanisms that can reduce emissions both as part of those 

shorter term dispatch decisions and as part of longer term 

business planning processes. 

At the company level, a number of utilities have developed 

climate mitigation plans that are designed to significantly 

reduce emissions of CO2. In many of these plans, companies set a 

single company-wide emission target then use combinations of 

strategies such as fuel switching, increased energy efficiency, 

increased renewable generation and/or increased nuclear 

generation to achieve those goals. Changes from these types of 

plans occur over time as companies make decisions about 

generation mix and demand side strategies that change the way 

they dispatch. 
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California and Colorado provide two examples of how a 

statewide (or company-wide within a state) target set with 

consideration of the wide range of mitigation options and 

designed to provide flexibility to meet those options can be 

implemented. California enacted its Global Warming Solutions Act 

in 2006 (i.e. AB32), requiring the state to reduce its GHG 

emissions to 1990 levels by 2020 and 80 percent below 1990 

levels by 2050.211 According to California, “the integrated 

nature of the 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.”212 As a 

result, California takes a comprehensive approach (or relies 

upon a suite of mechanisms) to reduce emissions in the state, 

using energy efficiency programs, renewable energy programs as 

 

211 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.pdfhttp://www.leginfo.ca.gov/

pub/05-06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdf. 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy. Formatted: Font: (Default) Courier New
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well as procurement processes and an economy-wide cap and trade 

program, along with other programs.213 

The Colorado Clean Air Clean Jobs Act (CACJA), signed into 

law on April 19, 2010, required investor-owned utilities (IOUs) 

with coal plants to submit a multi-pollutant plan to the state 

to meet current and foreseeable EPA standards for NOx, SO2, 

particulates, mercury, and CO2. Rather than prescribing 

specific control technologies, the law allowed for flexibility 

for the utilities to select the best set of measures to achieve 

the emission reductions, including by retiring, retrofitting or 

repowering plants and replacing retired plants with natural gas 

and other low- or non-emitting energy plants and through end-use 

efficiency measures.214 

The California plan, has put in place mechanisms that 

affect both companies’ longer term planning decisions and their 

short term dispatch decisions. Understanding the market 

dynamics that will occur because of the need to hold emissions 

allowances coupled with reduced demand from demand side programs 

 

213 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. 

214 See State of Colorado House Bill 10-1365, available 

at:http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcon

t/0CA296732C8CEF4D872576E400641B74?Open&file=1365_ren.pdf
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impacts longer term decisions companies make about investment in 

both existing and new plants. The price of allowances also 

impacts hourly dispatch decisions and sends companies a market 

signal to which they take action in response to reduce use of 

higher emitting generators and increase use of lower emitting 

generators. 

The Colorado Plan, which set explicit requirements for 

development of new renewable generation as well as requirements 

to phase out older coal units, generally focused more on 

impacting companies’ longer term planning decisions. 

Mechanisms have also been put in place regionally that have 

these same impacts. For example, nine northeast and mid-Atlantic 

states participate in the Regional Greenhouse Gas Initiative 

(RGGI), a market-based emissions budget trading program that 

sets an aggregate limit on CO2 from fossil fuel fired power 

plants in the participating states. To comply with the program, 

each source must acquire allowances, through purchases or by 

allocation from the state, equal to their emissions, and must 

surrender them at the end of each compliance period. The RGGI 

program provides flexibility to regulated sources using a 

variety of mechanisms. The RGGI program allows for trading among 

regulated and non-regulated parties, creating a market for 

emission allowances. It provides additional flexibility through 
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multi-year compliance periods, allowance banking, offsets, an 

auction reserve price and cost containment reserve of 

allowances.215 Operating in this regime, EGUs take a variety of 

actions including those that affect their utilization levels 

that in turn affect their emissions levels. 

Because, under CAA section 111(d), the standards of 

performance that are based on the BSER are established by the 

states in state plans, measures that the states are authorized 

to enact under state law may be considered to be part of the 

BSER. Therefore, for example, the demand-side energy efficiency 

measures that are described as the “state portfolio” measures 

elsewhere in this preamble may also be considered part of the 

BSER. 

5We 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 

 

215 Participating states include Connecticut, Delaware, Maine, 

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

and Vermont ; RGGI website: http://www.rggi.org/rggi 
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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.216 It should also be noted that, as discussed above, 

 

216 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. 

6. Alternate interpretation of 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 EPA believes the “system of 

emission reduction” may be identified as including, in addition 

to building blocks 1 and 2, the reduction of EGUs’ mass 

emissions achievable through reductions in generation of 

specified amounts from fossil fuel-fired EGUs. Under this 

approach, the measures in building blocks 3 and 4 would not be 

components of the BSER but instead would serve as bases for 

quantifying the reduction in emissions resulting from the 

reduction in generation at affected EGUs, and assuring that the 

reduced generation is “adequately demonstrated” because it could 

be achieved while continuing to meet the demand for electricity 

services in a reliable and affordable manner. Specifically, the 

amount of generation from the use of expanded low- and zerocarbon generating capacity that could be provided, and the 

amount of generation from fossil fuel-fired EUGs that could be 

avoided through the promotion of demand-side energy efficiency, 
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would determine the amount of the fossil fuel-fired generation 

reduction component of the BSER. 

In a variation of this alternate interpretation of the 

BSER, instead of including building block 2 in the BSER, only 

the portion of building block 2 consisting of reductions in 

generation at higher-emitting affected fossil fuel-fired steam 

EGUs would be included in the BSER. The portion of building 

block 2 consisting of increased generation at lower-emitting 

affected NGCC units would not be included in the BSER, but 

instead would serve as a basis for quantifying the amount of 

reduction in generation at higher-emitting affected EGUs that 

could achieved while continuing to meet the demand for 

electricity services in a reliable and affordable manner. Under 

this variation, to ensure that demand for electricity services 

can be met reliably, we propose that the amount of reduced 

generation from affected fossil fuel-fired steam EGUs is the 

amount of incremental generation that can be provided from 

affected NGCC units, and similarly we propose to find the cost 

of reduced generation from affected fossil fuel-fired steam EGUs 

reasonable only to the extent that the cost of the incremental 

generation from affected NGCC units is reasonable. 

Reduced generation is encompassed by the clear terms of the 

phrase “system of emission reduction” because, in accordance 
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with the above-discussed definition of “system,” reduced 

generation is a “set of things” – which include reduced use of 

generating equipment and reduced fuel input – that the affected 

source may take to reduce its CO2 emissions.217 If that phrase is 

not considered clear by its terms, then it may reasonably be 

interpreted to include reduced generation.218 As discussed in the 

Legal Memorandum, the legislative history of the CAA indicates 

that Congress recognized that emitting sources could comply with 

pollution control requirements by reducing production, including 

retiring. 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.219 

Reduction of, or limitation on, the amount of generation is 

already a well-established means of reducing emissions of 

pollutants in the electric sector and not merely a theoretical 

option that is unavailable as a practical matter for sources 

 

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

“system of emission reduction” includes reduced generation. 

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

“system of emission reduction” includes reduced generation. 

219 See, e.g., Consent Decree, United States v. Wis. Power & 

Light Co., No. 13-cv-266 (W.D. Wis. filed Apr. 22, 2013), at 18, 

section IV, available at 

http://www2.epa.gov/sites/production/files/documents/wisconsinpo

wer-cd.pdf.
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that may have to operate to ensure system reliability. For 

example, reduced generation by higher-emitting sources is one of 

the compliance options available to, and used by, EGUs to comply 

with the Clean Air Act acid rain program in CAA title IV, as 

well as the transport rules that we refer to as the NOx SIP 

Call220 and the Clean Air Interstate Rule (CAIR).221 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” 

because it is technically feasible due to the 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. 

Likewise, we propose to find the cost of reduced generation from 

affected EGUs reasonable only to the extent that the costs of 

 

220 63 FR 57356 (Oct. 27, 1998). 221 70 FR 25162 (May 12, 2005). 
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the measures meeting the demand for energy services in the 

absence of that reduced generation are reasonable. 

The levels of reduced generation proposed meet the criteria 

for the “best system of emission reduction ... adequately 

demonstrated.” The costs of the proposed levels of reduced 

generation are reasonable for the affected source category and 

the nation-wide electricity system, do not jeopardize 

reliability, and do promote the development and implementation 

of technology that is important for continued emissions 

reductions. This is because the extent to which the electrical 

grid operates through integrated generation, transmission and 

distribution networks creates fungibility for electricity and 

electricity services , which allows decreases in generation at 

one affected EGU to be seamlessly replaced by increased 

generation at a low- or zero-carbon EGU (building block 3) or by 

decreased demand (building block 4), or, in the variation 

described above, allows decreases in generation at affected 

fossil fuel-fired steam EGUs to be replaced by increases in 

generation at affected NGCC units (building block 2). These 

characteristics of the integrated electric system thereby make 

reduced generation a viable approach for achieving CO2 emission 

reductions by affected EGUs. 
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As noted above, the measures in building blocks 2, 3, and 4 

are already in widespread use in the industry. At the levels 

proposed, they have the technical capability to substitute for 

reduced generation at some or all affected EGUs at reasonable 

cost. The NGCC capacity necessary to accomplish the levels of 

generation reduction proposed for building block 2 is already in 

operation or under construction. Moreover, it is reasonable to 

expect that the incremental resources reflected in building 

blocks 3 and 4 will develop at the levels requisite to ensure an 

adequate and reliable supply of electricity at the same time 

that higher-emitting EGUs may choose or be required to reduce 

their CO2 emissions by means of reducing their utilization. There 

are two reasons for this. First, the affected sources themselves 

could invest in new renewable energy resources and demand-side 

energy efficiency, as discussed above.222 Second, the states, as 

part of their plans, have mechanisms available to put these 

substitutes in place: they could establish requirements or 

 

222It 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. 
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incentives that would result in new renewable energy and demandside energy efficiency programs, as also discussed above.223 

7. EPA’s discretion in applying the criteria for the best system 

of emission reduction 

As discussed above, each of the approaches to determining 

the “best system of emission reduction ... adequately 

demonstrated” entails applying the criteria described in the 

D.C. Circuit case law for evaluating 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. 

In the present rulemaking, the EPA is heavily weighting two 

criteria in particular: the amount of emissions reduction 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 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. Above, the EPA discusses this in the 

sections concerning the scientific background for this 

 

223 The nuclear generating capacity reflected in building block 3 

is already in operation or under construction. 
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rulemaking. The EPA also considers it especially important in 

this rulemaking 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 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, 

environmental and energy effects of different technological 

systems....”224

8. Combined categories 

 

224 Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981). 
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 As discussed above, the EPA is co-proposing combining the 

category of steam-generating EGUs and the category of combustion 

turbines (which include NGCC units) into a single category for 

fossil fuel-fired EGUs, for purposes of promulgating emission 

guidelines for CO2 emissions. The EPA solicits comment on whether 

combining the categories is, as a legal matter, a prerequisite 

for (i) identifying as a component of the BSER re-dispatch 

between sources in the two categories (i.e., re-dispatch between 

steam-generating EGUs and NGCC units), or (ii) facilitating 

averaging or trading systems that include sources in both 

categories, which states may wish to adopt.

69. 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. 

710. Solicitation of comment 
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 We invite comment on all aspects of our proposed 

interpretation of the BSER for CO2 emissions from existing fossil 

fuel-fired EGUs, both as identified above and as further 

discussed in the Legal Issues Memorandum in the docket, 

although, as noted, we are not soliciting comment on issues that 

were resolved by the frameworkimplementing regulations and 

therefore are not being re-opened here. In particular, we invite 

comment on our analysis of the four building blocks as 

components of the BSER, whether any of the types of measures 

discussed above, and any other potential measures recommended by 

commenters, must, may, or may notshould be considered as, and

the basis for the BSER for legal, technical, orand economic 

reasons.bases of our conclusions. With regardsregard to comments 

received during the stakeholder commentsmeetings, some 

commenters noted that trading programs like RGGI have been 

successful at reducing GHGs, and other commenters 

solicitedprovided 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 
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solely because they involve actions by entities or at locations 

other than affected sources. 

VII. State Goals 

A. Overview 

In this section, the EPA sets out proposed state-specific 

CO2 emission performance goals to guide states in development of 

their state plans. The proposed goals reflect the EPA’s 

quantification of each state’s average emission rate from 

affected EGUs that could be achieved by 2030 and sustained 

thereafter, with interim goals that would apply over a 2020-2029 

phase-in period, through reasonable implementation, considering 

the unique circumstances of each individual state, of the 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 four building 

blocks, 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. 
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 The proposed goals are expressed in the form of statespecific, adjusted225 output-weighted-average CO2 emission rates 

for affected EGUs. However, states are authorized to translate 

the form of the goal to a mass-based form, as long as the 

translated goal achieves the same degree of emission limitation. 

In addition, states have discretion to adopt and submit 

different forms of standards of performance, as long as the 

submittal achieves a level of performance (including timing) at 

least equivalent to the goal. For example, we anticipate that 

some states may prefer to adopt mass-based standards of 

performance in which performance is gauged in terms of the mass 

of CO2 emissions from affected units rather than in terms of the 

amounts of CO2 emitted per unit of energy output produced by 

those units. Likewise, although the proposed goals are statespecific, we anticipate that some states may prefer to submit 

plans reflecting a multi-state approach for complying with 

standards of performance. 

 

225 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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The EPA is proposing that measures that a state takes after 

the date of this proposal and prior to the beginning of the plan 

period in 2020, and which result in CO2 emission reductions 

during the plan period, would apply toward achievement of the 

state’s CO2 goal. Thus, states with existing programs and 

policies, and states that put in place new programs and policies 

early, will be better positioned to achieve the goals. 

At this time, the EPA is not proposing targetsCO2 emission 

performance goals for either tribal landsIndian country or U.S. 

territories. The EPA does believe it is appropriate to 

eventually require targetsplan to establish CO2 emission goals

for both tribal landsIndian country and territories. Emission 

goals for Indian country will be established in the future as 

necessary or appropriate, as provided for in the Tribal 

Authority Rule.

With respect to tribal lands,Indian country, the EPA is 

soliciting comment on the application of the four BSER building 

blocks to determine a CO2 emission performance standardgoals for 

units on individual tribal lands. Also, for tribes wishing to 

include theIndian country with affected EGUs on their tribal 

lands. The EPA notes that some present and future actions taken 

to reduce criteria pollutants from EGUs in Indian country will 

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result in significant CO2 emission reductions.226 As the EPA has 

done in setting state goals, the EPA would set emission 

performance goals for Indian country in a multi-state plan 

(i.e., treating the tribal lands as an additional state)manner 

that would allow the jurisdictional authority to meet the goals 

through the use of a wide range of policies and practices 

capable of achieving CO2 emission reductions. If the EPA develops 

one or more federal plans for EGUs located in Indian country, we 

are solicitingcurrently considering doing so on a regional basis 

in coordination with plans being developed for neighboring 

states. The EPA solicits comment on how to adjust the multistate plan goal to accommodate the addition of EGUs on tribal 

land. EPA also recognizes that in several cases, regional haze 

BART requirements may lead to significant CO2 reductions. EPA is 

soliciting comment on whether and how those actions should 

factor into setting tribal targets.such an approach for a 

federal plan. 

With respect to territories, the EPA takesrequests comment 

on the appropriateness of the four building block approach for 

 

226 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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territories. In particular, the EPA takessolicits comment on 

appropriate alternatives for territories that do not have access 

to natural gas as well as on ways to determine appropriate 

renewable targets in the absence of the types of regional data 

used to develop the renewable component of BSER for states.

The remainder of this section addresses fourfive 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. FinallyFourth, 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 

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

average, through implementation of the four building blocks (or 

alternative control methods). Several aspects of this proposed 

form of goal are worth noting at the outset: the use of an 

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

electricity generated), with the opportunity for the state to 

adopt a mass-based form (e.g., a cap on the tonnage of CO2

emissions); the use of output-weighted-average emission rates 

for all affected EGUs in a state rather than nationally uniform 

emission rates for all affected EGUs of particular types; the 

use of adjustments to accommodate measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation rather than by reducing the CO2 emission rate per MWh 

generated by affected sources; the use of emission rates 

expressed in terms of net rather than gross energy output; and 

the adjustability of the goals based on the severability of the 

underlying building blocks. 

 First, the EPA proposes to use an emission rate-based form 

for the 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 typesforms of goals presents advantages. Defining 

emission performance levels in a rate-based form provides 
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flexibility to accommodate changes in the overall quantities of 

electricity generated in response to increases in electricity 

demand. Defining emission performance levels in a mass-based 

form provides relative certainty as to the absolute emission 

levels that would be achieved as well as relative simplicity in 

accommodating and accounting for the emission impacts of a wide 

variety of emission reduction strategies. In light of these 

respective advantages, we propose to set an emission rate-based 

form of goal, and to allow any state to translate the rate-based 

goal to an equivalent mass-based emission performance level for 

state plan purposes. This approach allows each state to maximize 

the advantages it considers optimal and is consistent with the 

state flexibility principle that is central to the EPA’s 

development of this program. 

 The second aspect noted above concerns the proposed choice 

of 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 EGUs. Specifically, because 

CO2 emission rates differ widely across the fleet of affected 

EGUs, and because transmission interconnections typically 
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provide system operators with choices as to which EGU should be 

called upon to provide the next MWh of generation needed to meet 

demand, opportunities exist to manage utilization of high 

carbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this 

means that CO2 emission reductions can be achieved by shifting 

generation from EGUs with higher CO2 emission rates, such as 

coal-fired EGUs, to EGUs with lower CO2 emission rates, such as 

NGCC units. Our analysis indicates that shifting generation 

among EGUs is a potentiallyoffers opportunities to achieve large 

sourceamounts of cost-effective CO2 emission reductions for the 

power sectorat reasonable costs. These opportunities can be 

reflected in a goal established in the form of an outputweighted-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 associated with measures such as increases in low- 
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and zero-carbon generating capacity and demand-side energy 

efficiency. We recognize that these measures reduce overall CO2

mass emissions from affected EGUs are reduced by reducing the 

quantity of generation from thoseaffected EGUs collectively 

rather than bywithout necessarily reducing the weighted-average 

CO2 emission rates of affected EGUs or by shifting generation 

from the most carbon-intensive affected EGUs to less carbonintensive 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 avoid generation at affected 

EGUs could be used to help the state meet the rate-based 

emission performance level reflected in its plan. We note that 

adjustments of this nature are not necessary when a plan’s 

emission performance level is based on the mass of CO2
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emissions227 rather than on CO2 emission rates, because the 

emission-reducing effects of reduced utilization ofgeneration at

affected EGUs are evident in the EGUs’ reported CO2 mass 

emissions. 

 The fourth aspect noted above concerns the proposed 

expression of the goals in terms of net energy output – 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.228 (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.) 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. Improvements in 

the efficiency of these devices represent opportunities to 

reduce carbon intensity at affected EGUs that would not be 

 

227 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. 

228 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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captured in measurements of emissions per gross MWh. Further, 

nearly all EGUs already have in place the equipment necessary to 

determine and report hourly net MWh generation, and we believe 

that the proposed reporting requirement would therefore not be 

burdensome. However, we also recognize that at present EGUs 

report gross rather than net load229 to us under 40 CFR Part 75, 

and that the proposed GHG standards of performance for new EGUs 

are expressed in terms of gross MWh generation (although we 

sought comment on the use of net MWh generation instead). We 

therefore specifically seek comment on whether the goals and 

reporting requirements for existing EGUs should be expressed in 

terms of gross MWh generation instead of net MWh 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 are independent of each other and the goals are the sum 

of the emission reductions from all of the building blocks, if 

any of the building blocks are found to be invalid bases for the 

 

229 Some EGUs report gross steam output instead of gross 

electrical load. 
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“best system of emission reduction ... adequately demonstrated,” 

the goals would be adjusted to reflect the emissions reductions 

from the remaining building blocks. As noted above, the state 

goals that would result from any combination of the building 

blocks can be computed from data included in the Goal 

Computation TSD and its appendices using the methodology 

described below and in that TSD.

We invite comment on all aspects of the proposed form of 

the goals, including suggestions for specific alternative forms 

of goals not discussed above that may also merit consideration. 

C. Proposed goals and computation procedure 

 The EPA has developed proposed goals for state plans 

reflecting use of all four building blocks described earlier. 

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. In addition to the final goals, 

EPA has developed interim goals that would apply during the 

2020-2029 period on a cumulative or average basis as states 

progress toward the final goals. The proposed goals are set 

forth in Table 6 below, followed by a description of the 
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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.) The 

proposed goals are set forth in Table 5 below.

Table 56: Proposed State230 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,113147 1,024059

Alaska 1,039097 8781,003

Arizona * 724735 691702

Arkansas 1,012968 950910

California 580556 558537

Colorado 1,164159 1,112108

Connecticut 588597 533540

Delaware 922913 848841

Florida 750794 692740

Georgia 885891 826834

Hawaii 1,388378 1,304306

 

230 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 tribesIndian country or U.S. 

territories at this time. 

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Idaho 241244 225228

Illinois 1,391366 1,293271

Indiana 1,627607 1,549531

Iowa 1,351341 1,310301

Kansas 1,597578 1,516499

Kentucky 1,861844 1,778763

Louisiana 1,080948 993883

Maine 423393 407378

Maryland 1,325347 1,166187

Massachusetts 646655 567576

Michigan 1,337227 1,261161

Minnesota 891911 851873

Mississippi 717732 673692

Missouri 1,621 1,544 

Montana 1,900882 1,781771

Nebraska 1,587596 1,471479

Nevada 697 644647

New Hampshire 542546 485486

New Jersey 657647 531 

New Mexico * 1,088107 1,000048

New York 647635 557549

North Carolina 1,064077 977992

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North Dakota 1,821817 1,788783

Ohio 1,468452 1,349338

Oklahoma 916931 879895

Oregon 408407 375372

Pennsylvania 1,200179 1,067052

Rhode Island 816822 773782

South Carolina 802840 736772

South Dakota 794800 731741

Tennessee 1,234254 1,142163

Texas 932853 855791

Utah * 1,375378 1,318322

Virginia 869884 793810

Washington 294264 235215

West Virginia 1,766748 1,636620

Wisconsin 1,265281 1,185203

Wyoming 1,801808 1,701714

* Excludes EGUs located in tribal areas inIndian 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 

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total quantity of fossil fuel-fired generation associated with 

state plan measures that increase low- or zero carbon generating 

capacity or demand-side energy efficiency. Accordingly, under 

the proposed goals, the emission rate computation includes an 

adjustment designed to reflect those mass emission reductions. 

The adjustment is made by estimating the annual net MWh 

generation associated with an achievable amount of qualifying 

new low-carbon and zero-carbon generating capacity, as well as 

the annual avoided MWh 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.231 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 

 

231 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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form of emission performance level while still being able to 

rely on low- or zero-carbon capacity deployment programs and 

demand-side energy efficiency as components of its plan.) 

 The methodology used to compute each state’s proposed goal 

is summarized on a step-by-step basis below. The methodology is 

described in more detail in the Goal Computation TSD, which 

includes a numerical example illustrating the full procedure. 

The development of the data inputs used in the computation 

procedure is discussed in section VI above and in the Greenhouse 

Gas Abatement Measures TSD. 

 Step 1 (compilation of baseline data). On a state-by-state 

basis, we obtained total annual quantities of CO2 emissions, net 

MWh generation, (MWh), and capacity (MW capacity) from reported 

2012 data for all affected EGUs.232 For each state, we aggregated 

the 2012 data for all coal-fired steam EGUs as aone group, all 

oil- and gas-fired steam EGUs as a second group, and all NGCC 

units as a third group, and. We aggregated the 2012 data for all 

remaining affected EGUs as a group (i.e., integrated 

gasification combined-cycle (IGCC) units and any simple-cycle 

combustion turbines satisfying the size and electricity sales 

 

232 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.AB. above. 
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thresholds for qualification as affected EGUs).) as a fourth, 

“other” group.233 To these totals for affected EGUs operating in 

2012, we added estimates for other EGUs not yet in operation in 

2012 that are affected EGUs for purposes of this emission 

guideline.234 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 technically achievable and costeffective opportunity to reduce CO2 emission rates across the 

existing fleet of coal-fired steam EGUs through heat rate 

 

233 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. 

234 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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improvements that is technically achievable at a reasonable 

cost. 

 Step 3 (application of building block 2). If the generation 

data for the NGCC group in a state developed in Step 1 showed 

average annual utilization below 70 percent of those units’ 

maximum possible output, and the generation data developed in 

Step 1 also included generation from the coal-fired steam or 

oil/gas-fired steam EGU groups in that state, the generation and 

emissions figures for the NGCC group were increased, and the 

generation and emissions figures for the coal-fired and oil/gasfired steam EGU groups from Step 2 were proportionately235

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 MWh 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

 

235 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. 
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emission rate, the total (across all four groups) of the state’s 

CO2 emissions was reduced.236 

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

total quantities of new generation from renewable generating 

capacity and new or preserved nuclear capacity that would be 

made available in for each state under the “best practices” 

approaches to discussed 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 new and preserved 

nuclear capacity, and we estimated the MWh generation from this 

incremental low- or zero-carbon generating capacity based on 

historic for each state operated at a utilization rate of 90 

percent, consistent with recent industry-wide average

utilization rates for nuclear units of the same types. 

 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 by implementation in that state of a comprehensive “best 

practices” approach to demand-side energy efficiency programs 

 

236 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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resulting in annual incremental reductions in the state’s 

electricity usage (relative to usage absent those programs) of 

1.5 percent each year. Separate estimates were developed for 

each year to reflect the fact that energy efficiency programs 

that are implemented on an ongoing basis would be expected to 

produce larger cumulative impacts on total annual electricity 

usage over time. For states that are net importers of 

electricity, the estimated reduction in the generation by the 

state’s affected EGUs was scaled down to reflect an expectation 

that a portion of the generation avoided by the demand-side 

energy efficiency would occur at EGUs in other states. 

 Step 6 (computation of annual rates). We computed adjusted 

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 MWh 

generation from new 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 
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above.237 We performed these computations separately for each 

year from 2020 to 2029, using the respective cumulative annual 

MWh savings figures developed in StepSteps 4 and 5. 

 Step 7 (computation of interim and final goals). The final 

2030 goal for each state is the annual rate computed for 2029 

for the state from Step 6 above. We computed the 2020-2029 

interim goal for each state as the simple average of the annual 

rates computed for each of the years from 2020 to 2029 for the 

state from Step 6 above. 

 It bears emphasis that the procedure described above is 

proposed to be used only to determine state goals, and the 

particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

specific requirements applicable to individual EGUs, to the EGUs 

in a given state collectively, or to other affected entities in 

the state would be based on the standards of performance 

established through that state’s plan. The details of how states 

could attain emission performance levels consistent with the 

 

237 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.] 
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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.) 

above.) We also specifically invite comment on the statespecific historical generation and capacity 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 statespecific 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 should, we would

decrease generation from the state’s coal-fired steam group 

first, and then decrease generation from the state’s oil/gasfired steam group (instead of decreasing generation from the 

coal-fired steam and oil/gas-fired steam groups 

proportionately)?).

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With respect to building blocks 3 and 4, we specifically 

request comment on the following alternative procedure: in Steps 

4 and 5, should we estimate the quantity of generation 

reductions and associated emission reductions at the state’s 

affected EGUs that would be achieved through application of 

these building blocks and then, in Step 6, subtract these 

emission reduction quantities from the numerator of the adjusted 

emission rate equation (instead of computing the quantities of 

generation that would be produced by new low-carbon capacity and 

avoided by demand-side energy efficiency and then adding those 

generation quantities to the denominator of the adjusted 

emission rate equation)? Further, under this alternative 

approach for building blocks 3 and 4, should we estimate the 

emission reductions at the state’s affected EGUs by decreasing 

generation from the coal-fired steam group first or instead by 

decreasing generation proportionately from the coal-fired steam 

and oil/gas-fired steam groups? 

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 by the demand-side energy efficiency efforts 

of other, net electricity-importing states would occur at those 
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EGUs, analogous to the proposed adjustment for net importing 

states described in Step 5. We also request comment on the 

alternative of making no adjustment in Step 5 for either net 

electricity-importing or net electricity-exporting states. These 

alternatives are discussed in the Goal Computation TSD. 

We also request comment on whether CO2 emission reductions 

from other measures not currently included in any of the four 

proposed building blocks, such as reductions achievable through 

expansion of the amount of new NGCC capacity, should be included 

in the state goals. 

D. State flexibilities 

 As promulgated in the final rule following 

consideration of comment, the state-specific goals will be 

binding emission guidelines. States’ ability to achieve emission 

performance levels consistent with the binding goals is enhanced 

by several distinct types of flexibility: (i) choices as to the 

measures employed, including the timing of their implementation; 

(ii) the ability to translate from a rate-based form of goal to 

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

interstatemulti-state compliance 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 
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application of the control measures that the EPA identifies as 

the BSER, they need not mandate the particular control measures 

the EPA identifies as the basis for its BSER determination. In 

developing the building block data inputs applied to each 

state’s historical capacity and generation 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 measures that 

are not included in the building blocks. 

Further, by allowing states to demonstrate compliance over 

a multi-year interim plan period of as long as ten years, the 

emission guidelineEPA’s proposed approach increases states’ 

flexibility to choose among alternative potential 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 remaining useful lifestranded 

assets, for example, by enabling themstates to defer imposition 

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of requirements on EGUs that may be scheduled to retire after 

2020 but before 2029. 

Second, asThe second type of flexibility noted 

earlier,above is that while the EPA is proposing to establish 

goals in an emission rate-based 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 states 

that currently participate in the mass-based Regional Greenhouse 

Gas Initiative (RGGI) may choose to develop state plans 

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 emissionsemission budget 

program. Because the use of mass-based plans can simplify the 

process of accounting for the CO2 reduction impacts of a variety 

of measures, the EPA believes the flexibility to adopt massbased emission performance levels can facilitate plan 

development and could be attractive to states that do not 

already participate in mass-based programs as well. 

Third, the emission guidelines allowEPA’s approach allows

states to submit multi-state plans. The EPA expects this 

flexibility to reduce the cost of achieving the state goals and 
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therefore expects it to be attractive to states. For example, 

the RGGI-participating states could choose to submit a multistate mass-based plan that demonstrates emission performance on 

a multi-state basis. Additional states may also choose to join a 

multi-state plan. The mechanics of translating rate-based goals 

into mass-based goals and demonstrating equivalency between the 

two forms and issues related to multi-state plans are discussed 

below in sectionSection VIII on state plans. 

Some stakeholders have suggested that states themselves 

should have flexibilitybe 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 

frameworkimplementing regulations, we view for CAA section 

111(d) at 40 CFR part 60, this quantification asis the EPA’s 

role,.238 and we do not propose to re-open that portion of the 

frameworkAs discussed in the Legal Memorandum, CAA section 

111(d) directs the EPA to “prescribe regulations in which shall 

establish a procedure similar to that provided by [CAA section 

110) under which each State shall submit” a section 111(d) state 

 

238 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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plan. As noted in preamble section II.D above, the EPA 

promulgated implementing regulations in 1975, and has revised 

parts of them since. The regulations set out a multi-step 

process for the development and approval of state plans, and 

assign responsibility for the various steps in the process to 

the EPA or the states. The regulations provide that the EPA is 

to promulgate an “emission guideline that reflects the 

application of the best system of emission reduction 

(considering the cost of such reduction) that has been 

adequately demonstrated for” affected sources.239 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, 

 

239 Id. 
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is resolved by the frameworkimplementing regulations,240 and EPA 

is not re-opening it in this rulemaking..241 To reiterate, the 

proposed state goals are intended to demonstrate arepresent the

level of performance that is achievable through application of 

the building blocks considering the unique circumstances of BSER 

to the pertinent data for each individual state that would. 

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, the states will be acceptableable 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 adeveloping their state plan. Statesplans: 

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, and they can use rate-based 

or mass-based approaches. In addition, as we note thathave 

noted, multi-state coordination offers states an opportunity to 

 

240 40 CFR 60.22(b)(5). 241 Id. We do not propose to re-open that portion of the 

implementing regulations in this rulemaking. 
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achieve additional emission reductions and reduce implementation 

costs. These flexibilities, discussed further in Section VIII of 

this preamble, ensure that states will be able to achieve their 

final CO2 emission performance goals and that no special 

provision for state adjustment of goals outside the normal 

notice-and-comment rulemaking process is warranted.242

We solicit comment on whether, and, if so, when and under 

what circumstances the EPA should consider adjusting a statespecific goal in response to a state’s request on grounds that 

the goal does not reflect BSER as applied in that state. 

Specifically, should a request made after the comment period in 

the rulemaking be considered at all? Should a request made after 

issuance of the final rule be considered? Should a post-comment 

period request be considered if it is based on information that 

could have been provided during the comment period? What 

materiality thresholds should EPA apply to adjustment requests? 

Should the state be required to demonstrate that it would be 

unable to achieve the goal as set by EPA, even after considering 

all of the building blocks and all of the flexibilities 

available to the state discussed above regarding the selection 

 

242 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 §307(d)(7)(B). 
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of measures, the form of the goal, and the multi-year period to 

reach the final goal? Should the state be required to 

demonstrate that it would be unable to achieve the goal even 

after consideration of multi-state approaches? What could 

suffice for a demonstration that the goal does not represent 

BSER? 

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. 

 The alternate goals reflect several differences in data 

inputs from the proposed goals. Specifically, a value of four 

percent (instead of six percent) was used for the potential 

improvement in carbon intensity of coal-fired EGUs in Step 2; a 

value of 65 percent (instead of 70 percent) was used for the 

potential annual utilization rate of NGCC units in Step 3; and a 
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value of one percent (instead of 1.5 percent) was used for the 

annual incremental electricity savings achievable through a best 

practices portfolio of demand-side energy efficiency programs in 

Step 5. (No change was made to the data inputs regarding new

less carbon-intensive generating capacity in Step 4.) As noted 

above, the alternate goals also reflect a shortening of the 

proposed phase-in period from ten years (2020-2029) to five 

years (2020-2024) to reflect an expectation that less stringent 

goals could be achieved in less time. Steps 5, 6, and 7 of the 

goal computation procedure therefore were performed for the span 

of years from 2020 to 2024 rather than for the span from 2020 to 

2029. The alternate goals are set forth in Table 67 below. 

Table 67: Alternate State243 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,243270 1,208237

Alaska 1,142170 1,086131

Arizona * 767779 751763

Arkansas 1,128083 1,101058

California 611582 599571

 

243 See footnote accompanying Table VII.C-16 above. 

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Colorado 1,274265 1,232227

Connecticut 640651 617627

Delaware 1,036007 1,010983

Florida 795907 771884

Georgia 992997 958964

Hawaii 1,464446 1,429417

Idaho 259261 252254

Illinois 1,529501 1,484457

Indiana 1,738715 1,704683

Iowa 1,447436 1,428417

Kansas 1,698678 1,644625

Kentucky 1,971951 1,937918

Louisiana 1,208052 1,171025

Maine 448418 440410

Maryland 1,495518 1,417440

Massachusetts 708715 675683

Michigan 1,470349 1,434319

Minnesota 1,001018 981999

Mississippi 754765 729743

Missouri 1,726 1,694 

Montana 2,031007 1,980960

Nebraska 1,710721 1,661671

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Nevada 736734 714713

New Hampshire 593598 553557

New Jersey 740722 688676

New Mexico * 1,203214 1,163176

New York 756736 715697

North Carolina 1,189199 1,145156

North Dakota 1,887882 1,874870

Ohio 1,611588 1,566545

Oklahoma 1,022019 986 

Oregon 449450 418420

Pennsylvania 1,342316 1,293270

Rhode Island 854855 837840

South Carolina 889930 858897

South Dakota 885888 856861

Tennessee 1,345363 1,307326

Texas 1,059957 1,016924

Utah * 1,476478 1,451453

Virginia 1,011016 955962

Washington 350312 316284

West Virginia 1,877858 1,835817

Wisconsin 1,404417 1,366380

Wyoming 1,902907 1,862869

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* Excludes EGUs located in tribal areasIndian country in the 

state. 

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 the estimated 

opportunities to reduce utilization of the most carbon-intensive 

EGUs by shifting generation to less carbon-intensive EGUs should 

be based on regional evaluations rather than state-specific 

evaluations. A potential advantage of using regional evaluations 

is the ability to recognize additional cost-effective emission 

reduction opportunities based on a more complete representation 

of the capabilities of existing infrastructure to accommodate 

shifts in generation among EGUs in multiple states. On the other 

hand, it could be argued that states might have less flexibility 

to adopt plans that take different approaches than neighboring 

states if the goals are set at levels that reflect the ability 

to capture emission reduction opportunities that require 

interstate cooperation. We request comment on whether, and if so 

how, the EPA should incorporate greater consideration of 
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regional approaches into the goal-setting process, and on the 

issue of whether, and if so how, the potential cost savings 

associated with regional approaches mayshould be considered in 

assessing the cost effectiveness 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 is sympathetic to this concern,agrees that reliability must 

be maintained and so in designing this program the EPAproposed 

rulemaking has paid careful attention to this issue. 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 ofon

the power system. EPA staff and managers have also had numerous 

discussions with state public utility commissioners and their 

staffstaffs to get their suggestions and advice concerning this 

rule, including how to address reliability concerns. 

In addition, the EPA met with the independent system 

operators several times to discuss any potential impact of this 

rule on grid reliability. The ISO/RTO Council, a national 

organization of these entitieselectric grid operators, offered 

analytic support to help states design programs that do not 

compromise the regional bulk power system. They also offered to 
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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 plansThese 

suggestions are described elsewhere in this preamble and we 

welcome comment on them. 

The EPA has discussed this issuemet with the USU.S.

Department of Agriculture as well to discuss how we can address 

the concerns of small isolated power generators in rural America 

and especially the electric cooperatives. Many of these entities 

have special challenges, as they may have small, older carbon -

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intensive assets and might have particular challenges meeting 

carbon requirements. 

With all of this in mind, the EPA in determining the BSER,

looked specifically at the cost effectiveness of control options 

in part to assureensure that the optionoptions would not have a 

negative effect on system reliability. Each of the building 

blocks was determined to be cost effective.have reasonable 

costs. Further, the states 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 that emissions 

limitationthe required emission limitations. States are not 

required to use each of the measures that the EPA determines 

constitute BSER or use those measures to the same degree of 

stringencyor extent that the EPA determines is achievable andat 

a reasonable cost-effective. Thus, each state has the 

flexibility to choose measures that are cost effective given 

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

achievedachieves the reductions necessary to meetingmeet its 

goal. Many market-based approaches which states may choose 

reduce the costs of compliance. They can allow certain units 

that are seldom used to remain in operation if they are needed 

for reliability purposes. Regional approaches as well,also
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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. 

Because theThe EPA is proposing a 10-year period over which 

to achieve the full required CO2 reductions, and we would expect 

would 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. In addition, states can make 

adjustments to their implementation approaches along the way, or 

asand in doing so can consider changed conditions change may 

need to makeand whether any adjustments would help to ensure 

that their plans achieve the goals as intended without 

jeopardizing the grid. 

The EPA’s supporting analysis for this rule includes an 

examination of the effects of the rule on regional resource 

adequacy. The EPA’s analysis looked at the types of changes in 

the generation fleet that were projected to occur through 

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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 

thesethe 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 

support that economy. The EPA welcomes comments and suggestions 

on this issue. 

VIII. State Plans 

A. Overview 

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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 a standard of performance or 

set of standards of performance, 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 plansplan through 

certain procedures, which include a state hearing. Within the 

time period specified in the emission guidelines (from as early 

as June 30, 2016 to as late as June 30, 2018, depending on the 

state’s circumstances), the state must submit its complete state 

plan to the EPA. The EPA then must determine whether to approve 

or disapprove the plan. If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for the state. 
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In the case of a tribe that has one or more affected EGUs 

onlocated in its landsarea of Indian country, as described in 

the Tribal Authority Rule, the tribe would have the opportunity, 

but not the obligation, to establish a CO2 performance standard 

and a plan for its tribal lands. Consequently, developing a 

develop a CAA section 111(d) tribal plan is optional for 

tribesits area of Indian country. The CAA allows the EPA to 

treat tribes “in the same manner as states” for the purpose of 

implementing CAA programs, while providing flexibility for 

tribes to develop a program tailored to their specific 

circumstances. A tribe that develops a CAA section 111(d) tribal 

plan will actively contribute to helping reduce greenhouse gas 

emissions. Though the EPA is aware of three coal-fired EGUs and 

one natural gas-fired EGU located on tribal landsin Indian 

country, the agency is not proposing specific goals for tribes 

withareas of Indian country containing affected EGUs in this 

action at this time.. The EPA will coordinate with those tribes 

wishing to develop and implement a CAA section 111(d) tribal 

plan by determining BSER for the CAA section 111(d) affected 

units located on the tribe’s area of Indian country. As an 

alternative, the EPA is soliciting comment on tribal 

lands.whether tribes wishing to develop and implement a CAA 

section 111(d) plan should have the option of including the EGUs 
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located on their area of Indian country in a multi-state plan 

(i.e., treating the tribal lands as an additional state). If a 

tribe chooses not to submit a plan, or if the EPA does not 

approve a tribe’s plan, then the EPA mustwould need to determine 

if it is necessary or appropriate to establish a federal plan 

for affected EGUs on tribal landslocated in Indian country. 

This section is organized into fivesix parts. First, we 

discuss the proposed overall approach to state plans, with a 

focus on the different types of plans that we propose to 

authorize states tocould submit, and. Second, we address timing 

for plan implementation and achievement of the required level of 

state emission performance. Second goals for affected EGUs. 

Third, we discuss the proposed state plan approvability 

criteria. ThirdFourth, we summarize the proposed components of 

an approvable state plan. FourthFifth, we address the proposed 

process and timing for submittal of state plans and for 

demonstrating progress and compliance with the emission 

performance levels in the state plans. Fifth. Sixth, we identify 

several key considerations for states in developing and 

implementing plans, including: affected entities with 

obligations under a plan; treatment of existing state programs; 

incorporation of renewable energy (RE) and demand-side energy 

efficiency (EE) programs in certain plans; quantification, 

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monitoring, and verification of RE and demand-side EE measures; 

reporting and recordkeeping for responsible parties; treatment 

of interstate effects; and, projecting emission performance. 

Finally, we discuss a number of additional factors that cancould

help states meet their CO2 emission performance goals, and we 

note certain resources wethat are making 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: Mass-Based Goals and Plan 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 

usefollow in developing plans to establish and implement CO2

standards of performance for affected EGUs. In addition to the 

The proposed state-specific goals described in the Section VII 

of this preamble, the proposed emission plan guidelines include 

four general plan approvability criteria, twelve required 

components for a state plan to be approvable, the process and 

timing for state plan submittal and review, and the process and 
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timing for state plan submittal and review and fordemonstrating

achievement of the CO2 goal. 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 proposed emission guidelines provide 

states with options for establishing performance standards in a 

manner that accommodates a diverse range of state approaches. 

The proposed emissionThe 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 performance 

standards in a manner that accommodates a diverse range of state 

approaches. Each state will be able to determine how to best 

achieve the CO2 goals in light of its specific circumstances, 
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including addressing concerns particular to the state, such as 

employment transition issues, as they design and implement their 

plans over multiple years. As an example, the RGGI states’ 

implementation of their mass-based allowance trading program 

featured the raising of proceeds through allowance auctions and 

the use of those proceeds to advance policies 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, in fact 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 multi-state plan, and we solicit comment on other potential 

mechanisms for fostering multi-state collaboration.

1. State plan approaches 

a. Overview 
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The diversity of measures that qualify as the BSER 

indicatesWe believe that different types of state plans underCAA

section 111(d) plans could be constructed, and the that make use 

of the diversity of measures that comprise the BSER.[add 

examples – RGGI, AB32,...]. Based on EPA’s outreach efforts has 

made, it is clear that in fact, states are considering different 

types of plans. An 

Three important issue common to all types ofissues in the 

design of state plans isinclude: whether the plan should require 

the affected EGUs to be responsible for assuringsubject to 

emission limits that assure that the emissions performance level 

is achieved, or instead, whether the plan could rely on 

measures, such as renewable energy (RE) or demand-side energyefficiency (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, fall on entities other than 

affected EGUs; and 3) 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. 
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The EPA is proposing that all measures relied on to achieve 

the emission performance level be included in the state plan, 

and that inclusion in the state plan renders those measures 

federally enforceable. 

In light of current state programs, and of stakeholder 

expressions of concerns over those issues and legal 

considerations, 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 assure that at least part of that 

level is achieved. A second important issue concerns , as well 

as on affected EGUs for the fact that requiring all measures 

relied on to achieve the emissions performance level to be 

included in the state plan renders those measures federally 

enforceable. In lightbalance of current state programs, along 

with stakeholder concerns over those issues and legal 

considerations, thecompliance. The EPA is proposing to 

authorizerequests comment on this approach, as opposed to the 

approach under which state plans that do not simply would be 

required to hold the affected EGUs fully and solely responsible 

for achieving the emissionsemission performance level. 
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In addition, the EPA is soliciting comment on several other 

types of state plans that may assure the requisite level of 

emissionsemission performance without rendering certain types of 

measures federally enforceable and to 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 designed to reduce CO2 emissions 

from fossil fuel-fired power plants. Existing state programs are 

particularly informative for this purpose in light of the fact 

that 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 
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bear for the required emissionsemission reductions, in 

particular, those from reduced utilization associated with RE 

and demand-side EE measures. These stakeholders recommended that 

the EPA authorize states to achieve emission reductions from RE 

and demand-side EE measures by imposing requirements on entities 

other than fossil fuel-fired EGUs, and without imposing legal 

responsibility for these emission reductions on those EGUs. We 

request comment generally on this approach.

 Accordingly, the EPA is proposing to authorize a state plan 

to adopt what we refer to as thea “portfolio approach,” in which 

the plan would include emission limits for affected EGUs along 

with other enforceable measures, such as RE and demand-side EE 

measures, that reduce utilization of affected EGUs and thereby 

avoid CO2 emissions. Under this approach, all of the measures 

combined would be designed to achieve the required emission 

performance level for affected EGUs. However, the emission 

limits enforceable against the affected EGUs would not, on their 

own, 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 emissionsemission reductions from, the affected 

EGUs. As noted, these other measures would be federally 

enforceable because they would be included in the state plan. A 

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portfolio approach could be used for state plans that establish 

the emissionsemission 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 

RE and demand-side EE measures that avoid EGU CO2 emissions.244

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

would include emission limits for affected EGUs, as well as 

requirements that apply directly to entities other than affected 

EGUs, for example, renewable portfolio standards or end-use 

energy efficiency resource standards (EERS), both of which often 

apply to electric distribution utilities.245

It should be evident that these plan approaches differ 

substantially in the mechanics used to achieve the required 

 

244 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.

245 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 generationgenerating assets. 
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level of emission performance for affected EGUs, including 

necessary plan elements and the relative degree of plan 

complexity. The plan approaches also differ with regard to the 

partyentity or partiesentities that are responsible for 

achievement of the required level of emission performance. As a 

result, a state may develop an approach for cost-effectively 

reducing EGU CO2 emissions that best suits its circumstances and 

may select whether elements of the state approach are 

enforceable components of a plan or complementary to an 

enforceable measure in a plan. 

c. Obligations on affected EGUs 

Although the EPA is proposing to authorize state plans to 

adopt the portfolio approach, we are mindful that it presents a 

legal issue that bears further analysis. We describe, and 

solicit comment on, that issue below. In brief, it may be 

possible to read CAA §section 111(d)(1) as requiring that, when

the EPA promulgates emission guidelines to achieve emission 

reductions from a particular source category, thereby triggering 

state obligations to adopt plans that include standards of 

performance as well as implementing and enforcing measures, the 

standards of performance must impose the responsibility for 

achieving the required emissionsemission reductions on the 

sources in the affected source category. Accordingly, again as 
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noted below, we are soliciting comment on whether state plans 

must require the affected EGUs to be legally responsible for 

achieving the emissionsemission performance level. 

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 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 limits 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 demandside EE measures could be either enforceable components of the 

plan or complementary to the plan. In this manner, RE and 

demand-side EE measures could be a major component of a state’s 
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overall strategy for cost-effectively reducing EGU CO2

emissions.246 at a reasonable cost. 

It should be noted that state plans that impose legal 

responsibility on the affected EGUs to achieve the full level of 

required emissions performance could incorporate enforceable RE 

and demand-side EE measures regardless of whether the standards 

of performance that those plans apply to the affected EGUs take 

the form of an emissions rate or a mass limit. Plans with ratebased 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 

 246 It should be noted that state plans that impose legal 

responsibility on the affected EGUs to achieve the full level of 

required emissions performance could incorporate enforceable RE 

and demand-side EE measures regardless of whether the standards 

of performance that those plans apply to the affected EGUs take 

the form of an emissions rate or a mass limit. Plans with ratebased 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 crediting 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 relies on mass-based 

emission limits would be federally enforceable through the 

standard of performance that applies to an affected EGU itself 

(i.e., enforceable against the EGU). Such a plan would not need 

to make any adjustment or crediting to account for RE or demandside EE measures. 
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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 

We are also cognizant of anotherAnother concern expressed 

by some stakeholders, which is that including RE and demand-side 

EE measures in state plans would render those measures federally 

enforceable and thereby extend federal presence into areas that, 

to this pointdate, largely have been the reserveexclusive 

preserve of the state and, in particular, state public utility 

commissions and the electric utility companies they regulate. 

These stakeholders point out 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 those circumstances, the EGU emission limits would be 
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federally enforceable but RE and demand-side EE measures would 

serve as complementary measures and would not be enforceable 

under federal law, but ; instead, they would remain enforceable 

under state law. According to stakeholders, those types of state 

programs, particularly because they are well-established, can be 

expected to achieve their intended results. Thus, 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 aanother vehicle for approving CAA section 111(d) plans 

for states that wish to rely on state RE and demand-side EE 

programs but do not wish to include those programs in their 

state plans, the EPA requests comment on what we may refer to as 

a “state commitment approach.” This approach differs from the 

proposed portfolio approach, described above, in one major way: 

Underunder 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 
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federally enforceable) measures that would achieve a specified 

portion of the required emissions reductions of emission 

performance on behalf of affected EGUs. The agency requests 

comment on the legal authority for appropriateness of this 

approach. The agency also requests comment on the policy 

ramifications of the following: Underunder 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 emissionsemission

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 legal 

responsibility on affected EGUs for ensuring the emissions 

performance level. With this variation, the state plan would in 

effect shift a portion of that responsibility to the state, in 

the following manner: Thethe state plan would impose the full 

responsibility for achieving the emissionsemission performance 

level on the affected EGUs, but the state would credit the EGUs 

with the amount of emissionsemission reductions expected to be 

achieved from, for example, RE or demand-side EE measures. The 
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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 emissionsemission

performance level, this type of state plan would meet that 

requirement while also assuring those EGUs an important measure 

of support. 

f. Legal issues 

[NOTE: PER THE ADMINISTRATOR’S REQUEST, OGC HAS EXPANDED 

THE DISCUSSION OF THE POSSIBLE LEGAL INTERPRETATIONS OF 111(d). 

OGC IS CONTINUING TO WORK ON SEVERAL ASPECTS OF THIS. FURTHER 

DISCUSSIONS ON TONE MAY BE NEEDED.] The EPA is required to 

promulgate emission guidelines for state plans to address 

emissions from sources in a source category for which the EPA 

has promulgated requirements under CAA section 111(b). CAA 

section 111(d)(1) requires that the state plans “(A) establish[] 

standards of performance for any existing source [for certain 

air pollutants] . . . and (B) provide[] for the implementation 

and enforcement of such standards of performance.” CAA section 

111(a)(1) defines a “standard of performance” as “a standard for 

emissions of air pollutants which reflects the degree of 
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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, important issues with respect to the portfolio approach 

discussed in this proposed rulemaking concern (1) whether , in 

addition to such emission limits are the only mechanisms that on 

affected EGUs, state plans may include other measures for 

achieving the emissionsemission performance level, and (2) 

whether onlyentities other than affected EGUs may be subject to 

requirements associated with that contribute to reducing 

theirEGU emissions. The resolution of thoseWe discuss these

issues depends on whether the state plan requirements in 

section 111(d)(1), quoted above, are interpretedbelow, and, in 

doing so, solicit comment on possible interpretations that the 

only measures that may be included in a state plan are standards 

of performance and measures that implement and enforce those 

standards, so that the standards of performance must apply to 

the sources in the source category; and whether the definition 

in section 111(a)(1) is interpreted so that the standards of 

performance must consist of emission limitations and must 

achieve the full degree of emission limitation that results from 

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application of BSERwe could adopt as a basis for the portfolio 

approach. 

Specifically, we solicit comment on interpretations of 

these provisions that would authorize the portfolio approach 

described above. First, we solicit comment on whether state 

plans are limited to standards of performance and measures that 

implement and enforce those standards. Specifically, although 

section 111(d)(1) does not identify any types of measures other 

than those ones, does it preclude state plans from including 

other measures? Interpreting section 111(d)(1) to include other 

measures could provide a basis for the portfolio approach 

described above. 

The resolution of these issues depends in part on the 

threshold question of whether the phrases “standards of 

performance for any existing source” and “the implementation and 

enforcement of such standards of performance” can be read to 

encompass the various components of the portfolio approach. In 

looking at this threshold question, we solicit comment on 

interpreting the phrases “standards of performance” and 

“implementation and enforcement of such standards” in CAA 

section 111(d) to authorize the portfolio approach described 

above. CAA section 111(d) requires states to set performance 

standards “for” affected sources. Standards could be interpreted 
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to be “for” fossil fuel-fired EGUs if they were to result in 

reduced emissions from fossil fuel-fired EGUs, even if the 

standards did not apply directly to fossil fuel-fired EGUs. 

Under this interpretation, renewable energy and demand-side 

energy efficiency requirements could be standards “for” existing 

EGUs. Implementation and enforcement measures could also be 

interpreted to include measures such as RE and demand-side EE 

that reduce emissions from fossil fuel-fired plants. We request 

comment on these interpretations, as well as the following 

specific issues. 

First, we solicit comment on whether the definition in CAA 

section 111(a)(1) could be interpreted so that standards of 

performance could include measures that are not enforceable 

against the affected EGUs or whether it must be interpreted so 

that the standards of performance may only consist of emission 

limitations on affected sources and must achieve the full degree 

of emission limitation that results from application of BSER. 

Second, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include the emissionsemission

performance level – that is, the adjusted, average emission rate 

for affected EGUs in the state – on grounds that the level is “a 

standard for emissions” because it is in the nature of a 
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requirement that concerns emissions and it is “for” the affected 

sources because it helps determine their obligations under the 

plan. Interpreting the requirement in this manner could provide 

a basis for the portfolio approach because RE and demand-side EE 

measures could be considered measures that implement the 

emissionsemission performance level. 

Third, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include measures such as RE 

and demand-side EE measures, even if they may not directly 

reduce emission rates of the affected EGUs or are not 

enforceable against the affected EGUs, on grounds that they are 

associated with reducingindirectly reduce CO2 emissions from 

affected EGUs. 

 Fourth, the EPA is soliciting comment on whether measures 

such as RE and demand-side EE measures, even if they are not 

enforceable against the affected EGUs, may be included in the 

state plan as measures that “implement[] and enforce[]” the 

plan’s standards of performance. For example, if the plan 

achieves the emissionsemission performance level through ratebased emission limits applicable to the affected sources, 

coupled with a crediting mechanism for RE and demand-side EE 

measures, it may be argued that RE and demand-side EE measures 
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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 whether measures such as RE 

and demand-side EE may be considered “implement[ing]” measures 

in state plans if they are not associated withdirectly tied to

emission reductions that affected sources are required, to make

through emission limits, to make. 

FinallyFifth, the EPA solicits comment on whether state 

plans may include, either as standards of performance or as 

“implement[ing]” measures, requirements on entities other than 

the affected sources. 

TheFinally, in light of these legal issues, we solicit 

comment on whether, in the final rule, we should authorize 

different approaches in the alternative. For example, we could 

authorize the portfolio approach, but further provide that if 

legal challenges were successful, then, without the need for 

further notice-and-comment rulemaking by the EPA, states would 

be required to submit plans that achieve the emission 

performance level through emission limits on the affected 

sources. It should be noted that we consider those two 

approaches, as well as the other approaches for which we solicit 

comment, to be severable from each other. 
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Alternatively, the EPA acknowledges that commenters may 

argue that the conclusion to the threshold question is that the 

components of the portfolio approach are not all within the 

scope of “standards of performance for any existing source” 

and/or “the implementation and enforcement of such standards of 

performance.” In that case, the question becomes whether CAA 

section 111(d)(1) could be read to allow state plans to include 

the components of the portfolio approach because they 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.” If not, must the 

agency interpret CAA section 111(d) to prohibit state plans from 

including measures that are neither standards of performance nor 

measures to implement or enforce them? No specific language in 

CAA section 111(d) prohibits states from including measures 

other than performance standards and implementation and 

enforcement measures. EPA specifically requests comment on 

whether there is any other basis for concluding that CAA section 

111(d) allows or precludes state plans from including other 

measures provided that they would result in the reduction of 

emissions from existing sources. The EPA notes that cooperative 

federalism, which is one of the foundational principles of the 
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Clean Air Act, includes providing flexibility to states to meet 

environmental goals (provided minimum CAA statutory requirements 

are met). The EPA takes comment on whether 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 CAA section 111(d) to include 

in their CAA section 111(d) plans other measures (i.e., measures 

that are neither performance standards nor measures that enforce 

or implement performance standards). Finally, the EPA solicits 

comment on all other aspects of this question concerning the 

scope of measures allowed in state plans under CAA section 

111(d). 

Notwithstanding the specific requests for comment above, 

the EPA solicits comment on all legal issues under CAA section 

111(d)(1) with respect to the approaches described in this 

section and in the discussion above on portfolio approach and 

the types of state plans and measures that are discussed in this 

preamble. 

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 
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to be subject to those requirements even after it undertakes a 

modification or reconstruction. Under this interpretation, a 

modified or reconstructed source would be subject to both (1) 

the CAA section 111(d) requirements that it had previously been 

subject to and (2) the modified source or reconstructed source 

standard being promulgated under CAA section 111(b) 

simultaneously with this rulemaking. It should be noted that 

this proposal applies to any existing source subject to any CAA 

section 111(d) plan, and not only existing sources subject to 

the CAA section 111(d) plans promulgated under this rulemaking. 

As noted above, a “new source” is defined under CAA section 

111(a)(2) as “any stationary source, the construction or 

modification of which is commenced after,” in general, a 

proposed or final CAA section 111(b) rule becomes applicable to 

that source; and under 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 
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reconstructs. For example, CAA section 111(d) provides that the 

state plans will “establish[] standards of performance for any 

existing source” but does not say whether, once a standard of 

performance is established for a given source, that standard is 

lifted if the source ceases to be an existing source. Similarly, 

no other provisions of CAA section 111 address whether the 

imposition of a CAA section 111(b) standard on a modified or 

reconstructed source ends the source’s obligation to meet any 

applicable CAA section 111(d) requirements. 

Because CAA section 111(d) does not address whether an 

existing source that is subject to a CAA section 111(d) program 

remains subject 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 
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incentives for sources to seek to avoid their obligations under 

a CAA section 111(d) plan by undertaking modifications. The EPA 

is concerned that owners or operators of units might have 

incentives to modify purely because of potential discrepancies 

in the stringency of the two programs, which would undermine the 

emission reduction goals of CAA section 111(d). The EPA invites 

comments on this interpretation, 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. 

2. Timing for implementation and achievement of goals 

 This section addresses describes proposed state plan 

requirements related to the process and timing for demonstrating 

achievement of achieving emission performance goals and 

compliance with the emission, including performance levels in 

the state plans.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 carbonCO2

emissions, particularly blocks 3 (expansion of cleaner 

generationgenerating capacity) and 4 (increasing demand-side 

energy efficiency), on forward-looking, longer-term assumptions. 

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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 generationgenerating capacity over time. As suchTherefore, 

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 benefit to 

benefits that allow states to develop plans that will help 

Statesstates 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 

reductionsperformance between 2020 and 20302029, as long as the 

interim emission performance level is met on a 10-year average 

or cumulative overall emission reduction target is met.basis and 

the 2030 emission performance level is achieved. The EPA is also 

proposing that states submitting complete plans by June 30, 2016 

have the option to begin meeting interim goals earlier than 2020 

and that the average emission performance through 2029 could 
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reflect a higher emission rate reflective of the longer 

trajectory for achievement of the final CO2 goal by 2030. 

 The subsections below contain proposals for: a) a more 

thorough discussion of the time period covered by state 

plansplan 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, and e) out-year requirements 

for states to maintain over time CO2 emission performance levels 

consistent with the final goal. TheIn subsection f, the agency 

also is requestingrequests comment on alternative requirements 

aimed at continued emission performance improvement after 2029. 

Section [VII. F]Subsection g proposes flexibility fromfor states 

to change from mass-based to rate-based goals in different 

performance periods, and subsection [VII.G] takes comment on 

planning requirements that match the agency’soption of

alternative, less stringent state goals. 

a. Time period covered by state plans 

a. Performance demonstrations 

 As described previously, the agency is proposing final 

state-specific goals (specified in Table 5) that represent 

emission rates achievableto be achieved by 2030, as well as 

interim goals, achievableto be achieved on average over the 10-
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year period from 2020-2029. The agency is also proposing that 

emission performance levels consistent with the final statespecific goals be maintained fromafter 2030 and thereafter. 

 This relatively long planning and implementation period 

provides states with substantial flexibility regarding methods 

and timing of achieving emission reductions. States may wish to 

make adjustments to their implementation approaches along the 

way, or as conditions change may need to make adjustments to 

ensure that their plans achieve the goals as intended. As a 

result, the agency envisions that the EPA, states, and 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. In its planSpecifically, the state plan must also 

demonstrate that the projected emission performance meeting the 

level 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 will be maintainedduring the year 2030. The state plan must 

identify requirements that continue to apply after 2030 and are 
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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. Instead, the EPA proposes that the state 

plan would be considered to provide for maintenance of emission 

performance consistent with the final goal if the plan measures 

used to demonstrate achievement of the final goal by 2030 will 

continue in force and not sunset. 

 In addition to demonstrating that projected plan 

performance will meet the interim and final state goals, the EPA 

proposes that state plans must contain requirements for tracking 

actual plan performance during implementation. For plans that do 

not include enforceable requirements for affected EGUs that 

ensure achievement of the full level of required emission 

performance and interim progress, the state plan 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. 
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 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.247 Also, if the state plans address both achievement 

and maintenance of the goals, additional state submittals may be 

simpler and, for some states, unnecessary, depending on the 

nature of state programs and out-year requirements. 

 The EPA recognizes that the proposed approach requires 

states to make projections regarding electricity demand, supply, 

and capacity utilization of individual units, as well as the 

estimated effect of state measures included in a plan, for a 

lengthy period of time into the future. Therefore, the agency 

also is requesting comment on alternative approaches. 

 The agency requests comment on a second option in which

state plans would be required to demonstrate achievement of the 

 

247 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 BSER-based level is a more 

stringent level than the 2020-2029 average BSER-based level. The 

purpose of the final goal to be achieved and maintained is to 

ensure that each state ultimately achieves the emissionsemission

performance level for affected EGUs that is achievable by 2029 

through application of BSER. Depending on the emission 

performance improvement trajectory required by a state plan, a 

state plan that will achieve the 2020-2029 interim goal may or 

may not also result in meeting the 2030 final goal.
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interim and final goals but would not be required to demonstrate 

that the final, in addition to submitting a plan demonstrating

emission performance level will be maintained over time. 

Insteadthe 2020-2030 period, 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 (under one of the out-year approaches described in the 

relevant section below). If not, the state submittal would be 

required to strengthen or add to measures in the state plan 

additional measures to the extent necessary to maintain that 

level of performance over time. 

 The agency also requests comment on a third option in which 

the state plan would focus on the interim goal only. Because 

state plans may underperform with regard to the interim goal in 

the early years of the 10-year period and outperform the interim 

goal in the latter years of the period, the plan measures that a 

state implements by the last part of the interim goal period may 

be sufficient to achieve the final goal as well. Under this 

option, the state would make a second plan submittal in 2025 to 

demonstrate that the final goal will be met by existing plan 

measures. If not, the state submittal would be required to 

strengthen the state plan with additional measures so that the 
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plan will achieve the final goal and maintain that level of 

performance thereafter. 

 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 and third optionsoption. 

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 2020 for 

the interim goal plan performance period.248 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 

 

248 The start date for a plan performance period must match the 

start date of the corresponding state emissionsemission

performance goal. If a start date other than January 2020 were 

selected, the EPA would recompute the state goals consistent 

with the selected start date.
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that regulatedaffected entities may have greater lead time for 

compliance than might be implied by the plan submittal dates 

referenced above. RegulatedAffected 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 emissionsemission

performance improvement trajectory thanfrom that which the EPA 

assumes for purposes of calculating state goals, achieving 

lesslesser levels of performance in early years and more in 

later years. 

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 emissionsemission performance levels. Second, in 

advance of this proposal, many states already were contemplating 

design of strategies for meeting the requirements ofthat 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 viablefeasible

and broadly applicable, and can provide cost-effective 
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reductions in CO2 emissions from affected existing 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 engineered solutions used to improve 

heat rates at existing EGUs have long been commercially 

available and have been implemented at EGUs for many years. 

Further, the relatively modest capital costs (average $100/kW) 

and significant fuel savings associated with a suite of heat 

rate improvement (HRI) methods result in this measure being a 

low-cost approach to reducing CO2 emissions from existing EGUs. 

HRI “best practices” (e.g., installation of modern control 

systems, operator training, smart soot blowing) are the least -

cost HRI methods and can be applied quickly, without lengthy EGU 

outages. The somewhat more costly HRI “upgrades”(” (e.g., steam 

turbine upgrade, boiler draft fan/driver upgrade) may require 

modest EGU outages to implement, but have also been applied on 

numerous EGUs to improve or maintain performance. Drawing on the 

power sector’s extensive experience with HRI methods, and the 

many existing supply chains already supporting these methods, 

the EPA expects that it would be feasible to implement HRI 
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projects (i.e., building block 1) over a four-year period 

concluding inby 2020. 

Dispatch changes, which are largely driven by the variable 

cost of operating a given electric generating unitEGU, 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 (source: NERC, 2008-

2012 Generating Unit Statistical Brochure).249. In addition, the 

existing natural gas pipeline and electricity transmission 

networks are already connected to every existing NGCC facility, 

and can support aggregate operation of the NGCC fleet at 70 

percent (or above) at the state level, or can be reasonably 

expected to do so in the time frame for compliance with this 

rule. Therefore, building block 2, which represents shifting of 

generation from steam fossil EGUs to existing NGCCs, is a viable 

method for providing CO2 reductions at existing EGUs by the 2020 

compliance start date. 

Building Block 3 is based on shifting generation from 

steamaffected 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). 

 

249 Source: NERC, 2008-2012 Generating Unit Statistical Brochure

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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 provide cost 

effectiveachieve reductions in CO2 emissions from existing EGUs. 

The building at a reasonable cost. Building block 4 represents a 

feasible pathway for reducing utilization of carbon-emitting 

EGUs by implementing improvements in demand-side energy 

efficiency. This building block is based on a “best practices” 

scenario where all states achieve a level of performance – 

matching a level achieved or committed to by twelve leading 

states – of 1.5 percent annual incremental electricity savings 

as a percentage of retail sales. For the best practices 

scenario, all states achieve this level of performance no later 

than 2025, with leading states reaching the goalthis level

sooner. Each state’s current level of performance is taken into 

account, with state’sstates 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 
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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 

emissionsemission 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, demandside energy efficiency programs) may require several years to 

implement due tobecause of the time necessary to establish the 

proper infrastructure if a state does not already have such 

programs in place. Though some states have already implemented 

such programs that are achieving results, other states may have 

to establish them for the first time. New single and multi-state 

programs, as well as existing single and multi-state programs 

that are adding or revising measures, may need time for 

implementation to achieve the required level of emission 

performance. 

 As described in Section VII of the preamble, the EPA is 

proposing 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 

emissionsemission performance, while ensuring an overall level 

of performance consistent with the application of BSER. 

Specifically, the agency is proposing the state-specific goals 
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(shown in Table 5) which represent emission rates to be achieved 

by 2030 (final goal) and emission rates achievableto be achieved

on average over the 2020-2029 period (the interim goal.).

 The EPA proposes the following Option A as the preferred 

option for the final and interim goal performance periods. AAs 

further explained below, this option reflects three main 

objectives: (1) provide states with timing flexibility during 

the interim goal period to accommodate differences in state 

adoption processes and types of state programs, (2) ensure that 

state plans are designed to achieve the final goal no later than 

2030, and (3) provide flexibility for year-to-year variation in 

actual emission performance that may occur as the electricity 

system responds to economic fluctuations. 

Interim goal – Projected plan performance demonstration: To be 

approvable, a state plan must demonstrate that the statewide 

emission performance of affected EGUs will meet the interim 

emission performance level on average over the 2020-2029 period.

Similarly, the EPA proposes that plan measures 

Interim goal – Actual plan performance check: In 2030, the 

emission performance of affected EGUs during the period 2020-

2029 must initially achieve the final be compared against the 

interim goal. (In addition, as described separately below, 
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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 byno later than 2030, as reflected byon a 

3single-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 over 

thebasis (i.e., 2030-32 period. , 2031-33, 2032-2034, etc.). 

 This proposed approach provides a 10-year performance 

period for the interim performance level, and a three-year 

performance period for the final performance level.. The 10-year

interim performance period allows states flexibility for timing 

of program implementation as the state ramps up its programs to 

achieve the final performance level. The three-year performance 

period for initial achievement of the final performance level 

isUsing the single year 2030 as the projected year for 

achievement of the final goal ensures that state plans are 

designed to achieve the final goal no later than 2030; providing 

a multi-year time frame for projected plan performance would 

inappropriately delay the requirement for a final-goal level of 

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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 

output250 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.EF. 

For a mass-based plan, 2020-2029 emission performance is total 

tons of CO2 emitted by affected EGUs over the ten10-year 

performance period. 

 

250 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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 As noted, a 10-year performance period -- with a 

demonstration of average or cumulative performance over the 

period -- offers states flexibility in the timing of emission 

improvements. However, to ensure accountability throughout the 

course of the 10-year period, the EPA is proposing that certain 

types of state plans include interim progress milestones, as 

described in Section VIII.A.2.c of this preamble. 

 The EPA also requests comment on a second approach, Option 

B, to state plan performance periods. Option B is the same as 

Option A except thatUnder this approach, in addition to the 

requirements for Option Athe proposal, a state plan also would 

also need to achieve a 5five-year average emission performance 

level reflecting application of BSER for the 2020-2024 period. 

This 5five-year performance period would nest within the 10-year 

performance period for the 2020-2029 period. The purpose of 

Option Bthis approach would be to ensure greater emission 

performance improvement during the first five years of the 

interim goal plan performance period by precluding states from 

significantly delaying compliance obligations until the last 

five years. However, Option Bthis approach also would reduce 

states’ flexibility for the timing of emission improvements over 

the 2020-2029 period. 
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 The agency invites comment on any other approaches to 

specifying performance periods for state planplans. 

d. Interim progressProgram 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 

programmaticprogram implementation milestones to ensure interim 

progress, as well as periodic checks on overall 

emissionsemission performance leading to corrective 

actionmeasures 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 EGU, 

and we refer to these as “self-correcting” plans.EGUs. One 

example would beis a state plan with a rate-based emission 

performance level that requires affected EGUSEGUs collectively 

to meet, on a three-year average basis, a statewidean emission 

rate consistent with the state’s required emission performance 

level, and allows EGUs to comply through an emission rate 
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averaging system. Another example is a plan that includes 

measures or actions (e.g., emission limits that apply to

affected EGUs and ensure full plan performance) that take effect 

automatically if the plan’s required emission performance level 

is not met, in accordance with a specified milestone. The EPA 

requests comment on whether there are other types of state plans 

that should be considered “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. 

 For plans that are not self-correcting, the EPA proposes 

that the state plan must identify periodic programmaticprogram 

implementation milestones (e.g., start of an end-use energy 

efficiency program, retirement of an affected EGUsEGU, 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 programmatic milestones in its plan, the 

EPA wouldimplementation milestones in its plan, it would need to 

report the delay to EPA, explain the cause, and describe the 
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steps the state will take to accelerate subsequent 

implementation to achieve the planned improvements in emission 

performance. Depending on the severity of delay and the 

explanation, the EPA could ultimately evaluate actions under CAA 

authorities to ensure timely program implementation. 

 In addition, we propose that the state and the EPA would 

check 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, the state would be 

required to include a comparison of emission performance 

achieved versusto performance projected in the state plan at 

least everyeach year from the end of 2022 through the end of 

2028. Each comparison would cover the preceding two years. -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). 

If actual emission performance isof affected EGU was not 

within 10 percent of originalplan projections, the state would 

be required to submit a report to the EPA within 6 months of the 

two-year check point. The report wouldin its submission to

explain reasons for the deviation (e.g., energy efficiency 

program not working as effectively as expected, prolonged 
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extreme weather that had been unanticipated in electricity 

demand projections) and specify the corrective actionsmeasures

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 actionsmeasures as 

expeditiously as practical. The EPA requests comment on whether 

the corrective actions to be triggered in case of an emissions 

performance deficiency should be adopted in rules and included 

in the original plan, or should be identified and adopted by the 

state after the deficiency is found.

 The EPA proposes that the corrective measures to be 

triggered in case of an emission performance deficiency must be 

adopted as enforceable measures included in the original state 

plan. These previously adopted corrective measures would reduce 

the delay between the time an emission performance deficiency is 

discovered, and the time that corrective action can begin. 

Alternatively, the agency requests comment on whether states 

should be allowed to identify and adopt corrective measures 

after a performance deficiency is found. 

 At the end of the 2020-2029 performance period, the EPA 

proposes that the state be required to compare actual emission 

performance achieved during the performance period against the 

interim goal. As noted above, beginning after 2032, EPA proposes 
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that the state be required to compare actual emission 

performance achieved against the final goal on a rolling threeyear 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 

Option B and the planning approach for alternative state goals, 

which is described below. 

e. Consequences if actual emission performance does not meet 

state goal 

 There are scenarios under which an approved state plan 

might fail to achieve a level of emission performance by 

affected EGUs that meets the state goal. Under some types of 

plans, a possible scenario is that despite successful plan 

implementation, emissions under the plan turn out to be higher 

than projected at the time of plan 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 

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responsibilities, or because the state did not fulfill its 

responsibilities. 

 The EPA believes that the emission guidelines should 

specify the consequences in the event that actual emission 

performance under a state plan does not meet the applicable 

interim goal in 2020-2029, or does not meet the applicable final 

goal in 2030-2032 or later, because CAA section 111(d) is not 

specific on this point. The agency requests comment on how the 

consequences should vary depending on the reasons for a 

deficiency in performance. 

 Specifically, the agency requests comment on whether 

consequences should include the triggering of corrective 

measures in the state plan, or plan revisions to adjust 

requirements or add new measures. The agency also requests 

comment on whether corrective measures, in addition to ensuring 

future achievement of the state goal, should be required to 

achieve additional emission reductions to offset any emission 

performance deficiency that occurred during a performance period 

for the interim or final goal. This concept has been applied, 

for example, in the acid rain 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 
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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 made a finding of the plan's failure 

to achieve the state goal during a performance period, EPA would 

require the state to cure the deficiency with a new plan within 

a specified period of time (e.g., 18 months). If the state still 

lacked an approved plan by the end of that time period, the EPA 

would have the authority to promulgate a federal plan under 

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

e.f. Out-year requirements: Maintaining or improving the level 

of 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 emissionsemission performance should only be 

maintained -- or instead should be further improved -- once the 

2030-2032final goal is met in 2030. This involves questions of 

goal-setting as well as questions about state planning. In this 
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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 beyond the proposed plan performance 

periods.after 2030. The EPA requests comment on mechanismsis 

proposing a mechanism for implementing this objective, including 

but not limited to the following options. The EPA also asks 

whether states should be allowed to choose from among the 

options below.and is taking comment on an alternative option. 

One implementation option would be to requireAs noted 

above, the EPA proposes that the state plan tomust 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 
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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.251 After implementation, the 

state would be required to compare actual plan performance 

against the final goal on a rolling three-year average basis 

starting in 2030, and to implement corrective measures if 

necessary. 

 The EPA also requests comment on an alternative approach to 

a state’s 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 plan period final goal on a three-year 

 

251 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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rolling average basis for up to 10 years (i.e.,beyond 2030-32 

through 2039-41). This approach could be implemented through a 

second round of state plan analysis and submittals, perhaps in 

2025, to make the demonstration and add any new measures if 

necessary. EPA requests comment on whether the performance 

period for the rolling average should be a period other than 

three years, and on whether a year later than the year 2025 

would be preferable for a state plan to maintain emission 

performance after 2032. 

 The EPA also requests comment on a second “no backsliding” 

implementation option requiring continued implementation of plan 

measures for plans with EGU emission limits that ensure the full 

level of performance required. The state could either continue 

to implement those limits (no new submittal required)strengthen

or substitute other measures with equivalent effectiveness (new 

submittal required to make this effectiveness demonstration). 

 The EPA further requests comment on how a “no backsliding” 

concept could be implemented for end-use energy efficiency and 

renewable energy programs and add measures. For renewable energy 

programs, the agency requests comment on requiring that the 

renewable portfolio percentage level that was relied upon to 

demonstrate achievement of the 2030-2032 performance level be 

maintained. The EPA requests comment on what should be required 
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of end-use energy efficiency programs and measures that often 

involve an annual percentage energy savings requirement or goal, 

and require additional monetary expenditures each year to meet 

those savings requirements or goals. 

 if necessary. The EPA generally requests comment on 

appropriate requirements to maintain the emission performance of 

affected EGUs in years after 20322030. 

Alternatively, theThe EPA also requests comment on whether 

the EPAwe 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 BSER in 2030 and beyond to a specified 

time period and final date. The agency requests comment on the 

appropriate time period(s) and final year for the EPA’s 

calculation of state goals that reflect application of BSER

under this approach. 

f.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 plan performance level for 

each performance period. For example, if a state plan used a 

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mass-based performance level for the 2020-2029 period, the state 

plan may still use a rate-based performance level for the 2030-

2032final goal performance periodperiods, 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 additional emissions headroomflexibility in light of 

anticipated economic growth after 2029. The state either could 

adopt a rate-based performance level consistent with the final 

goal for specified time periods, or could adopt a new mass-based 

performance level thatbased on a translation of the state 

demonstrates will meet its translated,rate-based final goal to a

mass-based post-2029 goal for the relevant performance 

period.goal. 

g.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 a matching optionanother approach for state plan 
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performance periods, Option C.. This optionapproach would 

require state plans to showdemonstrate that the required interim 

emission performance level will be met on average by affected 

EGUs during the five-year 2020-2024 period. The required post2024 level ofinterim period, and that the alternative final goal 

be met no later than 2025. After plan implementation, actual

emission performance would be initially demonstratedcompared 

with the alternative final goal on a three-year rolling average 

basis for, 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.

This demonstration would be required as part of the same plan 

submittal that addresses 2020-2024 emission performance. 

 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 subsection 

e). For the out-year concepts that involve additional state 

planning and demonstrations,. The EPA requests comment on 

whether state plans due in 2016-2018, a second state plan due 

later, or other mechanisms that do not require a second plan 

submittal should provide for maintaining emission performance 

after 2027. 2025 solely through post-implementation emission 
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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 submittalssubmittal

designed to maintain emission performance after the 2025-2027

performance level is achieved. 

C. Criteria for Approving State Plans 

The EPA is proposing to require the twelve plan components 

discussed elsewhere in Section VIII.D of this preamble. We will 

evaluate the sufficiency of each plan meetingbased on the plan 

addressing those components basedand on four general criteria 

for a state plan to be approvable. 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 the applicable state-specific 

CO2 goal and derivative emission performance level in the 

emission guidelines, on a timeline equivalent to that in the 

emission guidelines.252 Third, EGU CO2 emission performance under 

the state plan must be quantifiable and verifiable. Fourth, the 

 

252 Flexibilities provided to states in meeting this general 

approvability criterion are discussed below in Section 

VIII.B.2., emission performance.
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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 

actions, if necessary. The EPA takesrequests comments on all 

aspects of these general criteria and the ten 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 

The first criterion inIn developing its plan, to ensure 

that the plan is enforceable and in conformance with the CAA, a 

state should follow established EPA guidance on 

enforceability.253 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 

 

253 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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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. 

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 also proposing that 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 that, by facilitating reduced utilization 

of affected EGUs, would , such as RE and demand-side EE 

measures, that avoid EGU CO2 emissions, and would beare

implemented by the state or by another partyentity assigned 

responsibility by the state. As noted above, we are proposing 

that state plans needare not be required to impose emission 

limits on affected EGUs that in themselves fully achieve the 

emission performance level, but. 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 should 

include additional measures that would apply if any of the other 

portfolio of measures in the plan are not fully implemented, or 
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if they are, but the plan fails to achieve the required level of 

emission performance.254 

The EPA recognizes that a portfolio approach may result in 

enforceable state plan obligations accruing to a diverse range 

of affected entities beyond affected EGUs, and that there may be 

challenges to practically enforcing against some such entities 

in the event of noncompliance. We request comment 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.EF. 

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, for example, lb CO2/MWh) 

or tonnage CO2 emission outcome by all affected EGUs equal to, or 

 

254 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 indirect measures that avoid EGU CO2

emissions, or emissions limits that apply to affected EGUs.
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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 BSER reduce 

CO2 emissions from affected EGUs. As a result, the EPA is not 

proposing that out-of-sector GHG offsets could be applied to 

demonstrated CO2 emission performance by affected EGUs in a state 

plan. 

However, states could still include in their plans emission 

limits for affected EGUs that include the ability to use GHG 

offsets for compliance, provided those emission limits would 

achieve the required level of emission performance in a state 

plan. 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. They 

note that existingExisting ISOs and RTOs 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. 

3. Quantifiable and verifiable emission performance 

The third criterion for approvability is that a state plan 

specifyplanspecify how the effects of each state plan measure 
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will be quantified and verified. At a minimum, the EPA proposes 

that all plans must specify how CO2 emissions from affected EGUs 

are monitored and reported. The EPA is proposing that both massbased and rate-based plans must include CO2 emission monitoring, 

reporting, and recordkeeping requirements for affected EGUs, as 

specified in the emission guidelines. A rate-based plan must 

also include monitoring, reporting, and recordkeeping 

requirements for useful energy output from affected EGUs 

(electricity and useful thermal output), as specified in the 

emission guidelines. With one exception, these proposed 

requirements are consistent with those in the proposed EGU 

Carbon Pollution Standards for New Power Plants. See 79 FR 1430-

1519 (January 8, 2014). The exception is that we are proposing 

that useful energy output be measured in terms of net output 

rather than gross output, as discussed below. 

For state plans that include other measures that avoid EGU 

CO2 emissions, such as RE and demand-side EE measures, the state 

will also need to include quantification, monitoring, and 

verification provisions in its plan for these measures, which 

may vary depending on the types of requirements included in the 

specific plan, as specified in the emission guidelines. This may 

include, for example, quantification, monitoring, and 
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verification of RE generation and demand-side EE energy savings 

under a rate-based approach.255

4. Reporting and corrective actions 

The fourth criterion for approval is that a state plan (i) 

specify a process for periodic reporting to the EPA of overall 

plan performance and implementation (including compliance of 

affected entities with applicable standards of performance) 

during the plan period, and (ii) include a process and schedule 

for modification 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 thea multi-year plan 

performance period if emission performance is not met, or at 

specified interim stages within thea multi-year plan performance 

 

255 Considerations for quantification, monitoring, and 

verification of RE and demand-side EE measures are addressed in 

Section VII.E of this preamble and in the State Plan 

Considerations TSD. 
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period. For plans with self-correcting mechanisms, the agency is 

not proposing that requirements for modification be included in 

the plan. All of these considerations are addressed in more 

detail below in Section VIII.EF. 

The agency is also proposing that a state plan specify 

appropriate periodic reporting requirements for each affected 

entity in a state plan that shouldwill 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, follow 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, and includeexcept as specified otherwise 

by these emission guidelines. These requirements apply both to 

individual state plans and multi-state plans. 

For states wishing to participate in a multi-state plan, 

the EPA is proposing that only one multi-state plan would be 
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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. 

The EPA proposes that each plan must have the following 

twelve components: 

1. Identification of affected entities (affected EGUs and other 

responsible parties) 

 The 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 

well as identify any other partiesaffected entities in a state 
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plan with responsibilities for implementation and enforcement of 

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 

guidelines or a translation of either the rate-based goal to a 

mass-based 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 per year). 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, 
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tools, methods, and assumptions used to translate from the ratebased goal to the mass-based goal. 

The EPA is proposing that multiple states could jointly 

demonstrate emission performance by affected EGUs. For these 

multi-state approaches, states would demonstrate emission 

performance by affected EGUs in aggregate with partner states. 

For states participating in a multi-state approach, the 

individual state performance goals in the emission guidelines 

would be replaced with an equivalent multi-state performance 

goal. For example, states taking a rate-based approach would 

demonstrate that all affected EGUs subject to the multi-state 

plan achieve a weighted average CO2 emission rate that is 

consistent, in aggregate, with an aggregation of the 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. 
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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 

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 
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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-asusual 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 
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limitgoal, the EPA should provide a presumptive translation of 

rate-based goals to mass-based goalgoals for all states, for 

those who request it, and/or for multi-state regions. As another 

alternative, the EPA could provide guidance for states to use in 

translating a rate-based goal to a mass-based goal. for 

individual states and for multi-state regions. This could 

include information about acceptable analytical methods and 

tools, as well as default input assumptions for key parameters 

that will likely influence projections, such as electricity load 

forecasts and projected fossil fuel prices. Under this approach, 

the EPA might also provide a coordinating function in addressing 

the assumptions applied by multiple states within a grid region, 

acknowledging that assumptions about state programs across a 

broader grid region that are included in an analysis scenario 

will influence projections of CO2 emissions by affected EGUs in 

any particular state. 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: Mass-Based Goals and 

Plan Performance in StatePlans TSD. The TSD includes a 
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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 the state’s emission performance level within the plan 

performance period. This demonstration will include a detailed 

description of the analytic process, tools and toolsassumptions

used to project future CO2 emission performance by affected 

entitiesEGUs under the plan and the results of the analysis. 

The ISO/RTO Council, an organization of electric grid 

operators, has suggested that ISOs and RTOs could provide 

analytic support to help states develop and implement their 

plans. The ISOs and RTOs have the capability to model the 

system-wide effects of individual state plans. Providing 

assistance in this way, they felt, would allow states with 

borders that fall within an ISO or RTO footprint to assess the 

system-wide impacts of potential state plan approaches. In 

addition, as the state implements its plan, ISO/RTO analytic 

support would allow the state to monitor the effects of its plan 

on the regional electricity system. ISO/RTO analytic capability 
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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 is requesting comment 

on this suggestion. 

5. Milestones 

As described in greater detail in Section VIII.A.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 emissionsemission

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 emissionsemission performance 

improvement. As described in Section VIII.A.2.d., no less than 

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

compare emission performance achieved by affected EGUEGUs in the 

state versuswith 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 July 1 of the 

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relevant year 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. BackstopCorrective measures 

For a plan that does not include self-correcting 

mechanisms, the plan must also specify corrective measures that 

have been or 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 

achieve (e.g., measures sufficient to address a 10 percent 

performance deficiency). 

7. Identification of standards of performance and any other 

measures 

A state plan must identify the affected entities to which 

each standard of performance 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 standard of performance and the process for 

demonstrating compliance with it pursuant to state regulations 

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or another legal instrument, including the schedule for 

compliance for each affected entity. In its January 2014 

proposed Carbon Pollution StandardStandards, the EPA proposed 

that the appropriate standard of performance for new EGUs be no 

longer than 12 months (on average or cumulative calendar year 

basis). Similarly, the EPA proposes here that an appropriate 

averaging time for any rate-based standard of performance for 

existing affected EGUs and/or other affected entities subject to 

a state plan is no longer than 12 months (on average or 

cumulative) within the plan period and no longer than three 

years for a mass-based standard. We also solicit comment on 

longer and shorter averaging times for a standard of performance 

included in a state plan. To maximize flexibility for the 

states, and in recognition that certain portfolio components may 

take longer to begin to achieve emission reductions than others, 

the EPA further proposes that such annual compliance timeframes 

may change over time (e.g., become more or less stringent in 

subsequent years), provided that the state plan demonstrates 

ultimate achievement of the state’s level of performance as 

described previously in this preamble. 

8. Demonstration that each standard of performance is 

quantifiable, surplusnon-duplicative, permanent, verifiable, and 

enforceable 
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In developing its CAA section 111(d) plan, to ensure that 

the plan is enforceable and in conformance with the CAA, a state 

should follow the EPA’s prior guidance on enforceability.256 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 term as reasonable. a term as 

reasonable. As reflected in section VIII.F.2.c.4 of this 

preamble, the EPA recognizes that states have a diversity of 

experiences with RE and demand-side EE measures, and we are 

seeking comment on whether the EPA should establish further 

guidance on the quantification, monitoring and verification of 

such measures.

For each standard of performance, a plan must describe how 

it is quantifiable, surplusnon-duplicative, permanent, 

verifiable, and enforceable with respect to an affected entity. 

 

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

29871987 memorandum and accompanying implementing guidance, 

“Review of State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,” (2) August 5, 2004 

“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures,” and (3) 

July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable 

Energy Policies and Programs into State and Tribal 

Implementation Plans, Appendix F.” 
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A standard of performance is quantifiable if it can be reliably 

measured, using technically sound methods (i.e., scientifically 

based, peer-reviewed, and EPA-approved),, in a manner that can 

be replicated. These issues are discussed further in Section 

VIII.F.4 and in the State Plan Considerations TSD. A standard of 

performance is surplusnon-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 

standard of performance 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 a standard of performance cannot also be 

used for other purposes. For example, if a state wished to take 

credit for CO2 emissions avoided due to electric generation from 

a new wind farm, those avoided emissions could be considered 

surplusnon-duplicative and included for purposes of CAA section 

111(d), even if electric generation from that wind farm was also 

being used to generate creditsrenewable energy certificates 

(RECs) to comply with the state’s RPS requirements. Credit from 

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avoided CO2 emissions from It also does not mean that wind farm 

could not, however, be applied in more than one state’s CAA 

section 111(d) plan, except in the case of a multi-state plan 

where credit is assigned among states or emission performance is 

demonstrated jointly for allsingle affected EGUs entity could 

not be subject to the multi-similar standards of performance in 

different state plans. For example, an affected entity might be 

an electric distribution utility that has a service territory 

that crosses state plan..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 standards of 

performance in each plan being considered duplicative. The EPA 

solicits comment as toon whether aan emission reduction, not 

previously part of a plan, becomes non-surplusduplicative (and 

therefore cannot be used for future creditingdemonstrating 

performance in a plan) if it is used as part of anyanother

state’s demonstration of compliance withemission performance 

under its CAA section 111(d) plan. 

A standard of performance is permanent if the standard of 

performance must be met by each applicable compliance year, or 

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replaced by another standard of performance in a plan revision, 

or the state demonstrates in a plan revision that the emission 

reductions from the standard of performance are no longer 

necessary for the state to meet its emission performance level. 

A standard of performance 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. A standard of performance 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 practicable enforceability (listed in Section 

VIII.C.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 ActCAA. 

9. Identification of monitoring, reporting, and recordkeeping 

requirements 
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The state plan must describe the CO2 emission monitoring, 

reporting, and recordkeeping requirements for affected 

entitiesEGUs, 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 reporting requirements under the proposed 

guidelines. However, we are seeking comment on two possible 

adjustments to the Part 75 Relative Accuracy Test Audit (RATA) 

requirements for steam EGU stack gas flow monitors that can 

affect reported CO2 emissions. The first possible adjustment 

would be to require use of the most accurate RATA reference 

method for specific stack configurations, while the second 
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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 

EPA’s existing Emission Collection and Monitoring Plan System 

(ECMPS) to be used for purposes of meeting the net energy output 

reporting requirement. The proposed protocols include a default 

apportionment procedure for multi-EGU facilities under which the 

net generation of each EGU at the facility would be determined 

as the net generation of the facility times 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 in the proposed EGU 

GHG NSPS regulations.).257) In addition, the protocol 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. 

 

257 70 FR 1429-1519; January 8, 2014. 
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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 plants; 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 Net 

Output Monitoring Issues Summary in the docket.)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. 

 A state plan that contains other standards of performance 

in addition to emission limits applicable to affected EGUs must 

include additional reporting and recordkeeping requirements 

related to these other measures. These 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 
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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 to require state plans to include a 

record retention requirement of ten years and requests comment 

on this proposed timeframe. The EPA is also soliciting comment 

on whether these reports should be submitted electronically, to 

streamline transmission, and made publicly available. 

10. Description of state reporting 

 A state plan must provide that the state will submit 

periodic reports to the EPA detailing plan implementation and 

progress, including the actions taken by the state, affected 

EGUs, and any other affected entities under the plan; the status 

of compliance by affected EGUs and any other affected entities 

with their obligations under the plan; current aggregate and 

individual CO2 emission performance by affected EGUs during the 

reporting year and prior reporting years; and any additional 

measures applied under the plan during the reporting period. The 
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state plan must describe the process, timing, and content for 

these reports. 

The EPA is soliciting comment on whether these reports 

should be submitted electronically, to streamline transmission, 

and made publicly available. 

11. Certification of state plan hearing 

A state plan shallmust 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. 

12. Supporting material 

The state must provide supporting material and technical 

documentation related to applicable components of the plan. In 

its plan, a state must adequately demonstrate that it has the 

legal authority for each implementation and enforcement 

component that it proposes to include in its plan as part of a 

federally enforceable standard of performance. 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 
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utility commission orders, and any other applicable legal 

instruments. 

A state plan shallmust 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 

Unless these emission guidelines specify otherwise, 

underUnder the framework regulations, state plans would be due 

nine months after finalization of the emission guidelines. 40 

CFR 60.23(a)(1). During the outreach process, many states 

expressed concern that this was not sufficient time to prepare 

and submit a state plan to the EPA. States commented that 

additional time was needed to accommodate, among other things, 

state legislative and rulemaking schedules, coordination among 

states involved in multi-state plans, coordination with third 

parties, and the complex technical work needed to develop a 

state plan. In responseThe EPA recognizes that state 

administrative procedures can be lengthy, some states may need 
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new legislative authority, and that states planning to these 

concernsjoin 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 (one yearthirteen months after the expected 

finalization date of the emission guidelines) and), 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 

implementing a complete plan. This approach involves the option 

that we refer to as an initial submittal, followed by submittal 

of a complete state plan at a later dateno later than either 

June 30, 2017 for single-state plans or June 30, 2018 for multistate plans. . 

In addition, for states wishing to participate in a multistate plan, the EPA is proposing that only one multi-state plan 

needswould be submitted on behalf of all participating states, 

provided it is signed by authorized officials for each of the 
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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,.258 In view of the complexity of these plans, we are 

extendingproposing to extend the submittal date. 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. If 

a state intends to make an initial submittal by June 30, 2016, 

in lieu of a complete plan, the state must notify the EPA by 

letter of such intent by no later than April 1, 2016. In this 

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 

 

258 40 CFR 60.23(a)(1). 
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requirements for an initial plan submittal by June 30, 2016. The 

EPA will respond to a state letter requesting an extension of 

the plan submittal date within 45 days through a formal letter 

response.

The EPA will respond to a state’s notice that it intends to 

request an extension of the plan submittal date within 45 days 

through a letter response. The EPA will acknowledge receipt of 

the state’s April notice and advise the state whether the 

outline of actions the state is currently undertaking to develop 

a plan indicate that the state is on track to submit an 

approvable initial submittal. The EPA’s response to the state’s 

April notice letter will be advisory only and will not 

constitute final agency action. The EPA will act to approve or 

disapprove a state’s request for a date extension in response to 

the state’s initial submittal. 

The EPA proposes that approvable justifications for seeking 

an extension 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 to limit the 
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types of justifications that the EPA wouldshould not consider 

foras warranting an extension. 

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 emissionplan guidelines, then the EPA will 

notify the state by letter, within 60 days, that it has received 

the initial state plan and thatdetermine whether it appears to 

meetmeets the minimum requirements. The EPA’s letter acting on 

the initial submittal will also specify whether the new due date 

by whichfor the state’s complete plan must be submitted to the 

EPAis June 30, 2017 or June 30, 2018. The EPA believes this 

approach is authorized by, and consistent with, section 60.27(a) 

of the implementing regulations. 

Where the EPA provides an extension of time to submit a 

complete plan, a state with a plan limited in geographic scope 

to the individual state would have until June 30, 2017, to 

submit a complete plan. If a state is developing a plan that 

includes a regional or multi-state approach, it would have until 

June 30, 2018, to submit a complete plan. Where the EPA approves 

a state’s initial submittal, including a state’s justification 

of the need for additional time to submit a complete plan after 

June 30, 2016 If the EPA approves a two-year extension to June 

30, 2018, for a state developing a multi-state plan, the state 
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would be required to provide one update, on June 30, 2017, on 

its progress toward milestones and schedules for developing and 

submitting a complete plan.259 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 June 30, 2016.that date. To be approved, the EPA 

proposes that the initial submittal must meet the following 

proposed criteria: Itplan must address all components of a 

complete plan, including identifying which onescomponents are 

not complete. For incomplete components, thean approvable 

initial submittal must contain a comprehensive roadmap outlining 

the path to completion, including milestones and dates. We 

recognize that certain options that states may choose involve 

more analytic effort to precisely demonstrate sources of 

reductions than other options. For the EPA to approve an 

extension of time for submittal of a complete The initial plan, 

 

259 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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the initial submittalplan must include, among other elements,

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. 

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. 

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”.260 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 

 

260 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. 
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draft and finalize the model rule by specified dates, and a 

commitment to seek to establish in statute and/or legislation a 

program materially consistent with the model rule in each state 

by a specified date.261 The MOU also included a commitment to 

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

specified a process for establishing a non-profit organization 

to assist the states in administering the regional aspects of 

the program. In addition, prior to execution of the MOU, the 

RGGI states committed, through letters from the Governors of 

participating states, to engage in the development of a 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 

 

261 The model rule specified elements that needed to be 

consistent across states for the program to function, as well as 

areas were 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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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, 

then the EPA will notify the state by letter, within 60 days, 

that it has received the plan and that the initial state plan 

appears to meetmeets the minimum requirements. The letter will 

also specify the date by whichwhether the complete plan must be 

submitted to the EPA by no later than June 30, 2017, or June 30, 

2018. 

States must submit complete plans to the EPA by the 

appropriate deadline, as identified in the preamble, and these 

range from June 30, 2016 to June 30, 2018. After receipt of a 

complete plan submittal, the EPA will review the plan and make a 

determination, within six months, to 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. 

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 their plans, the stateits plan, astate

will need to make a number of decisions that will require 
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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 identify several key decision points and 

factors that states should consider when developing their plans. 

The EPA has also draftedprepared 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 Affectedentities 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 the 

state itselfagency, authority or entity. We are seeking comment 
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on other appropriate examples of affected entities beyond the 

affected EGU. 

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 the 

ability of a state to include requirements of standards of 

performance upon particularfor affected entities other than 

EGUS, and if so, which such entities, and what is the 

justification for the limitations. on the 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 
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guidelines in a way that would disadvantage states that already 

have adopted CO2-reducing programs that reduce CO2 emissions. The 

EPA agrees with that policy principle. 

There is much less agreement among states and stakeholders 

on the specifics of how existing state programs should be 

treated in a demonstration that a proposed state plan will 

achieve the required level of emission performance. 

In considering options, the EPA recognized that the 

appropriate policy for determining treatment of existing state 

programs is related to the choice of methodology for setting 

state goals based on BSER. The EPA suggests that the treatment 

of existing state programs in state plan demonstrations should 

not conflict with the selected method for determining BSER-base 

state emissions performance goals. 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 many of the 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 
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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.262

The agency recognizes that states that have already shifted 

toward lower carbon-intensity generation or ramped up demandside 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 

 

262 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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The EPA is proposing that existing state programs, 

requirements, and measures,263 may qualify for use in showing 

that a state plan will achieve the required level of emission 

performance, provided they meet the approvability requirements 

in the emission guidelines (summarized above in Section VIII.B) 

and relevant requirements for plan components in the emission 

guidelines (described above in Section VIII.C). Several options 

for treatment of existing 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 the 

plan performance period due toas a result of actions taken after 

the date of this proposal.264 This proposed policy would 

recognize beneficial emission impacts from existing state 

 

263 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. 264 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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programs and measures during the plan 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 emissionsemission

performance goals based on 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 also would ensure that 

any pre-2020 actions taken after proposal of the emission 

guidelines and prior to 2020 as a result of requirements in a 

state plan, could be recognized as contributing toward meeting a 

state’s required emission performance level for affected EGUs. 

In general, the agency has identified two broad options for 

treatment of existing state programs and measures. As noted 

above, the EPA proposes that emission reductions that existing 

state requirements, programs, or measures achieve during the 

plan performance period due to actions taken byafter 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 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., beginning of 2013 for 
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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 measuresactions should be able to qualify 

for use during thea plan performance period, considering the 

method used to set state goals. Whether this option is 

consistent in practice with the EPA’s application of BSER may 

depend on the date or dates that are applied for qualifying 

actions under existing state programs, requirements, and 

measures. For example, implementation of measures subsequent to 

the proposal or promulgation of the emission guidelines may be 

consistent with a forward-looking goal setting approach, as 

these actions may be necessary to meet a required level of 

emission performance during the plan performance period or will 

put a state in a better position to meet the required level of 

performance. An example is the EPA’s treatment of end-use energy 

efficiency potential in state goal setting, where the energy 

savings achievable during the plan performance period are 

premised in part on a ramping up of end-use energy efficiency 

programprograms 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 
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could be taken prior to the plan 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. 

The EPA also solicits comment on a second broad option: 

Recognizing. This option would recognize emission reductions 

that existing state requirements, programs, or measures achieved 

starting from a specified date prior to the plan performance 

period, as well as emission reductions achieved during thea 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., beginning 

of 2013 for blocks 1-3 and beginning of 2017 for block 4, enduse 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 plan 

performance period could be applied toward meeting the required 

level of emission performance in a state plan. The agency also 

requests comment on the alternative dates listed above in 
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connection with this option. We also request comment on whether 

this option is inconsistent with the forward-looking method that 

the EPA has proposed for establishing state goals based on the 

application of BSER. 

The agency is seeking comment on whether some variation of 

this approach could be justified as consistent with the EPA’s 

proposed goal-setting approach, as well as the general concept 

of BSER and its application in establishing state goals. In 

particular, we are seeking comment on whether 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 athe 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 RE and demandside EE measures that, through MWh generation or MWh savings, 

avoid CO2 emissions from affected EGUs. Measures installed after 

the eligibility date could generate MWh generation or MWh 

savings during thea plan performance period, and related avoided 

CO2 emissions, that could be applied toward meeting a required 
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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 

renewable energy generating capacitydemand-side EE measures

installed in 2015 or later to meet an existing, on-the-books 

renewable portfolioenergy efficiency resource standard would be 

a qualifying measure. However, only MWh generationsavings

beginning in 2020 and related avoided CO2 emissions could be 

applied toward meeting a required emission rate 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, qualifying RE and 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 energy efficiency 

resource standard or renewable portfolio standard requirement in 

a reference case projection, beginning at a specified date. 

These considerations are addressed in more detail in Section 

VIII.EF.7. below and in the Projecting EmissionsCO2 Emission
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Performance: Mass-Based Goals and Plan Performance in State 

Plans TSD. 

1.3. 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 creditingcredit system applied to an EGU’s reported CO2

emission rate.265 Under such a process, measures that avoid 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 emission rate 

performance level in a state plan. 

 Under this approach, affected EGUs266 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 

 

265 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.

266 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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is implementing a portfolio approach, then the state could 

administratively adjust the average CO2 emission rate of affected 

EGUs through a similar process, provided that the CO2-avoiding 

measures are enforceable elements of the state plan. 

We are seeking comment on different approaches for 

providing such crediting or administrative adjustment of EGU CO2

emission rates, which are elaborated further in the State Plan 

Considerations TSD. 

Credits or adjustment might represent avoided MWh of 

electric generation or avoided tons of CO2 emissions. The 

approach chosen could have significant implications for the 

amount of adjustment or credit provided for RERERE and demandside 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 
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or demand-side EE measure reduces CO2 emissions from that 

individual EGU or group of EGUs.267 In practice, the average or 

marginal CO2 emission rate in the power pool or identified region 

– representing the avoided CO2 emissions from the generating 

sources being displaced by a MWh of energy savings or a MWh of 

renewable energy generation – could differ significantly from 

the calculated avoided CO2 emissions derived by adjusting the MWh 

output of an affected EGU. 

An alternative approach is to provide an adjustment based 

on the estimated CO2 emissions that are avoided from the power 

pool or identified region as a result of RE and demand-side EE 

measures. This approach implicitly assumes that the avoided CO2 

emissions come from the electric power pool or other identified 

region as a whole, rather than an individual EGU. The avoided CO2

emissions are determined based on the MWh saved or generated, 

multiplied by a CO2 emission rate for the power pool or region. 

This CO2 emission rate could be based on the average or marginal 

emission rate in the power pool or region, or could be the 

emission rate that represents the required rate-based emission 

 

267 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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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 demandside 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. 

Utilities and states have conducted ongoing The EPA is 

proposing that a state plan that includes enforceable RE and 

demand-side EE measures must include an evaluation of end-use, 

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 
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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 included as 

part of an approvable state plan. 

Utilities and states have conducted ongoing EM&V of demandside energy efficiency and renewable energy measures and 

programs for several decades. These evaluations, which include 

quantification, monitoring, and verification of results,Current 

practice with EM&V for demand-side energy efficiency and 

renewable energy programs in the U.S. is primarily defined by 

state public utility commission (PUC) requirements for customerfunded energy efficiency programs, as well as related compliance 

and reporting requirements for energy efficiency resource 

standards (EERS) and renewable energy portfolio standards (RPS). 

 

The level of PUC oversight of demand-side energy efficiency 

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. 
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Typically, impact evaluation reports are responsive to 

requirements established by PUCs and submitted (usually 

annually) for PUC review, approval, and use in resource planning 

and performance assessment. These PUC requirements generally 

rely upon a well-defined set of industry-standard practices and 

procedures. However, measurement approaches vary by state based 

on multiple factors, including the measure and program type 

being evaluated, the level and nature of regulatory oversight, 

the degree of state and utility In states with the most 

experience with these measures and programs, and the overall 

magnitude of programimplementing and overseeing EE programs, 

this typically includes: use of one or more of industry-standard 

EM&V protocols or guidelines; use of “deemed savings values,”268

where appropriate, for well-understood energy efficiency 

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 

 

268 Deemed savings are measure-specific stipulated values based 

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

deemed savings approaches involve limited or no measurement 

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

strategy for documenting energy savings. 

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provision of interim and annual reporting of achieved energy 

savings.

Current 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 savings269, run-time of 

equipment, measure lifetime). This can result in significant 

differences in claimed energy savings values for similar energy 

efficiency measures between states and utilities, even when the 

same measure type is installed under otherwise identical 

circumstances. In response to a growing awareness of this lack 

of cross-state comparability, policy makers, regulatory 

agencies, and other stakeholders are increasingly advocating for 

the use of common evaluation approaches across jurisdictions. A 

number of states and utilities in different regions of the 

country are already working to develop such common approaches. 

For renewable energy 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 

 

269 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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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 

approaches, or supplemental actions and procedures, should be 

required in an approvable state plan. In particular, we are 

seeking comment on whether the EPA shouldintend to establish 

good practice guidance for acceptable quantification, 

monitoring, and verification of RE and demand-side EE measures 

for an approvable stateEM&V plan, and on the contentare seeking 

comment on critical features of such guidance., including scope, 
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applicability, and minimum requirements.270 We are also seeking 

comment on the appropriate basis for and technical resources 

used to establish such guidance, if the EPA were to take this 

approach. This includesincluding consideration of existing state 

and utility protocols, as well as anyexisting international, 

national, and regional consensus standards or protocols.271 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 demand-side EE measures and programs, leverages the EM&V 

resources and infrastructure already in place in many states, 

and strikes a reasonable balance between EM&V costs, rigor, and 

the value of resulting information, while considering the 

specific use of such information in assessing avoided CO2

emissions from affected EGUs. 

In addition, we are seeking comment on whether any such 

guidance should identify types of end-use energy efficiency and 

renewable energy measures and programs for which quantification, 

monitoring, and verificationIn 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, 

 

270 Section 4 of the State Plan Considerations TSD includes a 

detailed description of these EM&V parameters.

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

State Plan Considerations TSD.
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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 demand-side EE measures and programs 

for which evaluation of results is relatively straightforward 

and which are appropriate for inclusion in a state plan. Such 

approaches might be subject to streamlined review of 

quantification, monitoring, and verificationEM&V protocols 

included in an approvable plan, provided that such protocols are 

applied in accordance with industry best practices. 

For example, many utilities have implemented a similar core 

set of RE and demand-side EE measures and programs for utility 

customers. For these types of measures and programs, a 

substantial base of experience has been established nationally 

for quantification, monitoring, and verificationthe evaluation

of measure and program outcomes. Other types of measures and 

programs, such as those that seek to alter consumer and building 

occupant behavior may pose quantification and verification 
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challenges. Still other types of measures, such as state energyefficient appliance standards and building codes, have not 

typically been subject to similar evaluation of energy savings 

results. These types of approaches may have substantial impacts, 

butand the EPA does not want to discourage their implementation 

in state plans, but they may 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 responsible partiesaffected 

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 

approach with such measures, reporting and recordkeeping 
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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 end-use energy efficiency resource 

standard (EERS) or renewable portfolio standard (RPS). They may 

also include reporting by a vertically integrated utility 

implementing an approved integrated resource plan. In the latter 

instance, the utility may also be the owner and operator of 

affected EGUs, but additional reporting of quantified effects of 

RE and demand-side EE measures under the utility plan would be 

necessary to demonstrate emissions performance under the state 

plan. In other instances, a state agency or entity or a private 

or public third-party entity may be implementing programs and 

measures that support the deployment of end-use energy 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 

responsibleaffected 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 
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any other appropriate reporting and recordkeeping and reporting

requirements for affected entities beyond affected EGUs. 

6. Treatment of interstate effects 

ProgramsThe 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 measuresprograms 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 agency recognizes the complexity of accounting for 

interstate effects associated with measures in a plan in a 
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consistent manner, to minimizeallow state to take into account 

the CO2 emission reductions resulting from these programs, while 

minimizing the likelihood of double counting. We also realize 

that interstate effects on CO2 emissions from affected EGUs could 

be attributed in different manners in the context of an 

approvable state plan. The agency 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 used in determining 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 states would have the flexibility to 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 

are equal to the total of each state’s in-state emissions 

reductions that result from demand-side EE measures implemented 

in those states. We are also proposing that states could jointly 

demonstrate CO2 emission performance by affected EGUs through a 
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multi-state plan in a contiguous electric grid region, in which 

case attribution among states of emission reductions from 

demand-side EE measures would not be necessary. We also request 

comment on whether a state should be able to take credit for 

emission reductions out of state due to in-state EE measures if 

the state can demonstrate that the reductions will not be 

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 reductions from demand-side EE measures 

in state plans. 

The EPA is also proposing that, for renewable energy 

measures, consistent with existing state RPS policies, a state 

could take into account all of the CO2 emisionemission reductions 

from renewable energy measures implemented by the state, whether 

they occur in the state and/or in other states. The EPA is also 

seeking comment on how to avoid double counting emission 

reductions using this proposed approach. The EPA is also 

proposing that states participating in multi-state plans could 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 

are equal to the total of each state’s in-state emission 

reductions for renewable energy measures. We also request 
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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 doublecounted 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 emissions performance by affected EGUs and 

other affected entities under the plan. In addition, a state 

plan that is using a mass-based goal in determining the required 

level of emission performance under the plan will include a 

translation of the rate-based emission goal in the emission 

guidelines to a mass-based goal. This translation will also

involve a projection of CO2 emissions from affected EGUs during 
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the plan period, 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 will need tomust include a 

projection of CO2 emission performance from affected EGUs during 

the multi-year plan period that will result from implementation 

of the plan. Depending on the type of plan approach, this will 

include either a projection of the average CO2 emission rate 

achieved by affected EGUs or total CO2 emissions from affected 

EGUs. 

The credibility of state plans under CAA section 111(d) 

will depend in large part on ensuring credible and consistent 

emission performance projections in state plans. Therefore, the 

use of appropriate methods, tools, and assumptions for such 

projections is critical. 

Considerations for projecting emission performance under a 

state plan will differ depending on the type of plan. This 

includes differences in how inputs to projections are derived; 

how projections are conducted, including tools and ,methods, and 
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assumptions; and, how aspects of a plan are represented in these 

projections. 

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.272 This 

latter approach would be able to capture dynamic interactions 

within the electricity sector, based on system operation and 

market forces, including interactions among state programs and 

measures and the dynamics of market-based measures. 

These considerations, and considerations for projecting 

emissionsemission performance under different types of state 

plan approaches, are discussed in detail in the Projecting 

EmissionsEGU CO2 Emission Performance: Mass-Based Goals and Plan 

Performance TSD. in State PlansTSD. 

We are seeking comment on the considerations discussed in 

this technical support documentTSD, including options presented 

for how projections might be conducted in an approvable state 

 

272 In many cases, this approach will also require the 

development of parameters for estimating the effect of 

individual state programs and measures, for use as input 

assumptions for modeling.
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plan, and how different types of state plan approaches are 

represented in these projections. We are further seeking 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 provide 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 RTOISO or ISORTO 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 is requesting comment 

on this suggestion. 
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88. Consideration of measures that the EPA did not include in 

the BSER determination 

States may include measures in their plans beyond those 

that the EPA included in its determination of the BSER. A wide 

range of other measures that could CO2 emission reductions. These 

include, for example, transmission improvements, retrofitting 

EGUs with partial CCS, the use of biomass-derived fuels, use of 

new NGCC units online, and new hydroelectric power and 

increments, and they are among the measures that states might 

consider for inclusion in their plans. The agency solicits 

comment on whether these measures are appropriate to include in 

a state plan to achieve CO2 emission reductions. We also request 

comment on other measures that would be appropriate. In 

addition, should the EPA provide specific guidance on these 

measures? 

We request comment, in particular, on the use of biomassderived fuels, in place of affected EGUs, as a measure to 

include in a state plan to achieve CO2 emission reductions. 

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 
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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, 

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 carbon 

dioxide (CO2) emission reduction strategies. We anticipate that 

states will likely 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 
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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 

developed a draft accounting framework which 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 

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. Once finalized, the EPA’s biogenic CO2 accounting 

framework is expected to provide important information regarding 

the scientific basis for assessing these biomass-derived fuels 
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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 statutory provision that requires EPA regulations 

implementing CAA section 111(d) to “permit the State in applying 

a standard of performance to any particular source under a 

[111(d)] plan . . . to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” 

As the EPA recognized in 1975 when it adopted framework 

regulations for implementation of CAA section 111(d) including 

the “remaining useful life” statutory provision, application of 

thesethe implementing provisions in the framework regulations 

may not be appropriate in every instance.273 For the reasons 

discussed below, the EPA is proposing that, in this case, the 

 

273 The agency is not reopening or considering changes to the 

existing framework regulations. 
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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. The agency also requests comment on whether it would 

be desirable to include any aspects of this analysis in 

regulatory text of this emission guideline. 

TheThis section addresses the legal background, concerning 

facility-specific considerations and the implications for 

implementation of these emission guidelines, and lack of 

relevance toincluding state emissions performance goals. 

a. Legal background 

As reflected in the framework regulations, the EPA believes 

that Congress included the remaining useful life provision in 

CAA section 111(d) to avoid imposition of unreasonable costs on 

an existing source that has a limited remaining useful life. 

This could occur if a rule imposed high capital costs that would 

normally be amortized over long periods of time. If a facility 
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will cease operation in the near future, it may have little time 

to earn revenue to help pay for the pollution control 

investment, and the facility’s retirement may occur before that 

debt is paid off. In addition, the impact of the controls in 

reducing emissions may be short-lived. As a result, it could be 

unreasonable for a facility with a short remaining useful life 

to incur the same pollution control costs that are reasonable 

for a facility with a long remaining useful life. Thus, 

remaining useful life could affect the determination of what 

requirements are appropriate for a facility with a short 

remaining useful life. 

The EPA’s 1975 framework regulations contain the following 

provision,274 which addresses remaining useful life and other 

facility-specific factors that might affect requirements for an 

existing source under section 111(d): 

“Unless otherwise specified in the applicable subpart, 

on a case-by-case basis for particular designated 

facilities, or classes of facilities, States may provide 

for the application of less stringent emission standards or 

longer compliance schedules than those otherwise required 

by paragraph (c) of this section275, provided that the state 

demonstrates with respect to each such facility (or class 

of facilities): 

 

274 40 CFR Section 60.24(f) 275 Paragraph (c) requires that for pollutants that endanger 

public health, standards of performance in state plans must be 

as stringent as EPA’s emission guidelines.

Formatted: Font: 12 pt
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(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 related 

toresulting from plant age” reflects 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 in some circumstances can 

affect the reasonableness of a control measure for a particular 

existing source. 

This regulatory provision provides the EPA’s default 

structure for implementing the remaining useful life provision 

of CAA section 111(d). The opening clause, however, which 

provides that this provision is applicable “unless otherwise 

specified in the applicable subpart” makes clear that this 

structure may not be appropriate in each case and that the EPA 

has discretion to alter the extent to which states may authorize 

relaxations to standards of performance that would otherwise 

apply to a particular source or source category, if appropriate 
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under the circumstances of the specific source category and 

proposed guidelines. 

b. Implications for implementation of this emissions guideline 

In general, the EPA notes that the framework 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 

pulp plants specify emission limits for sources.276 In the case of 

such emission guidelines, some individual sources, by virtue of 

their age or other unique circumstances, may warrant special 

accommodation. 

In the guidelines for state plans to limit CO2 from affected 

EGUs that the EPA is proposing, the agency does not take that 

approach. Instead, the EPA is proposing to establish state 

emissions performance goals for the collective group of affected 

EGU in a state, and leaving to each state the design of the 

specific requirements that fall on each affected EGU. Due to the 

 

276 [cites] 
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inherent flexibility in the EPA’s approach to establishing the 

state-specific goals, and the flexibility provided to states in 

developing approvable CAA section 111(d) plans to achieve those 

goals, no relief for individual facilities is needed from 

requirements in the EPA’s guidelines, because the EPA’s 

guideline contains no emissions standards that the state must 

apply directly to a specific EGU. 

Rather, because of the flexibility for states to design 

their own standards, the states have the ability, and would be 

required, 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 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. 

For these reasons, it appearsTherefore, to the extent that 

the quoted regulatory text abovea performance standard that a 

state may wish to adopt for affected EGUs raises facilityspecific issues, the state would be authorized to make 

adjustments to a particular facility’s requirements on remaining 

useful life and other factors need not apply to implementation 

of this proposedfacility-specific grounds, so long as any such 
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adjustments are reflected (along with any necessary compensating

emission guideline.reductions), as part of the state’s CAA 

section 111(d) plan submission. The agency requests comment on 

its interpretation. 

c. Lack of relevanceRelationship to state emissionsemission

performance goals and timing of achievement 

The EPA also believes that remaining useful life and other 

facility-specific considerations should not affect the 

determination of a state’s rate-based or mass-based 

emissionsemission performance goal or the state’s obligation to 

develop and submit an approvable CAA section 111(d) plan that 

achieves that goal by the applicable deadline. 

Under the proposed guideline, states would have the 

flexibility to adopt a state plan that relies on 

emissionsemission-reducing requirements that do not require 

affected EGUs with a short remaining useful life to make major 

capital expenditures277 or incur unreasonable costs. Indeed, the 

EPA’s proposal would provide states with broad flexibility 

regarding ways to improve emissionsemission performance through 

utilizing the emissions reduction methods represented by the 

 

277 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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four “building blocks.” 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. 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 EGUEGUs, 

the assumed 6 percent heat rate improvement in the EPA’s 

proposed BSER determination would be applicable to affected EGUs 

on a state-wide average basis, allowing the state to require a 

greater or lesser degree of heat rate improvement from any 

individual EGU in light of that EGU’s remaining useful life or 

any other source-specific factors that the state deemed 

appropriate to consider.278 The agency notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

 

278 Where states are unable to achieve the average 6 percent heat 

rate improvement assumed in the EPA’s BSER determination in 

light of the remaining useful life of one or more of their 

affected EGUs or for any other reasons (or where state so choose 

based on other considerations), they may adopt plan provisions 

that will obtain a lesser degree of average heat rate 

improvement from affected EGUs. 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, as 

long as they provide additional compensating emission reductions 

with respect to the other three building blocks. 

Formatted: Font: 12 pt

Formatted: Font: 12 pt
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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).279 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).averaging 

and trading programs). Under EPA’s proposed approach -- 

establishing state goals and providing states with flexibility 

in plan design – states have flexibility to avoid requirements 

that would result in stranded assets.

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant in 

determining requirements that are directly applicable to 

affected EGUs. For all of the reasons above, the agency believes 

that the issue of remaining useful life will arise infrequently 

in the development of state plans to limit CO2 emissions from 

affected existing EGUs. Even if relief is due a particular 

facility, the state has an available toolbox of emission 

 

279 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 

Formatted: Subscript
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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 framework 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. 

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 
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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 Agencyagency 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 

Statesstates in the development of their SectionCAA 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 
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development and implementation. Some states indicated that they 

wanted the EPA to create resources to assist with state plan 

development, especially resources related to accounting for enduse energy efficiency and renewable energy (EE/RE) in state 

plans. They requested clear methodologies for 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,”280 as well 

as the State Energy Efficiency Action Network’s “Energy 

Efficiency Program Impact Evaluation Guide.”281 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 this is 

available at [http://www2.epa.gov/carbon-pollutionstandards/toolbox]. Current resources on the site focus on 

 

280 http://epa.gov/airquality/eere/ 281

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

_guide.pdf
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approaches states and other entities have already taken that 

reduce CO2 emissions from the electric utility sector. 

For the final rulemaking, the EPA plans to organize 

resources 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,282 National Action Plan for Energy 

Efficiency (NAPEEAction Plan),283 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 

 

282 Currently under development as a TSD Appendix, State Plan 

Considerations TSD

283 http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html
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use in a state plan. States will need to demonstrate that any 

measure included in a state plan meets all relevant 

approvability criteria and adequately addresses elements of the 

plan components discussed in Section VIII of this preamble. 

The EPA solicits comment on this approach and the 

information currently included, and planned for inclusion, in 

the Decision Support Toolbox. 

IX. Implications for Other EPA Programs and Rules 

A. Implications for New Source Review Program 

 The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For GHG emissions, the PSD applicability 

analysis is described in the Prevention of Significant 

Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 

31514, June 3, 2010). As a general matter, a modifying major 
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stationary source would trigger PSD permitting requirements for 

GHGs if it emits GHGs in excess of 100,000 tons per year (tpy) 

of carbon dioxide equivalents (CO2e), and it undergoes a change 

or change in the method of operation (modification) resulting in 

an emissions increase of 75,000 tpy CO2e as well as an increase 

on a mass basis. Once it has been determined that a change 

triggers the requirements of the NSR program, the source must 

obtain a permit prior to making the change. The pollutant(s) at 

issue and the air quality designation of the area where the 

facility is located or proposed to be built determine the 

specific permitting requirements. 

As part of its CAA section 111(d) plan, a state may 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, the EGU would trigger 

NSR. 

As previously discussed in this preamble, states have 

considerable flexibility in selecting varied measures as they 

develop their plans to meet the goals of the emissions 

guidelines. One of these flexibilities is the ability of the 
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Page 497 of 639

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 

change in dispatch would not, in fact, increase their emissions, 

due to reduced demand for their operation. The state could also, 

as part of its CAA section 111(d) plan, develop conditions for a 

source expected to trigger NSR that would limit the unit’s 

ability to move up in the dispatch enough to result in a 
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Page 498 of 639

significant net emissions increase that would trigger NSR 

(effectively establishing a synthetic minor limit). If we are 

satisfied with the state’s showing that the standards of 

performance in its plan, if complied with, will not have 

emissions increase that trigger NSR, we will approve this 

provision in the state plan. 

We request comment on whether, with adequate record 

support, the state plan could include a provision 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. 

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 
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The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; 

January 8, 2014) explained that regulating GHGs for the first 

time under CAA section 111 of the CAA would make GHGs “regulated 

air pollutants” for the first time under the operating permit 

regulations of 40 CFR parts 70 and 71. This would result in GHGs 

becoming “fee pollutants” in certain state part 70 permit 

programs and in the EPA’s part 71 permit program, thus requiring 

the collection of fees for GHG emissions in these 

programs. Where title V fees would be required for GHGs, they 

would typically be charged at the same rate ($ per ton of 

pollutant) as all other fee pollutants. This would likely result 

in excessive and unnecessary fees being charged to subject 

sources. To avoid this situation, we proposed to exempt GHGs 

from the fee rates in effect for other fee pollutants, while 

proposing an alternative fee that would be much lower than the 

fee charged to other fee pollutants, yet sufficient to cover the 

costs of addressing GHGs in operating permits. 

This title V fee issue is a one-time occurrence resulting 

from the promulgation of the first CAA section 111 standard to 

regulate GHGs (the EGU NSPS for new sources) and is not an issue 

for any other subsequent 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 
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Page 500 of 639

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 

3 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 3 years, the newly 

applicable requirement must be incorporated at permit renewal. 

C. Interaction WithInteractions with Other EPA Rules 

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 

other recently finalized or proposed EPA rules.284 On February 16, 

 

284 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 
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Page 501 of 639

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 

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; if an 

 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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Page 502 of 639

existing source is unable to comply by that deadline, a 

permitting authority has the ability to grant the source up to a 

one year extension, on a case-by-case basis, if such additional 

time is necessary for the installation of controls. [Text on 

December 2011 Enforcement Response Policy and/or progress in 

MATS implementation will be added.] 

 On. The final MATS provided a foundation on which states 

and other permitting authorities could rely in granting an 

additional, 4th year for compliance provided for by the 

Act. States report that these 4th 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 reliabilityOn [INSERT PUBLICATION DATE OF FINAL RULE 

(which should be finalized in April)], 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). 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.285 The 316(b) 

 

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

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

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rule subjects existing power plants and manufacturing facilities 

that withdraw in excess of 2 million gallons per day (MGD) of 

cooling water, and use at least 25 percent of that water for 

cooling purposes, to a national 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 arewill 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, which are 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., 8 years from the rule's effective date) to comply with 

the rule's impingement standards. They must comply with 

applicable site-specific entrainment mortality standards based 

 

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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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 

fossil-fuel fossilfuel-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 Clean Water 

Act. 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. 
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This proposed regulation, which includes new requirements for 

both existing and new generating units, would reduce the amount 

of toxic metals and other pollutants discharged to surface 

waters from power plants. 

 On June 21, 2010 (75 FR 35128), the EPA proposed the CCR 

rule, which 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.286 While the agency is still evaluating all the 

 

286 Beneficial use involves the reuse of CCRs in a product to 

replace virgin raw materials that would otherwise be obtained 
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available information and comments, and while a final risk 

assessment for the CCR rule has not yet been completed, reliance 

on data and analyses discussed in the preamble to the recent 

Steam Electric ELG proposal may 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 may 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.287 The EPA is under a court- 

 

through extraction. The EPA encourages the beneficial use of 

CCRs in an appropriate and protective manner, because this 

practice can produce environmental, economic, and performance 

benefits. The Agency recently evaluated the environmental 

impacts associated with encapsulated beneficial uses of fly ash 

used as a direct substitute for Portland cement in concrete, and 

FGD gypsum used as a replacement for mined gypsum in wallboard. 

The EPA concluded that the beneficial use of CCRs in concrete 

and wallboard is appropriate because the environmental releases 

of constituents of potential concern (COPC) during use by the 

consumer are comparable to or lower than those from analogous 

non-CCR products, or are at or below relevant regulatory and 

health-based benchmarks for human and ecological receptors. See

U.S. Environmental Protection Agency, Coal Combustion Residual 

Beneficial Use Evaluation: Fly Ash Concrete and FGD Gypsum 

Wallboard (2014). 

287 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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ordered deadline to complete the CCR rulemaking by December 19, 

2014. 

 The EPA recognizes the importance of assuring that each of 

the rules described above can achieve its intended environmental 

objectives in a commonsense, cost-effective manner consistent 

with underlying statutory requirements and while assuring a 

reliable power system. Executive Order (EO) 13563, “Improving 

Regulation and Regulatory Review,” issued on January 18, 2011, 

states that “[i]n developing regulatory actions and identifying 

appropriate approaches, each agency shall attempt to promote... 

coordination, simplification, and harmonization. Each agency 

shall also seek to identify, as appropriate, means to achieve 

regulatory goals that are designed to promote innovation.” 

Within the EPA, we are paying careful attention to the 

interrelatedness and potential impacts on the industry, 

reliability and cost that these various rulemakings can have. 

As discussed in Sections VII and VIII of this preamble, the 

EPA is proposing to give states broad flexibility in developing 

approvable plans under CAA section 111(d), including the ability 

to adopt rate-based or mass-based emission performance goals, 

and to rely on a wide variety of CO2 emission reduction measures. 

 

 
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The EPA is also proposing to give states considerable 

flexibility with respect to the timeframes for plan development 

and implementation, with up to two or three years permitted for 

final plans to be submitted after the proposed GHG emission 

guidelines are finalized, and up to fifteen years for all 

emission reduction measures to be fully implemented. In light of 

these flexibilities, we believe that states will have ample 

opportunity, when developing and implementing their CAA section 

111(d) plans, to coordinate their response to this requirement 

with source and state responses to any obligations that may be 

applicable to affected EGUs as a result of the MATS, 316(b), SE 

ELG and CCR rules – all of which are or will be final rules 

before this rulemaking is finalized – and to do so in a manner 

that will help reduce cost and ensure reliability, while also 

ensuring that all applicable environmental requirements are 

met.288

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 

 

288 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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coordinate planning and investment decisions with respect to 

those rules) and, where possible, implement integrated 

compliance strategies. For example, in the proposed SE ELG rule, 

the EPA describes its current thinking on how it might 

effectively harmonize the potential requirements of that rule 

with the requirements of the final CCR rule, to the extent that 

both rules may regulate or affect the disposal of coal 

combustion wastes to and from surface impoundments at power 

plants.289 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.290

 

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

34441. 

290 [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 
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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. 

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. 

 

timeline for implementation that allows for coordinated planning 

and protects electricity reliability for consumers. 
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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 standardNAAQS. The EPA based these nonattainment 

designations on the most recent set of certified air quality 

monitoring data as well as an assessment of nearby emission 

sources and weather patterns that contribute to the monitored 

levels. The EPA intends to address the designations for all 

other areas in separate actions in the future291. 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. 

 

291 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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The development of these SIPs may, where applicable, have 

significant implications for existing fossil fuel-fired EGUs, as 

well as for the states that are responsible for developing them. 

The timeframes for submittal of SIPs for the various programs 

and the timeframes we are proposing for submittal of the CAA 

section 111(d) state plans will allow considerable time for 

coordination by states in the development of their respective 

plans. The EPA is willing to work with states to assist them in 

coordinating their efforts across these planning processes. The 

EPA believes that CAA section 111(d) efforts and actions will 

tend to contribute to overall air quality improvements and thus 

should be complementary to criteria pollutant and regional haze 

SIP efforts. 

In light of the broad flexibilities we are proposing in 

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 
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requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

X. Impacts of the Proposed Action292

A. What are the air impacts? 

The EPA anticipates significant emission reductions under 

the proposed guidanceguidelines. CO2 emissions are projected to 

be reduced, relative to the base case2005 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 ___22 percent to 23 percent in 2025.2030. 

The guidelines are projected to result in substantial cobenefits through reductions of SO2, PM2.5 and NOx that will have 

direct public health benefits by lowering ambient levels of 

these pollutants and ozone. Tables 7 and 8 show expected 

climateCO2 and other air pollutants pollutant emission reductions 

in the base case, with the proposed guidance and the anticipated 

 

292 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 

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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net change between the base case and proposal emission levels in 

2020 and 2030 for Option 1, and Tables 9 and 10 in 2020 and 2025 

for and regulatory alternative Option 2, respectively., for 

2020, 2025, and 2030. 

Table 7 – Summary of ClimateCO2 and Other Air Pollutant Emission 

Reductions with Proposed Option 1 - 2020

CO2

(million 

metric 

tonnestons

) 

SO2

(thousand

s of 

tons) 

NOX 

(thousand

s of 

tons) 

PM2.5 

(thousand

s of 

tons) 

2020 Regional Compliance Approach 

Base Case 2,161 1,476 1,559 N/A

Proposed 

Guidance 1,790 1,184 1,213

ChangeGuideline

s Emission 

Reductions 

 -371 -292 -345

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 1,730 1,120 1,166 N/A 

Guidelines 

Emission 

Reductions 

 -501 -395 -421 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 N/A 

Proposed 1,711 1,106 1,131 

Guidelines 

Emission 

Reductions 

 -545 -424 -407 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,777 1,140 1,191 N/A 

Emission 

Reductions -383 -335 -367 

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 N/A 

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Proposed 

Guidelines 1,724 1,090 1,151 

Emission 

 Reductions 

 -506 -425 -436 

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 N/A 

Proposed 

Guidelines 1,701 1,059 1,109 

Emission 

Reductions -555 -471 -428 

Source: Integrated Planning Model, 2014. 

N/A – not yet available. 

Table 8 –- Summary of ClimateCO2 and Air Pollutant Emission 

Reductions with Proposed Option 1 - 20302

CO2

(million 

metric 

tonnestons)

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 N/A

Proposed 

GuidanceGuidelines 1,878 1,231 1,290

ChangeEmissions 

Reductions -283 -244 -268

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,862 1,218 1,279 N/A 

Emissions 

Reductions -368 -297 -309 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,903 1,243 1,286 N/A 

Emissions 

Reductions -353 -287 -252 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,866 1,208 1,277 

Emissions 

Reductions -295 -267 -281 N/A 

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2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,855 1,188 1,271 

Emissions 

Reductions -376 -327 -317 N/A 

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,882 1,209 1,264 

Emissions 

Reductions -373 -321 -274 N/A 

 Source: Integrated Planning Model, 2014. 

N/A – not yet available. 

Table 9 – Summary of Climate and Air Pollutant Emission 

Reductions with Alternative Option 2 - 2020 

CO2 (million 

metric 

tonnes) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

Base Case 

Proposed 

Guidance 

Change 

 

Table 10 – Summary of Climate and Air Pollutant Emission 

Reductions with Alternative Option 2 - 2025 

CO2 (million 

metric 

tonnes) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

Base Case 

Proposed 

Guidance 

Change 

The reductions in these tables do not account for 

reductions in hazardous air pollutants (HAPs) that may occur as 

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a result of this rule. For instance, the fine particulate 

reductions presented above only partly reflect reductions in 

many heavy metal particulates. 

B. BComparison 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 

(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 
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Page 518 of 639

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 

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 (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 
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2030, excluding the costs associated with monitoring, reporting, 

and recordkeeping (MRR). 

The total combined climate benefits and health co-benefits 

are estimated to be $21 to $40 billion in 2020 and $32 to $63 

billion in 2030 (2011$ at a 3-percent discount rate [model 

average]). The net benefits are estimated to be $18 to $36 

billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-

percent discount rate [model average]). For the purposes of this 

summary, we list the climate benefits associated with the 

marginal value the model average at 3% discount rate, however we 

emphasize the importance and value of considering the full range 

of SCC values. 

C. Endangered Species Act 

Consistent with the requirements of section 7(a)(2) of the 

Endangered Species Act (ESA), the EPA has also considered the 

effects of this proposed rule and has reviewed applicable ESA 

regulations, case law, and guidance to determine what, if any, 

impact there may be to listed endangered or threatened species 

or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 
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Page 520 of 639

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. § 1536(a)(2). Under relevant 

implementing regulations, section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR § 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR § 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 

19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 

environmental baseline. 50 CFR § 402.02. Indirect effects are 

those that are caused by the action, later in time, and are 

reasonably certain to occur. Id. To trigger a consultation 

requirement, there must thus be a causal connection between the 

federal action, the effect in question, and the listed species, 

and the effect must be reasonably certain to occur. 

The EPA has considered the effects of this proposed rule 

and has reviewed applicable ESA regulations, case law, and 

guidance to determine what, if any, impact there may be to 
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Page 521 of 639

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, FWS and DOI expressed the view that the best scientific 

data available are insufficient to draw a causal connection 

between GHG emissions and effects on the species in its 

habitat.293 The DOI Solicitor concluded that where the effect at 

issue is climate change, proposed actions involving GHG 

emissions cannot pass the “may affect” test of the section 7 

regulations and thus are not subject to ESA consultation. The 

EPA has also previously considered issues relating to GHG 

 

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

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

Interior re: “Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to Proposed Actions 

Involving the Emission of Greenhouse Gases” (Oct. 3, 2008). 
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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 7 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 question294 and, based 

on air quality modeling of potential environmental effects, 

concluded that “EPA knows of no modeling tool which can link 

these small, time-attenuated changes in global metrics to 

particular effects on listed species in particular areas. 

Extrapolating from global metric to local effect with such small 

numbers, and accounting for further links in a causative chain, 

remain beyond current modeling capabilities.” EPA, Light Duty 

Vehicle Greenhouse Gas Standards and Corporate Average Fuel 

Economy Standards, Response to Comment Document for Joint 

Rulemaking at 4-102 (Docket EPA-OAR- HQ-2009-4782. The EPA 

reached this conclusion after evaluating issues relating to 

potential improvements relevant to both temperature and 

 

294 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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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. Preamble Table 7. However, 

CAA section 111(d)(1) standards cannot directly control 

emissions of criteria pollutants. Consequently, section 111(d) 

provides no discretion to adjust the standard based on potential 

impacts to endangered species of reduced criteria pollutant 

emissions. Section 7(a)(2) consultation thus is not required 

with respect to the projected reductions of criteria pollutant 

emissions. See 50 CFR § 402.03; see also, National Lime Ass’n 

v. EPA, 233 F. 3d 625, 638-39 (D.C. Cir. 2000)(although CAA 
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section 112(b)(2) prohibits the EPA from listing criteria 

pollutants as hazardous air pollutants, the EPA may use PM as a 

surrogate for metal hazardous air pollutants and reductions in 

PM do not constitute impermissible regulation of a criteria 

pollutant). 

Moreover, there are substantial questions as to whether any 

potential for relevant effects results from any element of the 

proposed rule or would result instead from the separate actions 

of States establishing standards of performance for existing 

sources and implementing and enforcing those standards. Cf. 

American Trucking Assn’s v. EPA, 175 F. 3d 1027, 1043-45 (D.C. 

Cir. 1999), rev’d on different grounds sub nom., Whitman v. 

American Trucking Assn’s, 531 U.S. 457 (2000) (National Ambient 

Air Quality Standards have no economic impact, for purposes of 

Regulatory Flexibility Act, because impacts result from the 

actions of States through their development, implementation and 

enforcement of state implementation plans). Thus, for example, 

although questions may exist whether actions such as increased 

utilization of solar or wind power could have effects on listed 

species, the EPA believes that such effects (if any) would 

result from decisions and actions by states in developing, 

implementing and enforcing their plans. The precise steps States 

choose to take in that regard cannot be determined or ordered by 
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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 _____ in the contiguous 

U.S.increase by ___roughly 6 to 7 percent in 2020, and by 

roughly 3 percent in 2030. While consumers average (contiguous 

U.S.). Average monthly electricity bills are anticipated to 

declineincrease by ___roughly 3 percent in 2020, but decline by 

approximately 9 percent by 2030. The decreased projection in 

these two metrics is a result of the increasing penetration of 

demand-side programs that more than offset increased prices to 

end users by their expected savings from reduced electricity 

use.

 The average delivered coal price to the power sector is 

projected to _____decrease by ___16 to 17 percent in 2020 and 

___roughly 18 percent in 2030, relative to the base case withfor

Option 1. The EPA also projects that electric power sectorFormatted: Indent: Before: 0", First line: 0"
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delivered natural gas prices will _____increase by __9 to 12

percent in 2020 and _______, with negligible changes by __ 

percent in 2030. Natural gas use for electricity generation will 

______increase by ___ billionas much as 1.2 trillion cubic feet 

(BCF) in 2020 relative to the base case. Finally, the, declining 

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 ___ million tonsroughly 25 to 27 percent in 

2020 from base case levels, which is about ___. The use of coal 

by the power sector will decrease roughly 30 to 32 percent of 
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total coal produced for the electric power sector in that year 

in the base case. 

 Under the proposed Option 1, the EPA projects ___ GW of 

coal-fired generation may be uneconomic to maintain and may be 

removed from operation by 2030. This level of projected, 

currently unplanned coal retirements exceeds the base case 

projectionRenewable energy capacity is anticipated to increase

by ___roughly 12 GW in 2020 and by 9 GW. If current forecasts of 

either natural gas prices or electricity demand are revised in 

the future to be higher, there would be greater incentive to 

keep these coal-fired units operational. in 2030 under Option 1.

Energy market impacts offrom the proposed guidelines are 

discussed more extensively in the RIA that isfound in the docket 

for this action.rulemaking. 

C.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 policy case in which 

Statesstates pursue a distinct set of strategies beyond the 

strategies taken in the base case to meet the terms of the EGU 

GHG emission guidelines, and include cost estimates for demand -

side energy efficiency. The compliance assumptions – and,

therefore, 
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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 pursuestates 

may ultimately pursue. These illustrative compliance scenarios 

are designed to reflect, to the extent possible, the scope and 

the nature of the proposed guidelines. However, there is 

considerable uncertainty with regards to the precise measures 

that states will adopt to meet the proposed requirements, 

because there are considerable flexibilities afforded to the 

states in developing their state plans. 

 The EPA projects that the annual incremental compliance 

cost of Option 1 is estimated to be $___between $5.5 and $7.5_

billion in 2020 and $___between $7.3 and $8.8 billion (2011$) in 

2030, excludingincluding` 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 20252030, the 

estimated compliance cost of Option 2 is estimated to be $ 

___between $1.9 and $3.1 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 

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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 $____$61.6 million 

(2011$) in 2020 for OptionOptions 1. and 2 and $8.2 million for 

both Options 1 and 2 in 2025 and 2030. More detailed cost 

estimates are available in the RIA included in the rulemaking

docket. 

DF. What are the economic and employment impacts? 

The proposed standards are projected to result in certain 

changes to power system operation as a result of the application 

of Statestate emission rate goals. Overall, we project dispatch 

changes, changes to fossil fuel and retail electricity prices, 

and some additional coal retirements. NaturalAverage electric 

power sector-delivered natural gas prices are projected to 

______increase by roughly ___9 to 12 percent in 2020 in Option 1

and , with negligible changes by ____2030. Under Option 2, 

electric power sector natural gas prices are projected to 

increase by roughly 8 percent under Option 2 in 2020, on an 

average nationwide basis. Under Option 1, natural gas prices 

____ by percent , and decrease in 2030. Coal prices areThe 

average delivered coal price to the power sector is projected to 

______decrease by roughly ___16 to 17 percent in 2020 under both 
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Options, Option 1, and decrease by roughly 14 percent under 

Option 2, on a nationwide average basis. Retail electricity 

prices are projected to _____ by increase 6 to 7 percent under 

Option 1 and _____increase by ____roughly 4 percent under Option 

2, both in 2020 and on an average nationwide basis across the 

contiguous U.S. By 2030 under Option 1, electricity prices _____ 

by ___ percent. Coal retirements are projected to be ___ W for 

increase by about 3 percent. Under Option 1 in 2030 and ___, the 

EPA projects 46 to 50 GW of additional coal-fired generation may 

be uneconomic to maintain and may be removed from operation by 

2030. The EPA projects that under Option 2 in, 30 to 33 GW of 

additional coal-fired generation may be uneconomic to maintain 

and may be removed from operation by 2030. 

 It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal fired capacity. By

2025, the average age of the coal-fired fleet will be 49 years 

old and 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 

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assumes that overall electric demand will decrease 

significantly, as Statesstates ramp up programs that result in 

lower overall demand. End-use energy efficiency levels increase 

such that they achieve a ___about an 11 percent reduction on 

overall electricity demand levels in 2030 for Option 1, and a 

___approximately an 8 percent reduction in 20252030 for Option 

2. In response, there are anticipated to be notable changes to 

costs, prices, and electricity generation in the power sector as 

more end-use efficiency is realized. 

Changes in price or demand for electricity, natural gas, 

coal, can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in cost of production may 

result in changes in price, changes in quantity produced, and 

changes in profitability of firms affected. The EPA recognizes 

that these guidelines provide significant flexibilities and 

states implementing the guidelines may choose to mitigate 

impacts to some markets outside the EGU sector. Similarly, 

demand for new generation or energy efficiency can result in 

shifts in production and profitability for firms that supply 

those goods and services, and the guidelines provide flexibility 

for states that may want to enhance demand for goods and 

services from those sectors. 
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Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science” (Executive Order 13563, 2011). Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, during 

periods of sustained high unemployment, employment impacts are 

of particular concern and questions may arise about their 

existence and magnitude. 

 States have the responsibility and flexibility to implement 

policies and practices for compliance with Proposed Electric 

Generating Unit Greenhouse Gas Existing Source Guidelines. As 

such, given the wide range of approaches that may be used, 

quantifyingQuantifying the associated employment impacts is 

difficult. 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 
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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 XXXXXX to XXXXXX jobyears in 2020. Demand side energy efficiency employment impacts 

may range from approximately YYYYY to YYYYY job-years in 2020. 

E. 25,900to 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 

78,800 jobs in 2020 for Option 1 and 57,000 increased jobs for 

Option 2. By its nature, energy efficiency reduces overall 

demand for electric power. The EPA recognizes as more efficiency 

is built into the U.S. power system over time, lower fuel 

requirements may lead to fewer jobs in the coal and natural gas 

extraction sectors, as well as in EGU construction and operation 

than would otherwise have been expected. The EPA also recognizes 

the fact that, in many cases, employment gains and losses that 

might be attributable to this rule would be expected to affect 

different sets of people. Moreover, workers who lose jobs in 

these sectors may find employment elsewhere just as workers 

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employed in new jobs in these sectors may have been previously 

employed elsewhere. Therefore the numbers reported in these 

sectors may have been previously employed elsewhere. Therefore 

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 

Mercury and Air Toxics Standards. 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 $__$32

billion to $__$51 billion in 2020 and $__$54 billion to $__$86

billion in 2030 (2011 dollars atassuming a 3-percent discount 

rate [model average]).regional compliance approach (2011 dollars 
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at a 3-percent discount rate [model average]). If states comply 

using a state-specific compliance approach, these climate and 

health co-benefits estimates are estimated to be $33 to $54 

billion in 2020 and $56 to $89 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 $__ billion to $__ billion in 2020 and $__$25

billion to $__$41 billion in 2020 and $35 billion to $56 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 $26 billion 

to $42 billion in 2020 and $35 billion to $57 billion in 2025 

(2011 dollars at a 3-percent discount rate [model average]). A 

summary of the emission reductions and monetized benefits 

estimated for this rule at all discount rates and additional 

analysis years is provided in Tables 11 and 129 through 14 of 

this preamble. 
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Table 11.9 Summary of the Monetized Global Climate Benefits for 

the Proposed StandardsOption 1 (billions of 2011 dollars)a

CO2 Emission 

Reductions (metric 

tons)

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

Option 1 in 2020 Regional 

Compliance

State 

Compliance

CO2 Reductions 

(million metric 

tons) 

371 383 

5 percent (average 

SCC) 

$4.7 $4.9

3 percent (average 

SCC) 

$17 $18

2.5 percent (average 

SCC) 

$25 $26

3 percent (95th

percentile SCC) 

$51 $52

Option 1 in 

20302025

Regional 

Compliance

State 

Compliance

CO2 Reductions 

(million metric 

tons) 

501 506 

5 percent (average 

SCC) 

$7.5 $7.6

3 percent(average SCC) $25 $25

2.5 percent (average 

SCC) 

$37 $37

3 percent (95th

percentile SCC) 

$76 $77

Option 2 in 

20202030

Regional 

Compliance

State 

Compliance

CO2 Reductions 

(million metric 

tons)

5 percent (average 

SCC)

545 555

3 percent(average 

SCC) 

2.5 percent (average 

SCC) 

$9.3 $9.5

3 percent (95th

percentile SCC) 

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Option 2 in 

2025 

5 percent 

(average SCC) 

3 percent(average SCC) $30 $31

2.5 percent (average 

SCC) 

$44 $44

3 percent (95th

percentile SCC) 

$92 $94

a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global SCCsocial cost of 

carbon (SCC) estimates for the analysis years (2020, 2025, 2030) 

and are rounded to two significant figures. 

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Table 12.10 Summary of the Monetized Health Co-Global Climate 

Benefits for the Proposed Standards in the U.S.Option 2

(billions of 2011 dollars)a

Pollutant

National Emission 

Reductions (short 

tons)Discount Rate 

(Statistic)

Monetized Health Cobenefits 

(3 percent 

discount)Climate Benefits 

Monetiz

ed Health 

Co-benefits 

(7 percent 

discount)

Option 1 in 

2020 

Regional 

Compliance State Compliance

CO2 Reductions 

(million 

metric tons) 

283 295

5 percent (average 

SCC) 

$3.6 $3.8

3 percent (average 

SCC) 

$13 $14

2.5 percent (average 

SCC) 

$19 $20

3 percent (95th

percentile SCC) 

$39 $40

2025 Regional 

Compliance State Compliance 

CO2 Reductions 

(million 

metric tons) 

368 376

PM2.5 

precursors

b

5 percent (average 

SCC)

$5.5 $5.6

SO2 3 percent(average SCC) $18 $19

2.5 percent (average 

SCC) 

$27 $28

3 percent (95th

percentile SCC) 

$56 $57

2030 Regional 

Compliance State Compliance 

CO2 Reductions 

(million 

metric tons) 

353 373

5 percent (average 

SCC) 

$6.0 $6.4

3 percent(average SCC) $20 $21

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2.5 percent (average 

SCC) 

$28 $30

3 percent (95th

percentile SCC) 

$60 $63

a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global SCC estimates for the 

analysis years (2020, 2025, 2030) and are rounded to two 

significant figures. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

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Table 11 Summary of the Monetized Health Co-Benefits for the 

Proposed Standards Option 1 Regional Compliance Approach in the 

U.S. (billions of 2011 dollars)a 

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 Regional Compliance Approach 2020 

PM2.5 precursors b

SO2 292 $12 to $26 $11 to $24 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 345 $2.2 to $5.0 $2.0 to 

$4.5

Ozone precursor c

NOx 146 $0.63 to 

$2.7

$0.63 to 

$2.7

Total Monetized Health Co-benefits $15 to $34 $13 to $31

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $51 $30 to $48

Option 1 in 2030Regional Compliance Approach 2025 

PM2.5 precursors b

SO2 395 $17 to $38 $15 to $35

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

Directly emitted PM2.5 

(crustal) 

NOx 421 $3.0 to $6.8 $2.7 to 

$6.1

Ozone precursor c

NOx 180 $1.0 to $4.3 $1.0 to 

$4.3

Total Monetized Health Co-benefits $21 to $50 $19 to $45

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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$46 to $75 $44 to $70

Option 2 in 20201 Regional Compliance Approach 2030

PM2.5 precursors b

SO2 424 $20 to $44 $18 to $40

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 407 $3.0 to $6.7 $2.7 to 

$6.1

Ozone precursor c

NOx 176 $1.1 to $4.5 $1.1 to 

$4.5

Total Monetized Health Co-benefits $24 to $55 $21 to $50

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$54 to $86 $52 to $81

Option 2 in 2025 

PM2.5 precursors b

SO2

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 
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Page 542 of 639

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. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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Table 12 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Proposed Guidelines Option 1 State Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 State Compliance Approach in 2020 

PM2.5 precursors b

SO2 335 $13 to $29 $11 to $26 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 367 $2.2 to 

$4.9

$2.0 to 

$4.4

Ozone precursor c

NoxNOx 157 $0.64 to 

$2.7

$0.64 to 

$2.7

Total Monetized Health Co-benefits $15 to $36 $14 to $33 

Total Monetized Health Co-benefits

combined with Monetized Climate 

Benefits d

$33 to $54 $32 to $50

Option 1 State Compliance Approach in 2025 

PM2.5 precursors b

SO2 425 $18 to $40 $16 to $36 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

Directly emitted PM2.5 

(crustal) 

NOx 436 $2.9 to 

$6.5 

$2.6 to 

$5.8 

Ozone precursor c

NOx 190 $1.0 to 

$4.4 

$1.0 to 

$4.4 

Total Monetized Health Co-benefits $22 to $51 $20 to $46 

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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$47 to $76 $45 to $71

Option 1 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 471 $21 to $47 $19 to $43 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 428 $2.9 to 

$6.6 

$2.6 to 

$6.0 

Ozone precursor c

NOx 187 $1.1 to 

$4.6 

$1.1 to 

$4.6 

Total Monetized Health Co-benefits $25 to $58 $23 to $53 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$56 to $89 $53 to $84 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

Formatted Table
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Page 545 of 639

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Formatted: Line spacing: Double
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

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Table 13 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Option 2 Regional Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

 Option 2 Regional Compliance Approach 2020 

PM2.5 precursors b

SO2 244 $9.8 to $22 $8.9 to $20 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 268 $1.7 to 

$3.9 

$1.6 to 

$3.5 

Ozone precursor c

NOx 111 $0.47 to 

$2.0 

$0.47 to 

$2.0 

Total Monetized Health Co-benefits $12 to $28 $11 to $25 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$25 to $41 $24 to $38 

Option 2 Regional Compliance Approach in 2025 

PM2.5 precursors b

SO2 $13 to $29 $12 to $26 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

297 

Directly emitted PM2.5 

(crustal) 

NOx 309 $2.2 to 

$5.0 

$2.0 to 

$4.5 

Ozone precursor c

NOx 129 $0.73 to 

$3.1 

$0.73 to 

$3.1 

Total Monetized Health Co-benefits $16 to $37 $14 to $34 
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Page 547 of 639

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $56 $33 to $52 

Option 2 Regional Compliance Approach in 2030 

PM2.5 precursors b

SO2 287 $13 to $30 $12 to $27 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 252 $1.8 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c

NOx 110 $0.66 to 

$2.8 

$0.66 to 

$2.8 

Total Monetized Health Co-benefits $16 to $37 $14 to $34 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $56 $34 to $53 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 548 of 639

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Table 14 Summary of the Monetized Health Co-Benefits in the U.S. 

for Option 2 State Compliance Approach (billions of 2011 

dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 2 State Compliance Approach in 2020 

PM2.5 precursors b

SO2 267 $10 to $23 $9.1 to $21 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 281 $1.7 to 

$3.8 

$1.5 to 

$3.4 

Ozone precursor c

NOx 119 $0.48 to 

$2.1 

$0.48 to 

$2.1 

Total Monetized Health Co-benefits $12 to $29 $11 to $26 
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Page 549 of 639

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$26 to $42 $25 to $40 

Option 2 State Compliance Approach in 2025 

PM2.5 precursors b

SO2 327 $14 to $30 $12 to $27 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

Directly emitted PM2.5 

(crustal) 

NOx 317 $2.1 to 

$4.7 

$1.9 to 

$4.2 

Ozone precursor c

NOx 136 $0.72 to 

$3.1 

$0.72 to 

$3.1 

Total Monetized Health Co-benefits $16 to $38 $15 to $35 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $57 $34 to $54 

Option 2 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 321 $14 to $32 $13 to $29 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

Directly emitted 

PM2.5 (crustal) 

NOx 274 $1.9 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c

NOx 120 $0.68 to 

$2.9

$0.68 to 

$2.9

Total Monetized Health Co-benefits $17 to $39 $15 to $36 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$37 to $60 $36 to $56 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 550 of 639

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate; however, we emphasize the 

importance and value of considering the full range of SCC 

values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 

The EPA has used the U.S. government’s SCC estimates to 

analyze CO2 climate impacts of this rulemaking. The U.S. 

government first published the federal SCC estimates in 2010 

following an interagency process that included the EPA and other 

executive branch entities; the process used three integrated 

assessment models (IAM) to develop SCC estimates and selected 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 551 of 639

four global values for use in regulatory analyses. The U.S. 

government recently updated these estimates using new versions 

of each integrated assessment model and published them in 2013. 

The 2013 update did not revisit the 2010 modeling decisions 

(e.g., with regard to the discount rate, reference case 

socioeconomic and emission scenarios or equilibrium climate 

sensitivity). Rather, improvements in the way damages are 

modeled are confined to those that have been incorporated into 

the latest versions of the models by the developers themselves 

and published in the peer-reviewed literature. The 2010 SCC 

Technical Support Document (2010 SCC TSD) provides a complete 

discussion of the methods used to develop these estimates and 

the 2013 SCC TSD presents and discusses the updated 

estimates.295,296 

 

295 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

296 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 
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Page 552 of 639

The EPA and other agencies have sought public comments on 

the USG SCC estimates as part of various rulemakings. In 

addition, OMB’s Office of Information and Regulatory Affairs 

recently sought public comment on the approach used to develop 

the estimates. The comment period ended on February 26, 2014, 

and OMB is reviewing the comments received. 

The four SCC estimates, updated in 2013, are as follows: 

$13, $46, $68, and $137 per metric ton of CO2 emissions in the 

year 2020 (2011 dollars).297 The first three values are based on 

the average SCC from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. SCCs at several discount rates 

are included because the literature shows that the SCC is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

 

Group on Social Cost of Carbon, with participation by the 

Council of Economic Advisers, Council on Environmental Quality, 

Department of Agriculture, Department of Commerce, Department of 

Energy, Department of Transportation, Environmental Protection 

Agency, National Economic Council, Office of Energy and Climate 

Change, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

November 2013). Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/assets/infore

g/technical-update-social-cost-of-carbon-for-regulator-impactanalysis.pdf>. 

297 The 2010 and 2013 TSDs present SCC in $2007. The estimates 

were adjusted to 2011$ using the GDP Implicit Price Deflator. 

Also available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-

02/pdf/ECONI-2013-02-Pg3.pdf. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 553 of 639

by different generations). The fourth value is the 95th

percentile of the SCC from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SCC distribution (representing less likely, but potentially 

catastrophic, outcomes). 

The 2010 SCC TSD noted a number of limitations to the SCC 

analysis, including the incomplete way in which the integrated 

assessment models capture catastrophic and non-catastrophic 

impacts, their incomplete treatment of adaptation and 

technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk 

aversion. Current integrated assessment models do not assign 

value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change 

literature because of a lack of precise information on the 

nature of damages and becausefor various reasons, including the 

inherent difficulties in valuing non-market impacts and the fact 

that the science incorporated into these models understandably 

lags behind the most recent research. Nonetheless, these 

estimates and the discussion of their limitations represent the 

best available information about the social benefits of CO2

emission reductions to inform the benefit-cost analysis. Model 
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Page 554 of 639

developers continually update the models to incorporate recent 

research. The new versions of the models used to estimate the 

values presented belowin this rulemaking offer some improvements 

in these areas identified above, although further work is 

warranted. Accordingly, the EPA and other parties continue to 

conduct research on modeling and valuation of climate impacts 

with the goal of improving these estimates. Additional details 

are provided in the SCC TSDs. 

 The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions under 

illustrative compliance options for the proposed standards. 

Unlike the global SCC estimates, the air pollution health cobenefits are estimated for the contiguous U.S. only. Because we 

were unable to conduct air quality modeling for this rule, we 

insteadWe used a “benefit-per-ton” approach to estimate the 

benefits of this rulemaking. To create the PM2.5 benefit-per-ton 

estimates, this approach uses a model to convert emissions of 

PM2.5 precursors into changes in ambient PM2.5 levels and another 

model to estimate the changes in human health associated with 

that change in air quality, which are then divided by the 

emissions in specific sectors. National average benefit-per-ton 

estimates for the EGU sector were derived using the approach 
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Page 555 of 639

published in Fann et al. (2012),298 but they have since been 

updated to reflect the studies and population data in the 2012 

PM NAAQS RIA and were separated into regional estimates to 

provide greater spatial resolution.299 In addition, we generated 

regional benefit-per-ton estimates for changes in ozone 

exposure. The ozone estimates used the ozone information from 

the sector modeling for the EGU sector described in Fann et al. 

(2012) and the health impact assumptions used in the Ozone NAAQS 

RIAs.300,301 To calculate the co-benefits for the proposed 

standards, we multiplied the regional benefit-per-ton estimates 

 

298 Fann, N., K.R. Baker and C.M. Fulcher. 2012. “Characterizing 

the PM2.5-related health benefits of emission reductions for 17 

industrial, area and mobile emission sectors across the U.S.” 

Environment International 49 41–151. 299 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>. 

300 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final 

Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, 

NC: Office of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and Cost Group 

Research. (EPA document number EPA-452/R-08-003, March). 

Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

301 U.S. Environmental Protection Agency (U.S. EPA). 2010. 

Section 3: Re-analysis of the Benefits of Attaining Alternative 

Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf>. 
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for the EGU sector by the corresponding emission reductions.302

All benefit-per-ton estimates reflect the geographic 

distribution of the modeled emissions, which may not exactly 

match the emission reductions in this rulemaking, and thus they 

may not reflect the local variability in population density, 

meteorology, exposure, baseline health incidence rates, or other 

local factors for any specific location. More information 

regarding the derivation of the benefit-per-ton estimates is 

available in the RIA. 

These models assume that all fine particles, regardless of 

their chemical composition, are equally potent in causing 

premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by 

particle type. Even though we assume that all fine particles 

have equivalent health effects, the benefit-per-ton estimates 

vary between precursors depending on the location and magnitude 

of their impact on PM2.5 levels, which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

 

302 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 

<http://www.epa.gov/airquality/benmap/models/Source_Apportionmen

t_BPT_TSD_1_31_13.pdf>. 
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response functionfunctions for premature mortality and the value 

of a statistical life used to value reductions in premature 

mortality. For PM2.5, we cite two key empirical studies, one 

based on the American Cancer Society cohort study303 and the 

extended Six Cities cohort study.304 We present the PM2.5 cobenefits results as a range based on the concentration-response 

functions from these two epidemiology studies, but this range 

does not capture the full range of uncertainty inherent in the 

co-benefits estimates. In the RIA for this rule, which is 

available in the docket, we also include PM2.5 co-benefits 

estimates derived from expert judgments (Roman et al., 2008)305

as a characterization of uncertainty regarding the PM2.5-

mortality relationship. For the ozone co-benefits, we present the 

results as a range reflecting the use of several different 

concentration-response functions for mortality, with the lower 

 

303 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. 

Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 

American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute. 

304 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970. 305 Roman, H., et al. 2008. “Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S.” Environmental Science & Technology, Vol. 42, No. 7, 

February, pp. 2268 – 2274. 
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end of the range based on a function from Bell, et al. (2004)306

and the upper end based on a function from Levy, et al. 

(2005)307. Similar to PM2.5, the range of ozone co-benefits does 

not capture the full range of inherent uncertainty. 

In this analysis, the EPA assumes that the health impact 

function for fine particles is without a threshold. This is 

based on the conclusions of EPA’s Integrated Science Assessment 

for Particulate Matter,308 which evaluated the substantial body 

of published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

 

306 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8. 307 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone 

exposure and mortality: an empiric bayes metaregression 

analysis.” Epidemiology. 16(4): p. 458-68. 308 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. 
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In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available due to time and resource limitations,309 and thus, we 

are unable to estimate the percentage of premature mortality 

associated with this specific rule’s emission reductions at each 

PM2.5 level. As a surrogate measure of mortality impacts, we 

provide the percentage of the population exposed above the 

lowest measured PM2.5 level (LML) in each of the studies from 

which we obtained concentration-response functions for PM2.5 

mortality, using the estimates of PM2.5 from the source 

apportionment modeling used to calculate the benefit-per-ton 

estimates for the EGU sector. Using the Krewski, et al. (2009) 

study, 93 percent of the population is exposed to annual mean 

PM2.5 levels at or above the LML of 5.8 micrograms per cubic 

meter (μg/m3

). Using the Lepeule, et al. (2012) study, 67 percent 

of the population is exposed above the LML of 8 μg/m3. It is 

 

309 In addition, site-specific emission reductions will depend upon how states 

implement the guidelines. 
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important to note that baseline exposure is only one parameter 

in the health impact function, along with baseline incidence 

rates, population, and change in air quality. Therefore, caution 

is warranted when interpreting the LML assessment for this rule 

because these results are not consistent with results from rules 

that had air quality modeling. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 

indication of the expected health benefits of the air pollution 

emission reductions for the illustrative compliance options for 

the proposed standards under a set of reasonable assumptions. 

This analysis does not include the type of detailed uncertainty 

assessment found in the 2012 PM2.5 National Ambient Air Quality 

Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the 

necessary air quality input and monitoring data to conduct a 

complete benefits assessment. In addition, using a benefit-perton approach adds another important source of uncertainty to the 

benefits estimates. The 2012 PM2.5 NAAQS benefits analysis 
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Page 561 of 639

provides an indication of the sensitivity of our results to 

various assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOx, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for these proposed amendments. 

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket. 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

Under Section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an "economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more or 

adversely affect in a material way the economy, a sector of the 

economy, productivity, competition, jobs, the environment, 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 562 of 639

public health or safety, or state, local, or tribal governments 

or communities. The $100 million threshold can be triggered by 

either costs or benefits, or a combination of them. Accordingly, 

the EPA submitted this action to OMB for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011),)), and 

any changes made in response to OMB recommendations have been 

documented in the docket for this action. 

 The EPA also prepared an analysis of the potential costs 

and benefits associated with this action. This analysis is 

contained in the RIA for this proposed rule. A copy of the 

analysis is available in the docket for this action.

 Consistent with EO 12866 and EO 13563, the EPA estimated 

the costs and benefits for illustrative compliance 

scenariosapproaches 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 U.S. government’s social cost of 

carbon (USG SCC) estimates — i.e., the monetary value of impacts 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 563 of 639

associated with a marginal change in CO2 emissions in a given 

year, to analyze CO2 climate impacts of this rulemaking. The four 

USG 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 by 

the USG: the model average at 3% discount rate. TheFor the 

regional compliance approach, the EPA estimates that in 2020 

this Option 1 proposal will yield monetized climate benefits (in 

2011$) of approximately $__$17 billion (3 percent model 

average). The air pollution health co-benefits in 2020 are 

estimated to be $__$15 billion to $__$34 billion (2011$) for a 3 

percent discount rate and $___$13 billion to $__$31 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 $___ billion (2011$) in 2020 [MRR costs to be 

added when available]. The quantified net benefits (the 

difference between monetized benefits and costs) in 2020 are 

estimated to be $__ billion to $__ billion (2011$) using a 3 

percent discount rate (model average). 
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 For Option 1 in 2030, the EPA estimates this proposal will 

yield monetized climate benefits (in 2011$) of approximately $__ 

billion (3 percent, model average). The air pollution health cobenefits in 2030 are estimated to be $__ billion to $__ billion 

(2011$) for a 3 percent discount rate and $__ billion to $__ 

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 $__$5.5 billion (2011$) in 

20302020. The quantified net benefits (the difference between 

monetized benefits and costs) in 20302020 are estimated to be 

$__$26 billion to $__$46 billion assuming a regional compliance 

approach (2011$) using a 3 percent discount rate (model 

average). Based upon the foregoing discussion, it remains clear 

that theThis range of net benefits of the proposalis also 

estimated to be $26 billion to $45 billion assuming a state 

compliance approach (2011$) using a 3 percent discount rate 

(model average). Table 15 shows the climate benefits, health cobenefits, cost and net benefits for Option 1 are substantial in 

2020 and 2030for state and far exceed the costs. regional 

compliance approaches. Table 16 shows similar estimates for 

2030.
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Page 565 of 639

 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 $24 billion to $55 billion (2011$) for 

a 3 percent discount rate and $21 billion to $50 billion (2011$) 

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 $47 billion to $78 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 

$25 billion to $58 billion (2011$) for a 3 percent discount rate 

and $23 billion to $53 billion (2011$) 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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Page 566 of 639

between monetized benefits and costs) in 2030 are estimated to 

be $47 billion to $80 billion (2011$) 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 1315—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – 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

$15 to $34 $13 to $31

Total Compliance 

Costs d

$5.5 $5.5

Net Monetized 

Benefits e

$26 to $45 $25 to $42

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___1.3 tons of Hg and ___ tons of HCl 

Ecosystem Effects 

Visibility impairment 

Option 1 State Compliance Approach

Formatted: Centered

Formatted: Centered

Formatted: Centered
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

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Climate benefits b $18

Air pollution health 

co-benefits c

$15 to $36 $14 to $33

Total Compliance 

Costs d

$7.5 $7.5

Net Monetized 

Benefits e

$26 to $46 $24 to $43

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 

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 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 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 568 of 639

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%. 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 1416—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – 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

$24 to $55 $21 to $50

Total Compliance 

Costs d

$7.3 $7.3

Net Monetized 

Benefits e

$47 to $78 $44 to $73

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___1.7 tons of Hg and ___580 tons of HCl 

Ecosystem Effects 

Visibility impairment 

Option 1 State Compliance Approach 

Formatted: Centered

Formatted: Centered

Formatted: Centered
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Page 569 of 639

Climate benefits b $31 

Air pollution health 

co-benefits c

$25 to $58 $23 to $53 

Total Compliance 

Costs d

$8.8 $8.8 

Net Monetized 

Benefits e

$47 to $80 $45 to $75 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

2.1 tons ofHg 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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

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

PM2.5 and ozone. These models assume that all fine particles, 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 570 of 639

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%. 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 1517 and 1618. As these tables reflect, net 

benefits in 2020 are estimateestimated to be $__$21 to $__$37

billion assuming a (3 percent discount rate) and from $__$20 to 

$__$34 billion assuming a(7 percent discount rate of 7 percent.) 

for Option 2 assuming regional compliance. These Option 2 net 

benefit estimates become $20 to $37 billion (3 percent discount 

rate) and $19 to $34 billion 7 percent discount rate) with the 

state compliance approach. In 2025, net benefits are estimated 

to be $___ billion to $__$30 billion to $51 billion (3 percent 

discount rate) and from $28 billion to $48 billion (7 percent 

discount rate)assuming a regional compliance approach and $30 

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

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

state compliance approach.
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Page 571 of 639

 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 1517 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE 

COSTS, AND NET BENEFITS FOR THE FINAL RULE – 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

$12 to $28 $11 to $25

Total Compliance 

Costs d

$4.3 $4.3

Net Monetized 

Benefits e

$21 to $37 $20 to $34

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___0.9 tons of Hg and __ tons of HCl 

Ecosystem Effects 

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Visibility impairment 

Option 2 State Compliance Approach 

Climate benefits b $14 

Air pollution health 

co-benefits c

$12 to $29 $11 to $26 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$20 to $37 $19 to $34 

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

emitted PM2.5, SO2 and NOX. The range reflects the use of 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 573 of 639

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 option and a discount rate of approximately 5%. This 

estimate includes monitoring, recordkeeping [MRR to be added 

when available], 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 1618 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE 

COSTS, AND NET BENEFITS FOR THE FINAL RULE – 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

$16 to $37 $14 to $34

Total Compliance 

Costs d

$4.5 $4.5

Net Monetized 

Benefits e

$30 to $51 $28 to $48

Non-monetized Direct exposure to SO2 and NO2___ 

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Benefits 1.3 tons of Hg and ___ tons of HCl 

Ecosystem Effects 

Visibility impairment 

Option 2 State Compliance Approach 

Climate benefits b $19 

Air pollution health 

co-benefits c

$16 to $38 $15 to $35 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$30 to $52 $28 to $48 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2 

1.7 tons of Hg 

Ecosystem Effects 

Visibility impairment 

[Billions of 2011]

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

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95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 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%. This 

estimate includes monitoring, recordkeeping [MRR to be added 

when available], 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. 

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 [insert #]. 

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 

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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 66,618 

hours at a total annual labor cost of $4,481,958. The total 

annual burden for the federal governmenta range of 315,554 hours 

at a total annual labor cost of $22,334,119, to 632,338 hours at 

a total annual labor cost of $44,755,317. 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 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 23,377a range of 

315,554 hours at a total annual labor cost of $1,201,952. 

Burden22,334,119, to 632,338 hours at a total annual labor 

cost of $44,755,317. The lower bound estimate reflects the 
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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 53,267 hours at a total annual labor cost of $2,958.005Burden

means the total time, effort, or financial resources expended by 

persons to generate, maintain, retain, or disclose or provide 

information to or for a Federal agency. This includes the time 

needed to review instructions; develop, acquire, install, and 

utilize technology and systems for the purposes of collecting, 

validating, and verifying information, processing and 

maintaining information, and disclosing and providing 

information; adjust the existing ways to comply with any 

previously applicable instructions and requirements; train 

personnel to be able to respond to a collection of information; 

search data sources; complete and review the collection of 

information; and transmit or otherwise disclose the information. 

An agency may not conduct or sponsor, and a person is not 

required to respond to a collection of information unless it 

displays a currently valid OMB control number. The OMB control 
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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 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 

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 
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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 1719 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 1719. Potentially Regulated Categories and Entitiesa

 

Category NAICS 

Code 

Examples of Potentially Regulated 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units. 
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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 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 
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F.3d 1029, 1043-45 (D.C. Cir. 1999) national standards for 

allowable concentrations of particulate matter in ambient air as 

required by section 109 of the CAA. See also American Trucking 

Associations v. EPA. 175 F.3d at 1044–45 (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, emission guidelines 

established under CAA section 111(d) do not impose any direct 

compliance requirements on regulated entities. Thus, this proposed 

rule is not subject to the requirements of section 202 or section 

205 of UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

In light of the interest among governmental entities, the 

EPA initiated consultations with governmental entities while 

formulating the provisions of the proposed standards for new 

EGUs. Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new and 

existing sources. As described in the UMRA discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1500-1501, January 8, 2014), the 

EPA consulted with the following 10 national organizations 
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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 

This Under Executive Order 13132, EPA may not issue an 

action that has federalism implications, that imposes 

substantial direct compliance costs, and that is not required by 

statute, unless the Federal government provides the funds 

necessary to pay the direct compliance costs incurred by State 

and local governments, or the EPA consults with state and local 
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officials early in the process of developing the proposed action

does not .

 The EPA has concluded that this action may have federalism 

implications. It would not have substantial direct effects on 

the States, on the relationship between the national government 

and the States, or on the distribution of power and 

responsibilities among the various levels of government, as 

specified in EO 13132. This proposed action would not , because 

it may impose substantial direct compliance costs on stateState

or local governments, nor would it preempt state law. 

Specifically, 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 
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and local officials in the process of developing the proposed 

standards for newly constructed EGUs. This outreach regarded 

planned actions for new, reconstructed, modified and existing 

sources. The EPA invited the following 10 national organizations 

representing state and local elected officials to a meeting on 

April 12, 2011, in Washington DC: (1) National Governors 

Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) 

U.S. Conference of Mayors, (6) National Association of Counties, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 

These 10 organizations representing elected state and local 

officials have been identified by the EPA as the “Big 10” 

organizations appropriate to contact for purpose of consultation 

with elected officials. On February 26, 2014, the EPA re-engaged 

with those governmental entities to provide a pre-proposal 

update on the emission guidelines established under CAAfor 

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 
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EPA officials and provide input regarding reducing carbon 

pollution from power plants.

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 111(d) do not impose any direct 

compliance costs on regulated entities. Thus, Executive Order 

13132 does not apply to this action6(b) of Executive Order 

13132. In the spirit of Executive Order 13132, and consistent 

with EPA policy to promote communications between EPA and State 

and local governments, 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 onin their landsarea 

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 

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for that purpose and is delegated authority for air quality 

planning purposes, these proposed emission guidelines would 

require that planning requirements be met and emission 

management implementation plans be executed by the tribes. The 

EPA is aware of three coal-fired EGUs and one natural 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 gasfired 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 
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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 onlocated in its landsarea of 

Indian Country310 would have the opportunity, but not the 

obligation, to establish a CO2 performance standard and a CAA 

section 111(d) plan for its tribal landsarea 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, 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 

 

310 The EPA is aware of at least threefour affected sourcesEGUs

located in Indian Country,country: two on [Navajo] lands --, the 

Navajo Generating Station and the Four Corners Generating 

Station -- and; 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 coalfired EGUs. The fourth affected EGU is an NGCC facility. 

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summary of issues being explored by the agency. Tribes have 

expressed varied points of view. Some tribes raised concerns 

about the impacts of the regulations on EGUs and the subsequent 

impact on jobs and revenue for their tribes. Other tribes 

expressed concern about the impact the regulations would have on 

the cost of water to their communities as a result of increased 

costs to the EGU that provide energy to transport the water to 

the tribes. Other tribes raised concerns about the impacts of 

climate change on their communities, resources, life ways and 

hunting and treaty rights. The tribes were also interested in 

the scope of the guidelines being considered by the agency 

(e.g., over what time period, relationship to state and 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. 
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G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5-

501 of the Order has the potential to influence the regulation. 

This action is not subject to EO 13045 because it does not 

involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that 

the CO2 emission reductions resulting from implementation of the 

proposed guidelines, as well as substantial ozone and PM2.5 

emission reductions as a 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 adverse effect 

on the supply, distribution, or use of energy. We have prepared 

a Statement of Energy Effects for this action as follows. We 
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estimate a ___4 to 7 percent price increase forin retail 

electricity prices nationwide, on average, across the contiguous 

U.S. in 2020, and a ___16 to 22 percent reduction in coal-fired 

power productionelectricity generation as a result of this rule. 

The EPA projects that electric power sector delivered natural 

gas prices will increase by about ___8 to 12 percent in 

2020. For more information on the estimated energy effects, 

please refer to the economic impact analysis for this final 

ruleproposal. 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 NTTAA of 1995 (Public Law No. 104-113; 

15 U.S.C. 272 note) directs the EPA to use Voluntary Census 

Standards in their 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 the OMB, with 

explanations when an agency does not use available and 

applicable VCS. This proposed rulemaking does not involve 

technical standards. 
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The EPA welcomes comments on this aspect of the proposed 

rulemaking and specifically invites the public to identify 

potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low-income populations in the U.S. 

Section II.A of this preamble summarizes the public health 

and welfare impacts from GHG emissions that were detailed in the 

2009 Endangerment Finding under CAA section 202(a)(1).311 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 

 

311 “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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vulnerable based on their circumstances. These include the poor, 

the elderly, the very young, those already in poor health, the 

disabled, those living alone, and/or indigenous populations 

dependent on one or a few resources. The Administrator placed 

weight on the fact that certain groups, including children, the 

elderly, and the poor, are most vulnerable to 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 
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likely be affected by the degradation of ecosystem goods and 

services associated with climate change. Southwest native 

cultures are especially vulnerable to water quality and 

availability impacts. Native Alaskan communities are likely to 

experience disruptive impacts, including shifts in the range or 

abundance of wild species crucial to their livelihoods and wellbeing. The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority and 

low-income populations. 

This proposed rule limits GHG emissions by establishing CO2 

emission guidelines for existing fossil fuel-fired EGUs. In 

addition to reducing CO2 emissions, implementing the proposed 

rule would reduce other emissions from EGUs which are dispatched 

less under a state’s 111(d) program because of 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. In the final 

rule revising the annual PM2.5 standard312313, the EPA identified 

persons with lower socioeconomic status as an at -risk 

 

312 U.S. EPA (2013). National Ambient Air Quality Standards for 

Particulate Matter, Final Rule. Federal Register 78 (15 January 

2013): 3086-3287. 

313 U.S. EPA (2013). National Ambient Air Quality Standards for 

Particulate Matter, Final Rule. Federal Register 78 (15 January 

2013): 3086-3287. 
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population for experiencing adverse health effects related to PM 

exposures. Persons with lower socioeconomic status have been 

generally found to have a higher prevalence of pre-existing 

diseases, limited access to medical treatment, and increased 

nutritional deficiencies, which can increase this population’s 

risk to PM-related and ozone-related effects.314315 Therefore, in 

areas where this rulemaking reduces exposure to PM2.5, ozone, and 

methylmercury persons with low socioeconomic status would also 

benefit. The regulatory impact analysis (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 methylmercury, 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 

 

314 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>.

315 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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at EGUs that are 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 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 

of GHGs and/or other regulated pollutants. As we noted in the 

NSR discussion in this preamble, a state can take steps to avoid 

increased utilization of particular EGUs and thus to 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, 
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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 

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 

highhigher peak concentrations of PM2.5, NOx, or ozone around such 

EGUs than is already occurring because peak hourly or daily 
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emissions generally would not change, but increased utilization 

may make periods of relatively high concentrationconcentrations

more frequent. It should be noted that the gas-fired sources 

that are likely to be dispatched more frequently than at present 

have very low emissions of primary particulate matter, SO2 and 

hazardous air pollutants per unit of electrical output, such 

that local (or regional) air quality for these pollutants is 

likely to be affected very little. Many are also very well 

controlled for emission of NOx. Depending on the specificity of 

the stateFor natural gas-fired EGUS, the EPA found that 

regulation of HAP emissions “is not appropriate or necessary 

because the impacts due to HAP emissions from such units are 

negligible based on the results of the study documented in the 

utility RTC” 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 
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predict which EGUs and communities may be in this type of 

situation and to address any concerns about localized NO2

concentrations in the design of the CAA section 111(d) program, 

or separately from the CAA section 111(d) program but before its 

implementation. In any case, existing tracking systems will 

allow states and the EPA to be aware of the EGUs whose 

utilization has increased most significantly, and thus to be 

able to prioritize our efforts to assess whether air quality has 

changed in the communities in the vicinity of such EGUs. There 

are multiple mechanisms in the CAA to address situations in 

which air quality has degraded significantly.

In conclusion, this proposed rule will result in regional 

and national pollutant reductions; however, there likely will 

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 
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Page 600 of 639

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 

pollutant addressed by this proposal. 

XII. Statutory Authority 

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(V) of the CAA, as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(V)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). 
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Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from Existing 

Stationary Sources: Electric Utility Generating Units

Page 601 of 639

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 UUUUU 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 greenhouse gases 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? 

60.5735 What authorities will not be delegated to state, 

local, or tribal agencies? 
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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 emissionsemission

performance goals? 

60.5770 What is the procedure for converting my state ratebased CO2 emissionsemission performance goal to a massbased CO2 emissions performance goal? 

60.5775 What schedules, performance periods, and compliance 

periods must I include in my state plan? 

60.5780 What emissionsemission 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?

 This subpart establishes emission guidelines and compliance 

schedules forapproval criteria for state plans that establish 

standards of performance limiting the control of greenhouse gas 
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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 subpart A 

of this part, the requirements of this subpart will apply. 

§ 60.5705 What greenhouse gases are regulated by this subpart? 

 The greenhouse gas regulated by this subpart is carbon 

dioxide (CO2). 

§ 60.5710 Am I affected by this subpart? 

 If you are the Administrator of an air quality program in a 

state with one or more affected EGUs that commenced construction 

on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], you must submit a state plan to U.S. Environmental 

Protection Agency (EPA) that implements the emission guidelines 

contained in this subpart. You must submit a negative 

declaration letter in place of the state plan if there are no 

affected EGUs for which construction commenced on or before 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] in your 

state. 
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§ 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 six 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 in lieu of a complete state plan the 

Administrator will have six months after the date required for 

submission to approve or disapprove the request. 

§ 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 EPA for the state. The Federal plan is an interim action and 

will be automatically withdrawn when your state plan is 

approved. 

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

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

obligations? 

 No. 
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§ 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, 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 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] 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 paragraphs (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. 

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)(1011) of this section in your state plan. 
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(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 emissionsemission

performance level for affected entities that will be achieved 

through implementation of the plan, during the plan performance 

period. 

(i) The identified plan must specify the average emissions 

performance levelthat 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 emissionsemission

performance goalgoals in Table 1 of this Subpart for affected 

entities in your state. The emissionsemission performance levels 

may be in either a rate-based form or a mass based form which is 
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calculated according to § 60.5770. The CO2 emissionsemission

performance level specified must include either of the following 

as applicable: 

(aA) For a rate-based CO2 emissionsemission 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, on average, during the plan 

performance period, including identification of any increments 

of performance that will be achieved within the plan performance 

period. 

(bB) For a mass-based CO2 emissionsemission performance 

level, the identified level of performance must represent the 

total tons of CO2 that will be emitted by affected entities 

during theeach plan performance period, including identification 

of any increments of performance that will be achieved within 

the . 

(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 emissionsemission performance levels for 

affected entities according to § 60.5740paragraph (a)(3).) of 

this section.
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(5) Identification of emissionsemission standards for each 

affected entity, compliance periodperiods for each 

emissionsemission standard, and demonstration that the 

emissionsemission standards are, when taken together, 

sufficiently protective to meet the state emissions performance 

level. 

(6) A demonstration that each emissionsemission standard is 

quantifiable, surplusnon-duplicative, permanent, verifiable, and 

enforceable with respect to an affected entity. 

(7(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 
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§ 60.5775(c)(1), and a process and schedule for implementing 

such corrective measures. 

(8) Identification of applicable monitoring, reporting, and 

recordkeeping requirements for each affected entity. If 

applicable, these requirements must be consistent with the 

requirements specified in § 60.5810.

(89) Description of the process, contents, and schedule for 

annual state reporting to the EPA about plan implementation and 

progress including information required under § 60.58205815. 

(910) 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. 

(1011) 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 

emissionsemission performance goal, calculated pursuant to § 

60.5770, if applicable; and 
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(iiii) Materials necessary to support evaluation of the 

plan by EPA. 

(b) You must follow the requirements of subpart B of this 

part (Adoption and Submittal of state plans for Designated 

Facilities) and demonstrate that they were met in your state 

plan. 

§ 60.5745 Can I work with other states to develop a multi-state 

plan? 

 (a) 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: 

(b) 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 
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performance period; or 

(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. 

(c) 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: 

 (i) 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 

(ii) 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) (a) 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 letter, the 

state must 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, listed in paragraph (b) of this section, by June 30, 

2016. 

(b) You must include the following required elements in an 

initial submittal in lieu of a complete state plan if your 

request for extension in paragraph (a) of this section has been 

approved: 

(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 emissionsemission

performance that will be achieved by affected EGUs under the 

complete plan; 
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(3) A commitment by the state to maintain existing state 

programs and measures that limit or avoid CO2 emissions from 

affected EGUs, which must at a minimum apply during the interim 

period prior to state submission and EPA approval of a complete 

plan, and must continue to apply in lieu of a complete plan if 

one is ultimately not submitted and approved; 

(4) Justification of why additional time is needed to 

submit a complete plan; 

(5) A comprehensive roadmap for completing the plan, 

including process, analytical methods and schedule (including 

milestones) specifying when all necessary plan components will 

be complete (e.g., projection of emissionsemission 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 
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addressing incomplete plan components prior to submittal of the 

complete plan. 

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

goals? 

(a) The annual average state rate-based CO2

emissionsemission performance goals for the planinterim

performance periods of 2020 through 2029, and inthe final 2030 

and thereafter period are respectively listed in Table 1 of this 

Subpart. The state rate-based CO2 emissionsemission performance 

goal may be converted to a mass-based emissionsemission

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 

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: 
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(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)(10). 

(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)(10). 

(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 

under the plan. 

(c) Your state plan must show that it will achieveFor the 

state emissions performance level by end of the interim 

performance period of 2020-2029 your state must meet the 

requirements in paragraphs (c)(1) and as well as at (c)(2) of 

this section 
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 (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. Additionally you must include 

provisions to demonstrate progress toward the state for every 

2-rolling calendar years starting January 1, 2020 and ending in 

2028 (i.e. 2020-2022, 2021-2023, 2022-2024, 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 

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 emissionsemission
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standard(s) that are quantifiable, verifiable, surplusnonduplicative, permanent, and enforceable with respect to each 

affected entity. The plan shall include the methods by which 

each emissionsemission standard meets each of the following 

requirements in paragraphs (b)-(f). 

(b) An emissionsemission standard is quantifiable with 

respect to an affected entity if it can be reliably measured, in 

a manner that can be replicated. 

(c) An emissionsemission 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 emissionsemission

standard. 

(d) An emissionsemission standard is surplusnon-duplicative

with respect to an affected entity if it is not already 

incorporated as an emissionsemission standard in another state 

plan unless incorporated in multi-state plan.

(e) An emissionsemission standard is permanent with respect 

to an affected entity if the emissionsemission standard must be 

met for each compliance period, or unless it is replaced by 

another emissionsemission 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 
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necessary for the state to meet its state level of performance. 

(f) An emissionsemission 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 emissionsemission performance goal set in § 60.5765 a 

request may be submitted to the Administrator indicating the 

proposed corrections to the state plan to ensure the 

emissionsemission 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? 
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(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 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, 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 [DATE OF PROPOSED RULE PUBLICATION IN 

THE FEDERAL REGISTER] reaches compliance with all the provisions 

of this subpart. 

§ 60.5795 What affected EGUs must I address in my state plan? 

The EGUs that must be addressed by your state plan are any 

affected steam generating unit, IGCC, or stationary combustion 

turbine that commences construction before [DATE OF PROPOSED 

RULE PUBLICATION IN THE FEDERAL REGISTER] 

§ 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 after the subpart TTTT applicability 

date and 2) those subject to subpart TTTT as a result of 

commencing modification or reconstruction prior to the submittal 

ofEPA approving the applicable state plan. 
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§ 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 

emissionsemission 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, 

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 
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certification and quality assurance procedures in § 75.20 of 

this chapter and Appendices B and D to part 75 of this chapter. 

(iii) An affected EGU must use a laser device to measure 

the dimensions of each exhaust gas stack or duct at the flow 

monitor and the reference method sampling locations prior to the 

initial setup (characterization) of the flow monitor. For 

circular stacks, an affected EGU must measure the diameter at 

three or more distinct locations and average the results. For 

rectangular stacks or ducts, an affected EGU must measure each 

dimension (i.e., depth and width) at three or more distinct 

locations and average the results. If the flow rate monitor or 

reference method sampling site is relocated, an affected EGU 

must repeat these measurements at the new location. 

(iv) An affected EGU must use only unadjusted exhaust gas 

volumetric flow rates to determine the hourly CO2 mass emissions 

from the affected facility; an affected EGU must not apply the 

bias adjustment factors described in section 7.6.5 of Appendix A 

to part 75 of this chapter to the exhaust gas flow rate data. 

(v) If an affected EGU chooses to use Method 2 in Appendix 

A-1 to this part to perform the required relative accuracy test 

audits (RATAs) of the part 75 flow rate monitoring system, they 

must use a calibrated Type-S pitot tube or pitot tube assembly. 

An affected EGU must not use the default Type-S pitot tube 

coefficient. 
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(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. 

(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. 

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. 
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(5) In accordance with § 60.13(g), if two or more affected 

EGUs that implement the continuous emissions monitoring 

provisions in paragraph (a)(2) of this section share a common 

exhaust gas stack and are subject to the same emissions 

standard, they may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

affected EGU chooses this option, the hourly net electric output 

for the common stack must be the sum of the hourly net electric 

output of the individual affected facility and you must express 

the operating time as “stack operating hours” (as defined in § 

72.2 of this chapter). 

(6) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU that implements the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), they must monitor 

the hourly CO2 mass emissions and the “stack operating time” (as 

defined in § 72.2 of this chapter) at each stack or duct 

separately. In this case, an affected EGU must determine 

compliance with an applicable emissions standard by summing the 

CO2 mass emissions measured at the individual stacks or ducts and 

dividing by the net energy output for the affected EGU. 
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(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 

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 eachthe 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 goalsgoal. 
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(b) States must keep records of all data submitted by each 

affected entity that is used to determine compliance with each 

affected entity’s emissions standard. 

(c) If a state has a requirement for hourly CO2 emissions 

and net generation information to be used to calculate 

compliance with an annual emissions standard for affected EGUs, 

any information that is submitted to the EPA electronically 

pursuant to requirements in Part 75 would meet the recordkeeping 

requirement of this section and a state would not need to keep 

records of information that would be in duplicate of paragraph 

(b) of this section. 

(d) A state must keep records at minimum for 20 years. 

§ 60.5815 What are my state reporting requirements? 

(a) You must submit aan annual report covering each 

calendar year no later than 60 days after completing each annual 

performance period as defined in your state plan regarding 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. 
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(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. 

 (23) A list of affected entities and their compliance 

status with the applicable emissions standards specified in the 

state plan. 

(34) A list of all affected EGUs and their reported CO2

emissions performance for each compliance period during the 

reporting period, and prior reporting periods. 

 (35) All other required information, as specified in your 

state plan according to §60.5740(a)(8).9). 

 (6) All information required by § 60.5775(e). 

(b) For each two-year period in § 60.5775(c)(1), you must 

compare the CO2 emission performance achieved by affected EGU 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 
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performance in the plan will be met. The information required in 

this paragraph must be included in the annual report required by 

paragraph (a) of this section. 

 (c) You must include in your 2029 annual report (which is 

subsequently due by July 1, 2030) the calculation of average 

emissions over the 2020-2029 interim performance period used to 

determine compliance with your interim emission performance 

level. The calculated value must be in units consistent with 

your interim emission performance level. 

(d) You must include in each report, starting with the 2032 

annual report (which is subsequently due by July 1, 2033), a 3-

calendar year rolling average used to determine compliance with 

the final emission performance level. The calculated value must 

be in units consistent with your final emission performance 

level. 

Definitions 

§ 60.5820 What definitions apply to this subpart? 

As used in this subpart, all terms not defined herein will 

have the meaning given them in the Clean Air Act and in subparts 

A (General Provisions of this part) and B. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, an IGCC facility, or a stationary 
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combustion turbine that serves a generator capable of selling 

greater than 25 MW to a power distribution system. 

Affected Entity shall mean any of the following: an 

affected EGU, or another entity with obligations under this 

subpart for the purpose of meeting the emissions performance 

goal requirements in these emission guidelines. 

Base load rating means the maximum amount of heat input 

(fuel) that a steam generating unit can combust on a steady 

state basis, as determined by the physical design and 

characteristics of the steam generating unit at ISO conditions. 

For a stationary combustion turbine, base load rating means 100 

percent of the design heat input capacity of the simple cycle 

portion of the stationary combustion turbine at ISO conditions 

(heat input from duct burners is not included). 

CO2 emissions performance goal means the rate-based CO2

emissions performance goal specified for a state in Table 1 of 

this subpart, or a translated mass-based form of that goal. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

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

turbine to simultaneously produce both electric (or mechanical) 

and useful thermal energy 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.

Distillate oil means fuel oils that contain no more than 

0.05 weight percent nitrogen and comply with the specifications 

for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by 

reference, see § 60.17); diesel fuel oil numbers 1 and 2, as 

defined by the American Society for Testing and Materials in 

ASTM D975 (incorporated by reference, see § 60.17); kerosene, as 
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defined by the American Society of Testing and Materials in ASTM 

D3699 (incorporated by reference, see § 60.17); biodiesel as 

defined by the American Society of Testing and Materials in ASTM 

D6751 (incorporated by reference, see § 60.17); or biodiesel 

blends as defined by the American Society of Testing and 

Materials in ASTM D7467 (incorporated by reference, see § 

60.17). 

Emission performance level in a state plan means the level 

of emissions performance for affected entities specified in a 

state plan, according to § 60.5745. 

Emission standard means in addition to the definition in § 

60.21, any requirement applicable to any affected entity other 

than an affected source that has the effect of reducing 

utilization of one or more affected sources, thereby avoiding 

emissions from such sources, including, for example, renewable 

energy and demand-side energy efficiency measures requirements. 

Excess emissions means a specified averaging period over 

which the CO2 emissions rate is higher than an applicable 

emissions standard or an averaging period during which an 

affected EGU is not in compliance with any other emission 

limitation specified in an emission standard. 

Existing state program, requirement, or measure means, in 

the context of a state plan, a regulation, requirement, program, 

or measure administered by a state, utility, or other entity 
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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 

facility means a combined cycle facility that has a base load 

rating heat inputfor fossil fuel of greater than 73 MW (250 

MMBtu/h), that supplieswas constructed for the purpose of supplying 

more than one-third or more of its potential electric output and 
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more than 219,000 MWh net-electric output to a utility 

distribution system on an annual basis and 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 energy, 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). Measurements must 

be performed using 0.2 accuracy class electricity metering 

instrumentation and calibration procedures as specified under 

ANSI Standards No. C12.20. 

Net energy output means: 

(1) the net electric or mechanical output from the affected 

facility, plus 75 percent of the useful thermal output measured 
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relative to ISO conditions that is not used to generate 

additional electric or mechanical output or to enhance the 

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

process for a heating application). 

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

20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross energy output consists of 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 ISO 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). 

Oil means crude oil or petroleum or a fuel derived from 

crude oil or petroleum, including distillate and residual oil, 

and gases derived from solid oil-derived fuels (not meeting the 

definition of natural gas). 

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. 

Stationary combustion turbine means all equipment, 
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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) that has a base load rating 

heat inputfor fossil fuel of greater than 73 MW (250 MMBtu/h) 

and that supplieswas constructed for the purpose of supplying 

more than one-third or more of its potential electric output and 

more than 219,000 MWh net-electric output to a utility 

distribution system on an annual basis plus any integrated 
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equipment that provides electricity or useful thermal output to 

the affected facility or auxiliary equipment. 

Thermal output for this subpart means the energy in 

recovered thermal output measured against the energy in the 

thermal output at ISO conditions. 

Useful thermal output means the thermal energy made 

available for use in any industrial or commercial process, or 

used in any heating or cooling application, i.e., total thermal 

energy made available for processes and applications other than 

electric generation, mechanical output at the affected facility, 

or to directly enhance the performance of the affected facility 

(e.g., thermal energy used to reduce fuel moisture is considered 

useful thermal output). 
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6560-50-P 

EO12866_GHG EGU ExistingSources 2060-AR33 Proposal_20140328 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

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

RIN 2060-AR33 

Carbon Pollution Guidelines for Existing Power Plants: 

Emission Guidelines for Greenhouse Gas Emissions from 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 would continue progress already 

underway to reduce carbon dioxide emissions from the electric 

power sector in the United States.

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

on or before [INSERT THE DATE 60 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. Public hearings will be held on [INSERT 

DATES HERE], at [INSERT LOCATIONS HERE]. The hearings will 

convene at [INSERT TIME] and end at [INSERT TIME]. Please 

contact [add name] at [phone#] or at xxx.xxx@epa.gov] to 

register to speak at one of the hearings. The last day to preregister in advance to speak at the hearing will be [INSERT DATE 

HERE]. Additionally, requests to speak will be taken the day of 

the hearing 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 hearing 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 
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speakers who arrive and register. Because this hearing is 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 

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. Written comments on the proposed rule must 

be postmarked by [INSERT DATE HERE]. Commenters should notify

[ADD NAME] if they will need specific equipment, or if there are 

other special needs related to providing comments at the 

hearing. The EPA will provide equipment for commenters to show 

overhead slides or make computerized slide presentations if we 

receive special requests in advance. Oral testimony will be 
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limited to 5 minutes for each commenter. The EPA encourages 

commenters to provide the EPA with a copy of their oral 

testimony electronically (via email or CD) or in hard copy form. 

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 hearing to 

run either ahead of schedule or behind schedule. Information 

regarding the hearing (including information as to whether or 

not one will be held) 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: 

At the website http://www.regulations.gov: Follow the 

instructions for submitting comments. 

At the website http://www.epa.gov/oar/docket.html: Follow 

the instructions for submitting comments on the EPA Air and 

Radiation Docket website. 

Email: Send your comments by electronic mail (email) to aand-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. 

Facsimile: Fax your comments to (202) 566-9744, Attn: 

Docket ID No. EPA-HQ-OAR-2013-0602. 

Mail: Send your comments to the EPA Docket Center, U.S. 
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EPA, Mail Code 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0602. 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 Delivery or Courier: Deliver your comments to the EPA 

Docket Center, William Jefferson Clinton Building West, Room 

3334, 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 

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 
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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 

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 
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Page 7 of 584

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 

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 
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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) through the Technology Transfer Network (TTN). 

Following signature, a copy of the proposed rule will be posted 

on the TTN’s policy and guidance page for newly proposed or 

promulgated rules at the following address: 

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

FOR FURTHER INFORMATION CONTACT: [ADD CONTACTS] 

SUPPLEMENTARY INFORMATION: [INSERT TEXT, AS APPROPRIATE]

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 
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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 

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 
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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 

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
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A. Authority to Regulate Carbon Dioxide 

B. Authority to Regulate EGUs 

C. Affected Sources 

D. Combined Categories and Codification in the Code of Federal 

Regulations 

VI. Building Blocks for Setting State Goals and Considerations 

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 

E. Overview 

F. Approach 

G. Criteria for Approving State Plans 

H. State Plan Components 

I. Process for State Plan Submittal and Review

J. State Plan Considerations

K. Additional Factors That Can Help States Meet Their CO2

Emission Performance Goals

L. 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. Comparision 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 goals? 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 
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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 use in 

developing plans to address greenhouse gas (GHG) emissions from 

existing fossil fuel-fired electric generating units (EGUs). In 

this summary, we broadly outline the proposal; discuss its 

purpose; summarize its major provisions, including its approach 

to determining goals; describe flexibilities available to 

states, including timing requirements both for states to submit 

plans and for EGUs to meet obligations under those plans; and 

briefly describe the estimated CO2 emission reductions, costs and 

benefits expected to result from full implementation of the 

proposal. 
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This rule, as proposed, would continue progress already 

underway to lower the carbon intensity of power generation in 

the United States. The proposal incorporates critical elements 

that reflect the information and views shared during the 

unprecedented effort that the EPA has undertaken, beginning in 

the summer of 2013, to interact directly with and solicit input 

from a wide range of states and stakeholders. This effort 

encompassed several hundred meetings across the country with 

state environmental and energy officials, public utility 

commissioners, system operators, utilities and public interest 

advocates, as well as members of the public. A great 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 emissions levels in 2005. This goal is within reach 

because innovations in the production, distribution and use of 

electricity are already making the power sector more efficient 

and sustainable while maintaining a diverse energy mix. This 

proposed rule would reinforce and continue this progress. The 

EPA projects that, in 2030, this rule will lead to meaningful 

reductions in harmful carbon pollution resulting in net climate 

and health benefits of $47 billion to $78 billion. At the same 
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time coal and natural gas will remain the two dominant sources 

of electricity generation in the U.S. with each providing more 

than 30 percent of the projected generation. 

The proposed guidelines also reinforce the steps already 

being taken by states and utilities to upgrade aging electricity 

infrastructure with 21st century technologies and ensure that 

these trends continue in ways that are consistent with the longterm planning and investment processes already used in this 

sector. The proposal provides flexibility for states to build 

upon their progress in addressing GHGs and allows them to pursue 

policies to reduce carbon pollution that: 1) continue to rely on 

a diverse set of energy resources, 2) ensure electric 

reliability, 3) provide affordable electricity and, 4) recognize 

investments that states and power companies are already making. 

The proposal has two main elements: 1) state-specific 

goals for reductions from power plants and 2) guidelines 

for the elements needed for a state plans to be approved 

when they are submitted to the EPA for review as required 

under section 111(d). To set the state-specific 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 
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plants, programs that enhance the dispatch priority of low 

emitting and renewable power sources, and programs that 

help homes and businesses use electricity more efficiently. 

While this proposal lays out state-specific goals, it 

does not prescribe how a state should meet those goals. The 

Clean Air Act and EPA’s implementing regulation authorize 

the EPA to set these goals, and rely on states to take the 

lead on meeting them by creating a plan that is consistent 

with the EPA’s guidelines. This approach ensures that each 

state will have the flexibility to design a program to meet 

its goal in ways that reflects its particular circumstances 

and policy objectives. Each state can do so e alone or can 

collaborate with other states on multi-state or regional 

plans that may provide additional opportunities for cost 

savings and flexibility. 

To facilitate the state planning process, this 

proposal lays out the components of a state plan to meet 

the goal, the latitude states have in developing compliance 

strategies, the flexibility they have in the timing for 

submittal of their plans and the flexibility states have in 

determining the schedule by which their sources must 

achieve the reductions required under state plans. The EPA 

recognizes that each state has different state policy 
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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 

flexible manner that accommodates a diverse range of state 

approaches. This proposal also gives states considerable 

flexibility with respect to the timeframes for plan 

development and implementation, providing up to two or 

three years for submission of final plans after the 

proposed emission rate guidelines are finalized and 

providing up to fifteen years for full implementation of 

all emission reduction measures. 

The EPA believes that this proposal, which employs the 

flexibilities inherent in CAA section 111(d), will provide 

states with ample opportunity to design plans that use 

innovative, cost-effective regulatory strategies and that 

take advantage of the investments already being made in 

programs and measures that lower the carbon intensity of 

the power sector and thus reduce GHG emissions that cause 

harmful climate change. 
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a. Policy context and industry conditions 

This proposal is an important step toward achieving the 

emissions reductions needed to address the serious threat of 

climate change. GHG pollution threatens the health and welfare 

of the American public by leading to potentially rapid and long 

lasting changes in our climate that can have a range of severe 

negative effects on human health and the environment. CO2 is the 

primary GHG pollutant, accounting for nearly three-quarters of 

global GHG emissions and over 77 percent of U.S. GHG emissions. 

The President’s Climate Action Plan,1 issued in June 2013, 

recognizes that climate change comes with 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 Memorandum2

 directing 

 

1

 The President’s Climate Action Plan, June 2013. 

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

climateactionplan.pdf 
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the EPA to complete carbon pollution standards, regulations or 

guidelines, as appropriate, for new, modified, reconstructed and 

existing power plants, and to build on state leadership to move 

toward a cleaner power sector. 

Advancements in innovative power sector technologies, in 

the availability and cost of low carbon fuel, and in energy 

efficient demand-side technologies, as well as economic 

conditions, are already changing the way power is produced, 

distributed and used. In addition, the average age of the coalfired 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 under way 

between now and 2030, a CAA section 111(d) rulemaking for CO2

emissions can inform current and ongoing decision making by 

states and utilities while prompting states to develop and 

 2

 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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implement plans that will reduce GHG emissions and lower the 

carbon intensity of the power sector, while ensuring a reliable 

supply of power at a reasonable cost. The proposed guidelines 

are designed to build on and reinforce progress by states and 

companies on a growing variety of sustainable strategies to 

reduce power sector CO2 emissions. At the same time, the EPA 

believes that this proposal provides flexibility for states to 

develop plans that can be crafted for their individual and 

unique circumstances and that can be aligned with their other 

environmental policy and energy and economic goals. All states 

will have the flexibility to shape compliance plans as they 

believe appropriate for meeting the proposed CO2 reduction goals. 

This includes states such as Kentucky, West Virginia and 

Wyoming, with long-established reliance on coal-fired 

generation, as well as states such as Washington and Oregon 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 AB 32, and Colorado’s “Clean Air, Clean Jobs Act”. 

To make plans to reduce CO2, states can rely on and extend 

programs they may already have created to address the power 

sector. Those states committed to Integrated Resource Planning 
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(IRP) would be able to establish their CO2 reduction plans within 

that framework. Similarly, states with a more deregulated power 

sector system can develop CO2 reduction plans within that 

framework. At the same time, states would also be able to 

address the economic interests of their utilities and ratepayers 

by using the flexibilities in this proposed action: 1) to reduce 

costs and minimize stranded assets, and 2) to 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 provides a broad 

range of compliance options for a wide and 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 municipallyowned utilities. 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. 

b. CAA section 111(d) requirements 

Under CAA section 111(d)3

 state plans must establish 

standards of performance that reflect the degree of emission 

 

3

 See also 40 CFR 60.22(b)(5).
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limitation achievable through the application of the “best 

system of emission reduction 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 (BSER).4

 Consistent 

with CAA section 111(d), the EPA is proposing state-specific 

goals that reflect the EPA’s calculation of the emission 

reductions that the states 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 to the affected EGUs in each state. . A CAA 

section 111(d) state plan will differ from a state 

implementation plan (SIP) for a criteria air pollutant national 

ambient air quality standard (NAAQS) in several respects, 

 

4

 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; and the state is 

authorized to identify the standard(s) 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. 
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reflecting the significant differences between CAA sections 110 

and 111. A CAA section 110 SIP must be designed to meet a 

specific ambient air quality level -- the NAAQS for the criteria 

air pollutant -- for a particular area (not for a source 

category) within a timeframe specified in the CAA, and the 

NAAQS, in turn, is based on the current body of scientific 

evidence and, by law, does not reflect consideration of cost. A 

CAA section 111(d) state plan must be designed to meet a level 

specific to emissions from 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 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. These measures fall into four main 

categories or “building blocks.” Overall, the BSER proposed here 

is based on a range of measures that comprise improved 

operations at EGUs, dispatching lower-emitting EGUs and zeroemitting energy sources, and end use energy efficiency, all of 

which have been amply demonstrated via their current widespread 
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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 BSER or to 

apply any one of those measures to the same extent that the 

EPA determines is achievable and cost-effective with 

respect to that measure. 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 

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 necessary to meet its goal. 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 key assumptions, the methodology, and the 

specific data used to calculate the state-specific CO2

goals, and on the broad flexibilities provided to meet the 

goals and ensure states the necessary tools to address any 

distinctive circumstances (such as the remaining useful 
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life of certain EGUs) without adjusting the underlying 

targets. 

This proposed rule sets forth the state goals that 

reflect 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 BSER, as well 

as state goals and the states’ responsibility to develop 

and implement standards of performance consistent with 

BSER. Additional detail on various aspects of the proposal 

is included in several technical support documents (TSDs), 

which are available in the rulemaking docket. The proposal 

was substantially informed by the extensive input from 

states and a wide range of stakeholders that the EPA sought 

and has received since the summer of 2013. The EPA invites 

comment on all aspects of this proposal. 

2. Summary of the major provisions 

a. Approach 

In developing this proposed rulemaking, the EPA is 

implementing 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 
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previous CAA section 111(d) rulemakings since then. These 

provisions ensure that, in concert with the provisions of CAA 

sections 110 and 112, new and existing major stationary sources 

address 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 BSER, for states to follow in formulating compliance plans to 

implement standards of performance to achieve emissions 

reductions consistent with 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 in 

the power sector.5

 

The CAA, as interpreted by the courts, identifies several 

factors for the EPA to consider in a BSER determination: 

technical feasibility, costs, size of emission reductions and 

technology (i.e., whether the system promotes the implementation 

and further development of technology). To determine BSER, the 

EPA considered the reductions achievable through measures that 

 

5

 The final emission guidelines for landfill gas emissions from 

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

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

respectively), allow either of two approaches for controlling 

landfill gas – by recovering the gas as a fuel, for sale, and 

removing from the premises, or by destroying the organic content 

of the gas on the premises using a control device. Recovering 

the gas as a fuel source was a practice already being used by 

some affected sources prior to promulgation of the rulemaking.
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reduce CO2 emissions from existing fossil fuel-fired EGUs either 

by reducing the CO2 emission rate at those units or by reducing 

the units’ CO2 emission total by shifting generation from higheremitting fossil fuel-fired EGUs to lower- or zero-emitting 

options (including both low- or zero-emitting generation and 

demand-side energy efficiency). As the EPA has done in making 

BSER determinations in the past, the agency considered the types 

of strategies that states and operators are already employing to 

reduce the covered pollutant (in this case, CO2) from affected 

sources (in this case, fossil fuel-fired EGUs). For this 

pollutant and source category, many states and companies are 

already taking action to reduce GHGs. For example, currently 10 

states have market-based GHG emission programs, 29 states have 

implemented renewable portfolio standards, and utilities in 48 

states run demand-side energy efficiency programs. Many 

individual companies also have significant voluntary GHG 

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 are 

undertaken in ways that accommodate reductions in both pollution 

emissions rates and total emissions. Specifically, electricity 

production, at least to some extent, takes place interchangeably 

between and among multiple generation facilities and different 
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types of generation, a fact that Congress, the EPA and the 

states have long since relied on in enacting or promulgating 

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 the most 

cost-effective 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. 

To determine BSER for reducing CO2 emissions at 

affected EGUs, and to establish the numerical goals that 

reflect BSER, the EPA considered numerous measures that can 

and are being implemented to improve emission rates and to 

reduce or limit mass CO2 emissions from fossil fuel-fired 

EGUs. These measures encompass two basic approaches: 1) 

reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 
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addressing affected EGUs’ mass emissions by varying their 

utilization levels. For purposes of expressing BSER as an 

emissions limitation, in this case in the form of statelevel goals, we propose to group these measures 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 fuelfired 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 carbonintensive affected EGUs in the amount that results 

from substituting generation at those EGUs with 

generation from less carbon-intensive affected EGUs 

(including NGCC units under construction). 
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3. Reducing emissions from affected EGUs in the 

amount that results from substituting generation at 

those EGUs with expanded generating low- or zerocarbon generation. 

4. Reducing emissions from affected EGUs in the 

amount that results fromthe use of demand-side energy 

efficiency that reduces the amount of generation 

required. 

The four building blocks are described in detail in 

Sections VI and VII of this preamble. As those sections 

explain, while the EPA found that each of the building 

blocks met the attributes of BSER, combining all four 

blocks best represents BSER because it achieves greater 

emission reductions, is more cost effective and takes 

better advantage of the wide range of measures already in 

use at the state and company level to reduce CO2 from EGUs. 

Those sections also explain how the EPA considered more 

aggressive application of measures in each block. This 

includes consideration of options in some blocks that the 

EPA determined not to represent BSER for existing sources 

(such as the inclusion of retrofit carbon capture and 

storage or sequestration (CCS) on existing units), as well 

as consideration of more aggressive application of measures 
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that the EPA determined do represent a component of BSER 

(such as more aggressive application of demand-side 

measures). While the EPA made these determinations by 

applying the BSER factors to each measure, the EPA also 

considered the impacts of combining each of the measures 

into a unified BSER. 

As part of the BSER determination, the EPA considered 

the impacts that implementation of the emission reductions 

required by the combination of the blocks would have on the 

cost of electricity and on system reliability. As the 

preamble details, the EPA believes that, both individually 

and in combination, the costs associated with the BSER we 

are proposing today are reasonable. Importantly, the 

proposed BSER, expressed as a numeric goal for each state, 

provide states with the flexibility to determine how to 

achieve the reductions (i.e., greater reductions from one 

building block and less from another) and to adjust the 

timing in which reductions are achieved, in order to 

address key issues such as cost to consumers, reliability 

and “remaining useful life.” 

In sum, the EPA believes that the BSER for purposes of 

CAA section 111(d), as applied to the sources in the power 

sector, is a combination of measures that reduce CO2
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emissions and CO2 emission rates and reflect or encompass 

all four building blocks. A range of amounts of reductions 

can be achieved by application of each building block. In 

determining BSER, we have considered these ranges, in light 

of statutory factors, and we have identified goals that we 

believe best satisfy those 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 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 meaningful, and 

technically feasible reductions of CO2 at a reasonable cost, 

while also promoting technology and approaches that are 

important for achieving further reductions, all while 

providing the states with a balance of flexibility and 

direction. Finally, the EPA believes that the inherent 

flexibility of the measures encompassed in the four 

building blocks reinforces the inherent flexibility of the 

current electricity system operations and the system’s 
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capacity to deliver affordable and reliable electricity 

because these measures rely on the flexibility of the 

electricity system itself. 

In addition to proposing the four building blocks as 

the basis for BSER, the EPA is also soliciting comment on 

application of only the first two building blocks as BSER, 

while noting that application of only the first two 

building blocks achieves fewer CO2 reductions at a higher 

cost. 

The EPA recognizes that states differ in important 

ways, including in their mix of existing EGUs and in the 

policy priorities that they are pursuing. Consequently, 

opportunities and preferences for reducing emissions, as 

reflected in each of the building blocks, vary across 

states. While the state-specific goals that the EPA is 

proposing in this rule are based on consistent application 

of a goal setting methodology across all states, they are 

designed to account for these key differences. The statespecific CO2 reduction requirements and CO2 rate-based 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 
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of its electricity system (e.g., current mix of generation 

resources). 

This approach and incorporation of the measures in 

each of the building blocks reflect information provided 

and priorities expressed during the EPA’s recent, extensive 

public outreach process. These 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 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. They 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 plan. Further, this 

approach allows regional compliance strategies. The agency 
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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. Because, for its primary proposal, the EPA is 

proposing a 10-year period over which to achieve the full 

required CO2 reductions, a period that begins more than five 

years from the date of this proposal, a state could take 

advantage of this relationship in the design of its program 

by using relevant combinations of building blocks to 

achieve its state goal in a timely and cost-effective 

manner. 

b. State goals and flexibilities 

In this action, the EPA is proposing state-specific 

rate-based goals to guide states in the development of 

their plans. These state-specific goals are based on an 

assessment of the amount of emissions that can be reduced 

at high-emitting facilities through application of BSER, as 

contemplated and required under CAA section 111. The agency 

is proposing state-specific interim and final goals that 

must be achieved by no later than the year 2030. The 

proposed final goals reflect the EPA’s quantification of 

adjusted state-average emission rates from affected EGUs 

that could be achieved at reasonable cost by 2030 through 
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implementation of the four building blocks described above. 

The proposed interim goals would apply over a 2020-2029 

phase-in period. They reflect the level of reductions in CO2

emissions and emission rates and the extent of the 

application of the building blocks that would be 

presumptively approvable in a state plan during the ramp-up 

to achieving the final goal. 

The EPA is proposing to allow each state flexibility 

with regard to the form of the goal. Under this proposal, a 

state would not be obligated to adopt the rate-based form 

of the goal established by the EPA. A state plan submittal 

reflecting a mass-based form of the goal or a regional 

approach based upon either rate or mass would be approvable 

based upon a demonstration that the submittal is 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 
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reasonable balance between two competing objectives 

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

consistency in calculating emission reductions and a need 

for flexibility in establishing and implementing the 

standards of performance that reflect those emission 

reductions. The importance of this balance is heightened by 

the fact that the operations of the electricity system 

itself rely on the flexibility made available and achieved 

through dispatching between and among multiple 

interconnected EGUs, demand management and end use energy 

efficiency. We view the proposed goals as providing this 

rigor where required by the statute with respect to the 

amount of emissions reductions, while providing states with 

flexibility where permitted by the statute, particularly 

with respect to the development and implementation of 

performance standards and the overall compliance plans. 

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 more 
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sustainable system that puts greater reliance on renewable 

energy and energy efficiency. 

c. State plans 

i. Approach 

Each state will determine, and include in its plan, 

emissions 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 this 

level, 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 reductions. 

The plan must include a process for reporting on plan 

implementation, progress toward achieving CO2 goals, and 

implementation of corrective actions, if necessary. No less 
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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 use 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 regional approaches 

that can be achieved on either a rate or mass basis. They 

also address several key policy considerations that states 

will have 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 
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stakeholders that the EPA should authorize state plans to 

include a portfolio of actions that encompass a diverse set of 

programs and measures that achieve either a rate-based or massbased emission performance level for affected EGUs but that do 

not place legal responsibility for achieving the entire amount 

of the emission performance level on the affected EGUs. In view 

of this strong sentiment from stakeholders, the EPA is proposing 

that state plans that take this portfolio approach would be 

approvable, provided that they meet other key requirements such 

as achieving the required emission reductions over the 

appropriate timeframes. Plans that do directly assure that 

affected EGUs achieve all of the required emission reductions 

(such as the mass-based programs being implemented in California 

and the RGGI states) would also be approvable provided that they 

meet other key requirements, such as achieving the required 

emission reductions over the appropriate timeframes. 

ii. State plan components 

The EPA is proposing to evaluate and approve state 

plans based on four general criteria: 1) enforceable 

measures that reduce EGU CO2 emissions; 2) projected 

achievement of emission performance equivalent to the goals 

established by the EPA, on a timeline equivalent to that in 

the emission guidelines; 3) quantifiable and verifiable 
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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 C.F.R. 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 

In accordance with the President’s Climate Action 

Plan,6 the EPA expects to finalize this rulemaking by June 

1, 2015. The Climate Action Plan 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 rather than the 9 months specified 

 

6

 The President’s Climate Action Plan, June 2013, available at 

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

climateactionplan.pdf
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in the EPA framework regulations at 40 C.F.R. 60.23. 

However, the EPA recognizes that some states may need more 

than one year to develop a final state plan in order to 

provide sufficient time for technical work, state 

legislative and rulemaking schedules, 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 its plan 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 

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. To be approvable, the initial plan must include 

specific components, including a description of the plan 

approach, initial quantification of the level of emission 

performance that will be achieved in the plan, a commitment 

to maintain existing measures that limit CO2 emissions, and 

an explanation of the path to completion, as described in 

Section VIII.E of this preamble. 
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If the initial plan includes those components, the EPA 

will approve the initial plan and provide an extension of 

time to submit a complete plan. If given an extension, 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. However, if the state develops a plan that includes 

a multi-state approach, then 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, and the potential 

complexity of the plans the EPA anticipates receiving, the 

EPA is proposing to extend the period of the EPA review of 

plans from the four month period provided in the EPA 

framework regulations to a six month review and approval 

period. 

v. Timing of compliance 

 The agency is proposing that states must begin to make 

reductions by 2020 and achieve compliance with the CO2 emission 
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performance level in the state plan 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 would best support the 

optimization of overall CO2 reductions. The agency is also 

requesting comment on two alternative options. The first 

alternative option includes the addition of a required second 

submittal by each state in 2025 showing whether its plan 

measures would maintain the final emission performance level 

after 2030. The second alternative option is 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. 

The EPA is also 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 emission goal. Thus, states with 

existing programs and policies, and states that put in place new 
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programs and policies early, will be better positioned to 

achieve the goals. 

vi. 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..7

 

3. Projected national-level emission reductions 

Under the proposed guidelines, the EPA projects annual 

CO2 reductions of 26 to 30 percent below 2005 levels. 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). 

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 PM2.5, from the electric power 

industry. States will make the ultimate determination as to 

how the emission guidelines are implemented. Thus, all 

 

7 www2.epa.gov/carbonpollutionstandardstoolbox
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costs and benefits reported for this action are 

illustrative estimates. 

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.8

 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 $15 billion to $34 billion using a 3 percent 

discount rate and $13 billion to $31 billion (2011$) using a 7 

percent discount rate relative to the 2020 base case. The annual 

compliance costs are estimated using the Integrated Planning 

Model (IPM) and include demand-side energy efficiency program 

and participant costs as well as monitoring and reporting costs. 

 

8

 The EPA has used the U.S. government’s social cost of carbon 

(USG 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 USG 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 by the USG: the model average at 3 percent discount 

rate. 
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Total compliance costs of this proposal are approximately $5.4 

billion (2011$) in 2020. The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2020 are estimated to be $26 billion to $46 billion (2011$) 

using a 3 percent discount rate (model average). 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 $24 to $55 

billion (3 percent discount rate) and $21 to $50 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 $47 billion 

to $78 billion (3 percent discount rate model average, 2011$) 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), rather than collaboratively the climate 

benefits in 2020 are expected to be approximately $18 billion (3 

percent discount rate, model average, 2011$). Health co-benefits 

are estimated to be $15 to $36 billion (3 percent discount rate) 

and $14 to $33 billion (7 percent discount rate). Net benefits 
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are estimated to range from $26 to $46 billion (3 percent model 

average discount rate, 2011$). Climate benefits are 

approximately $31 billion in 2030 using a 3 percent discount 

rate (model average, 2011$) relative to the 2030 base case 

assuming a state compliance approach. Health co-benefits are 

estimated to be approximately $25 to $58 billion (3 percent 

discount rate) and $23 to $53 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 $47 to $80 billion (3 percent discount rate, 

2011$) assuming a state compliance approach. 

There are additional important benefits that the EPA 

could not monetize. These unquantified benefits include 

climate benefits from reducing emissions of non-CO2

greenhouse gases (e.g., nitrous oxide and methane)9

 and cobenefits from reducing direct exposure to SO2, NOx and 

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

 

9 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
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chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

Based upon the foregoing, it is clear that the monetized 

benefits of this proposal are substantial and far outweigh the 

costs. 

B. Organization and Approach for this Proposed Rule 

This action presents the EPA’s proposed emission guidelines 

for states to consider in developing plans to reduce GHG 

emissions from the electric power sector. Section II provides 

background on climate change impacts from GHG emissions, GHG 

emissions from fossil fuel-fired EGUs and the utility power 

sector and CAA section 111(d) requirements. Section III presents 

a summary of the EPA’s stakeholder outreach efforts, key 

messages provided by stakeholders, state policies and programs 

that reduce GHG emissions, and conclusions. In Section IV of the 

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

legal basis for these, followed by identification of affected 

sources and the proposed treatment of source categories in 

Section V. 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 

goals and the proposed requirements for state plans, 

respectively. Implications for the new source review and Title V 
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programs and potential interactions with other EPA rules are 

described in Section IX. Impacts of the proposed action are then 

described in Section X, followed by a discussion of statutory 

and executive order reviews in Section XI and the statutory 

authority for this action in Section XII. 

We note that this rulemaking overlaps in certain respects 

with two other related rulemakings: the January 2014 proposed 

rulemaking that the EPA published on January 8, 2014 for CO2

emissions from newly constructed affected sources10, 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. 

 

10 79 FR 1430
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A. Climate Change Impacts from GHG Emissions

In 2009, the EPA Administrator issued the document known as 

the Endangerment Finding under CAA section 202(a)(1).11 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 

Finding12

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, 

 

11 “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”).

12 “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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climate change is expected to increase ozone pollution over 

broad areas of the U.S., including in the largest metropolitan 

areas with the worst ozone problems, and thereby increase the 

risk of morbidity and mortality. Other public health threats 

also stem from projected increases in intensity or frequency of 

extreme weather associated with climate change, such as 

increased hurricane intensity, increased frequency of intense 

storms, and heavy precipitation. Increased coastal storms and 

storm surges due to rising sea levels are expected to cause 

increased drownings and other health impacts. Children, the 

elderly, and the poor are among the most vulnerable to these 

climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding13

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 

 

13 “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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rising sea level, such as land loss due to inundation, erosion, 

wetland submergence and habitat loss. Climate change is expected 

to result in an increase in peak electricity demand, and extreme 

weather from climate change threatens energy, transportation, 

and water resource infrastructure. Climate change may exacerbate 

ongoing environmental pressures in certain settlements, 

particularly in Alaskan indigenous communities. Climate change 

also is very likely to fundamentally rearrange U.S. ecosystems 

over the 21st century. Though some benefits may balance adverse 

effects on agriculture and forestry in the next few decades, the 

body of evidence points towards increasing risks of net adverse 

impacts on U.S. food production, agriculture and forest 

productivity as temperature continues to rise. These impacts are 

global and may exacerbate problems outside the U.S. that raise 

humanitarian, trade, and national security issues for the U.S. 

3. New scientific assessments 

As outlined in Section VIII.A. of the 2009 Endangerment 

Finding, the EPA’s approach to providing the technical and 

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

assessments by the U.S. Global Change Research Program (USGCRP), 

the Intergovernmental Panel on Climate Change (IPCC), and the 
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National Research Council (NRC) of the National Academies. These 

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. Since the 

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 

such assessments have been released. These assessments include 

the IPCC’s 2012 “Special Report on Managing the Risks of Extreme 

Events and Disasters to Advance Climate Change Adaptation” 

(SREX) and the 2013-2014 Fifth Assessment Report (AR5), the 

USGCRP’s 2014 “Climate Change Impacts in the United States” 

(Climate Change Impacts), and the NRC’s 2010 “Ocean 

Acidification: A National Strategy to Meet the Challenges of a 

Changing Ocean” (Ocean Acidification), 2011 “Report on Climate 

Stabilization Targets: Emissions, Concentrations, and Impacts 

over Decades to Millennia” (Climate Stabilization Targets), 2011 

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

Security Implications), 2011 “Understanding Earth’s Deep Past: 

Lessons for Our Climate Future” (Understanding Earth’s Deep 

Past), 2012 “Sea Level Rise for the Coasts of California, 

Oregon, and Washington: Past, Present, and Future”, 2012 
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“Climate and Social Stress: Implications for Security Analysis” 

(Climate and Social Stress), and 2013 “Abrupt Impacts of Climate 

Change” (Abrupt Impacts) assessments. 

The EPA has reviewed these new assessments and finds that 

the improved understanding of the climate system they present 

strengthens the case that GHGs endanger public health and 

welfare. 

In addition, these assessments highlight the urgency of the 

situation as the concentration of CO2 in the atmosphere continues 

to rise. Absent a reduction in emissions, a recent National 

Research Council of the National Academies assessment projected 

that concentrations by the end of the century would increase to 

levels that the Earth has not experienced for millions of 

years.14 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.”15

What this means, as stated in another NRC assessment, is 

that: 

 

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

1.

15 Id., p.138.
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Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe. Therefore, 

emission reductions choices made today matter in 

determining impacts experienced not just over the next 

few decades, but in the coming centuries and 

millennia.16 

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” 

assessment17 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 

 

16 National Research Council, Climate Stabilization Targets, 

p. 3. 

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

the United States: The Third National Climate Assessment. 

Available at http://nca2014.globalchange.gov/. 
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events in recent decades, the damage and disruption to 

infrastructure and agriculture, and projects continued increase 

and more severe changes across a wide range of peoples, sectors, 

and ecosystems. 

These assessments underscore the urgency of reducing 

emissions now: today’s emissions will otherwise lead to raised 

atmospheric concentrations for thousands of years, and raised 

Earth system temperatures for even longer. Emission reductions 

today will benefit the public health and public welfare of 

current and future generations. 

Finally, it should be noted that the concentration of 

carbon dioxide in the atmosphere continues to rise dramatically. 

In 2009, the year of the Endangerment Finding, the average 

concentration of carbon dioxide as measured on top of Mauna Loa 

was 387 parts per million.18 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, and for at least the past 800,000 years according 

to ice core records.19

B. GHG Emissions from Fossil Fuel-fired EGUs 

 

18 

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

19 http://www.esrl.noaa.gov/gmd/ccgg/trends/
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Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs, primarily in the form 

of CO2, among stationary sources in the U.S., and among fossil 

fuel-fired units, coal-fired units are by far the largest 

emitters. This section describes the amounts of those emissions 

and places those amounts in the context of the national 

inventory of GHGs. 

The EPA prepares the official U.S. Inventory of Greenhouse 

Gas Emissions and Sinks20 (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 1 below, which presents total U.S. 

anthropogenic emissions and sinks21 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2012. 

Table 1. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))22

SECTOR 1990 2005 2012 

Energy 5,260.1 6,243.5 5,498.9

 

20 “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. 

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

forests or underground or deep sea reservoirs of carbon dioxide.

22 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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Industrial Processes 316.1 334.9 334.4

Solvent and Other 

Product Use 4.4 4.4 4.4 

Agriculture 473.9 512.2 526.3 

Land Use, Land-Use 

Change and Forestry 13.7 25.5 37.8 

Waste 165.0 133.2 124.0 

Total Emissions 6,233.2 7,253.8 6,525.6

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.3)

Net Emissions (Sources 

and Sinks) 5,402.1 6,223.1 5,546.3

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.7 percent of total 

2012 GHG emissions.23 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.24

 

23 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. 

24 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. 
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Table 2 below presents total CO2 emissions from fossil fuel-fired 

EGUs, for years 1990, 2005 and 2012. 

Table 2. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2)25

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. Currently, the majority of 

power in the U.S. is generated from the combustion of coal, 

natural gas, and other fossil fuels. In recent years, though, 

the proportion of new renewable generation coming on line has 

increased dramatically. For instance, one-third of new 

generating capacity built in 2013 used renewable power 

generation technologies (EIA, 2014). 

 

25 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 

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 

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 
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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.”26 EPA has listed more than 60 stationary 

source categories under this provision.27 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. 28 These standards are 

known as new source standards of performance (NSPS), and they 

are national requirements that apply directly to the sources 

subject to them. 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to prescribe regulations for states to submit 

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

(HAP). CAA section 111(d)’s mechanism for regulating existing 

 

26 CAA §111(b)(1)(A). 

27 See 40 CFR 60 subparts Cb – OOOO. 

28 CAA §111(b)(1)(B), 111(a)(1). 
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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.” 29 If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for that state.30 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 

 

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

30 CAA section 111(d)(2)(A). 
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approved SIP under CAA section 110. In the case of a tribe that 

has one or more affected EGUs located in its area of Indian 

country,31 the tribe would have the opportunity, but not the 

obligation, to establish a CO2 performance standard and a plan 

for its tribal lands. 

The EPA issued regulations implementing CAA section 111(d) 

in 1975,32 and has revised them in the years since.33 (We refer to 

the regulations generally as the implementing regulations, and 

we refer to the 1975 rulemaking as the framework regulations.) 

These regulations provide that, in promulgating requirements for 

sources under CAA section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish 

binding requirements that states must address when they develop 

their plans.34 The implementing regulations also establish 

 

31 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. 

32 “State Plans for the Control of Certain Pollutants From 

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

33 [Cites] 

34 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emissions guidelines” – instead of emissions 

limitations – to make clear that guidelines would not be binding 

requirements applicable to the sources, but instead are 

“criteria for judging the adequacy of State plans.” 40 Fed. Reg. 

at 53,343. 
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timetables for state and EPA action: states must submit state 

plans within 9 months of the EPA’s issuance of the guidelines,35

and the EPA must take final action on the state plans within 4 

months of the due date for those plans,36 although the EPA has 

authority to extend those deadlines.37 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 

pulp plants (total reduced sulfur), and municipal solid waste 

landfills (landfill gases)).38 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.39 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 towards the pollutants and industries 

 

35 40 CFR 60.23(a)(2). 

36 40 CFR 60.27(b). 

37 See 40 CFR 60.27(a). 

38 [Cites] 

39 [Cites] 
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regulated. Similarly, in the present rulemaking, in defining CAA 

section 111(d) goals and guidelines for the states, the EPA 

believes it is necessary to take into account the particular 

characteristics of carbon pollution and the interconnected 

nature of the power sector and the manner in which EGUs are 

currently operated such that operators themselves treat 

increments of generation as interchangeable between and among 

sources in a way that creates options for relying on varying 

utilization levels, lowering carbon generation, and reducing 

demand as components of the overall method for reducing CO2

emissions. Doing so results in a broader, forward-thinking 

approach to the design of programs to yield critical CO2

reductions that improve the overall power system by lowering the 

carbon intensity of power generation, while offering continued 

reliability and cost-effectiveness. 

In this action, the EPA is proposing emission guidelines 

for states to use in developing their plans to reduce emissions 

of CO2 from the electric power sector. 

III. Stakeholder Outreach and Conclusions 

A. Stakeholder Outreach 

1. The President’s call for engagement 
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Following the direction of the Presidential Memorandum to 

the Administrator (June 25, 2013),40 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. 

 

40 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 

February 2013, the presentation had been viewed more than 4,400 

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 – a new email account: 

carbonpollutioninput@epa.gov; and a web-based form: 
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http://www2.epa.gov/carbon-pollution-standards/forms/carbonpollution-standards-contact-us. These links, along with policy, 

program, and technical information about this rulemaking effort, 

are available on the EPA’s website at: 

http://www2.epa.gov/carbon-pollution-standards. The EPA has 

received more than 2,000 emails offering input into the 

development of these guidelines. 

These emails and other materials provided to the EPA are 

posted on line as part of a non-regulatory docket, EPA Docket ID 

No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. All of the 

documents on which this proposal is based are available at 

Docket ID No. EPA-HQ-OAR-2013-0602, at www.regulations.gov.

However, while the information collected through extensive 

outreach helped the agency formulate this proposal, we are not 

relying on all of the documents, emails, and other information 

included in the informational docket that was established as a 

part of that outreach effort, nor will the EPA be responding to 

specific comments or issues raised during the outreach effort. 

Rather, we have included in the docket for this proposal all of 

the information we relied on for this action. 

The agency has encouraged, organized, and participated in 

hundreds of meetings about CAA section 111(d) and reducing 

carbon pollution from existing power plants. Attendees at these 
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various meetings have included states and tribes, members of the 

public, and representatives from multiple industries, labor 

leaders, environmental groups and other non-governmental 

organizations. The direct engagement has brought together a 

variety of states and stakeholders to discuss a wide range of 

issues related to the electricity sector and the development of 

emission guidelines under CAA section 111(d). The meetings 

occurred in Washington, DC, and at locations across the country. 

The meetings were attended by the EPA Regional Administrators, 

managers and staff and who are playing or will play key roles in 

developing and implementing the rule 

Part of this effort included the agency’s holding of 11 

public listening sessions; one national listening session in 

Washington, DC and 10 listening sessions in locations in the EPA 

regional offices across the country. All of the outreach 

meetings were designed to solicit policy ideas, concerns and 

technical information from stakeholders about using CAA section 

111(d). 

This outreach process has produced a wealth of information 

which has informed this proposal significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialog with states and stakeholders will continue 
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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 

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 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 
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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 

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 
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sector. The agency has engaged, and will continue to engage 

with, all of the 50 states throughout the rulemaking process. 

5. Tribal officials 

 The EPA conducted significant outreach to tribes, who are 

not required to – but may – develop or adopt Clean Air Act 

programs. The EPA is aware of three coal-fired power plants and 

one natural gas-fired EGU located in Indian country but is not 

aware of any EGUs that are owned or operated by tribal entities. 

The EPA conducted outreach to tribal environmental staff 

and offered consultation with tribal officials in developing 

this action. Because the EPA is aware of tribal interest in this 

proposed rule, the EPA offered consultation with tribal 

officials early in the process of developing the proposed 

regulation to permit tribes to have meaningful and timely input 

into its development. 

The EPA sent consultation letters to 584 tribal leaders. 

The letters provided information regarding the EPA’s development 

of emission guidelines for existing power plants and offered 

consultation. None have requested consultation. Tribes were 

invited to participate in the national informational webinar 

held August 27, 2013. In addition, a consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA 
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representatives also met with tribal environmental staff with 

the National Tribal Air Association, by teleconference, on 

December 19, 2013. In those teleconferences, the EPA provided 

background information on the GHG emission guidelines to be 

developed and a summary of issues being explored by the agency. 

In addition, the EPA held a series of listening sessions 

prior to development of this proposed action. Tribes 

participated in a session on September 9, 2013 with the state 

agencies, as well as in a separate session with tribes on 

September 26, 2013. 

6. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in scores of 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 
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meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries 

to help understand the issues related to large industrial users 

of electricity. 

7. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations. The meetings focused on the 

importance of the utility industry in reducing carbon emissions 

from power plants. Power plant emissions are central to this 

rulemaking. The EPA encouraged industry representatives to work 

with state environmental and energy officers. 

The electric utility representatives included private 

utilities or investor owned utilities. Public utilities and 

cooperative utilities were also part of 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 
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The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

Regional Offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

9. Representatives from 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 
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policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. 

 Public health groups discussed the need for protection of 

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

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low cost carbon reductions. 

10. Labor 

A number of labor unions invited EPA officials to their 

meetings to give presentations and engage in discussions about 

reducing carbon pollution using CAA section 111(d). EPA senior 

officials and staff met with union representatives that included 

the United Mine Workers of America, SMART, the International 

Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, 

Forgers and Helpers, United Association, the International 

Brotherhood of Electrical Workers, the Utility Workers Union of 
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America. In addition, agency leaders participated in a meeting 

of the Presidents of several unions at the AFL-CIO. 

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 

that they described as based on measures implementable only 

within the facility “fence line” (i.e., measures implementable 
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only at the source). Many stakeholders stated that the EPA 

should not require the state plans to impose on the affected 

EGUs legal responsibility for the full amount of required CO2

emissions reductions, and instead, the EPA should authorize the 

state plans to include requirements on entities other than the 

affected EGUs that would have the effect of reducing utilization 

and therefore emissions, from the affected EGUs. 

Views on the form and stringency of the goal or guidelines 

varied. Some stakeholders preferred a rate-based form of the 

goal, while others preferred a mass-based form. In addition, 

some stakeholders recommended that the EPA let the states have 

the flexibility to either choose among multiple forms of the 

goals or to set their own goals. With regard to the stringency 

of the goal, some stakeholders recommended that the stringency 

of the goals vary by state, to account for differences in state 

circumstances. 

Many stakeholders recognized the value of allowing states 

flexibility in implementing the goals the EPA establishes. For 

example, states highlighted the importance of the EPA 

recognizing existing state and regional programs that address 

carbon pollution, including market-based programs, and allowing 

credit for prior accomplishments in reducing CO2 emissions. Many 

states and other stakeholders noted the importance of the EPA 
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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. 

During the outreach process, some stakeholders raised 

general concerns that the rulemaking could have a negative 
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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. These ideas include those 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 

program for its plan. One group suggested the model rule should 

include a provision to allow the state to compensate merchant 
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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 

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 
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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 

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 
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Presidential Memorandum,41 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 2009.42 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 

of affected EGUs. A price signal for CO2 emissions also allows 

 

41 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 

42 The nine states include Connecticut, Delaware, Maine, 

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

and Vermont.
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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.43 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.44 Through 2012, for example, 

the RGGI states invested approximately $460 million of proceeds 

into energy efficiency programs.45 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.46

Between 2005, when an agreement to implement RGGI was 

announced, and 2012, power sector CO2 emissions in the RGGI 

 

43 Regional Greenhouse Gas Initiative 2013 Allowance Allocation 

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

allocation. 

44 Regional Investments of RGGI CO2 Allowance Proceeds, 2012 

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

Investment-Report.pdf 

45 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 

46 Id.
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participating states fell by more than 40 percent.47 RGGI was not 

the primary driver for these reductions but the reductions led 

RGGI-participating states to adjust the CO2 emission limits.48 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.49 

 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.50 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 

 

47 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).

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

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

49 RGGI Press Release, January 13, 2014, 

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

pdf. 

50 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. 51 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.52 

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 

 

51 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, 

http://www.georgetownclimate.org/sites/default/files/EPA_Submiss

ion_from_States-FinalCompl.pdf 

52Id.
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emission rate of either 1450 pounds CO2/MWh (based on output) or 

160 pounds of CO2/MMBtu (based on input).53 

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.54 

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 

 

53 6 New York CoCodes, Rules & Regulations. Part 251 (Adopted 

June 28, 2012) 

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

Wash SB 6001 (2007) 
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foreseeable federal CAA requirements.55 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 2020.56 

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.57 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 

 

55 Colorado Clean Air Clean Jobs Act, HB1365 

56 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. 

57 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.58 The 2012 requirement increased to 18 percent of 

total retail sales for Xcel Energy and 12 percent for all other 

 

58 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.59 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.60

 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 

Oregonload 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 2012.61 

 

59 Id.

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

Solar Energy Standard 

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

61 Eugene Water Electric Board Oregon Renewable Portfolio 

Standard 2012 Compliance Report and 2013 – 2030 Implementation 
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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. These 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 

by other sources, such as from RGGI CO2 allowance auction 

proceeds mentioned above. 

 

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

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

Renewable Portfolio Standard Compliance Report, June 1, 2013. 
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Nationally, total spending on electric ratepayer-funded 

energy efficiency programs was about $5 billion in 2012.62 Based 

on Lawrence Berkeley National Laboratory (LBNL) projections, 

spending is projected to reach $8.1 billion in 2025.63 

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.64 

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.”65 It requires its investor-owned utilities 

to meet electricity load “through all available energy 

efficiency and demand reduction resources that are cost-

 

61 Consortium for Energy Efficiency Annual Industry Report: 2013 

State of the Efficiency Program Industry – Budgets, Expenditures 

and Impacts, 2014. 

http://library.cee1.org/sites/default/files/library/11350/CEE_20

13_Annual_Industry_Report.pdf

63 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) 

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

State Scorecard 

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

ports/e13k.pdf 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy.
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effective, reliable and feasible.”66 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.”67 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.”68 Between 2010 

and 2011, these programs are estimated to have reduced CO2 by 3.8 

million tons.69 

 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.70 Vermont law requires that the energy efficiency utility 

 

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

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

Chairman of California Air Resources Board, to EPA Administrator 

Gina McCarthy.

68 Id.

69 Id.

70 State of Vermont Public Service Board, Energy Efficiency 

Utility Creation and Structure. 

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

creationandstructure
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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.71 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.72 Efficiency 

Vermont projects a net lifetime economic value to Vermont of 

more than $60 million from the 2013 energy efficiency 

investments.73 

6. Energy efficiency resource standards 

 More than 20 states have energy efficiency resource 

standards (EERS) that require utilities to save a certain amount 

of energy each year or cumulatively.74 They are typically multiyear requirements expressed as a percentage of annual retail 

 

71 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 

72 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. 

73 Id. 

74 State Energy Efficiency Resource Standards: Policy Design, 

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

Report NREL/TP-6A20-61023, April 2014.
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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-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.75

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.76 In 2012, for example, investor-owned 

utilities were required to achieve energy savings equivalent to 

1.75 percent of the 2011 sales, leading to a cumulative savings 

requirement of 3 percent by the end of 2012 (an average of 1.5% 

annually over the 2 year period).77 Utilities can meet the energy 

savings requirements through a variety of means, including cost-

 

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

August 2010., Available at 

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

76 Id. 

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

August 2010., Available at 

http://images.edocket.azcc.gov/docketpdf/0000116125.pdf
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effective energy efficiency programs, as well as load management 

and demand response programs.78 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.79

E. Conclusions 

States have taken a leadership role in mitigating GHG 

emissions and have demonstrated the potential for national 

application of a number of approaches. Throughout the 

development of this proposed rule, the EPA considered the 

states’ experiences and lessons learned regarding the design and 

implementation of successful GHG mitigation programs. The agency 

also fully considered input from stakeholders during the 

development of this proposed rulemaking. 

Considering all input from stakeholders, the agency 

recognizes that the most cost-effective approach to reducing GHG 

emissions from the power sector under CAA section 111(d) is to 

follow the lead of numerous states and not only to identify 

 

78 Id. 

79 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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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 

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 
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“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 

emission reductions that a state can achieve through the costeffective application of 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 the emission performance level it will include in its 

plan by deciding whether it will adopt the rate-based CO2 goal 

set by the EPA or translate the rate-based goal into a massbased goal. The state would then establish a standard of 

performance or set of standards of performance (known as 
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emission standards under the existing 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 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 NGCC units that are 

under construction). 

3. Reducing emissions of affected EGUs in the amount that 

results from substituting generation at those EGUs with 

expandedlow- 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. 
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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/gasfired 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 some amount of 

generation from nuclear units under construction, avoiding 

retirement of about eight percent of existing nuclear capacity, 

and increasing renewable electricity generation over time 

through the use of state-level renewable generation targets 

consistent with renewable generation portfolio standards that 

have been established by states in the same region; and block 4, 

increasing state demand-side 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 
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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 

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. 
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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 

performance or set of standards of performance, along with 

implementing and enforcing measures, that will achieve that 

emission performance level. The EPA is further proposing, as 

part of the guidelines, to authorize the state to submit either 

of two types of measures to achieve the performance level: 1) a 

set of measures that we refer to as “portfolio” measures, which 

include a combination of emission limitations that apply 

directly to the affected sources and other measures that have 

the effect of limiting generation by, and therefore emissions 

from, the affected sources; or 2) solely emission limitations 

that apply directly to the affected sources. 
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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 

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 
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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. 

 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,80 the tribe would have the opportunity, but not 

 

80 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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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 

The EPA believes that today’s proposed action is consistent 

with the requirements of CAA section 111(d) and the framework 

regulations. As an initial matter, the EPA reasonably interprets 

the provisions concerning the air pollutants covered under CAA 

section 111(d) to authorize the EPA to regulate CO2 from EGUs. We 

recognize 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 the CAA section 111(b) 

rulemaking regulating CO2 from new EGUs, and that rulemaking 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 framework 

regulations, the EPA explicitly stated that it is authorized to 

determine BSER;81 ccordingly, in this rulemaking, the EPA is 

determining BSER. 

The four building blocks include two types of measures 

that, together, comprise BSER for fossil-fired EGUs. Building 

 

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

rulemaking. 
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block 1 provides the basis for identifying carbon intensity 

improvements as a component of BSER. Building blocks 2, 3, and 4 

provide the foundation for the achievability of mass emissions 

limits at these EGUs. The EPA reasonably identified both types 

of measures as components of BSER based on the factors that the 

EPA is required to consider and the EPA’s authority to weigh 

those factors. 

In addition, the measures in building blocks 2, 3, and 4 

may be viewed as separate measures that reduce emissions by 

replacing the demand for generation at coal-fired EGUs. Because 

of the integration of the electricity system and the fungibility 

of electricity, these measures must be considered part of the 

system of emission reduction for fossil-fired EGUs. 

Moreover, the measures in each of the building blocks are 

“adequately demonstrated,” including as being technically 

feasible and reasonable in terms of cost. Heat improvement 

measures are well-recognized as feasible within the industry. 

The measures that entail dispatch changes from coal-fired EGUs 

to NGCC units, investments in renewable energy, and demand-side 

energy efficiency 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. Further, all 

of the measures achieve an important degree of emission 
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reduction. In addition, they are not unreasonably costly, 

particularly when considered on the level of the nation’s 

electricity system. Importantly, the measures encourage the 

development and expansion of technology and practices to reduce 

CO2 and are consistent with current trends in the electricity 

sector. 

After determining BSER, the EPA is authorized under the 

framework regulations, as an integral component to setting 

emission guidelines, to apply the BSER to each state and 

determine the resulting emission limitation for each state. 

 With the promulgation of the emission guidelines, each 

state must develop a plan to achieve its emission performance 

level. The state plans must establish standards of performance 

and include measures that implement and enforce those measures. 

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 impose 

requirements on other affected entities – for requirements, such 

as renewable energy and demand-side energy efficiency measures, 

that would avoid CO2 emissions from the affected EGUs. The EPA 

solicits comment on whether such requirements on other affected 

entities may be authorized as standards of performance or 
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implementing measures in a state’s CAA section 111(d) plan. The 

EPA also solicits comment on whether state plans must impose all 

of the legal responsibility for achieving the emission 

performance level on the affected EGUs. We note that even if as 

a legal matter states would be required to impose responsibility 

in such a way, the state plan – and state policy – nevertheless 

still could include requirements on other affected entities in 

order to facilitate, as a practical and economic matter, 

implementation of measures that avoid CO2 emissions from affected 

EGUs. We emphasize that the states have discretion as to the 

form of the standards of performance and may include emission 

trading programs. 

 To comply with the applicable standards of performance, 

sources may rely on any 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 

deadlines vary from those in the framework regulations. 

V. Authority to Regulate Carbon Dioxide, Affected Sources, 

Treatment of Categories

A. Authority to Regulate Carbon Dioxide 
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The EPA has the authority to regulate, under CAA section 

111(d), CO2 emissions from EGUs, under the Agency’s construction 

of the ambiguous provisions in CAA section 111(d)(1)(A)(i) that 

identify the air pollutants subject to CAA section 111(d). The 

ambiguities stem from apparent drafting errors that occurred 

during enactment of the 1990 CAA Amendments, which revised 

section 111(d). 

During the 1990 CAA Amendments, the House of 

Representatives and the Senate each passed an amendment to CAA 

section 111(d)(1)(A)(i). The two amendments differed from each 

other, and were not reconciled during the Conference Committee 

and, as a result, both were enacted into law. As amended, CAA 

section 111(d)(1) requires states to submit standards of 

performance for existing sources “for any air pollutant (i) for 

which air quality criteria have not been issued or which is not 

included on a list published under [CAA] section 108(a)... [or 

emitted from a source category which is regulated under section 

112]82 [or 112(b)]83... ” The bracketed and emphasized provisions 

set forth the House and Senate versions, respectively. The two 

versions conflict with each other and thus are ambiguous. Under 

 

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

1990).

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

1990).
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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 

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 
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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 

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 
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undertaking new constructions, by notice dated January 8, 2014, 

which we refer to as the January 2014 Proposal. The EPA is 

proposing the second, which applies to affected sources 

undertaking modifications or reconstructions, concurrently with 

this CAA section 111(d) proposal. The EPA will complete one or 

both of these CAA section 111(b) rulemakings before or 

concurrently with this CAA section 111(d) rulemaking, which will 

provide the requisite predicate for applicability of CAA section 

111(d). 

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 1429; 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 
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annual heat input; (3) sells the greater of 219,000 MWh per year 

or one-third of its potential electrical output to a utility 

distribution system; and (4) was not in operation or under 

construction as of January 8, 2014 (the date the proposed GHG 

standards of performance for new EGUs were published in the 

Federal Register). The minimum fossil fuel consumption condition 

applies over any consecutive three-year period (or as long as 

the unit has been in operation, if less). The minimum 

electricity sales condition applies over rolling three-year 

periods (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. Combined Categories and Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is co-proposing 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 co-proposing 

codifying all of the proposed requirements for the affected EGUs 

new subpart UUUU of 40 CFR part 60. 
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As discussed in the January 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 

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 co-proposing to combine 

the two categories into a single category for purposes of the CO2 
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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 preexisting and the EPA would not be subjecting any additional 

sources to regulation, the combined category would not be 

considered a new category that the EPA must list under CAA 

section 111(b)(1)(A). As a result, this proposal does not list a 

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

revise either of the two source categories – steam-generating 

boilers and combustion turbines – that the EPA has already 

listed under that provision. Thus, the EPA would not be required 

to make a finding that the combined category causes or 

contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare. 

In addition, the EPA is co-proposing two options for 

codifying the emission guidelines for affected sources. Under 

the first option, the EPA is proposing to codify the standards 

of performance for the respective sources within existing 40 CFR 

part 60 subparts: subpart Da, electric utility steam generating 
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units, which includes steam electric utility boilers and IGCC 

units, and subpart KKKK, stationary combustion turbines, which 

includes both simple cycle and combined cycle stationary 

combustion turbines. Emission guidelines for electric utility 

steam generating units would be included in subpart Da and 

emission guidelines for stationary combustion turbines would be 

included in subpart KKKK. 

Under the second option, 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. 

We solicit comment on the relative merits of each approach. 

In particular, we seek comment on whether the co-proposal to 

combine the categories and codify the GHG emission guidelines 

for all existing affected sources in subpart UUUU would offer 

any additional flexibility in the ways described above. 

VI.Building Blocks for Setting State Goals and Considerations 

A. Introduction 
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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

emissions 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 grouped 

those 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 subsection VI.B. and more 

detailed discussion of each block in subsection VI.C. In 

subsection VI.D. we discuss possible combinations of the 

building blocks, and in subsection VI.E., we explain why as a 

legal matter all four building blocks, taken together, 

constitute the basis for 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, we are mindful of numerous and 

varied stakeholder concerns, including the need to achieve 

meaningful CO2 emission reductions and to recognize and take 

advantage of the progress already made by existing programs. 

Like stakeholders, we are attentive to the need to maintain 

electric system reliability and to minimize adverse impacts on 
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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 applying the building blocks, as discussed more in Section 

VII, and we consider several of these to be key principles in 

this application. As discussed in Sections VII and VIII, we 

acknowledge and appreciate the advantages of allowing and 

promoting flexibility for states in crafting their programs. We 

recognize the knowledge that states have about their specific 

situations and their ability to evaluate and leverage existing 

and new capacity and programs to ultimately reduce EGU CO2

emissions. 

Similarly, we recognize and appreciate that states operate 

with differing circumstances and policy preferences. For 

example, states have differing access to specific fuel types, 

and the variety of types of EGUs operating in different states 

is broad and significant. States are part of assorted EGU 

dispatch systems and vary in the amounts of electricity that 

they import and export. For these reasons, we also recognize and 

appreciate the value in allowing and promoting regional and 

multi-state reduction strategies. Some states already 

participate in a regional program that reduces CO2 emissions, the 
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RGGI, and we have noted the success of that program for those 

states. 

Another key consideration in application of these building 

blocks, 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 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. Further discussion of particular 

measures and how they form the basis of the BSER is provided 

below in subsections VI.C and VI.D, respectively. 

1. Overview of approach 

 In considering the appropriate scope of the proposed BSER, 

the EPA evaluated three basic groupings of strategies for 

reducing CO2 emission from EGUs: (i) reductions achievable 

through improvements in individual EGUs’ emission rates 

(referred to throughout this preamble as "building block 1"); 
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(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 of increased demand-side energy 

efficiency (“building block 4”). 

As described in the remainder of this section, the EPA 

concluded that while certain strategies within the first 

grouping clearly should be part of the BSER, it was not 

appropriate to limit consideration of the BSER to this first 

grouping, for several reasons. First, we determined that some 

strategies available in the other two groupings can reduce 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 
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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.84 These 

factors reinforced the appropriateness of our considering 

strategies from all three groupings for purposes of determining 

the BSER. 

2. CO2 reductions achievable through improvements in individual 

EGUs’ emission rates 

The first grouping of CO2 emission reduction options that 

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 electricity85

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 

 

84 The potential for efficiency improvements to lead to increased 

utilization is generally described as a “rebound effect.” 

85 For simplicity, in this subsection we 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. 
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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. Specifically, our analysis 

indicated that average CO2 emission reductions of 1.3 to 6.7 

percent could be achieved by coal steam EGUs through adoption of 

best practices, and that additional average reductions of up to 

four percent could be achieved through equipment upgrades.86 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 steam EGUs for net costs in a range of $6 

to $12 per metric ton.87

 

86 These estimated ranges are averages applicable to the fleet of 

coal steam EGUs as a whole. Potential improvements at individual 

EGUs could be higher or lower. 

87 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”). 
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The EPA also examined application of CCS technology at 

existing EGUs. CCS offers the technical potential for CO2

emission reductions of over 90 percent, or smaller percentages 

in partial applications. In the recently proposed Carbon 

Pollution Standards for new fossil fuel-fired EGUs (79 FR 1430), 

we found that partial CCS was adequately demonstrated for new 

fossil fuel-fired steam EGUs and integrated gasification 

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. 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 
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circumstances,88 the EPA is not proposing and does not expect to 

finalize CCS as a component of the BSER for existing EGUs in 

this rulemaking.89

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 instead the 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 co-firing is likely to be the 

incremental cost of natural gas relative to the cost of coal. 

Using Energy Information Administration (EIA) fuel price 

projections, we estimated that the CO2 reductions achieved 

 

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

EGUs, as noted in the discussion of CCS later in the preamble. 

89 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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through natural gas conversion or co-firing at an average coalfired steam EGU would have costs ranging from approximately $83 

to $150 per metric ton.90 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, 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 

 

90 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. 
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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.91 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 BSER for 

reducing 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 

 

91 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,92 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. 

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 2012.93 In 2012, the average utilization 

rate of U.S. NGCC capacity was 46 percent, well below the 

utilization rates the units are capable of achieving. In 2012 

approximately 10 percent of NGCC plants operated at annual 

utilization rates of 70 percent or higher, and 19 percent of 

 

92 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. 

93 EIA Form 860. 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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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 2012.94 Further, 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 subsection VI.C.2, the above facts 

support our assessment that an average NGCC utilization rate in 

a range of 65 to 75 percent is a reasonable target for the 

amount of additional NGCC generation that could be substituted 

for higher carbon generation from steam EGUs as part of the 

 

94 EIA Form 923. 
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BSER.95 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 AB32, shifting 

generation from more carbon-intensive EGUs to less carbonintensive 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 encompassed 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 

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 

 

95 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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CO2 emissions at EGUs were already being used and would continue 

to be used throughout the industry, at least potentially for the 

purpose of compliance with CO2 emission reduction requirements. 

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 the reduction of CO2 emissions at EGUs. 

Again, many instances were observed as taking place incidental 

to the ongoing operation of the electricity system as well as 

taking place in response to specific CO2 emissions limits in 

place in states that have been implementing CO2 emissions 

reduction programs affecting the power sector. We concluded 

that there are two principal types of such potential options for 

measures that result in CO2 emission reductions at EGUs affected 

under this proposal: ongoing development and use of low- and 

zero-carbon generating capacity, and ongoing development and 

application of demand-side energy efficiency measures. 

Low-and zero-carbon generating capacity provides 

electricity that can be substituted for generation from more 

carbon-intensive EGUs. More than half the states already have 

established some form of state-level renewable energy 

requirements, with targets calling on average for almost 20% of 

2020 generation to be supplied from renewable sources. The EPA 

is unaware of analogous state policies to support development of 
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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. 

Demand-side energy efficiency programs reduce the demand 

for generation from existing fossil fuel-fired EGUs, and 

therefore eliminate the CO2 emissions associated with the avoided 

generation as well, by producing electricity-dependent services 

with less electricity. More than 40 states already have 

established some form of demand-side energy efficiency polices, 

and individual states have avoided up to 13% of their 

electricity demand. Again, policies that encourage demand-side 

energy efficiency could be useful elements of CO2 reduction 

strategies and are consistent with current industry behavior. 

Using conservatively high estimates of the costs of demand-side 

energy efficiency, the EPA estimates that the costs of CO2 

emission reductions achievable consistent with such policies 

would be in a range of $16 to $24 per metric ton. 
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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. 

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 result either in improved operating efficiency 

or in reductions in mass emissions at existing EGUs, each of the 

four building blocks represents a demonstrated approach for 

reducing CO2 emissions from affected EGUs that is already being 
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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 section 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 state goals described in section 

VII. We also discuss certain measures that we are not proposing 

to consider part of the best system of emission 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, but 

rather have flexibility to establish plans to meet their goals 

using their own preferred combinations and stringencies of 
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measures. 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 aggressively, 

and others less aggressively, than is reflected in the goal 

computations, according to each state’s needs and preferences. 

1. Building block 1 - heat rate improvements 

 The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 

reduce the carbon intensity of generation at individual coalfired steam EGUs96 by improving heat rate. Heat rate improvements 

 

96 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 
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are changes that increase the efficiency with which an EGU 

converts fuel energy to electric energy (and useful thermal 

energy in the case of units that cogenerate steam for process 

use as well as electricity), thereby reducing the amount of fuel 

needed to produce the same amount of electricity and lowering 

the amount of CO2 produced as a byproduct of fuel combustion. 

Heat rate improvements yield important benefits to affected 

sources by reducing their fuel costs. 

The EPA is aware of the potential for “rebound effects” 

from improvements in heat rates at individual EGUs. In this 

context, a rebound effect would occur where, because of an 

improvement in its heat rate, an EGU experiences a reduction in 

variable operating costs that makes the EGU more competitive 

relative to other EGUs and consequently raises the EGU’s 

generation output. The increase in the EGU’s CO2 emissions 

associated with the increase in generation output would offset 

the reduction in the EGU’s CO2 emissions caused by the decrease 

in its heat rate and rate of CO2 emissions per unit of generation 

output. The extent of the offset would depend on the extent to 

which the EGU’s generation output increased (as well as the CO2

 

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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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 prevent or discourage increases in generation output 

from coal-fired steam EGUs on average. The topic of potential 

rebound effects is discussed further in section VI.B above and 

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 

coal-fired steam EGUs than for other EGUs, and for purposes of 

determining the best system of emission reduction EPA has 

therefore conservatively based its estimate of CO2 emission 

reductions from heat rate improvements on coal-fired steam EGUs 

only.97 The remainder of this section focuses primarily on the 

EPA’s analysis of potential heat rate improvements from coalfired steam EGUs. In the final subsection below we discuss our 

 

97 States and EGUs would also be able to rely on CO2 emission 

reductions achieved through heat rate improvements at other 

types of EGUs. 
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analysis of potential heat rate improvements from other types of 

affected EGUs. 

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).98 The current weighted-average annual 

heat rate of U.S. coal-fired EGUs in the range of 400 to 600 MW 

is approximately 10,434 Btu per net kWh.99 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.100

 

98 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.

99 See NEEDSv.5.13 at 

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

100 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. 
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 Several studies have examined the opportunities to employ 

heat rate improvements as a means of reducing CO2 emissions from 

coal-fired power plants.101 Among these, a 2009 study by the 

engineering firm Sargent & Lundy used bottom-up engineering 

approaches evaluating potential heat rate improvements from 

specific best practices and equipment upgrades, including 

upgrades to boilers, steam turbines, and control systems. Based 

on this study, the EPA believes that implementation of all 

identified best practices and equipment upgrades at a facility 

could provide total heat rate improvements in a range of 

approximately 4 to 12 percent. (We recognize that individual 

EGUs would only be able to implement the best practices or 

upgrades that were applicable to their specific designs or fuel 

types and that had not already been implemented.) 

 In addition to the Sargent & Lundy study, which looked 

generically at the types of improvements that can be made at 

specific types of EGUs, historical heat rate data also provides 

a basis for 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. 

 

101 See chapter 2 of the GHG Abatement Measures TSD for details. 
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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 

 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. 
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 For the best practices analysis, the EPA worked with the 

hourly data reported to the EPA by affected EGUs subject to the 

monitoring and reporting requirements of 40 CFR Part 75. The 

reported data include hourly heat input and, for most reporting 

EGUs, hourly gross generation, making it possible to compute 

hourly gross heat rates. We used the hourly data to assess 

variability in the hourly gross heat rates of approximately 900 

individual coal-fired steam EGUs over the period from 2002 to 

2012. Specifically, the EPA evaluated the consistency with which 

individual EGUs maintained their hourly heat rates over time. We 

expected that a certain degree of short-term heat rate 

variability was caused by factors beyond operators’ control, 

notably variation in hourly ambient temperature and hourly load, 

and preliminary analysis confirmed our expectation. We therefore 

controlled for variation in those factors by grouping the 

observed hourly heat rate data for each EGU into subsets 

corresponding to ranges of hourly ambient temperatures and 

hourly load levels.102 We believe that the amount of residual 

variability within each data subset is an indication of the 

 

102 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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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 

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.103 Based on this analysis, we believe a reasonable estimate 

 

103 We examined whether the potential for heat rate improvement 

varied based on EGU characteristics such as capacity, boiler 
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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. 

 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 

 

type, and location, and found no meaningful differences. 
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various upgrades in this subset, implementation of the full 

subset of appropriate opportunities at a single EGU could be 

expected to result in an aggregate heat rate improvement of 

approximately four percent (incremental to the improvement 

achievable from adoption of best practices). However, we 

recognize that this total may overstate the average equipment 

upgrade opportunity across all EGUs because some EGUs may have 

already implemented some of these upgrades. We therefore propose 

to use as a data input for purposes of developing state goals an 

estimate that, on average across the fleet of affected EGUs, 

only half of the full equipment upgrade opportunity just 

described remains – i.e., that for the fleet of affected EGUs as 

a whole, the technical potential for heat rate improvements from 

equipment upgrades incremental to the 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 
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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.104 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 

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 cost effectively.105 

 

104 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). 

105 As proposed, the state-specific goals are expressed in the 

form of CO2 emissions per net MWh, and reporting requirements for 
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 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. Because of the close relationship between an EGU’s 

fuel consumption and its CO2 emissions, a six percent heat rate 

improvement would be associated with a reduction in CO2 emissions 

of approximately six percent. We believe that this represents a 

reasonable estimate of the technical potential for CO2 emission 

reductions that would be achievable from affected coal-fired 

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 we have used an 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 

 

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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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 EGUs. 

 It should be noted that we have not evaluated the technical 

and economic potential for analogous heat rate improvements at 

types of EGUs other than coal-fired steam EGUs. We have 

therefore not identified such improvements as part of this 

building block. 

c. Costs of heat rate improvements 

 By definition, any heat rate improvement made for the 

purpose of reducing CO2 emissions will also reduce the amount of 

fuel the EGU consumes to produce its electricity output. The 

cost attributable to CO2 emission reductions therefore would be 

at most 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 
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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 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 

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,106 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 

 

106 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. 
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kW-year.107 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.108 On the other 

hand, if an average heat rate improvement of four percent could 

be achieved for an average investment of $50 per kW, reflecting 

an assumption that the first improvements pursued would be the 

least expensive ones, the average cost of CO2 reductions would 

fall to $5.81 per metric ton.109 

 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 

 

107 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.

108 $7.75 per metric ton of CO2 * 6% / 4% = $11.63 per metric ton 

of CO2. 109 $11.63 per metric ton of CO2 * $50 / $100 = $5.81 per metric 

ton of CO2.
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reduce the fuel savings associated with heat rate improvements, 

thereby raising the effective cost of achieving the CO2 emission 

reductions from the heat rate improvements. Nevertheless, we 

still expect that the majority of the investment required to 

capture the technical potential for CO2 emission reductions from 

heat rate improvements would be offset by fuel savings, and that 

the net costs of heat rate improvements as an approach to 

reducing CO2 emissions from existing fossil fuel-fired EGUs are 

reasonable. 

 Based on the analyses of technical potential and cost 

summarized above, we propose to find that a six percent 

reduction in the CO2 emission rate of the coal-fired EGUs in a 

state, on average, is a reasonable estimate of the amount of 

heat rate improvement that can be implemented at a reasonable 

cost.110 

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 

 

110 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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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, 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. 

d. Assessment of heat rate improvement opportunities at 

gas- and oil-fired steam EGUs and NGCC units 

The EPA also 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/gas-fired 

steam EGUs, NGCC units, and combustion turbine units. For these 

non-coal technologies, the EPA concludes that the total 

additional potential CO2 reductions are very small compared to 

the potential CO2 reductions achievable at coal-fired steam EGUs. 

For this reason, the EPA does not propose to include heat rate 

improvement opportunities at oil/gas-fired steam EGUs or NGCC 

units as an element of the BSER for CO2 emissions from affected 
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EGUs. However, the EPA expects that for some individual oil/gasfired steam EGUs, NGCC units, and combustion turbine 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. 

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 

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 
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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. Treating 

increments of generation as 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. Electricity demand varies 

across geography and time in response to numerous conditions, 

such that EGU owners and grid operators are constantly 

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

demand in the most reliable and cost-effective manner possible. 

Operators of EGUs subject to existing market-based programs to 

limit emissions of pollutants such as SO2 and NOx have for many 

years factored directly into dispatch decisions the costs 

associated with the EGUs’ emission rates of those pollutants 

because each ton of emissions requires an emission allowance 

that has an economic cost. Operators of EGUs subject to CO2 

emissions limits in RGGI have also relied on replacing 

generation at higher-emitting EGUs with generation from loweremitting sources to reduce emissions at the former. Reducing or 

limiting emissions at high carbon-intensity EGUs by replacing 

generation at those EGUs with generation at less carbon-
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intensive EGUs clearly has the technical capability to reduce 

overall power sector CO2 emissions. 

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 turn in our BSER 

determination to the quantity of replacement generation that may 

be relied upon at reasonable costs. The U.S. electric 

generating fleet includes EGUs employing a variety of generating 

technologies. EGUs using technologies with relatively low 

variable costs, such as nuclear units, are for economic reasons 

generally operated at their maximum output whenever they are 

available. Renewable EGUs such as wind and solar units also have 

low variable costs, but in any event are generally operated when 

wind and sun conditions permit rather than at operators’ 
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discretion. In contrast, fossil fuel-fired EGUs have higher 

variable costs and are also relatively flexible. Fossil fuelfired EGUs are therefore generally the units that operators use 

to respond to intra-day and intra-week changes in demand. 

Because of these typical characteristics of the various EGU 

types, the primary re-dispatch opportunities among existing 

units available to EGU owners and grid operators generally 

consist of opportunities to shift generation among various 

fossil fuel-fired units, in particular between coal-fired EGUs 

(as well as oil- and gas-fired steam EGUs) and NGCC units. In 

the 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 coalfired EGUs to NGCC units that takes place as a result of this 

competition is highly relevant to overall power sector GHG 

emissions, because a typical NGCC unit produces less than half 

as much CO2 per MWh of electricity generated as a typical coalfired EGU. 

 In order to estimate the potential magnitude of the costeffective opportunity to reduce power sector CO2 emissions 

through re-dispatch among existing EGUs, the EPA first examined 

information on the design capabilities and availability of NGCC 
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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% for some groups.111 

 We also researched historical data to determine the 

utilization rates that NGCC units have already been demonstrated 

capable of sustaining. Over the last several years, EGU owners 

and grid operators have engaged in considerable re-dispatch 

among various types of fossil fuel-fired units relative to 

historical dispatch patterns, with NGCC units increasing 

generation and many coal-fired EGUs reducing generation. In 

fact, in April 2012, for the first time ever the total quantity 

of electricity generated nationwide from natural gas was 

approximately equal to the total quantity of electricity 

 

111 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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generated nationwide from coal.112 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 

aggregate the historical data provide ample evidence indicating 

that, on average, existing NGCC units can achieve and sustain 

utilization rates higher than their present utilization rates. 

 The experience of relatively heavily used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. 

According to the historical NGCC unit utilization rate data 

reported to the EPA, in 2012 roughly 10 percent of existing NGCC 

units operated at annual utilization rates of 70 percent or 

higher.113 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 

 

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

113 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. 
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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.114 During the spring and fall periods when electricity 

demand levels are typically lower, these units were sometimes 

idled or operated at much lower capacity factors. Nonetheless, 

the data clearly demonstrate that a substantial number of 

existing NGCC units have proven the ability to sustain 70 

percent utilization rates for extended periods of time. We view 

this as strong evidence that increasing the utilization rates of 

existing NGCC units to 70 percent, not in every individual 

instance but on average, as part of a comprehensive approach to 

reducing CO2 emissions from existing high carbon-intensity EGUs, 

would be technically feasible. 

For purposes of establishing state goals, historical (2012) 

electric generation data was used to apply each building block 

and develop each state’s goal (expressed as an adjusted CO2 

 

114 Air Markets Program Data (at http://ampd.epa.gov/ampd/). 
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emission rate in lbs per MWh).115 In 2012, electric generation 

from existing NGCC units was 959 TWh.116 After the application of 

NGCC re-dispatch toward a 70 percent target utilization rate, 

these existing sources were calculated to collectively generate 

1,390 TWh. Adding in the existing sources that were under 

construction in 2012 but not yet in operation increases total 

NGCC generation calculated in the goal setting to 1,443 TWh. 

Although states may choose to comply with state goals 

through a variety of abatement measures and achieving upwards of 

1,400 TWh of NGCC generation in 2020 is therefore not actually 

required, the EPA nevertheless believes that producing this 

quantity of generation is feasible for this set of NGCC units. 

As a reference point, NGCC generation increased by approximately 

430 TWh (an 80% 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 rate in NGCC generation than has been observed from 

2005 to 2012. We also regard these changes as not impairing 

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 

 

115 See section VII for further explanation of how goals were 

computed. 

116 For covered sources. 
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the rule. Similar conclusions have been reached in recent 

studies of the potential impact of emissions reduction from 

existing power plants.117

 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 system is already supporting national average NGCC 

utilization rates of 60 percent or higher during peak hours, 

which are the hours when constraints on pipelines or electricity 

transmission networks are most likely to arise. NGCC unit 

utilization rates during the range of peak daytime hours from 10 

a.m. to 9 p.m. are typically 15 to 20 percentage points above 

their average utilization rates (which have recently been in the 

range of 40 to 50 percent).118 Fleet-wide combined-cycle average 

 

117 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. 

118 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 
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monthly utilization rates have reached 65 percent,119 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 gas and electric system infrastructure 

would be capable of supporting increased NGCC unit utilization 

rates is the flexibility of the emission guidelines. The state 

goals do not require any particular NGCC unit utilization rate 

to be achieved in any hour or year of the initial plan period. 

Thus, even if isolated gas or electric 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 infrastructure is that pipeline and 

transmission planners have repeatedly demonstrated the ability 

 

in Energy, Jan. 15, 2014, 

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

data).

119 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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to methodically relieve bottlenecks and expand capacity.120

Natural gas pipeline capacity is regularly added in response to 

increased gas demand and supply, such as the addition of large 

amounts of new NGCC capacity in 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 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.121 There have also been 

notable capacity expansions over the past five years, in 

response to increased natural gas supply estimates and advances 

in drilling techniques.122 Further, as discussed below in section 

 

120 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). 

121 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. 

122 Energy Information Administration, 

http://www.eia.gov/naturalgas/data.cfm 
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VII.D on state flexibilities and section VIII on state plans, we 

believe the flexible nature of the goals provides time for 

infrastructure improvements to occur should they prove necessary 

in some locations.123 Combining these factors of currently 

observed utilization rates of up to 65 percent on a monthly 

basis and time flexibility to address existing infrastructure 

limitations, it is reasonable to conclude that the natural gas 

supply system can reliably deliver sufficient supplies to allow 

average annual NGCC utilization rates of 65 percent, and, given 

the flexible compliance potential, to move beyond this level to 

70 percent utilization rates. 

 We recognize that re-dispatch does contemplate an 

associated increase in natural gas production. 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. 

 

123 See section VII.D and section VIII below for discussion of 

timing flexibility. 
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According to EIA, natural gas proved reserves have doubled 

between 2000 and 2012. Domestic production has increased by 32 

percent over that same timeframe (from 19.2 TCF to 25.3 TCF). 

EIA’s Annual Energy Outlook for 2014 projects that production 

will further increase to 29.1 TCF, as a result of increased 

supplies and favorable market conditions. For comparison, NGCC 

generation growth of 450 TWh (calculated in goal setting) would 

result in increased gas consumption of roughly 3.5 TCF for the 

electricity sector. 

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 

fulfil its purpose of producing projections related to the 

electric power sector and its related markets - including least 

cost capacity expansion and electricity dispatch projections – 

that reflect industry conditions in as realistic a manner as 

possible, IPM incorporates representations of fuel supply, 
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transmission, dispatch, and reliability constraints. The model 

includes a detailed representation of the natural gas pipeline 

network and the capability to project economic expansion of the 

network based on pipeline load factors. At the EGU level, IPM 

includes detailed representations of key operational limitations 

such as turn-down constraints, which are designed to account for 

the cycling capabilities of EGUs to ensure that the model 

properly reflects the distinct operating characteristics of 

peaking, cycling, and base load units. 

As described in more detail below, the EPA used IPM to 

assess the costs of requiring increasing levels of 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.124 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 

 

124 See Chapter 3 of the Regulatory Impact Analysis for more 

detail.
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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 

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 in our BSER 

determination to the question of cost. The cost of the power 

sector CO2 emission reductions that can be achieved through redispatch among existing fossil fuel-fired EGUs depends on the 

relative variable costs of electricity production at EGUs with 

different degrees of carbon intensity. These variable costs are 

driven by the EGUs’ respective fuel costs and by the 

efficiencies with which they can convert fuel to electricity 

(i.e., their heat rates). Historically, natural gas has had a 

higher cost per unit of energy content (e.g., MMBtu) than coal 

in most locations, but for NGCC units this disadvantage in fuel 

cost per MMBtu relative to coal-fired EGUs is typically offset 

in significant part, and sometimes completely, by a heat rate 

advantage. 
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 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 analysis of the 

opportunity to reduce CO2 emissions through re-dispatch. The 

first set was a dispatch-only set that provided a framework for 

understanding the broader economic and emissions implications of 

shifting generation to NGCC units from more carbon-intensive 

EGUs without consideration of emission reduction measures 

reflected in the other building blocks. The second set included 

additional refinements and more closely reflected all the 

characteristics of the proposed goals that were used as the 

basis for assessing the costs and benefits of the overall 

proposal.125 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 cost-effectively 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 

 

125 See Regulatory Impact Analysis for more detail.
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possible requirements, signals, or incentives to re-dispatch 

from more carbon-intensive to less carbon-intensive EGUs, the 

EPA analyzed a series of scenarios in which the fleet of NGCC 

units nationwide was required, on average, to achieve a 

specified annual utilization rate.126 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 constraints and requiring re-dispatch to 

occur exclusively within a region’s existing fleet.127 

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 

 

126 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. 

127 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.
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over the 2020-2029 period was $30 per metric ton of CO2.128 We 

view these estimated costs as not unreasonable and therefore as 

supporting the use of a 70 percent utilization rate target for 

purposes of quantifying the cost-effective emission reductions 

achievable 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 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.129 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 

 

128 The analogous costs for the scenarios with 65 and 75 percent 

NGCC utilization rates were $21 and $40 per metric ton of CO2, 

respectively. 

129 For further explanation of the state goal computation 

methodology, see section VII of the preamble and the Goal 

Computation TSD. 
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potential impacts of re-dispatch in particular, and as a result, 

they reflect an assumption that even in a state where redispatch might be relatively expensive compared to other 

available CO2 reduction measures that are part of the BSER, the 

state would seek to meet its emission reduction obligations 

using re-dispatch to the same extent as 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 employing 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% 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 
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appropriate degree of re-dispatch to incorporate into the state 

goals for CO2 emission reductions, and in assessing costs. 

 We also conclude from our analysis 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.130 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.131 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. 

 

130 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. 

131 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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However, for the same reasons discussed above with respect 

to estimated costs per ton of CO2, in actual implementation we 

again expect that the economic impacts shown in these scenarios, 

including natural gas price impacts, are 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 on the 

regulatory impacts analysis. 

 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 
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to 70 percent, on average across all the NGCC units in the 

state. 

For purposes of the alternative set of goals on which we 

are seeking comment, we have used the less stringent target of a 

65 percent average utilization rate for NGCC units. In 2012, 

approximately 16 percent of existing NGCC plants larger than 25 

megawatts had utilization rates equal to or higher than this 

level. Also, as noted earlier, average NGCC utilization 

nationwide is already over 60 percent in some peak hours. We 

therefore view 65 percent as a reasonable lower-bound estimate 

of an achievable average NGCC utilization rate, and we would 

expect the costs and economic impacts from re-dispatch 

associated with a 65 percent NGCC utilization target to be lower 

than the costs and impacts associated with the 70 percent 

utilization target. 

We also specifically invite comment on raising the NGCC 

utilization rate target to a level higher than 70 percent, and 

in particular 75 percent. As noted above, six percent of NGCC 

plants operated at or above a 75 percent utilization rate in 

2012.132 

 

132 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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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, 

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 
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be supplied with generation from renewable generating 

resources.133 Production of this renewable generation displaces 

predominantly fossil fuel-fired generation and thereby avoids 

the CO2 emissions from that displaced generation. EPA believes 

that renewable electricity generation is a proven way for states 

to reduce CO2 emissions at affected EGUs at a reasonable cost.134

To estimate the CO2 emission reductions from affected EGUs 

achievable through increases in renewable generation, EPA has 

estimated a “best practices” scenario for renewable capacity 

development 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 

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 

 

133 Database of State Incentives for Renewables & Efficiency 

(DSIRE), 

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

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

state plans, see section VIII below. 
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developed by the states necessarily reflect consideration of the 

states’ own regional contexts.135 

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 effectiveness. 

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.136 By 

 

135 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 cost-effective RE 

generation potential within the same region. 

136 Given their unique locations, Alaska and Hawaii are not 

grouped with other states into these regions. As a conservative 
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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.137 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 3 below. 

Table 3: Regions for Development of Best Practices RPS 

Scenario 

Region States 

East Central Delaware, District of Columbia*, Maryland, New 

Jersey, Ohio, Pennsylvania, Virginia, West 

Virginia 

North Central Illinois, Indiana, Iowa, Michigan, Minnesota, 

 

approach to estimating cost-effective 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. 

137 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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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 

growing annual levels of RE generation estimated based on 

application of an annual RE growth factor to the state’s 

historical RE generation, subject to a maximum RE generation 

target. The annual RE growth factors and maximum RE generation 

targets were developed separately for each of the six regions. 

Our procedure for determining these elements is described in the 

Greenhouse Gas Abatement Measures TSD and summarized below. 
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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. Most hydropower generation is excluded from 

this existing 2012 generation for purposes of quantifying BSERrelated RE generation potential because state RPS requirements 

typically exclude the historical output at pre-existing 

hydropower facilities from qualifying. Additionally, building 

the methodology from a baseline that includes large amounts of 

existing hydropower generation could distort goals for states 

with large amounts of existing hydropower capacity as well as 

for their regional neighbors lacking that existing capacity. 

(The exclusion of pre-existing hydropower generation from the 

baseline of this goal-setting framework does not exclude it as 

an option for state compliance.) 

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 

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 
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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,138

and continues through 2029. This regional growth factor is the 

growth factor used for each state in that region to develop the 

best practices scenario. 

Finally, we developed the annual RE generation levels for 

each state. To do this, we applied the appropriate regional 

growth factor to that state’s initial RE generation level, 

starting in 2017, but stopping at the point when additional 

growth would cause total RE generation for the state to exceed 

the state’s maximum RE generation target. For computation of the 

proposed state goals discussed in section VII.C below, we used 

the annual amounts for the years 2020 through 2029. For 

 

138 See Section VIII below for further discussion of timing 

requirements for state plan submittals. 
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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 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 4. 

 Table 4: State RE Generation Levels for State Goal 

Development (Percentage of Annual Generation)139

State 2012 Proposed Goals Alternate Goals 

Interim 

Level 

Final 

Level 

Interim 

Level 

Final 

Level 

 Alabama 2% 6% 9% 4% 5% 

 Alaska 1% 2% 2% 1% 1% 

 

139 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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 Arizona 2% 3% 3% 2% 3% 

 Arkansas 3% 5% 7% 4% 5% 

 California 15% 20% 21% 20% 21% 

 Colorado 12% 19% 21% 17% 19% 

 Connecticut 2% 5% 9% 4% 5% 

 Delaware 2% 7% 12% 4% 5% 

 Florida 2% 6% 10% 4% 6% 

 Georgia 3% 8% 10% 6% 7% 

 Hawaii 9% 10% 10% 10% 10% 

 Idaho 16% 21% 21% 21% 21% 

 Illinois 4% 7% 9% 6% 7% 

 Indiana 3% 5% 7% 4% 5% 

 Iowa 25% 15% 15% 15% 15% 

 Kansas 12% 19% 20% 19% 20% 

 Kentucky 0% 1% 2% 1% 1% 

 Louisiana 2% 5% 7% 4% 4% 

 Maine 28% 25% 25% 25% 25% 

 Maryland 2% 10% 16% 6% 8% 

 Massachusetts 5% 15% 24% 11% 13% 

 Michigan 3% 6% 7% 5% 6% 

 Minnesota 18% 15% 15% 15% 15% 

 Mississippi 3% 8% 10% 6% 8% 

 Missouri 1% 2% 3% 2% 2% 
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 Montana 5% 8% 10% 7% 7% 

 Nebraska 4% 8% 11% 6% 7% 

 Nevada 8% 15% 19% 12% 14% 

 New Hampshire 7% 19% 25% 15% 19% 

 New Jersey 2% 8% 16% 5% 7% 

 New Mexico 7% 12% 16% 10% 12% 

 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% 20% 

 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% 6% 4% 5% 

 Virginia 3% 12% 16% 9% 12% 

 Washington 7% 12% 16% 10% 12% 

 West Virginia 2% 8% 14% 5% 6% 

 Wisconsin 5% 8% 11% 7% 8% 
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 Wyoming 9% 15% 20% 13% 15% 

We note that the RE generation levels represent total 

amounts of RE generation, rather than incremental amounts. 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 to deploy 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 that have already achieved a higher 

proportion of their generation from renewable resources are 

assumed to have less additional renewable generation to deploy 

as part of the BSER framework informing state goals, in 

comparison to states in that region that have not achieved as 

high a share of RE generation to date. 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. 

The EPA believes that RE generation at the levels 

represented in the best practices scenario can be achieved at 
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reasonable costs. According to an EPA analysis based on EIA 

levelized costs, the cost to displace emissions through RE 

ranges from $10 to $40 per metric ton of CO2.140 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.141 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.142

 

140 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.

141 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. 

142 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., 
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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.143

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 2007-2012 has exceeded 6 GW per year.144 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 - 

 

“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.

143 NREL, “Renewable Electricity Futures Study”, NREL/TP-6A20-

52409, 2012, http://www.nrel.gov/analysis/re_futures/.

144 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.145 

We invite comment on this approach to treatment of 

renewable generating capacity as an emission limitation 

component of the best system of emission reduction and a basis 

for quantification of state goals. 

[PLACEHOLDER FOR SOLICITATION OF COMMENT ON AN ALTERNATIVE 

METHOD OF QUANTIFYING BSER RE GENERATION THAT IS CURRENTLY UNDER 

DEVELOPMENT WITH INTERAGENCY REVIEWERS] 

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 for reducing 

CO2 emissions from affected fossil fuel-fired EGUs. 

 

145 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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 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 new 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 a highly cost-effective opportunity to reduce CO2

emissions from affected fossil fuel-fired EGUs. For this reason, 

we are proposing that the emission reductions achievable at 

affected sources as a result of the generation provided at the 

identified new nuclear units should be factored into the state 
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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 in the 

existing 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.146

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. 

We have determined that, based on available information 

regarding the cost and performance of the nuclear fleet, 

preserving the operation of this existing, at-risk nuclear 

capacity is likely to be a relatively cost-effective approach to 

achieving CO2 reductions from affected EGUs. For example, 

retaining the estimated seven percent of at-risk nuclear 

capacity could avoid 200 to 300 million metric tons of CO2 over 

an initial compliance phase-in period of ten years.147 According 

 

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

accelerated power plant retirements,” (April 2014). 

147 Assuming replacement power for at-risk nuclear capacity is 

sourced from new NGCC capacity at 800 lbs/MWh or the power 
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to a recent report, nuclear units may be experiencing up to a 

$6/MWh shortfall in covering their operating costs with 

electricity sales.148 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. EPA views this cost as reasonable. We 

therefore propose that the emission reductions achievable by 

retaining in operation six percent of each state’s existing 

nuclear capacity should be factored into the state goals for the 

respective states. 

 For purposes of goal computation, generation from new and 

preserved nuclear capacity is based on an estimated 90 percent 

average utilization rate for U.S. nuclear units, consistent with 

long-term average annual utilization rates observed across the 

nuclear fleet. The methodology for taking this generation into 

account for purposes of setting state emission rate goals is 

described below in section VII on state goals and in the Goal 

Computation TSD. 

 

system at 1127 lbs CO2/MWh (average 2020 power sector emissions 

intensity as projected in EPA’s IPM Base Case). 

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

Suisse, February 2013 
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 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. 

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 reduces mass emissions at all affected EGUs, and 

entails an analysis of the extent to which generation at the 

affected EGUs can be reduced by reducing the demand for 

generation at those EGUs through measures that reduce the 

overall quantity of generation demanded by end-users.149 

a. Benefits of demand-side energy efficiency 

 Reducing demand for generation at affected EGUs through 

policies to improve demand-side energy efficiency is a proven 

method of 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, 

 

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

throughout this section includes the residential, commercial and 

industrial sectors. 
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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.150

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.151

 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 displaced 

when demand is reduced. Consequently, reductions in fossil fuelfired utilization may be achieved cost-effectively by reducing 

electricity consumption and, by the same token, reductions in 

electricity consumption generally cause reductions in the amount 

of fossil fuel-fired generation, thereby avoiding the CO2

emissions associated with the avoided generation. In this 

manner, in 2011, state demand-side energy efficiency programs 

 

150 Energy Information Administration Form 861, 2012, available 

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

151 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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are estimated to have reduced CO2 emissions by 75 million metric 

tons.152 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 

further reduce carbon intensity. This potential effect 

reinforces the appropriateness of incorporating demand-side 

efficiency improvements in a comprehensive approach to address 

power sector CO2 emissions. In addition to reducing the CO2 

emissions and carbon intensity of the power sector, because it 

drives reductions in fossil fuel usage at EGUs, demand-side 

energy efficiency also reduces 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 

 

152 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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 To estimate the potential CO2 reductions at affected EGUs 

that could be achieved through 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 cost-effective demand-side energy efficiency 

technologies and practices. It does not represent an EPA 

forecast of business-as-usual impacts of state energy efficiency 

policies or an EPA estimate of the full potential of end-use 

energy efficiency available to the power system, but rather 

represents a feasible policy scenario showing the reductions in 

fossil fuel-fired 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, 
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municipal and cooperative electric utilities as well as state 

agencies and third-party administrators. These include energy 

efficiency programs,153 building energy codes, state appliance 

standards (for appliances without federal standards), tax 

credits, and benchmarking requirements for building energy 

use.154 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 standards155 (EERS) to drive 

 

153 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.

154 See the Existing State Actions TSD for descriptions of the 

full array of demand-side energy efficiency policies currently 

employed by states. 

155 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 
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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.156 The 1.5 percent savings rate is inclusive of, 

not additional to, existing state energy efficiency 

requirements. These savings levels are realized exclusively 

through the adoption and implementation of energy efficiency 

programs. The energy savings data underpinning these analyses 

are derived from energy efficiency program reports required by 

state public utility commissions and other entities with a 

similar oversight role.157 These state commissions define and 

oversee the analysis and reporting requirements for energy 

 

efficiency, have been the most impactful state energy efficiency 

strategies in recent years.

156 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 

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

Greenhouse Gas Abatement Measures TSD for more information.

157 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. 
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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.158 

While EM&V data reflect documented electricity savings from 

energy efficiency programs, they typically do not account for 

potential electricity savings available from additional stateimplemented policies for which EM&V protocols are less 

consistently required or applied, such as building energy codes. 

Thus, we consider the 1.5 percent annual incremental savings159

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 cost-effectively by all states 

given adequate time. If we were to capture the potential for 

additional policies, such as the adoption and enforcement of 

 

158 See the EM&V section of the state Plan TSD for more 

information on EE program evaluation. 

159 This incremental savings rate and all others discussed in 

this section 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. 
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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 with more limited EE program experience, 

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 rate160 to a 

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

(Thus, the goal for each state differs to reflect the assumption 

that a state already close to a 1.5 percent annual incremental 

savings rate can expand its energy efficiency programs to reach 

that rate sooner than 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.161

For states already at or above the 1.5 percent annual 

incremental savings rate (based on 2012 reported data), we 

 

160 2012 is the most recent year for energy efficiency program 

incremental savings data reported using EIA Form 861.

161 See the Greenhouse Gas Abatement Measures TSD for more 

information. 
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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 achieved162 and 

is then maintained at that level through 2029 The savings from 

energy efficiency programs are cumulative, meaning that, in 

simplified terms, a state implementing a sustained program with 

a 1.5 percent annual incremental savings rate could expect 

cumulative annual savings of approximately 1.5 percent after the 

first year, 3.0 percent after the second year, 4.5 percent after 

the third year, and so on. Savings from the first year would 

drop off at the end of the average life of the energy efficiency 

program portfolio (typically about ten years). Accordingly, we 

have projected the cumulative annual savings for each state that 

would be achieved for the period 2020 to 2029 based on the 

state’s reaching and then sustaining the best practices annual 

incremental savings rate through 2029. These values, for each 

 

162 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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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 is relaxed by using 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 requirements will cause to be achieved - by 20 

states.163 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 

 

163 See the Greenhouse Gas Abatement Measures TSD for more 

information.
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stringent alternative are discussed in the Greenhouse Gas 

Abatement Measures TSD and summarized in Table 5. 

Table 5: Demand-Side Energy Efficiency State Goal Development: 

Cumulative Annual Electricity Savings (Percentage of Annual 

Sales) Resulting from Best Practices Scenario164

State 1.5% Savings 

Target Scenario 

1.0% Savings 

Target Scenario 

2020 2029 2020 2024 

 Alabama 1.4% 9.5% 1.1% 3.9% 

 Alaska 1.2% 9.5% 0.9% 3.7% 

 Arizona 5.2% 11.4% 3.5% 6.0% 

 Arkansas 1.5% 9.7% 1.2% 4.1% 

 California 5.0% 11.6% 3.6% 6.1% 

 Colorado 3.9% 11.0% 3.3% 5.9% 

 Connecticut 4.7% 11.9% 3.6% 6.3% 

 Delaware 1.1% 9.5% 0.9% 3.6% 

 Florida 2.0% 10.0% 1.8% 4.7% 

 Georgia 1.8% 9.8% 1.5% 4.4% 

 Hawaii 1.3% 9.5% 1.0% 3.8% 

 Idaho 3.8% 11.1% 3.5% 5.9% 

 Illinois 4.4% 11.6% 3.5% 6.2% 

 Indiana 3.2% 11.1% 2.9% 5.7% 

 Iowa 4.7% 11.7% 3.6% 6.0% 

 Kansas 1.2% 9.5% 0.9% 3.7% 

 

164 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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 Kentucky 1.9% 10.0% 1.6% 4.6% 

 Louisiana 1.1% 9.3% 0.9% 3.6% 

 Maine 5.4% 12.1% 3.6% 6.3% 

 Maryland 4.2% 11.5% 3.5% 6.1% 

 Massachusetts 4.4% 11.8% 3.6% 6.2% 

 Michigan 4.6% 11.8% 3.6% 6.2% 

 Minnesota 4.8% 11.7% 3.6% 6.2% 

 Mississippi 1.4% 9.6% 1.1% 3.9% 

 Missouri 1.6% 9.9% 1.3% 4.2% 

 Montana 3.4% 10.9% 3.0% 5.7% 

 Nebraska 2.2% 10.4% 1.9% 4.9% 

 Nevada 3.0% 10.7% 2.7% 5.5% 

 New Hampshire 2.8% 11.0% 2.6% 5.5% 

 New Jersey 1.3% 9.6% 1.0% 3.7% 

 New Mexico 3.1% 10.6% 2.8% 5.5% 

 New York 4.4% 11.8% 3.5% 6.2% 

 North Carolina 2.4% 10.3% 2.1% 5.0% 

 North Dakota 1.4% 9.7% 1.1% 4.0% 

 Ohio 4.2% 11.6% 3.5% 6.1% 

 Oklahoma 1.9% 10.0% 1.6% 4.5% 

 Oregon 4.7% 11.4% 3.6% 6.1% 

 Pennsylvania 4.7% 11.7% 3.6% 6.2% 

 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% 
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 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 and believes that this 

represents a technically feasible approach to reducing 

greenhouse gas emissions from the existing fossil fuel-fired 

EGUs. 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, 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 
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service demands. Indeed, a major reason for the widespread 

presence and rapid growth of demand-side energy efficiency 

programs is the strong evidence of their cost-effectiveness even 

before the additional benefit of CO2 reductions is considered.165

Independent studies have found that end-users’ needs for energydependent 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.166 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.167

 

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

their evaluations of cost effectiveness.

166 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/.

167 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 
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 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, EPA has included a cost escalation factor to represent 

the possibility of increased costs associated with higher levels 

of incremental energy savings rates and the national scope of 

the best practices scenario. 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 EPA 

 

demand-side energy efficiency programs, implementation of such 

programs is likely to be a highly cost-effective approach to 

reducing CO2 emissions even for a state whose own affected EGUs 

achieve only part of the CO2 emission reduction benefit from the 

state’s demand-side energy efficiency efforts. 
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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 $54/MWh (2011$).168 

 To estimate the reductions in power system costs and CO2

emissions associated with the best practices level of demandside energy efficiency described above, 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 

 

168 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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(IPM) described previously. Combining the resulting power system 

cost reductions with the energy efficiency cost estimates 

associated with the best practices scenario, EPA derived net 

cost impacts for 2020, 2025, and 2030. Dividing these net cost 

impacts by the associated CO2 reductions for each year, EPA found 

that the average cost of the CO2 reductions achieved ranged from 

$16 to $24 per metric ton of CO2. EPA views these estimated costs 

as reasonable. Together with the history of demonstrated 

successful state implementation of cost-effective demand-side 

energy efficiency programs discussed above, this analysis 

supports the reasonableness of the level of demand-side energy 

efficiency represented by the best practices scenario and, by 

extension, the reasonableness of the emission reductions at 

affected EGUs that can be achieved consistent with achievement 

of that level of demand-side energy efficiency. 

 Further details regarding the data and methodology used to 

evaluate the potential for demand-side energy efficiency 

programs to substitute for generation at affected EGUs and 

thereby facilitate reductions of power sector CO2 emissions at 

reasonable costs are provided in the Greenhouse Gas Abatement 

Measures TSD. We invite comment on all aspects of our data and 

methodology as discussed above and in the TSD, as well as on the 

level of reductions we propose to define as best practices 
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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 incremental annual 

electricity savings, and 3) alternative approaches and/or data 

sources for evaluating costs associated with implementation of 

state demand-side energy efficiency policies. 

5. Potential emission reduction measures not used to set 

proposed goals 

 There are three additional potential measures for reducing 

GHG emissions from EGUs that the EPA does not propose to 

consider part of the best system of emission reduction for 

existing EGUs at this time and therefore has not used for goalsetting purposes, but that merit discussion here: fuel switching 

at individual EGUs, carbon capture and storage (CCS), and 

reducing emissions at affected fossil fuel-fired steam EGUs by 
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using expanded amounts of less carbon-intensive new NGCC 

capacity to provide replacement generation. 

 a. Fuel switching at individual units 

 One technically feasible approach for reducing CO2 emissions 

per MWh of generation from an EGU designed for coal-fired 

generation is to substitute natural gas for some or all of the 

coal. Most existing coal-fired steam EGU boilers can be modified 

to switch to 100 percent gas input or to co-fire gas with coal 

in any desired proportion. For certain individual EGUs, 

switching to or co-firing with gas may be an attractive option 

for reducing CO2 emissions. 

 Changing the type of fuel burned at a steam EGU typically 

requires certain plant modifications (e.g., new burners) and may 

have some negative impact on the net efficiencies of the boiler 

and the overall generation process. If the plant lacks existing 

gas pipeline infrastructure capable of delivering the necessary 

quantities of natural gas to the boiler, installation of a new 

pipeline lateral would also be required. 

 The capital costs of plant modifications required to switch 

a 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 
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pipeline built. Offsetting these capital costs, conversion to 

100 percent gas input would typically reduce the EGU’s fixed 

operating and maintenance costs by about 33 percent due mainly 

to certain equipment retirements and a reduction in staffing, 

while non-fuel variable costs would be reduced by about 25 

percent due to reduced maintenance and waste disposal costs. 

However, in most cases, the most significant cost change 

associated with switching from coal to gas in a coal-fired 

boiler is likely to be the difference in fuel cost. Using EIA’s 

projections of future coal and natural gas prices, switching a 

steam EGU’s fuel from coal to gas typically would more than 

double the EGU’s fuel cost per MWh of generation. 

 The CO2 reduction potential of natural gas co-firing or 

conversion is due largely to the different carbon intensities of 

coal and natural gas and is directly related to the proportion 

of gas burned. Greater reductions in the CO2 emission rate are 

achieved at higher proportions of gas usage. For example, at ten 

percent gas co-firing, the net emission rate (e.g., pounds of CO2

per net MWh of generation) of a typical steam EGU previously 

burning only coal would decrease by approximately four percent. 

At 100 percent gas burn, the net emission rate of a typical 

steam EGU previously burning only coal would decrease by 

approximately 40 percent. 
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 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 

co-firing. As a result, the EPA has not proposed at this time to 

include this option in the BSER and has not incorporated 

implementation of the option into the proposed state goals. 

However, the EPA believes that there are a number of factors 

that warrant further consideration in determining whether the 

option should be included. First, the EPA is aware that a number 

of utilities have reworked some of their coal-fired units to 

allow for some level of natural gas co-firing (and in some cases 

have converted the units to fire entirely on natural 

gas). Second, the EPA is aware of several possible reasons 

beyond reduction of CO2 emissions that may make natural gas co-
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firing economic in some circumstances. One example is that 

natural gas reburn strategies that involve co-firing with 10 to 

20 percent natural gas can be an effective control strategy for 

NOx emissions and, thus, can offset operational (and in some 

cases, capital) costs associated with other NOx controls such as 

SCR or SNCR. A second example suggested by some vendors is that 

the capability to burn natural gas in a coal-fired boiler can 

improve economics because it allows the boiler to operate more 

effectively at lower loads. A third example, applicable to units 

that run infrequently but may be needed for reliability 

purposes, is that converting to or co-firing with natural gas 

may be more economic than either installing non-CO2 emission 

controls or taking other measures, such as transmission 

upgrades, that could be associated with retiring the 

unit. Finally, beyond the reasons just described 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 
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 Another possible approach for reducing CO2 emissions from 

existing fossil fuel-fired EGUs is through the application of 

carbon capture and storage169 technology (CCS). In the recently 

proposed standards of performance for new fossil fuel-fired EGUs 

(79 FR 1430), the EPA proposed to find that the best system of 

emission reduction for new fossil fuel-fired boilers and IGCC 

units is partial application of CCS. In that proposal, the EPA 

found that, for new units, partial CCS has been adequately 

demonstrated; it is technically feasible; it can be implemented 

at costs that are not unreasonable; it provides meaningful 

emission reductions; and its implementation will serve to 

promote further development and deployment of the technology. 

The EPA also noted in the proposal that most of the relatively 

few new boiler and IGCC EGU projects currently under development 

are already planning to implement CCS; and, as a result, the 

proposed standard would not have a significant impact on 

nationwide energy prices. 

In contrast, the EPA did not identify full or partial CCS 

as the BSER for new natural gas-fired stationary combustion 

turbines, noting technical challenges to implementation of CCS 

at NGCC units as compared to implementation at new solid fossil 

 

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

sequestration.”
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fuel-fired sources. The EPA also noted that, because virtually 

all new fossil fuel-fired power projects are projected to use 

NGCC technology, requiring full or partial CCS would have a 

greater impact on the price of electricity than requiring CCS at 

the few projected coal plants, and the larger number of NGCC 

projects would make a CCS requirement difficult to implement in 

the short term. 

 Partial CCS has been demonstrated at existing EGUs. It has 

been demonstrated at a pilot-scale at Southern Company’s Plant 

Barry; it is being installed for large-scale demonstration at 

NRG’s W.A. Parish facility; and it is expected soon to be 

applied at commercial-scale as a retrofit at SaskPower’s 

Boundary Dam plant in Canada. However, the costs of integrating 

a retrofit CCS system into an existing facility would be 

expected to 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 
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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, but does not expect to finalize CCS as a 

component of BSER in this rulemaking. It should be noted, 

however, that in light of the fact that several existing fossilfired EGUs are currently being retrofitted with CCS, the 

implementation of partial CCS may be a viable GHG mitigation 

option at some facilities, and as a result, emission reductions 

achieved through use of the technology could be used to help 

meet the emission performance level required under a state plan. 

Additional discussion can be found in the Greenhouse Gas 

Abatement Measures TSD. We invite comment on this proposed 

finding. 

c. New NGCC capacity 

 In subsection 2 above, we discussed the opportunity to 

reduce CO2 emissions by replacing generation at high carbonintensity affected EGUs with generation from lower-carbon 

generation from existing NGCC units.170 From a technical 

perspective, the same potential would exist to replace highemitting generation with generation from additional NGCC 

capacity that may be built in the future; the analysis above 

 

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

construction as of January 8, 2014 are “existing” units. 
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regarding the feasibility of policies to increase utilization 

rates of existing NGCC units on average to 70 percent applies 

equally to new NGCC units.171 We view the opportunity to reduce 

CO2 emissions at affected EGUs by means of addition and operation 

of new NGCC capacity as clearly feasible. 

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 could be 

somewhat more costly. Some amount of new NGCC capacity (beyond 

the units that were already under construction as of January 8, 

2014 and are “existing” units for purposes of this proposal) 

would likely be built to meet perceived electricity market 

demand or to replace less economic capacity regardless of this 

proposal. The costs of achieving CO2 emission reductions through 

re-dispatch to these new NGCC units and through re-dispatch to 

existing NGCC units would be comparable. 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 

 

171 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 more carbonintensive existing EGUs. Because the proposed state goals also 

reflect the opportunity to reduce utilization of high carbonintensity EGUs by shifting generation to less carbon-intensive 

EGUs, we believe that in the context of a comprehensive state 

plan, the necessary incentives would likely exist, in which case 

adding new NGCC capacity would tend to reduce CO2 emissions. 
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achieving CO2 reductions at affected EGUs, some portion of their 

construction or fixed operating costs might also be attributable 

to the CO2 reduction opportunity, increasing to some uncertain 

extent the cost of the CO2 reductions at affected EGUs achieved 

through re-dispatch to those new NGCC units. 

Moreover, unlike generation from other types of potential 

new generating capacity such as wind, solar, and nuclear 

capacity, NGCC generation does produce CO2 emissions. Because of 

this distinction it is less apparent that addition of new NGCC 

capacity, as opposed to those other types of capacity, should be 

a primary building block of a strategy for reducing CO2 emissions 

from the power sector. We therefore do not propose any “best 

practices” quantities of new NGCC capacity to include in state 

goals. 

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 is comprised only 

of building blocks 1 and 2 with the merits of a BSER that is 

comprised of all four building blocks - the preferred option in 

this proposal. (A more detailed discussion of how we evaluated 
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each option against the criteria to be considered the BSER 

follows in section VI.E.) 

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 

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 comprised of only 

strategies within building block 1. As described earlier in 

subsection VI.B, the EPA concluded that certain strategies 

within building block 1 – specifically heat rate improvements at 
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individual coal-fired steam EGUs - should be a component of the 

BSER determination, as they are technically feasible and can be 

implemented at a reasonable cost. However, the EPA further 

concluded that, while heat rate improvements qualify as a system 

of emission reduction, they are not in themselves the BSER as 

there are additional strategies that can be utilized in 

combination with building block 1 that are technically feasible, 

can be implemented at reasonable cost, and result in greater 

emission reductions than would be achieved through building 

block 1 strategies alone. The EPA is also concerned that if the 

measures that improve heat rates at coal-fired steam EGUs in 

building block 1 are implemented in isolation, without 

additional measures that reduce overall electricity demand or 

encourage substitution of less carbon-intensive generation for 

more carbon-intensive generation, the resulting increased 

efficiency of coal-fired steam units would provide incentives to 

operate those EGUs more, leading to smaller overall reductions 

in CO2 emissions. Further, in listening sessions and other 

outreach meetings, the EPA learned that states and other sources 

were already implementing and pursuing strategies in the other 

building blocks for the purpose, at least in part, of reducing 

CO2 emissions. 
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2. A combination of building blocks 1 and 2 as the Best System 

of Emission Reduction 

We considered a BSER that is comprised of 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 comprised of these two 

building blocks is that it involves only affected EGUs and 

generation from affected EGUs. 

The EPA believes that the combination of building blocks 1 

and 2 would be a “system of emission reduction” capable of 

achieving significant reductions in CO2 emissions from affected 

EGUs at a reasonable cost. As discussed in subsection 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 
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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 it fails to 

encompass the additional measures – building blocks 3 and 4 – 

that we and stakeholders have identified as already in use and 

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 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 
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and 2” available in the docket. We invite comment on a potential 

BSER comprised of 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 subsection VI.C above, each of 

the four building blocks is a proven way to support either 

improvements in emissions rates at affected EGUs or reductions 

in EGU mass emissions; each is in widespread use and is 

independently capable of supporting significant CO2 reductions 

from affected EGUs, either on an emission rate or mass-emissions 

basis, at a reasonable cost consistent with ensuring system 

reliability. As discussed in subsection 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 electric system, where 

electricity is fungible and the demand for electricity services 

can be met in many ways (including through demand-side energy 
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efficiency), states and the industry have long pursued a wide 

variety of strategies for ensuring that the demand for 

electricity services is met reliably, at reasonable costs, and 

in a manner consistent with evolving constraints, including 

environmental objectives. These strategies have long extended to 

the measures in all four building blocks. We believe the 

combination of all four building blocks fairly represents the 

range of measures that states and the industry will consider 

when developing state plans and strategies for reducing CO2

emissions from affected EGUs while continuing to meet demand for 

electricity services reliably and affordably. As such, 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 

 The EPA is proposing that the measures in the four building 

blocks described in the preceding subsections are essential 

features of the “best system of emission reduction ... 

adequately demonstrated” (BSER) for the standards of performance 

that the section 111(d) state plans must apply to affected EGUs. 

Specifically, the EPA is proposing alternative formulations for 

the BSER. Under one approach, emission rate improvements and 
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mass emission reductions 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 an alternate approach, BSER consists of building block 1 

coupled with reduced utilization in specified amounts from 

higher-emitting 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 nine 

subsections. Subsection 2 contains a summary of relevant 

considerations for the BSER as defined in the statute and 

further interpreted in court decisions. Subsection 3 discusses 

characteristics of the electricity industry relevant to 

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 
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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. In 

subsection 6, we describe and seek comment on the alternate 

interpretation that the BSER includes, in addition to one or 

more of the building blocks, a component consisting of reduced 

generation from 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 7 we discuss the discretion that the case law gives 

us in weighing the various criteria to determine the BSER. 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”: 
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The term “standard of performance” means a standard for 

emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of 

the best system of emission reduction which (taking into 

account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy 

requirements) the Administrator determines has been 

adequately demonstrated. 

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

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

Circuit or Court) has handed down case law over a 40-year period 

that interprets this CAA provision, including its component 

elements.172 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, 

 

172 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); 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). 
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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.173 

 The EPA must also consider that CAA section 111 is designed 

to promote the development and implementation of 

technology. 

Another consideration particularly relevant to this 

rulemaking is energy impacts, which, as with costs, 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, 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. 

Importantly, the EPA has discretion to weigh these various 

considerations, may determine that some merit greater weight 

 

173 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 427, 433 (D.C. Cir. 1973), see Lignite 

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

“greater than the industry could bear and survive,” Portland 

Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or 

“excessive” or “unreasonable,” Sierra Club v. Costle, 657 F.2d 

298, 343 (D.C. Cir. 1981). 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. 
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than others, and may vary the weighting depending on the source 

category. 

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 in this rulemaking. 

 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 is costly to store, 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 (ISO/RTOs), and market mechanisms. The electricity 

sector is both critical to the nation’s economy and the source 
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of more than 30 percent of U.S. greenhouse gas emissions, 

predominantly in the form of CO2. 

The integrated electricity system allows increased 

generation from less carbon-intensive NGCC units to substitute 

for generation from more carbon-intensive steam EGUs (building 

block 2), thereby lowering CO2 emissions from the group of 

affected EGUs as a whole. The electricity system similarly 

allows increased generation resulting from expansion of the 

amount of available low- or zero-carbon generating capacity 

connected to the electric grid (building block 3), as well as 

avoided generation resulting from reductions in electricity 

demand (building block 4), to substitute for fossil fuel-fired 

generation, thereby reducing CO2 emissions from affected EGUs. 

Each of these measures already routinely occurs within this 

integrated system for providing electricity and electricity 

services. 

The integrated nature of the electricity system has long 

played a central role in the industry’s continuing efforts to 

assure reliability and to manage costs generally. Specifically 

in the area of pollution control, state governments and the 

federal government have repeatedly taken advantage of the 

integrated nature of the electricity system when designing 

programs to allow the industry to meet the pollution control 
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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 

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.174 Each of 

these programs was designed to take advantage of the fact that 

in an integrated electricity system, some EGUs can reduce 

emissions more cost-effectively than others, and that by 

allowing the industry to determine through market mechanisms 

which EGUs to control, and potentially operate more, and which 

to leave uncontrolled, and potentially operate less, overall 

compliance costs can be reduced. The integrated electricity 

system plays the important function of allowing some EGUs to 

 

174 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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reduce their generation while ensuring that overall electricity 

demand can be reliably met. It is worth noting that adoption by 

affected EGUs of any of the measures in the building blocks 

could be (or could have been) used to facilitate compliance with 

each of the programs just described. 

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.175 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 

 

175 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 2050.176 According to California, “the integrated 

nature of the 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.”177 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.178 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 

 

176 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. 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy. 

178 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.179 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.180 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 

 

179 The requirement to hold allowances covering their CO2

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

2013. 

180 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.181 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. 

Regional mechanisms with analogous impacts on both longerterm planning decisions and short-term dispatch decisions have 

also been put in place. For example, nine northeastern and MidAtlantic States182 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 

 

181 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. 

182 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.183 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 electric 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 electricity demand in a costeffective 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 

 

183 See RGGI website at http://www.rggi.org/rggi. 
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(with consideration of building blocks 1 and 2),184 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. 

Importantly, experience has shown that because the grid is 

interconnected, CO2 emissions reductions can be achieved through 

several different mechanisms, which differ primarily in their 

timing and in the extent of their advance planning: (i) 

Establishing and implementing a plan in advance under which a 

specific amount of generation from higher-emitting fossil fuel-

 

184 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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fired EGUs is substituted for the same amount of generation 

from, or avoided from, specific measures in building blocks 2, 

3, and 4. (ii) Instituting measures in building blocks 2, 3, and 

4, which, because of the interconnected nature of the grid, 

result in drawing utilization away from higher-emitting fossil 

fuel-fired EGUs, even in the absence of a plan in advance that 

targets those EGUs. (iii) Reducing utilization from higheremitting fossil fuel-fired EGUs, which because of the 

interconnected nature of the grid and its operation in the 

regulated markets, leads to the measures in building blocks 2, 

3, and 4 that develop or utilize replacement generation or 

demand-side energy efficiency, even in the absence of a plan in 

advance that includes those measures. The existence of these 

mechanisms supports what we propose in this rulemaking as the 

two alternative “best system[s] of emission reduction ... 

adequately demonstrated,” as discussed below. 

4. Evaluation of individual building blocks against the BSER 

criteria 

In this section 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 BSER as including 

reduced utilization of higher-emitting generating capacity in 
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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 

BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable through heat rate improvements are discussed in 

section VI.C.1 above. We consider heat rate improvement to be a 

common and well-established practice within the industry. 

 Other BSER criteria also favor building block 1 as a 

component of 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 

waste products. With respect to technological innovation, 

building block 1 encourages the spread of more advanced 
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technology to EGUs currently using components with older 

designs. The EPA has not considered whether enhanced maintenance 

practices leading to heat rate improvements might also lead to 

electric reliability improvements, but does not expect there 

would be any negative impact on reliability. 

 As noted above, the EPA is concerned about the potential 

“rebound effect” associated with building block 1 if applied in 

isolation. More specifically, we noted that in the context of 

the integrated electricity system, absent other incentives to 

reduce generation and CO2 emissions from coal-fired EGUs, heat 

rate improvements and consequent variable cost reductions at 

those EGUs would cause them to become more competitive compared 

to other EGUs and increase their generation, leading to smaller 

overall reductions in CO2 emissions (depending on the CO2

emission rates of the displaced generating capacity). However, 

we believe that this concern can be readily addressed by 

ensuring that the BSER also reflects other CO2 reduction 

strategies that discourage overall increases in coal-fired 

generation or fossil fuel-fired generation, thereby allowing 

building block 1 to be considered part of the BSER for CO2

emissions at affected EGUs. 

b. Building block 2 – re-dispatch 
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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 (including NGCC units under construction) – is a 

component of the BSER because the shifts in generation that it 

involves demonstrate that reducing mass CO2 emissions at higheremitting EGUs is technically feasible, will not jeopardize 

system reliability, is of reasonable cost, and meets the other 

requirements for a component of the BSER. 

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 
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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. There is a long-term industry trend away from 

coal-fired generation and toward NGCC generation. States can 

encourage this trend in a variety of ways. First, a state could 

use its permitting authority to impose limits on the hours of 

operation (or emissions) of individual steam generating units 

over a given time period. Second, a state could change the 

relative costs of generation for more carbon-intensive and less 

carbon-intensive generating units by imposing a cost on carbon 

emissions. A state could do so through any of several marketbased mechanisms. One would be to adopt an allowance-based 

system. An example is the Regional Greenhouse Gas Initiative, an 

allowance-based system in which sources purchase allowances in 

periodic auctions. Another way would be through a tradable 

emission rate system, under which the state would impose an 

emission rate limit on the steam generating unit that the unit 

could meet only by purchasing the right to average its emission 

rate with a unit with a lower rate, such as an NGCC unit. Most 

broadly, an allowance system would provide the greatest 

incentive for the most carbon-intensive affected sources to 

reduce emissions as much as possible so as to reduce their need 

to purchase allowances (or to allow them to sell un-needed 
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allowances), and the same would be true for a tradable emission 

rate system. 

The emission reductions achievable or supported by the 

application of building block 2 also perform well against other 

BSER criteria. For example, we expect that building block 2 

would have positive non-air health and environmental impacts. 

Coal combustion for electricity generation produces large 

volumes of solid wastes that require disposal, with some 

potential for adverse environmental impacts; these wastes are 

not produced by natural gas combustion. The intake and discharge 

of water for cooling at many EGUs also carries some potential 

for adverse environmental impacts; NGCC units generally require 

less cooling water than steam EGUs.185 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 the building block’s 

definition, the shifts in generation taking place under building 

block 2 occur entirely among existing EGUs subject to this 

 

185 Some NGCC units use air rather than water for cooling 

purposes. 
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rulemaking.186 Through application of this building block 

considered in isolation, some affected sources – mostly coalfired steam EGUs - would reduce their generation and CO2

emissions, while other affected sources – NGCC units – would 

increase their generation and CO2 emissions.187 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

 

186 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. 

187 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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emissions from a subset of those affected EGUs. 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, reduced 

generation from fossil fuel-fired steam EGUs is a component of 

the BSER. The potential to use increased generation from less 

carbon-intensive NGCC units would serve as a basis for 

quantifying the amounts of generation reductions and CO2 emission 

reductions at more carbon-intensive 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.6 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 

generating capacity, completion and use of new nuclear capacity, 
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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 BSER. 

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 can 

and do establish targets for procurement of renewable generating 

capacity. Moreover, a market for renewable energy certificates, 

which facilitates investment in renewable energy, is already 

well-established. In addition, 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 by substituting for their generation with 

generation from renewable energy. In addition, owners of 

existing nuclear units and new nuclear units 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 
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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, 

as discussed above renewable generation has grown quickly in 

recent years, and the EPA has seen no evidence that operators 

will be less able to cope with future growth than they have with 

rapid past growth. Further, if a state were concerned that 

increasing the use of NGCC capacity might create risks to 

reliability in the form of potential inadequacies in natural gas 

infrastructure, use of expanded renewable generation capacity 

could help address that concern. 
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The EPA believes that the performance of the nuclear 

measures in building block 3 against the other BSER measures is 

acceptable. With respect to encouragement of technological 

innovation, incentives for completion of new nuclear capacity 

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. Use 

of expanded nuclear capacity would be another way for a state to 

address any concern that increasing the use of NGCC capacity 

might create risks to reliability in the form of potential 

inadequacies in natural gas infrastructure. New nuclear units 

would have closed-cycle cooling systems with lower cooling water 

usage than some existing fossil fuel-fired EGUs; existing 

nuclear units may use amounts of cooling water comparable to the 

amounts used by those fossil fuel-fired steam EGUs. The EPA 

recognizes that nuclear generation poses unique waste disposal 

issues (although it avoids the solid waste issues specific to 

coal-fired generation). However, we do not consider that 

potential disadvantage of nuclear generation relative to fossil 

fuel-fired generation as outweighing nuclear generation’s other 

advantages as an element of building block 3. For all these 
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reasons, we consider building block 3 to be a component of the 

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

Finally, the EPA notes that under 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.6 below. 

d. Building block 4 – increased demand-side energy 

efficiency 

Building block 4 – reducing CO2 emissions at and reducing 

generation from affected EGUs by promoting demand-side energy 

efficiency that reduces the amount of generation required from 

affected EGUs – is a component of the BSER because the demandside energy efficiency is technically feasible and of reasonable 

cost, and meets the other requirements for a component of the 

BSER. 

The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the building block 4 are 

discussed in section VI.C.4 above. We consider demand-side 
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energy efficiency programs to be proven, well-established 

practices within the industry that are consistent with industry 

trends. States can and do 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 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 
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these reasons, the measures in building block 4 qualify as a 

component of the “best system of emission reduction ... 

adequately demonstrated.” 

The EPA notes that the alternative BSER discussed later 

would include a component consisting of reduced generation from 

affected EGUs, with demand-side energy efficiency serving as a 

basis for quantifying the amounts of generation reductions and 

consequent CO2 emission reductions that can be achieved while 

continuing to meet the demand for electricity services in a 

reliable and affordable manner. This alternate interpretation of 

the BSER is discussed in section VI.E.6 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 
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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 noted earlier. 

That concern is the potential for the heat rate improvements in 

building block 1, if implemented in isolation, to make coalfired steam EGUs more competitive compared to other EGUs and 

cause them to increase their generation, creating a “rebound 

effect” that would make building block 1 less effective at 

reducing CO2 emissions. As discussed above, building blocks 1 and 

2 each appear attractive or neutral with respect to each of the 

other BSER criteria. 

With respect to most of the BSER criteria, there is no 

reason to expect that the combination of building blocks 1 and 2 

would be evaluated differently than 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, 
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with the result that the reduction in CO2 emission rates of coalfired EGUs brought about by heat rate improvements would on 

average be accompanied by a reduction in CO2 emissions 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. 

By reducing overall generation from coal-fired EGUs, the 

combination of building blocks 1 and 2 also has the potential to 

raise the cost of emission reductions achievable through heat 

rate improvements relative to the cost if building block 1 were 

implemented in isolation.188 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 substantially 

increased. Second, although under the combination of building 

blocks 1 and 2 the volume of coal-fired generation would 

 

188 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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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. Some coal-fired EGUs could increase their 

generation. We would expect EGU owners to take these changes in 

EGU operating patterns into account when considering where to 

invest in heat rate improvements, with the result that there 

would be a tendency for such investments to be concentrated in 

EGUs whose generation output was expected to decrease the least 

(or to increase). This enlightened bias in spending on heat rate 

improvements 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 

comprised of 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 like 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 
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“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 it is well-established. 

Further, because the combination of all four building blocks 

would achieve greater CO2 emission reductions at a lower cost 

than the combination of building blocks 1 and 2 described above, 

and would also perform better against other BSER criteria, we 

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.189 

 Because the measures in building blocks 2, 3, and 4 involve 

the interconnected electricity grid, evaluating them against the 

criteria for the BSER involves certain considerations. The EPA 

discusses these in the Legal Memorandum, and summarizes them 

briefly below. 

The EPA’s proposal that the “system of emission reduction” 

includes the measures in building blocks 2, 3, and 4 is grounded 

in the EPA’s interpretation of the key CAA provisions: section 

 

189 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2 

applies to the combination of all four building blocks as well. 

The EPA believes that 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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111(d)(1), which 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), which 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 system that reduces the 

affected sources’ emissions. As discussed in the Legal 

Memorandum, the EPA is justified in adopting this interpretation 

under the first step of the framework for administrative 

agencies to construe statutes that the U.S. Supreme Court 

established in Chevron U.S.A. Inc. v NRDC, 467 U.S. 837, 842-844 

(1984) (Chevron), which we refer to as Chevron step 1. 

Specifically, the term “system,” which is not defined in 

the CAA, is broad: “a set of things working together as parts of 

a mechanism or interconnecting network.”190 The remaining 

provisions of the definition of “standard of performance” do not 

 

190 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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include any constraints on the “set of things” that may 

constitute a “system of emission reduction.” Nor does the 

context in which “standard of performance” is found – the 

provisions of section 111(d)(1) – add constraints on the things 

that may constitute such a system. Rather, it is clear from 

these CAA provisions that anything that reduces the emissions of 

affected sources may be considered a “system of emission 

reduction” for those sources. For this reason, the measures in 

building blocks 2, 3, and 4 must be considered components of 

such a system. 

 Even if these CAA provisions leave room for interpretation 

as to whether those measures must be considered components of 

such a system, the EPA’s interpretation that they do is 

reasonable. As discussed in the Legal Memorandum, the EPA is 

justified in adopting this interpretation under the second step 

of the Chevron framework, which we refer to as Chevron step 2. 

There are several reasons. In enacting the CAA, Congress 

established “pollution prevention” as a “primary goal” of the 

Act, and described it as “the reduction or elimination, through 

any measures, of the amount of pollutants produced or created at 

the source.”191 Building blocks 2, 3, and 4 are pollution 

prevention measures, and, in light of the importance of 

 

191 CAA §101(a)(3), (c). 
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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.192 Further support is found in Title 

IV of the CAA, in which Congress established the program that 

regulates fossil fuel-fired power plants to reduce their 

emissions of SO2 and NOx, the precursors to acid deposition. In 

designing Title IV, Congress recognized the integrated nature of 

the electricity sector and how that integration could be 

harnessed to reduce air pollutant emissions; and, in fact, 

Congress included provisions to encourage re-dispatch to loweremitting sources, renewable energy, and demand-side energy 

efficiency, all of which are measures in those building 

blocks.193 All this supports the reasonableness of interpreting 

“system of emission reduction” in section 111 to incorporate 

 

192 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.) 

193 CAA §401(b), 404(f)-(g). 
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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 section 111(d) standards of performance 

on measures such as re-dispatch, renewable energy, and demandside energy efficiency.194 Some stakeholders have as well.195

 

194 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 

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.”). 

195 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_cost-
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 As described earlier with respect the individual building 

blocks, the measures in each of building blocks 2, 3, and 4 

qualify as components of the “best system of emission reduction 

... adequately demonstrated.” The evaluations above of the 

individual building blocks against the criteria for the BSER 

generally apply to the combination of all four building blocks 

as well. 

In addition, the measures in building blocks 2, 3, and 4 

are “adequately demonstrated” because, as discussed, due 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, some 

utilities, states and regions are already relying on these 

measures for the specific purpose of reducing CO2 emissions from 

EGUs. 

 Further, measures in building blocks 2, 3, and 4 may be 

undertaken by the affected EGUs themselves, which confirms that 

these measures are “adequately demonstrated.” 

 

effective_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). 
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Each state’s electric utility sector has unique 

circumstances, and 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. For instance, while 

the EPA’s BSER 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 
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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 EPA also 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 compliance time-frame, owners can consider 

longer-term options such as implementing energy efficiency 

programs or replacement of older generating resources with more 

modern types of generation, as well as 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 
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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.196 Within the 5-to-15-year planning horizon 

established in this proposal to begin in June 2015, most of 

these companies are likely to be investing in new generation and 

can consider options such as increased reliance on new renewable 

generating capacity. They also run energy efficiency programs 

for their customers. 

Municipal utilities and rural cooperatives that own their 

own generation also have multiple options for reducing CO2

emissions, particularly generation and transmission cooperatives 

and larger municipal utilities. The 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 

 

196 http://online.wsj.com/article/PR-CO-20140508-915605.html. 
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flexibility in the guidelines, these owners can use both shortterm dispatch strategies and longer-term capacity planning 

strategies to reduce GHG emissions. 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 multistate compliance strategies to increase the flexibility and 

cost-saving opportunities that would be available to the covered 

EGUs. 

Municipal utilities and rural cooperatives can face other 

challenges as well. In deregulated areas, even though they 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 where 

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 
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utilities and rural cooperatives that are already aggressively 

pursuing such strategies.197

Independent power producers (IPPs) may also face unique 

challenges but nevertheless have options. Most IPP generating 

units are natural gas-fired, but IPP owners with coal-fired EGUs 

can implement efficiency improvements as well as other unitlevel 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 do long-term business planning and 

therefore 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. In addition, many IPPs 

participate in markets that allow both generating resources and 

demand-side resources to compete, so even though they do not 

directly serve customers, they have opportunities to participate 

in demand-side energy efficiency programs. 

In a regulated state, if a company’s compliance strategies 

included reducing generation at higher-emitting EGUs, it would 

 

197 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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work through its state’s integrated planning process to ensure 

that adequate generation was available through a combination of 

all four building blocks. 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 loweremitting generation, and in some markets that treat demand-side 

resources on par with supply side resources, energy service 

companies would likely see opportunities. 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. 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 well-accepted 

CO2 reduction methods in the eyes of various stakeholders, as was 

clear from views expressed in our outreach process. 

Moreover, there are mechanisms through which states could 

require measures from any of the building blocks in state plans. 

In fact, the state plan formulation process through which 
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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.198 

As has also been discussed in earlier portions of the 

preamble, the costs and energy impacts of each of the four 

building blocks individually are not unreasonable 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 

 

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

section and elsewhere in the preamble. 
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more extensively in their plans and strategies on whichever 

measures best suit their particular circumstances will further 

improve cost-effectiveness. The analysis the EPA performed to 

assess the costs, benefits, and other impacts of the proposed 

goals reflects this compliance flexibility, along with 

transmission and pipeline capabilities and constraints, fuel 

market and electricity dispatch dynamics, and seasonal 

electricity load requirements. As described below in section X, 

the results indicate that the proposed state goals (discussed in 

section VII) are readily achievable with no adverse impacts on 

electric 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 cost effectiveness of the measures in the four building 

blocks in combination as the best system of emission reduction. 

We note that some stakeholders have argued that section 

111(a)(1) does not authorize the EPA to identify re-dispatch, 

low- or zero-emitting generation, or demand-side energy 
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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” 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 

emissions reductions at affected EGUs. Moreover, under our 

alternative approach, the “system of emission reduction” 

includes reductions in utilization at the affected sources 

themselves.199 It should also be noted that, as discussed above, 

 

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

6. Alternate interpretation of the best system of emission 

reduction 

 

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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As an alternative to the approach described above for 

determining the “best system of emission reduction ... 

adequately demonstrated,” the EPA believes the “system of 

emission reduction” may be identified as including, in addition 

to building blocks 1 and 2, the reduction of EGUs’ mass 

emissions achievable through reductions in generation of 

specified amounts from fossil fuel-fired EGUs. Under this 

approach, the measures in building blocks 3 and 4 would not be 

components of the BSER but instead would serve as bases for 

quantifying the reduction in emissions resulting from the 

reduction in generation at affected EGUs, and assuring that the 

reduced generation is “adequately demonstrated” because it could 

be achieved while continuing to meet the demand for electricity 

services in a reliable and affordable manner. Specifically, the 

amount of generation from the use of expanded low- and zerocarbon generating capacity that could be provided, and the 

amount of generation from fossil fuel-fired EUGs that could be 

avoided through the promotion of demand-side energy efficiency, 

would determine the amount of the fossil fuel-fired generation 

reduction component of the BSER. 

In a variation of this alternate interpretation of the 

BSER, instead of including building block 2 in the BSER, only 

the portion of building block 2 consisting of reductions in 
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generation at higher-emitting affected fossil fuel-fired steam 

EGUs would be included in the BSER. The portion of building 

block 2 consisting of increased generation at lower-emitting 

affected NGCC units would not be included in the BSER, but 

instead would serve as a basis for quantifying the amount of 

reduction in generation at higher-emitting affected EGUs that 

could achieved while continuing to meet the demand for 

electricity services in a reliable and affordable manner. Under 

this variation, to ensure that demand for electricity services 

can be met reliably, we propose that the amount of reduced 

generation from affected fossil fuel-fired steam EGUs is the 

amount of incremental generation that can be provided from 

affected NGCC units, and similarly we propose to find the cost 

of reduced generation from affected fossil fuel-fired steam EGUs 

reasonable only to the extent that the cost of the incremental 

generation from affected NGCC units is reasonable. 

Reduced generation is encompassed by the clear terms of the 

phrase “system of emission reduction” 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 reduced fuel input – that the affected 
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source may take to reduce its CO2 emissions.200 If that phrase is 

not considered clear by its terms, then it may reasonably be 

interpreted to include reduced generation.201 As discussed in the 

Legal Memorandum, the legislative history of the CAA indicates 

that Congress recognized that emitting sources could comply with 

pollution control requirements by reducing production, including 

retiring. 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.202 

Reduction of, or limitation on, the amount of generation is 

already a well-established means of reducing emissions of 

pollutants in the electric sector and not merely a theoretical 

option that is unavailable as a practical matter for sources 

that may have to operate 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 

 

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

“system of emission reduction” includes reduced generation. 

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

“system of emission reduction” includes reduced generation. 

202 See, e.g., Consent Decree, United States v. Wis. Power & 

Light Co., No. 13-cv-266 (W.D. Wis. filed Apr. 22, 2013), at 18, 

section IV, available at 

http://www2.epa.gov/sites/production/files/documents/wisconsinpo

wer-cd.pdf.
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with the Clean Air Act acid rain program in CAA title IV, as 

well as the transport rules that we refer to as the NOx SIP 

Call203 and the Clean Air Interstate Rule (CAIR).204 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” 

because it is technically feasible due to the 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. 

Likewise, we propose to find the cost of reduced generation from 

affected EGUs reasonable only to the extent that the costs of 

the measures meeting the demand for energy services in the 

absence of that reduced generation are reasonable. 

The levels of reduced generation proposed meet the criteria 

for the “best system of emission reduction ... adequately 

 

203 63 FR 57356 (Oct. 27, 1998). 

204 70 FR 25162 (May 12, 2005). 
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demonstrated.” The costs of the proposed levels of reduced 

generation are reasonable for the affected source category and 

the nation-wide electricity system, do not jeopardize 

reliability, and do promote the development and implementation 

of technology that is important for continued emissions 

reductions. This is because the extent to which the electrical 

grid operates through integrated generation, transmission and 

distribution networks creates fungibility for electricity and 

electricity services , which allows decreases in generation at 

one affected EGU to be seamlessly replaced by increased 

generation at a low- or zero-carbon EGU (building block 3) or by 

decreased demand (building block 4), or, in the variation 

described above, allows decreases in generation at affected 

fossil fuel-fired steam EGUs to be replaced by increases in 

generation at affected NGCC units (building block 2). These 

characteristics of the integrated electric system thereby make 

reduced generation a viable approach for achieving CO2 emission 

reductions by affected EGUs. 

As noted above, the measures in building blocks 2, 3, and 4 

are already in widespread use in the industry. At the levels 

proposed, they have the technical capability to substitute for 

reduced generation at some or all affected EGUs at reasonable 

cost. The NGCC capacity necessary to accomplish the levels of 
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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 higher-emitting EGUs may choose or be required to reduce 

their CO2 emissions by means of reducing their utilization. There 

are two reasons for this. First, the affected sources themselves 

could invest in new renewable energy resources and demand-side 

energy efficiency, as discussed above.205 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.206 

7. EPA’s discretion in applying the criteria for the best system 

of emission reduction 

 

205It 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. 

206 The nuclear generating capacity reflected in building block 3 

is already in operation or under construction. 
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As discussed above, each of the approaches to determining 

the “best system of emission reduction ... adequately 

demonstrated” entails applying the criteria described in the 

D.C. Circuit case law for evaluating 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. 

In the present rulemaking, the EPA is heavily weighting two 

criteria in particular: the amount of emissions reduction 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 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. Above, the EPA discusses this in the 

sections concerning the scientific background for this 

rulemaking. The EPA also considers it especially important in 

this rulemaking 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 
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practices is critical to making the substantial reductions in 

emissions that will be required during the next few decades to 

reduce the risks 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, 

environmental and energy effects of different technological 

systems....”207

8. Combined categories 

 As discussed above, the EPA is co-proposing combining the 

category of steam-generating EGUs and the category of combustion 

turbines (which include NGCC units) into a single category for 

fossil fuel-fired EGUs, for purposes of promulgating emission 

guidelines for CO2 emissions. The EPA solicits comment on whether 

combining the categories is, as a legal matter, a prerequisite 

for (i) identifying as a component of the BSER re-dispatch 

 

207 Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981). 
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between sources in the two categories (i.e., re-dispatch between 

steam-generating EGUs and NGCC units), or (ii) facilitating 

averaging or trading systems that include sources in both 

categories, which states may wish to adopt. 

9. 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. 

10. Solicitation of comment 

 We invite comment on all aspects of our proposed 

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, although, as 

noted, we are not soliciting comment on issues that were 

resolved by the implementing regulations and therefore are not 

being re-opened here. In particular, we invite comment on our 

analysis of the four building blocks as components of the BSER, 
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whether any other potential measures should be considered, and 

the legal, technical, and economic bases of our conclusions. 

With regard to comments received during the stakeholder 

meetings, some commenters noted that trading programs like RGGI 

have been successful at reducing GHGs, and other commenters 

provided specific BSER proposals based on trading and/or 

emissions averaging approaches. We specifically request comment 

on whether any of these approaches should be considered as the 

BSER. We also specifically invite comment on the question, 

raised by some stakeholders, as to whether if measures may be 

relied on in the state plan to achieve emissions reductions, 

they cannot be excluded from the scope of the BSER solely 

because they involve actions by entities or at locations other 

than affected sources. 

VII. State Goals 

A. Overview 

In this section, the EPA sets out proposed state-specific 

CO2 emission performance goals to guide states in development of 

their state plans. The proposed goals reflect the EPA’s 

quantification of each state’s average emission rate from 

affected EGUs that could be achieved by 2030 and sustained 

thereafter, with interim goals that would apply over a 2020-2029 

phase-in period, through reasonable implementation, considering 
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the unique circumstances of each individual state, of the 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 four building 

blocks, 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, adjusted208 output-weighted-average CO2 emission rates 

for affected EGUs. However, states are authorized to translate 

the form of the goal to a mass-based form, as long as the 

translated goal achieves the same degree of emission limitation. 

 The EPA is proposing that measures that a state takes after 

the date of this proposal and prior to the beginning of the plan 

period in 2020, and which result in CO2 emission reductions 

during the plan period, would apply toward achievement of the 

 

208 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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state’s CO2 goal. Thus, states with existing programs and 

policies, and states that put in place new programs and policies 

early, will be better positioned to achieve the goals. 

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. Emission goals for Indian country will 

be established in the future as necessary or appropriate, as 

provided for in the Tribal Authority Rule. 

With respect to Indian country, the EPA is soliciting 

comment on the application of the four BSER building blocks to 

determine CO2 emission performance goals for Indian country with 

affected EGUs. The EPA notes that some present and future 

actions taken to reduce criteria pollutants from EGUs in Indian 

country will result in significant CO2 emission reductions.209 As 

the EPA has done in setting state goals, the EPA would set 

emission performance goals for Indian country in a manner that 

would allow the jurisdictional authority to meet the goals 

through the use of a wide range of policies and practices 

 

209 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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capable of achieving CO2 emission reductions. If the EPA develops 

one or more federal plans for EGUs located in Indian country, we 

are currently considering doing so on a regional basis in 

coordination with plans being developed for neighboring states. 

The EPA solicits comment on such an approach for a federal plan. 

With respect to territories, the EPA requests comment on 

the appropriateness of the four building block approach for 

territories. In particular, the EPA solicits comment on 

appropriate alternatives for territories that do not have access 

to natural gas as well as on ways to determine appropriate 

renewable targets in the absence of the types of data used to 

develop the renewable component of BSER for states. 

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 
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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 implementation of the four building blocks (or 

alternative control methods). Several aspects of this proposed 

form of goal are worth noting at the outset: the use of an 

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

electricity generated), with the opportunity for the state to 

adopt a mass-based form (e.g., a cap on the tonnage of CO2

emissions); the use of output-weighted-average emission rates 

for all affected EGUs in a state rather than nationally uniform 

emission rates for all affected EGUs of particular types; the 

use of adjustments to accommodate measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation rather than by reducing the CO2 emission rate per MWh 

generated by affected sources; the use of emission rates 

expressed in terms of net rather than gross energy output; and 
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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. Defining emission 

performance levels in a rate-based form provides flexibility to 

accommodate changes in the overall quantities of electricity 

generated in response to increases in electricity demand. 

Defining emission performance levels in a mass-based form 

provides relative certainty as to the absolute emission levels 

that would be achieved as well as relative simplicity in 

accommodating and accounting for the emission impacts of a wide 

variety of emission reduction strategies. In light of these 

respective advantages, we propose to set an emission rate-based 

form of goal, and to allow any state to translate the rate-based 

goal to an equivalent mass-based emission performance level for 

state plan purposes. This approach allows each state to maximize 

the advantages it considers optimal and is consistent with the 

state flexibility principle that is central to the EPA’s 

development of this program. 
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 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 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 provide the next MWh of generation needed to meet 

demand, opportunities exist to manage utilization of high 

carbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this 

means that CO2 emission reductions can be achieved by shifting 

generation from EGUs with higher CO2 emission rates, such as 

coal-fired EGUs, to EGUs with lower CO2 emission rates, such as 

NGCC units. Our analysis indicates that shifting generation 

among EGUs offers opportunities to achieve large amounts of CO2

emission reductions at reasonable costs. These opportunities can 

be reflected in a goal established in the form of an outputweighted-average emission rate for multiple affected EGU types. 

Our approach is also consistent with the fact that the 
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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 associated with measures such as increases in lowand zero-carbon generating capacity and demand-side energy 

efficiency. We recognize that these measures reduce overall CO2

mass emissions from affected EGUs by reducing the quantity of 

generation from affected EGUs without necessarily reducing the 

weighted-average 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 
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avoid generation at affected EGUs could be used to help the 

state meet the rate-based emission performance level reflected 

in its plan. We note that adjustments of this nature are not 

necessary when a plan’s emission performance level is based on 

the mass of CO2 emissions210 rather than on CO2 emission rates, 

because the emission-reducing effects of reduced generation at 

affected EGUs are evident in the EGUs’ reported CO2 mass 

emissions. 

 The fourth aspect noted above concerns the proposed 

expression of the goals in terms of net energy output – 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.211 (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.) The 

difference between net and gross generation is the electricity 

 

210 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. 

211 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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used at a plant to operate auxiliary equipment such as fans, 

pumps, motors, and pollution control devices. Improvements in 

the efficiency of these devices represent opportunities to 

reduce carbon intensity at affected EGUs that would not be 

captured in measurements of emissions per gross MWh. Further, 

nearly all EGUs already have in place the equipment necessary to 

determine and report hourly net generation, and we believe that 

the proposed reporting requirement would therefore not be 

burdensome. However, we also recognize that at present EGUs 

report gross rather than net load212 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 

 

212 Some EGUs report gross steam output instead of gross 

electrical load. 
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VI above, upon which the goals are based. Because the building 

blocks are independent of each other and the goals are the sum 

of the emission reductions from all of the building blocks, if 

any of the building blocks are found to be invalid bases for the 

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

the goals would be adjusted to reflect the emissions reductions 

from the remaining building blocks. As noted above, the state 

goals that would result from any combination of the building 

blocks can be computed from data included in the Goal 

Computation TSD and its appendices using the methodology 

described below and in that TSD. 

We invite comment on all aspects of the proposed form of 

the goals, including suggestions for specific alternative forms 

of goals not discussed above that may also merit consideration. 

C. Proposed goals and computation procedure 

 The EPA has developed proposed goals for state plans 

reflecting use of all four building blocks described earlier. 

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. In addition to the final goals, 
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EPA has developed interim goals that would apply during the 

2020-2029 period on a cumulative or average basis as states 

progress toward the final goals. The proposed goals are set 

forth in Table 6 below, followed by a description of the 

computation methodology. (The issue of how states could 

demonstrate emission performance consistent with the interim and 

final goals is addressed in Section VIII on state plans.) 

Table 6: Proposed State213 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 

 

213 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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Florida 794 740 

Georgia 891 834 

Hawaii 1,378 1,306 

Idaho 244 228 

Illinois 1,366 1,271 

Indiana 1,607 1,531 

Iowa 1,341 1,301 

Kansas 1,578 1,499 

Kentucky 1,844 1,763 

Louisiana 948 883 

Maine 393 378 

Maryland 1,347 1,187 

Massachusetts 655 576 

Michigan 1,227 1,161 

Minnesota 911 873 

Mississippi 732 692 

Missouri 1,621 1,544 

Montana 1,882 1,771 

Nebraska 1,596 1,479 

Nevada 697 647 

New Hampshire 546 486 

New Jersey 647 531 
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New Mexico * 1,107 1,048 

New York 635 549 

North Carolina 1,077 992 

North Dakota 1,817 1,783 

Ohio 1,452 1,338 

Oklahoma 931 895 

Oregon 407 372 

Pennsylvania 1,179 1,052 

Rhode Island 822 782 

South Carolina 840 772 

South Dakota 800 741 

Tennessee 1,254 1,163 

Texas 853 791 

Utah * 1,378 1,322 

Virginia 884 810 

Washington 264 215 

West Virginia 1,748 1,620 

Wisconsin 1,281 1,203 

Wyoming 1,808 1,714 

* Excludes EGUs located in Indian country within the state. 

 The proposed goals are expressed as adjusted outputweighted-average emission rates for all affected EGUs in a 

state. As discussed earlier in this section, a goal expressed as 
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an unadjusted output-weighted-average emission rate would fail 

to account for mass emission reductions from reductions in the 

total quantity of fossil fuel-fired generation associated with 

state plan measures that increase low- or zero carbon generating 

capacity or demand-side energy efficiency. Accordingly, under 

the proposed goals, the emission rate computation includes an 

adjustment designed to reflect those mass emission reductions. 

The adjustment is made by estimating the annual net generation 

associated with an achievable amount of qualifying new 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.214 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 

 

214 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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adjustments to compliance measurement approaches under its state 

plan, thereby enabling the state to adopt an emission rate-based 

form of emission performance level while still being able to 

rely on low- or zero-carbon capacity deployment programs and 

demand-side energy efficiency as components of its plan.) 

 The methodology used to compute each state’s proposed goal 

is summarized on a step-by-step basis below. The methodology is 

described in more detail in the Goal Computation TSD, which 

includes a numerical example illustrating the full procedure. 

The development of the data inputs used in the computation 

procedure is discussed in section VI above and in the Greenhouse 

Gas Abatement Measures TSD. 

 Step 1 (compilation of baseline data). On a state-by-state 

basis, we obtained total annual quantities of CO2 emissions, net 

generation (MWh), and capacity (MW) from reported 2012 data for 

all affected EGUs.215 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 

 

215 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. 
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(IGCC) units and any simple-cycle combustion turbines satisfying 

the size and electricity sales thresholds for qualification as 

affected EGUs) as a fourth, “other” group.216 To these totals for 

affected EGUs operating in 2012, we added estimates for other 

EGUs not yet in operation in 2012 that are affected EGUs for 

purposes of this emission guideline.217 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 

 

216 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. 

217 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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rates across the existing fleet of coal-fired steam EGUs through 

heat rate improvements that is technically achievable at a 

reasonable cost. 

 Step 3 (application of building block 2). If the generation 

data for the NGCC group in a state developed in Step 1 showed 

average annual utilization below 70 percent of those units’ 

maximum possible output, and the generation data developed in 

Step 1 also included generation from the coal-fired steam or 

oil/gas-fired steam EGU groups in that state, the generation and 

emissions figures for the NGCC group were increased, and the 

generation and emissions figures for the coal-fired and oil/gasfired steam EGU groups from Step 2 were proportionately218

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 

 

218 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. 
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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.219 

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

total quantities of generation from renewable generating 

capacity and new or preserved nuclear capacity for each state 

under the “best practices” approaches discussed 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 new 

and preserved nuclear capacity for each state operated at a 

utilization rate of 90 percent, consistent with recent industrywide 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 by implementation in that state of a comprehensive “best 

practices” approach to demand-side energy efficiency programs 

resulting in annual incremental reductions in the state’s 

electricity usage (relative to usage absent those programs) of 

 

219 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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1.5 percent each year. Separate estimates were developed for 

each year to reflect the fact that energy efficiency programs 

that are implemented on an ongoing basis would be expected to 

produce larger cumulative impacts on total annual electricity 

usage over time. For states that are net importers of 

electricity, the estimated reduction in the generation by the 

state’s affected EGUs was scaled down to reflect an expectation 

that a portion of the generation avoided by the demand-side 

energy efficiency would occur at EGUs in other states. 

 Step 6 (computation of annual rates). We computed adjusted 

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.220

 

220 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.] 
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We performed these computations separately for each year from 

2020 to 2029, using the respective cumulative annual MWh savings 

figures developed in Steps 4 and 5. 

 Step 7 (computation of interim and final goals). The final 

2030 goal for each state is the annual rate computed for 2029 

for the state from Step 6 above. We computed the 2020-2029 

interim goal for each state as the simple average of the annual 

rates computed for each of the years from 2020 to 2029 for the 

state from Step 6 above. 

 It bears emphasis that the procedure described above is 

proposed to be used only to determine state goals, and the 

particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

specific requirements applicable to individual EGUs, to the EGUs 

in a given state collectively, or to other affected entities in 

the state would be based on the standards of performance 

established through that state’s plan. The details of how states 

could attain emission performance levels consistent with the 

goals through different state plan approaches that recognize 

emission reductions achieved through all the building blocks are 

discussed further in section VIII on state plans. 

 
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 We invite comment on all aspects of the goal computation 

procedure. (Note that we also invite comment on certain specific 

alternate data inputs to the procedure in Section VI.C above.) 

We also specifically invite comment on the state-specific 

historical generation and capacity 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 
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generation avoided by the demand-side energy efficiency efforts 

of other, net electricity-importing states would occur at those 

EGUs, analogous to the proposed adjustment for net importing 

states described in Step 5. We also request comment on the 

alternative of making no adjustment in Step 5 for either net 

electricity-importing or net electricity-exporting states. These 

alternatives are discussed in the Goal Computation TSD. 

We also request comment on whether CO2 emission reductions 

from 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 compliance 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 
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application of the control measures that the EPA identifies as 

the BSER, they need not mandate the particular control measures 

the EPA identifies as the basis for its BSER determination. In 

developing the building block data inputs applied to each 

state’s historical capacity and generation 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 measures that 

are not included in the building blocks. 

Further, by allowing states to demonstrate compliance over 

a multi-year interim plan period of as long as ten years, the 

EPA’s proposed approach increases states’ flexibility to choose 

among alternative potential 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 
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to defer imposition of requirements on EGUs that may be 

scheduled to retire after 2020 but before 2029. 

 The second type of flexibility noted above is that while 

the EPA is proposing to establish goals in an emission ratebased form, we are also proposing to provide states with the 

flexibility to translate the rate-based goals to mass-based 

goals in order to accommodate states’ potential interest in 

having emission performance requirements measured in absolute 

tons. For example, the northeastern states that currently 

participate in the mass-based Regional Greenhouse Gas Initiative 

(RGGI) may choose to develop state plans 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 program. Because the use of 

mass-based plans can simplify the process of accounting for the 

CO2 reduction impacts of a variety of measures, the EPA believes 

the flexibility to adopt mass-based emission performance levels 

can facilitate plan development and could be attractive to 

states that do not already participate in mass-based 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 
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attractive to states. For example, the RGGI-participating states 

could choose to submit a multi-state mass-based plan that 

demonstrates emission performance on a multi-state basis. 

Additional states may also choose to join a multi-state plan. 

The mechanics of translating rate-based goals into mass-based 

goals and demonstrating equivalency between the two forms and 

issues 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.221 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 preamble 

section II.D above, the EPA promulgated implementing regulations 

 

221 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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in 1975, and has revised parts of them since. The regulations 

set out a multi-step process for the development and approval of 

state plans, and assign responsibility for the various steps in 

the process to the EPA or the states. The regulations provide 

that the EPA is to promulgate an “emission guideline that 

reflects the application of the best system of emission 

reduction (considering the cost of such reduction) that has been 

adequately demonstrated for” affected sources.222 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 

 

222 Id. 
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resolved by the implementing regulations.223 To reiterate, the 

proposed state goals represent the level of performance that is 

achievable through application of the BSER to the pertinent data 

for each individual state. States have the opportunity to 

comment on the proposed BSER, the proposed methodology for 

computing state goals based on application of the BSER, and the 

state-specific data that is proposed for use in the 

computations. We expect that the states will have an adequate 

opportunity to comment on the state goals during the comment 

period. Once the final goals have been promulgated, 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, 

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 

 

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

implementing regulations in this rulemaking. 
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will be able to achieve their final CO2 emission performance 

goals and that no special provision for state adjustment of 

goals outside the normal notice-and-comment rulemaking process 

is warranted.224

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. 

 The alternate goals reflect several differences in data 

inputs from the proposed goals. Specifically, a value of four 

percent (instead of six percent) was used for the potential 

improvement in carbon intensity of coal-fired EGUs in Step 2; a 

value of 65 percent (instead of 70 percent) was used for the 

 

224 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 §307(d)(7)(B). 
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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 best 

practices portfolio of demand-side energy efficiency programs in 

Step 5. (No change was made to the data inputs regarding less 

carbon-intensive generating capacity in Step 4.) As noted above, 

the alternate goals also reflect a shortening of the proposed 

phase-in period from ten years (2020-2029) to five years (2020-

2024) to reflect an expectation that less stringent goals could 

be achieved in less time. Steps 5, 6, and 7 of the goal 

computation procedure therefore were performed for the span of 

years from 2020 to 2024 rather than for the span from 2020 to 

2029. The alternate goals are set forth in Table 7 below. 

Table 7: Alternate State225 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 

Arkansas 1,083 1,058 

 

225 See footnote accompanying Table 6 above. 
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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 

Montana 2,007 1,960 
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Nebraska 1,721 1,671 

Nevada 734 713 

New Hampshire 598 557 

New Jersey 722 676 

New Mexico * 1,214 1,176 

New York 736 697 

North Carolina 1,199 1,156 

North Dakota 1,882 1,870 

Ohio 1,588 1,545 

Oklahoma 1,019 986 

Oregon 450 420 

Pennsylvania 1,316 1,270 

Rhode Island 855 840 

South Carolina 930 897 

South Dakota 888 861 

Tennessee 1,363 1,326 

Texas 957 924 

Utah * 1,478 1,453 

Virginia 1,016 962 

Washington 312 284 

West Virginia 1,858 1,817 

Wisconsin 1,417 1,380 
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Wyoming 1,907 1,869 

* Excludes EGUs located in Indian country in the state. 

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 the estimated 

opportunities to reduce utilization of the most carbon-intensive 

EGUs by shifting generation to less carbon-intensive EGUs should 

be based on regional evaluations rather than state-specific 

evaluations. A potential advantage of using regional evaluations 

is the ability to recognize additional cost-effective emission 

reduction opportunities 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 regional approaches into the goalsetting process, and on the issue of whether, and if so how, the 

potential cost savings associated with regional approaches 

should be considered in assessing the cost effectiveness of 

state-specific goals. 
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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. EPA has met on several occasions with staff and managers 

from the Department of Energy and the Federal Energy Regulatory 

Commission to discuss our approach to the rule and its potential 

impact on the power system. EPA staff and managers have also had 

numerous discussions with state public utility commissioners and 

their staffs to get their suggestions and advice concerning this 

rule, including how to address reliability concerns. 

In addition, the EPA met with independent system operators 

several times to discuss any potential impact of this rule on 

grid reliability. The ISO/RTO Council, a national organization 

of electric grid operators, offered analytic support to help 

states design programs that do not compromise the regional bulk 

power system. They also offered to help states develop regional 

approaches which may reduce costs and strengthen the reliability 

of the electricity grid. Specifically, the ISO/RTO Council has 

suggested that ISOs and RTOs could provide analytic support to 

help states develop and implement their plans. The ISOs and RTOs 

have the capability to model the system-wide effects of 
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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 has met with the U.S. Department of Agriculture as 

well to discuss how we can address the concerns of small 

isolated power generators in rural America and especially the 

electric cooperatives. Many of these entities have special 

challenges, as they may have small, older carbon-intensive 

assets and might have particular challenges meeting carbon 

requirements. 

With all of this in mind, the EPA in determining the BSER 

looked specifically at the cost effectiveness of control options 

in part to ensure that the options would not have a negative 

effect on system reliability. Each of the building blocks was 

determined to have reasonable costs. Further, under the Clean 

Air Act the states are given the flexibility to design state 
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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 BSER or use those measures to the same degree or 

extent that the EPA determines is achievable at a reasonable 

cost. Thus, each state has the flexibility to choose measures 

that are cost effective given that state’s energy profile and 

economy, as long as the state achieves the reductions necessary 

to meet its goal. Many market-based approaches which states may 

choose reduce the costs of compliance. They can allow certain 

units that are seldom used to remain in operation if they are 

needed for reliability purposes. Regional 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 
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relatively long planning and implementation period provides 

states with substantial flexibility regarding methods and timing 

of achieving emission reductions. In addition, states can make 

adjustments to their implementation approaches along the way, 

and in doing so can consider changed conditions and whether any 

adjustments would help to ensure that their plans achieve the 

goals without jeopardizing the grid. 

The EPA’s supporting analysis for this rule includes an 

examination of the effects of the rule on regional resource 

adequacy. 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. 
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The EPA concludes that the proposed rule will not raise 

significant concerns over regional resource adequacy or raise 

the potential for interregional grid problems. The EPA believes 

that any remaining local issues can be managed through standard 

reliability planning processes. The flexibility inherent in the 

rule is responsive to the CAA’s recognition that state plans for 

emission reduction can, and must, be consistent with a vibrant 

and growing economy and reliable, affordable electricity to 

support that economy. The EPA welcomes comments and suggestions 

on this issue. 

VIII. State Plans 

A. Overview 

After the EPA establishes the 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 a standard of performance or 

set of standards of performance, along with implementing and 

enforcing measures, that will achieve a level of emission 
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performance that is equal to or better than the level specified 

in the state plan. 

The state must then adopt the state plan through certain 

procedures, which include a state hearing. Within the time 

period specified in the emission guidelines (from as early as 

June 30, 2016 to as late as June 30, 2018, depending on the 

state’s circumstances), the state must submit its complete state 

plan to the EPA. The EPA then must determine whether to approve 

or disapprove the plan. If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for the state. 

In the case of a tribe that has one or more affected EGUs 

located in its area of Indian country, as described in the 

Tribal Authority Rule, the tribe would have the opportunity, but 

not the obligation, to establish a CO2 performance standard and 

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

country. The CAA allows the EPA to treat tribes “in the same 

manner as states” for the purpose of implementing CAA programs, 

while providing flexibility for tribes to develop a program 

tailored to their specific circumstances. A tribe that develops 

a CAA section 111(d) tribal plan will actively contribute to 

helping reduce greenhouse gas emissions. Though the EPA is aware 

of three coal-fired EGUs and one natural gas-fired EGU located 
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in Indian country, the agency is not proposing specific goals 

for areas of Indian country containing affected EGUs in this 

action. The EPA will coordinate with those tribes wishing to 

develop and implement a CAA section 111(d) tribal plan by 

determining BSER for the CAA section 111(d) affected units 

located on the tribe’s area of Indian country. As an 

alternative, the EPA is soliciting comment on whether tribes 

wishing to develop and implement a CAA section 111(d) plan 

should have the option of including the EGUs located on their 

area of Indian country in a multi-state plan (i.e., treating the 

tribal lands as an additional state). If a tribe chooses not to 

submit a plan, or if the EPA does not approve a tribe’s plan, 

then the EPA would need to determine if it is necessary or 

appropriate to establish a federal plan for affected EGUs 

located in Indian country. 

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 
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considerations for states in developing and implementing plans, 

including: affected entities with obligations under a plan; 

treatment of existing state programs; incorporation of renewable 

energy (RE) and demand-side energy efficiency (EE) programs in 

certain plans; quantification, monitoring, and verification of 

RE and demand-side EE measures; reporting and recordkeeping for 

responsible parties; treatment of interstate effects; and, 

projecting 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 standards of 

performance for affected EGUs. The proposed plan guidelines 

include four general plan approvability criteria, twelve 

required components for a state plan to be approvable, the 
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process and timing for state plan submittal and review, and the 

process and timing for demonstrating achievement of the CO2 goal. 

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 performance 

standards in a manner that accommodates a diverse range of state 

approaches. Each state will be able to determine how to best 

achieve the CO2 goals in light of its specific circumstances, 

including addressing concerns particular to the state, such as 

employment transition issues, as they design and implement their 
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plans over multiple years. As an example, the RGGI states’ 

implementation of their mass-based allowance trading program 

featured the raising of proceeds through allowance auctions and 

the use of those proceeds to advance policies 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 

We believe that different types of state CAA section 111(d) 

plans could be constructed that make use of the diversity of 
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measures that comprise the BSER.[add examples – RGGI, AB32,...]. 

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: whether the plan should require the affected EGUs to be 

subject to emission limits that assure that the emissions 

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, fall on entities other than 

affected EGUs; and 3) 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. 

In light of current state programs, and of stakeholder 

expressions of concerns over those issues and legal 
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considerations, 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 assure that at least part of that 

level is achieved, as well as on affected EGUs for the balance 

of compliance. The EPA requests comment on this 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 to 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 designed to reduce CO2 emissions 

from fossil fuel-fired power plants. Existing state programs are 

particularly informative for this purpose in light of the fact 

that 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 
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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. We request comment generally 

on this approach.

 Accordingly, the EPA is proposing to authorize a state plan 

to adopt what we refer to as a “portfolio approach,” in which 

the plan would include emission limits for affected EGUs along 

with other enforceable measures, such as RE and demand-side EE 

measures, that reduce CO2 emissions. Under this approach, all of 
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the measures combined would be designed to achieve the required 

emission performance level for affected EGUs. However, the 

emission limits enforceable against the affected EGUs would not, 

on their own, 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 

RE and demand-side EE measures that avoid EGU CO2 emissions.226

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

 

226 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.
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would include emission limits for affected EGUs, as well as 

requirements that apply directly to entities other than affected 

EGUs, for example, renewable portfolio standards or end-use 

energy efficiency resource standards (EERS), both of which often 

apply to electric distribution utilities.227

It should be evident that these plan approaches differ 

substantially in the mechanics used to achieve the required 

level of emission performance for affected EGUs, including 

necessary plan elements and the relative degree of plan 

complexity. The plan approaches also differ with regard to the 

entity or entities that are responsible for achievement of the 

required level of emission performance. As a result, a state may 

develop an approach for cost-effectively reducing EGU CO2

emissions that best suits its circumstances and may select 

whether elements of the state approach are enforceable 

components of a plan or complementary to an enforceable measure 

in a plan. 

c. Obligations on affected EGUs 

Although the EPA is proposing to authorize state plans to 

adopt the portfolio approach, we are mindful that it presents a 

 

227 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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legal issue that bears further analysis. We describe, and 

solicit comment on, that issue below. In brief, it may be 

possible to read CAA section 111(d)(1) as requiring that, when 

the EPA promulgates emission guidelines to achieve emission 

reductions from a particular source category, thereby triggering 

state obligations to adopt plans that include standards of 

performance as well as implementing and enforcing measures, the 

standards of performance must impose the responsibility for 

achieving the required emission reductions on the sources in the 

affected source category. Accordingly, as noted below, we are 

soliciting comment on whether state plans must require the 

affected EGUs to be legally responsible for achieving the 

emission performance level. 

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

the northeastern states, do impose the ultimate responsibility 

on fossil fuel-fired EGUs to achieve the required 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 limits enforceable against affected EGUs — 

whether in the form of emission rates or mass limits — to ensure 
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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 demandside EE measures could be either enforceable components of the 

plan or 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 plans that impose legal 

responsibility on the affected EGUs to achieve the full level of 

required emissions performance could incorporate enforceable RE 

and demand-side EE measures regardless of whether the standards 

of performance that those plans apply to the affected EGUs take 

the form of an emissions rate or a mass limit. Plans with ratebased 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 
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on affected EGUs that is sufficiently stringent to achieve the 

emission performance level would not need to include RE or 

demand-side EE measures as an enforceable component of the plan 

to assure the achievement of that performance level. The mass 

limit itself would suffice. However, the state may wish to 

implement RE and demand-side EE measures as a complement to the 

plan to support achievement of the mass limit at lesser cost. 

d. Federal enforceability 

 Another concern expressed by some stakeholders is that 

including RE and demand-side EE measures in state plans would 

render those measures federally enforceable and thereby extend 

federal presence into areas that, to date, largely have been the 

exclusive preserve of the state and, in particular, state public 

utility commissions and the electric utility companies they 

regulate. These stakeholders point out 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 those circumstances, 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 
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types of state programs, particularly because they are wellestablished, can be expected to achieve their intended results. 

Thus, the states could conclude that those RE and demand-side EE 

measures would be beneficial in assuring the achievement of the 

required emission performance level by the affected EGUs 

specified in the CAA section 111(d) state plan, even without 

including those measures in the plan. 

e. Plans with state commitments 

As another vehicle for approving CAA section 111(d) plans 

for states that wish to rely on state RE and demand-side EE 

programs but do not wish to include those programs in their 

state plans, the EPA requests comment on what we refer to as a 

“state commitment approach.” This approach differs from the 

proposed portfolio approach, described above, in one major way: 

under the state commitment approach, the state requirements for 

entities other than affected EGUs would not be components of the 

state plan and therefore would not be federally enforceable. 

Instead, the state plan would include an enforceable commitment 

by the state itself to implement state-enforceable (but not 

federally enforceable) measures that would achieve a specified 

portion of the required emission performance on behalf of 

affected EGUs. The agency requests comment on the 

appropriateness of this approach. The agency also requests 
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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 legal 

responsibility on affected EGUs for ensuring the emissions 

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 
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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 

[NOTE: PER THE ADMINISTRATOR’S REQUEST, OGC HAS EXPANDED 

THE DISCUSSION OF THE POSSIBLE LEGAL INTERPRETATIONS OF 111(d). 

OGC IS CONTINUING TO WORK ON SEVERAL ASPECTS OF THIS. FURTHER 

DISCUSSIONS ON TONE MAY BE NEEDED.] The EPA is required to 

promulgate emission guidelines for state plans to address 

emissions from sources in a source category for which the EPA 

has promulgated requirements under CAA section 111(b). CAA 

section 111(d)(1) requires that the state plans “(A) establish[] 

standards of performance for any existing source [for certain 

air pollutants] . . . and (B) provide[] for the implementation 

and enforcement of such standards of performance.” CAA section 

111(a)(1) defines a “standard of performance” as “a standard for 

emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of the 

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

These provisions make clear that emission limits that are 

enforceable against affected EGUs appropriately belong in state 

plans because they clearly are “standards of performance.” 

However, important issues with respect to the portfolio approach 
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discussed in this proposed rulemaking concern (1) whether, in 

addition to such emission limits on affected EGUs, state plans 

may include other measures for achieving the emission 

performance level, and (2) whether entities other than affected 

EGUs may be subject to requirements that contribute to reducing 

EGU emissions. We discuss these issues below, and, in doing so, 

solicit comment on possible interpretations that we could adopt 

as a basis for the portfolio approach. 

The resolution of these issues depends in part on the 

threshold question of whether the phrases “standards of 

performance for any existing source” and “the implementation and 

enforcement of such standards of performance” can be read to 

encompass the various components of the portfolio approach. In 

looking at this threshold question, we solicit comment on 

interpreting the phrases “standards of performance” and 

“implementation and enforcement of such standards” in CAA 

section 111(d) to authorize the portfolio approach described 

above. CAA section 111(d) requires states to set performance 

standards “for” affected sources. Standards could be interpreted 

to be “for” fossil fuel-fired EGUs if they were to result in 

reduced emissions from fossil fuel-fired EGUs, even if the 

standards did not apply directly to fossil fuel-fired EGUs. 

Under this interpretation, renewable energy and demand-side 
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energy efficiency requirements could be standards “for” existing 

EGUs. Implementation and enforcement measures could also be 

interpreted to include measures such as RE and demand-side EE 

that reduce emissions from fossil fuel-fired plants. We request 

comment on these interpretations, as well as the following 

specific issues. 

First, we solicit comment on whether the definition in CAA 

section 111(a)(1) could be interpreted so that standards of 

performance could include measures that are not enforceable 

against the affected EGUs or whether it must be interpreted so 

that the standards of performance may only consist of emission 

limitations on affected sources and must achieve the full degree 

of emission limitation that results from application of BSER. 

Second, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include the emission 

performance level – that is, the adjusted, average emission rate 

for affected EGUs in the state – 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. Interpreting the requirement in this manner could provide 

a basis for the portfolio approach because RE and demand-side EE 
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measures could be considered measures that implement the 

emission performance level. 

Third, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include measures such as RE 

and demand-side EE measures, even if they may not directly 

reduce emission rates of the affected EGUs or are not 

enforceable against the affected EGUs, on grounds that they 

indirectly reduce CO2 emissions from affected EGUs. 

Fourth, the EPA is soliciting comment on whether measures 

such as RE and demand-side EE measures, even if they are not 

enforceable against the affected EGUs, may be included in the 

state plan as measures that “implement[] and enforce[]” the 

plan’s standards of performance. For example, if the 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, it may 

be argued 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 whether measures such as RE and demand-side 

EE may be considered “implement[ing]” measures in state plans if 
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they are not directly tied to emission reductions that affected 

sources are required to make through emission limits. 

Fifth, the EPA solicits comment on whether state plans may 

include, either as standards of performance or as 

“implement[ing]” measures, requirements on entities other than 

the affected sources. 

Finally, in light of these legal issues, we solicit comment 

on whether, in the final rule, we should authorize different 

approaches in the alternative. For example, we could authorize 

the portfolio approach, but further provide that if legal 

challenges were successful, then, without the need for further 

notice-and-comment rulemaking by the EPA, states would be 

required to submit plans that achieve the emission performance 

level through emission limits on the affected sources. It should 

be noted that we consider those two approaches, as well as the 

other approaches for which we solicit comment, to be severable 

from each other. 

Alternatively, the EPA acknowledges that commenters may 

argue that the conclusion to the threshold question is that the 

components of the portfolio approach are not all within the 

scope of “standards of performance for any existing source” 

and/or “the implementation and enforcement of such standards of 

performance.” In that case, the question becomes whether CAA 
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section 111(d)(1) could be read to allow state plans to include 

the components of the portfolio approach because they 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.” If not, must the 

agency interpret CAA section 111(d) to prohibit state plans from 

including measures that are neither standards of performance nor 

measures to implement or enforce them? No specific language in 

CAA section 111(d) prohibits states from including measures 

other than performance standards and implementation and 

enforcement measures. EPA specifically requests comment on 

whether there is any other basis for concluding that CAA section 

111(d) allows or precludes state plans from including other 

measures provided that they would result in the reduction of 

emissions from existing sources. The EPA notes that cooperative 

federalism, which is one of the foundational principles of the 

Clean Air Act, includes providing flexibility to states to meet 

environmental goals (provided minimum CAA statutory requirements 

are met). The EPA takes comment on whether 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 
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interpretation of CAA section 111(d) that allows states 

sufficient flexibility in meeting CAA section 111(d) to include 

in their CAA section 111(d) plans other measures (i.e., measures 

that are neither performance standards nor measures that enforce 

or implement performance standards). Finally, the EPA solicits 

comment on all other aspects of this question concerning the 

scope of measures allowed in state plans under CAA section 

111(d). 

Notwithstanding the specific requests for comment above, 

the EPA solicits comment on all legal issues under CAA section 

111(d)(1) with respect to the portfolio approach and the types 

of state plans and measures that are discussed in this preamble. 

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. For example, CAA section 111(d) provides that the 

state plans will “establish[] standards of performance for any 

existing source” but does not say whether, once a standard of 

performance is established for a given source, that standard is 

lifted if the source ceases to be an existing source. Similarly, 

no other provisions of CAA section 111 address whether the 

imposition of a CAA section 111(b) standard on a modified or 
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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 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). The EPA invites 

comments on this interpretation, including whether this 
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interpretation is supported by the statutory text and whether 

this interpretation is sensible policy and will further the 

goals of the statute. 

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 

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 
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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. The EPA is also proposing that states submitting 

complete plans by June 30, 2016 have the option to begin meeting 

interim goals earlier than 2020 and that the average emission 

performance through 2029 could reflect a higher emission rate 

reflective of the longer trajectory for achievement of the final 

CO2 goal by 2030. 

 The subsections below contain 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, and e) out-year requirements for states 

to maintain over time CO2 emission performance levels consistent 

with the final goal. In subsection f, the agency requests 

comment on alternative requirements aimed at continued emission 
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performance improvement after 2029. Subsection g proposes 

flexibility for states to change from mass-based to rate-based 

goals in different performance periods, and subsection [VII.G] 

takes comment on planning requirements that match the option of 

alternative, less stringent state goals. 

a. Performance demonstrations 

 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 

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. 
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 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 level 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. Instead, the EPA 

proposes that the state plan would be considered to provide for 

maintenance of emission performance consistent with the final 

goal if the plan measures used to demonstrate achievement of the 

final goal by 2030 will continue in force and not sunset. 

 In addition to demonstrating that projected plan 

performance will meet the interim and final state goals, the EPA 

proposes that state plans must contain requirements for tracking 

actual plan performance during implementation. For plans that do 

not include enforceable requirements for affected EGUs that 
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ensure achievement of the full level of required emission 

performance and interim progress, the state plan 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.228 

 

228 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 BSER-based level is a more 

stringent level than the 2020-2029 average BSER-based level. The 

purpose of the final goal to be achieved and maintained is to 

ensure that each state ultimately achieves the emission 

performance level for affected EGUs that is achievable by 2029 

through application of BSER. Depending on the emission 

performance improvement trajectory required by a state plan, a 

state plan that will achieve the 2020-2029 interim goal may or 

may not also result in meeting the 2030 final goal.
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 The agency requests comment on a second option in which, in 

addition to submitting a plan demonstrating emission performance 

over the 2020-2030 period, 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 (under one of the out-year approaches described in the 

relevant section 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 2020 for 

the interim goal plan performance period.229 The agency generally 

requests comment on the appropriate start date and rationale. 

 

229 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 

would recompute the state goals consistent with the selected 

start date.
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In considering the start date, it is relevant to consider 

the due dates for state plan submittals and the amount of time 

available for program implementation by the start date. January 

2020 is 3.5 years from the proposed June 2016 deadline for 

initial plan submittals, 2.5 years from the proposed June 2017 

extended deadline for complete plans from states not 

participating in a multi-state plan, and 1.5 years from the 

proposed June 2018 extended deadline for complete plans from 

states participating in a multi-state plan. The EPA suggests 

that affected entities may have greater lead time for compliance 

than might be implied by the plan submittal dates referenced 

above. Affected entities will have knowledge of state 

requirements as they are adopted, and the state must adopt rules 

and requirements in advance of submitting its complete plan to 

the EPA. Also, as explained in detail in subsection c, states 

may choose a different emission performance improvement 

trajectory from that which the EPA assumes for purposes of 

calculating state goals, achieving lesser levels of performance 

in early years and more in later years. 

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 
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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 engineered solutions used to improve 

heat rates at existing EGUs have long been commercially 

available and have been implemented at EGUs for many years. 

Further, the relatively modest capital costs (average $100/kW) 

and significant fuel savings associated with a suite of heat 

rate improvement (HRI) methods result in this measure being a 

low-cost approach to reducing CO2 emissions from existing EGUs. 

HRI “best practices” (e.g., installation of modern control 

systems, operator training, smart soot blowing) are the leastcost HRI methods and can be applied quickly, without lengthy EGU 

outages. The somewhat more costly HRI “upgrades” (e.g., steam 
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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 groups230. In addition, the existing natural gas 

pipeline and electricity transmission networks are already 

connected to every existing NGCC facility, and can support 

aggregate operation of the NGCC fleet at 70 percent (or above) 

at the state level, or can be reasonably expected to do so in 

the time frame for compliance with this rule. Therefore, 

building block 2, which represents shifting of generation from 

steam fossil EGUs to existing NGCCs, is a viable method for 

providing CO2 reductions at existing EGUs by the 2020 compliance 

start date. 

 

230 Source: NERC, 2008-2012 Generating Unit Statistical Brochure
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Building Block 3 is based on shifting generation from 

affected fossil units to new renewable energy generating 

capacity, which is added over time, and new or preserved nuclear 

capacity, all of which is expected to be in place by 2020 (see 

the GHG Abatement Measures TSD for more information). 

Finally, there is considerable experience with the states 

and the power sector in designing and implementing demand-side 

energy efficiency improvement strategies and programs. It is 

also well accepted that such improvements can achieve reductions 

in CO2 emissions from existing EGUs at a reasonable cost. 

Building block 4 represents a feasible pathway for reducing 

utilization of carbon-emitting EGUs by implementing improvements 

in demand-side energy efficiency. This building block is based 

on a “best practices” scenario where all states achieve a level 

of performance – matching a level achieved or committed to by 

twelve leading states – of 1.5 percent annual incremental 

electricity savings as a percentage of retail sales. For the 

best practices scenario, all states achieve this level of 

performance no later than 2025, with leading states reaching 

this level sooner. Each state’s current level of performance is 

taken into account, with states achieving lower levels of 

performance being allowed more time to reach the best practice 

level. 
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c. Duration of performance periods for final and interim goals 

 The EPA recognizes that a state’s circumstances and choice 

of emission reduction strategies may affect the timing of CO2 

emission performance improvement within a multi-year planning 

period. States can be expected to select various combinations of 

measures and those measures may vary in the time needed to reach 

full implementation. The agency recognizes that certain emission 

reduction measures and programs (e.g., heat rate improvements) 

are generally easier to implement in the near term, while others 

(e.g., renewable portfolio standards, demand-side energy 

efficiency programs) may require several years to implement 

because of the time necessary to establish the proper 

infrastructure if a state does not already have such programs in 

place. Though some states have already implemented such programs 

that are achieving results, other states may have to establish 

them for the first time. New single and multi-state programs, as 

well as existing single and multi-state programs that are adding 

or revising measures, may need time for implementation to 

achieve the required level of emission performance. 

 As described in Section VII of the preamble, the EPA is 

proposing 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 
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performance, while ensuring an overall level of performance 

consistent with the application of 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. 

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 
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described separately below, interim emission performance checks 

will occur during this 10-year period.) 

Final goal – Projected plan performance demonstration: To be 

approvable, a state plan must demonstrate that the emission 

performance of affected EGUs will meet the final emission 

performance level no later than 2030, on a single-year basis. 

Final goal – Actual plan performance check: Starting at the end 

of 2032, emission performance of affected EGUs must be compared 

against the final goal on a three-year rolling average basis 

(i.e., 2030-32, 2031-33, 2032-2034, etc.). 

 This proposed approach provides a 10-year performance 

period for the interim performance level. The 10-year period 

allows states flexibility for timing of program implementation 

as the state ramps up its programs to achieve the final 

performance level. Using the single year 2030 as the projected 

year for achievement of the final goal ensures that state plans 

are designed to achieve the final goal no later than 2030; 

providing a multi-year time frame for projected plan performance 

would inappropriately delay the requirement for a final-goal 

level of performance that the EPA’s analysis shows is achievable 

at the end of the 10-year interim ramp-up period. Using 2030 

also avoids overlap with the interim goal performance period. 

The rolling three-year performance periods for measuring actual 
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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 

output231 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. 

For a mass-based plan, 2020-2029 emission performance is total 

tons of CO2 emitted by affected EGUs over the 10-year performance 

period. 

 The EPA also requests comment on a second approach to state 

plan performance periods. Under this approach, in addition to 

the requirements the proposal, a state plan also would also need 

to achieve a five-year average emission performance level 

reflecting application of BSER for the 2020-2024 period. This 

 

231 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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five-year performance period would nest within the 10-year 

performance period for the 2020-2029 period. The purpose of this 

approach would be to ensure greater emission performance 

improvement during the first five years of the interim goal plan 

performance period by precluding states from significantly 

delaying compliance obligations until the last five years. 

However, this approach also would reduce states’ flexibility for 

the timing of emission improvements over the 2020-2029 period. 

 The agency invites comment on any 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 
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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, on a three-year average basis, an emission rate consistent 

with the state’s required emission performance level, and allows 

EGUs to comply through an emission rate averaging system. 

Another example is a plan that includes measures or actions 

(e.g., emission limits that apply to affected EGUs and ensure 

full plan performance) that take effect automatically if the 

plan’s required emission performance level is not met, in 

accordance with a specified milestone. The EPA requests comment 

on whether there are other types of state plans that should be 

considered “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. 

 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 
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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 

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, the state would be 

required to include a comparison of emission performance 

achieved to performance projected in the state plan each year 

from the end of 2022 through the end of 2028. 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). 
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 If actual emission performance of affected EGU was not 

within 10 percent of plan projections, the state would be 

required in its submission to explain reasons for the deviation 

(e.g., energy efficiency program not working as effectively as 

expected, prolonged extreme weather that had been unanticipated 

in electricity demand projections) and specify the corrective 

measures that will be taken to ensure that the required level of 

emission performance in the plan will be met. The state also 

would be required to implement those corrective measures as 

expeditiously as practical. 

 The EPA proposes that the corrective measures to be 

triggered in case of an emission performance deficiency must be 

adopted as enforceable measures included in the original state 

plan. These previously adopted corrective measures would reduce 

the delay between the time an emission performance deficiency is 

discovered, and the time that corrective action can begin. 

Alternatively, the agency requests comment on whether states 

should be allowed to identify and adopt corrective measures 

after a performance deficiency is found. 

 At the end of the 2020-2029 performance period, the EPA 

proposes that the state be required to compare actual emission 

performance achieved during the performance period against the 

interim goal. As noted above, beginning after 2032, EPA proposes 
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that the state be required to compare actual emission 

performance achieved against the final goal on a rolling threeyear 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 

Option B and the planning approach for alternative state goals, 

which is described below. 

e. Consequences if actual emission performance does not meet 

state goal 

 There are scenarios under which an approved state plan 

might fail to achieve a level of emission performance by 

affected EGUs that meets the state goal. Under some types of 

plans, a possible scenario is that despite successful plan 

implementation, emissions under the plan turn out to be higher 

than projected at the time of plan 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 
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responsibilities, or because the state did not fulfill its 

responsibilities. 

 The EPA believes that the emission guidelines should 

specify the consequences in the event that actual emission 

performance under a state plan does not meet the applicable 

interim goal in 2020-2029, or does not meet the applicable final 

goal in 2030-2032 or later, because CAA section 111(d) is not 

specific on this point. The agency requests comment on how the 

consequences should vary depending on the reasons for a 

deficiency in performance. 

 Specifically, the agency requests comment on whether 

consequences should include the triggering of corrective 

measures in the state plan, or plan revisions to adjust 

requirements or add new measures. The agency also requests 

comment on whether corrective measures, in addition to ensuring 

future achievement of the state goal, should be required to 

achieve additional emission reductions to offset any emission 

performance deficiency that occurred during a performance period 

for the interim or final goal. This concept has been applied, 

for example, in the acid rain 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 
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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 made a finding of the plan's failure 

to achieve the state goal during a performance period, EPA would 

require the state to cure the deficiency with a new plan within 

a specified period of time (e.g., 18 months). If the state still 

lacked an approved plan by the end of that time period, the EPA 

would have the authority to promulgate a federal plan under 

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

f. Out-year requirements: Maintaining or improving the level of 

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 
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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. 

 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 
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goal by 2030 will continue in force and not sunset.232 After 

implementation, the state would be required to compare actual 

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

average basis starting in 2030, and to implement corrective 

measures if necessary. 

 The EPA also requests comment on an alternative approach to 

a state’s 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 

 

232 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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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 

BSER in 2030 and beyond to a specified time period and final 

date. The agency requests comment on the appropriate time 

period(s) and final year for the EPA’s calculation of state 

goals that reflect application of BSER under this approach. 

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

performance level consistent with the final goal, or could adopt 

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 
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weather, that influence power system operation and affect EGU CO2

emissions. 

 In connection with the alternative state goals, for the 

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

performance over time that are described above in subsection e. 

The EPA requests comment on whether state plans should provide 

for emission performance after 2025 solely through postimplementation 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. First, a state plan must contain enforceable 

measures that reduce EGU CO2 emissions. Second, these enforceable 
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measures must be projected to achieve emission performance 

equivalent to the applicable state-specific CO2 goal on a 

timeline equivalent to that in the emission guidelines.233 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 actions, if necessary. The EPA 

requests comments on all aspects of these general criteria and 

the ten 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, to ensure that the plan is 

enforceable and in conformance with the CAA, a state should 

follow established EPA guidance on enforceability.234 This 

 

233 Flexibilities provided to states in meeting this general 

approvability criterion are discussed below in Section 

VIII.B.2., emission performance.

234 Enforceability guidance includes:(1) September 23, 1987 

memorandum and accompanying implementing guidance, “Review of 

State Implementation Plans and Revisions for Enforceability and 
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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. 

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 could include enforceable CO2

emission limits that apply to affected EGUs as well as other 

enforceable measures, such as RE and demand-side EE measures, 

that avoid EGU CO2 emissions and are implemented by the state or 

by another entity 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 

 

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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achievement of the required level of emission performance, the 

state plan should 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.235 

The EPA recognizes that a portfolio approach may result in 

enforceable state plan obligations accruing to a diverse range 

of affected entities beyond affected EGUs, and that there may be 

challenges to practically enforcing against some such entities 

in the event of noncompliance. We request comment 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. 

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 

 

235 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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the state plan. State plans that are projected to achieve an 

average CO2 emission rate (expressed in, for example, 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 BSER reduce 

CO2 emissions from affected EGUs. As a result, the EPA is not 

proposing that out-of-sector GHG offsets could be applied to 

demonstrated CO2 emission performance by affected EGUs in a state 

plan. 

However, states could still include in their plans emission 

limits for affected EGUs that include the ability to use GHG 

offsets for compliance, provided those emission limits would 

achieve the required level of emission performance in a state 

plan. 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 
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management. How to address GHG offsets included in EGU emission 

limits when projecting emission performance under a state plan 

is addressed in the Projecting EGU CO2 Emission Performance in 

State Plans TSD. 

The ISO/RTO Council, an organization of electric grid 

operators, has suggested that ISOs and RTOs could play a 

facilitative role in developing and implementing region-wide, 

multi-state plans, or coordinated individual state 

plans. Existing ISOs and RTOs 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. 

3. Quantifiable and verifiable emission performance 
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The third criterion for approvability is that a state 

planspecify how the effects of each state plan measure will be 

quantified and verified. At a minimum, the EPA proposes that all 

plans must specify how CO2 emissions from affected EGUs are 

monitored and reported. The EPA is proposing that both massbased and rate-based plans must include CO2 emission monitoring, 

reporting, and recordkeeping requirements for affected EGUs, as 

specified in the emission guidelines. A rate-based plan must 

also include monitoring, reporting, and recordkeeping 

requirements for useful energy output from affected EGUs 

(electricity and useful thermal output), as specified in the 

emission guidelines. With one exception, these proposed 

requirements are consistent with those in the proposed EGU 

Carbon Pollution Standards for New Power Plants. See 79 FR 1430-

1519 (January 8, 2014). The exception is that we are proposing 

that useful energy output be measured in terms of net output 

rather than gross output, as discussed below. 

For state plans that include other measures that avoid EGU 

CO2 emissions, such as RE and demand-side EE measures, the state 

will also need to include quantification, monitoring, and 

verification provisions in its plan for these measures, which 

may vary depending on the types of requirements included in the 

specific plan, as specified in the emission guidelines. This may 
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include, for example, quantification, monitoring, and 

verification of RE generation and demand-side EE energy savings 

under a rate-based approach.236

4. Reporting and corrective actions 

The fourth criterion for approval is that a state plan (i) 

specify a process for periodic reporting to the EPA of overall 

plan performance and implementation (including compliance of 

affected entities with applicable standards of performance) 

during the plan period, and (ii) include a process and schedule 

for modification if reporting shows that the plan is not 

achieving the projected level of emission performance. We 

solicit comment on whether the latter process should include the 

adoption of new plan measures and subsequent resubmission of the 

plan to the EPA for review and approval, or whether the process 

should specify the implementation of measures that are already 

included in the approved plan in the event that the projected 

level of performance is not being achieved. We also solicit 

comment on the point at which such a process and schedule would 

be triggered, such as at the end of a multi-year plan 

performance period if emission performance is not met, or at 

 

236 Considerations for quantification, monitoring, and 

verification of RE and demand-side EE measures are addressed in 

Section VII.E of this preamble and in the State Plan 

Considerations TSD. 
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specified interim stages within a multi-year plan performance 

period. For plans with self-correcting mechanisms, the agency is 

not proposing that requirements for modification be included in 

the plan. All of these considerations are addressed in more 

detail below in Section VIII.F. 

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. 

The EPA proposes that each plan must have the following 

twelve components: 

1. Identification of affected entities (affected EGUs and other 

responsible parties) 

 The 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 
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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 enforcement of 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 

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 per year). 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, 
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the plan must include a description of the analytic process, 

tools, methods, and assumptions used to translate from the ratebased goal to the mass-based goal. 

The EPA is proposing that multiple states could jointly 

demonstrate emission performance by affected EGUs. For these 

multi-state approaches, states would demonstrate emission 

performance by affected EGUs in aggregate with partner states. 

For states participating in a multi-state approach, the 

individual state performance goals in the emission guidelines 

would be replaced with an equivalent multi-state performance 

goal. For example, states taking a rate-based approach would 

demonstrate that all affected EGUs subject to the multi-state 

plan achieve a weighted average CO2 emission rate that is 

consistent, in aggregate, with an aggregation of the 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 
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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 

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 
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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-asusual 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. 
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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 

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 will influence 

projections of CO2 emissions by affected EGUs in any particular 

state. 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 
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Projecting EGU CO2 Emission Performance in StatePlans 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 the state’s emission performance level within the plan 

performance period. 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. 

5. Milestones 

As described in greater detail in Section VIII.A.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 
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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.A.2.d., no less than every two 

years, beginning January 1, 2022, the state must compare 

emission performance achieved by affected EGUs in the state 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 July 1 of the relevant year 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 

have been or 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 
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achieve (e.g., measures sufficient to address a 10 percent 

performance deficiency). 

7. Identification of standards of performance and any other 

measures 

A state plan must identify the affected entities to which 

each standard of performance 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 standard of performance 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 January 2014 

proposed Carbon Pollution Standards, the EPA proposed that the 

appropriate standard of performance for new EGUs be no longer 

than 12 months (on average or cumulative calendar year basis). 

Similarly, the EPA proposes here that an appropriate averaging 

time for any rate-based standard of performance for affected 

EGUs and/or other affected entities subject to a state plan is 

no longer than 12 months within the plan period and no longer 

than three years for a mass-based standard. We also solicit 

comment on longer and shorter averaging times for a standard of 

performance included in a state plan. To maximize flexibility 
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for the states, and in recognition that certain portfolio 

components may take longer to begin to achieve emission 

reductions than others, the EPA further proposes that such 

annual compliance timeframes may change over time (e.g., become 

more or less stringent in subsequent years), provided that the 

state plan demonstrates ultimate achievement of the state’s 

level of performance as described previously in this preamble. 

8. Demonstration that each standard of performance is 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable 

In developing its CAA section 111(d) plan, to ensure that 

the plan is enforceable and in conformance with the CAA, a state 

should follow the EPA’s prior guidance on enforceability.237 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 

 

237 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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calculated over as short a term as reasonable. As reflected in 

section VIII.F.2.c.4 of this preamble, the EPA recognizes that 

states have a diversity of experiences with RE and demand-side 

EE measures, and we are seeking comment on whether the EPA 

should establish further guidance on the quantification, 

monitoring and verification of such measures. 

For each standard of performance, a plan must describe how 

it is quantifiable, non-duplicative, permanent, verifiable, and 

enforceable with respect to an affected entity. A standard of 

performance 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. A standard of 

performance 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 standard of 

performance 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 
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mean that measures in a standard of performance cannot also be 

used for other purposes. For example, if a state wished to take 

credit for CO2 emissions avoided due to electric generation from 

a new wind farm, those avoided emissions could be considered 

non-duplicative and included for purposes of CAA section 111(d), 

even if electric generation from that wind farm was also being 

used to generate renewable energy certificates (RECs) to comply 

with the state’s RPS requirements. It also does not mean that a 

single affected entity could not be subject to similar standards 

of performance 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 standards of 

performance 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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A standard of performance is permanent if the standard of 

performance must be met by each applicable compliance year, or 

replaced by another standard of performance in a plan revision, 

or the state demonstrates in a plan revision that the emission 

reductions from the standard of performance are no longer 

necessary for the state to meet its emission performance level. 

A standard of performance 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. A standard of performance 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 practicable enforceability (listed in Section 

VIII.C.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 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. The proposed protocols include a default 

apportionment procedure for multi-EGU facilities under which the 

net generation of each EGU at the facility would be determined 

as the net generation of the facility times 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 in the proposed EGU 

GHG NSPS regulations.238) In addition, the protocol would allow 

facilities to use alternative apportionment procedures with EPA 

approval. We invite comment on the proposal for reporting of net 

 

238 70 FR 1429-1519; January 8, 2014. 
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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 plants; 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. 

 A state plan that contains other standards of performance 

in addition to emission limits applicable to affected EGUs must 

include additional reporting and recordkeeping requirements 

related to these other measures. These 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 
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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 to require state plans to include a 

record retention requirement of ten years and requests comment 

on this proposed timeframe. The EPA is also soliciting comment 

on whether these reports should be submitted electronically, to 

streamline transmission, and made publicly available. 

10. Description of state reporting 

 A state plan must provide that the state will submit 

periodic reports to the EPA detailing plan implementation and 

progress, including the actions taken by the state, affected 

EGUs, and any other affected entities under the plan; the status 

of compliance by affected EGUs and any other affected entities 

with their obligations under the plan; current aggregate and 

individual CO2 emission performance by affected EGUs during the 

reporting year and prior reporting years; and any additional 

measures applied under the plan during the reporting period. The 
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state plan must describe the process, timing, and content for 

these reports. 

The EPA is soliciting comment on whether these reports 

should be submitted electronically, to streamline transmission, 

and made publicly available. 

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. 

12. Supporting material 

The state must provide supporting material and technical 

documentation related to applicable components of the plan. In 

its plan, a state must adequately demonstrate that it has the 

legal authority for each implementation and enforcement 

component that it proposes to include in its plan as part of a 

federally enforceable standard of performance. 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 
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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). During the outreach process, many states 

expressed concern that this was not sufficient time to prepare 

and submit a state plan to the EPA. States commented that 

additional time was needed to accommodate, among other things, 

state legislative and rulemaking schedules, coordination among 

states involved in multi-state plans, coordination with third 

parties, and the complex technical work needed to develop a 

state plan. The EPA recognizes that state administrative 

procedures can be lengthy, some states may need new legislative 

authority, and that states planning to join in a multi-state 
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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 implementing a complete plan. This 

approach involves the option that we refer to as an initial 

submittal, followed by submittal of a complete state plan no 

later than either June 30, 2017 for single-state plans or June 

30, 2018 for multi-state plans. . 

In addition, for states wishing to participate in a 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 multi-
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state plan. In this instance, the joint submittal would have the 

same legal effect as an individual submittal for each 

participating state. 

2. State plan submittal and timing 

The EPA framework regulations (40 CFR 60.23) require that 

state plans be submitted to the EPA within nine months of 

promulgation of the emission guidelines, unless EPA specifies 

otherwise.239 In view of the complexity of these plans, we are 

proposing to extend the submittal date. 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. If a state intends to 

make an initial submittal by June 30, 2016, in lieu of a 

complete plan, the state must notify the EPA by letter of such 

intent by no later than April 1, 2016. In this 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 plan submittal by June 30, 2016. 

 

239 40 CFR 60.23(a)(1). 
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The EPA will respond to a state’s notice that it intends to 

request an extension of the plan submittal date within 45 days 

through a letter response. The EPA will acknowledge receipt of 

the state’s April notice and advise the state whether the 

outline of actions the state is currently undertaking to develop 

a plan indicate that the state is on track to submit an 

approvable initial submittal. The EPA’s response to the state’s 

April notice letter will be advisory only and will not 

constitute final agency action. The EPA will act to approve or 

disapprove a state’s request for a date extension in response to 

the state’s initial submittal. 

The EPA proposes that approvable justifications for seeking 

an extension 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 to limit the 

types of justifications that the EPA should not consider as 

warranting an extension. 

If a state submits an initial state plan by June 30, 2016, 

and it meets the minimum requirements for an initial state plan, 
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as specified in the plan guidelines, then the EPA will notify 

the state by letter, within 60 days, that it has received the 

initial state plan and determine whether it meets the minimum 

requirements. The EPA’s letter acting on the initial submittal 

will specify whether the new due date for the state’s complete 

plan is June 30, 2017 or June 30, 2018. The EPA believes this 

approach is authorized by, and consistent with, section 60.27(a) 

of the implementing regulations. 

 If the EPA approves a two-year extension to June 30, 2018, 

for a state developing a multi-state plan, the state would be 

required to provide one update, on June 30, 2017, on its 

progress toward milestones and schedules for developing and 

submitting a complete plan.240 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, 

 

240 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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including identifying which components are not complete. For 

incomplete components, an approvable initial submittal must 

contain a comprehensive roadmap outlining the path to 

completion, including milestones and dates. We recognize that 

certain options that states may choose involve more analytic 

effort to precisely demonstrate sources of reductions than other 

options. The initial plan, 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) 
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 Identification of existing programs, if any, the state 

intends to rely on to meet its emission performance level 

 Identification of executed agreements with other states 

(e.g., memorandum of understanding (MOU)), if a multi-state 

approach is being pursued 

 A commitment to submit a complete plan by no later than the 

applicable required date and explanation of actions the 

state will take to show progress in addressing incomplete 

plan components. 

 A description of all steps the state has already taken in 

furtherance of actions needed to finalize a complete plan. 

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. 

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 
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mutual understandings and commitments”.241 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 legislation a 

program materially consistent with the model rule in each state 

by a specified date.242 The MOU also included a commitment to 

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

specified a process for establishing a non-profit organization 

to assist the states in administering the regional aspects of 

the program. In addition, prior to execution of the MOU, the 

RGGI states committed, through letters from the Governors of 

participating states, to engage in the development of a marketbased program to reduce CO2 emissions from power plants. This was 

followed by publication of an action plan for tasks leading up 

 

241 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. 

242 The model rule specified elements that needed to be 

consistent across states for the program to function, as well as 

areas were 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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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, 

then the EPA will notify the state by letter, within 60 days, 

that it has received the plan and that the initial state plan 

meets the minimum requirements. The letter will also specify 

whether the complete plan must be submitted to the EPA by no 

later than June 30, 2017, or June 30, 2018. 

After receipt of a complete plan submittal, the EPA will 

review the plan and, within six 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. 

F. State Plan Considerations 
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The EPA is proposing to give states broad discretion to 

develop plans that best suit their circumstances and policy 

objectives. In developing its plan, astate 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 

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 
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is regulated by the state, such as an electric distribution 

utility, or a private or public third-party entity), and the 

state agency, authority or entity. We are seeking comment on 

other appropriate examples of affected entities beyond the 

affected EGU. 

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 the 

ability of a state to include requirements for affected entities 

other than EGUS, and if so, which such entities, and the 

justification for the limitations on the entities. The State 

Plan Considerations TSD provides illustrative examples of 

possible entities and legal mechanisms. 

2. Treatment of existing state programs 

a. Framing considerations 
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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. The EPA agrees 

with that policy principle. 

There is much less agreement among states and stakeholders 

on the specifics of how existing state programs should be 

treated in a demonstration that a proposed state plan will 

achieve the required level of emission performance. 

The EPA, starting from recent historical data, has 

identified the affected EGU emission performance improvements 

and resulting average emission performance levels for affected 

EGUs that are achievable, considering cost, in each state over 

the 2020-2029 period, with achievement of the final CO2 emission 

performance level by 2030. 

As explained in Section VII above, the EPA’s proposed 

state-specific goals reflect actions that many states have 

already taken to reduce or avoid EGU CO2 emissions. CO2 emission 

reductions due to shifts to lower CO2-emitting power generation 

are also represented in the 2012 base period that was used to 
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assess certain building blocks that are applied in calculating a 

state emission performance goal.243

The agency recognizes that states that have already shifted 

toward lower carbon-intensity generation or ramped up demandside 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,244 may qualify for use in showing 

 

243 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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that a state plan will achieve the required level of emission 

performance, provided they meet the approvability requirements 

in the emission guidelines (summarized above in Section VIII.B) 

and relevant requirements for plan components in the emission 

guidelines (described above in Section VIII.C). Several options 

for treatment of existing 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 the 

plan performance period as a result of actions taken after the 

date of this proposal.245 This proposed policy would recognize 

beneficial emission impacts from existing state programs and 

measures during the plan period. It would do so in a way that 

may be generally compatible with the forward-looking methodology 

 244 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.

245 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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that the EPA used to propose state emission performance goals 

based on BSER. By making actions taken after proposal eligible 

to help meet a state’s required emission performance level, this 

approach would support early beneficial emission-reducing 

actions. This option would ensure that actions taken after 

proposal of the emission guidelines and prior to 2020 as a 

result of requirements in a state plan, could be recognized as 

contributing toward meeting a state’s required emission 

performance level for affected EGUs. 

In general, the agency has identified two broad options for 

treatment of existing state programs and measures. As noted 

above, the EPA proposes that emission reductions that existing 

state requirements, programs, or measures achieve during the 

plan performance period due to 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 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., 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. 
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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 BSER may depend on the date or 

dates that are applied for qualifying actions under existing 

state programs, requirements, and measures. For example, 

implementation of measures subsequent to the proposal or 

promulgation of the emission guidelines may be consistent with a 

forward-looking goal setting approach, as these actions may be 

necessary to meet a required level of emission performance 

during the plan performance period or will put a state in a 

better position to meet the required level of performance. An 

example is the EPA’s treatment of end-use energy efficiency 

potential in state goal setting, where the energy savings 

achievable during the 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 plan period. However, inconsistency issues may 

arise if the selected date is not adequately synchronized with 
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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. 

The EPA also solicits comment on a second broad option. 

This option would recognize emission reductions that existing 

state requirements, programs, or measures achieved starting from 

a specified date prior to the 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., 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. 

The EPA requests comment on this option -- that emission 

reduction effects that occur prior to the beginning of the plan 

performance period could be applied toward meeting the required 

level of emission performance in a state plan. The agency also 

requests comment on the alternative dates listed above in 

connection with this option. We also request comment on whether 

this option is inconsistent with the forward-looking method that 
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the EPA has proposed for establishing state goals based on the 

application of BSER. 

The agency is seeking comment on whether some variation of 

this approach could be justified as consistent with the EPA’s 

proposed goal-setting approach, as well as the general concept 

of BSER and its application in establishing state goals. In 

particular, we are seeking comment on whether 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 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 
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approach, new demand-side EE measures installed in 2015 or later 

to meet an existing, on-the-books energy efficiency resource 

standard would be a qualifying measure. However, only MWh 

savings beginning in 2020 and related avoided CO2 emissions could 

be applied toward meeting a required emission rate 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 energy efficiency resource standard 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 
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tradable credit system applied to an EGU’s reported CO2 emission 

rate.246 Under such a process, measures that avoid 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 emission rate 

performance level in a state plan. 

 Under this approach, affected EGUs247 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

 

246 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.

247 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.248 In practice, the average or 

marginal CO2 emission rate in the power pool or identified region 

 

248 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 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 included as 

part of an approvable state plan. 
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Utilities and states have conducted ongoing EM&V of demandside energy efficiency and renewable energy measures and 

programs for several decades. Current practice with EM&V for 

demand-side energy efficiency and renewable energy programs in 

the U.S. is primarily defined by state public utility commission 

(PUC) requirements for customer-funded energy efficiency 

programs, as well as related compliance and reporting 

requirements for energy efficiency resource standards (EERS) and 

renewable energy portfolio standards (RPS). 

The level of PUC oversight of demand-side energy efficiency 

programs varies from state to state, but this oversight process 

has generated the majority of the industry guidance and 

protocols for documenting energy savings from EE programs. 

Typically, impact evaluation reports are responsive to 

requirements established by PUCs and submitted (usually 

annually) for PUC review, approval, and use in resource planning 

and performance assessment. These PUC requirements generally 

rely upon a well-defined set of industry-standard practices and 

procedures. In states with the most experience implementing and 

overseeing EE programs, this typically includes: use of one or 

more of industry-standard EM&V protocols or guidelines; use of 
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“deemed savings values,”249 where appropriate, for wellunderstood energy efficiency 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 savings250, 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 

 

249 Deemed savings are measure-specific stipulated values based 

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

deemed savings approaches involve limited or no measurement 

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

strategy for documenting energy savings. 

250 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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circumstances. In response to a growing awareness of this lack 

of cross-state comparability, policy makers, regulatory 

agencies, and other stakeholders are increasingly advocating for 

the use of common evaluation approaches across jurisdictions. A 

number of states and utilities in different regions of the 

country are already working to develop such common approaches.

For renewable energy 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 
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comment on the suitability of these approaches in the context of 

an approvable state plan, and on whether harmonization of state 

approaches, or supplemental actions and procedures, should be 

required in an approvable state plan. In particular, we intend 

to establish guidance for acceptable quantification, 

monitoring, and verification of RE and demand-side EE measures 

for an approvable EM&V plan, and are seeking comment on critical 

features of such guidance, including scope, applicability, and 

minimum requirements.251 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.252 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 

 

251 Section 4 of the State Plan Considerations TSD includes a 

detailed description of these EM&V parameters.

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

State Plan Considerations TSD.
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such information in assessing avoided CO2 emissions from affected 

EGUs. 

In developing guidance, the agency does not intend to limit

the types of RE and demand-side EE measures and programs that 

can be included in a state plan, provided that supporting EM&V 

is rigorous, complete, and consistent with 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 

plan, provided that such protocols are applied in accordance 

with industry best practices. For example, many utilities have 

implemented a similar core set of RE and demand-side EE measures 

and programs for utility customers. For these types of measures 

and programs, a substantial base of experience has been 

established nationally for the evaluation of measure and program 
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outcomes. Other types of measures and programs, such as those 

that seek to alter consumer and building occupant behavior may 

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 may have substantial impacts, and the EPA does not 

want to discourage their implementation in state plans, but they 

may 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 
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If a state plan incorporates RE and demand-side EE measures 

under a rate-based approach or implements a mass-based portfolio 

approach with such measures, reporting and recordkeeping 

requirements for an approvable plan would differ from those 

applicable to an affected EGU. For example, these requirements 

may include compliance reporting by an electric distribution 

utility subject to an end-use energy efficiency resource 

standard (EERS) or renewable portfolio standard (RPS). They may 

also include reporting by a vertically integrated utility 

implementing an approved integrated resource plan. In the latter 

instance, the utility may also be the owner and operator of 

affected EGUs, but additional reporting of quantified effects of 

RE and demand-side EE measures under the utility plan would be 

necessary to demonstrate emissions performance under the state 

plan. In other instances, a state agency or entity or a private 

or public third-party entity may be implementing programs and 

measures that support the deployment of end-use energy 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 
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approvable state plan are provided in the State Plan 

Considerations TSD. We are seeking comment on the examples and 

suitability of potential approaches described in the TSD and any 

other appropriate reporting and recordkeeping requirements for 

affected entities beyond affected EGUs. 

6. Treatment of interstate effects 

The electricity system and wholesale electricity markets 

are interstate in nature. EGUs in one state provide electricity 

to customers in neighboring states. Power companies often own 

EGUs in more than one state and manage them as a system. EGUs 

are dispatched both within and across state borders. 

Similarly, programs and measures in a state plan, such as 

RE and 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. 
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The agency recognizes the complexity of accounting for 

interstate effects associated with measures in a plan in a 

consistent manner, to allow state to take into account the CO2

emission reductions resulting from these programs, while 

minimizing the likelihood of double counting. We also realize 

that interstate effects on CO2 emissions from affected EGUs could 

be attributed in different manners in the context of an 

approvable state plan. The agency 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 used in determining 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 states would have the flexibility to 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 

are equal to the total of each state’s in-state emissions 

reductions that result from demand-side EE measures implemented 
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in those states. We are also proposing that states could jointly 

demonstrate CO2 emission performance by affected EGUs through a 

multi-state plan in a contiguous electric grid region, in which 

case attribution among states of emission reductions from 

demand-side EE measures would not be necessary. We also request 

comment on whether a state should be able to take credit for 

emission reductions out of state due to in-state EE measures if 

the state can demonstrate that the reductions will not be 

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 reductions from demand-side EE measures 

in state plans. 

The EPA is also 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 and/or in other states. The EPA is also 

seeking comment on how to avoid double counting emission 

reductions using this proposed approach. The EPA is also 

proposing that states participating in multi-state plans could 

distribute the CO2 emission reductions among states in the multistate area, as long as the total CO2 emission reductions claimed 
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are equal to the total of each state’s in-state emission 

reductions for renewable energy 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 emissions performance by affected EGUs under 

the plan. In addition, a state plan that is using a mass-based 

goal in determining the required level of emission performance 

under the plan will include a translation of the rate-based 

emission goal in the emission guidelines to a mass-based goal. 
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This translation will involve a projection of CO2 emissions from 

affected EGUs during the plan period, under a scenario that 

assumes the rate-based goal in the emission guidelines is met. 

The EPA is striving to find a balance between providing 

state implementation flexibility and ensuring that the emission 

performance required by CAA section 111(d) is properly defined 

in state plans and that plan performance projections have 

technical integrity. Each state plan must include a projection 

of CO2 emission performance from affected EGUs during the multiyear plan period that will result from implementation of the 

plan. Depending on the type of plan approach, this will include 

either a projection of the average CO2 emission rate achieved by 

affected EGUs or total CO2 emissions from affected EGUs. 

The credibility of state plans under CAA section 111(d) 

will depend in large part on ensuring credible and consistent 

emission performance projections in state plans. Therefore, the 

use of appropriate methods, tools, and assumptions for such 

projections is critical. 

Considerations for projecting emission performance under a 

state plan will differ depending on the type of plan. This 

includes differences in how inputs to projections are derived; 

how projections are conducted, including tools,methods, and 
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assumptions; and, how aspects of a plan are represented in these 

projections. 

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.253 This 

latter approach would be able to capture dynamic interactions 

within the electricity sector, based on system operation and 

market forces, including interactions among state programs and 

measures and the dynamics of market-based measures. 

These considerations, and considerations for projecting 

emission performance under different types of state plan 

approaches, are discussed in detail in the Projecting EGU CO2

Emission Performance in State PlansTSD. 

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 

 

253 In many cases, this approach will also require the 

development of parameters for estimating the effect of 

individual state programs and measures, for use as input 

assumptions for modeling.
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projections. We are further seeking 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 provide technical resources for conducting projections. 

The ISO/RTO Council, an organization of electric grid 

operators, has suggested that ISOs and RTOs could provide 

analytic support to help states develop and implement their 

plans. The ISOs and RTOs have the capability to model the 

system-wide effects of individual state plans. Providing 

assistance in this way, they felt, would allow states with 

borders that fall within an ISO or RTO footprint to assess the 

system-wide impacts of potential state plan approaches. In 

addition, as the state implements its plan, ISO/RTO analytic 

support would allow the state to monitor the effects of its plan 

on the regional electricity system. ISO/RTO analytic capability 

could help states assure that their plans are consistent with 

region-wide system reliability. The ISO/RTO Council suggested 

that the EPA ask states to consult with the applicable ISO/RTO 

in developing their state plans. 

8. Consideration of measures that the EPA did not include in the 

BSER determination 

States may include measures in their plans beyond those 

that the EPA included in its determination of the BSER. A wide 
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range of other measures that could CO2 emission reductions. These 

include, for example, transmission improvements, retrofitting 

EGUs with partial CCS, the use of biomass-derived fuels, use of 

new NGCC units online, and new hydroelectric power and 

increments, and they are among the measures that states might 

consider for inclusion in their plans. The agency solicits 

comment on whether these measures are appropriate to include in 

a state plan to achieve CO2 emission reductions. We also request 

comment on other measures that would be appropriate. In 

addition, should the EPA provide specific guidance on these 

measures? 

We request comment, in particular, on the use of biomassderived fuels, in place of affected EGUs, as a measure to 

include in a state plan to achieve CO2 emission reductions. 

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 
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fuels can, to varying degrees for different biomass feedstocks, 

sequester carbon from the atmosphere. For example, America’s 

forests currently play a critical role in addressing carbon 

pollution, removing nearly 12 percent of total U.S. greenhouse 

gas emissions each year. As a result, broadly speaking, burning 

biomass-derived fuels for energy recovery can yield climate 

benefits as compared to burning conventional fossil fuels. 

Many states have recognized the importance of forests and 

other lands for climate resilience and mitigation and have 

developed a variety of different sustainable forestry policies, 

renewable energy incentives and standards and greenhouse gas 

accounting procedures. Because of the positive attributes of 

certain biomass-derived fuels, the EPA also recognizes that 

biomass-derived fuels can play an important role in carbon 

dioxide (CO2) emission reduction strategies. We anticipate that 

states will likely 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 
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biomass feedstocks for energy recovery by stationary sources and 

developed a draft accounting framework which 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 

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. Once finalized, 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 
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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 statutory provision that requires EPA regulations 

implementing CAA section 111(d) to “permit the State in applying 

a standard of performance to any particular source under a 

[111(d)] plan . . . to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” 

As the EPA recognized in 1975 when it adopted framework 

regulations for implementation of CAA section 111(d) including 

the “remaining useful life” statutory provision, application of 

the implementing provisions in the framework regulations may not 

be appropriate in every instance.254 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 

 

254 The agency is not reopening or considering changes to the 

existing framework regulations. 
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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. The agency also 

requests comment on whether it would be desirable to include any 

aspects of this analysis 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 

As reflected in the framework regulations, the EPA believes 

that Congress included the remaining useful life provision in 

CAA section 111(d) to avoid imposition of unreasonable costs on 

an existing source that has a limited remaining useful life. 

This could occur if a rule imposed high capital costs that would 

normally be amortized over long periods of time. If a facility 

will cease operation in the near future, it may have little time 

to earn revenue to help pay for the pollution control 

investment, and the facility’s retirement may occur before that 

debt is paid off. In addition, the impact of the controls in 
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reducing emissions may be short-lived. As a result, it could be 

unreasonable for a facility with a short remaining useful life 

to incur the same pollution control costs that are reasonable 

for a facility with a long remaining useful life. Thus, 

remaining useful life could affect the determination of what 

requirements are appropriate for a facility with a short 

remaining useful life. 

The EPA’s 1975 framework regulations contain the following 

provision,255 which addresses remaining useful life and other 

facility-specific factors that might affect requirements for an 

existing source under section 111(d): 

“Unless otherwise specified in the applicable subpart, 

on a case-by-case basis for particular designated 

facilities, or classes of facilities, States may provide 

for the application of less stringent emission standards or 

longer compliance schedules than those otherwise required 

by paragraph (c) of this section256, provided that the state 

demonstrates with respect to each such 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 

 

255 40 CFR Section 60.24(f) 

256 Paragraph (c) requires that for pollutants that endanger 

public health, standards of performance in state plans must be 

as stringent as EPA’s emission guidelines.
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standard or final compliance time significantly more 

reasonable. 

The reference to “[u]nreasonable cost of control resulting 

from plant age” reflects 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 in some circumstances can affect 

the reasonableness of a control measure for a particular 

existing source. 

This regulatory provision provides the EPA’s default 

structure for implementing the remaining useful life provision 

of CAA section 111(d). The opening clause, however, which 

provides that this provision is applicable “unless otherwise 

specified in the applicable subpart” makes clear that this 

structure may not be appropriate in each case and that the EPA 

has discretion to alter the extent to which states may authorize 

relaxations to standards of performance that would otherwise 

apply to a particular source or source category, if appropriate 

under the circumstances of the specific source category and 

proposed guidelines. 

b. Implications for implementation of this emissions guideline 

In general, the EPA notes that the framework regulation 

provisions for remaining useful life and other facility-specific 
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factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 

much more like a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, and Kraft 

pulp plants specify emission limits for sources.257 In the case of 

such emission guidelines, some individual sources, by virtue of 

their age or other unique circumstances, may warrant special 

accommodation. 

In the guidelines for state plans to limit CO2 from affected 

EGUs that the EPA is proposing, the agency does not take that 

approach. Instead, the EPA is proposing to establish state 

emissions performance goals for the collective group of affected 

EGU in a state, and 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 

state-specific goals, and the flexibility provided to states in 

developing approvable CAA section 111(d) plans to achieve those 

goals, no relief for individual facilities is needed from 

requirements in the EPA’s guidelines, because the EPA’s 

 

257 [cites] 
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guideline contains no emissions standards that the state must 

apply directly to a specific EGU. 

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 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 would be authorized to make 

adjustments to a particular facility’s requirements on facilityspecific grounds, so long as any such adjustments are reflected 

(along with any necessary compensating emission reductions), 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 remaining useful life and other 

facility-specific considerations should not affect the 

determination of a state’s rate-based or mass-based emission 
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performance goal or the state’s obligation to develop and submit 

an approvable CAA section 111(d) plan that achieves that goal by 

the applicable deadline. 

Under the proposed guideline, states would have the 

flexibility to adopt a state plan that relies on emissionreducing requirements that do not require affected EGUs with a 

short remaining useful life to make major capital expenditures258

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.” 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. 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, the 

assumed 6 percent heat rate improvement in the EPA’s proposed 

 

258 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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BSER determination would be applicable to affected EGUs on a 

state-wide average basis, allowing the state to require a 

greater or lesser degree of heat rate improvement from any 

individual EGU in light of that EGU’s remaining useful life or 

any other source-specific factors that the state deemed 

appropriate to consider.259 The agency notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

to remove sulfur dioxide; a fleet-wide average cost for heat 

rate improvements at coal-fired generating units is $100/kW, 

compared with a typical SO2 scrubber cost of $500/kw (costs vary 

with unit size).260 In addition, the proposed guideline allows 

states to regulate affected EGUs through flexible regulatory 

approaches that do not require affected EGUs to incur large 

 

259 Where states are unable to achieve the average 6 percent heat 

rate improvement assumed in the EPA’s BSER determination in 

light of the remaining useful life of one or more of their 

affected EGUs or for any other reasons (or where state so choose 

based on other considerations), they may adopt plan provisions 

that will obtain a lesser degree of average heat rate 

improvement from affected EGUs. 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, as 

long as they provide additional compensating emission reductions 

with respect to the other three building blocks. 

260 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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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 avoid requirements that would result in stranded 

assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant in 

determining requirements that are directly applicable to 

affected EGUs. For all of the reasons above, the agency believes 

that the issue of remaining useful life will arise infrequently 

in the development of state plans to limit CO2 emissions from 

affected existing EGUs. Even if relief is due a particular 

facility, the state has an available toolbox of emission 

reduction methods that it can use to develop a section 111(d) 

plan that meets its emissions performance goal on time. The EPA 

therefore proposes that the remaining useful life of affected 

EGUs, and the other facility-specific factors identified in the 

existing framework 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. 

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

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 
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review of the “Accounting Framework for Biogenic CO2 Emissions 

from Stationary Sources,” issued in September 2011. That study 

was reviewed by the EPA’s Science Advisory Board in 2011 and 

2012 and the agency continues to assess the framework and 

consider the latest scientific analyses and technical input 

received from stakeholders. The EPA expects that the framework, 

when finalized, will be a resource that could help inform states 

in the development of their CAA section 111(d) plans. 

H. Resources for States to Consider in Developing Their Plans 

As part of the stakeholder outreach process, the EPA asked 

states what the agency could do to facilitate state plan 

development and implementation. Some states indicated that they 

wanted the EPA to create resources to assist with state plan 

development, especially resources related to accounting for enduse energy efficiency and renewable energy (EE/RE) in state 

plans. They requested clear methodologies for 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,”261 as well 

as the State Energy Efficiency Action Network’s “Energy 

 

261 http://epa.gov/airquality/eere/
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Efficiency Program Impact Evaluation Guide.”262 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 this is 

available at [http://www2.epa.gov/carbon-pollutionstandards/toolbox]. Current resources on the site focus on 

approaches states and other entities have already taken that 

reduce CO2 emissions from the electric utility sector. 

For the final rulemaking, the EPA plans to organize 

resources 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 

 

262

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

_guide.pdf
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EE/RE policies and programs,263 National Action Plan for Energy 

Efficiency (Action Plan),264 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 

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 

 

263 Appendix, State Plan Considerations TSD

264 http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html
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and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For GHG emissions, the PSD applicability 

analysis is described in the Prevention of Significant 

Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 

31514, June 3, 2010). As a general matter, a modifying major 

stationary source would trigger PSD permitting requirements for 

GHGs if it emits GHGs in excess of 100,000 tons per year (tpy) 

of carbon dioxide equivalents (CO2e), and it undergoes a change 

or change in the method of operation (modification) resulting in 

an emissions increase of 75,000 tpy CO2e as well as an increase 

on a mass basis. Once it has been determined that a change 

triggers the requirements of the NSR program, the source must 

obtain a permit prior to making the change. The pollutant(s) at 

issue and the air quality designation of the area where the 

facility is located or proposed to be built determine the 

specific permitting requirements. 

As part of its CAA section 111(d) plan, a state may require 

an affected EGU to undertake a physical or operational change to 
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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, the EGU would trigger 

NSR. 

As previously discussed in this preamble, states have 

considerable flexibility in selecting varied measures as they 

develop their plans to meet the goals of the emissions 

guidelines. One of these flexibilities is the ability of the 

state to establish the standards of performance in their CAA 

section 111(d) plans in such a way so that their affected 

sources, in complying with those standards, in fact would not 

have emissions increases that trigger NSR. To achieve this, the 

state would need to conduct an analysis consistent with the NSR 

regulatory requirements that supports its determination that as 

long as affected sources comply with the standards of 

performance in their CAA section 111(d) plan, the source’s 

emissions would not increase in a way that trigger NSR 

requirements. 

For example, a state could decide to adjust its demand side 

measures or increase reliance on renewable energy as a way of 

reducing the future emissions of an affected source initially 
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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 

change in dispatch would not, in fact, increase their emissions, 

due to reduced demand for their operation. The state could also, 

as part of its CAA section 111(d) plan, develop conditions for a 

source expected to trigger NSR that would limit the unit’s 

ability to move up in the dispatch enough to result in a 

significant net emissions increase that would trigger NSR 

(effectively establishing a synthetic minor limit). If we are 

satisfied with the state’s showing that the standards of 

performance in its plan, if complied with, will not have 

emissions increase that trigger NSR, we will approve this 

provision in the state plan. 

We request comment on whether, with adequate record 

support, the state plan could include a provision 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 
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analysis that would be required to support a state’s 

determination that sources will not trigger NSR when complying 

with the standards of performance included in the state’s CAA 

section 111(d) plan and the type of plan requirements, if any, 

that would need to be included in the state’s plan. 

As a result of such flexibility and anticipated state 

involvement, we expect that a limited number of affected sources 

would trigger NSR when states implement their plans. 

B. Implications for Title V Program 

The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; 

January 8, 2014) explained that regulating GHGs for the first 

time under section 111 of the CAA would make GHGs “regulated air 

pollutants” for the first time under the operating permit 

regulations of 40 CFR parts 70 and 71. This would result in GHGs 

becoming “fee pollutants” in certain state part 70 permit 

programs and in the EPA’s part 71 permit program, thus requiring 

the collection of fees for GHG emissions in these 

programs. Where title V fees would be required for GHGs, they 

would typically be charged at the same rate ($ per ton of 

pollutant) as all other fee pollutants. This would likely result 

in excessive and unnecessary fees being charged to subject 

sources. To avoid this situation, we proposed to exempt GHGs 

from the fee rates in effect for other fee pollutants, while 
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proposing an alternative fee that would be much lower than the 

fee charged to other fee pollutants, yet sufficient to cover the 

costs of addressing GHGs in operating permits. 

This title V fee issue is a one-time occurrence resulting 

from the promulgation of the first CAA section 111 standard to 

regulate GHGs (the EGU NSPS for new sources) and is not an issue 

for any other subsequent 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 

3 years or more, a permit reopening to incorporate the newly 

applicable requirement shall be completed no later than 18 
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months after promulgation of the applicable requirement. If the 

permit has a remaining life of less than 3 years, the newly 

applicable requirement must be incorporated at permit renewal. 

C. Interactions with Other EPA Rules 

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 

other recently finalized or proposed EPA rules.265 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. 

 

265 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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The EPA is closely monitoring MATS compliance and finds 

that the industry is making substantial progress. Plant owners 

are moving proactively to install controls that will achieve the 

MATS performance standards. Certain units, especially those that 

operate infrequently, may be considered not worth investing in 

given today’s electricity market, and those are closing. 

Existing sources subject to the MATS rule are given until 

April 16, 2015 to comply with the rule's requirements. The final 

MATS provided a foundation on which states and other permitting 

authorities could rely in granting an additional, 4th year for 

compliance provided for by the Act. States report that these 4th

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 reliabilityOn [INSERT 

PUBLICATION DATE OF FINAL RULE (which should be finalized in 

April)], 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). 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 
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manufacturing facilities.266 The 316(b) rule subjects existing 

power plants and manufacturing facilities that withdraw in 

excess of 2 million gallons per day (MGD) of cooling water, and 

use at least 25 percent of that water for cooling purposes, to a 

national 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 sitespecific 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., 8 years from the rule's 

effective date) to comply with the rule's impingement standards. 

 

266 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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They must comply with applicable site-specific 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 

fossilfuel-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 Clean Water 

Act. 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. 
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This proposed regulation, which includes new requirements for 

both existing and new generating units, would reduce the amount 

of toxic metals and other pollutants discharged to surface 

waters from power plants. 

 On June 21, 2010 (75 FR 35128), the EPA proposed the CCR 

rule, which 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.267 While the agency is still evaluating all the 

 

267 Beneficial use involves the reuse of CCRs in a product to 

replace virgin raw materials that would otherwise be obtained 
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available information and comments, and while a final risk 

assessment for the CCR rule has not yet been completed, reliance 

on data and analyses discussed in the preamble to the recent 

Steam Electric ELG proposal may 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 may 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.268 The EPA is under a court- 

 

through extraction. The EPA encourages the beneficial use of 

CCRs in an appropriate and protective manner, because this 

practice can produce environmental, economic, and performance 

benefits. The Agency recently evaluated the environmental 

impacts associated with encapsulated beneficial uses of fly ash 

used as a direct substitute for Portland cement in concrete, and 

FGD gypsum used as a replacement for mined gypsum in wallboard. 

The EPA concluded that the beneficial use of CCRs in concrete 

and wallboard is appropriate because the environmental releases 

of constituents of potential concern (COPC) during use by the 

consumer are comparable to or lower than those from analogous 

non-CCR products, or are at or below relevant regulatory and 

health-based benchmarks for human and ecological receptors. See

U.S. Environmental Protection Agency, Coal Combustion Residual 

Beneficial Use Evaluation: Fly Ash Concrete and FGD Gypsum 

Wallboard (2014). 

268 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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ordered deadline to complete the CCR rulemaking by December 19, 

2014. 

 The EPA recognizes the importance of assuring that each of 

the rules described above can achieve its intended environmental 

objectives in a commonsense, cost-effective manner consistent 

with underlying statutory requirements and while assuring a 

reliable power system. Executive Order (EO) 13563, “Improving 

Regulation and Regulatory Review,” issued on January 18, 2011, 

states that “[i]n developing regulatory actions and identifying 

appropriate approaches, each agency shall attempt to promote... 

coordination, simplification, and harmonization. Each agency 

shall also seek to identify, as appropriate, means to achieve 

regulatory goals that are designed to promote innovation.” 

Within the EPA, we are paying careful attention to the 

interrelatedness and potential impacts on the industry, 

reliability and cost that these various rulemakings can have. 

As discussed in Sections VII and VIII of this preamble, the 

EPA is proposing to give states broad flexibility in developing 

approvable plans under CAA section 111(d), including the ability 

to adopt rate-based or mass-based emission performance goals, 

and to rely on a wide variety of CO2 emission reduction measures. 

 

 
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The EPA is also proposing to give states considerable 

flexibility with respect to the timeframes for plan development 

and implementation, with up to two or three years permitted for 

final plans to be submitted after the proposed GHG emission 

guidelines are finalized, and up to fifteen years for all 

emission reduction measures to be fully implemented. In light of 

these flexibilities, we believe that states will have ample 

opportunity, when developing and implementing their CAA section 

111(d) plans, to coordinate their response to this requirement 

with source and state responses to any obligations that may be 

applicable to affected EGUs as a result of the MATS, 316(b), SE 

ELG and CCR rules – all of which are or will be final rules 

before this rulemaking is finalized – and to do so in a manner 

that will help reduce cost and ensure reliability, while also 

ensuring that all applicable environmental requirements are 

met.269

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 

 

269 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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coordinate planning and investment decisions with respect to 

those rules) and, where possible, implement integrated 

compliance strategies. For example, in the proposed SE ELG rule, 

the EPA describes its current thinking on how it might 

effectively harmonize the potential requirements of that rule 

with the requirements of the final CCR rule, to the extent that 

both rules may regulate or affect the disposal of coal 

combustion wastes to and from surface impoundments at power 

plants.270 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.271

 

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

34441. 

271 [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 
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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. 

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. 

 

timeline for implementation that allows for coordinated planning 

and protects electricity reliability for consumers. 
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The SO2 NAAQS was revised in June 2010 to protect public 

health from the short-term effects of SO2 exposure. In July 2013, 

the EPA designated 29 areas in 16 states as nonattainment for 

the SO2 NAAQS. The EPA based these nonattainment designations on 

the most recent set of certified air quality monitoring data as 

well as an assessment of nearby emission sources and weather 

patterns that contribute to the monitored levels. The EPA 

intends to address the designations for all other areas in 

separate actions in the future272. 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. 

 

272 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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The development of these SIPs may, where applicable, have 

significant implications for existing fossil fuel-fired EGUs, as 

well as for the states that are responsible for developing them. 

The timeframes for submittal of SIPs for the various programs 

and the timeframes we are proposing for submittal of the CAA 

section 111(d) state plans will allow considerable time for 

coordination by states in the development of their respective 

plans. The EPA is willing to work with states to assist them in 

coordinating their efforts across these planning processes. The 

EPA believes that CAA section 111(d) efforts and actions will 

tend to contribute to overall air quality improvements and thus 

should be complementary to criteria pollutant and regional haze 

SIP efforts. 

In light of the broad flexibilities we are proposing in 

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 
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requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

X. Impacts of the Proposed Action273

A. What are the air impacts? 

The EPA anticipates significant emission reductions under 

the proposed guidelines. CO2 emissions are projected to be 

reduced, relative 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 22 percent 

to 23 percent in 2030. 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 7 and 8 show 

expected CO2 and other air pollutant emission reductions in the 

base case, with the proposed Option 1 and regulatory alternative 

Option 2, respectively, for 2020, 2025, and 2030. 

 

273 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 

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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Table 7 – 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 N/A

Proposed 1,790 1,184 1,213 

Guidelines 

Emission 

Reductions 

 -371 -292 -345 

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 1,730 1,120 1,166 N/A

Guidelines 

Emission 

Reductions 

 -501 -395 -421 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 N/A

Proposed 1,711 1,106 1,131 

Guidelines 

Emission 

Reductions 

 -545 -424 -407 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,777 1,140 1,191 N/A

Emission 

Reductions -383 -335 -367 

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 N/A

Proposed 

Guidelines 1,724 1,090 1,151 

Emission 

 Reductions 

 -506 -425 -436 

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 N/A

Proposed 

Guidelines 1,701 1,059 1,109 

Emission 

Reductions -555 -471 -428 

Source: Integrated Planning Model, 2014. 
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N/A – not yet available. 

Table 8 - 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 N/A

Proposed 

Guidelines 1,878 1,231 1,290 

Emissions 

Reductions -283 -244 -268 

2025 Regional Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,862 1,218 1,279 N/A

Emissions 

Reductions -368 -297 -309 

2030 Regional Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,903 1,243 1,286 N/A

Emissions 

Reductions -353 -287 -252 

2020 State Compliance Approach 

Base Case 2,161 1,476 1,559 

Proposed 

Guidelines 1,866 1,208 1,277 

Emissions 

Reductions -295 -267 -281 N/A

2025 State Compliance Approach 

Base Case 2,231 1,515 1,587 

Proposed 

Guidelines 1,855 1,188 1,271 

Emissions 

Reductions -376 -327 -317 N/A

2030 State Compliance Approach 

Base Case 2,256 1,530 1,537 

Proposed 

Guidelines 1,882 1,209 1,264 

Emissions 

Reductions -373 -321 -274 N/A

Source: Integrated Planning Model, 2014. 
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N/A – not yet available. 

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 only partly reflect 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 

(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 
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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 

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 (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 
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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). 

The total combined climate benefits and health co-benefits 

are estimated to be $21 to $40 billion in 2020 and $32 to $63 

billion in 2030 (2011$ at a 3-percent discount rate [model 

average]). The net benefits are estimated to be $18 to $36 

billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-

percent discount rate [model average]). For the purposes of this 

summary, we list the climate benefits associated with the 

marginal value the model average at 3% discount rate, however we 

emphasize the importance and value of considering the full range 

of SCC values. 

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 
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or designated critical habitat. Section 7(a)(2) of the ESA 

requires federal agencies, in consultation with the U.S. Fish 

and Wildlife Service (FWS) and/or the National Marine Fisheries 

Service, to ensure that actions they authorize, fund, or carry 

out are not likely to jeopardize the continued existence of 

federally listed endangered or threatened species or result in 

the destruction or adverse modification of designated critical 

habitat of such species. 16 U.S.C. § 1536(a)(2). Under relevant 

implementing regulations, section 7(a)(2) applies only to 

actions where there is discretionary federal involvement or 

control. 50 CFR § 402.03. Further, under the regulations 

consultation is required only for actions that “may affect” 

listed species or designated critical habitat. 50 CFR § 402.14. 

Consultation is not required where the action has no effect on 

such species or habitat. Under this standard, it is the federal 

agency taking the action that evaluates the action and 

determines whether consultation is required. See 51 FR 19926, 

19949 (June 3, 1986). Effects of an action include both the 

direct and indirect effects that will be added to the 

environmental baseline. 50 CFR § 402.02. Indirect effects are 

those that are caused by the action, later in time, and are 

reasonably certain to occur. Id. To trigger a consultation 

requirement, there must thus be a causal connection between the 
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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, FWS and DOI expressed the view that the best scientific 

data available are insufficient to draw a causal connection 

between GHG emissions and effects on the species in its 

habitat.274 The DOI Solicitor concluded that where the effect at 

 

274 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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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 7 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 question275 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). 

275 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. Preamble Table 7. However, 

CAA section 111(d)(1) standards cannot directly control 

emissions of criteria pollutants. Consequently, section 111(d) 

provides no discretion to adjust the standard based on potential 
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impacts to endangered species of reduced criteria pollutant 

emissions. Section 7(a)(2) consultation thus is not required 

with respect to the projected reductions of criteria pollutant 

emissions. See 50 CFR § 402.03; see also, National Lime Ass’n 

v. EPA, 233 F. 3d 625, 638-39 (D.C. Cir. 2000)(although CAA 

section 112(b)(2) prohibits the EPA from listing criteria 

pollutants as hazardous air pollutants, the EPA may use PM as a 

surrogate for metal hazardous air pollutants and reductions in 

PM do not constitute impermissible regulation of a criteria 

pollutant). 

Moreover, there are substantial questions as to whether any 

potential for relevant effects results from any element of the 

proposed rule or would result instead from the separate actions 

of States establishing standards of performance for existing 

sources and implementing and enforcing those standards. Cf. 

American Trucking Assn’s v. EPA, 175 F. 3d 1027, 1043-45 (D.C. 

Cir. 1999), rev’d on different grounds sub nom., Whitman v. 

American Trucking Assn’s, 531 U.S. 457 (2000) (National Ambient 

Air Quality Standards have no economic impact, for purposes of 

Regulatory Flexibility Act, because impacts result from the 

actions of States through their development, implementation and 

enforcement of state implementation plans). Thus, for example, 

although questions may exist whether actions such as increased 
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utilization of solar or wind power could have effects on listed 

species, the EPA believes that such effects (if any) would 

result from decisions and actions by states in developing, 

implementing and enforcing their plans. The precise steps States 

choose to take in that regard cannot be determined or ordered by 

this federal action, and they are not sufficiently certain to be 

attributable to this proposed rule for ESA purposes. 

Consequently, for this additional reason, the EPA does not 

believe that this proposed rule (if enacted) would have effects 

on listed species that would trigger the section 7 (a)(2) 

consultation requirement. 

D. What are the energy impacts?

 The proposed guidelines have important energy market 

implications. Under Option 1, average nationwide retail 

electricity prices are projected to increase by roughly 6 to 7 

percent in 2020, 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. The decreased projection in 

these two metrics 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. 
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 The average delivered coal price to the power sector is 

projected to decrease by 16 to 17 percent in 2020 and roughly 18 

percent in 2030, relative to the base case for Option 1. The EPA 

also projects that electric power sector-delivered natural gas 

prices will increase by 9 to 12 percent in 2020, with negligible 

changes by 2030. Natural gas use for electricity generation will 

increase by as much as 1.2 trillion cubic feet (BCF) in 2020 

relative to the base case, declining 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 
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use of coal by the power sector will decrease roughly 30 to 32 

percent in 2030. Renewable energy capacity is anticipated to 

increase by roughly 12 GW in 2020 and by 9 GW in 2030 under 

Option 1. Energy market impacts from the guidelines are 

discussed more extensively in the RIA found in the docket for 

this rulemaking. 

E What are the compliance costs? 

 The ‘‘compliance costs’’ of this proposed action are 

represented in this analysis as the change in electric power 

generation costs between the base case and policy case in which 

states pursue a distinct set of strategies beyond the strategies 

taken in the base case to meet the terms of the EGU GHG emission 

guidelines, and include cost estimates for demand-side energy 

efficiency. The compliance assumptions – and, therefore, the 

projected “compliance costs” - set forth in this analysis are 

illustrative in nature and do not represent the full suite of 

compliance flexibilities states may ultimately pursue. These 

illustrative compliance scenarios are designed to reflect, to 

the extent possible, the scope and the nature of the proposed 

guidelines. However, there is considerable uncertainty with 

regards to the precise measures that states will adopt to meet 

the proposed requirements, because there are considerable 
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flexibilities afforded to the states in developing their state 

plans. 

 The EPA projects that the annual incremental compliance 

cost of Option 1 is estimated to be between $5.5 and $7.5_ 

billion in 2020 and between $7.3 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 2030, the estimated 

compliance cost of Option 2 is estimated to be between $1.9 and 

$3.1 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 $61.6 million (2011$) 

in 2020 for Options 1 and 2 and $8.2 million for both Options 1 

and 2 in 2025 and 2030. More detailed cost estimates are 

available in the RIA included in the rulemaking docket. 

F. What are the economic and employment impacts? 
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The proposed standards are projected to result in certain 

changes to power system operation as a result of the application 

of state emission rate goals. Overall, we project dispatch 

changes, changes to fossil fuel and retail electricity prices, 

and some additional coal retirements. Average electric power 

sector-delivered natural gas prices are projected to increase by 

roughly 9 to 12 percent in 2020 in Option 1, with negligible 

changes by 2030. Under Option 2, electric power sector natural 

gas prices are projected to increase by roughly 8 percent in 

2020, on an average nationwide basis, and decrease in 2030. 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 coal-fired 

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 2030. 
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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 

approximately an 8 percent reduction in 2030 for Option 2. In 

response, there are anticipated to be notable changes to costs, 

prices, and electricity generation in the power sector as more 

end-use efficiency is realized. 

Changes in price or demand for electricity, natural gas, 

coal, can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in cost of production may 
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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, 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 25,900to 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 78,800 jobs in 2020 for Option 1 and 57,000 increased 

jobs for Option 2. By its nature, energy efficiency reduces 

overall demand for electric power. The EPA recognizes as more 

efficiency is built into the U.S. power system over time, lower 
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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 numbers reported in 

these sectors may have been previously employed elsewhere. 

Therefore 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 

Mercury and Air Toxics Standards. The health and welfare 

benefits from reducing air pollution are considered co-benefits 

for these standards. For this rulemaking, we were only able to 
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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 $32 billion 

to $51 billion in 2020 and $54 billion to $86 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 $33 to $54 billion in 

2020 and $56 to $89 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 $25 billion to $41 billion in 2020 and $35 billion to $56 

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 $26 billion 

to $42 billion in 2020 and $35 billion to $57 billion in 2025 

(2011 dollars at a 3-percent discount rate [model average]). A 

summary of the emission reductions and monetized benefits 

estimated for this rule at all discount rates and additional 

analysis years is provided in Tables 9 through 14 of this 

preamble. 
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Table 9 Summary of the Monetized Global Climate Benefits for the 

Proposed Option 1 (billions of 2011 dollars)a

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

2020 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

371 383

5 percent (average 

SCC) 

$4.7 $4.9

3 percent (average 

SCC) 

$17 $18

2.5 percent (average 

SCC) 

$25 $26

3 percent (95th

percentile SCC) 

$51 $52

2025 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

501 506

5 percent (average 

SCC) 

$7.5 $7.6

3 percent(average SCC) $25 $25

2.5 percent (average 

SCC) 

$37 $37

3 percent (95th

percentile SCC) 

$76 $77

2030 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

545 555

5 percent (average 

SCC) 

$9.3 $9.5

3 percent(average SCC) $30 $31

2.5 percent (average 

SCC) 

$44 $44

3 percent (95th

percentile SCC) 

$92 $94
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a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global social cost of carbon 

(SCC) estimates for the analysis years (2020, 2025, 2030) and 

are rounded to two significant figures. 
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Table 10 Summary of the Monetized Global Climate Benefits for 

the Option 2 (billions of 2011 dollars)a

Discount Rate 

(Statistic) 

Monetized Climate Benefits 

2020 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

283 295

5 percent (average 

SCC) 

$3.6 $3.8

3 percent (average 

SCC) 

$13 $14

2.5 percent (average 

SCC) 

$19 $20

3 percent (95th

percentile SCC) 

$39 $40

2025 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

368 376

5 percent (average 

SCC) 

$5.5 $5.6

3 percent(average SCC) $18 $19

2.5 percent (average 

SCC) 

$27 $28

3 percent (95th

percentile SCC) 

$56 $57

2030 Regional 

Compliance 

State 

Compliance 

CO2 Reductions 

(million 

metric tons) 

353 373

5 percent (average 

SCC) 

$6.0 $6.4

3 percent(average SCC) $20 $21

2.5 percent (average 

SCC) 

$28 $30

3 percent (95th

percentile SCC) 

$60 $63
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a

 Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the federal government’s global SCC estimates for the 

analysis years (2020, 2025, 2030) and are rounded to two 

significant figures. 
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Table 11 Summary of the Monetized Health Co-Benefits for the 

Proposed Standards Option 1 Regional Compliance Approach in the 

U.S. (billions of 2011 dollars)a 

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 Regional Compliance Approach 2020 

PM2.5 precursors b 

SO2 292 $12 to $26 $11 to $24 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 345 $2.2 to $5.0 $2.0 to 

$4.5 

Ozone precursor c 

NOx 146 $0.63 to 

$2.7 

$0.63 to 

$2.7 

Total Monetized Health Co-benefits $15 to $34 $13 to $31 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $51 $30 to $48 

Option 1 Regional Compliance Approach 2025 

PM2.5 precursors b 

SO2 395 $17 to $38 $15 to $35 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 421 $3.0 to $6.8 $2.7 to 

$6.1 

Ozone precursor c 

NOx 180 $1.0 to $4.3 $1.0 to 

$4.3 

Total Monetized Health Co-benefits $21 to $50 $19 to $45 
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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$46 to $75 $44 to $70 

Option 1 Regional Compliance Approach 2030 

PM2.5 precursors b

SO2 424 $20 to $44 $18 to $40 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 407 $3.0 to $6.7 $2.7 to 

$6.1 

Ozone precursor c

NOx 176 $1.1 to $4.5 $1.1 to 

$4.5 

Total Monetized Health Co-benefits $24 to $55 $21 to $50 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$54 to $86 $52 to $81 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 
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mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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Table 12 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Proposed Guidelines Option 1 State Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 State Compliance Approach in 2020 

PM2.5 precursors b 

SO2 335 $13 to $29 $11 to $26 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 367 $2.2 to 

$4.9 

$2.0 to 

$4.4 

Ozone precursor c 

NOx 157 $0.64 to 

$2.7 

$0.64 to 

$2.7 

Total Monetized Health Co-benefits $15 to $36 $14 to $33 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$33 to $54 $32 to $50 

Option 1 State Compliance Approach in 2025 

PM2.5 precursors b 

SO2 425 $18 to $40 $16 to $36 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 436 $2.9 to 

$6.5 

$2.6 to 

$5.8 

Ozone precursor c 

NOx 190 $1.0 to 

$4.4 

$1.0 to 

$4.4 

Total Monetized Health Co-benefits $22 to $51 $20 to $46 
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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$47 to $76 $45 to $71 

Option 1 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 471 $21 to $47 $19 to $43 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 428 $2.9 to 

$6.6 

$2.6 to 

$6.0 

Ozone precursor c

NOx 187 $1.1 to 

$4.6 

$1.1 to 

$4.6 

Total Monetized Health Co-benefits $25 to $58 $23 to $53 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$56 to $89 $53 to $84 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 
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Page 494 of 584

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 
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Table 13 Summary of the Monetized Health Co-Benefits in the U.S. 

for the Option 2 Regional Compliance Approach 

(billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

 Option 2 Regional Compliance Approach 2020 

PM2.5 precursors b 

SO2 244 $9.8 to $22 $8.9 to $20

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 268 $1.7 to 

$3.9 

$1.6 to 

$3.5 

Ozone precursor c 

NOx 111 $0.47 to 

$2.0 

$0.47 to 

$2.0 

Total Monetized Health Co-benefits $12 to $28 $11 to $25 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$25 to $41 $24 to $38 

Option 2 Regional Compliance Approach in 2025 

PM2.5 precursors b 

SO2 $13 to $29 $12 to $26 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

297 

Directly emitted PM2.5 

(crustal) 

NOx 309 $2.2 to 

$5.0 

$2.0 to 

$4.5 

Ozone precursor c 

NOx 129 $0.73 to 

$3.1 

$0.73 to 

$3.1 

Total Monetized Health Co-benefits $16 to $37 $14 to $34 
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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $56 $33 to $52 

Option 2 Regional Compliance Approach in 2030 

PM2.5 precursors b

SO2 287 $13 to $30 $12 to $27 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 252 $1.8 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c

NOx 110 $0.66 to 

$2.8 

$0.66 to 

$2.8 

Total Monetized Health Co-benefits $16 to $37 $14 to $34 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $56 $34 to $53 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 
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Page 497 of 584

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate, however we emphasize the importance 

and value of considering the full range of SCC values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Table 14 Summary of the Monetized Health Co-Benefits in the U.S. 

for Option 2 State Compliance Approach (billions of 2011 

dollars)a

Pollutant 

National 

Emission 

Reductions 

(thousands of 

short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 2 State Compliance Approach in 2020 

PM2.5 precursors b 

SO2 267 $10 to $23 $9.1 to $21

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 281 $1.7 to 

$3.8 

$1.5 to 

$3.4 

Ozone precursor c 

NOx 119 $0.48 to 

$2.1 

$0.48 to 

$2.1 

Total Monetized Health Co-benefits $12 to $29 $11 to $26 
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Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$26 to $42 $25 to $40 

Option 2 State Compliance Approach in 2025 

PM2.5 precursors b 

SO2 327 $14 to $30 $12 to $27 

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

 

Directly emitted PM2.5 

(crustal) 

NOx 317 $2.1 to 

$4.7 

$1.9 to 

$4.2 

Ozone precursor c 

NOx 136 $0.72 to 

$3.1 

$0.72 to 

$3.1 

Total Monetized Health Co-benefits $16 to $38 $15 to $35 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$35 to $57 $34 to $54 

Option 2 State Compliance Approach in 2030 

PM2.5 precursors b

SO2 321 $14 to $32 $13 to $29 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 274 $1.9 to 

$4.2 

$1.7 to 

$3.8 

Ozone precursor c

NOx 120 $0.68 to 

$2.9 

$0.68 to 

$2.9 

Total Monetized Health Co-benefits $17 to $39 $15 to $36 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$37 to $60 $36 to $56 

a

 [Emission reductions of directly emitted particles are not yet 

available but will be added to the totals above.] All estimates 

are for the analysis years (2020, 2025, 2030) and are rounded to 
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Page 499 of 584

two significant figures, so estimates may not sum. It is 

important to note that the monetized co-benefits do not include 

reduced health effects from direct exposure to SO2, direct 

exposure to NO2, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b

 The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. PM co-benefits are shown as a range reflecting the 

use of two concentration-response functions, with the lower end 

of the range based on a function from Krewski et al. (2009) and 

the upper end based on a function from Lepeule et al. (2012). 

These models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c

 The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d

 We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent), which each increase over time. For the purposes of 

this table, we show the benefits associated with the model 

average at 3% discount rate; however, we emphasize the 

importance and value of considering the full range of SCC 

values. We provide combined climate and health estimates based 

on additional discount rates in the RIA. 

The EPA has used the U.S. government’s SCC estimates to 

analyze CO2 climate impacts of this rulemaking. The U.S. 

government first published the federal SCC estimates in 2010 

following an interagency process that included the EPA and other 

executive branch entities; the process used three integrated 

assessment models (IAM) to develop SCC estimates and selected 
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Page 500 of 584

four global values for use in regulatory analyses. The U.S. 

government recently updated these estimates using new versions 

of each integrated assessment model and published them in 2013. 

The 2013 update did not revisit the 2010 modeling decisions 

(e.g., with regard to the discount rate, reference case 

socioeconomic and emission scenarios or equilibrium climate 

sensitivity). Rather, improvements in the way damages are 

modeled are confined to those that have been incorporated into 

the latest versions of the models by the developers themselves 

and published in the peer-reviewed literature. The 2010 SCC 

Technical Support Document (2010 SCC TSD) provides a complete 

discussion of the methods used to develop these estimates and 

the 2013 SCC TSD presents and discusses the updated 

estimates.276,277 

 

276 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf>. 

277 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 
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The EPA and other agencies have sought public comments on 

the USG SCC estimates as part of various rulemakings. In 

addition, OMB’s Office of Information and Regulatory Affairs 

recently sought public comment on the approach used to develop 

the estimates. The comment period ended on February 26, 2014, 

and OMB is reviewing the comments received. 

The four SCC estimates, updated in 2013, are as follows: 

$13, $46, $68, and $137 per metric ton of CO2 emissions in the 

year 2020 (2011 dollars).278 The first three values are based on 

the average SCC from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. SCCs at several discount rates 

are included because the literature shows that the SCC is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

 

Group on Social Cost of Carbon, with participation by the 

Council of Economic Advisers, Council on Environmental Quality, 

Department of Agriculture, Department of Commerce, Department of 

Energy, Department of Transportation, Environmental Protection 

Agency, National Economic Council, Office of Energy and Climate 

Change, Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

November 2013). Also available at: 

<http://www.whitehouse.gov/sites/default/files/omb/assets/infore

g/technical-update-social-cost-of-carbon-for-regulator-impactanalysis.pdf>. 

278 The 2010 and 2013 TSDs present SCC in $2007. The estimates 

were adjusted to 2011$ using the GDP Implicit Price Deflator. 

Also available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-

02/pdf/ECONI-2013-02-Pg3.pdf. 
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by different generations). The fourth value is the 95th

percentile of the SCC from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

impacts from temperature change further out in the tails of the 

SCC distribution (representing less likely, but potentially 

catastrophic, outcomes). 

The 2010 SCC TSD noted a number of limitations to the SCC 

analysis, including the incomplete way in which the integrated 

assessment models capture catastrophic and non-catastrophic 

impacts, their incomplete treatment of adaptation and 

technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk 

aversion. Current integrated assessment models do not assign 

value to all of the important physical, ecological, and economic 

impacts of climate change recognized in the climate change 

literature for various reasons, including the inherent 

difficulties in valuing non-market impacts and the fact that the 

science incorporated into these models understandably lags 

behind the most recent research. Nonetheless, these estimates 

and the discussion of their limitations represent the best 

available information about the social benefits of CO2 emission 

reductions to inform the benefit-cost analysis. Model developers 

continually update the models to incorporate recent research. 
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The new versions of the models used to estimate the values 

presented in this rulemaking offer some improvements in these 

areas identified above, although further work is warranted. 

Accordingly, the EPA and other parties continue to conduct 

research on modeling and valuation of climate impacts with the 

goal of improving these estimates. Additional details are 

provided in the SCC TSDs. 

 The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions under 

illustrative compliance options for the proposed standards. 

Unlike the global SCC estimates, the air pollution health cobenefits are estimated for the contiguous U.S. only. We used a 

“benefit-per-ton” approach to estimate the benefits of this 

rulemaking. To create the PM2.5 benefit-per-ton estimates, this 

approach uses a model to convert emissions of PM2.5 precursors 

into changes in ambient PM2.5 levels and another model to 

estimate the changes in human health associated with that change 

in air quality, which are then divided by the emissions in 

specific sectors. National average benefit-per-ton estimates for 

the EGU sector were derived using the approach published in Fann 
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et al. (2012),279 but they have since been updated to reflect the 

studies and population data in the 2012 PM NAAQS RIA and were 

separated into regional estimates to provide greater spatial 

resolution.280 In addition, we generated regional benefit-per-ton 

estimates for changes in ozone exposure. The ozone estimates 

used the ozone information from the sector modeling for the EGU 

sector described in Fann et al. (2012) and the health impact 

assumptions used in the Ozone NAAQS RIAs.281,282 To calculate the 

co-benefits for the proposed standards, we multiplied the 

regional benefit-per-ton estimates for the EGU sector by the 

 

279 Fann, N., K.R. Baker and C.M. Fulcher. 2012. “Characterizing 

the PM2.5-related health benefits of emission reductions for 17 

industrial, area and mobile emission sectors across the U.S.” 

Environment International 49 41–151. 

280 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>. 

281 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final 

Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, 

NC: Office of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and Cost Group 

Research. (EPA document number EPA-452/R-08-003, March). 

Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 

282 U.S. Environmental Protection Agency (U.S. EPA). 2010. 

Section 3: Re-analysis of the Benefits of Attaining Alternative 

Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf>. 
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Page 505 of 584

corresponding emission reductions.283 All benefit-per-ton 

estimates reflect the geographic distribution of the modeled 

emissions, which may not exactly match the emission reductions 

in this rulemaking, and thus they may not reflect the local 

variability in population density, meteorology, exposure, 

baseline health incidence rates, or other local factors for any 

specific location. More information regarding the derivation of 

the benefit-per-ton estimates is available in the RIA. 

These models assume that all fine particles, regardless of 

their chemical composition, are equally potent in causing 

premature mortality because the scientific evidence is not yet 

sufficient to allow differentiation of effects estimates by 

particle type. Even though we assume that all fine particles 

have equivalent health effects, the benefit-per-ton estimates 

vary between precursors depending on the location and magnitude 

of their impact on PM2.5 levels, which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

 

283 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 

<http://www.epa.gov/airquality/benmap/models/Source_Apportionmen

t_BPT_TSD_1_31_13.pdf>. 
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statistical life used to value reductions in premature 

mortality. For PM2.5, we cite two key empirical studies, one 

based on the American Cancer Society cohort study284 and the 

extended Six Cities cohort study.285 We present the PM2.5 cobenefits results as a range based on the concentration-response 

functions from these two epidemiology studies, but this range 

does not capture the full range of uncertainty inherent in the 

co-benefits estimates. In the RIA for this rule, which is 

available in the docket, we also include PM2.5 co-benefits 

estimates derived from expert judgments (Roman et al., 2008)286

as a characterization of uncertainty regarding the PM2.5-

mortality relationship. For the ozone co-benefits, we present the 

results as a range reflecting the use of several different 

concentration-response functions for mortality, with the lower 

 

284 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. 

Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 

American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute. 

285 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970. 

286 Roman, H., et al. 2008. “Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S.” Environmental Science & Technology, Vol. 42, No. 7, 

February, pp. 2268 – 2274. 
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end of the range based on a function from Bell et al. (2004)287

and the upper end based on a function from Levy et al. (2005)288. 

Similar to PM2.5, the range of ozone co-benefits does not capture 

the full range of inherent uncertainty. 

In this analysis, the EPA assumes that the health impact 

function for fine particles is without a threshold. This is 

based on the conclusions of EPA’s Integrated Science Assessment 

for Particulate Matter,289 which evaluated the substantial body 

of published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

 

287 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8. 

288 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone 

exposure and mortality: an empiric bayes metaregression 

analysis.” Epidemiology. 16(4): p. 458-68. 

289 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. 
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In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available,290 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule’s 

emission reductions at each PM2.5 level. As a surrogate measure of 

mortality impacts, we provide the percentage of the population 

exposed above the lowest measured PM2.5 level (LML) in each of the 

studies from which we obtained concentration-response functions 

for PM2.5 mortality, using the estimates of PM2.5 from the source 

apportionment modeling used to calculate the benefit-per-ton 

estimates for the EGU sector. Using the Krewski et al. (2009) 

study, 93 percent of the population is exposed to annual mean 

PM2.5 levels at or above the LML of 5.8 micrograms per cubic 

meter (μg/m3

). Using the Lepeule et al. (2012) study, 67 percent 

of the population is exposed above the LML of 8 μg/m3

. It is 

important to note that baseline exposure is only one parameter 

 

290 In addition, site-specific emission reductions will depend upon how states 

implement the guidelines. 
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Page 509 of 584

in the health impact function, along with baseline incidence 

rates, population, and change in air quality. Therefore, caution 

is warranted when interpreting the LML assessment for this rule 

because these results are not consistent with results from rules 

that had air quality modeling. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 

indication of the expected health benefits of the air pollution 

emission reductions for the illustrative compliance options for 

the proposed standards under a set of reasonable assumptions. 

This analysis does not include the type of detailed uncertainty 

assessment found in the 2012 PM2.5 National Ambient Air Quality 

Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the 

necessary air quality input and monitoring data to conduct a 

complete benefits assessment. In addition, using a benefit-perton approach adds another important source of uncertainty to the 

benefits estimates. The 2012 PM2.5 NAAQS benefits analysis 

provides an indication of the sensitivity of our results to 
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Page 510 of 584

various assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOx, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for these proposed amendments. 

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket. 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

Under Section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an "economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more or 

adversely affect in a material way the economy, a sector of the 

economy, productivity, competition, jobs, the environment, 

public health or safety, or state, local, or tribal governments 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 511 of 584

or communities. The $100 million threshold can be triggered by 

either costs or benefits, or a combination of them. Accordingly, 

the EPA submitted this action to OMB for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and any 

changes made in response to OMB recommendations have been 

documented in the docket for this action. 

 The EPA also prepared an analysis of the potential costs 

and benefits associated with this action. This analysis is 

contained in the RIA for this proposed rule. A copy of the 

analysis is available in the docket for this action.

 Consistent with EO 12866 and EO 13563, the EPA estimated 

the costs and benefits for illustrative compliance approaches of 

implementing the proposed guidelines. This proposal sets goals 

to reduce CO2 emissions from the electric power industry. Actions 

taken to comply with the proposed guidelines will also reduce 

the emissions of directly emitted PM2.5, sulfur dioxide (SO2) and 

nitrogen oxides (NOX). The benefits associated with these PM, SO2

and NOX reductions are referred to as co-benefits, as these 

reductions are not the primary objective of this rule. 

 The EPA has used the U.S. government’s social cost of 

carbon (USG 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 
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USG 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 by 

the USG: the model average at 3% discount rate. For the regional 

compliance approach, the EPA estimates that in 2020 this Option 

1 proposal will yield monetized climate benefits (in 2011$) of 

approximately $17 billion (3 percent model average). The air 

pollution health co-benefits in 2020 are estimated to be $15 

billion to $34 billion (2011$) for a 3 percent discount rate and 

$13 billion to $31 billion (2011$) 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 $26 billion to $46 billion assuming a regional compliance 

approach (2011$) using a 3 percent discount rate (model 

average). This range of net benefits is also estimated to be $26 

billion to $45 billion assuming a state compliance approach 

(2011$) using a 3 percent discount rate (model average). Table 

15 shows the climate benefits, health co-benefits, cost and net 
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benefits for Option 1 in 2020 for state and regional compliance 

approaches. Table 16 shows similar estimates for 2030. 

 For Option 1 in 2030 assuming a regional compliance 

approach, the EPA estimates this proposal will yield monetized 

climate benefits (in 2011$) of approximately $30 billion (3 

percent, model average). The air pollution health co-benefits in 

2030 are estimated to be $24 billion to $55 billion (2011$) for 

a 3 percent discount rate and $21 billion to $50 billion (2011$) 

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 $47 billion to $78 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 

$25 billion to $58 billion (2011$) for a 3 percent discount rate 

and $23 billion to $53 billion (2011$) for a 7 percent discount 

rate. The annual illustrative compliance costs estimated using 

IPM, inclusive of demand side energy efficiency program and 
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participant costs and MRR costs, are approximately $8.8 billion 

(2011$) in 2030. The quantified net benefits (the difference 

between monetized benefits and costs) in 2030 are estimated to 

be $47 billion to $80 billion (2011$) 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 15—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – 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

$15 to $34 $13 to $31 

Total Compliance 

Costs d

$5.5 $5.5 

Net Monetized 

Benefits e

$26 to $45 $25 to $42 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.3 tons of Hg 

Ecosystem Effects 
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Visibility impairment 

Option 1 State Compliance Approach

Climate benefits b $18

Air pollution health 

co-benefits c

$15 to $36 $14 to $33

Total Compliance 

Costs d

$7.5 $7.5

Net Monetized 

Benefits e

$26 to $46 $24 to $43

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 

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 
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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%. 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 16—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – 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

$24 to $55 $21 to $50 

Total Compliance 

Costs d

$7.3 $7.3 

Net Monetized 

Benefits e

$47 to $78 $44 to $73 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

1.7 tons of Hg and 580 tons of HCl 

Ecosystem Effects 
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Visibility impairment 

Option 1 State Compliance Approach 

Climate benefits b $31 

Air pollution health 

co-benefits c

$25 to $58 $23 to $53

Total Compliance 

Costs d

$8.8 $8.8

Net Monetized 

Benefits e

$47 to $80 $45 to $75

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

2.1 tons ofHg 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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

 The estimated costs and benefits for the regulatory 

alternative – Option 2 regional and state compliance approaches 

are shown in Tables 17 and 18. As these tables reflect, net 

benefits in 2020 are estimated to be $21 to $37 billion (3 

percent discount rate) and $20 to $34 billion (7 percent 

discount rate) for Option 2 assuming regional compliance. These 

Option 2 net benefit estimates become $20 to $37 billion (3 

percent discount rate) and $19 to $34 billion 7 percent discount 

rate) with the state compliance approach. In 2025, net benefits 

are estimated to be $30 billion to $51 billion (3 percent 

discount rate) and from $28 billion to $48 billion (7 percent 

discount rate)assuming a regional compliance approach and $30 

billion to $52 billion (3 percent discount rate) and from $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 17 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – 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

$12 to $28 $11 to $25 

Total Compliance 

Costs d

$4.3 $4.3 

Net Monetized 

Benefits e

$21 to $37 $20 to $34 

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

$12 to $29 $11 to $26

Total Compliance 

Costs d

$5.5 $5.5

Net Monetized 

Benefits e

$20 to $37 $19 to $34

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 
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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%. 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 THE FINAL RULE – 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

$16 to $37 $14 to $34 

Total Compliance 

Costs d

$4.5 $4.5 

Net Monetized 

Benefits e

$30 to $51 $28 to $48 

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

$16 to $38 $15 to $35

Total Compliance 

Costs d

$5.5 $5.5

Net Monetized 

Benefits e

$30 to $52 $28 to $48

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 by the USG 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 USG SCC estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SCC estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

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

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

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 [insert #]. 

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 
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which a claim of confidentiality is made is safeguarded 

according to agency policies set forth in 40 CFR part 2, subpart 

B. 

The annual burden for this collection of information for 

the states (averaged over the first 3 years following 

promulgation of this proposed action) is estimated to be a range 

of 315,554 hours at a total annual labor cost of $22,334,119, to 

632,338 hours at a total annual labor cost of $44,755,317. 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 annual burden for this collection of information for 

the states (averaged over the first 3 years following 

promulgation of this proposed action) is estimated to be a range 

of 315,554 hours at a total annual labor cost of $22,334,119, to 

632,338 hours at a total annual labor cost of $44,755,317. 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 
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proposed action) is estimated to be 53,267 hours at a total 

annual labor cost of $2,958.005Burden means the total time, 

effort, or financial resources expended by persons to generate, 

maintain, retain, or disclose or provide information to or for a 

Federal agency. This includes the time needed to review 

instructions; develop, acquire, install, and utilize technology 

and systems for the purposes of collecting, validating, and 

verifying information, processing and maintaining information, 

and disclosing and providing information; adjust the existing 

ways to comply with any previously applicable instructions and 

requirements; train personnel to be able to respond to a 

collection of information; search data sources; complete and 

review the collection of information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or sponsor, and a person is not 

required to respond to a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations are listed in 40 CFR part 9 

and 48 CFR chapter 15. 

To comment on the agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 
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Page 526 of 584

ICR, under Docket ID Number EPA-HQ-OAR-2013-0602. Submit any 

comments related to the ICR to the EPA and 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 

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. 
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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 19. Potentially Regulated Categories and Entitiesa

 

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. 
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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 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) national standards for 

allowable concentrations of particulate matter in ambient air as 

required by section 109 of the CAA. See also American Trucking 

Associations v. EPA. 175 F.3d at 1044–45 (NAAQS do not have 

significant impacts upon small entities because NAAQS themselves 
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impose no regulations upon small entities). 

Nevertheless, the EPA is aware that there is substantial 

interest in the proposed rule among small entities (municipal 

and rural electric cooperatives). As detailed in Section 

III.A.of this preamble, the EPA has conducted an unprecedented 

amount of stakeholder outreach on setting emission guidelines 

for existing EGUs. While formulating the provisions of the 

proposed rule, the EPA considered the input provided over the 

course of the stakeholder outreach. Section III.B of this 

preamble describes the key messages from stakeholders. In 

addition, as described in the RFA section of the preamble to the 

proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1499-1500, January 8, 2014), the EPA conducted 

outreach to representatives of small entities while formulating 

the provisions of the proposed standards. Although only new EGUs 

would be affected by those proposed standards, the outreach 

regarded planned actions for new and existing sources. We invite 

comments on all aspects of the proposal and its impacts, 

including potential impacts on small entities. 

D. Unfunded Mandates Reform Act

This proposed action does not contain a federal mandate that 

may result in expenditures of $100 million or more for State, 

local, and tribal governments, in the aggregate, or the private 
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sector in any one year. Specifically, emission guidelines 

established under CAA section 111(d) do not impose any direct 

compliance requirements on regulated entities. Thus, this proposed 

rule is not subject to the requirements of section 202 or section 

205 of UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

In light of the interest among governmental entities, the 

EPA initiated consultations with governmental entities while 

formulating the provisions of the proposed standards for new 

EGUs. Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new and 

existing sources. As described in the UMRA discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1500-1501, January 8, 2014), the 

EPA consulted with the following 10 national organizations 

representing state and local elected officials: 1) National 

Governors Association; 2) National Conference of State 

Legislatures, 3) Council of State Governments, 4) National 

League of Cities, 5) U.S. Conference of Mayors, 6) National 

Association of Counties, 7) International City/County Management 
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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 

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 
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docket for this rulemaking, the development of state plans will 

entail many hours of staff time to develop and coordinate 

programs for compliance with the proposed rule, as well as time 

to work with state legislatures as appropriate, and develop a 

plan submittal.

The EPA consulted with state and local officials early in 

the process of developing the proposed action to permit them to 

have meaningful and timely input into its development. As 

described in the Federalism discussion in the preamble to the 

proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1501, January 8, 2014), the EPA consulted with state 

and local officials in the process of developing the proposed 

standards for newly constructed EGUs. This outreach regarded 

planned actions for new, reconstructed, modified and existing 

sources. The EPA invited the following 10 national organizations 

representing state and local elected officials to a meeting on 

April 12, 2011, in Washington DC: (1) National Governors 

Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) 

U.S. Conference of Mayors, (6) National Association of Counties, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 
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These 10 organizations representing elected state and local 

officials have been identified by the EPA as the “Big 10” 

organizations appropriate to contact for purpose of consultation 

with elected officials. On February 26, 2014, the EPA re-engaged 

with those governmental entities to provide a pre-proposal 

update on the emission guidelines for existing EGUs and emission 

standards for modified and reconstructed EGUs. In addition, 

extensive stakeholder outreach conducted by the EPA allowed 

state leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 

directors, opportunities to engage with EPA officials and 

provide input regarding reducing carbon pollution from power 

plants.

A detailed Federalism Summary Impact Statement (FSIS) 

describing the 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 EPA policy 

to promote communications between EPA and State and local 

governments, EPA specifically solicits comment on this proposed 

action from State and local officials.

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments 
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This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

would not impose substantial direct compliance costs on tribal 

governments that have affected EGUs located in their area of 

Indian country. Tribes are not required to, but may, develop or 

adopt CAA programs. Tribes are not required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 

EGUs. To the extent that a tribal government seeks and attains 

treatment in a manner similar to a state (TAS) status for that 

purpose and is delegated authority for air quality planning 

purposes, these proposed emission guidelines would require that 

planning requirements be met and emission management 

implementation plans be executed by the tribes. The EPA is aware 

of three coal-fired EGUs and one natural 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. 
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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 

Country291 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 

 

291 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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and offered consultation. No tribes have requested consultation. 

Tribes were invited to participate in the national informational 

webinar held August 27, 2013. In addition, consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA also met 

with tribal environmental staff via National Tribal Air 

Association teleconferences on July 25, 2013, and December 19, 

2013. In those teleconferences, the EPA provided background 

information on the GHG emission guidelines to be developed and a 

summary of issues being explored by the agency. Tribes have 

expressed varied points of view. Some tribes raised concerns 

about the impacts of the regulations on EGUs and the subsequent 

impact on jobs and revenue for their tribes. Other tribes 

expressed concern about the impact the regulations would have on 

the cost of water to their communities as a result of increased 

costs to the EGU that provide energy to transport the water to 

the tribes. Other tribes raised concerns about the impacts of 

climate change on their communities, resources, life ways and 

hunting and treaty rights. The tribes were also interested in 

the scope of the guidelines being considered by the agency 

(e.g., over what time period, relationship to state and multistate plans) and how tribes will participate in these planning 

activities. In addition, the EPA held a series of listening 
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sessions prior to development of this proposed action. In 2013, 

tribes participated in a session with the state agencies, as 

well as a separate session with tribes. 

During the public comment period for this proposal, the EPA 

will hold meetings with tribal environmental staff to inform 

them of the content of this proposal, as well as offer further 

consultation with tribal elected officials where it is 

appropriate. We specifically solicit comment from tribal 

officials on this proposed rule. 

G. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5-

501 of the Order has the potential to influence the regulation. 

This action is not subject to EO 13045 because it does not 

involve decisions on environmental health or safety risks that 

may disproportionately affect children. The EPA believes that 

the CO2 emission reductions resulting from implementation of the 

proposed guidelines, as well as substantial ozone and PM2.5 

emission reductions as a co-benefit, would further improve 

children’s health. 

H. Executive Order 13211, Actions Concerning Regulations That 
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Significantly Affect Energy Supply, Distribution, or Use 

Executive Order 13211 (66 FR 28355; May 22, 2001) requires 

the EPA to prepare and submit a Statement of Energy Effects to 

the Administrator of the Office of Information and Regulatory 

Affairs, OMB, for actions identified as ‘‘significant energy 

actions.’’ This action, which is a significant regulatory action 

under EO 12866, is likely to have a significant effect on the 

supply, distribution, or use of energy. We have prepared a 

Statement of Energy Effects for this action as follows. We 

estimate a 4 to 7 percent increase in retail electricity prices, 

on average, across the contiguous U.S. in 2020, and a 16 to 22 

percent reduction in coal-fired electricity generation as a 

result of this rule. The EPA projects that electric power sector 

delivered natural gas prices will increase by about 8 to 12 

percent in 2020. For more information on the estimated energy 

effects, please refer to the economic impact analysis for this 

proposal. The analysis is available in the RIA, which is in the 

public docket.

I. National Technology Transfer and Advancement Act 

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 

15 U.S.C. 272 note) directs the EPA to use Voluntary Census 

Standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise 
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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 the OMB, with 

explanations when an agency does not use available and 

applicable VCS. This proposed rulemaking does not involve 

technical standards. 

The EPA welcomes comments on this aspect of the proposed 

rulemaking and specifically invites the public to identify 

potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low-income populations in the U.S. 
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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).292 As part 

of the Endangerment Finding, the Administrator considered 

climate change risks to minority or low-income populations, 

finding that certain parts of the population may be especially 

vulnerable based on their circumstances. These include the poor, 

the elderly, the very young, those already in poor health, the 

disabled, those living alone, and/or indigenous populations 

dependent on one or a few resources. The Administrator placed 

weight on the fact that certain groups, including children, the 

elderly, and the poor, are most vulnerable to 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 

 

292 “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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tend to have more limited adaptive capacities and are more 

dependent on climate-sensitive resources such as local water and 

food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly 

those on established reservations that are restricted to 

reservation boundaries and therefore have limited relocation 

options. Tribal communities whose health, economic well-being, 

and cultural traditions depend upon the natural environment will 

likely be affected by the degradation of ecosystem goods and 

services associated with climate change. Southwest native 

cultures are especially vulnerable to water quality and 

availability impacts. Native Alaskan communities are likely to 

experience disruptive impacts, including shifts in the range or 

abundance of wild species crucial to their livelihoods and wellbeing. The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority and 

low-income populations. 

This proposed rule limits GHG emissions by establishing CO2 

emission guidelines for existing fossil fuel-fired EGUs. In 

addition to reducing CO2 emissions, implementing the proposed 

rule would reduce other emissions from EGUs which are dispatched 

less under a state’s 111(d) program because of their relatively 

low energy efficiency. These emission reductions will include SO2
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and NOx, which form ambient PM2.5 and ozone in the atmosphere, and 

hazardous air pollutants (HAP), such as mercury. In the final 

rule revising the annual PM2.5 standard293, the EPA identified 

persons with lower socioeconomic status as an at-risk population 

for experiencing adverse health effects related to PM exposures. 

Persons with lower socioeconomic status have been generally 

found to have a higher prevalence of pre-existing diseases, 

limited access to medical treatment, and increased nutritional 

deficiencies, which can increase this population’s risk to PMrelated and ozone-related effects.294 Therefore, in areas where 

this rulemaking reduces exposure to PM2.5, ozone, and 

methylmercury persons with low socioeconomic status would also 

benefit. The regulatory impact analysis (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 methylmercury, there may also be 

 

293 U.S. EPA (2013). National Ambient Air Quality Standards for 

Particulate Matter, Final Rule. Federal Register 78 (15 January 

2013): 3086-3287. 

294 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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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 are 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 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 

of GHGs and/or other regulated pollutants. As we noted in the 

NSR discussion in this preamble, a state can take steps to avoid 

increased utilization of particular EGUs and thus to 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 
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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 

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 
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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 be dispatched more frequently than at present have 

very low emissions of primary particulate matter, SO2 and 

hazardous air pollutants per unit of electrical output, such 

that local (or regional) air quality for these pollutants is 

likely to be affected very little. For natural gas-fired EGUS, 

the EPA found that regulation of HAP emissions “is not 

appropriate or necessary because the impacts due to HAP 

emissions from such units are negligible based on the results of 

the study documented in the utility RTC” 65 FR 79831. In studies 

done by DOE/NETL comparing cost and performance of coal- and NGfired 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 
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may be able to predict which EGUs and communities may be in this 

type of situation and to address any concerns about localized NO2

concentrations in the design of the CAA section 111(d) program, 

or separately from the CAA section 111(d) program but before its 

implementation. In any case, existing tracking systems will 

allow states and the EPA to be aware of the EGUs whose 

utilization has increased most significantly, and thus to be 

able to prioritize our efforts to assess whether air quality has 

changed in the communities in the vicinity of such EGUs. There 

are multiple mechanisms in the CAA to address situations in 

which air quality has degraded significantly.In conclusion, this 

proposed rule will result in regional and national pollutant 

reductions; however, there likely will 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. 
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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 

pollutant addressed by this proposal. 

XII. Statutory Authority 

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(V) of the CAA, as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(V)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). 
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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 UUUUU 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 greenhouse gases 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?

 This subpart establishes emission guidelines and approval 

criteria for state plans that establish standards of performance 
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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 subpart A of this part, 

the requirements of this subpart will apply. 

§ 60.5705 What greenhouse gases are regulated by this subpart? 

 The greenhouse gas regulated by this subpart is carbon 

dioxide (CO2). 

§ 60.5710 Am I affected by this subpart? 

 If you are the Administrator of an air quality program in a 

state with one or more affected EGUs that commenced construction 

on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], you must submit a state plan to U.S. Environmental 

Protection Agency (EPA) that implements the emission guidelines 

contained in this subpart. You must submit a negative 

declaration letter in place of the state plan if there are no 

affected EGUs for which construction commenced on or before 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] in your 

state. 
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§ 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 six 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 in lieu of a complete state plan the 

Administrator will have six months after the date required for 

submission to approve or disapprove the request. 

§ 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 EPA for the state. The Federal plan is an interim action and 

will be automatically withdrawn when your state plan is 

approved. 

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

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

obligations? 

 No. 
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§ 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, 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 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] 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 paragraphs (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. 

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. 
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(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 

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 
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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 

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. 
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(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. 

(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. 
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(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 

(iiii) Materials necessary to support evaluation of the 

plan by EPA. 

(b) You must follow the requirements of subpart B of this 

part (Adoption and Submittal of state plans for Designated 

Facilities) and demonstrate that they were met in your state 

plan. 

§ 60.5745 Can I work with other states to develop a multi-state 

plan? 

 (a) A multi-state plan may be submitted, provided it is 

signed by authorized officials for each of the states 
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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: 

(b) 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 

(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. 

(c) 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. 
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§ 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). 

 (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: 

 (i) 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 

(ii) The existing state program, requirement, or measure, 
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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. 

(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) 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 letter, the state 

must explain why more time is needed to submit a complete plan, 

outline the actions it is currently taking to develop a plan and 
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commit to meet all of the requirements for an initial submittal, 

listed in paragraph (b) of this section, by June 30, 2016. 

(b) You must include the following required elements in an 

initial submittal in lieu of a complete state plan if your 

request for extension in paragraph (a) of this section has been 

approved: 

(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 by affected EGUs 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 EGUs, which must at a minimum apply during the interim 

period prior to state submission and EPA approval of a complete 

plan, and must continue to apply in lieu of a complete plan if 

one is ultimately not submitted and approved; 

(4) Justification of why additional time is needed to 

submit a complete plan; 

(5) A comprehensive roadmap for completing the plan, 

including process, analytical methods and schedule (including 

milestones) specifying when all necessary plan components will 

be complete (e.g., projection of emission performance; 
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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. 

§ 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? 
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 (a) If the plan adopts a mass-based goal according to § 

60.5740(a)(3), the plan must identify the mass-based goal, in 

tons of CO2 emitted by affected EGUs over the plan performance 

period, and include a description of the analytic process, 

tools, methods, and assumptions used to convert from the 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)(10). 

(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)(10). 

(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.
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(b) Your state plan must include compliance periods, as 

defined in section § 60.5820, for each affected entity regulated 

under the plan. 

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

state must meet the requirements in paragraphs (c)(1) and (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. 2020-2022, 

2021-2023, 2022-2024, 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 
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in this section and section § 60.5740 in your state’s annual 

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 

corrections to the state plan to ensure the emission performance 

goal is met. 
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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 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, 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 [DATE OF PROPOSED RULE PUBLICATION IN 

THE FEDERAL REGISTER] reaches compliance with all the provisions 

of this subpart. 

§ 60.5795 What affected EGUs must I address in my state plan? 

The EGUs that must be addressed by your state plan are any 

affected steam generating unit, IGCC, or stationary combustion 

turbine that commences construction before [DATE OF PROPOSED 

RULE PUBLICATION IN THE FEDERAL REGISTER] 

§ 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 after the subpart TTTT applicability 
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date and 2) those subject to subpart TTTT as a result of 

commencing modification or reconstruction prior to the EPA 

approving the 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. 

(v) If an affected EGU chooses to use Method 2 in Appendix 

A-1 to this part to perform the required relative accuracy test 
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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. 

(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. 

Further, an affected EGU that is a combined heat and power 
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facility must install, calibrate, maintain and operate equipment 

to continuously measure and record on an hourly basis useful 

thermal output and, if applicable, mechanical output, which are 

used with net electric output to determine net energy output. 

(5) In accordance with § 60.13(g), if two or more affected 

EGUs that implement the continuous emissions monitoring 

provisions in paragraph (a)(2) of this section share a common 

exhaust gas stack and are subject to the same emissions 

standard, they may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

affected EGU chooses this option, the hourly net electric output 

for the common stack must be the sum of the hourly net electric 

output of the individual affected facility and you must express 

the operating time as “stack operating hours” (as defined in § 

72.2 of this chapter). 

(6) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU that implements the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), they must monitor 

the hourly CO2 mass emissions and the “stack operating time” (as 

defined in § 72.2 of this chapter) at each stack or duct 

separately. In this case, an affected EGU must determine 
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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 

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 
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information that is used to support any continued effort to meet 

the final emissions performance goal. 

(b) States must keep records of all data submitted by each 

affected entity that is used to determine compliance with each 

affected entity’s emissions standard. 

(c) If a state has a requirement for hourly CO2 emissions 

and net generation information to be used to calculate 

compliance with an annual emissions standard for affected EGUs, 

any information that is submitted to the EPA electronically 

pursuant to requirements in Part 75 would meet the recordkeeping 

requirement of this section and a state would not need to keep 

records of information that would be in duplicate of paragraph 

(b) of this section. 

(d) A state must keep records at minimum for 20 years. 

§ 60.5815 What are my state reporting requirements? 

(a) You must submit an annual report covering each calendar year 

no later than July 1 of the following year, starting July 1 

2021. The annual report must include the following: 

(1) The level of emissions performance achieved by all 

affected entities and identification of whether affected 

entities are on schedule to meet the applicable level of 

emissions performance for affected entities during the plan 

performance period and compliance periods, as specified in the 

plan. 
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(2) The level of emissions performance achieved by all 

affected EGUs during the reporting period, and prior reporting 

periods, expressed as average CO2 emissions rate or total mass 

CO2 emissions, consistent with the plan approach, and 

identification of whether affected EGUs are on schedule to meet 

the applicable level of emissions performance for affected EGUs 

during the plan performance period, as specified in the plan. 

 (3) A list of affected entities and their compliance status 

with the applicable emissions standards specified in the state 

plan. 

(4) A list of all affected EGUs and their reported CO2

emissions performance for each compliance period during the 

reporting period, and prior reporting periods. 

 (5) All other required information, as specified in your 

state plan according to §60.5740(a)(9). 

 (6) All information required by § 60.5775(e). 

(b) For each two-year period in § 60.5775(c)(1), you must 

compare the CO2 emission performance achieved by affected EGU 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 
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performance in the plan will be met. The information required in 

this paragraph must be included in the annual report required by 

paragraph (a) of this section. 

 (c) You must include in your 2029 annual report (which is 

subsequently due by July 1, 2030) the calculation of average 

emissions over the 2020-2029 interim performance period used to 

determine compliance with your interim emission performance 

level. The calculated value must be in units consistent with 

your interim emission performance level. 

(d) You must include in each report, starting with the 2032 

annual report (which is subsequently due by July 1, 2033), a 3-

calendar year rolling average used to determine compliance with 

the final emission performance level. The calculated value must 

be in units consistent with your final emission performance 

level. 

Definitions 

§ 60.5820 What definitions apply to this subpart? 

As used in this subpart, all terms not defined herein will 

have the meaning given them in the Clean Air Act and in subparts 

A (General Provisions of this part) and B. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, an IGCC facility, or a stationary 
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combustion turbine that serves a generator capable of selling 

greater than 25 MW to a power distribution system. 

Affected Entity shall mean any of the following: an 

affected EGU, or another entity with obligations under this 

subpart for the purpose of meeting the emissions performance 

goal requirements in these emission guidelines. 

Base load rating means the maximum amount of heat input 

(fuel) that a steam generating unit can combust on a steady 

state basis, as determined by the physical design and 

characteristics of the steam generating unit at ISO conditions. 

For a stationary combustion turbine, base load rating means 100 

percent of the design heat input capacity of the simple cycle 

portion of the stationary combustion turbine at ISO conditions 

(heat input from duct burners is not included). 

CO2 emissions performance goal means the rate-based CO2

emissions performance goal specified for a state in Table 1 of 

this subpart, or a translated mass-based form of that goal. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

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

turbine to simultaneously produce both electric (or mechanical) 

and useful thermal energy 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.

Distillate oil means fuel oils that contain no more than 

0.05 weight percent nitrogen and comply with the specifications 

for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by 

reference, see § 60.17); diesel fuel oil numbers 1 and 2, as 

defined by the American Society for Testing and Materials in 

ASTM D975 (incorporated by reference, see § 60.17); kerosene, as 
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defined by the American Society of Testing and Materials in ASTM 

D3699 (incorporated by reference, see § 60.17); biodiesel as 

defined by the American Society of Testing and Materials in ASTM 

D6751 (incorporated by reference, see § 60.17); or biodiesel 

blends as defined by the American Society of Testing and 

Materials in ASTM D7467 (incorporated by reference, see § 

60.17). 

Emission performance level in a state plan means the level 

of emissions performance for affected entities specified in a 

state plan, according to § 60.5745. 

Emission standard means in addition to the definition in § 

60.21, any requirement applicable to any affected entity other 

than an affected source that has the effect of reducing 

utilization of one or more affected sources, thereby avoiding 

emissions from such sources, including, for example, renewable 

energy and demand-side energy efficiency measures requirements. 

Excess emissions means a specified averaging period over 

which the CO2 emissions rate is higher than an applicable 

emissions standard or an averaging period during which an 

affected EGU is not in compliance with any other emission 

limitation specified in an emission standard. 

Existing state program, requirement, or measure means, in 

the context of a state plan, a regulation, requirement, program, 

or measure administered by a state, utility, or other entity 
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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 facility 

means a combined cycle facility that has a base load rating for 

fossil fuel of greater than 73 MW (250 MMBtu/h), that was 

constructed for the purpose of supplying more than one-third or 

more of its potential electric output and more than 219,000 MWh 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 580 of 584

net-electric output to a utility distribution system on an 

annual basis and that is designed to burn fuels containing 50 

percent (by heat input) or more solid-derived fuel not meeting 

the definition of natural gas plus any integrated equipment that 

provides electricity or useful thermal output to either the 

affected facility or auxiliary equipment. The Administrator may 

waive the 50 percent solid-derived fuel requirement during 

periods of the gasification system construction, startup and 

commissioning, shutdown, or repair. No solid fuel is directly 

burned in the unit during operation. 

ISO conditions means 288 Kelvin (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 energy, 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 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 581 of 584

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). Measurements must 

be performed using 0.2 accuracy class electricity metering 

instrumentation and calibration procedures as specified under 

ANSI Standards No. C12.20. 

Net energy output means: 

(1) the net electric or mechanical output from the affected 

facility, plus 75 percent of the useful thermal output measured 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 582 of 584

relative to ISO conditions that is not used to generate 

additional electric or mechanical output or to enhance the 

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

process for a heating application). 

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

20.0 percent of the total gross energy output consists of 

electric or direct mechanical output and 20.0 percent of the 

total gross energy output consists of 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 ISO 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). 

Oil means crude oil or petroleum or a fuel derived from 

crude oil or petroleum, including distillate and residual oil, 

and gases derived from solid oil-derived fuels (not meeting the 

definition of natural gas). 

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. 

Stationary combustion turbine means all equipment, 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 583 of 584

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) that has a base load rating 

for fossil fuel of greater than 73 MW (250 MMBtu/h) and that was 

constructed for the purpose of supplying more than one-third or 

more of its potential electric output and more than 219,000 MWh 

net-electric output to a utility distribution system on an 

annual basis plus any integrated equipment that provides 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 584 of 584

electricity or useful thermal output to the affected facility or 

auxiliary equipment. 

Thermal output for this subpart means the energy in 

recovered thermal output measured against the energy in the 

thermal output at ISO conditions. 

Useful thermal output means the thermal energy made 

available for use in any industrial or commercial process, or 

used in any heating or cooling application, i.e., total thermal 

energy made available for processes and applications other than 

electric generation, mechanical output at the affected facility, 

or to directly enhance the performance of the affected facility 

(e.g., thermal energy used to reduce fuel moisture is considered 

useful thermal output). 
DRAFT April May 0415, 2014 

Chapter 1: Introduction 

CAA section 111(d) requires that state plans must establish standards of performance that 

reflect the degree of emission limitation achievable through the application of the best system of 

emission reduction (BSER) that, taking into account the cost of achieving such reductions and 

any non-air quality health and environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 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. 

As a first step towards determination of BSER, the EPA recognized that, in general, 

reductions in carbon dioxide (CO2) emissions from individual existing electric generating units 

(EGUs) can be achieved by implementing either of two basic approaches: (1) making emission 

rate improvements at affected EGUs (e.g., by improving heat rates or switching to lower carbon 

fuels), and/or (2) reducing utilization of greenhouse gas (GHG)-emitting EGUs (e.g., by reducing 

the overall demand for electricity or by shifting dispatch from higher-GHG-emitting EGUs to 

lower-GHG-emitting and non-emitting units). Accordingly, to determine BSER for reducing 

GHG emissions at affected units, the EPA evaluated numerous GHG abatement measures that 

utilize the above approaches. In its evaluation, the EPA considered only those measures that have 

been adequately demonstrated to reduce CO2 emissions from fossil fuel-fired EGUs. These 

measures included: heat rate improvements at individual EGUs, switching to lower carbon fuels 

at individual EGUs, carbon capture and sequestration at individual EGUs, shifting dispatch from 

higher-GHG-emitting EGUs to lower-GHG-emitting and non-emitting units, and reducing the 

overall demand for electricity via improvements in demand-side energy efficiency. 

Based on its evaluation of the above GHG abatement measures, the EPA identified four 

categories of demonstrated measures, or “building blocks,” that are technically viable and 

broadly applicable, and can provide cost-effective reductions in CO2 emissions from individual 

existing EGUs. These building blocks include: 

1. Lowering Reducing the carbon intensity of generation at individual affected EGUs 

(e.g., through heat rate improvements); 
DRAFT April 04, 2014 

2 

2. Reducing emissions of the most carbon-intensive affected EGUs to the extent that 

thisin the amount that results from substituting generation at those EGUs with generation 

from less carbon-intensive affected EGUscan be accomplished cost-effectively by 

shifting generation to less carbon-intensive existing fossil fuel-fired EGUs, (including 

NGCC units that are under construction); 

3. Reducing emissions of carbon-emittingfrom affected EGUs in the amount that results 

from substituting generation at those EGUs with expanded low- or zero-carbon 

generationto the extent that this can be accomplished cost-effectively by expanding the 

amount of new, lower (or no) carbon-intensity generation; and, 

4. Reducing emissions of carbon-emittingfrom affected EGUs in the amount that results 

from the use of demand-side energy efficiency that reduces the amount of generation 

requiredto the extent that this can be accomplished cost-effectively by increasing 

demand-side energy efficiency. 

The EPA believes that for purposes of CAA section 111(d), as applied to the power 

sector, the BSER encompasses all four building blocks. The application of all four building 

blocks as BSER is consistent with current trends in the electric power sector and with strategies 

that companies and states are already taking to reduce GHG emissions. Also, the application of 

all four building blocks as BSER supports achieving cost-effective, and technically feasible 

reductions of CO2. 

The subsequent chapters in this technical support document describe EPA’s evaluation of 

all adequately demonstrated GHG abatement measures. While evaluating each measure, the EPA 

considered its technical feasibility, applicability and use, application level appropriate for BSER, 

and cost effectiveness associated with reducing GHG emissions at EGUs. 
DRAFT May 15, 2014 

Chapter 1: Introduction 

CAA section 111(d) requires that state plans must establish standards of performance that 

reflect the degree of emission limitation achievable through the application of the best system of 

emission reduction (BSER) that, taking into account the cost of achieving such reductions and 

any non-air quality health and environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 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. 

As a first step towards determination of BSER, the EPA recognized that, in general, 

reductions in carbon dioxide (CO2) emissions from individual existing electric generating units 

(EGUs) can be achieved by implementing either of two basic approaches: (1) making emission 

rate improvements at affected EGUs (e.g., by improving heat rates or switching to lower carbon 

fuels), and/or (2) reducing utilization of greenhouse gas (GHG)-emitting EGUs (e.g., by reducing 

the overall demand for electricity or by shifting dispatch from higher-GHG-emitting EGUs to 

lower-GHG-emitting and non-emitting units). Accordingly, to determine BSER for reducing 

GHG emissions at affected units, the EPA evaluated numerous GHG abatement measures that 

utilize the above approaches. In its evaluation, the EPA considered only those measures that have 

been adequately demonstrated to reduce CO2 emissions from fossil fuel-fired EGUs. These 

measures included: heat rate improvements at individual EGUs, switching to lower carbon fuels 

at individual EGUs, carbon capture and sequestration at individual EGUs, shifting dispatch from 

higher-GHG-emitting EGUs to lower-GHG-emitting and non-emitting units, and reducing the 

overall demand for electricity via improvements in demand-side energy efficiency. 

Based on its evaluation of the above GHG abatement measures, the EPA identified four 

categories of demonstrated measures, or “building blocks,” that are technically viable and 

broadly applicable, and can provide cost-effective reductions in CO2 emissions from individual 

existing EGUs. These building blocks include: 

1. Reducing the carbon intensity of generation at individual affected EGUs through heat 

rate improvements; 
DRAFT April 04, 2014 

2 

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 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; and, 

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 believes that for purposes of CAA section 111(d), as applied to the power 

sector, the BSER encompasses all four building blocks. The application of all four building 

blocks as BSER is consistent with current trends in the electric power sector and with strategies 

that companies and states are already taking to reduce GHG emissions. Also, the application of 

all four building blocks as BSER supports achieving cost-effective, and technically feasible 

reductions of CO2. 

The subsequent chapters in this technical support document describe EPA’s evaluation of 

all adequately demonstrated GHG abatement measures. While evaluating each measure, the EPA 

considered its technical feasibility, applicability and use, application level appropriate for BSER, 

and cost effectiveness associated with reducing GHG emissions at EGUs. 
DRAFT April May 15, 2014 

Draft Deliberative

Chapter 2: Heat Rate Improvement at Existing Coal-fired EGUs 

2.0 Introduction 

Based on the range of operating efficiencies for existing coal-fired electric generating 

units (EGUs), it is evident can be presumed that EGUs are generally less efficient at converting 

fuel into electricity than is technically and economically possible. For example, the difference in 

operating efficiency of EGUs with similar design characteristics and the year to year variability 

in individual EGU efficiency indicates that there is potential for broadly applicable efficiency 

improvements through cost-effective operational and maintenance practices. These improved 

efficiencies would result in corresponding reductions in greenhouse gas emissions. 

This chapter presents an overview of existing coal-fired EGUs, design factors that 

influence efficiency, technologies to improve efficiency, previous studies estimating potential 

efficiency improvements, the proposed EPA approach to calculate efficiency improvements, and 

the estimated capital costs of those improvements. 

2.1 Overview of U.S. Existing Coal-Fired Electric Generating Units 

Coal in the United States and is predominately used for electric power generation. Most 

coal-fired EGUs in the United States burn either bituminous or subbituminous coals. The largest 

sources of bituminous coals burned in coal-fired EGUs are mines in regions along the 

Appalachian Mountains and in southern Illinois, western Kentucky and Indiana. Additional 

bituminous coals are supplied from mines in Utah and Colorado. The vast majority of 

subbituminous coals are supplied from mines in Wyoming and Montana, with many coal-fired 

EGUs burning subbituminous coals from the Powder River Basin (PRB) region in Wyoming. In 

general, the burning of lignite by U.S. electric utilities is limited to coal-fired EGUs that are 

located near the mines that supply the lignite in Texas, Louisiana, Mississippi, Montana, and 

North Dakota. At a few power plant locations in the Eastern United States., recovered anthracite 

coal or coal refuse is burned in limited quantities. 

Existing coal-fired EGUs in the U.S. electric utility fleet use one of five basic coal 

combustion configurations: (1) pulverized coal (PC) combustion, (2) fluidized-bed combustion 

(FBC), (3) gasified coal combustion, (4) cyclone furnace combustion, or (5) stoker-fired coal 

combustion. Table 2-1 presents a summary of the operating characteristics of each of these coal 

combustion configurations. 

Comment [A1]: This section read quite weakly as

initially written.   

EPA response: Thank you for the edit.

Comment [A2]: MATS Compliance.  MATS

compliance will lead to significant installations of

pollution control equipment (PCE) over the 2013 to

2016 period on capacity that owners intend to keep

in service beyond the MATS compliance deadline

but would not be MATS‐compliant without

augmenting the PCE that was in place during 2012.  

The PCE systems likely to be installed on such units

include FGD systems that may consume significant

power and therefore, all else equal, increase energy

input per net kilowatt‐hour of generation.  It would

be helpful to understand if or how additions of PCE

for MATS compliance are reflected in the analysis of

HRI in the draft TSD.

EPA response: The results of our statistical analysis

(described later) are based on gross heat rates and

will not change with installation of MATS controls,

which will add additional parasitic load

requirements and thereby have an impact on the

net heat rates. However, in this TSD chapter, we

explain that EPA conservatively considers fleet‐wide

net heat rate improvement potential to be the same

as that indicated for the fleet‐wide gross heat rate.

And based on this consideration, IPM modeling and

state goals calculations used 6% improvement on a

net heat rate basis. So we also need to speak to the

fleet‐wide net heat rate. That being said, MATS

controls are expected to lead to a small increase in

auxiliary power use and therefore will not have a

significant effect on the fleet‐wide net heat rate.

Here is what we projected (using IPM) for the final

MATS policy case.

Technology                       Capacity         Parasitic Load

New wet FGD                    0 GW               1.5‐2%

New SCR                             0 GW               0.5%       

New dry FGD (SDA)          22 GW              1‐1.5%

New DSI                             43 GW              0.5%  

                                                          (assumed same as

ACI + FF)

New ACI                             141 GW            0.5%

New FF                               102 GW             0.5%

Upgrade of existing ESP            34 GW                   

Upgrade of existing wet FGD   63 GW                   

So MATS requirements would increase parasitic load

from 0% (for a unit that can meet the standards

with existing equipment) up to 2 % for units that

install a SDA and implement ACI + FF   [Note: a unit

would implement either SDA or DSI but not both].

In any case, EPA’s IPM v 5.13 Base Case modelling

for this proposal assumes that MATS is in effect and

that such controls as are needed for compliance are

added before 111(d) policy options are evaluated in

policy runs.  
DRAFT April May 15, 2014 

2 

Table 2-1. Characteristics of coal-firing configurations used for U.S. EGUs 

Coal-firing 

Configuration 

Coal Combustion Process 

Description Distinctive Design/Operating Characteristics 

Pulverized 

Coal (PC)

Combustion 

Coal is ground to a fine powder that 

is pneumatically fed to a burner 

where it is mixed with combustion 

air and then blown into the furnace. 

The pulverized-coal particles burn in 

suspension in the furnace. Unburned 

and partially burned coal particles 

are carried off with the flue gas. 

Wall-fired 

An array of burners fire into the 

furnace horizontally, and can be 

positioned on one wall or opposing 

walls depending on furnace design. 

Tangential-fired 

(Corner-fired) 

Multiple burners are positioned in 

opposite corners of the furnace 

producing a fireball that moves in a 

cyclonic motion and expands to fill 

the furnace. 

Fluidized-bed 

Combustion 

(FBC) 

Coal is crushed into fine particles. 

The coal particles are suspended in a 

fluidized bed by upward-blowing jets 

of air creating a turbulent mixing of 

combustion air with the coal 

particles. Typically, the coal is mixed 

with a sorbent such as limestone (for 

SO2 emission control). FBCFBC 

have a greater fuel flexibility than 

PC EGUs and can be designed for 

combustion within the bed to occur 

at atmospheric or elevated pressures. 

FBC operating temperatures are in 

the range of 1,500 to 1,650F (800 to 

900o

C). 

Bubbling 

fluidized bed 

(BFB) 

Operates at relatively low gas stream 

velocities and with coarse-bed size 

particles. Air in excess of that 

required to fluidize the bed passes 

through the bed in form of bubbles. 

Circulating 

fluidized bed 

(CFB) 

Operates at higher gas stream 

velocities and with finer-bed size 

particles. No defined bed surface. 

Must use high-volume, hot cyclone 

separators to recirculate entrained 

solid particles in flue gas to maintain 

the bed and achieve high combustion 

efficiency. 

Integrated Coal 

Gasification 

Combined 

Cycle (IGCC) 

Synthetic combustible gas (“syngas”) 

derived from an on-site coal 

gasification process is burned in a 

combustion turbine. The hot exhaust 

gases from the combustion turbine 

pass through a heat recovery steam 

generator to produce steam for 

driving a steam turbine/generator 

unit. 

Coal gasification units are unique among coal-firing 

configurations because a gaseous fuel (synfuel or syngas) 

is burned instead of solid coal because the combustion 

and power generation process and combines the Rankine 

and Brayton thermodynamic cycles as is the case for a 

combined cycle power plant. 

Cyclone 

Furnace 

Combustion 

Coal is crushed into small pieces and 

fed through a burner into the cyclone 

furnace. A portion of the combustion 

air enters the burner tangentially 

creating a whirling motion to the 

incoming coal. 

Designed to burn coals with low-ash fusion temperatures 

that are difficult to burn in PC boilers. The majority of 

the ash is retained in the form of a molten slag. 

Stoker-fired 

Coal 

Combustion 

Coal is crushed into large lumps and 

burned in a fuel bed on a moving, 

vibrating, or stationary grate. Coal is 

fed to the grate by a mechanical 

device called a “stoker.” 

One of three types of stoker mechanisms can be used that 

ether feed the coal by pushing, dropping, or flipping coal 

unto the grate. 

The three technologies currently used for new coal-fired power plants are pulverized 

coal, fluidized bed (FBC), and integrated coal gasification combined cycle (IGCC). Pulverized 

coal combustion involves pulverizing the coal into a fine powder, which allows the coal to be 

Comment [A3]: We would suggest reducing the

amount of text in tables (perhaps as bullet points).

EPA response: Thank you for the observation.

Comment [A4]: It might be helpful to indicate

the typical size (MW) and capital cost ($/installed

MW) here.  

EPA response: Thank you for the observation, but it 

is unclear how the suggested edit would relate to the 

analysis.
DRAFT April May 15, 2014 

3 

burned more easily and efficiently. This is the coal-firing configuration predominately used at 

existing EGUs, and is the most frequently selected technology for new coal-fired EGU projects.

However, FBC EGUs are becoming more prevalent since they have a greater fuel flexibility. The 

most recent coal technology combustion development involves the integration of coal 

gasification technologies with the combined cycle electric generation process. The efficiency of 

an IGCC power plant is comparable to the latest advanced PC-fired and FBC EGU designs using 

supercritical steam cycles. The advantages of using IGCC technology can include greater fuel 

flexibility (e.g., capability to use a wider variety of coal ranks), potential improved control of 

PM, SO2 emissions, and other air pollutants, the need for fewer post-combustion control devices 

(e.g., almost all of the sulfur and ash in the coal can be removed once the fuel is gasified and 

prior to combustion), generation of less solid waste, and reduced water consumption, and the 

chemical process that creates a concentrated CO2 stream that is more amenable to carbon capture 

processes.. . 

Older combustion technologies, namely cyclone furnaces and stoker-fired coal 

combustion, have been replaced at new coal-fired EGUs by more efficient methods that provide 

superior coal combustion efficiency and other advantages. However, a few remaining old stokerfired EGUs and cyclone furnaces still remain in service for a small number of existing EGUs in 

the U.S. electric utility market. 

2.2 Influence of Heat Rate on Coal-Fired EGU CO2 Emission Rate 

Heat rate is a common way to measure EGU efficiency. As the efficiency of a coal-fired 

EGU is increased, less coal is burned per kilowatt-hour (kWh) generated by the EGU resulting in 

a corresponding decrease in CO2 and other air emissions. Heat rate is expressed as the number of 

British thermal units (Btu) or kilojoules (kJ) required to generate a kilowatt-hour (kWh) of 

electricity. Lower heat rates are associated with more efficient coal-fired EGUs. 

The electric energy output for an EGU can be expressed as either as “gross output” or 

“net output.” The gross output of an EGU is the total amount of electricity generated at the 

generator terminal. The net output of an EGU is the gross output minus the total amount of 

auxiliary (or parasitic) electricity used to operate the EGU (e.g., electricity to power fuel 

handling equipment, pumps, fans, pollution control equipment, and other on-site electricity 

needs), and thus is a measure of the electricity delivered to the transmission grid for distribution 

and sale to customers. Some EGUs also produce part of their useful output in the form of useful 

Comment [A5]: No one is building coal plants

currently in the U.S., so the future tense is not

appropriate.  Who is building coal plants using FBC?  

China?  If so, we should specify, or else delete.

EPA response: The text has been deleted.

Formatted: Subscript

Comment [A6]: One of the primary benefits of

IGCC is the concentrated CO2 stream and ability to

use in CCS.  Needs to be highlighted.

EPA response: Thank you for the observation and

the suggested text, which has been included.
DRAFT April May 15, 2014 

4 

thermal output (e.g., steam for heating purposes). These types of facilities are called combined 

heat and power, or CHP, facilities. 

A variety of factors must be considered when comparing the effectiveness of heat rate 

improvement technologies to increase the efficiency of a given coal-fired EGU. The actual 

overall efficiency that a given coal-fired EGU achieves is determined by the interaction of a 

combination of site-specific factors that impact efficiency to varying degrees. Examples of the 

factors affecting EGU efficiency at a given facility include: 

 EGU thermodynamic cycle – EGU efficiency can be significant improved by using a 

supercritical or ultra-supercritical steam cycle. Supercritical and ultra-supercritical boilers 

operate above the critical point of water (approximately 374°C (705°F) and 22.1 MPa 

(3,210 psia)). As a general guideline, the thermal design efficiencies for subcritical EGUs 

are in the range of 35% to 37%, supercritical EGUs are in the range of 39% to 40%, and 

ultra-supercritical EGUs in the range of 42% to 45%. However, actual operating 

efficiencies are lower than design efficiencies. The majority of existing PC-fired EGUs in 

the U.S. electric fleet use subcritical boilers

 EGU coal rank and quality – EGUs burning higher quality coals (e.g., bituminous) tend 

to be more efficient than EGUs burning lower quality coals with a greater moisture 

content (e.g., lignite). Bituminous coals have higher heating values of greater than 10,500 

British thermal units per pound and lignite coals have higher heating values of less than 

8,300 British thermal units per pound. 

 EGU plant size –EGU efficiency generally increases somewhat with size (e.g., from 200 

MW to 800 MW) because: a) the boiler and steam turbine losses are lower for larger 

equipment compared to smaller equipment, b) larger units tend to be younger 

incorporating improvements from advanced technologies, and 3) the economy of scale of 

larger units allows the use of higher cost improvements to be more economic. However, 

as equipment size increases the differences in these losses start to taper off. 

 EGU pollution control systems – The electric power consumed by air pollution control 

equipment reduces the overall efficiency of the EGU.

Comment [A7]: Could indicate the approximate

range (BTUs / lb) of the different coal types, as well

as the influence of moisture.

EPA response: The ranges have been added.

Comment [A8]: : Could indicate approximate

turbine size / size class here.  

EPA response: Edits made to address the comment.
DRAFT April May 15, 2014 

5 

 EGU operating and maintenance practices – The specific practices used by an individual 

electric utility company for combustion optimization, equipment maintenance, etc. can 

affect EGU efficiency. 

 EGU cooling system – The temperature of the cooling water entering the condenser can 

have impacts on steam turbine performance. Once-through cooling systems can have an 

efficiency advantage over recirculating cooling systems (e.g., cooling towers). However, 

once-though cooling systems typically have larger water related ecological concerns than 

recirculating cooling systems. 

 EGU geographic location and ambient conditions – The elevation and seasonal ambient 

temperatures at the facility site potentially may have aan measureable impact on EGU 

efficiency. At higher elevations, air pressure is lower and less oxygen is available for 

combustion per unit volume of ambient air than at lower elevations. Cooler ambient 

temperatures theoretically could increase the overall EGU efficiency by increasing the 

draft pressure of the boiler flue gases and the condenser vacuum, and by increasing the 

efficiency of a condenser recirculatingthe cooling system. Also, geographic location 

influences the type of cooling system that can be used (e.g., EGUs located in arid 

locations often cannot use once through cooling)

 EGU load generation flexibility requirements – Operating an EGU as a baseload unit is 

more efficient than operating an EGU as a load cycling following unit to respond to 

fluctuations in customer electricity demand. 

 EGU equipment manufacturers – The efficiency specifications of major EGU 

components such as boilers, turbines, and electrical generators provided by equipment 

manufacturers can affect EGU efficiency. 

 EGU plant components – EGUs using the optimum number of feedwater heaters, highefficiency electric motors, variable speed drives, better materials for heat exchangers, etc. 

tend to be more efficient. 

2.3 Technologies to Improve Existing Coal-Fired EGU Heat Rate 

Comment [A9]: Geographic location could also

influence cooling water issues, mentioned earlier

(i.e. coal plants in the arid west).

EPA response: Text has been added to address the

comment.  

Comment [A10]: Suggest using “load following”

for clarity

EPA response: Done.

Comment [A11]: This seems less about the

manufacturers and more about the specific

technology choice. Suggest describing this as “EGU

technology choice” and, if necessary, note that

efficiency can vary by manufacturer or by product.

EPA Response: Deleted since this is not relevant to

the discussion.
DRAFT April May 15, 2014 

6 

A number of studies have been conducted involving literature reviews of published 

articles and technical papers identifying potential efficiency improvement techniques applicable 

to existing coal-fired EGUs.1

 For example, a summary of the findings from one study conducted 

by the Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) is 

presented in Table 2-2. The efficiency percentages were converted to a common basis so that all 

of the data can be compared. All of the improvement technologies presented in Table 2-2 cannot 

necessarily be implemented at every existing coal-fired EGU facility in the U.S. electric utility 

fleet. The existing EGU design configuration and other site-specific factors may prevent the 

technical feasibility of using a given technology. 

Typically, these studies share as a common basis the estimated potential efficiency 

improvement percentages and costs from the engineering study originally completed by Sargent 

and Lundy in 2009 titled “Coal-Fired Power Plant Heat Rate Reductions.” It describes numerous 

well known and technically proven methods to improve efficiency of coal-fired EGUs. The study 

lists possible efficiency improvements in the boiler, turbine, flue gas system, air pollution control 

equipment and the water treatment system. Each of these main areas are expanded upon below. 

2.3.1 Boiler 

The systems to focus on for improving heat input within the boiler area include the 

materials handling, combustion system, boiler control system, sootblowers and the air heaters. 

2.3.1.1 Materials Handling2

The coal handling portion of materials handling typically requires about 0.07% (7 

Btu/kWh) of the gross electrical output of a power plant. Depending on the state of the motors 

and drives, replacing them with energy-efficient motors and variable frequency drives (VFDs)

can reduce the auxiliary power requirements. The VFDsvariable frequency drivesVFDs also 

limit the stress and strain on the other equipment. 

Coal pulverizers typically require about 0.6% (60 Btu/kWh) of the gross electrical output 

and can be upgraded to provide more consistent size and finer coal particles. The fine particles 

improve combustion efficiency, consequently reducing fuel cost and heat rate. The costs for 

                                                            

1

 See HRI Partial Bibliography at the end of this chapter. 

2 The Sargent and Lundy report did not provide potential savings for material handling operations. Energy use in 

Btu/kWh has been provided to compare the energy use of materials handling relative to the potential energy savings 

from other efficiency activities.

Comment [A12]: Did you want to include an

estimate of pulverizer electric demand?

EPA response: An approximate electric demand has

been added.
DRAFT April May 15, 2014 

7 

changes to the pulverizer system are significant, and historically, the projects have improved the 

heat rate justifiably only when the existing equipment has degraded. 

The bottom ash handling system may be a source for heat rate improvement. Switching 

from a water-sluicing bottom ash system to a dry drag chain system can reduce the auxiliary 

requirements and reduce the amount of water to the water treatment plant. The typical power 

requirements are about 0.1% (10 Btu/kWh) of the plant’s gross output. 

2.3.1.12 Economizer 

An economizer is a heat exchanger that improves the efficiency of an EGU by recovering 

energy from the exhaust gases to preheat the boiler feedwater. The replacement of the 

economizer can lead substantial heat rate improvements around 50-100 Btu/kWh, but is large 

capital investment (~$2-8M). Due to this high cost, economizers upgrades are not generally 

performed unless the existing equipment has degraded or a replacement is necessary due to the 

installation of new control equipment. 

2.3.1.23 Boiler Control System 

The boiler control system has a large impact on the heat rate of the unit. The process 

control capabilities can control and evaluate many aspects of the plant’s operations. Commonly 

referred to as the Neural Network (NN), computer models are able to control the plant’s 

processes by predicting performance during static and dynamic changes. Many vendors offer 

Neural NetworkNN systems to improve the overall efficiency. Neural networkNN systems are 

typically around $550,000-$750,000 and offer heat rate reductions up to 150 Btu/kWh. 

2.3.1.34 Sootblowers 

Intelligent sootblowers (ISB) may be installed to improve system efficiency. The 

intelligent sootblowersISB system monitors the furnace exhaust gas temperatures and steam 

temperatures. Other readings may be incorporated into the intelligent sootblowersISB system 

which also communicates with the boiler control system. This system uses real-time data to 

identify which areas need sootblowing. Boiler efficiency improvements have ranges from 

0.330%-(1.5%0 Btu/kWh) with capital costs around $300,000-$500,000 and $50,000/year for 

fixed operating and maintenance costs. 

Comment [A13]: For this part of the discussion,

some efficiency gains are given in percent, and

others in Btu/kWh. It would be helpful to keep

either one common unit (suggest Btu/kWh) or

provide both metrics.

EPA response: See footnote.  

Comment [A14]: Please add a sentence on what

an economizer is and does.

EPA response:  Added an introductory sentence.
DRAFT April May 15, 2014 

8 

2.3.1.45 Air Heaters 

Air heaters operate to transfer heat between the incoming pre-combustion air and the 

effluent flue gas. These systems are critical to maintain an efficient power plant. In order to 

maintain these systems to operate most efficiently, air heater leakages must be maintained below 

6% of incoming air flow. Most leakage is due to the pre-combustion air leaking across the 

rotating section and leaving with the flue gas. This increases the flue gas volume going through 

the forced draft and induced draft fans to the emissions controls and avoids capturing the heat 

transferred between the flue gas and pre-combustion gas. The increased volume requires more 

power to pump more flue gas. Additionally, improvements to seals on the air heaters also reduce 

the leakages. Improvements to reduce air heater and duct leakages generally reduces the heat rate 

by 10-40 Btu/kWh with capital costs between $0.3-1.2M. 

A second method to improve the heat rate is to lower the air heater outlet temperature by 

controlling the acid dew point. Typically the air heater outlet is maintained at 20-30°F above the 

sulfuric acid dew point to prevent corrosion of cold-end baskets. Sorbent injections such as 

Trona or hydrated lime can be used to lower the dew point. Depending on the sizing of the air 

heater, the air heater may need to be modified in order to optimize the lower outlet temperature. 

Generally, a 40°F reduction in the air heater outlet results in 1% efficiency improvement. These 

systems are costly and depend on whether the air heater is adequate, needs modifications or 

needs a complete replacement. The capital costs can range from $1.5-18M for heat rate 

reductions of 50-120 Btu/kWh. 

2.3.2 Turbine 

The systems within the turbine area for which to focus heat rate improvements are the 

turbine, the feedwater heaters, the condenser, and the turbine drive and motor-driven feed 

pumps. 

2.3.2.1 Turbine 

Replacements or overhauls of existing steam turbines with advanced turbine designs 

improves the efficiency of converting the energy in the steam to electrical energy. The 

performance and longevity of turbines is constantly increasing with advances in technology. 

Most turbines in the industry are maintained so that the efficiency improvements are 1-3%; 

however, some extremely degraded turbines may benefit up to 10% with a turbine overhaul. The 
DRAFT April May 15, 2014 

9 

capital costs for these projects ranges from $2-25M with heat rate reductions of 100-300 

Btu/kWh.

2.3.2.2 Feedwater Heaters 

The feedwater heaters are heat exchangers to heat the boiler feedwater by extracting heat 

from the steam leaving the turbine section. The efficiency can be increased by improving heat 

transfer surface area. This entails adding heat exchange surfaces to the existing heaters or adding 

additional heaters. The costs relative to the heat rate improvement associated with these projects 

typically prohibit the advancement of the project unless the feedwater heaters are in need of 

repair. 

2.3.2.3 Condenser 

To obtain the most efficiency from the condenser section, the most effective operation 

would have the steam from the turbine to reach the lowest temperature possible before entering 

the condenser. This allows for the turbine to extract as much energy from the steam as possible. 

Condensers are subject to fouling and plugging which directly impact the heat transfer rates and 

water quality. To improve water quality, closed cooling water systems provide better control of 

the water quality and tube cleaning can be performed. Heat rate reductions observed from the 

condenser upgrades and maintenances are 30-70 Btu/kWh with annual fixed costs of $30,000-

$80,000. 

2.3.2.4 Boiler Feed Pumps 

Boiler feed pumps require a large amount of auxiliary power to pump massive amounts 

of boiler feedwater through the heaters and boiler. Due to the high use of these pumps, 

maintenance is extremely important to ensure reliability and the most efficient operation. As the 

pumps wear and operate less efficiently, a pump overhaul may be required. The overhaul can 

reduce the heat rate by 25-50 Btu/kWh with capital costs around $250,000-$800,000. 

2.3.3 Flue Gas System 

Two aspects of the flue gas system that offer potential improvements to the plant 

efficiency are to improve the forced draft (FD) and induced draft (ID) fan efficiencies and 

implementation of variable frequency drivesVFDs. 

Comment [A15]: Not clear whether the 1‐3%

efficiency improvement refers to improvement

resulting from an overhaul. It might be helpful to

indicate what size of turbines correspond to these

costs.  

EPA response: the paragraph has been modified.

Comment [A16]: Please spell out acronym –

even if it has been spelled out earlier, I have

forgotten and couldn’t find the location on looking

back.

EPA response: Spelled out acronyms.
DRAFT April May 15, 2014 

10 

2.3.3.1 Induced DraftID Fans 

One of the most important features in the fans is being able to control the flue gas flow. 

Many fans have dampers, which are the least effective and efficient option. There are many 

methods, such as variable inlet vanes (VIV), variable frequency drivesVFD, and variable pitch 

blades (VPB), available to control the flue gas flow allowing highly efficient fan performance. 

These upgrades or replacements provide a heat rate reduction of 10-50 Btu/kWh and cost 

between $6-$16M. 

2.3.3.2 VFDVariable Frequency Drives (VFD)

It is apparent with the control that a variable frequency drivesVFD offers, the plant is 

able to reduce the auxiliary load immensely. Considering upgrading all drives, the capital costs 

are $6-16M with heat rate reductions between 10-150 Btu/kWh. 

2.3.4 Emission Control Technologies 

With the passage of environmental regulations, additional emission control devices have 

been and must be implemented in the power plant. These systems typically require large amounts 

of auxiliary power with their benefit being improved air quality. Even small upgrades can 

decrease the power requirements significantly while at least maintaining the same level of 

emissions reduction. The three technologies discussed are the flue gas desulfurization (FGD), the 

electrostatic precipitator (ESP), and the selective catalytic reduction (SCR) systems. 

2.3.4.1 FGDFlue Gas DesulfurizationFGD

Coal-fired power plants contain many variances between their flue gas 

desulfurizationFGD systems. A few common technology improvements are discussed further in 

this section. Older units typically contained a venturi throat that increased the velocity of the 

fluid, but resulted in a large pressure drop and greater power to operate the ID induced draft fans. 

To improve this operation, a co-current spray tower quencher may replace the unit. The capital 

cost is about $2.5M with heat rate reductions around 13 Btu/kWh. 

Another technology upgrade affects the vanes and distribution plate into an absorber. The 

improvement of the gas flow coming into contact with the absorber sorbent increases SO2

capture, reduces maintenance due to erosion, and reduces the amount of energy required from the 

ID induced draft fan. Turning vanes and a perforated gas distribution plate improve gas 

distribution. The cost of the vanes is around $250,000 with heat rate reductions of 1-2 Btu/kWh. 

Comment [A17]: For all these subtitles, it

wouldn’t hurt to spell out the acronym in the

section title.

EPA response: Spelled out acronyms.
DRAFT April May 15, 2014 

11 

In a wet flue gas desulfurizationFGD multiple spray levels are installed to deliver the limestone 

slurry. If a power plant is operating with SO2 levels below its permit limit, turning off one spray 

level will reduce the auxiliary power necessary. If this is possible, a unit heat rate reduction of 16 

Btu/kWh may be available. 

2.3.4.2 ESPElectrostatic PrecipitatorESP

The best operation for an electrostatic precipitatorESP involves maintaining the 

maximum applied voltage, but below the level in which spark-over occurs. Eelectrostatic 

precipitatorESP energy management system (EMS) upgrades often help improve the electrostatic 

precipitatorESP performance by maintaining the optimal performance and lowering power 

consumption. The installation for this technology can be from minimal to $0.8M and can lower 

heat rate by 5 Btu/kWh. 

2.3.4.3 SCRSelective Catalytic ReductionSCR

For the last 15 years, selective catalytic reductionSCR systems have been in use to reduce 

NOX emissions from power plants. Extensive modeling was performed to achieve the necessary 

reduction with minimum ammonia slip. The results showed that reducing pressure drop and 

using secondary air as dilution for the ammonia vaporizer can reduce the auxiliary power 

necessary. The heat rate reduction is 0-10 Btu/kWh and capital costs between $0.5-$2M with 

fixed and variable costs up to $100,000 each. 

2.3.5 Water Treatment System 

The water treatment system heat rate improvements can occur for the boiler water 

treatment and the cooling tower improvements. The boiler water is one of the most important 

aspects of the power plant. The quality of the water plays a huge impact on the scale buildup on 

the boiler tubes, which reduces the heat transfer in the tubes or can cause tube failures. Proper 

use of chemicals to maintain pure water is key. Also, high-quality water can reduce the 

blowdowns required, which allows for more steam in the turbine cycle. If the water is not 

properly maintained, heat transfer may be reduced up to 10%. 

Similar to the boiler water, the cooling towers are also affected by the water quality. 

Fouling and scaling remain issues for heat transfer and purity of the water. By maintaining the 

cooling water system efficiently, the overall water quality is improved, which branches into other 

aspects already mentioned. 
DRAFT April May 15, 2014 

12 

Table 2-2. Existing coal-fired EGU efficiency improvements reported for actual efficiency improvement projects 

Efficiency 

Improvement 

Technology

Description 

Reported 

Efficiency 

Increasea

Combustion 

Control 

Optimization 

Combustion controls adjust coal and air flow to optimize steam production for the steam turbine/generator set. However, combustion control for a coal-fired EGU is complex and impacts a number of important operating parameters including combustion efficiency, steam temperature, furnace slagging and fouling, and NOX

formation. The technologies include instruments that measure carbon levels in ash, coal flow rates, air flow rates, CO levels, oxygen levels, slag deposits, and burner metrics as well as advanced coal nozzles and plasma assisted coal combustion. 

0.15 to 0.84% 

Cooling System 

Heat Loss 

Recovery 

Recover a portion of the heat loss from the warm cooling water exiting the steam condenser prior to its circulation thorough a cooling tower or discharge to a water body. The identified technologies include replacing the cooling tower fill (heat transfer surface) and tuning the cooling tower and condenser. 

0.2 to 1% 

Flue Gas Heat 

Recovery 

Flue gas exit temperature from the air preheater can range from 250 to 350°F depending on the acid dew point temperature of the flue gas, which is dependent on the concentration of vapor phase sulfuric acid and moisture. For power plants equipped with wet FGD systems, the flue gas is further cooled to approximately 125°F as it is sprayed with the FGD reagent slurry. However, it may be possible to recover some of this lost energy in the flue gas to preheat boiler feedwater via use of a condensing heat exchanger. 

0.3 to 1.5% 

Low-rank Coal 

Drying 

Subbituminous and lignite coals contain relatively large amounts of moisture (15 to 40%) compared to bituminous coal (less than 10%). A significant amount of the heat released during combustion of low-rank coals is used to evaporate this moisture, rather than generate steam for the turbine. As a result, boiler efficiency is typically lower for plants burning low-rank coal. The technologies include using waste heat from the flue gas and/or cooling water systems to dry low-rank coal prior to combustion. 

0.1 to 1.7% 

Sootblower 

Optimization 

Sootblowers intermittently inject high velocity jets of steam or air to clean coal ash deposits from boiler tube surfaces in order to maintain adequate heat transfer. Proper control of the timing and intensity of individual sootblowers is important to maintain steam temperature and boiler efficiency. The identified technologies include 

intelligent or neural-network sootblowing (i.e., sootblowing in response to real-time conditions in the boiler) and detonation sootblowing. 

0.1 to 0.65% 

Steam Turbine 

Design 

There are recoverable energy losses that result from the mechanical design or physical condition of the steam turbine. For example, steam turbine manufacturers have improved the design of turbine blades and steam seals which can increase both efficiency and output (i.e., steam turbine dense pack technology). 

0.84 to 2.6 

Source: National Energy Technology Laboratory (NETL), 2008. Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired Power Plant 

Fleet, DOE/NETL-2008/1329. U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA. July 23, 2008. Available at: <http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf>. a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming individual component efficiencies for a reference 

plant as follows: 87% boiler efficiency, 40% turbine efficiency, 98% generator efficiency, and 6% auxiliary load. Based on these assumptions, the reference power plant has an overall efficiency of 32% and a net heat rate of 10,600 Btu/kWh. As a result, if a particular efficiency improvement method was reported to achieve a 1% point increase in boiler efficiency, it would be converted to a 0.37 % point increase in overall efficiency. Likewise, a reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30% point increase in overall efficiency. 
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2.4 Previous Studies on Heat Rate Improvements 

A number of studies using varying approaches have been performed to determine 

potential efficiency improvements and associated resulting CO2 emission reductions. These 

approaches include characterizing the current U.S. coal-fired EGU fleet, identifying potential 

efficiency improvements, and applying improvement actions to existing EGUs. The approach 

taken within each study varies. Five studies are briefly summarized and compared in Table 2-3. 

The NETL studiesStudies 1 and 2 used a benchmarking approach that evaluated the 

design factors that are known to influence efficiency and grouped EGUs based on similar design 

characteristics. The studies categorized the industry based on fuel type, location, steam cycle, 

and age of the boilers. Potential efficiency improvements were calculated based on an 

assumption that the lower-performing EGUs in each group should to be able to do as well as the 

better performing EGUs in that group. Specifically, the goal for potential improvement: for each 

subcategory was that the bottom 90% of EGUs in each group improved their heat rate to the 

average performance of top 10% in that group. While the studies are different in the level of 

detail and assumptions, the results of these studies overall suggest that a U.S. coal-fired EGU 

fleet-wide improvement ranging from 9% to 15% is theoretically possible. Study 3The Lehigh 

study used a less detailed approach and evaluated technologies applicable to bituminous and 

subbituminous coals to estimate potential fleet wide reductions. 

An alternative approach to evaluate heat rate improvement is used for Study 4.by 

Resources for the Future. This study focused on the operating efficiency (synonymous with heat 

rate) of the entire existing U.S. coal-fired EGU fleet. The authors evaluated decades of data from 

industrial responses to economic factors such as demand, coal price and energy policies. This 

approach This approach sought to estimate overall changes in industry fleet efficiency in 

response to changes in fuel prices or carbon pricesdetermined that given specific changes in the 

coal price and a carbon tax, the industry will make heat rate improvements on their own. In this 

specific example, the coal price was assumed to be a 10% increase and the CO2 emissions tax at 

$1.64 per ton for heat rate reductions of 0.3 to 0.9%. 

Study 5The National Resources Defense Council approach considered the fleet of coalfired EGUs and assumes a target heat rate in order for the EGUs to comply with an inferred 

Comment [A19]: To avoid ambiguity it might be

helpful to cite (footnote) studies when referring to

them.  

EPA response: Added study names.

Comment [A20]: Suggest an alternate phrasing

such as: This approach sought to estimate overall

changes in industry fleet efficiency in response to

changes in fuel prices or carbon prices.

EPA response: The language has been edited as

suggested.
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standard. As opposed to the above studies that determined by how much the efficiencies can 

improve, this approach estimated how the industry will meet any imposed standards and 

calculated the heat rates necessary to meet a standard. As it has not been determined with regards

to how the CO2 emissions limit will be averaged, the paper discusses many potential options that 

coal-fired EGUs may have to meet new standards. These options include additional options such 

as adding renewable, natural gas, and combined-cycle sources. 

The EPA observed that most of the existing studies develop fleet-wide average HRI 

potentials/goals that are higher than values considered feasible and sustainable by the power 

sector engineers with whom the EPA has informally discussed this subject. The EPA also 

notedobserved that all existing HRI studies using a benchmarking approach have relied on a 

single year annual average heat rate data, whereas many of the operational impacts on heat rate 

(diurnal temperatures, load following, etc) become more apparent in the variability of hourly 

performance data. We further recognized that an examination of heat rate data over a multiple 

year period, perhaps a decadal time frame might reveal patterns of performance that should also 

inform estimates of HRI potential. For these reasons, the EPA has developed in this TSD an 

additional assessment of HRI potential that draws on multiyear historical hourly data. While we 

understanoodunderstood that engineering judgment would remains still be essential to a proper 

interpretation of the results, the EPA intendeds that this assessment be a more substantial basis 

for estimating the fleet-wide HRI potential for coal-fired EGUs. 

Table 2-3. Summary comparison of previous studies on EGU heat rate improvements 

Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

StudyRelevant 

HRI 

Results 

1 “Reducing CO2 

Emissions by 

Improving the 

Efficiency of the 

Existing Coal-fired 

Power Plant Fleet” 

NETL 

• Plant design: age and 

steam cycle 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

performance of top 10% in 

that category 

• Units with capacity factors 

under 50% were removed 

from dataset 

• 15% reduction in 

overall heat rate of 

coal-fired EGUs 

2 “Improving the 

Efficiency of CoalFired Power Plants 

for Near Term 

• Plant design: coal type, 

steam cycle, and size 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

• 8.7% reduction in 

overall heat rate of 

coal-fired EGUs 

Comment [A21]: The reasons for considering

the existing studies unrealistic could be discussed

more explicitly. Perhaps, for example, there is a

more explicit argument to be made about specific

interventions and timescales.

EPA response: The text has been deleted.

Comment [A22]: Not certain this is correct ‐ the

RFF study abstract states: “This paper examines the

operation of coal‐fired generating units over 25

years to estimate the marginal costs and potential

magnitude of emissions reductions from improving

their efficiency.” Please correct if appropriate.

EPA response: The text has been clarified to refer to

studies that used a benchmarking type approach to

estimate potential reductions.  

Comment [A23]: Please check on the tense –

past or present?

EPA response: Thank you for the observation.
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Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

StudyRelevant 

HRI 

Results 

Greenhouse Gas 

Emissions 

Reductions” 

NETL 

performance of top 10% in 

that category • Units with 

anomalous data, capacity 

factors under 10%, using 

less than 97% coal, and 

gasification plants were 

removed from dataset 

• Low pressure subcritical 

units and 0-200 MW 

subbituminous units 

assumed retired for goal 

• Lost generation made up by 

more efficient coal-fired 

EGUs 

3 “Reducing Heat 

Rates of Coal-Fired 

Power Plants” 

Lehigh Energy 

Update 

 All possible heat rate 

improvements are made 

including drying of high 

moisture coal: 

• 10% improvement 

for bituminous coalfired EGU 

• 15% improvement 

for subbituminous 

coal-fired EGU 

4 “Regulating 

Greenhouse Gases 

from Coal Power 

Plants under the 

Clean Air Act” 

Resources for the 

Future 

• Analyze the actual 

operating efficiency of the 

entire fleet of U.S. coalfired EGUs 

• Assess abatement 

opportunities and costs by 

observing how coal plants 

respond to market and 

regulatory incentives to 

improve energy efficiency 

Overall efficiency 

improvements of 2 to 5%, 

from other literature studies 

10% coal price 

increase, 

corresponding to a 

tax on CO2

emissions of about 

$1.64 per ton, 

improving heat rates 

by 0.3 to 0.9 % 

5 “Closing the Power 

Plant Carbon 

Pollution Loophole: 

Smart Ways the 

Clean Air Act Can 

Clean Up 

America’s Biggest 

Climate Polluters” 

NRDC 

• Plant design: coal type 

and steam cycle 

Improvements are broken into 

3 group 

• Top 10% for each 

subcategory, no change 

• Top 11% to 49%, improve 

heat rate by 50% of the 

difference between facility 

heat rate and performance of 

top 10% in class or 600 

Btu/kWh, whichever is less 

• Bottom 50%, improve heat 

rate by 100% of the difference 

between facility heat rate and 

performance of top 10% in 

class or 600 Btu/kWh, 

whichever is less 

 Broader analysis 

not strictly focused 

on heat rate 

improvements. 11% 

reduction on overall 

fossil fuel-fired EGU 

emission rates; 

includes switching 

from coal to natural 

gas. 

2.5 EPA’s Heat Rate Improvement Assessment 

Comment [A24]: Please include text regarding

the peer review to which all these reports have

been subject. If not, please consider subjecting this

concept to technical peer review in the period

following proposal release.

EPA response: We will check on the peer review

status of the studies.  

Comment [A25]: Is there a reason there is no

comment in this box?

EPA response: Text has been added.
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This EPA assessment of fleet-wide HRI potential looks at historical data from coal-fired 

EGUs in the U.S. to identify changes to EGUs’ heat rates – the amount of heat input required, on 

average, to generate 1 kWh of electricity – that can be attributed to operation and maintenance 

practices and equipment upgrades. These heat rate changes are analyzed to determine their 

applicability to the rest of the coal-fired EGU fleet and to determine the potential heat rate 

improvement that, on average, could be achieved by the fleet. 

This data analysis portion of the study relies on unit-level heat input and gross generation 

data reported to the EPA by owners or operators of EGUs to assess in detail the changes in gross 

heat rates. Potential changes in net heat rates are then addressed later in this section. Unit-level 

evaluations allowed the EPA to recognize the significant heterogeneity of coal-fired EGUs; even 

‘sister’ units, units built at the same time at a given facility, may display different operating 

profiles and may have different equipment, controls, fuel mixes or cooling systems. 

Based on literature reviews; informal interviews with engineering experts, vendors, and 

plant operators; and historical information collected by the EPA, we believe EGUs achieve heat 

rate improvements by: 1) operating under recommended operation and maintenance conditions 

(best practices), and 2) installing and using equipment upgrades. Best practices include no-cost 

or low-cost methods such as the installation or more frequent tuning of control systems and the 

like-kind replacement of worn existing components. Upgrades often involve higher costs and 

greater downtime, such as, extensive overhaul or upgrade of major equipment (turbine or boiler) 

or replacing existing components with improved versions. 

The EPA developed unit-level statistics from over 60 million rows of hourly data. We 

evaluate each unit on its individual performance using heat rate variability as an indicator of the 

application of best practices and potential for improvement. To estimate heat rate improvement 

through equipment upgrades we survey engineering studies, examine year-to-year trends, and 

research EGUs where such methods were applied. 

2.5.1 Study Population and Data 
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The EGU study population consists of 884 coal- and petroleum coke-fired EGUs that 

reported both heat input3

 and electrical output to the EPA’s Clean Air Markets Division in 2012.4

It includes a wide range of configurations, from 24 to 1,500 MW nameplate capacities, super and 

subcritical thermodynamic cycles, between 1 and 69 years old, and different coal ranks. It 

excludes any EGUs at any facility that reported cogeneration to the EPA or the EIA. These units 

are excluded because a portion of the heat input was used to generate electricity and/or steam 

heat. Therefore, it is difficult for the EPA, using available data, to make a meaningful 

comparison of these units’ heat rates. 

The EPA performed this study using hourly heat input (Btu), and electricity output 

(MWh) data from the Clean Air Markets Division and meteorological data from NOAA’s 

National Climatic Data Center for the years 2002-2012. As described later in this section, these 

meteorological data were used to account for temperature impacts on heat rates. The eleven year 

study period is representative of a wide range of conditions, including growth and recessionary 

economic conditions, changing electricity generation from renewable and natural gas, and 

different regulatory constraints. 

The hourly heat input and generation data used in this study is collected under the 

authority of 40 CFR part 75 (hereafter, Part 75). The EPA designed Part 75 to encourage 

complete and accurate emission measurement and reporting to support emission trading 

programs, including the Acid Rain Program and Clean Air Interstate Rule (CAIR). However, the 

EPA recognized that there will be times when emission data are not available due to monitoring 

system malfunctions or maintenance, technical challenges, or missed quality assurance/quality 

control (QA/QC) tests. When data are not available or deemed invalid (e.g., when a QA/QC test 

was not performed as required), the EPA has specified data substitution methods that are 

designed to overestimate emissions. This conservative bias is intended to create an incentive for 

better emission measurement – the overestimate incurs an economic penalty because, at the end 

of the compliance period, an EGU must surrender allowances equal to total reported emissions. 

Because of this conservative bias and the impact it would have on the results of this study, the 

                                                            

3 Sources calculate heat input using an ‘F factor’ for the carbon content of the fuel being combusted and the average 

hourly measurements of CO2 flow and concentration. 4

 Information on the Clean Air Markets Division data is available at http://ampd.epa.gov/ampd/

Comment [A26]: IS QA/QC defined in the

abbreviations?

EPA response: It is defined in the sentence.
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EPA excluded substitute data reported by EGUs from this study’s dataset. These substitute data 

represent approximately 2% of all reported operating hours. In addition, we excluded partial 

hours of operation that occur during the first hour of startup and the last hour of shutdown. 

We also excluded 40 unit-years (0.5% of records) with atypical annual heat rates less 

than 6,500 or greater than 15,000 Btu/kWh resulting from a variety of factors including firing of 

natural gas, very low operating time, or errors in reporting reported gross load. Table 2-4 

summarizes the heat input, electric generation, heat rate and unit counts by year for the study 

population used in this work. This population corresponds to 9,38850350 unit-years of data at 

884 distinct EGUs. Figure 2-21 displays the study population average annual gross heat rate by 

year and the 11-year average.
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Table 2-4. Study Population Annual Heat Input, Generation, Heat Rate and Unit Count 

2002 - 2012 Study Population Unit Count by Year5

Year 

Heat Input 

(million 

MMBtu)

Electric 

Generation 

(million MWhgross) 

Heat Rate 

(Btu/kWhgross) Unit Count 

2002 18,601 1,874 9,924 839833

2003 18,428 1,864 9,886 834828

2004 18,405 1,875 9,819 836833

2005 18,665 1,910 9,774 838836

2006 18,644 1,914 9,743 848845

2007 18,704 1,920 9,740 846844

2008 18,459 1,914 9,643 852851

2009 16,588 1,719 9,649 864860

2010 17,693 1,831 9,662 869865

2011 16,934 1,744 9,708 878876

2012 14,947 1,536 9,732 884879

Figure 2-21. Study Ppopulation Average Gross Heat Rate by Year 

NOAA’s Integrated Surface Data (ISD) product provides hourly temperature for over 

20,000 weather stations worldwide.67 Since EGU heat rate performance is sensitive to air 

temperature and barometric pressure, which vary with elevation, we use meteorological data 

                                                            

5 The study population for each year includes those EGUs that reported both heat input and electric generation.

7 Temperature data is from NOAA’s Integrated Surface Data at http://www.ncdc.noaa.gov/data-access/land-basedstation-data/land-based-datasets/integrated-surface-database-isd.

9,500

9,550

9,600

9,650

9,700

9,750

9,800

9,850

9,900

9,950

10,000

20022003200420052006200720082009201020112012

Heat Rate (btu/kwh)

Annual Heat Rate

11-yr Avg Heat Rate

Comment [A27]: Change in unit counts due to

using conditions that match preceding paragraph.   
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from stations that are reasonably close to the EGU's location and elevation to account for the 

impact of ambient conditions. For each of the plants in this study’s database, we identified the 

nearest stations that reported a minimum of 8,400 hourly observations in the calendar year (i.e., 

greater than 95% of the hours in a year). Generally, each plant was associated with 

meteorological data from the two closest stations over the eleven-year study period. The average 

distance between the plant and the nearest station was 22 miles and the average difference in 

elevation was 366 feet. At nine plants we used data with as few as 7,000 observations in order to 

keep the maximum difference in elevation under 10001,000 feet. The EPA believes that nearby 

weather station measurements are a good approximation of ambient meteorological conditions at 

each facility. Joining the trimmed heat rate and hourly temperature datasets resulted in 

61,848,580 hourly records for the study population of EGUs (see Table 2-4). 

The results of this study are based on analyses of data from the population of coal-fired 

EGUs shown in Table 2-4. These units emitted 1,6065 million tons of CO2 in 2012. In contrast, 

emissions of CO2 from coal-fired EGUs in the entire U.S. electric power sector in 2012 were at 

1,669 million tons according preliminary data from to the EIA.8

 Since the study population of 

EGUs accounted for over 96% of CO2 emissions from the fleet of U.S. coal-fired EGUs, the 

EPA considers the results of this study to be applicable to the coal-fired fleet at large. 

2.5.2 Subcategorization 

In this analysis, units are not categorized by unit specific design characteristics or fuel 

because: (1) EGU-specific detailed design information on all factors that influence heat rate is 

not available, and (2) certain design characteristics are not easily categorized (e.g., EGUs use a 

large range of steam conditions). Several other studies do categorize EGUs broadly by capacity, 

thermodynamic cycle, and/or fuel rank. Although the EPA believes grouping by categories can 

provide a useful way of understanding the operating profile of an EGU and the fleet, the range of 

heat rates for the broad categories has significant overlap (see box and whisker chart in Figure 2-

12) and therefore makes it challenging to develop appropriate categorization. The figure below 

displays available information on coal-fired EGUs considered in this work for the years 2009-

                                                            

8

 Preliminary 2012 results from http://www.eia.gov/tools/faqs/faq.cfm?id=77&t=3. Revised 2012 results will be 

available in March, 2014. The somewhat lower 2012 CO2 emissions total in Table 2-5 below is due to the exclusion 

of substitute data.   
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21 

2011 in typical subcategories of capacity, fuel rank, and thermodynamic cycle. As the figure 

reflects, the means are clustered and the ranges of heat rates overlap. 

 

Figure 2-21. . Three3-Year Average Heat Rates by Subcategory9

2.5.3 Observed Trends in the Period 2002-2012 

Three trends are notable for the study population during the period 2002-2012. 

Comparing the averages of the first three years (2002-2004) to the last three years (2010-2012), 

electric generation , capacity factor, and gross heat rate declined by 9%, 21%, and 2%, 

respectively. UsingC the same time periods cCapacity factor for the study population fell by 14% 

comparing the same time periods (see Table 2-5). The decrease in coal-fired generation and 

capacity factor may be because of reduced demand for electricity resulting from the recession 

starting in late 2008 and greater use of natural gas and renewables to generate electricity. 

The 11-year average annual gross heat rate for the study population of coal-fired EGUs 

(see Table 2-4) was 9,75463 (Btu/kWh). The decrease in study population annual heat rate 

between 2002 and 2012 may be due to several factors. Unit efficiency may have improved or 

units with lower heat rates may have taken up a larger share of generation. In addition, changes 

                                                            

9 Abbreviations in the figure: BIT means bituminous, SUB means subbituminous, PC means petroleum coke, LIG 

means lignite, SUPER means supercritical, SUB means subcritical OVER/UNDER means greater/less than 

indicated MW capacity. Unit counts (n) by category: BIT SUPER, n=80; SUB SUPER, n=30; BIT OVER, 200 

n=196; PC, n=2; BIT 100 to 200 n=140; SUB OVER 100, n=299; LIG OVER 100, n=20; BIT UNDER 100, n=68; 

SUB UNDER 100, n=56; LIG UNDER 100, n=2. Total unit count is 893.

6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

BIT SUPER

SUB SUPER

BIT OVER 200

PC

BIT 100 to 200

SUB OVER 100

LIG OVER 100

BIT UNDER 100

SUB UNDER 100

LIG UNDER 100

3-Year (2009-2011) Average Heat Rate (Btu/kWh)

Subcategory

Comment [A28]: Suggest including on the figure

the number of plants in each category (N=? for each

category).

EPA response: added counts to footnote.

Comment [A29]: The footnote uses SUB twice

for different terms.  Please clarify/fix.

EPA response: Done
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22 

in reporting methodology described later in this chapter may be partly responsible. The minimum 

annual heat rate (9,650 643 (Btu/kWh)) occurred in 2008 , near peak generation for the years 

under consideration, and was approximately 1% below the 11-year average. 

Table 2-5 displays the annual heat input, electricity generation, capacity factor, and heat 

rate for the study population of EGUs as reported to EPA. Figure 2-2 displays the average annual 

gross heat rate by year and the 11-year average.

Table 2-5. Reported Annual Heat Input, Generation, Capacity Factor and Heat Rate 

Annual for the PeriodTrends 2002-201102210210

Year Capacity 

Factor (%)

2002 6864

2003 6965

2004 7065

2005 7166

2006 7065

2007 7166

2008 7064

2009 6254

2010 6558

2011 6153

2012 5344

Figure 2-2. Study population Average Gross Heat Rate by Year 

2.5.4 Startups and Shutdowns - Impact On the Results of This Study 

                                                            

10 Table 2-5 shows data as reported to EPA as of May 8, 2014.

9,500

9,550

9,600

9,650

9,700

9,750

9,800

9,850

9,900

9,950

10,000

20022003200420052006200720082009201020112012

Heat Rate (btu/kwh)

Annual Heat Rate

11-yr Avg Heat Rate

Comment [A30]: Suggest making the Table title

more descriptive.  

Also could present fewer signficant  digits in table

...i.e. heat input‐ MM BTU x 106  ‐‐ 

EPA response: changed units and title.

Comment [A31]: This capacity factor decline in

2012 is very different from the CF used later, see

comment on page p. 35, i.e., 78% in 2020.  Which is

correct?  And, did coal CF at 44% factor into the EPA

modeling?

EPA response: The table has been updated to use all

reported data (rather than a trimmed data set). This

changes the capacity factor in 2012 to 53%. Note

the capacity factor of 78% is for the coal‐fired steam

fleet in base case, 2020. Note also that the study

population includes a significant number of EGUs

that IPM lists as retiring prior to 2016.
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23 

During periods of startup and shutdown, EGUs are known to operate at higher heat rates. 

Therefore, we evaluated the potential impact of such events on in our evaluationstudy. A startup 

event, as defined here, occurs when an EGU begins combusting fossil fuel and generates some 

measurable amount of electricity. Table 2-6 summarizes the study population average, 

maximum and total starts by year. On average, coal-fired EGUs start combusting fuel and 

generating electricity 11 times per year. The total number (approximately 9,000) of starts for the 

study population of EGUs has remained stable over the study period. Our data reflects that some 

coal-fired units operate in a load following capacity and may report upwards of 200 starts in a 

single year, but these units tend to have low annual capacity factors. The subset of EGUs with 

more than 20 annual startup and shutdown events is responsible for less than 4% of total 

generation in any study year. Therefore while the number of starts is an important variable at a 

small number of EGUs, its impact on heat rate performance evaluated in this study is considered 

to be marginal. 

Comment [A32]: At about this point, the

chapter transitions into the quantitative analysis.

Suggest highlighting that in some way. There seem

to be several components of the quantitative

analysis: 1. Regressing HR onto CF and Temp; 2.

Looking at residual heat rates relative to model

prediction; 3. The “bin model” for assessing HRI

potential via best practice; 4. The assessment of HRI

potential via equipment upgrades. Suggest

presenting those more clearly either here or even

forward in the chapter in summary form.

EPA response: Thank you. We have added a

paragraph introducing more‐quantitative analyses.
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24 

Table 2-6. EGU Start Count by Year 

Year Average Maximum (at 

any single EGU) Total 

2002 11.1 209 9,363 

2003 10.6 194 8,936

2004 10.7 134 9,081 

2005 11.0 183 9,265 

2006 10.5 139 8,859 

2007 10.5 164 8,908 

2008 10.4 134 8,880

2009 10.3 178 8,902 

2010 10.5 211 9,110 

2011 10.6 206 9,295 

2012 9.9 119 8,805 

To understand the potential for heat rate improvement available with existing coal-fired 

steam EGUs, the EPA conducted a number of quantitative analyses. These included: (1) 

regression analyses to understand the impact of capacity factor and ambient temperature; (2) 

using a bin model to determine the potential from best practices; and, (3) evaluating available 

data and information to assess the potential from equipment upgrades. These analyses are 

described in the following sections. 

2.5.5 Impact of capacity factor and ambient temperature 

Two important factors that affect heat rate at an EGU are hourly capacity factor and 

ambient temperature. In this section, we examine the impact of these two variables on heat rates 

of the EGUs in the study population. Power plant operators today typically use digital control 

systems to capture hundreds of data points in near real-time that are summarized in the unit heat 

rate statistic. EPA has access to a small fraction of that information. A key reason this study used 

capacity factor and ambient temperature as independent variables is that both were available as 

hourly data. Preliminary analyses of heat rate at higher time increments, such as month, were 

useful to describe aspects such as seasonality but we determined hourly data was necessary to 

understand how heat rate was responding to constantly changing operating conditions. We tested 

for collinearity between capacity factor and ambient temperature using a zero-order correlation 

Comment [A33]: After this sentence, suggest

adding a sentence stating why this is important to

do, and a sentence summarizing the approach.

(EPA) see updated text  
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25 

matrix on the entire hourly data set. The correlation between the independent variables was -.048 

– well below an indication of collinearity. 

We also considered fixed unit characteristics such as unit type, fuel rank and age as 

independent variables. As noted above in the discussion on subcategorization, these factors can 

be helpful to understanding the heat rate performance of EGUs. The purpose of this study, 

however, is to find the potential for heat rate improvement across the fleet. We use heat rate 

variability as a key statistic to measure this potential. The correlation between the potential for 

heat rate improvement and fixed characteristics is typically low.11 

Coal-fired units are designed to operate most efficiently at full capacity. As a unit drops 

below this level, in general, heat rate will increase. The average capacity factor over 11 years for 

the study population is 67%, but as noted above, has moved markedly over the study period. This 

study looks at utilization level at both hour and year time scales. The two are related but reveal 

different information about how an EGU is operating. For example, for a unit to achieve a high 

annual capacity factor (e.g., over 90%) it must operate at a high load for most hours in a year. At 

lower capacity factors interpreting the relationship between hourly and yearly utilization levels 

becomes more complex. For example, an EGU may run at an annual 60% capacity factor by 

operating 8 months at near full capacity and generating no electricity the rest of the year, or it 

may run at lower utilization levels for most hours of the year in response to weather, generation 

cost, and transmission constraints. 

Ambient temperature can affect heat rate in two ways: 1) the efficiency of the 

thermodynamic steam cycle12 and, 2) in many regions of the country, as temperatures increase 

electricity demand and capacity factor follows. Figure 2-3 shows the average monthly capacity 

factor in 2012 alongside the climate normal monthly temperature.13 The lines intersect in the 

                                                            

11 For example, the correlation between annual unit heat rate variability (discussed below as relative standard 

deviation) and unit nameplate capacity (MW) is in the -0.1 range. 12 The availability of a cold heat sink in the condenser is a key factor in that cycle. The design of the heat exchanger, 

type of cooling system and availability of water all have an impact on performance. An increase in ambient air 

temperature, and consequent increase in water temperature, typically lower the effectiveness of the cooling system, 

the condenser, and, therefore, overall plant efficiency.

13 Climate normal is the average of temperature (or other measure) over a prescribed 30-year interval and location. 

The chart shows the 1981-2010 climate normal monthly temperature at Baltimore-Washington Airport, MD.

Comment [A34]: Suggest discussing explicitly

the choice of CF as an independent variable – why is

it reasonable to think of it as an independent

element? Are there better factors that EPA could

have used but was unable to because of information

availability?

EPA response: see the preceding paragraph
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26 

spring as temperatures begin to rise and the need for cooling drives electricity demand. 

Generally, Ppeak capacity factor and generation in most parts of the U.S. occur on the hottest 

days of the year. Yet, the relationship between ambient temperature and capacity factor is 

complex. Each plant responds differently depending on design, meteorological conditions and 

electricity demand. For example, a base load plant may operate at a high capacity factor seven7 

days a week regardless of temperature. As noted above, the ere is little collinearity between 

these two variables is low.

Figure 2-3. Monthly Capacity Factor, 2012. 

2.5.5.1 Regression AnalysisAnalysis to Aassess Iassess impact of Capacity FactorFCF and 

Ambient Temperature on Hheat rate

Using the hourly data set, the EPA performed three regression analyses for each unityear: heat rate onto capacity factor, heat rate onto ambient temperature and heat rate onto 

capacity factor and ambient temperature. The single variable analyses evaluations help to 

examine the relative influence of capacity factor and ambient temperature on heat rate. Since this 

analysis seeks to evaluate heat rate under normal operating conditions, we removed records with 

hourly heat rate values outside of +/- 2.6 standard deviations (1.9% of records) before 

performing the regressions.14 Similarly to partial operating hours, these outliers tend to occur 

during low load conditions. The records trimmed amount to one-fourth of a percent of the total 

study population generation. Regression results describe the goodness of fit for the model and 

are expressed as the coefficient of determination or ‘r-squared’. To represent the relative 

                                                            

14 The 2.6 standard deviation bound is used in other EPA regulatory analyses. 

0

20

40

60

80

100

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Electric generation monthly 2012 capacity 

factor and normal temperature

Capacity Factor

(Monthly %, 2012)

Climate Normal

(BWI, MD)

Comment [A35]: Could more granularity on unit

characteristic/type of fuel/design be included as

part of the regression analysis?  

EPA response: As noted earlier in the TSD, fixed unit

characteristics such as unit type, fuel rank and age

can be useful for understanding the heat rate

performance of EGUs.  The purpose of the study,

however, was to find the potential for heat rate

improvement. We found very little correlation

between potential for heat rate improvement and

fixed characteristics.  For example, the correlation

between the unit heat rate variability (annual

relative standard deviation) and unit capacity (MW)

is typically in the ‐.1 range.   

Comment [A36]: It is sometimes hard to follow

the outline of the chapter – currently uses bold,

bold italic, underline.  Suggest using headings like

1.1, 1.1.2, etc. or other indicators.

EPA response: Done ‐ thanks for the suggestion.

Comment [A37]: Capacity factor is also

influenced by temperature – any considerations for

collinearity effects in the regression?

EPA response: We tested for collinearity between

capacity factor and ambient temperature using a

zero‐order correlation matrix on the entire hourly

data set. The correlation between the independent

variables was ‐.048 – well below an indication of

collinearity.    
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27 

contribution of varying unit capacities all results are generation-weighted.15 The average study 

population r-squared for the multivariate regression is 26%. This means that hourly ambient 

temperature and capacity factor together explain 26% of the change in heat rate for the study 

population over the study period. The average study population r-squared from the single 

variable analysis of capacity factor is 16%; the corresponding result for temperature is 10%. 

This means that approximately 16% of the change in hourly heat rate is attributable to capacity 

factor and 10% to ambient temperature. These results, however, conceal considerable variability. 

Some EGUs, typically load-following, have an 11-year average r-squared for capacity factor 

exceeding 50%. At those EGUs, the capacity factor is a key variable influencing changes in heat 

rate. 

At approximately one-fourth of the study population the response to ambient temperature 

is larger than the response to capacity factor. At some individual EGUs, temperature may explain 

up to 30% of the change in heat rate. These are typically, but not exclusively, units with oncethrough, fresh water, cooling systems. Identifying temperature-responsive EGUs allows us to 

understand why heat rate may increase during periods of peak demand. These are the EGUs 

where the ambient temperature ‘signal’ is an important variable. At a typical EGU, summer 

month heat rates may increase by 2-4% compared to winter months, but at a temperatureresponsive EGU that figure may be as high as 10%. 

Our results analysis found indicates that as EGUs cyclecycled more, i.e., movemoved

from base load to load following, capacity factor will tendtended to have a larger effect on heat 

rate. Since 2008, the study population capacity factors moved from the top load bin into lower 

load bins. This can be seen from Figure 2-4, which compares the study population duty cycles in 

2008 to 2012. A significant share of 2008 generation occurred at EGUs running at greater than 

845% annual capacity factor. In 2012, little generation took place in that bin or above, and 

generation was reduced by about half in the next lower bin (789-834% capacity factor). 

                                                            

15 In a weighted average, each component is multiplied by a factor reflecting its importance. In this case, generationweighted r-squaredissquared is the average sum of r-squared for each unit multiplied 

bymultipliedmultipliedbymultiplied by its annual generation divided by the sum of generation for all units.
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Figure 2-4. Change in Annual Duty-Cycle 2008 and 2012 

2.5.6 Heat Rate Variability and Indication of Improvement Potential 

This study examines heat rate variability from the standpoint of statistical process 

control, which is utilized throughout the power industry. Several years ago, the EPA introduced 

process control charts for auditing emissions data reported under Part 75. Sources and vendors 

adopted the EPA methodology to identify potential problems early, before they significantly 

affect emission measurements. Heat rate lends itself to process control since it is the principal 
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indicator that defines the quality of the electric generation process.16,17 Therefore, in general, 

high variability in heat rate values would reflect opportunities for process improvement. 

We use the relative standard deviation (RSD) of the hourly heat rates to evaluate each 

unit against its past performance and to compare with the study population. Each unit has up to 

eleven RSD values, i.e., one for each operating year between 2002 and 2012. The generationweighted mean RSD for the study population across 11 years is 5.4%. Table 2-8 summarizes 

eleven years of results for the study population by quartiles ordered by the 11-year generationweighted RSD average (ascending).18 The RSD of the top quartile (3.5%) is significantly lower 

than the study population generation-weighted mean RSD of 5.4%. Notably, the EGUs in the top 

quartile are not outliers; they report a third of all generation – the most of any segment. The 

results display a wide range of heat rate variability in the study population and thereby indicate 

the potential for heat rate improvement. 

Table 2-8. RSD in reported heat rate (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

Share of 

Generation 

1 3.5 1.6 4.2 33

2 4.87 4.2 5.3 26

3 6.1 5.3 7.0 24

4 9.8 7.10 25.2 16

The study also examined EGU heat rate variability using the residual heat rate. The 

residual in a regression analysis is the difference between the observed value of the dependent 

variable (heat rate) and the predicted value. The intercept is the value where the linear regression 

crosses the y-axis. For each EGU, we calculated the residual heat rate by summing the residual 

for each hour to the intercept value. The standard deviation of the residual heat rate statistic is 

                                                            

16 “The principal indicator that defines the quality of the process is heat rate.” (Fredrick & Todd, 1993. Statistical 

Process Control Methods in Performance Monitoring. Available at 

famos.scientech.us/Papers/1993/1993section11.pdf) 

17 Since accurate measurement is essential to process control the introduction of increasingly sophisticated digital 

control systems (DCS) presents new opportunities for finding inefficiencies. Vendors (ABB, SeimensSeiemens, 

Emerson) claim heat rate improvements of 2-5 percent can result from upgrading to a modern DCS and advanced 

control technologies. The improvement can be even higher if system-wide real-time optimization is included. 18 Nine EGU RSD values exceeded 2.6 standard deviations above the mean and were removed from the results in the 

table.
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used to understand the amount of variability that is not explained by capacity factor and 

temperature. 

The average RSD corresponding to residual heat rate variability for each EGU is the 

generation-weighted average of up to eleven annual values. The study population generationweighted mean RSD over the study period is 4.5%. This percentage represents the total 

variability across the study population that our analysis could not explain by hourly capacity 

factor or ambient temperature. Possible causes of this variability include changes in plant 

equipment, operating procedures and maintenance, fuels (particularly coal rank), reporting 

methodology, and unexplained factors. There is no temporal trend evident in the RSD. Table 2-9 

summarizes the study population generation-weighted average RSD of residual heat rate over the 

study period in quartiles ordered by the 11-year generation-weighted RSD average (ascending). 

Table 2-9. RSD of residual heat rate (generation weighted)19

Quartile RSD 

average 

RSD 

Minimum 

RSD 

Maximum 

1 2.7 0.0 3.2 

2 3.6 3.2 4.1 

3 4.7 4.1 5.3 

4 6.9 5.3 10.4 

The weighted average RSD of the top quartile is 2.7% – well below the study population 

average of 4.5 %. This means that the residual hourly heat rates of these units generally stay in a 

narrow range within a given year. The maximum RSD in the top quartile is 3.2%. From the 

statistical process control point of view, these units appear to have low variability. 

The weighted average RSD of the bottom quartile is 6.9%, which is over twice that of the top 

quartile. This spread indicates that there is likely room for improvement in study population 

operation to reduce variability and heat rate. 

2.5.6.1 Heat rate variability and performance 

To examine the association between heat rate variability and heat rate performance this 

study examined the RSD for unit-year heat rates calculated from reported data. The study 

                                                            

19 This table excludes nine units where RSD exceeded 2.6 standard deviations from the mean. 

Comment [A38]: This Table (and others like it)

might be more clearly presented as a simple line

graph.  

EPA response: Thank you.
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population generation-weighted annual RSD ranges between 5% and 6% during the study period. 

Figure 2-5 below summarizes the results of regressing RSD of heat rate onto annual heat rate.20

The r-squared result is 57%. These results indicate that, other factors held equal, if an EGU 

reduces heat rate variability, generally heat rate performance will improve. 

Figure 2-5. Regression analysis of reported heat rate RSD onto annual heat rate 

2.5.7 Units with large heat rate changes 

Over one third of the study population (355 units) reported at least one year-to-year 

change in heat rate greater than +/- 8.5%.21 We consider this magnitude to be in the upper range 

of what would be expected due to changes in fuel rank, operations and maintenance, or plant 

equipment. Table 2-10 presents the counts by three categories: EGUs with at least one year-toyear decrease in heat rate > 8.5%; units with at least one year-to-year increase in heat rate > 

8.5%; and, units with both. We examined whether the large heat rate changes were due to a 

`year-to-year changes in capacity factor and found no correlation between the year-to-year 

changes in heat rate and capacity factor for any of the three groups in Table 2-10.22 This would 

indicate that other factors account for these large changes to heat rate. The EPA’s research found 

that approximately two-thirds of the large decreases in heat rate can be associated with changes 

                                                            

20 This table excludes nine units where RSD exceeded 2.6 standard deviations from the mean. 

dThe regression analysis was performed on 9,3488 unit-years of study data which were trimmed to remove values 

outside 2.6 standard deviations.

21 After removing unit-years where annual capacity factor fell under 50 percent the count is 313 EGUs. 22 The correlation remains weak even when limited to cases where capacity factor changed more than 30 percent. 

y = 0.002x - 14.254

R2 = 0.5704

5.0

5.2

5.4

5.6

5.8

6.0

6.2

9600 9650 9700 9750 9800 9850 9900 9950

RSD heat rate % 

(generation weighted)

Heat Rate
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in reporting method implemented to provide more accurate heat input data.23 The large changes 

noted at the remaining one-third could not be explained by changes in reporting methodology. 

Moreover, we found no correlation between changes in reporting method and heat rate RSD. 

Table 2-10. Year-to-Year Heat Rate Change 

Description Count 

Correlation of 

heat rate to 

capacity factor 

Units with only year-to-year heat rate decrease > 8.5% 166 .1 

Units with only year-to-year heat rate increase > 8.5% 80 .1 

Units with both year-to-year heat rate decrease and increase > 8.5% 355 .1 

The breakdown of the ‘large decrease’ EGUs by quartile, in Table 2-11 below, is consistent with 

the study population results shown in Table 2-8. This does not imply that the changes associated 

with a large year-to-year decrease, which may include operations and maintenance, more 

accurate reporting methods, or new equipment, do not affect heat rate variability. If they occur as 

part of an engineering effort to improve efficiency, heat rate variability may also be reduced. 

Table 2-11. RSD in reported heat rate of 166 ‘large 

decrease’ EGUs (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

1 4.0 2.3 4.8 

2 5.3 4.8 5.9 

3 6.6 5.9 7.5 

4 10.5 7.6 26.5 

2.5.8 Assessment of heat rate improvement potential via best practices 

As mentioned before, across the study period, the effects of hourly capacity factor and 

ambient temperature explain a generation-weighted average of 26% of the change in study 

                                                            

23 EPA Reference method 2 specifies the normal procedure for measuring stack gas volumetric flow rate during a 

relative accuracy test audit. Methods 2F, 2G, 2H and CTM-041 are approved alternatives. Methods 2F and 2G 

correct measured flow rates for angular (non-axial) flow, Method 2H (for circular stacks) and conditional test 

method CTM-041 (method J, for rectangular stacks and ducts) are used to correct measured flow rates for velocity 

decay near the stack wall, using a “wall effects adjustment factor”. These alternative methodologies are optional. 

Therefore, given the additional complexity and cost of using these alternatives a source is likely to use them only if 

the results are significantly lower volumetric stack gas flow. The EPA was unable to draw conclusions about the 

effect of changes in flow reporting methods on fleet heat rate performance.
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population heat rate.24 This means that on average 74% of the change remains unexplained after 

controlling for those factors. The residual heat rate analysis determined there is significant 

variation in the operation of EGUs. Since lower heat rate variability is associated with lower heat 

rate, other factors held equal, the range of variation indicates that significant potential for heat 

rate improvement is available through the application of best practices. 

To control for known factors, the EPA constructed a model that groups each EGU’s 

hourly heat rate data into 14 temperature bins and 12 capacity factor bins, resulting in a 12 by 14 

matrix of 168 bins.25 For a given EGU, a temperature and capacity factor bin will have all the 

relevant hourly values over the eleven-year study period. For each bin with 15 or more values the 

model finds the reported hourly heat input value corresponding to the 10th percentile (p10).26

This means that approximately 90% of the heat input values in that bin exceed p10. For each 

unit, the model reduces the reported hourly heat input greater than p10 by a percentage of the 

distance between the reported value and p10, (e.g., 50% of the difference). The same statistical 

procedure is applied to every hour of heat input data in each bin. These reduced hourly heat input 

values are then used to calculate a reduced 11-year average heat rate for each unit. The percent 

difference between a unit’s reported 11-year average heat rate and the heat rate that corresponds 

to reduced heat inputs is the potential heat rate improvement for that unit.27 Using this approach, 

those units with the lowest variability (e.g., in the top quartile of residual heat rate variability) 

take proportionally smaller reductions. 

Table 2-12 below shows the model results with options of 10% to 50% stringency. For 

example, reducing reported heat input 10 % of the distance to the p10 value achieves a 1.3% 

study population wide reduction. Alternatively, a 50% reduction will result in a 6.7% study 

population wide improvement in heat rate. In effect, the model proportionately reduces heat rate 

                                                            

24 The 26% result is the generation weighted average of r-squared values from the multivariate regression analysis. 25 The matrix provides up to 168 bins but only 164 contained hourly values. Temperature bins ranged from -20 to 

greater than 110 with 10 degrees F in each. Capacity factor bins ranged from 0% to greater than 110% with 10% in 

each. 

26 Performing the calculation with a minimum of 30 values in each bin has a modest effect on the results in Table 2-

12. For example, a 30% reduction obtains a 3.9% fleet wide improvement in heat rate (rather than 4.0%). 27 Heat rate is calculated as the sum of heat input (btuBtu, reported or reduced) divided by the sum of generation 

(kWh) for the given population and time period.  
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variability and improves performance for each unit while controlling for temperature and 

capacity factor. The heat rate improvement for the study population is derived from the 

performance of each individual EGU as compared to its own record. 

Table 2-12. Assessment of heat rate improvement potential via best practices 

% Reduction from 

reported heat input 

to p10 

Study population 

heat rate 

(Btu(kWh-gross)28

Reduced study 

population heat 

rate (Btu/kWhgross) 

Study population 

heat rate 

improvement (%)

10 

9,755 

9,625 1.3 

20 9,495 2.7 

30 9,365 4.0 

40 9,235 5.3 

50 9,105 6.7 

2.5.9 Assessment of potential heat rate improvement via equipment upgrades 

The EPA inspected the study population to find examples of EGUs that made significant 

year-to-year improvements in heat rate. After filtering out those cases that may have been the 

result of changes in capacity factor, reporting method, or other events, we identified 16 EGUs 

that reported a one or more single year-to-year heat rate improvements of 3-8%. In two of these 

cases we were able to identify equipment upgrades responsible for 2-3% heat rate improvement 

using the applicable estimates from the Sargent & Lundy 2009 study. Similarly, in the other 

cases, while our research was unable to confirm specific equipment upgrades, based on the 

elimination of other possible explanations we believe that equipment upgrades were the most 

likely cause of some of the observed heat rate improvements. 

Two other sources provide information about heat rate improvements after equipment 

upgrades at existing plants. EPA Region 7 provided data for seven coal-fired units at three 

anonymous plants with details on specific equipment modifications. These included turbine 

efficiency and condenser performance upgrades, installation of variable frequency drive fans, 

reducing boiler air in-leakage and others. Together, these measures achieved from 0.25% to 

3.5% heat rate improvement at the seven EGUs. 

                                                            

28 Fleet heat rate for entire study population as described in Table 2-4 is 9,75463; the 9,755 value is derived from the 

dataset that includes hourly temperature values.

Comment [A39]: This technical analysis of the

possibility for heat rate improvements should be

peer reviewed.  Has EPA run this by the SAB, or does

EPA intend to do so after release of the proposal?

EPA response: Thanks for your comment

Comment [A40]: Do you really mean in a single

year to year change, as an indicator of a functional

change in the equipment?  Otherwise, 8% annual

improvement year after year is immense.  

Suggested edit, but change at EPA’s discretion.

EPA response: We meant one time – thank you.

Comment [A41]: Is it possible to give any more

information about this or provide further support?  

EPA response: More information has been added.
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An EPA study (SRA, 2001) describes WEPCO’s two-phase efficiency program at four 

coal-fired plants over a ten-year period. In the first phase, 1990 – 1994, WEPCO installed 

equipment upgrades that included retractable turbine packing, variable speed drives on the forced 

and induced draft fans, feed water heater replacements and new performance monitoring 

instrumentation. The four units reported heat rate improvements ranging from 2.3% – 4.1% as a 

result of the equipment upgrades. In the second phase, 1995-2000, WEPCO implemented 

changes that would generally fall into the best practices category: equipment control and 

metering upgrades, boiler cleaning, feed water heater improvements and reduced condenser air 

in-leakage and thermal losses. These gained an additional 0.5% per year heat rate improvement 

(for a total of 2.5%). 

The EPA also reviewed the engineering studies available in the literature and selected the 

Sargent & Lundy 2009 study as the basis for our assessment of heat rate improvement potentials 

from equipment and system upgrades. We focused on some thirteen heat rate improvement 

methods discussed by Sargent & Lundy, seen in Table 2-13. We used the average of the 

estimated $/kW costs for each method to develop the cost-ranked list of heat rate improvement 

methods (lowest cost at the top, highest at the bottom) shown in Table 2-13. The first nine items 

in Table 2-13 contribute about 15 percent of the total average $/kW cost for all items. We believe 

it is reasonable to consider those nine no-cost and low-cost heat rate improvement methods as 

belonging in the category of what has been described above as best practices. The remaining four 

methods are higher cost heat rate improvement items that we believe properly fall into the 

category discussed here as upgrades. Using an average of the ranges of potential Btu 

improvements estimated by Sargent & Lundy for the four upgrade methods, upgrades, as defined 

here, could provide a 4% heat rate improvement if all were applied on an EGU that has not 

already made these upgrades. 

Table 2-13. Sargent & Lundy Heat Rate Improvement Methods 

No-Cost and Low-Cost Options 

Condenser Cleaning 

Intelligent Soot Blowers 

ESP Modification 

Boiler Feed Pump Rebuild 

Air Heater and Duct Leakage Control 
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Neural Network 

SCR System Modification 

FGD System Modification 

Cooling Tower Advanced Packing 

Higher Cost Options 

Economizer Replacement 

Acid Dew Point Control 

Combined VFD and Fan 

Turbine Overhaul 

We also examined the annual heat rate trend line for each unit developed using the 

method of least squares. Using the slope of the trend line, 2002-2012, as an indicator of the heat 

rate performance of an EGU, a negative slope would indicate that the heat rate has improved. 

The annual trend line incorporates performance due to operating conditions (capacity factor, 

temperature), coal rank, maintenance, reporting method changes, equipment upgrades, and other 

factors. Over 40% of units have a positive slope. This would imply that equipment maintenance 

and upgrades at a significant fraction of the study population have not been sufficient even to 

maintain the status quo. 

2.5.10 Combined study population results 

The EPA’s analysis finds that a total of 6% heat rate improvements for the coal study 

population can be achieved through two types of changes: best practices that have the potential 

to improve heat rate by 4% and equipment upgrades that have the potential to improve heat rate 

by 2%. 

The best practices results are supported by the variability analysis using 11 years of 

hourly data applied to each unit. This analysis found that the top quartile of EGUs reported 

significantly lower heat rate variability than the study population average. Reducing heat rate 

variability will generally also improve heat rate performance, other factors held equal. We found 

that a 4% improvement is determined by conservatively reducing heat input by 30% of the 

difference between the reported value and p10 in each unit’s capacity factor and ambient 

temperature bins. The 30% approach is in the middle of the range of options shown in Table 2-12 

and is comparable to other approaches for measuring potential fleet heat rate improvement. For 

example, if each unit achieved heat rate performance equal to its best three-year moving average, 
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the study population as a whole would post a 3.9% heat rate improvement. The best two-year 

moving average would achieve nearly a 5% improvement and the best single year over 6%. EPA 

believes that the minimum three-year moving average heat rate is a reasonable target for the 

improvement potential from applying best practices. Single year results could be due to unusual 

conditions, such as, an extended outage or weather. Using three consecutive years tends to 

smooth out the effect of equipment maintenance cycles and unusual meteorological patterns. 

The equipment upgrades results are supported by numerous studies29 and by the EPA’s 

analysis of the costs and associated improvements in heat rate that can be attributed to equipment 

and system upgrades. We considered that a 4% reduction in heat rate might be achieved on a 

coal-steam unit by applying the four higher cost upgrade actions described in Table 2-13 above. 

However, because details of current actual unit configurations are unknown, and some units may 

have applied at least some of the upgrades, we conservatively estimate the heat rate improvement 

potential for upgrades at 2%. The EPA considers the results of this study to be applicable to the 

U.S. coal-fired fleet at large since the study population of EGUs accounted for over 96% of 2012 

electric sector CO2 emissions from coal. 

2.5.11 Sensitivity Analysis Removing Planned or Announced EGU Retirements 

The EPA’s research found 2330 coal-fired, non-cogeneration230 EGUs that have 

announced they will retire before 2016.30 A sensitivity analysis was applied to the EGUs in the 

study population that plan to operate through 2015. The results are identical to the full population 

– both achieve a heat rate reduction of 4% under the 30 percent difference option described in 

best practices. 

2.6 Heat Rate Improvement – Economics 

Most of the methods that can be applied to achieve a sustained Heat Rate Improvement 

(HRI) on a coal-steam EGU will entail a capital cost. These HRI capital costs can be economic to 

incur if they yield sufficient reductions in other current or potential costs, particularly reductions 

                                                            

29 See discussion in Table 2-3 above, and the HRI Partial Bibliography at the end of this section 

30The EPA research was derived from Ventyx Velocity Suite New Entrants database (proprietary) and other 

sources, IPM documentation includes a list of the announced retirements. See Table 4-36 of IPM Documentation: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/Chapter_4.pdf and 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/NEEDS_v513.xlsx

Comment [A42]: This is an important statement,

that is accorded little explanation.  I presume these

are coal EGUs? And is it plants or separate units?  

How did these anticipated requirements factor into

the state goal setting, and then into the IPM

modeling?   

EPA response: See updated footnote with IPM

source.
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in coal fuel cost and any cost related to CO2 emissions. For the purpose of this TSD analysis, it is 

assumed that HRI can be economic if the annualized net savings (coal cost savings plus CO2

emission cost savings minus capital cost) is positive: 

Annual Net HRI Savings = Coal Cost Savings + CO2 Emission Cost Savings – Capital Cost31

2.6.1 Heat Rate Improvement Capital Cost Assumption 

The 2009 Sargent & Lundy study describes numerous well known and technically proven 

HRI methods for coal-steam EGUs. The study includes an estimated min-max range of heat rate 

improvement, and the min-max range of associated capital cost for each HRI method, for units 

ranging in size from 200 MW to 900 MW. If these methods and unit sizes are combined, as 

though they were all applied on a single EGU, the following range of Sargent & Lundy estimated 

Btu reductions and associated range of capital costs are obtained: 

Combined Min-Max HRI Btu Reduction: 415-1205 Btu 

Combined Min-Max HRI Capital Cost: $40-150/kW32

EPA Assumed Combined HRI Capital Cost: $100/kW 

The wide ranges of estimated HRI Btu and costs are indicative of the wide range of real 

differences in the many details of site specific EGU designs, fuel types, age, size, ambient 

conditions, current physical condition, etc. This TSD analysis therefore assumes $100/kW as a 

representative combined HRI capital cost to achieve whatever HRI Btu reduction is possible at 

an average site. The effect of a lower HRI cost is also examined. 

2.6.2 Heat Rate Reduction Assumption 

The weighted average annual net heat rate of the U.S. coal-steam EGU fleet in 2020 is 

projected at 10,450 Btu/kWh in the EPA’s IPMv5.13 Base Case modeling. As indicated by the 

Sargent & Lundy estimates given above, HRI methods could possibly reduce this average coal 

                                                            

31 This TSD analysis assesses a broadly combined application of multiple HRI methods. As estimated in the 2009 

Sargent & Lundy study most HRI-related O&M costs are sufficiently small relative to the associated annualized 

capital costs, such that they do not materially affect the economics of broadly combined HRI methods. The analysis 

therefore does not consider the small economic impact of HRI-related O&M costs. 32 Note that highest cost does not necessarily align with greatest heat rate improvement. A low cost HRI method

can have a large HRI potential (e.g.,: upgraded digital control system, neural network). Also, economy of scale

causes most HRI methods to be more costly ($/kW) on smaller unit sizes.
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fleet heat rate by about 400 to 1200 Btu/kWh, or by about 4% to 12% of the projected 2020 

average, provided that all units were able to apply all of the combined HRI methods. The proviso 

is important to this analysis because the EPA expects that a significant fraction of the coal fleet 

has already applied some or many of the available HRI methods.33 

The EPA does not have sufficient site specific information to accurately estimate what 

percentage of the fleet has adopted various HRI methods, nor how effectively, and is not aware 

of any other investigator having sufficient information. HRI potential can therefore not be 

estimated at this time through analysis of the current equipment configurations of the coal steamEGU fleet. The EPA therefore analyzed 11 years of historical heat rate data and the literature on 

HRI methods, as discussed earlier in this TSD, to estimate that the U.S. coal-steam EGU fleet 

might reasonably be expected to reduce its annual average gross heat rate by about 6%. 

The EPA understands that any HRI method that reduces gross heat rate will also reduce 

net heat rate, and that some HRI methods reduce net heat rate without reducing gross heat rate. 

We expect that the HRI potential on a net output basis is somewhat greater than on a gross output 

basis, primarily through upgrades that result in reductions in auxiliary loads. For purposes of this 

TSD the EPA conservatively assumes that the coal fleet average net heat rate can be reduced by 

6%. 

2.6.3 Heat Rate Improvement Breakeven Economic Analysis 

Figure 2-6 presents a simple breakeven economic analysis for combined HRI methods 

using the assumptions described above, also assuming there is no CO2 emission cost that is 

reduced via HRI. 

                                                            

33 Based on the EPA informal discussions with Sargent & Lundy and other power sector engineering firms. The 

EPA has found no comprehensive data set on the extent to which specific HRI methods have already been applied at 

individual EGUs. The EPA believes that many EGU owners consider such information to be confidential. 
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Figure 2-6. HRI Breakeven Economics 

Notes: 

1. Capital cost S/MWh assumes the following: HRI capital cost = $100/kW; capital charge rate 

= 14.3%; IPM projected 2020 annual capacity factor = 78% 

2. Coal fleet average 2020 net heat rate = 10,450 Btu/kWh; heat rate reduction = 6% 

Figure 2-6 shows that the average fleet-wide savings in coal cost would become greater 

than the annualized capital cost of an average 6% reduction in heat rate when the average fleetwide coal cost exceeds about $3.25/MMBtu. For comparison, the average U.S. power sector 

delivered cost of coal in 2020 is projected in EPA’s IPMv5.13 Base Case modeling at 

$2.62/MMBtu. For different assumptions, the HRI economic breakeven point would change 

directionally as follows: 

 If the HRI capital cost were on average less than the assumed $100/kW, 6% HRI would 

then become economic at lower coal costs. For example, if the average capital cost were 

actually $75/kW, a fleet-wide 6% HRI would become economic at an average coal cost 

of about $2.50/MMBtu, which is comparable to the U.S. power sector average costs of 

$2.38/MMBtu for all coal ranks and $2.89/MMBtu for bituminous coals in 2012.34 This 

                                                            

34 EIA, Electricity DataTable 7.4, Average Weighted Cost of Fossil Fuels for the Electric Power Industry 2002-

2012, http://www.eia.gov/electricity/annual/html/epa_07_04.html 

0.00

0.50

1.00

1.50

2.00

2.50

3.00

1.00 2.00 3.00 4.00

$/MWh‐net

Coal Cost  $/MMBtu

Coal Cost Savings   $/MWh‐net Capital Cost  $/MWh‐net

HRI Capital Cost = $100/kW
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sensitivity indicates that fuel cost savings alone would make it economic for some of 

those EGUs currently using high cost bituminous coals to make HRI investments. 

 At an EGU net heat rate that is higher than the IPM projected 2020 average value of 

10,450 Btu/kWh, 6% HRI could be economic at coal costs lower than the values 

mentioned above. 

 If the average heat rate reduction were only 4% instead of the assumed 6%, at a cost of 

$100/kW, average coal costs would have to exceed $4/MMBtu for 4% HRI to be 

economic fleet wide, 

 But, if the average heat rate reduction were 4% at a cost of $50/kW, HRI could become 

economic at an average coal cost of about $2.50/MMBtu. 

 If there were additional HRI savings due to avoided future CO2 emission costs, HRI 

could become economic at lower coal costs, or at higher capital costs, or at lower heat 

rate reduction percentages. 

2.6.4 Estimated Fleet-wide U.S. Coal-steam EGUs – Estimated Fleet-wide EGU CO2

Reduction and Cost via HRI 

It is possible to make an order-of-magnitude estimate of the fleet-wide extent and costeffectiveness of HRI using reasonable assumptions as in the following example: 

Fleet-wide 2020 Assumptions (basis: similar to IPMv5.13 Base Case): 

 Coal fleet capacity applying combined HRI methods = 244,000 MW 

 Average CO2 emission rate = 0.976 tonne/MWh net 

 Average net heat rate = 10,450 Btu/kWh net 

 Average capacity factor = 78% 

 Pre-HRI CO2 emissions = 1.62 billion tonne/yr (calculated) 

 HRI Btu and CO2 reduction = 6% 

 HRI capital cost = $100/kW 

 Annual capital charge rate = 14.3% 

 Average coal cost = $2.62/MMBtu 

Estimated Fleet-wide Results: 

Comment [A43]: Throughout the paper, it might

help to indicate the “fleet‐ wide” data refer to the

national fleet (i.e. all the coal facilities in the U.S.) if

this is the case.

  

EPA response: Thank you for the suggestion.  See

new section heading above.

Comment [A44]: It was ostensibly 44% in 2012 –

see Table 2‐5, page 19 above – or am I missing

something?  Please clarify.  Is this assuming a lot of

coal plant closures to get the capacity factor up?  If

so, please clarify the discrepancy/change over time

in the text and how this might affect state goal

setting,  especially building block 2?

EPA response: Good catch. See revised Table 2‐5

and associated text.  Also see the RIA and other TSD

discussions regarding IPM Base Case assumptions,

resulting 2020 coal capacity, etc.
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 Fleet-wide CO2 reduction via HRI = 97 million tonne/yr 

 Total HRI capital cost = $24 billion 

 Annualized HRI capital cost = $3.5 billion 

 Annual coal cost savings (cost) = $2.7 billion 

 Annual net savings (cost) = ($0.8 billion) 

 Annual net savings (cost) of CO2 reduction = ($7.7/tonne) 

2.6.5 Conclusion - HRI Economics 

This necessarily simplified HRI economic analysis supports the following summary conclusions: 

 Some degree of HRI is already economic for high heat rate – high coal cost EGUs 

 If a fleet-wide average 6% HRI is technically feasible, it would also be economic on the 

basis of fuel savings alone, before consideration of the value of the associated CO2

emission reductions, on a fleet-wide basis at today’s coal prices if the associated average 

capital cost is about $75/kW or less. 

 If a fleet-wide average 6% HRI is technically feasible, and the associated average capital 

cost is as much as $100/kW, 6% HRI could become economic on the basis of fuel 

savings alone, before consideration of the value of the associated CO2 emission 

reductions, if/when average coal prices rise to about $3.25/MMBtu (IPM projects coal at 

$2.62/MMBtu in 2020). 

 Even at a capital cost of $100/kW and an IPM projected 2020 coal price of 

$2.62/MMBtu, the fleet-wide cost of CO2 reduction via 6% HRI would be a relatively 

low $7.7/tonne. 

Thus, although there is currently some uncertainty associated with the costs of achieving a 

particular fleet-wide amount of HRI, it is clear that HRI is an available low-cost approach to CO2

reduction for existing coal-fired EGUs 

Definitions/Abbreviations

Btu British thermal unit 

capacity factor 

electricity generation expressed as a percentage of maximum 

electricity generation (i.e., actual generation / maximum potential 

generation) 

CO2 carbon dioxide 

EGU electric generating unit 

EIA Energy Information Administration 
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EPA Environmental Protection Agency 

heat input amount of energy consumed in a combustion unit (e.g., boiler) 

expressed in Btu 

heat rate improvement decrease in the amount of heat input required to generate 1 kWh of 

electricity 

heat rate gross heat input required to generate 1 kWh of electricity, expressed 

in gross Btu/kWh. 

MMBtu million Btu 

MW megawatt 

PC pulverized coal (boiler) 

RSD Relative standard deviation 

S & L report 

Sargent & Lundy engineering study on the potential heat rate 

improvement from equipment upgrades (EPA 2009 version) 

[Available at: 

http://www.epa.gov/airmarket/resource/docs/coalfired.pdf] 

start 

a startup event in which an EGU begins combusting fossil fuel and 

generates some measurable amount of electricity before ceasing fossil 

fuel combustion 

unit-year data for one EGU over a one year period 

Docket Datasets 

Name Description 

hour_QA_data.txt 2002-2012 hourly dataset 

hour_QA_regression_data.txt 2002-2012 hourly dataset for regression analysis 

units_885.txt List of study units and characteristics 

year_bin_10_50_data.txt 2002-2012 unit-year binned results at 10 – 50% difference 

options 
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HRI Partial Bibliography 

PowerEng 2002, “Heat Rate Optimization Pays Dividends,” Power Engineering, January 1, 

2002, available at http://www.power-eng.com/articles/print/volume-106/issue-1/features/heatrate-optimization-pays-dividends.html

NETL 2008, Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired 

Power Plant Fleet, DOE/NETL-2008/1329, July 2008 

NETL 2009, Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants, 

Workshop Report, NETL July 2009, available at http://www.netl.doe.gov/energyanalyses/pubs/NETL%20Power%20Plant%20Efficiency%20Workshop%20Report%20Final.pdf

NETL 2010, Improving the Thermal Efficiency of Coal-Fired Power Plants in the United States, 

DOE/NETL Technical Workshop Report, February 2010, available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEf

ficCoalFiredPowerPlants-TechWorkshopRpt.pdf

NETL 2010a, Improving the Efficiency of Coal-Fired Power Plants for Near Term GHG 

Emissions Reductions, DOE/NETL-2010/1411, April 2010, available at 

http://www.alrc.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=307

Sargent & Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, 

January 2009, available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf

Storm 2009, “Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal 

Fueled Boilers, Storm Technologies, Inc, EPRI 2009 Heat Rate Conference, available at 

http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf

NRDC 2013, Closing the Power Plant Carbon Pollution Loophole, NRDC Report R:12-11-A, 

March 2013 available at http://www.nrdc.org/air/pollution-standards/files/pollution-standardsreport.pdf

Lehigh 2009, Reducing Heat Rates Of Coal-Fired Power Plants, Lehigh Energy Update, January 

2009, available at http://www.lehigh.edu/~inenr/leu/leu_61.pdf

ESC/OnLocation, Efficient Heat Rate Benchmarks for Coal-Fired Generating Units, draft, B. 

Roberts, Economic Sciences Corporation, L Goudarzi, OnLocation, Inc., 1998, available at 

http://www.onlocationinc.com/heatratepaper.pdf

CRS 2013, Increasing the Efficiency of Existing Coal-Fired Power Plants, Congressional 

Research Service, December 2013, available at http://www.fas.org/sgp/crs/misc/R43343.pdf

Evonik/VGB 2008, “Power Plant Performance Reporting and Improvement under the Provision 

of the Indian Energy Conservation Act – Output 1.1”, Evonik/VGB 2008, available at 

http://www.emt-india.net/PowerPlantComponent/Output1.1/Output1.1.pdf

IEA 2010, Power Generation from Coal - Measuring and Reporting Efficiency Performance and 

CO2 Emissions, OECD/IEA-CIAB 2010, available at 

http://www.iea.org/ciab/papers/power_generation_from_coal.pdf

EPRI 2009, Renewed Interest in Reducing Heat Rate, EPRI Journal, Spring 2009, available at 

http://mydocs.epri.com/docs/CorporateDocuments/EPRI_Journal/2009-

Spring/1019287_Heat%20Rate.pdf
DRAFT May 15, 2014 

INTERAGENCY WORKING COMMENTS ON DRAFT LANGUAGE UNDER EO12866

INTERAGENCY REVIEW. SUBJECT TO FURTHER POLICY REVIEW.

45 

EPRI/Korellis 2011, Identifying Ways to Improve Plant Heat Rate, Energy-Tech Magazine, 

March 2011, available at http://www.energy-tech.com/article.cfm?id=30528

EPRI 2011a , Opportunities to Enhance Electric Energy Efficiency in the Production and 

Delivery of Electricity, EPRI Technical Report 1024651, November 2011, available at 

http://www.google.com/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=1&ved=0CCsQF

jAA&url=http%3A%2F%2Fwww.pserc.wisc.edu%2Fdocuments%2Fpublications%2Fspecial_in

terest_publications%2FEPRI_Electricity_Use_Report_Final_1024651.pdf&ei=Qo9yUvmwMY

Xb4AOZz4GYAw&usg=AFQjCNElzekbtoSNCR5SKFwkfbKx83p0Uw&bvm=bv.55819444,d.

dmg

RFF 2013, Regulating Greenhouse Gases from Coal Power Plants under the Clean Air Act, RFF 

DP 13-05, February 2013, available at http://www.rff.org/RFF/documents/RFF-DP-13-05.pdf
DRAFT May 15, 2014 

Draft Deliberative 

Chapter 2: Heat Rate Improvement at Existing Coal-fired EGUs 

2.0 Introduction 

Based on the range of operating efficiencies for existing coal-fired electric generating 

units (EGUs), it is evident that EGUs are generally less efficient at converting fuel into 

electricity than is technically and economically possible. For example, the difference in operating 

efficiency of EGUs with similar design characteristics and the year to year variability in 

individual EGU efficiency indicates that there is potential for broadly applicable efficiency 

improvements through cost-effective operational and maintenance practices. These improved 

efficiencies would result in corresponding reductions in greenhouse gas emissions. 

This chapter presents an overview of existing coal-fired EGUs, design factors that 

influence efficiency, technologies to improve efficiency, previous studies estimating potential 

efficiency improvements, the proposed EPA approach to calculate efficiency improvements, and 

the estimated capital costs of those improvements. 

2.1 Overview of U.S. Existing Coal-Fired Electric Generating Units 

Coal in the United States is predominately used for electric power generation. Most coalfired EGUs in the United States burn either bituminous or subbituminous coals. The largest 

sources of bituminous coals burned in coal-fired EGUs are mines in regions along the 

Appalachian Mountains and in southern Illinois, western Kentucky and Indiana. Additional 

bituminous coals are supplied from mines in Utah and Colorado. The vast majority of 

subbituminous coals are supplied from mines in Wyoming and Montana, with many coal-fired 

EGUs burning subbituminous coals from the Powder River Basin (PRB) region in Wyoming. In 

general, the burning of lignite by U.S. electric utilities is limited to coal-fired EGUs that are 

located near the mines that supply the lignite in Texas, Louisiana, Mississippi, Montana, and 

North Dakota. At a few power plant locations in the Eastern United States, recovered anthracite 

coal or coal refuse is burned in limited quantities. 

Existing coal-fired EGUs in the U.S. electric utility fleet use one of five basic coal 

combustion configurations: (1) pulverized coal (PC) combustion, (2) fluidized-bed combustion 

(FBC), (3) gasified coal combustion, (4) cyclone furnace combustion, or (5) stoker-fired coal 

combustion. Table 2-1 presents a summary of the operating characteristics of each of these coal 

combustion configurations. 

Comment [A1]: This section read quite weakly as

initially written.   

EPA response: Thank you for the edit.

Comment [A2]: MATS Compliance.  MATS

compliance will lead to significant installations of

pollution control equipment (PCE) over the 2013 to

2016 period on capacity that owners intend to keep

in service beyond the MATS compliance deadline

but would not be MATS‐compliant without

augmenting the PCE that was in place during 2012.  

The PCE systems likely to be installed on such units

include FGD systems that may consume significant

power and therefore, all else equal, increase energy

input per net kilowatt‐hour of generation.  It would

be helpful to understand if or how additions of PCE

for MATS compliance are reflected in the analysis of

HRI in the draft TSD.

EPA response: The results of our statistical analysis

(described later) are based on gross heat rates and

will not change with installation of MATS controls,

which will add additional parasitic load

requirements and thereby have an impact on the

net heat rates. However, in this TSD chapter, we

explain that EPA conservatively considers fleet‐wide

net heat rate improvement potential to be the same

as that indicated for the fleet‐wide gross heat rate.

And based on this consideration, IPM modeling and

state goals calculations used 6% improvement on a

net heat rate basis. So we also need to speak to the

fleet‐wide net heat rate. That being said, MATS

controls are expected to lead to a small increase in

auxiliary power use and therefore will not have a

significant effect on the fleet‐wide net heat rate.

Here is what we projected (using IPM) for the final

MATS policy case.

Technology                       Capacity         Parasitic Load

New wet FGD                    0 GW               1.5‐2%

New SCR                             0 GW               0.5%       

New dry FGD (SDA)          22 GW              1‐1.5%

New DSI                             43 GW              0.5%  

                                                          (assumed same as

ACI + FF)

New ACI                             141 GW            0.5%

New FF                               102 GW             0.5%

Upgrade of existing ESP            34 GW                   

Upgrade of existing wet FGD   63 GW                   

So MATS requirements would increase parasitic load

from 0% (for a unit that can meet the standards

with existing equipment) up to 2 % for units that

install a SDA and implement ACI + FF   [Note: a unit

would implement either SDA or DSI but not both].

In any case, EPA’s IPM v 5.13 Base Case modelling

for this proposal assumes that MATS is in effect and

that such controls as are needed for compliance are

added before 111(d) policy options are evaluated in

policy runs.  
DRAFT May 15, 2014 

2 

Table 2-1. Characteristics of coal-firing configurations used for U.S. EGUs 

Coal-firing 

Configuration 

Coal Combustion Process 

Description Distinctive Design/Operating Characteristics 

Pulverized 

Coal (PC) 

Combustion 

Coal is ground to a fine powder that 

is pneumatically fed to a burner 

where it is mixed with combustion 

air and then blown into the furnace. 

The pulverized-coal particles burn in 

suspension in the furnace. Unburned 

and partially burned coal particles 

are carried off with the flue gas. 

Wall-fired 

An array of burners fire into the 

furnace horizontally, and can be 

positioned on one wall or opposing 

walls depending on furnace design. 

Tangential-fired 

(Corner-fired) 

Multiple burners are positioned in 

opposite corners of the furnace 

producing a fireball that moves in a 

cyclonic motion and expands to fill 

the furnace. 

Fluidized-bed 

Combustion 

(FBC) 

Coal is crushed into fine particles. 

The coal particles are suspended in a 

fluidized bed by upward-blowing jets 

of air creating a turbulent mixing of 

combustion air with the coal 

particles. Typically, the coal is mixed 

with a sorbent such as limestone (for 

SO2 emission control). FBC have a 

greater fuel flexibility than PC EGUs 

and can be designed for combustion 

within the bed to occur at 

atmospheric or elevated pressures. 

FBC operating temperatures are in 

the range of 1,500 to 1,650F (800 to 

900o

C). 

Bubbling 

fluidized bed 

(BFB) 

Operates at relatively low gas stream 

velocities and with coarse-bed size 

particles. Air in excess of that 

required to fluidize the bed passes 

through the bed in form of bubbles. 

Circulating 

fluidized bed 

(CFB) 

Operates at higher gas stream 

velocities and with finer-bed size 

particles. No defined bed surface. 

Must use high-volume, hot cyclone 

separators to recirculate entrained 

solid particles in flue gas to maintain 

the bed and achieve high combustion 

efficiency. 

Integrated Coal 

Gasification 

Combined 

Cycle (IGCC) 

Synthetic combustible gas (“syngas”) 

derived from an on-site coal 

gasification process is burned in a 

combustion turbine. The hot exhaust 

gases from the combustion turbine 

pass through a heat recovery steam 

generator to produce steam for 

driving a steam turbine/generator 

unit. 

Coal gasification units are unique among coal-firing 

configurations because a gaseous fuel (synfuel or syngas) 

is burned instead of solid coal because the combustion 

and power generation process and combines the Rankine 

and Brayton thermodynamic cycles as is the case for a 

combined cycle power plant. 

Cyclone 

Furnace 

Combustion 

Coal is crushed into small pieces and 

fed through a burner into the cyclone 

furnace. A portion of the combustion 

air enters the burner tangentially 

creating a whirling motion to the 

incoming coal. 

Designed to burn coals with low-ash fusion temperatures 

that are difficult to burn in PC boilers. The majority of 

the ash is retained in the form of a molten slag. 

Stoker-fired 

Coal 

Combustion 

Coal is crushed into large lumps and 

burned in a fuel bed on a moving, 

vibrating, or stationary grate. Coal is 

fed to the grate by a mechanical 

device called a “stoker.” 

One of three types of stoker mechanisms can be used that 

ether feed the coal by pushing, dropping, or flipping coal 

unto the grate. 

The three technologies currently used for new coal-fired power plants are pulverized 

coal, fluidized bed (FBC), and integrated coal gasification combined cycle (IGCC). Pulverized 

coal combustion is the coal-firing configuration predominately used at existing EGUs. The most 

Comment [A3]: We would suggest reducing the

amount of text in tables (perhaps as bullet points).

EPA response: Thank you for the observation.

Comment [A4]: It might be helpful to indicate

the typical size (MW) and capital cost ($/installed

MW) here.  

EPA response: Thank you for the observation, but it 

is unclear how the suggested edit would relate to the 

analysis.

Comment [A5]: No one is building coal plants

currently in the U.S., so the future tense is not

appropriate.  Who is building coal plants using FBC?  

China?  If so, we should specify, or else delete.

EPA response: The text has been deleted.
DRAFT May 15, 2014 

3 

recent coal technology combustion development involves the integration of coal gasification 

technologies with the combined cycle electric generation process. The efficiency of an IGCC 

power plant is comparable to the latest advanced PC-fired and FBC EGU designs using 

supercritical steam cycles. The advantages of using IGCC technology can include greater fuel 

flexibility (e.g., capability to use a wider variety of coal ranks), potential improved control of 

PM, SO2 emissions, and other air pollutants, the need for fewer post-combustion control devices 

(e.g., almost all of the sulfur and ash in the coal can be removed once the fuel is gasified and 

prior to combustion), generation of less solid waste, reduced water consumption, and the 

chemical process that creates a concentrated CO2 stream that is more amenable to carbon capture 

processes. 

Older combustion technologies, namely cyclone furnaces and stoker-fired coal 

combustion, have been replaced at new coal-fired EGUs by more efficient methods that provide 

superior coal combustion efficiency and other advantages. However, a few remaining old stokerfired EGUs and cyclone furnaces still remain in service for a small number of existing EGUs in 

the U.S. electric utility market. 

2.2 Influence of Heat Rate on Coal-Fired EGU CO2 Emission Rate 

Heat rate is a common way to measure EGU efficiency. As the efficiency of a coal-fired 

EGU is increased, less coal is burned per kilowatt-hour (kWh) generated by the EGU resulting in 

a corresponding decrease in CO2 and other air emissions. Heat rate is expressed as the number of 

British thermal units (Btu) or kilojoules (kJ) required to generate a kilowatt-hour (kWh) of 

electricity. Lower heat rates are associated with more efficient coal-fired EGUs. 

The electric energy output for an EGU can be expressed as either as “gross output” or 

“net output.” The gross output of an EGU is the total amount of electricity generated at the 

generator terminal. The net output of an EGU is the gross output minus the total amount of 

auxiliary (or parasitic) electricity used to operate the EGU (e.g., electricity to power fuel 

handling equipment, pumps, fans, pollution control equipment, and other on-site electricity 

needs), and thus is a measure of the electricity delivered to the transmission grid for distribution 

and sale to customers. Some EGUs also produce part of their useful output in the form of useful 

thermal output (e.g., steam for heating purposes). These types of facilities are called combined 

heat and power, or CHP, facilities. 

Comment [A6]: One of the primary benefits of

IGCC is the concentrated CO2 stream and ability to

use in CCS.  Needs to be highlighted.

EPA response: Thank you for the observation and

the suggested text, which has been included.
DRAFT May 15, 2014 

4 

A variety of factors must be considered when comparing the effectiveness of heat rate 

improvement technologies to increase the efficiency of a given coal-fired EGU. The actual 

overall efficiency that a given coal-fired EGU achieves is determined by the interaction of a 

combination of site-specific factors that impact efficiency to varying degrees. Examples of the 

factors affecting EGU efficiency at a given facility include: 

 EGU thermodynamic cycle – EGU efficiency can be significant improved by using a 

supercritical or ultra-supercritical steam cycle. Supercritical and ultra-supercritical boilers 

operate above the critical point of water (approximately 374°C (705°F) and 22.1 MPa 

(3,210 psia)). As a general guideline, the thermal design efficiencies for subcritical EGUs 

are in the range of 35% to 37%, supercritical EGUs are in the range of 39% to 40%, and 

ultra-supercritical EGUs in the range of 42% to 45%. However, actual operating 

efficiencies are lower than design efficiencies. 

 EGU coal rank and quality – EGUs burning higher quality coals (e.g., bituminous) tend 

to be more efficient than EGUs burning lower quality coals with a greater moisture 

content (e.g., lignite). Bituminous coals have higher heating values of greater than 10,500 

British thermal units per pound and lignite coals have higher heating values of less than 

8,300 British thermal units per pound. 

 EGU size –EGU efficiency generally increases somewhat with unit size (e.g., from 200 

MW to 800 MW) because: a) the boiler and steam turbine losses are lower for larger 

equipment compared to smaller equipment, b) larger units tend to be younger 

incorporating improvements from advanced technologies, and c) the economy of scale of 

larger units allows the use of higher cost improvements to be more economic. 

 EGU pollution control systems – The electric power consumed by air pollution control 

equipment reduces the overall efficiency of the EGU.

 EGU operating and maintenance practices – The specific practices used by an individual 

electric utility company for combustion optimization, equipment maintenance, etc. can 

affect EGU efficiency. 

 EGU cooling system – The temperature of the cooling water entering the condenser can 

have impacts on steam turbine performance. Once-through cooling systems can have an 

efficiency advantage over recirculating cooling systems (e.g., cooling towers). However, 

Comment [A7]: Could indicate the approximate

range (BTUs / lb) of the different coal types, as well

as the influence of moisture.

EPA response: The ranges have been added.

Comment [A8]: : Could indicate approximate

turbine size / size class here.  

EPA response: Edits made to address the comment.
DRAFT May 15, 2014 

5 

once-though cooling systems typically have larger water related ecological concerns than 

recirculating cooling systems. 

 EGU geographic location and ambient conditions – The elevation and seasonal ambient 

temperatures at the facility site potentially may have an impact on EGU efficiency. At 

higher elevations, air pressure is lower and less oxygen is available for combustion per 

unit volume of ambient air than at lower elevations. Cooler ambient temperatures 

theoretically could increase the overall EGU efficiency by increasing the draft pressure of 

the boiler flue gases and the condenser vacuum, and by increasing the efficiency of the 

cooling system. Also, geographic location influences the type of cooling system that can 

be used (e.g., EGUs located in arid locations often cannot use once through cooling) 

 EGU load generation flexibility requirements – Operating an EGU as a baseload unit is 

more efficient than operating an EGU as a load following unit to respond to fluctuations 

in customer electricity demand. 

 EGU plant components – EGUs using the optimum number of feedwater heaters, highefficiency electric motors, variable speed drives, better materials for heat exchangers, etc. 

tend to be more efficient. 

2.3 Technologies to Improve Existing Coal-Fired EGU Heat Rate 

A number of studies have been conducted involving literature reviews of published 

articles and technical papers identifying potential efficiency improvement techniques applicable 

to existing coal-fired EGUs.1

 For example, a summary of the findings from one study conducted 

by the Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) is 

presented in Table 2-2. The efficiency percentages were converted to a common basis so that all 

of the data can be compared. All of the improvement technologies presented in Table 2-2 cannot 

necessarily be implemented at every existing coal-fired EGU facility in the U.S. electric utility 

fleet. The existing EGU design configuration and other site-specific factors may prevent the 

technical feasibility of using a given technology. 

Typically, these studies share as a common basis the estimated potential efficiency 

improvement percentages and costs from the engineering study originally completed by Sargent 

                                                            

1

 See HRI Partial Bibliography at the end of this chapter. 

Comment [A9]: Geographic location could also

influence cooling water issues, mentioned earlier

(i.e. coal plants in the arid west).

EPA response: Text has been added to address the

comment.  

Comment [A10]: Suggest using “load following”

for clarity

EPA response: Done.
DRAFT May 15, 2014 

6 

and Lundy in 2009 titled “Coal-Fired Power Plant Heat Rate Reductions.” It describes numerous 

well known and technically proven methods to improve efficiency of coal-fired EGUs. The study 

lists possible efficiency improvements in the boiler, turbine, flue gas system, air pollution control 

equipment and the water treatment system. Each of these main areas are expanded upon below. 

2.3.1 Boiler 

The systems to focus on for improving heat input within the boiler area include the 

materials handling, combustion system, boiler control system, sootblowers and the air heaters. 

2.3.1.1 Materials Handling2

The coal handling portion of materials handling typically requires about 0.07% (7 

Btu/kWh) of the gross electrical output of a power plant. Depending on the state of the motors 

and drives, replacing them with energy-efficient motors and variable frequency drives can 

reduce the auxiliary power requirements. The variable frequency drives also limit the stress and 

strain on the other equipment. 

Coal pulverizers typically require about 0.6% (60 Btu/kWh) of the gross electrical output 

and can be upgraded to provide more consistent size and finer coal particles. The fine particles 

improve combustion efficiency, consequently reducing fuel cost and heat rate. The costs for 

changes to the pulverizer system are significant, and historically, the projects have improved the 

heat rate justifiably only when the existing equipment has degraded. 

The bottom ash handling system may be a source for heat rate improvement. Switching 

from a water-sluicing bottom ash system to a dry drag chain system can reduce the auxiliary 

requirements and reduce the amount of water to the water treatment plant. The typical power 

requirements are about 0.1% (10 Btu/kWh) of the plant’s gross output. 

2.3.1.2 Economizer 

An economizer is a heat exchanger that improves the efficiency of an EGU by recovering 

energy from the exhaust gases to preheat the boiler feedwater. The replacement of the 

economizer can lead substantial heat rate improvements around 50-100 Btu/kWh, but is large 

capital investment (~$2-8M). Due to this high cost, economizers upgrades are not generally 

                                                            

2 The Sargent and Lundy report did not provide potential savings for material handling operations. Energy use in 

Btu/kWh has been provided to compare the energy use of materials handling relative to the potential energy savings 

from other efficiency activities.

Comment [A11]: Did you want to include an

estimate of pulverizer electric demand?

EPA response: An approximate electric demand has

been added.

Comment [A12]: For this part of the discussion,

some efficiency gains are given in percent, and

others in Btu/kWh. It would be helpful to keep

either one common unit (suggest Btu/kWh) or

provide both metrics.

EPA response: See footnote.  

Comment [A13]: Please add a sentence on what

an economizer is and does.

EPA response:  Added an introductory sentence.
DRAFT May 15, 2014 

7 

performed unless the existing equipment has degraded or a replacement is necessary due to the 

installation of new control equipment. 

2.3.1.3 Boiler Control System 

The boiler control system has a large impact on the heat rate of the unit. The process 

control capabilities can control and evaluate many aspects of the plant’s operations. Commonly 

referred to as the Neural Network, computer models are able to control the plant’s processes by 

predicting performance during static and dynamic changes. Many vendors offer Neural Network 

systems to improve the overall efficiency. Neural network systems are typically around 

$550,000-$750,000 and offer heat rate reductions up to 150 Btu/kWh. 

2.3.1.4 Sootblowers 

Intelligent sootblowers may be installed to improve system efficiency. The intelligent 

sootblowers system monitors the furnace exhaust gas temperatures and steam temperatures. 

Other readings may be incorporated into the intelligent sootblowers system which also 

communicates with the boiler control system. This system uses real-time data to identify which 

areas need sootblowing. Boiler efficiency improvements have ranges from 30-(150 Btu/kWh) 

with capital costs around $300,000-$500,000 and $50,000/year for fixed operating and 

maintenance costs. 

2.3.1.5 Air Heaters 

Air heaters operate to transfer heat between the incoming pre-combustion air and the 

effluent flue gas. These systems are critical to maintain an efficient power plant. In order to 

maintain these systems to operate most efficiently, air heater leakages must be maintained below 

6% of incoming air flow. Most leakage is due to the pre-combustion air leaking across the 

rotating section and leaving with the flue gas. This increases the flue gas volume going through 

the forced draft and induced draft fans to the emissions controls and avoids capturing the heat 

transferred between the flue gas and pre-combustion gas. The increased volume requires more 

power to pump more flue gas. Additionally, improvements to seals on the air heaters also reduce 

the leakages. Improvements to reduce air heater and duct leakages generally reduces the heat rate 

by 10-40 Btu/kWh with capital costs between $0.3-1.2M. 

A second method to improve the heat rate is to lower the air heater outlet temperature by 

controlling the acid dew point. Typically the air heater outlet is maintained at 20-30°F above the 
DRAFT May 15, 2014 

8 

sulfuric acid dew point to prevent corrosion of cold-end baskets. Sorbent injections such as 

Trona or hydrated lime can be used to lower the dew point. Depending on the sizing of the air 

heater, the air heater may need to be modified in order to optimize the lower outlet temperature. 

The capital costs can range from $1.5-18M for heat rate reductions of 50-120 Btu/kWh. 

2.3.2 Turbine 

The systems within the turbine area for which to focus heat rate improvements are the 

turbine, the feedwater heaters, the condenser, and the turbine drive and motor-driven feed 

pumps. 

2.3.2.1 Turbine 

Replacements or overhauls of existing steam turbines with advanced turbine designs 

improves the efficiency of converting the energy in the steam to electrical energy. The capital 

costs for these projects ranges from $2-25M with heat rate reductions of 100-300 Btu/kWh.

2.3.2.2 Feedwater Heaters 

The feedwater heaters are heat exchangers to heat the boiler feedwater by extracting heat 

from the steam leaving the turbine section. The efficiency can be increased by improving heat 

transfer surface area. This entails adding heat exchange surfaces to the existing heaters or adding 

additional heaters. The costs relative to the heat rate improvement associated with these projects 

typically prohibit the advancement of the project unless the feedwater heaters are in need of 

repair. 

2.3.2.3 Condenser 

To obtain the most efficiency from the condenser section, the most effective operation 

would have the steam from the turbine to reach the lowest temperature possible before entering 

the condenser. This allows for the turbine to extract as much energy from the steam as possible. 

Condensers are subject to fouling and plugging which directly impact the heat transfer rates and 

water quality. To improve water quality, closed cooling water systems provide better control of 

the water quality and tube cleaning can be performed. Heat rate reductions observed from the 

condenser upgrades and maintenances are 30-70 Btu/kWh with annual fixed costs of $30,000-

$80,000. 

Comment [A14]: Not clear whether the 1‐3%

efficiency improvement refers to improvement

resulting from an overhaul. It might be helpful to

indicate what size of turbines correspond to these

costs.  

EPA response: the paragraph has been modified.
DRAFT May 15, 2014 

9 

2.3.2.4 Boiler Feed Pumps 

Boiler feed pumps require a large amount of auxiliary power to pump massive amounts 

of boiler feedwater through the heaters and boiler. Due to the high use of these pumps, 

maintenance is extremely important to ensure reliability and the most efficient operation. As the 

pumps wear and operate less efficiently, a pump overhaul may be required. The overhaul can 

reduce the heat rate by 25-50 Btu/kWh with capital costs around $250,000-$800,000. 

2.3.3 Flue Gas System 

Two aspects of the flue gas system that offer potential improvements to the plant 

efficiency are to improve the forced draft and induced draft fan efficiencies and implementation 

of variable frequency drives. 

2.3.3.1 Induced Draft Fans 

One of the most important features in the fans is being able to control the flue gas flow. 

Many fans have dampers, which are the least effective and efficient option. There are many 

methods, such as variable inlet vanes , variable frequency drives, and variable pitch blades, 

available to control the flue gas flow allowing highly efficient fan performance. These upgrades 

or replacements provide a heat rate reduction of 10-50 Btu/kWh and cost between $6-$16M. 

2.3.3.2 Variable Frequency Drives 

It is apparent with the control that a variable frequency drives offers, the plant is able to 

reduce the auxiliary load immensely. Considering upgrading all drives, the capital costs are $6-

16M with heat rate reductions between 10-150 Btu/kWh. 

2.3.4 Emission Control Technologies 

With the passage of environmental regulations, additional emission control devices have 

been and must be implemented in the power plant. These systems typically require large amounts 

of auxiliary power with their benefit being improved air quality. Even small upgrades can 

decrease the power requirements significantly while at least maintaining the same level of 

emissions reduction. The three technologies discussed are the flue gas desulfurization, the 

electrostatic precipitator, and the selective catalytic reduction systems. 

Comment [A15]: Please spell out acronym –

even if it has been spelled out earlier, I have

forgotten and couldn’t find the location on looking

back.

EPA response: Spelled out acronyms.

Comment [A16]: For all these subtitles, it

wouldn’t hurt to spell out the acronym in the

section title.

EPA response: Spelled out acronyms.
DRAFT May 15, 2014 

10 

2.3.4.1 Flue Gas Desulfurization 

Coal-fired power plants contain many variances between their flue gas desulfurization 

systems. A few common technology improvements are discussed further in this section. Older 

units typically contained a venturi throat that increased the velocity of the fluid, but resulted in a 

large pressure drop and greater power to operate the induced draft fans. To improve this 

operation, a co-current spray tower quencher may replace the unit. The capital cost is about 

$2.5M with heat rate reductions around 13 Btu/kWh. 

Another technology upgrade affects the vanes and distribution plate into an absorber. The 

improvement of the gas flow coming into contact with the absorber sorbent increases SO2

capture, reduces maintenance due to erosion, and reduces the amount of energy required from the 

induced draft fan. Turning vanes and a perforated gas distribution plate improve gas distribution. 

The cost of the vanes is around $250,000 with heat rate reductions of 1-2 Btu/kWh. 

In a wet flue gas desulfurization multiple spray levels are installed to deliver the limestone 

slurry. If a power plant is operating with SO2 levels below its permit limit, turning off one spray 

level will reduce the auxiliary power necessary. If this is possible, a unit heat rate reduction of 16 

Btu/kWh may be available. 

2.3.4.2 Electrostatic Precipitator 

The best operation for an electrostatic precipitator involves maintaining the maximum 

applied voltage, but below the level in which spark-over occurs. Electrostatic precipitator energy 

management system upgrades often help improve the electrostatic precipitator performance by 

maintaining the optimal performance and lowering power consumption. The installation for this 

technology can be from minimal to $0.8M and can lower heat rate by 5 Btu/kWh. 

2.3.4.3 Selective Catalytic Reduction 

For the last 15 years, selective catalytic reduction systems have been in use to reduce 

NOX emissions from power plants. Extensive modeling was performed to achieve the necessary 

reduction with minimum ammonia slip. The results showed that reducing pressure drop and 

using secondary air as dilution for the ammonia vaporizer can reduce the auxiliary power 

necessary. The heat rate reduction is 0-10 Btu/kWh and capital costs between $0.5-$2M with 

fixed and variable costs up to $100,000 each. 
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11 

2.3.5 Water Treatment System 

The water treatment system heat rate improvements can occur for the boiler water 

treatment and the cooling tower improvements. The boiler water is one of the most important 

aspects of the power plant. The quality of the water plays a huge impact on the scale buildup on 

the boiler tubes, which reduces the heat transfer in the tubes or can cause tube failures. Proper 

use of chemicals to maintain pure water is key. Also, high-quality water can reduce the 

blowdowns required, which allows for more steam in the turbine cycle. If the water is not 

properly maintained, heat transfer may be reduced up to 10%. 

Similar to the boiler water, the cooling towers are also affected by the water quality. 

Fouling and scaling remain issues for heat transfer and purity of the water. By maintaining the 

cooling water system efficiently, the overall water quality is improved, which branches into other 

aspects already mentioned. 
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12 

Table 2-2. Existing coal-fired EGU efficiency improvements reported for actual efficiency improvement projects 

Efficiency 

Improvement 

Technology

Description 

Reported 

Efficiency 

Increasea

Combustion 

Control 

Optimization 

Combustion controls adjust coal and air flow to optimize steam production for the steam turbine/generator set. However, combustion control for a coal-fired EGU is complex and impacts a number of important operating parameters including combustion efficiency, steam temperature, furnace slagging and fouling, and NOX

formation. The technologies include instruments that measure carbon levels in ash, coal flow rates, air flow rates, CO levels, oxygen levels, slag deposits, and burner metrics as well as advanced coal nozzles and plasma assisted coal combustion. 

0.15 to 0.84% 

Cooling System 

Heat Loss 

Recovery 

Recover a portion of the heat loss from the warm cooling water exiting the steam condenser prior to its circulation thorough a cooling tower or discharge to a water body. The identified technologies include replacing the cooling tower fill (heat transfer surface) and tuning the cooling tower and condenser. 

0.2 to 1% 

Flue Gas Heat 

Recovery 

Flue gas exit temperature from the air preheater can range from 250 to 350°F depending on the acid dew point temperature of the flue gas, which is dependent on the concentration of vapor phase sulfuric acid and moisture. For power plants equipped with wet FGD systems, the flue gas is further cooled to approximately 125°F as it is sprayed with the FGD reagent slurry. However, it may be possible to recover some of this lost energy in the flue gas to preheat boiler feedwater via use of a condensing heat exchanger. 

0.3 to 1.5% 

Low-rank Coal 

Drying 

Subbituminous and lignite coals contain relatively large amounts of moisture (15 to 40%) compared to bituminous coal (less than 10%). A significant amount of the heat released during combustion of low-rank coals is used to evaporate this moisture, rather than generate steam for the turbine. As a result, boiler efficiency is typically lower for plants burning low-rank coal. The technologies include using waste heat from the flue gas and/or cooling water systems to dry low-rank coal prior to combustion. 

0.1 to 1.7% 

Sootblower 

Optimization 

Sootblowers intermittently inject high velocity jets of steam or air to clean coal ash deposits from boiler tube surfaces in order to maintain adequate heat transfer. Proper control of the timing and intensity of individual sootblowers is important to maintain steam temperature and boiler efficiency. The identified technologies include 

intelligent or neural-network sootblowing (i.e., sootblowing in response to real-time conditions in the boiler) and detonation sootblowing. 

0.1 to 0.65% 

Steam Turbine 

Design 

There are recoverable energy losses that result from the mechanical design or physical condition of the steam turbine. For example, steam turbine manufacturers have improved the design of turbine blades and steam seals which can increase both efficiency and output (i.e., steam turbine dense pack technology). 

0.84 to 2.6 

Source: National Energy Technology Laboratory (NETL), 2008. Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired Power Plant 

Fleet, DOE/NETL-2008/1329. U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA. July 23, 2008. Available at: <http://www.netl.doe.gov/energy-analyses/pubs/CFPP%20Efficiency-FINAL.pdf>. a Reported efficiency improvement metrics adjusted to common basis by conversion methodology assuming individual component efficiencies for a reference 

plant as follows: 87% boiler efficiency, 40% turbine efficiency, 98% generator efficiency, and 6% auxiliary load. Based on these assumptions, the reference power plant has an overall efficiency of 32% and a net heat rate of 10,600 Btu/kWh. As a result, if a particular efficiency improvement method was reported to achieve a 1% point increase in boiler efficiency, it would be converted to a 0.37 % point increase in overall efficiency. Likewise, a reported 100 Btu/kWh decrease in net heat rate would be converted to a 0.30% point increase in overall efficiency. 
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2.4 Previous Studies on Heat Rate Improvements 

A number of studies using varying approaches have been performed to determine 

potential efficiency improvements and associated resulting CO2 emission reductions. These 

approaches include characterizing the current U.S. coal-fired EGU fleet, identifying potential 

efficiency improvements, and applying improvement actions to existing EGUs. The approach 

taken within each study varies. Five studies are briefly summarized and compared in Table 2-3. 

The NETL studies used a benchmarking approach that evaluated the design factors that 

are known to influence efficiency and grouped EGUs based on similar design characteristics. 

The studies categorized the industry based on fuel type, location, steam cycle, and age of the 

boilers. Potential efficiency improvements were calculated based on an assumption that the 

lower-performing EGUs in each group should to be able to do as well as the better performing 

EGUs in that group. Specifically, the goal for potential improvement: for each subcategory was 

that the bottom 90% of EGUs in each group improved their heat rate to the average performance 

of top 10% in that group. While the studies are different in the level of detail and assumptions, 

the results of these studies overall suggest that a U.S. coal-fired EGU fleet-wide improvement 

ranging from 9% to 15% is theoretically possible. The Lehigh study used a less detailed 

approach and evaluated technologies applicable to bituminous and subbituminous coals to 

estimate potential fleet wide reductions. 

An alternative approach to evaluate heat rate improvement is used by Resources for the 

Future. This study focused on the operating efficiency (synonymous with heat rate) of the entire 

existing U.S. coal-fired EGU fleet. The authors evaluated decades of data from industrial 

responses to economic factors such as demand, coal price and energy policies. This approach 

sought to estimate overall changes in industry fleet efficiency in response to changes in fuel 

prices or carbon prices. In this specific example, the coal price was assumed to be a 10% 

increase and the CO2 emissions tax at $1.64 per ton for heat rate reductions of 0.3 to 0.9%. 

The National Resources Defense Council approach considered the fleet of coal-fired 

EGUs and assumes a target heat rate in order for the EGUs to comply with an inferred standard. 

As opposed to the above studies that determined by how much the efficiencies can improve, this 

approach estimated how the industry will meet any imposed standards and calculated the heat 

Comment [A18]: To avoid ambiguity it might be

helpful to cite (footnote) studies when referring to

them.  

EPA response: Added study names.

Comment [A19]: Suggest an alternate phrasing

such as: This approach sought to estimate overall

changes in industry fleet efficiency in response to

changes in fuel prices or carbon prices.

EPA response: The language has been edited as

suggested.
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14 

rates necessary to meet a standard. As it has not been determined with regard to how the CO2

emissions limit will be averaged, the paper discusses many potential options that coal-fired 

EGUs may have to meet new standards. These options include additional options such as adding 

renewable, natural gas, and combined-cycle sources. 

The EPA observed that existing HRI studies using a benchmarking approach have relied 

on a single year annual average heat rate data, whereas many of the operational impacts on heat 

rate (diurnal temperatures, load following, etc) become more apparent in the variability of hourly 

performance data. We further recognized that an examination of heat rate data over a multiple 

year period, perhaps a decadal time frame might reveal patterns of performance that should also 

inform estimates of HRI potential. For these reasons, the EPA has developed in this TSD an 

additional assessment of HRI potential that draws on multiyear historical hourly data. While we 

understand that engineering judgment remains essential to a proper interpretation of the results, 

the EPA intends that this assessment be a more substantial basis for estimating the fleet-wide 

HRI potential for coal-fired EGUs. 

Table 2-3. Summary comparison of previous studies on EGU heat rate improvements 

Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

Relevant HRI 

Results 

1 “Reducing CO2 

Emissions by 

Improving the 

Efficiency of the 

Existing Coal-fired 

Power Plant Fleet” 

NETL 

• Plant design: age and 

steam cycle 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

performance of top 10% in 

that category 

• Units with capacity factors 

under 50% were removed 

from dataset 

• 15% reduction in 

overall heat rate of 

coal-fired EGUs 

2 “Improving the 

Efficiency of CoalFired Power Plants 

for Near Term 

Greenhouse Gas 

Emissions 

Reductions” 

NETL 

• Plant design: coal type, 

steam cycle, and size 

• Category improvement is 

the bottom 90% of EGUs in 

each group improving their 

heat rate to the average 

performance of top 10% in 

that category • Units with 

anomalous data, capacity 

factors under 10%, using 

less than 97% coal, and 

gasification plants were 

removed from dataset 

• Low pressure subcritical 

units and 0-200 MW 

subbituminous units 

• 8.7% reduction in 

overall heat rate of 

coal-fired EGUs 

Comment [A20]: Not certain this is correct ‐ the

RFF study abstract states: “This paper examines the

operation of coal‐fired generating units over 25

years to estimate the marginal costs and potential

magnitude of emissions reductions from improving

their efficiency.” Please correct if appropriate.

EPA response: The text has been clarified to refer to

studies that used a benchmarking type approach to

estimate potential reductions.  

Comment [A21]: Please check on the tense –

past or present?

EPA response: Thank you for the observation.
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Study 

ID 

Study Title 

Author 

Factors Used for 

Industry Grouping 

Key Study 

Assumptions 

Relevant HRI 

Results 

assumed retired for goal 

• Lost generation made up by 

more efficient coal-fired 

EGUs 

3 “Reducing Heat 

Rates of Coal-Fired 

Power Plants” 

Lehigh Energy 

Update 

 All possible heat rate 

improvements are made 

including drying of high 

moisture coal: 

• 10% improvement 

for bituminous coalfired EGU 

• 15% improvement 

for subbituminous 

coal-fired EGU 

4 “Regulating 

Greenhouse Gases 

from Coal Power 

Plants under the 

Clean Air Act” 

Resources for the 

Future 

• Analyze the actual 

operating efficiency of the 

entire fleet of U.S. coalfired EGUs 

• Assess abatement 

opportunities and costs by 

observing how coal plants 

respond to market and 

regulatory incentives to 

improve energy efficiency 

Overall efficiency 

improvements of 2 to 5%, 

from other literature studies 

10% coal price 

increase, 

corresponding to a 

tax on CO2

emissions of about 

$1.64 per ton, 

improving heat rates 

by 0.3 to 0.9 % 

5 “Closing the Power 

Plant Carbon 

Pollution Loophole: 

Smart Ways the 

Clean Air Act Can 

Clean Up 

America’s Biggest 

Climate Polluters” 

NRDC 

• Plant design: coal type 

and steam cycle 

Improvements are broken into 

3 group 

• Top 10% for each 

subcategory, no change 

• Top 11% to 49%, improve 

heat rate by 50% of the 

difference between facility 

heat rate and performance of 

top 10% in class or 600 

Btu/kWh, whichever is less 

• Bottom 50%, improve heat 

rate by 100% of the difference 

between facility heat rate and 

performance of top 10% in 

class or 600 Btu/kWh, 

whichever is less 

 Broader analysis 

not strictly focused 

on heat rate 

improvements. 11% 

reduction on overall 

fossil fuel-fired EGU 

emission rates; 

includes switching 

from coal to natural 

gas. 

2.5 EPA’s Heat Rate Improvement Assessment 

This EPA assessment of fleet-wide HRI potential looks at historical data from coal-fired 

EGUs in the U.S. to identify changes to EGUs’ heat rates – the amount of heat input required, on 

average, to generate 1 kWh of electricity – that can be attributed to operation and maintenance 

practices and equipment upgrades. These heat rate changes are analyzed to determine their 

applicability to the rest of the coal-fired EGU fleet and to determine the potential heat rate 

improvement that, on average, could be achieved by the fleet. 

Comment [A22]: Please include text regarding

the peer review to which all these reports have

been subject. If not, please consider subjecting this

concept to technical peer review in the period

following proposal release.

EPA response: We will check on the peer review

status of the studies.  

Comment [A23]: Is there a reason there is no

comment in this box?

EPA response: Text has been added.
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This data analysis portion of the study relies on unit-level heat input and gross generation 

data reported to the EPA by owners or operators of EGUs to assess in detail the changes in gross 

heat rates. Potential changes in net heat rates are then addressed later in this section. Unit-level 

evaluations allowed the EPA to recognize the significant heterogeneity of coal-fired EGUs; even 

‘sister’ units, units built at the same time at a given facility, may display different operating 

profiles and may have different equipment, controls, fuel mixes or cooling systems. 

Based on literature reviews; informal interviews with engineering experts, vendors, and 

plant operators; and historical information collected by the EPA, we believe EGUs achieve heat 

rate improvements by: 1) operating under recommended operation and maintenance conditions 

(best practices), and 2) installing and using equipment upgrades. Best practices include no-cost 

or low-cost methods such as the installation or more frequent tuning of control systems and the 

like-kind replacement of worn existing components. Upgrades often involve higher costs and 

greater downtime, such as, extensive overhaul or upgrade of major equipment (turbine or boiler) 

or replacing existing components with improved versions. 

The EPA developed unit-level statistics from over 60 million rows of hourly data. We 

evaluate each unit on its individual performance using heat rate variability as an indicator of the 

application of best practices and potential for improvement. To estimate heat rate improvement 

through equipment upgrades we survey engineering studies, examine year-to-year trends, and 

research EGUs where such methods were applied. 

2.5.1 Study Population and Data 

The EGU study population consists of 884 coal- and petroleum coke-fired EGUs that 

reported both heat input3

 and electrical output to the EPA’s Clean Air Markets Division in 2012.4

It includes a wide range of configurations, from 24 to 1,500 MW nameplate capacities, super and 

subcritical thermodynamic cycles, between 1 and 69 years old, and different coal ranks. It 

excludes any EGUs at any facility that reported cogeneration to the EPA or the EIA. These units 

are excluded because a portion of the heat input was used to generate electricity and/or steam 

                                                            

3 Sources calculate heat input using an ‘F factor’ for the carbon content of the fuel being combusted and the average 

hourly measurements of CO2 flow and concentration. 4

 Information on the Clean Air Markets Division data is available at http://ampd.epa.gov/ampd/
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heat. Therefore, it is difficult for the EPA, using available data, to make a meaningful 

comparison of these units’ heat rates. 

The EPA performed this study using hourly heat input (Btu), and electricity output 

(MWh) data from the Clean Air Markets Division and meteorological data from NOAA’s 

National Climatic Data Center for the years 2002-2012. As described later in this section, these 

meteorological data were used to account for temperature impacts on heat rates. The eleven year 

study period is representative of a wide range of conditions, including growth and recessionary 

economic conditions, changing electricity generation from renewable and natural gas, and 

different regulatory constraints. 

The hourly heat input and generation data used in this study is collected under the 

authority of 40 CFR part 75 (hereafter, Part 75). The EPA designed Part 75 to encourage 

complete and accurate emission measurement and reporting to support emission trading 

programs, including the Acid Rain Program and Clean Air Interstate Rule (CAIR). However, the 

EPA recognized that there will be times when emission data are not available due to monitoring 

system malfunctions or maintenance, technical challenges, or missed quality assurance/quality 

control (QA/QC) tests. When data are not available or deemed invalid (e.g., when a QA/QC test 

was not performed as required), the EPA has specified data substitution methods that are 

designed to overestimate emissions. This conservative bias is intended to create an incentive for 

better emission measurement – the overestimate incurs an economic penalty because, at the end 

of the compliance period, an EGU must surrender allowances equal to total reported emissions. 

Because of this conservative bias and the impact it would have on the results of this study, the 

EPA excluded substitute data reported by EGUs from this study’s dataset. These substitute data 

represent approximately 2% of all reported operating hours. In addition, we excluded partial 

hours of operation that occur during the first hour of startup and the last hour of shutdown. 

We also excluded 40 unit-years (0.5% of records) with atypical annual heat rates less 

than 6,500 or greater than 15,000 Btu/kWh resulting from a variety of factors including firing of 

natural gas, very low operating time, or errors in reported gross load. Table 2-4 summarizes the 

heat input, electric generation, heat rate and unit counts by year for the study population used in 

this work. This population corresponds to 9,388 unit-years of data at 884 distinct EGUs. Figure 

2-1 displays the study population average gross heat rate by year and the 11-year average. 

Comment [A24]: IS QA/QC defined in the

abbreviations?

EPA response: It is defined in the sentence.
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Table 2-4. Study Population Annual Heat Input, Generation, Heat Rate and Unit Count 

2002 - 2012 5

Year 

Heat Input 

(million 

MMBtu) 

Electric 

Generation 

(million MWhgross) 

Heat Rate 

(Btu/kWhgross) Unit Count 

2002 18,601 1,874 9,924 839 

2003 18,428 1,864 9,886 834 

2004 18,405 1,875 9,819 836 

2005 18,665 1,910 9,774 838 

2006 18,644 1,914 9,743 848 

2007 18,704 1,920 9,740 846 

2008 18,459 1,914 9,643 852 

2009 16,588 1,719 9,649 864 

2010 17,693 1,831 9,662 869 

2011 16,934 1,744 9,708 878 

2012 14,947 1,536 9,732 884 

Figure 2-1. Study Population Average Gross Heat Rate by Year 

NOAA’s Integrated Surface Data (ISD) product provides hourly temperature for over 

20,000 weather stations worldwide.6

 Since EGU heat rate performance is sensitive to air 

                                                            

5 The study population for each year includes those EGUs that reported both heat input and electric generation. 6 Temperature data is from NOAA’s Integrated Surface Data at http://www.ncdc.noaa.gov/data-access/land-basedstation-data/land-based-datasets/integrated-surface-database-isd.

9,500

9,550

9,600

9,650

9,700

9,750

9,800

9,850

9,900

9,950

10,000

20022003200420052006200720082009201020112012

Heat Rate (btu/kwh)

Annual Heat Rate

11-yr Avg Heat Rate

Comment [A25]: Change in unit counts due to

using conditions that match preceding paragraph.   
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temperature and barometric pressure, which vary with elevation, we use meteorological data 

from stations that are reasonably close to the EGU's location and elevation to account for the 

impact of ambient conditions. For each of the plants in this study’s database, we identified the 

nearest stations that reported a minimum of 8,400 hourly observations in the calendar year (i.e., 

greater than 95% of the hours in a year). Generally, each plant was associated with 

meteorological data from the two closest stations over the eleven-year study period. The average 

distance between the plant and the nearest station was 22 miles and the average difference in 

elevation was 366 feet. At nine plants we used data with as few as 7,000 observations in order to 

keep the maximum difference in elevation under 1,000 feet. The EPA believes that nearby 

weather station measurements are a good approximation of ambient meteorological conditions at 

each facility. Joining the trimmed heat rate and hourly temperature datasets resulted in 

61,848,580 hourly records for the study population of EGUs (see Table 2-4). 

The results of this study are based on analyses of data from the population of coal-fired 

EGUs shown in Table 2-4. These units emitted 1,605 million tons of CO2 in 2012. In contrast, 

emissions of CO2 from coal-fired EGUs in the entire U.S. electric power sector in 2012 were at 

1,669 million tons according preliminary data from the EIA.7

 Since the study population of 

EGUs accounted for over 96% of CO2 emissions from the fleet of U.S. coal-fired EGUs, the 

EPA considers the results of this study to be applicable to the coal-fired fleet at large. 

2.5.2 Subcategorization 

In this analysis, units are not categorized by unit specific design characteristics or fuel 

because: (1) EGU-specific detailed design information on all factors that influence heat rate is 

not available, and (2) certain design characteristics are not easily categorized (e.g., EGUs use a 

large range of steam conditions). Several other studies do categorize EGUs broadly by capacity, 

thermodynamic cycle, and/or fuel rank. Although the EPA believes grouping by categories can 

provide a useful way of understanding the operating profile of an EGU and the fleet, the range of 

heat rates for the broad categories has significant overlap (see box and whisker chart in Figure 2-

2) and therefore makes it challenging to develop appropriate categorization. The figure below 

displays available information on coal-fired EGUs considered in this work for the years 2009-

                                                            

7

 Preliminary 2012 results from http://www.eia.gov/tools/faqs/faq.cfm?id=77&t=3.    
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2011 in typical subcategories of capacity, fuel rank, and thermodynamic cycle. As the figure 

reflects, the means are clustered and the ranges of heat rates overlap. 

 

Figure 2-2. Three-Year Average Heat Rates by Subcategory8

2.5.3 Observed Trends in the Period 2002-2012 

Three trends are notable for the study population during the period 2002-2012. 

Comparing the averages of the first three years (2002-2004) to the last three years (2010-2012), 

electric generation and gross heat rate declined by 9% and 2%, respectively. Capacity factor for 

the study population fell by 14% comparing the same time periods (see Table 2-5). The decrease 

in coal-fired generation and capacity factor may be because of reduced demand for electricity 

resulting from the recession starting in late 2008 and greater use of natural gas and renewables to 

generate electricity. 

The 11-year average annual gross heat rate for the study population of coal-fired EGUs 

(see Table 2-4) was 9,754 (Btu/kWh). The decrease in study population annual heat rate between 

2002 and 2012 may be due to several factors. Unit efficiency may have improved or units with 

lower heat rates may have taken up a larger share of generation. In addition, changes in reporting 

                                                            

8 Abbreviations in the figure: BIT means bituminous, SUB means subbituminous, PC means petroleum coke, LIG 

means lignite, SUPER means supercritical, OVER/UNDER means greater/less than indicated MW capacity. Unit 

counts (n) by category: BIT SUPER, n=80; SUB SUPER, n=30; BIT OVER, 200 n=196; PC, n=2; BIT 100 to 200 

n=140; SUB OVER 100, n=299; LIG OVER 100, n=20; BIT UNDER 100, n=68; SUB UNDER 100, n=56; LIG 

UNDER 100, n=2. Total unit count is 893.

6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

BIT SUPER

SUB SUPER

BIT OVER 200

PC

BIT 100 to 200

SUB OVER 100

LIG OVER 100

BIT UNDER 100

SUB UNDER 100

LIG UNDER 100

3-Year (2009-2011) Average Heat Rate (Btu/kWh)

Subcategory

Comment [A26]: Suggest including on the figure

the number of plants in each category (N=? for each

category).

EPA response: added counts to footnote.

Comment [A27]: The footnote uses SUB twice

for different terms.  Please clarify/fix.

EPA response: Done
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methodology described later in this chapter may be partly responsible. The minimum annual heat 

rate (9,643 (Btu/kWh)) occurred in 2008 and was approximately 1% below the 11-year average. 

Table 2-5. Reported Annual Capacity Factor 2002-20129

Year Capacity 

Factor (%) 

2002 68 

2003 69 

2004 70 

2005 71 

2006 70 

2007 71 

2008 70 

2009 62 

2010 65 

2011 61 

2012 53 

2.5.4 Startups and Shutdowns - Impact On the Results of This Study 

During periods of startup and shutdown, EGUs are known to operate at higher heat rates. 

Therefore, we evaluated the potential impact of such events in our study. A startup event, as 

defined here, occurs when an EGU begins combusting fossil fuel and generates some measurable 

amount of electricity. Table 2-6 summarizes the study population average, maximum and total 

starts by year. On average, coal-fired EGUs start combusting fuel and generating electricity 11 

times per year. The total number (approximately 9,000) of starts for the study population of 

EGUs has remained stable over the study period. Our data reflects that some coal-fired units 

operate in a load following capacity and may report upwards of 200 starts in a single year, but 

these units tend to have low annual capacity factors. The subset of EGUs with more than 20 

annual startup and shutdown events is responsible for less than 4% of total generation in any 

study year. Therefore while the number of starts is an important variable at a small number of 

EGUs, its impact on heat rate performance evaluated in this study is considered to be marginal. 

                                                            

9 Table 2-5 shows data as reported to EPA as of May 8, 2014.

Comment [A28]: Suggest making the Table title

more descriptive.  

Also could present fewer signficant  digits in table

...i.e. heat input‐ MM BTU x 106  ‐‐ 

EPA response: changed units and title.

Comment [A29]: This capacity factor decline in

2012 is very different from the CF used later, see

comment on page p. 35, i.e., 78% in 2020.  Which is

correct?  And, did coal CF at 44% factor into the EPA

modeling?

EPA response: The table has been updated to use all

reported data (rather than a trimmed data set). This

changes the capacity factor in 2012 to 53%. Note

the capacity factor of 78% is for the coal‐fired steam

fleet in base case, 2020. Note also that the study

population includes a significant number of EGUs

that IPM lists as retiring prior to 2016.

Comment [A30]: At about this point, the

chapter transitions into the quantitative analysis.

Suggest highlighting that in some way. There seem

to be several components of the quantitative

analysis: 1. Regressing HR onto CF and Temp; 2.

Looking at residual heat rates relative to model

prediction; 3. The “bin model” for assessing HRI

potential via best practice; 4. The assessment of HRI

potential via equipment upgrades. Suggest

presenting those more clearly either here or even

forward in the chapter in summary form.

EPA response: Thank you. We have added a

paragraph introducing more‐quantitative analyses.
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Table 2-6. EGU Start Count by Year 

Year Average Maximum (at 

any single EGU) Total 

2002 11.1 209 9,363 

2003 10.6 194 8,936

2004 10.7 134 9,081 

2005 11.0 183 9,265 

2006 10.5 139 8,859 

2007 10.5 164 8,908 

2008 10.4 134 8,880

2009 10.3 178 8,902 

2010 10.5 211 9,110 

2011 10.6 206 9,295 

2012 9.9 119 8,805 

To understand the potential for heat rate improvement available with existing coal-fired 

steam EGUs, the EPA conducted a number of quantitative analyses. These included: (1) 

regression analyses to understand the impact of capacity factor and ambient temperature; (2) 

using a bin model to determine the potential from best practices; and, (3) evaluating available 

data and information to assess the potential from equipment upgrades. These analyses are 

described in the following sections. 

2.5.5 Impact of capacity factor and ambient temperature 

Two important factors that affect heat rate at an EGU are hourly capacity factor and 

ambient temperature. In this section, we examine the impact of these two variables on heat rates 

of the EGUs in the study population. Power plant operators today typically use digital control 

systems to capture hundreds of data points in near real-time that are summarized in the unit heat 

rate statistic. EPA has access to a small fraction of that information. A key reason this study used 

capacity factor and ambient temperature as independent variables is that both were available as 

hourly data. Preliminary analyses of heat rate at higher time increments, such as month, were 

useful to describe aspects such as seasonality but we determined hourly data was necessary to 

understand how heat rate was responding to constantly changing operating conditions. We tested 

for collinearity between capacity factor and ambient temperature using a zero-order correlation 

Comment [A31]: After this sentence, suggest

adding a sentence stating why this is important to

do, and a sentence summarizing the approach.

(EPA) see updated text  
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23 

matrix on the entire hourly data set. The correlation between the independent variables was -.048 

– well below an indication of collinearity. 

We also considered fixed unit characteristics such as unit type, fuel rank and age as 

independent variables. As noted above in the discussion on subcategorization, these factors can 

be helpful to understanding the heat rate performance of EGUs. The purpose of this study, 

however, is to find the potential for heat rate improvement across the fleet. We use heat rate 

variability as a key statistic to measure this potential. The correlation between the potential for 

heat rate improvement and fixed characteristics is typically low.10 

Coal-fired units are designed to operate most efficiently at full capacity. As a unit drops 

below this level, in general, heat rate will increase. The average capacity factor over 11 years for 

the study population is 67%, but as noted above, has moved markedly over the study period. This 

study looks at utilization level at both hour and year time scales. The two are related but reveal 

different information about how an EGU is operating. For example, for a unit to achieve a high 

annual capacity factor (e.g., over 90%) it must operate at a high load for most hours in a year. At 

lower capacity factors interpreting the relationship between hourly and yearly utilization levels 

becomes more complex. For example, an EGU may run at an annual 60% capacity factor by 

operating 8 months at near full capacity and generating no electricity the rest of the year, or it 

may run at lower utilization levels for most hours of the year in response to weather, generation 

cost, and transmission constraints. 

Ambient temperature can affect heat rate in two ways: 1) the efficiency of the 

thermodynamic steam cycle11 and, 2) in many regions of the country, as temperatures increase 

electricity demand and capacity factor follow. Figure 2-3 shows the average monthly capacity 

factor in 2012 alongside the climate normal monthly temperature.12 The lines intersect in the 

spring as temperatures begin to rise and the need for cooling drives electricity demand. 

                                                            

10 For example, the correlation between annual unit heat rate variability (discussed below as relative standard 

deviation) and unit nameplate capacity (MW) is in the -0.1 range. 11 The availability of a cold heat sink in the condenser is a key factor in that cycle. The design of the heat exchanger, 

type of cooling system and availability of water all have an impact on performance. An increase in ambient air 

temperature, and consequent increase in water temperature, typically lower the effectiveness of the cooling system, 

the condenser, and, therefore, overall plant efficiency.

12 Climate normal is the average of temperature (or other measure) over a prescribed 30-year interval and location. 

The chart shows the 1981-2010 climate normal monthly temperature at Baltimore-Washington Airport, MD.

Comment [A32]: Suggest discussing explicitly

the choice of CF as an independent variable – why is

it reasonable to think of it as an independent

element? Are there better factors that EPA could

have used but was unable to because of information

availability?

EPA response: see the preceding paragraph
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Generally, peak capacity factor and generation in most parts of the U.S. occur on the hottest days 

of the year. Yet, the relationship between ambient temperature and capacity factor is complex. 

Each plant responds differently depending on design, meteorological conditions and electricity 

demand. For example, a base load plant may operate at a high capacity factor seven days a week 

regardless of temperature. As noted above, the collinearity between these two variables is low. 

Figure 2-3. Monthly Capacity Factor, 2012. 

2.5.5.1 Regression Analysis to Assess Impact of Capacity Factor and Ambient Temperature on 

Heat rate

Using the hourly data set, the EPA performed three regression analyses for each unityear: heat rate onto capacity factor, heat rate onto ambient temperature and heat rate onto 

capacity factor and ambient temperature. Since this analysis seeks to evaluate heat rate under 

normal operating conditions, we removed records with hourly heat rate values outside of +/- 2.6 

standard deviations (1.9% of records) before performing the regressions.13 Similarly to partial 

operating hours, these outliers tend to occur during low load conditions. The records trimmed 

amount to one-fourth of a percent of the total study population generation. Regression results 

describe the goodness of fit for the model and are expressed as the coefficient of determination 

or ‘r-squared’. To represent the relative contribution of varying unit capacities all results are 

generation-weighted.14 The average study population r-squared for the multivariate regression is 

                                                            

13 The 2.6 standard deviation bound is used in other EPA regulatory analyses. 14 In a weighted average, each component is multiplied by a factor reflecting its importance. In this case, generationweighted r-squared is the sum of r-squared for each unit multiplied by its annual generation divided by the sum of 

generation for all units.

0

20

40

60

80

100

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Electric generation monthly 2012 capacity 

factor and normal temperature

Capacity Factor

(Monthly %, 2012)

Climate Normal

(BWI, MD)

Comment [A33]: Capacity factor is also

influenced by temperature – any considerations for

collinearity effects in the regression?

EPA response: We tested for collinearity between

capacity factor and ambient temperature using a

zero‐order correlation matrix on the entire hourly

data set. The correlation between the independent

variables was ‐.048 – well below an indication of

collinearity.    
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26%. This means that hourly ambient temperature and capacity factor together explain 26% of 

the change in heat rate for the study population over the study period. The average study 

population r-squared from the single variable analysis of capacity factor is 16%; the 

corresponding result for temperature is 10%. This means that approximately 16% of the change 

in hourly heat rate is attributable to capacity factor and 10% to ambient temperature. These 

results, however, conceal considerable variability. Some EGUs, typically load-following, have 

an 11-year average r-squared for capacity factor exceeding 50%. At those EGUs, the capacity 

factor is a key variable influencing changes in heat rate. 

At approximately one-fourth of the study population the response to ambient temperature 

is larger than the response to capacity factor. At some individual EGUs, temperature may explain 

up to 30% of the change in heat rate. These are typically, but not exclusively, units with oncethrough, fresh water, cooling systems. Identifying temperature-responsive EGUs allows us to 

understand why heat rate may increase during periods of peak demand. These are the EGUs 

where the ambient temperature ‘signal’ is an important variable. At a typical EGU, summer 

month heat rates may increase by 2-4% compared to winter months, but at a temperatureresponsive EGU that figure may be as high as 10%. 

Our analysis indicates that as EGUs moved from base load to load following, capacity 

factor tended to have a larger effect on heat rate. Since 2008, the study population capacity 

factors moved from the top load bin into lower load bins. This can be seen from Figure 2-4, 

which compares the study population duty cycles in 2008 to 2012. A significant share of 2008 

generation occurred at EGUs running at greater than 84% annual capacity factor. In 2012, little 

generation took place in that bin or above, and generation was reduced by about half in the next 

lower bin (78-83% capacity factor). 
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Figure 2-4. Change in Annual Duty-Cycle 2008 and 2012 

2.5.6 Heat Rate Variability and Indication of Improvement Potential 

This study examines heat rate variability from the standpoint of statistical process 

control, which is utilized throughout the power industry. Several years ago, the EPA introduced 

process control charts for auditing emissions data reported under Part 75. Sources and vendors 

adopted the EPA methodology to identify potential problems early, before they significantly 

affect emission measurements. Heat rate lends itself to process control since it is the principal 

indicator that defines the quality of the electric generation process.15,16 Therefore, in general, 

high variability in heat rate values would reflect opportunities for process improvement. 

We use the relative standard deviation (RSD) of the hourly heat rates to evaluate each 

unit against its past performance and to compare with the study population. Each unit has up to 

eleven RSD values, i.e., one for each operating year between 2002 and 2012. The generationweighted mean RSD for the study population across 11 years is 5.4%. Table 2-8 summarizes 

                                                            

15 “The principal indicator that defines the quality of the process is heat rate.” (Fredrick & Todd, 1993. Statistical 

Process Control Methods in Performance Monitoring. Available at 

famos.scientech.us/Papers/1993/1993section11.pdf) 

16 Since accurate measurement is essential to process control the introduction of increasingly sophisticated digital 

control systems (DCS) presents new opportunities for finding inefficiencies. Vendors (ABB, Siemens, Emerson) 

claim heat rate improvements of 2-5 percent can result from upgrading to a modern DCS and advanced control 

technologies. The improvement can be even higher if system-wide real-time optimization is included. 
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eleven years of results for the study population by quartiles ordered by the 11-year generationweighted RSD average (ascending).17 The RSD of the top quartile (3.5%) is significantly lower 

than the study population generation-weighted mean RSD of 5.4%. Notably, the EGUs in the top 

quartile are not outliers; they report a third of all generation – the most of any segment. The 

results display a wide range of heat rate variability in the study population and thereby indicate 

the potential for heat rate improvement. 

Table 2-8. RSD in reported heat rate (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

Share of 

Generation 

1 3.5 1.6 4.2 33

2 4.8 4.2 5.3 26

3 6.1 5.3 7.0 24

4 9.8 7.1 25.2 16

The study also examined EGU heat rate variability using the residual heat rate. The 

residual in a regression analysis is the difference between the observed value of the dependent 

variable (heat rate) and the predicted value. The intercept is the value where the linear regression 

crosses the y-axis. For each EGU, we calculated the residual heat rate by summing the residual 

for each hour to the intercept value. The standard deviation of the residual heat rate statistic is 

used to understand the amount of variability that is not explained by capacity factor and 

temperature. 

The average RSD corresponding to residual heat rate variability for each EGU is the 

generation-weighted average of up to eleven annual values. The study population generationweighted mean RSD over the study period is 4.5%. This percentage represents the total 

variability across the study population that our analysis could not explain by hourly capacity 

factor or ambient temperature. Possible causes of this variability include changes in plant 

equipment, operating procedures and maintenance, fuels (particularly coal rank), reporting 

methodology, and unexplained factors. There is no temporal trend evident in the RSD. Table 2-9 

                                                            

17 Nine EGU RSD values exceeded 2.6 standard deviations above the mean and were removed from the results in the 

table.
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summarizes the study population generation-weighted average RSD of residual heat rate over the 

study period in quartiles ordered by the 11-year generation-weighted RSD average (ascending). 

Table 2-9. RSD of residual heat rate (generation weighted)18

Quartile RSD 

average 

RSD 

Minimum 

RSD 

Maximum 

1 2.7 0.0 3.2 

2 3.6 3.2 4.1 

3 4.7 4.1 5.3 

4 6.9 5.3 10.4 

The weighted average RSD of the top quartile is 2.7% – well below the study population 

average of 4.5 %. This means that the residual hourly heat rates of these units generally stay in a 

narrow range within a given year. The maximum RSD in the top quartile is 3.2%. From the 

statistical process control point of view, these units appear to have low variability. 

The weighted average RSD of the bottom quartile is 6.9%, which is over twice that of the top 

quartile. This spread indicates that there is likely room for improvement in study population 

operation to reduce variability and heat rate. 

2.5.6.1 Heat rate variability and performance 

To examine the association between heat rate variability and heat rate performance this 

study examined the RSD for unit-year heat rates calculated from reported data. The study 

population generation-weighted annual RSD ranges between 5% and 6% during the study period. 

Figure 2-5 below summarizes the results of regressing RSD of heat rate onto annual heat rate.19

The r-squared result is 57%. These results indicate that, other factors held equal, if an EGU 

reduces heat rate variability, generally heat rate performance will improve. 

                                                            

18 This table excludes nine units where RSD exceeded 2.6 standard deviations from the mean. 19 The regression analysis was performed on 9,388 unit-years of study data which were trimmed to remove values 

outside 2.6 standard deviations.

Comment [A34]: This Table (and others like it)

might be more clearly presented as a simple line

graph.  

EPA response: Thank you.
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Figure 2-5. Regression analysis of reported heat rate RSD onto annual heat rate 

2.5.7 Units with large heat rate changes 

Over one third of the study population (355 units) reported at least one year-to-year 

change in heat rate greater than +/- 8.5%.20 We consider this magnitude to be in the upper range 

of what would be expected due to changes in fuel rank, operations and maintenance, or plant 

equipment. Table 2-10 presents the counts by three categories: EGUs with at least one year-toyear decrease in heat rate > 8.5%; units with at least one year-to-year increase in heat rate > 

8.5%; and, units with both. We examined whether the large heat rate changes were due to `yearto-year changes in capacity factor and found no correlation between the year-to-year changes in 

heat rate and capacity factor for any of the three groups in Table 2-10.21 This would indicate that 

other factors account for these large changes to heat rate. The EPA’s research found that 

approximately two-thirds of the large decreases in heat rate can be associated with changes in 

reporting method implemented to provide more accurate heat input data.22 The large changes 

                                                            

20 After removing unit-years where annual capacity factor fell under 50 percent the count is 313 EGUs. 21 The correlation remains weak even when limited to cases where capacity factor changed more than 30 percent. 22 EPA Reference method 2 specifies the normal procedure for measuring stack gas volumetric flow rate during a 

relative accuracy test audit. Methods 2F, 2G, 2H and CTM-041 are approved alternatives. Methods 2F and 2G 

correct measured flow rates for angular (non-axial) flow, Method 2H (for circular stacks) and conditional test 

method CTM-041 (method J, for rectangular stacks and ducts) are used to correct measured flow rates for velocity 

decay near the stack wall, using a “wall effects adjustment factor”. These alternative methodologies are optional. 

Therefore, given the additional complexity and cost of using these alternatives a source is likely to use them only if 

the results are significantly lower volumetric stack gas flow. The EPA was unable to draw conclusions about the 

effect of changes in flow reporting methods on fleet heat rate performance.

y = 0.002x - 14.254

R2 = 0.5704

5.0

5.2

5.4

5.6

5.8

6.0

6.2

9600 9650 9700 9750 9800 9850 9900 9950

RSD heat rate % 

(generation weighted)

Heat Rate
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noted at the remaining one-third could not be explained by changes in reporting methodology. 

Moreover, we found no correlation between changes in reporting method and heat rate RSD. 

Table 2-10. Year-to-Year Heat Rate Change 

Description Count 

Correlation of 

heat rate to 

capacity factor 

Units with only year-to-year heat rate decrease > 8.5% 166 .1 

Units with only year-to-year heat rate increase > 8.5% 80 .1 

Units with both year-to-year heat rate decrease and increase > 8.5% 355 .1 

The breakdown of the ‘large decrease’ EGUs by quartile, in Table 2-11 below, is consistent with 

the study population results shown in Table 2-8. This does not imply that the changes associated 

with a large year-to-year decrease, which may include operations and maintenance, more 

accurate reporting methods, or new equipment, do not affect heat rate variability. If they occur as 

part of an engineering effort to improve efficiency, heat rate variability may also be reduced. 

Table 2-11. RSD in reported heat rate of 166 ‘large 

decrease’ EGUs (generation weighted) 

Quartile RSD 

Average 

RSD 

Minimum 

RSD 

Maximum 

1 4.0 2.3 4.8 

2 5.3 4.8 5.9 

3 6.6 5.9 7.5 

4 10.5 7.6 26.5 

2.5.8 Assessment of heat rate improvement potential via best practices 

As mentioned before, across the study period, the effects of hourly capacity factor and 

ambient temperature explain a generation-weighted average of 26% of the change in study 

population heat rate.23 This means that on average 74% of the change remains unexplained after 

controlling for those factors. The residual heat rate analysis determined there is significant 

variation in the operation of EGUs. Since lower heat rate variability is associated with lower heat 

rate, other factors held equal, the range of variation indicates that significant potential for heat 

rate improvement is available through the application of best practices. 

                                                            

23 The 26% result is the generation weighted average of r-squared values from the multivariate regression analysis.
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To control for known factors, the EPA constructed a model that groups each EGU’s 

hourly heat rate data into 14 temperature bins and 12 capacity factor bins, resulting in a 12 by 14 

matrix of 168 bins.24 For a given EGU, a temperature and capacity factor bin will have all the 

relevant hourly values over the eleven-year study period. For each bin with 15 or more values the 

model finds the reported hourly heat input value corresponding to the 10th percentile (p10).25

This means that approximately 90% of the heat input values in that bin exceed p10. For each 

unit, the model reduces the reported hourly heat input greater than p10 by a percentage of the 

distance between the reported value and p10 (e.g., 50% of the difference). The same statistical 

procedure is applied to every hour of heat input data in each bin. These reduced hourly heat input 

values are then used to calculate a reduced 11-year average heat rate for each unit. The percent 

difference between a unit’s reported 11-year average heat rate and the heat rate that corresponds 

to reduced heat inputs is the potential heat rate improvement for that unit.26 Using this approach, 

those units with the lowest variability (e.g., in the top quartile of residual heat rate variability) 

take proportionally smaller reductions. 

Table 2-12 below shows the model results with options of 10% to 50% stringency. For 

example, reducing reported heat input 10 % of the distance to the p10 value achieves a 1.3% 

study population wide reduction. Alternatively, a 50% reduction will result in a 6.7% study 

population wide improvement in heat rate. In effect, the model proportionately reduces heat rate 

variability and improves performance for each unit while controlling for temperature and 

capacity factor. The heat rate improvement for the study population is derived from the 

performance of each individual EGU as compared to its own record. 

Table 2-12. Assessment of heat rate improvement potential via best practices 

% Reduction from 

reported heat input 

to p10 

Study population 

heat rate 

(Btu(kWh-gross)27

Reduced study 

population heat 

rate (Btu/kWhStudy population 

heat rate 

improvement (%)

                                                            

24 The matrix provides up to 168 bins but only 164 contained hourly values. Temperature bins ranged from -20 to 

greater than 110 with 10 degrees F in each. Capacity factor bins ranged from 0% to greater than 110% with 10% in 

each. 

25 Performing the calculation with a minimum of 30 values in each bin has a modest effect on the results in Table 2-

12. For example, a 30% reduction obtains a 3.9% fleet wide improvement in heat rate (rather than 4.0%). 26 Heat rate is calculated as the sum of heat input (Btu, reported or reduced) divided by the sum of generation (kWh) 

for the given population and time period.   27 Fleet heat rate for study population as described in Table 2-4 is 9,754; the 9,755 value is derived from the dataset 

that includes hourly temperature values.

Comment [A35]: This technical analysis of the

possibility for heat rate improvements should be

peer reviewed.  Has EPA run this by the SAB, or does

EPA intend to do so after release of the proposal?

EPA response: Thanks for your comment
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gross) 

10 

9,755 

9,625 1.3 

20 9,495 2.7 

30 9,365 4.0 

40 9,235 5.3 

50 9,105 6.7 

2.5.9 Assessment of potential heat rate improvement via equipment upgrades 

The EPA inspected the study population to find examples of EGUs that made significant 

year-to-year improvements in heat rate. After filtering out those cases that may have been the 

result of changes in capacity factor, reporting method, or other events, we identified 16 EGUs 

that reported a single year-to-year heat rate improvement of 3-8%. In two of these cases we were 

able to identify equipment upgrades responsible for 2-3% heat rate improvement using the 

applicable estimates from the Sargent & Lundy 2009 study. Similarly, in the other cases, while 

our research was unable to confirm specific equipment upgrades, based on the elimination of 

other possible explanations we believe that equipment upgrades were the most likely cause of 

some of the observed heat rate improvements. 

Two other sources provide information about heat rate improvements after equipment 

upgrades at existing plants. EPA Region 7 provided data for seven coal-fired units at three 

anonymous plants with details on specific equipment modifications. These included turbine 

efficiency and condenser performance upgrades, installation of variable frequency drive fans, 

reducing boiler air in-leakage and others. Together, these measures achieved from 0.25% to 

3.5% heat rate improvement at the seven EGUs. 

An EPA study (SRA, 2001) describes WEPCO’s two-phase efficiency program at four 

coal-fired plants over a ten-year period. In the first phase, 1990 – 1994, WEPCO installed 

equipment upgrades that included retractable turbine packing, variable speed drives on the forced 

and induced draft fans, feed water heater replacements and new performance monitoring 

instrumentation. The four units reported heat rate improvements ranging from 2.3% – 4.1% as a 

result of the equipment upgrades. In the second phase, 1995-2000, WEPCO implemented 

changes that would generally fall into the best practices category: equipment control and 

metering upgrades, boiler cleaning, feed water heater improvements and reduced condenser air 

Comment [A36]: Do you really mean in a single

year to year change, as an indicator of a functional

change in the equipment?  Otherwise, 8% annual

improvement year after year is immense.  

Suggested edit, but change at EPA’s discretion.

EPA response: We meant one time – thank you.
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in-leakage and thermal losses. These gained an additional 0.5% per year heat rate improvement 

(for a total of 2.5%). 

The EPA also reviewed the engineering studies available in the literature and selected the 

Sargent & Lundy 2009 study as the basis for our assessment of heat rate improvement potentials 

from equipment and system upgrades. We focused on some thirteen heat rate improvement 

methods discussed by Sargent & Lundy, seen in Table 2-13. We used the average of the 

estimated $/kW costs for each method to develop the cost-ranked list of heat rate improvement 

methods (lowest cost at the top, highest at the bottom) shown in Table 2-13. The first nine items 

in Table 2-13 contribute about 15 percent of the total average $/kW cost for all items. We believe 

it is reasonable to consider those nine no-cost and low-cost heat rate improvement methods as 

belonging in the category of what has been described above as best practices. The remaining four 

methods are higher cost heat rate improvement items that we believe properly fall into the 

category discussed here as upgrades. Using an average of the ranges of potential Btu 

improvements estimated by Sargent & Lundy for the four upgrade methods, upgrades, as defined 

here, could provide a 4% heat rate improvement if all were applied on an EGU that has not 

already made these upgrades. 

Table 2-13. Sargent & Lundy Heat Rate Improvement Methods 

No-Cost and Low-Cost Options 

Condenser Cleaning 

Intelligent Soot Blowers 

ESP Modification 

Boiler Feed Pump Rebuild 

Air Heater and Duct Leakage Control 

Neural Network 

SCR System Modification 

FGD System Modification 

Cooling Tower Advanced Packing 

Higher Cost Options 

Economizer Replacement 

Acid Dew Point Control 

Combined VFD and Fan 

Turbine Overhaul 
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We also examined the annual heat rate trend line for each unit developed using the 

method of least squares. Using the slope of the trend line, 2002-2012, as an indicator of the heat 

rate performance of an EGU, a negative slope would indicate that the heat rate has improved. 

The annual trend line incorporates performance due to operating conditions (capacity factor, 

temperature), coal rank, maintenance, reporting method changes, equipment upgrades, and other 

factors. Over 40% of units have a positive slope. This would imply that equipment maintenance 

and upgrades at a significant fraction of the study population have not been sufficient even to 

maintain the status quo. 

2.5.10 Combined study population results 

The EPA’s analysis finds that a total of 6% heat rate improvements for the coal study 

population can be achieved through two types of changes: best practices that have the potential 

to improve heat rate by 4% and equipment upgrades that have the potential to improve heat rate 

by 2%. 

The best practices results are supported by the variability analysis using 11 years of 

hourly data applied to each unit. This analysis found that the top quartile of EGUs reported 

significantly lower heat rate variability than the study population average. Reducing heat rate 

variability will generally also improve heat rate performance, other factors held equal. We found 

that a 4% improvement is determined by conservatively reducing heat input by 30% of the 

difference between the reported value and p10 in each unit’s capacity factor and ambient 

temperature bins. The 30% approach is in the middle of the range of options shown in Table 2-12 

and is comparable to other approaches for measuring potential fleet heat rate improvement. For 

example, if each unit achieved heat rate performance equal to its best three-year moving average, 

the study population as a whole would post a 3.9% heat rate improvement. The best two-year 

moving average would achieve nearly a 5% improvement and the best single year over 6%. EPA 

believes that the minimum three-year moving average heat rate is a reasonable target for the 

improvement potential from applying best practices. Single year results could be due to unusual 

conditions, such as, an extended outage or weather. Using three consecutive years tends to 

smooth out the effect of equipment maintenance cycles and unusual meteorological patterns. 
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The equipment upgrades results are supported by numerous studies28 and by the EPA’s 

analysis of the costs and associated improvements in heat rate that can be attributed to equipment 

and system upgrades. We considered that a 4% reduction in heat rate might be achieved on a 

coal-steam unit by applying the four higher cost upgrade actions described in Table 2-13 above. 

However, because details of current actual unit configurations are unknown, and some units may 

have applied at least some of the upgrades, we conservatively estimate the heat rate improvement 

potential for upgrades at 2%. The EPA considers the results of this study to be applicable to the 

U.S. coal-fired fleet at large since the study population of EGUs accounted for over 96% of 2012 

electric sector CO2 emissions from coal. 

2.5.11 Sensitivity Analysis Removing Planned or Announced EGU Retirements 

The EPA’s research found 233 coal-fired, non-cogeneration EGUs that have announced 

they will retire before 2016.29 A sensitivity analysis was applied to the EGUs in the study 

population that plan to operate through 2015. The results are identical to the full population – 

both achieve a heat rate reduction of 4% under the 30 percent difference option described in best 

practices. 

2.6 Heat Rate Improvement – Economics 

Most of the methods that can be applied to achieve a sustained Heat Rate Improvement 

(HRI) on a coal-steam EGU will entail a capital cost. These HRI capital costs can be economic to 

incur if they yield sufficient reductions in other current or potential costs, particularly reductions 

in coal fuel cost and any cost related to CO2 emissions. For the purpose of this TSD analysis, it is 

assumed that HRI can be economic if the annualized net savings (coal cost savings plus CO2

emission cost savings minus capital cost) is positive: 

Annual Net HRI Savings = Coal Cost Savings + CO2 Emission Cost Savings – Capital Cost30

                                                            

28 See discussion in Table 2-3 above, and the HRI Partial Bibliography at the end of this section 

29 IPM documentation includes a list of the announced retirements. See Table 4-36 of IPM Documentation: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/Chapter_4.pdf and 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/NEEDS_v513.xlsx 30 This TSD analysis assesses a broadly combined application of multiple HRI methods. As estimated in the 2009 

Sargent & Lundy study most HRI-related O&M costs are sufficiently small relative to the associated annualized 

capital costs, such that they do not materially affect the economics of broadly combined HRI methods. The analysis 

therefore does not consider the small economic impact of HRI-related O&M costs. 

Comment [A37]: This is an important statement,

that is accorded little explanation.  I presume these

are coal EGUs? And is it plants or separate units?  

How did these anticipated requirements factor into

the state goal setting, and then into the IPM

modeling?   

EPA response: See updated footnote with IPM

source.
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2.6.1 Heat Rate Improvement Capital Cost Assumption 

The 2009 Sargent & Lundy study describes numerous well known and technically proven 

HRI methods for coal-steam EGUs. The study includes an estimated min-max range of heat rate 

improvement, and the min-max range of associated capital cost for each HRI method, for units 

ranging in size from 200 MW to 900 MW. If these methods and unit sizes are combined, as 

though they were all applied on a single EGU, the following range of Sargent & Lundy estimated 

Btu reductions and associated range of capital costs are obtained: 

Combined Min-Max HRI Btu Reduction: 415-1205 Btu 

Combined Min-Max HRI Capital Cost: $40-150/kW31

EPA Assumed Combined HRI Capital Cost: $100/kW 

The wide ranges of estimated HRI Btu and costs are indicative of the wide range of real 

differences in the many details of site specific EGU designs, fuel types, age, size, ambient 

conditions, current physical condition, etc. This TSD analysis therefore assumes $100/kW as a 

representative combined HRI capital cost to achieve whatever HRI Btu reduction is possible at 

an average site. The effect of a lower HRI cost is also examined. 

2.6.2 Heat Rate Reduction Assumption 

The weighted average annual net heat rate of the U.S. coal-steam EGU fleet in 2020 is 

projected at 10,450 Btu/kWh in the EPA’s IPMv5.13 Base Case modeling. As indicated by the 

Sargent & Lundy estimates given above, HRI methods could possibly reduce this average coal 

fleet heat rate by about 400 to 1200 Btu/kWh, or by about 4% to 12% of the projected 2020 

average, provided that all units were able to apply all of the combined HRI methods. The proviso 

is important to this analysis because the EPA expects that a significant fraction of the coal fleet 

has already applied some or many of the available HRI methods.32 

                                                            

31 Note that highest cost does not necessarily align with greatest heat rate improvement. A low cost HRI method

can have a large HRI potential (e.g., upgraded digital control system, neural network). Also, economy of scale

causes most HRI methods to be more costly ($/kW) on smaller unit sizes.   32 Based on the EPA informal discussions with Sargent & Lundy and other power sector engineering firms. The 

EPA has found no comprehensive data set on the extent to which specific HRI methods have already been applied at 

individual EGUs. The EPA believes that many EGU owners consider such information to be confidential. 
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The EPA does not have sufficient site specific information to accurately estimate what 

percentage of the fleet has adopted various HRI methods, nor how effectively, and is not aware 

of any other investigator having sufficient information. HRI potential can therefore not be 

estimated at this time through analysis of the current equipment configurations of the coal steamEGU fleet. The EPA therefore analyzed 11 years of historical heat rate data and the literature on 

HRI methods, as discussed earlier in this TSD, to estimate that the U.S. coal-steam EGU fleet 

might reasonably be expected to reduce its annual average gross heat rate by about 6%. 

The EPA understands that any HRI method that reduces gross heat rate will also reduce 

net heat rate, and that some HRI methods reduce net heat rate without reducing gross heat rate. 

We expect that the HRI potential on a net output basis is somewhat greater than on a gross output 

basis, primarily through upgrades that result in reductions in auxiliary loads. For purposes of this 

TSD the EPA conservatively assumes that the coal fleet average net heat rate can be reduced by 

6%. 

2.6.3 Heat Rate Improvement Breakeven Economic Analysis 

Figure 2-6 presents a simple breakeven economic analysis for combined HRI methods 

using the assumptions described above, also assuming there is no CO2 emission cost that is 

reduced via HRI. 

Figure 2-6. HRI Breakeven Economics 

Notes: 

0.00

0.50

1.00

1.50

2.00

2.50

3.00

1.00 2.00 3.00 4.00

$/MWh‐net

Coal Cost  $/MMBtu

Coal Cost Savings   $/MWh‐net Capital Cost  $/MWh‐net

HRI Capital Cost = $100/kW
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1. Capital cost S/MWh assumes the following: HRI capital cost = $100/kW; capital charge rate 

= 14.3%; IPM projected 2020 annual capacity factor = 78% 

2. Coal fleet average 2020 net heat rate = 10,450 Btu/kWh; heat rate reduction = 6% 

Figure 2-6 shows that the average fleet-wide savings in coal cost would become greater 

than the annualized capital cost of an average 6% reduction in heat rate when the average fleetwide coal cost exceeds about $3.25/MMBtu. For comparison, the average U.S. power sector 

delivered cost of coal in 2020 is projected in EPA’s IPMv5.13 Base Case modeling at 

$2.62/MMBtu. For different assumptions, the HRI economic breakeven point would change 

directionally as follows: 

 If the HRI capital cost were on average less than the assumed $100/kW, 6% HRI would 

then become economic at lower coal costs. For example, if the average capital cost were 

actually $75/kW, a fleet-wide 6% HRI would become economic at an average coal cost 

of about $2.50/MMBtu, which is comparable to the U.S. power sector average costs of 

$2.38/MMBtu for all coal ranks and $2.89/MMBtu for bituminous coals in 2012.33 This 

sensitivity indicates that fuel cost savings alone would make it economic for some of 

those EGUs currently using high cost bituminous coals to make HRI investments. 

 At an EGU net heat rate that is higher than the IPM projected 2020 average value of 

10,450 Btu/kWh, 6% HRI could be economic at coal costs lower than the values 

mentioned above. 

 If the average heat rate reduction were only 4% instead of the assumed 6%, at a cost of 

$100/kW, average coal costs would have to exceed $4/MMBtu for 4% HRI to be 

economic fleet wide, 

 But, if the average heat rate reduction were 4% at a cost of $50/kW, HRI could become 

economic at an average coal cost of about $2.50/MMBtu. 

 If there were additional HRI savings due to avoided future CO2 emission costs, HRI 

could become economic at lower coal costs, or at higher capital costs, or at lower heat 

rate reduction percentages. 

                                                            

33 EIA, Electricity DataTable 7.4, Average Weighted Cost of Fossil Fuels for the Electric Power Industry 2002-

2012, http://www.eia.gov/electricity/annual/html/epa_07_04.html 
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2.6.4 U.S. Coal-steam EGUs – Estimated Fleet-wide CO2 Reduction and Cost via HRI 

It is possible to make an order-of-magnitude estimate of the fleet-wide extent and costeffectiveness of HRI using reasonable assumptions as in the following example: 

Fleet-wide 2020 Assumptions (basis: similar to IPMv5.13 Base Case): 

 Coal fleet capacity applying combined HRI methods = 244,000 MW 

 Average CO2 emission rate = 0.976 tonne/MWh net 

 Average net heat rate = 10,450 Btu/kWh net 

 Average capacity factor = 78% 

 Pre-HRI CO2 emissions = 1.62 billion tonne/yr (calculated) 

 HRI Btu and CO2 reduction = 6% 

 HRI capital cost = $100/kW 

 Annual capital charge rate = 14.3% 

 Average coal cost = $2.62/MMBtu 

Estimated Fleet-wide Results: 

 Fleet-wide CO2 reduction via HRI = 97 million tonne/yr 

 Total HRI capital cost = $24 billion 

 Annualized HRI capital cost = $3.5 billion 

 Annual coal cost savings (cost) = $2.7 billion 

 Annual net savings (cost) = ($0.8 billion) 

 Annual net savings (cost) of CO2 reduction = ($7.7/tonne) 

2.6.5 Conclusion - HRI Economics 

This necessarily simplified HRI economic analysis supports the following summary conclusions: 

 Some degree of HRI is already economic for high heat rate – high coal cost EGUs 

 If a fleet-wide average 6% HRI is technically feasible, it would also be economic on the 

basis of fuel savings alone, before consideration of the value of the associated CO2

emission reductions, on a fleet-wide basis at today’s coal prices if the associated average 

capital cost is about $75/kW or less. 

Comment [A38]: Throughout the paper, it might

help to indicate the “fleet‐ wide” data refer to the

national fleet (i.e. all the coal facilities in the U.S.) if

this is the case.

  

EPA response: Thank you for the suggestion.  See

new section heading above.

Comment [A39]: It was ostensibly 44% in 2012 –

see Table 2‐5, page 19 above – or am I missing

something?  Please clarify.  Is this assuming a lot of

coal plant closures to get the capacity factor up?  If

so, please clarify the discrepancy/change over time

in the text and how this might affect state goal

setting,  especially building block 2?

EPA response: Good catch. See revised Table 2‐5

and associated text.  Also see the RIA and other TSD

discussions regarding IPM Base Case assumptions,

resulting 2020 coal capacity, etc.
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 If a fleet-wide average 6% HRI is technically feasible, and the associated average capital 

cost is as much as $100/kW, 6% HRI could become economic on the basis of fuel 

savings alone, before consideration of the value of the associated CO2 emission 

reductions, if/when average coal prices rise to about $3.25/MMBtu (IPM projects coal at 

$2.62/MMBtu in 2020). 

 Even at a capital cost of $100/kW and an IPM projected 2020 coal price of 

$2.62/MMBtu, the fleet-wide cost of CO2 reduction via 6% HRI would be a relatively 

low $7.7/tonne. 

Thus, although there is currently some uncertainty associated with the costs of achieving a 

particular fleet-wide amount of HRI, it is clear that HRI is an available low-cost approach to CO2

reduction for existing coal-fired EGUs 

Definitions/Abbreviations

Btu British thermal unit 

capacity factor 

electricity generation expressed as a percentage of maximum 

electricity generation (i.e., actual generation / maximum potential 

generation) 

CO2 carbon dioxide 

EGU electric generating unit 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

heat input amount of energy consumed in a combustion unit (e.g., boiler) 

expressed in Btu 

heat rate improvement decrease in the amount of heat input required to generate 1 kWh of 

electricity 

heat rate gross heat input required to generate 1 kWh of electricity, expressed 

in gross Btu/kWh. 

MMBtu million Btu 

MW megawatt 

PC pulverized coal (boiler) 

RSD Relative standard deviation 

S & L report 

Sargent & Lundy engineering study on the potential heat rate 

improvement from equipment upgrades (EPA 2009 version) 

[Available at: 

http://www.epa.gov/airmarket/resource/docs/coalfired.pdf] 

start 

a startup event in which an EGU begins combusting fossil fuel and 

generates some measurable amount of electricity before ceasing fossil 

fuel combustion 

unit-year data for one EGU over a one year period 
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Docket Datasets 

Name Description 

hour_QA_data.txt 2002-2012 hourly dataset 

hour_QA_regression_data.txt 2002-2012 hourly dataset for regression analysis 

units_885.txt List of study units and characteristics 

year_bin_10_50_data.txt 2002-2012 unit-year binned results at 10 – 50% difference 

options 
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HRI Partial Bibliography   

PowerEng 2002, “Heat Rate Optimization Pays Dividends,” Power Engineering, January 1, 

2002, available at http://www.power-eng.com/articles/print/volume-106/issue-1/features/heatrate-optimization-pays-dividends.html

NETL 2008, Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired 

Power Plant Fleet, DOE/NETL-2008/1329, July 2008 

NETL 2009, Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants, 

Workshop Report, NETL July 2009, available at http://www.netl.doe.gov/energyanalyses/pubs/NETL%20Power%20Plant%20Efficiency%20Workshop%20Report%20Final.pdf

NETL 2010, Improving the Thermal Efficiency of Coal-Fired Power Plants in the United States, 

DOE/NETL Technical Workshop Report, February 2010, available at 

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEf

ficCoalFiredPowerPlants-TechWorkshopRpt.pdf

NETL 2010a, Improving the Efficiency of Coal-Fired Power Plants for Near Term GHG 

Emissions Reductions, DOE/NETL-2010/1411, April 2010, available at 

http://www.alrc.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=307

Sargent & Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, 

January 2009, available at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf

Storm 2009, “Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal 

Fueled Boilers, Storm Technologies, Inc, EPRI 2009 Heat Rate Conference, available at 

http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf

NRDC 2013, Closing the Power Plant Carbon Pollution Loophole, NRDC Report R:12-11-A, 

March 2013 available at http://www.nrdc.org/air/pollution-standards/files/pollution-standardsreport.pdf

Lehigh 2009, Reducing Heat Rates Of Coal-Fired Power Plants, Lehigh Energy Update, January 

2009, available at http://www.lehigh.edu/~inenr/leu/leu_61.pdf

ESC/OnLocation, Efficient Heat Rate Benchmarks for Coal-Fired Generating Units, draft, B. 

Roberts, Economic Sciences Corporation, L Goudarzi, OnLocation, Inc., 1998, available at 

http://www.onlocationinc.com/heatratepaper.pdf

CRS 2013, Increasing the Efficiency of Existing Coal-Fired Power Plants, Congressional 

Research Service, December 2013, available at http://www.fas.org/sgp/crs/misc/R43343.pdf

Evonik/VGB 2008, “Power Plant Performance Reporting and Improvement under the Provision 

of the Indian Energy Conservation Act – Output 1.1”, Evonik/VGB 2008, available at 

http://www.emt-india.net/PowerPlantComponent/Output1.1/Output1.1.pdf

IEA 2010, Power Generation from Coal - Measuring and Reporting Efficiency Performance and 

CO2 Emissions, OECD/IEA-CIAB 2010, available at 

http://www.iea.org/ciab/papers/power_generation_from_coal.pdf

EPRI 2009, Renewed Interest in Reducing Heat Rate, EPRI Journal, Spring 2009, available at 

http://mydocs.epri.com/docs/CorporateDocuments/EPRI_Journal/2009-

Spring/1019287_Heat%20Rate.pdf
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EPRI/Korellis 2011, Identifying Ways to Improve Plant Heat Rate, Energy-Tech Magazine, 

March 2011, available at http://www.energy-tech.com/article.cfm?id=30528

EPRI 2011a , Opportunities to Enhance Electric Energy Efficiency in the Production and 

Delivery of Electricity, EPRI Technical Report 1024651, November 2011, available at 

http://www.google.com/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=1&ved=0CCsQF

jAA&url=http%3A%2F%2Fwww.pserc.wisc.edu%2Fdocuments%2Fpublications%2Fspecial_in

terest_publications%2FEPRI_Electricity_Use_Report_Final_1024651.pdf&ei=Qo9yUvmwMY

Xb4AOZz4GYAw&usg=AFQjCNElzekbtoSNCR5SKFwkfbKx83p0Uw&bvm=bv.55819444,d.

dmg

RFF 2013, Regulating Greenhouse Gases from Coal Power Plants under the Clean Air Act, RFF 

DP 13-05, February 2013, available at http://www.rff.org/RFF/documents/RFF-DP-13-05.pdf