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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 use 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 use 

in developing plans to attain the state-specific goals. This 

rule, as proposed, would set in motion actions to reduce carbon 

dioxide emissions from the electric power sector in the United 

States.

DATES: Comments. 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]. Under the Paperwork Reduction 

Act (PRA), since the Office of Management and Budget (OMB) is 
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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 

speakers who arrive and register. Because this hearing is being 

held at U.S. government facilities, individuals planning to 
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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 

limited to 5 minutes for each commenter. The EPA encourages 

commenters to provide the EPA with a copy of their oral 
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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. 

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

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

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 
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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 

contact information unless you provide it in the body of your 

comment. If you send an email comment directly to the EPA 
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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 

is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 

excluding federal holidays. The telephone number for the Public 
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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 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CEMS Continuous Emissions Monitoring System 

CHP Combined Heat and Power 
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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 

PSB Public Service Board 

PUC Public Utilities Commission 

REC Renewable Energy Credit 

RES Renewable Energy Standard 
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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 

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. Affected Sources and Combining Categories 

A. Affected Sources 

B. Combining Categories 

VI. Building Blocks for Setting State Goals and Considerations 

A. Introduction 
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B. Building Blocks for Setting State Goals 

C. Detailed Discussion of Building Blocks and Other Options 

Considered 

D. Determination of the Best System of Emission Reduction 

VII. State Goals 

A. Overview 

B. Form of Goals 

C. Proposed Goals and Computation Procedure 

D. State Flexibilities 

E. Alternate Goals and Other Approaches Considered 

F. Reliable Affordable Electricity 

VIII. State Plans 

A. Overview 

B. Approach 

C. Criteria for Approving State Plans 

D. State Plan Components 

E. Process for State Plan Submittal and Review

F. State Plan Considerations

G. Additional Factors That Can Help States Meet Their CO2

Emission Performance Goals

H. Resources for States to Consider in Developing Plans

IX. Implications for Other EPA Programs and Rules 

A. Implications for NSR Program 

B. Implications for Title V Program 

C. Implications for Other EPA Rules 

X. Impacts of the Proposed Action 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment impacts? 

E. 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 
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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 

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. 

GHG pollution threatens Americans' health and welfare by 

leading to potentially rapid but 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 84 percent of U.S. GHG emissions. 

Fossil fuel-fired EGUs are, by far, the largest emitters of 
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GHGs, primarily in the form of CO2, among stationary sources in 

the U.S. While much of the existing U.S. fleet of fossil fuelfired EGUs began operations in the 20th century, advancements, 

innovation and changes in economics in power sector 

technologies, fuel sources and production, demand-side 

management, and energy efficiency are leading to changes in 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 under CAA section 111(d) by which 

states can develop and implement plans to 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 energy 

strategies already being used by a number of States and 

companies in meeting the CO2 goals set forth in this proposal. 

In moving forward with those actions, states can rely on 

and extend plans they may already have underway to continue the 

development of their energy systems. Those states committed to 

Integrated Resource Planning (IRP) would be able to establish 

their plans within that framework to meet the CO2 goals proposed 

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

economic interests of their utilities and ratepayers, by 
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reducing costs and avoiding stranded asset risks using the 

flexibilities in this proposed action and working in concert 

with other states to put in place regional approaches reflecting 

the multi-state structure of electricity operating systems 

already critical to ensuring a reliable supply of affordable 

energy. 

Under CAA section 111(d), 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).1 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 BSER. 

 

1

 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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While the EPA must establish BSER and is proposing goals 

that reflect BSER, CAA section 111(d) also provides the EPA with 

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 required to use each of the 

measures that the EPA determines constitute BSER or use those 

measures to the same degree of stringency that the EPA 

determines is achievable and cost-effective. Thus, a state could 

choose to achieve more reductions from one BSER measure and less 

from another or use measures that were not part of the EPA’s 

BSER determination, as long as the state achieves the reductions 

necessary to meet its goal. 
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This preamble sets forth the EPA’s proposal for BSER and 

guidelines for states to use in developing their plans. The 

preamble describes the EPA’s approach to determining BSER and 

setting state goals and lays out proposed expectations for state 

plans, along with discussion of other options that the EPA has 

considered. 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 input the EPA sought beginning in 

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 ensure 

that in concert with the provisions of 110 and 112, new and 

existing major stationary sources address all major air 

pollutants. In this 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. These requirements 

call on the EPA to develop emission guidelines, which include 
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determining BSER. In general, the states must follow these 

guidelines, including adhering to their stringency in requiring 

emission reductions, in developing state plans. These 

requirements authorize the EPA to develop emission reduction 

goals based on the application of 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 the power sector.2

 

The CAA identifies the 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 CO2

emissions from existing fossil fuel-fired EGUs: making emission 

rate improvements at affected EGUs (e.g., by improving heat 

rates or switching to lower carbon fuels) and limiting emissions 

of the fossil fuel—fired EGU category as a whole (e.g., by 

shifting dispatch from higher carbon-emitting EGUs to lower 

carbon-emitting EGUs and by employing demand-side energy 

 

2

 [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).]
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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 companies are already employing to reduce CO2

emissions from fossil fuel-fired EGUs. For example, 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. Such 

strategies and the proposed BSER determination reflect the fact 

that, in almost all states, the production of electricity can be 

undertaken, at least to some extent, interchangeably between and 

among multiple generation facilities and different types of 

generation. As a result, the agency, in quantifying state goals 

(and the states in devising plans to meet those goals) can 

assess what combination of electricity production, or energy 

demand reduction, across generation facilities can offer the 

most cost-effective approach to achieving GHG emission 

reductions. States, in turn, can look broadly at opportunities 

across their electricity system 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 goals. 
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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 limit overall CO2

emissions from fossil fuel-fired EGUs. These measures can be 

grouped into four main categories, or “building blocks,” both 

for formulating state goals and for constructing broad-based, 

cost-effective, long-term strategies to reduce CO2 emissions on 

the part of the states. The EPA believes that each of the 

building blocks represents a method of CO2 emission reduction at 

fossil fuel-fired EGUs that, when combined with the other 

building blocks, represent the “best system of emission 

reduction... adequately demonstrated” for fossil-fuel-fired 

EGUs. The building blocks are: 

1. Lowering the carbon intensity of generation at 

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

improvements); 

2. Reducing emissions of the most carbon-intensive 

affected EGUs to the extent that this can be accomplished 

cost-effectively by shifting generation to less carbonintensive existing fossil fuel-fired EGUs, including NGCC 

units that are under construction; 
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3. Reducing emissions of carbon-emitting EGUs to 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-emitting EGUs to the 

extent that this can be accomplished cost-effectively by 

increasing demand-side energy efficiency. 

The four building blocks are described in detail in 

Sections VI and VII of this preamble. 

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 determining BSER, we have 

considered these ranges, in light of statutory factors, and we 

have identified goals that we feel 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 that companies and states are already taking to 

reduce GHG emissions and with current trends in the electric 

power sector, driven by efforts to reduce GHGs, as well as by 
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other factors, such as advancements in technology. Reliance on 

all four building blocks in this way also supports the goals of 

achieving meaningful, cost-effective, and technically feasible 

reductions of CO2, and promotes technology and approaches that 

are important for achieving further reductions, all while 

providing the states with a balance of flexibility and 

direction. 

Recognizing that states differ in important ways, including 

in their mix of existing EGUs, and consequently that 

opportunities to reduce EGUs’ emission rates and limit each 

EGU’s overall 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 

state-specific data in order to determine state-specific goals. 

This use of building blocks aligns with key messages from 

stakeholders provided during the EPA’s recent, extensive public 

outreach process, notably the desire for flexibility and 

recognition of varying state circumstances. The state-specific 

approach 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 
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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 and/or 

strategies not explicitly spelled out in any of the four 

building blocks and use those technologies and/or strategies as 

part of their overall plan. This approach also allows regional 

compliance strategies. The agency also recognizes the important 

functional relationship between the timing of measures and their 

stringency. Because the EPA is proposing a 10-year period over 

which to achieve the full required CO2 reductions, 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 ratebased 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. 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 
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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 through implementation of the four building blocks 

described above to achieve reductions in overall CO2 emissions at 

affected EGUs. The proposed state-specific goals are intended to 

demonstrate the level of reductions in CO2 emissions and emission 

rates and the level of stringency of the application of the 

building blocks that would be presumptively approvable in a 

state plan. 

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. 
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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 timing, to the state-specific rate-based goal set by 

the EPA. 

We believe that this approach to establishing requirements 

for state plans is responsive to the range of viewpoints 

expressed by stakeholders regarding the simultaneous need for 

both flexibility and clear guidance on what would constitute an 

approvable state plan. We likewise believe that this approach 

represents a reasonable balance, 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. We view the proposed goals as providing 

rigor where rigor is required by the statute, while providing 

states with flexibility where flexibility is permitted by the 
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statute. This approach is also 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. 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 carbonintensive fuels to a more sustainable system that puts greater 

reliance on renewable energy, energy efficiency, and demand-side 

management. 

c. State plans 

i. Approach 

Each state would determine, and include in its plan, an 

emission performance level that is equivalent to the statespecific CO2 goals in the emission guidelines. As part of 

determining this level, the state would 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. 
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In this action, the EPA is proposing emission guidelines 

that, in addition to establishing the state-specific goals, 

include approvability criteria, requirements for state plan 

components, and requirements for the process and timing for 

state plan submittal and 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 emission 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-only 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 address 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 
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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. 

ii. State plan components 

The EPA is proposing to evaluate and approve each of the 

ten components of a state plan based on four general criteria: 

1) enforceable measures that reduce EGU CO2 emissions; 2) 

projected achievement of emission performance equivalent to the 

goals established by the EPA, on a timeline equivalent to that 

in the emission guidelines; 3) quantifiable and verifiable 

emission reductions; and, 4) a process for reporting on plan 

implementation, progress toward achieving CO2 goals, and 

implementation of corrective actions, if necessary. In addition, 

each state plan must follow the EPA framework regulations at 40 

C.F.R. 60.23 – 60.29 and include the following twelve components 

for the EPA to evaluate and approve the plan: 

 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 
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 Demonstration that each emissions standard is quantifiable, 

surplus, 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, 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 the 9 months specified 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 a 

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, then the state may 

submit an initial plan by June 30, 2016. This initial plan must 
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meet specific criteria for approval, including a justification 

for why more time is needed, a requirement to maintain existing 

measures that limit CO2 emissions, and an explanation of the path 

to completion. 

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, the 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-month period 

provided in the EPA framework regulations to 6 months. 

v. Timing of compliance 
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 The agency is proposing that states must 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. 

vi. Key considerations for state plans 

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 
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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. 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, has collected available resources and is making these 

available at an EPA website.3 

3. Projected national-level emission reductions 

Under the proposed rule, the EPA projects annual CO2

reductions of 25 to 30 percent below 2005 levels (ranges reflect 

ongoing evaluation of building block 3 alternatives, and the 

rest of the preamble is being modified to reflect these 

ranges). 

4. Costs and benefits 

Actions taken to comply with the proposed guidelines will 

reduce CO2 emissions from the electric power industry, as well as 

other fossil-fuel-fired EGU emissions including directly emitted 

 

3

 [Add address for the EPA website]
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fine particulate matter (PM2.5), sulfur dioxide (SO2) and nitrogen 

oxides (NOX). States will make the ultimate determination as to 

how the emission guidelines are implemented, thus all costs and 

benefits reported for this action are illustrative estimates. 

The EPA 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 is important to also note that there are benefits that 

the EPA could not monetize. The EPA could not monetize important 

benefits. 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. 

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 
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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, 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 

programs are described in Section IX, and impacts of the 

proposed action are described in Section X. 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. 
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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 new affected sources, and the rulemaking for 

modified and reconstructed sources that the EPA is proposing at 

the same time as the present 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 anything 

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 

to as the Endangerment Finding under CAA section 202(a)(1).4

 In 

the Endangerment Finding, which focused on public health and 

 

4

 “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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public welfare impacts within the United States, the 

Administrator found that elevated concentrations of GHGs in the 

atmosphere may reasonably be anticipated to endanger public 

health and welfare of current and future generations. We 

summarize these adverse effects on public health and welfare 

briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Anthropogenic emissions of GHGs and consequent climate 

change threaten public health in multiple aspects. 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 to reductions in 

cold-related mortality, evidence indicates that the increases in 

heat mortality will be larger than the decreases in cold 

mortality. Climate change is expected to increase ozone 

pollution over broad areas of the country, including large 

population areas with already unhealthy surface ozone levels, 

and thereby increase morbidity and mortality. Other public 

health threats also stem from 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 
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storms and storm surges due to rising sea levels are expected to 

cause increased drownings and other health impacts. Children, 

the elderly, and the poor are among the most vulnerable to these 

climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding 

Anthropogenic emissions of GHGs and consequent climate 

change also threaten public welfare in multiple aspects. Climate 

changes are expected to place large areas of the country at 

serious risk of reduced water supplies, increased water 

pollution, and increased occurrence of extreme events such as 

floods and droughts. Coastal areas are expected to face 

increased risks from storm and flooding damage to property, as 

well as adverse impacts from rising sea level, such as land loss 

due to inundation, erosion, wetland submergence and habitat 

loss. Climate change is expected to result in an increase in 

peak electricity demand, and extreme weather from climate change 

threatens energy, transportation, and water resource 

infrastructure. Climate change may exacerbate ongoing 

environmental pressures in certain settlements, particularly in 

Alaskan indigenous communities. Climate change also is very 

likely to fundamentally rearrange U.S. ecosystems over the 21st

century. Though some benefits may balance adverse effects on 
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agriculture and forestry in the next few decades, the body of 

evidence points towards increasing risks of net adverse impacts 

on U.S. food production, agriculture and forest productivity as 

temperature continues to rise. These impacts are global and may 

exacerbate problems outside the U.S. that raise humanitarian, 

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

3. New scientific assessments 

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

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

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

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

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

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

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

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

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 

such assessments have been released. These assessments include 
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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 2013 Fifth 

Assessment Report (AR5), 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 endangering 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 
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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.5

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.”6

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

that: 

Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe. Therefore, 

emission reductions choices made today matter in 

determining impacts experienced not just over the next 

few decades, but in the coming centuries and millenia.7

 

 

5

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

1.

6

 Ibid, p.138.

7

 National Research Council, Climate Stabilization Targets, 

p. 3. 
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Moreover, due to the time-lags inherent in the Earth’s 

climate, the NRC assessment notes that the full warming from any 

given concentration of CO2 reached will not be realized for 

several centuries. 

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. 

At the time of the 2009 Endangerment Finding, the concentration 

of carbon dioxide was 387 parts per million.8

 As of the date of 

signature of this proposed rulemaking, the concentration is [XX 

– likely higher than 398] parts per million.9

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 

 

8

 

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

9

 http://www.esrl.noaa.gov/gmd/ccgg/trends/
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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 Sinks10 (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 sinks11 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.))12

SECTOR 1990 2005 2012 

Energy 5,256.5 6,239.4 5,489.6

Industrial Processes 316.1 330.2 319.6

Solvent and Other 

Product Use 4.4 4.4 4.4 

Agriculture 

 

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

2012”, Draft Report, United States Environmental Protection 

Agency, February 2014. 

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

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

forests or underground or deep sea reservoirs of carbon dioxide.

12 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2012, Draft Report, United States 

Environmental Protection Agency, February 2014. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 
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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 6,229.6 7,244.9 6,501.5 

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.4)

Net Emissions (Sources 

and Sinks) 5,398.5 6,214.2 5,522.1 

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.9 percent of total 

2012 GHG emissions. 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. 

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.) 

GHG EMISSIONS 1990 2005 2012 

Total CO2 from fossil fuel 

combustion EGUs 1,820.8 2,402.1 2,023.6 

 - from coal 1,547.6 1,983.8 1,512.2

 - from natural gas 175.3 318.8 492.2 
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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 

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. 

 - from petroleum 97.5 99.2 18.8 
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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 

health or welfare.”13 EPA has listed more than 60 stationary 

source categories under this provision.14 Once EPA lists a source 

category, EPA must, under CAA section 111(b)(1)(B), establish 

 

13 CAA §111(b)(1)(A). 

14 See 40 CFR 60 subparts Cb – OOOO. 
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“standards of performance” for emissions of air pollutants from 

new sources in the source categories. 15 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 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 

 

15 CAA §111(b)(1)(B), 111(a)(1). 
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“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.” 16 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.17 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 on its lands,18 the tribe would 

have the opportunity, but not the obligation, to establish a CO2

performance standard and a plan for its tribal lands. 

 

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

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

18 The EPA is aware of at least three 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 Bonanza Generating 

Station. All three are coal-fired EGUs. 
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The EPA issued regulations implementing CAA section 111(d) 

in 1975,19 and has revised them in the years since.20 (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.21 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,22

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

months of the due date for those plans,23 although the EPA has 

authority to extend those deadlines.24 In the present rulemaking, 

the EPA is following the requirements of the implementing 

 

19 “State Plans for the Control of Certain Pollutants From 

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

20 [Cites] 

21 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. 

22 40 CFR 60.23(a)(2). 

23 40 CFR 60.27(b). 

24 See 40 CFR 60.27(a). 
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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)).25 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.26 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 

characteristics of carbon pollution and the interconnected 

nature of the power sector, especially the fact that increments 

of generation are interchangeable between and among sources in a 

way that creates options for relying on varying utilization 

 

25 [Cites] 

26 [Cites] 
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levels, lowering carbon generation, and reducing demand as 

components of the overall method for reducing CO2 emissions. 

Doing so results in a broader, forward-thinking approach to the 

design of programs to yield critical CO2 reductions that improve 

the overall power system by lowering the carbon intensity of 

power generation, while offering continued reliability and costeffectiveness. 

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 a Memorandum to 

the Administrator (June 25, 2013), 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 
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the same time, with leaders in the power sector, labor 

leaders, non-governmental organizations, other experts, 

tribal officials, other stakeholders, and members of the 

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

2. Educating the public and stakeholder outreach 

To carry out this stakeholder outreach, the EPA embarked on 

an unprecedented, pre-proposal outreach effort. From consumer 

groups to states to power plant owner/operators to technology 

innovators, the EPA sought input from all perspectives. 

The EPA began the outreach efforts with a webinar and 

associated teleconferences to establish a common understanding 

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

August 27, 2013 overview presentation was offered as a webinar 

for state and tribal officials, “Building a Common 

Understanding: Clean Air Act and Upcoming Carbon Pollution 

Guidelines for Existing Power Plants.” 

The EPA followed up on the presentation by offering four 

national teleconference calls with representatives from states, 

tribes, industry, environmental justice organizations, community 

organizations and environmental representatives. The 

teleconferences offered a venue for stakeholders to ask 

questions of the EPA about the overview presentation and for the 

EPA to gather initial reactions from stakeholders. Stakeholders 
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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 

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

included in the informational docket that was established as a 

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

specific comments or issues raised during the outreach effort. 

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

the information we relied on for this action. 

The agency has encouraged, organized, and participated in 

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

carbon pollution from existing power plants. Attendees at these 

various meetings have included states and tribes, members of the 

public, and representatives from multiple industries, labor 

leaders, environmental groups and other non-governmental 

organizations. The direct engagement has brought together a 

variety of states and stakeholders to discuss a wide range of 

issues related to the electricity sector and the development of 

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

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

The meetings were attended by the EPA Regional Administrators, 

managers and staff and who 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 
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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 has taken information from these meetings and used it to 

inform this proposal. 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 a dialog with 

states and stakeholders will continue 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 
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development and ultimate implementation of this upcoming rule to 

attend and learn from the views expressed. 

More than 1,600 people spoke at the 11 listening sessions. 

Speakers included Members of Congress, other public officials, 

industry representatives, faith-based organizations, unions, 

environmental groups, community groups, students, public health 

groups, energy groups, academia and concerned citizens. 

Participants shared a range of perspectives. Many were concerned 

by the impacts of climate change on their health and on future 

generations, others worried about the impact of regulations on 

the economy. Their support for the agency’s efforts varied. 

Summaries of these 11 public listening sessions are 

available at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020. 

4. State officials 

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 may benefit from working 

together to address the requirements of this rulemaking 

implementation. The meetings provided state leaders, including 
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governors, environmental commissioners, energy officers, public 

utility commissioners, and air directors, opportunities to 

engage with the EPA officials. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 

experience in reducing carbon pollution from power plants. The 

agency has collected policy papers from states with overarching 

energy goals and technical details on the states’ electricity 

sector. The agency has engaged, and will continue to engage 

with, all of the 50 states throughout the rulemaking process. 

5. Tribal officials 

 The EPA conducted significant outreach to tribes, who are 

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

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

located in Indian country but is not aware of any power plants 

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. 
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The EPA sent consultation letters to 584 tribal leaders. 

The letters provided information regarding the EPA’s development 

of emission guidelines for existing power plants and offered 

consultation. None have requested consultation. Tribes were 

invited to participate in the national informational webinar 

held August 27, 2013. In addition, a consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA 

representatives also met with tribal environmental staff with 

the National Tribal Air Association, by teleconference, on 

December 19, 2013. In those teleconferences, the EPA provided 

background information on the GHG emission guidelines to be 

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

In addition, the EPA held a series of listening sessions 

prior to development of this proposed action. Tribes 

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

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

September 26, 2013. 

6. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in scores of one-on-one 

and national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 
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sponsored by stakeholder groups. Due to the focus of the 

standard on the electricity sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the electricity sector. The agency has also 

met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

have expertise in renewable energy and energy efficiency. Other 

meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries 

to help understand the issues related to large industrial users 

of electricity. 

7. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations. The meetings focused on the 

importance of the utility industry in reducing carbon emissions 

from power plants. Power plant emissions are central to this 

rulemaking. The EPA encouraged industry representatives to work 

with state environmental and energy officers. 

The electric utility representatives included private 

utilities or investor owned utilities. Public utilities and 

cooperative utilities were also part of in-depth conversations 

about CAA section 111(d) with EPA officials. 
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The conversations included meetings with the EPA 

headquarters and Regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy, and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 

8. Electricity grid operators 

The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

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

Council on several occasions to collect their ideas. The EPA 

Regional Offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

9. Representatives from non-governmental organizations 

Agency officials engaged with representatives of 

environmental justice organizations during the outreach effort, 

including outreach to the National Environmental Justice 

Advisory Committee members in September 2014. 
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 The EPA has also met with a number of environmental groups 

to provide their ideas on how to reduce carbon pollution from 

existing power plants using section 111(d) of the CAA. 

Many environmental organizations discussed the need for 

reducing carbon pollution. Meetings were technical, policy and 

legal in nature and many groups discussed specific state 

policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. 

 Public health groups discussed the need for protection of 

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

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low cost carbon reductions. 

10. Labor 

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 staff 
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met with union representatives that included the United Mine 

Workers of America, 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. 

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 

only 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. 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 
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should not require the state plans to impose on the affected 

EGUs legally 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 to 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 the 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 

generators as well as retail rate payers. Another group 
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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, a demonstration that the state program achieves 

equivalent or better carbon intensity for the regulated sector; 

mass-based equivalency, a demonstration that the program 

achieves equal or greater emission reductions relative to what 

would be archived by the federal approach; or a market pricebased equivalency, 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. 

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. They 

indicate that once plant-specific goals are established based on 

on-site CO2 reduction opportunities, the source should have the 
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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-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. 

1. Market-based emission limits 
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 Nine states actively participate in the Regional Greenhouse 

Gas Initiative (RGGI), a market-based CO2 emission reduction 

program addressing EGUs that was established in 2009.27 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 

sources flexibility to make emission reductions where reduction 

costs are lowest, and encourages innovation in developing 

emission control strategies. 

 

27 The nine states include Connecticut, Delaware, Maine, 

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

and Vermont.
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 Approximately 90 percent of CO2 allowances are distributed 

by the RGGI participating states through auction.28 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.29 Through 2012, for example, 

the RGGI states invested approximately $460 million of proceeds 

into energy efficiency programs.30 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.31

Between 2005, when an agreement to implement RGGI was 

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

participating states fell by more than 40 percent.3233 In January 

 

28 Regional Greenhouse Gas Initiative 2013 Allowance Allocation 

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

allocation. 

29 Regional Investments of RGGI CO2 Allowance Proceeds, 2012 

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

Investment-Report.pdf 

30 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 

31 Ibid.

32 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).
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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.34 

 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.35 While 

California’s emission trading program, like its state emission 

limit, is multi-sector in scope, the state projects that the 

emissions trading program and related complementary measures 

will reduce power sector GHG emissions to less than 80 million 

metric tons of CO2 equivalent by 2025, a 25 percent reduction 

from 2005 power sector emission levels. 36 Prior to the 

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

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

34 RGGI Press Release, January 13, 2014, 

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

pdf. 

35 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 

36 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, 
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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.37 

2. GHG performance standards 

Four states, California, New York, Oregon and Washington, 

have enacted GHG emission standards that impose enforceable 

emission limits on new and/or expanded electric generating 

units. For example, since 2012, New York requires new or 

expanded baseload plants that are greater than 25 Megawatts(MW) 

to meet an emission rate of either 925 pounds CO2/Megawatt 

hour(MWh) (based on output) or 120 pounds of CO2/ Million British 

Thermal Units (MMBtu) (based on input). Similarly, non-baseload 

plants in New York of at least 25 MW or larger must meet an 

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

160 pounds of CO2/MMBtu (based on input).38 

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 

 

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

ion_from_States-FinalCompl.pdf 

37Ibid.

38 6 New York CoCodes, Rules & Regulations. Part 251 (Adopted 

June 28, 2012) 
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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.39 

3. Utility planning approaches 

Two states, Minnesota and Colorado, have worked 

collaboratively with their investor-owned utilities to develop 

multi-pollutant emission reduction plans on a utility-wide 

basis. This multi-pollutant, collaborative approach enables 

utilities to determine the least cost way to meet long term and 

comprehensive energy and environmental goals.

 Colorado’s Clean Air Clean Jobs Act of 2010, for example, 

required Colorado investor-owned utilities with coal plants to 

develop a multi-pollutant plan to meet existing and reasonably 

foreseeable federal CAA requirements. 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 

 

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

Wash SB 6001 (2007) 
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plan that was approved in 2010. With this plan, Xcel Energy is 

projected to reduce its CO2 emissions by 28 percent by 2020.40 

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. These standards have been established via utility 

regulatory commissions, legislatures and citizen ballots and 

requirements vary from state to state. State RPS typically 

specify the types of renewable energy, or other energy sources, 

that qualify for use toward achievement of the standard, and 

often allow for the use of qualifying renewable energy resources 

located outside of the state. They reduce utilization of fossil 

fuel electricity generating units, 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 

 

40 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. 
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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.41 The 2012 requirement increased to 18 percent of 

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

utilities.42 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.43

 The Oregon Renewable Portfolio Standard (RPS), is another 

example of a state requirement for renewables. Originally 

 

41 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

42 Ibid.

43 HF 729, 

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

&type=0#laws.10.3.0 , 
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enacted in 2007, it requires that all utilities serving Oregon 

load 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, each had achieved 

the five percent target as of the end of 2012.44 

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 

 

44 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. 
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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. 

Nationally, total spending on electric ratepayer-funded 

energy efficiency programs was $5.9 billion in 2010.45 Based on 

Lawrence Berkeley National Laboratory (LBNL) projections, 

spending is projected to reach $8.1 billion in 2025.46 

Electricity savings from energy efficiency programs are 

also growing. In 2011, electricity savings from these programs 

 

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.

46 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) 
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totaled approximately 22.9 million MWh, a 22 percent increase 

from the previous year.47 

California has been advancing energy efficiency through utilityrun demand-side energy efficiency programs for decades and 

considers energy efficiency “the bedrock upon which climate 

policies are built.”48 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.”49 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.50 Investor-owned 

utilities use demand-side energy efficiency programs to achieve 

their targets and currently “save about 3,000 GW per year, 

 

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

State Scorecard 

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

ports/e13k.pdf 

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

California Air Resources Board, to EPA Administrator Gina 

McCarthy.

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

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

Chairman of California Air Resources Board, to EPA Administrator 

Gina McCarthy.
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enough savings to power about 600,000 households.”51 Between 2010 

and 2011, California estimates that their demand-side energy 

efficiency programs reduced CO2 by 3.8 million tons.52 

 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.53 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.54 In 2012, Efficiency Vermont, the PSB-appointed energy 

efficiency utility, achieved annual savings of 1.9 percent of 

the state’s electricity sales, at a cost of 3.5 cents per 

kilowatt‐hour, lower than the cost of comparable electric supply 

in the same year, which was 8.6 cents per kWh.55 Efficiency 

Vermont projects a net lifetime economic value to Vermont of 

 

51 Ibid.

52 Ibid.

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

creationandstructure

54 [Insert link to Law]

55 Efficiency Vermont Annual Report 2012, 

http://www.efficiencyvermont.com/About-Us/Oversight-ReportsPlans/Annual-Reports-amp-Plans
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more than $100 million from the 2012 energy efficiency 

investments.56 

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. 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. 

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. 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 

 

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

annually over the 2 year period).57 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.58 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.59

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 

 

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

August 2010., Available at 

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

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

August 2010., Available at 

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

59 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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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 improve the 

efficiency of fossil-fired EGUs, but also reduce their 

utilization through taking advantage of opportunities for loweremitting 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 the 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 
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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 

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 
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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: 

1. Lowering the carbon intensity of generation at 

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

improvements). 

2. Reducing utilization of the most carbon-intensive 

affected EGUs to the extent that this can be accomplished 

cost-effectively by shifting generation to less carbonintensive existing fossil fuel-fired EGUs, including NGCC 

units that are under construction. 
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3. Reducing emissions of affected carbon-emitting EGUs to 

the extent that this can be accomplished cost-effectively 

by expanding the amount of new, lower (or no) carbonintensity generation. 

4. Reducing emissions of affected carbon-emitting EGUs to 

the extent that this can be accomplished cost-effectively 

by increasing demand-side energy efficiency. 

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 up to a 70 percent 

utilization rate; block 3, including 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, 
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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 further proposing, as part of the emission 

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. 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. The EPA is also proposing that the 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 (ii) a set of measures that we 

refer to as “portfolio” measures, which include emission 

limitations that apply directly to the affected sources as well 

as other measures that have the effect of limiting generation 

by, and therefore emissions from, the affected sources. 

The EPA is also proposing, as part of its emission 

guidelines, that a complete state plan include the following 

twelve components: 

 Identification of affected entities 

 Description of plan approach and geographic scope 
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 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, surplus, 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 emission 

guidelines, requirements for the timing for implementation and 

achievement of the required level of emission performance, 

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 
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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 ultimate 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 on its lands,60 the 

tribe would have the opportunity, but not the obligation, to 

adopt a plan for its tribal lands that establishes CO2

performance standards. 

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 

 

60 The EPA is aware of at least three 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 Bonanza Generating 

Station. All three are coal-fired EGUs. 
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the ambiguous provisions concerning the air pollutants covered 

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

from EGUs. Moreover, although 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 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, and the EPA is not re-opening that 

interpretation in this rulemaking. Accordingly, 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 limit mass emissions at these EGUs. The EPA reasonably 

identified both types of measures as components of BSER based on 
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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 being technically feasible. 

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-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. 
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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 emissions performance level, but instead impose 

requirements on other affected entities – such as renewable 

energy and demand-side energy efficiency measures - that would 

reduce utilization of, and therefore CO2 emissions from, the 

affected EGUs. It could be argued that those 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 EPA also solicits 

comment on whether state plans must impose all of the legal 

responsibility for achieving the emissions performance level on 

the affected EGUs. If so, the state plan could nevertheless 

include the requirements on other affected entities in order to 
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facilitate the reduced utilization of, 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. 

 To comply with the applicable standards of performance, 

sources may rely on any 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 §111(d)(1)(A)(i). 

The two amendments differed from each other, and were not 
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reconciled during the Conference Committee and, as a result, 

both were enacted into law. As amended, §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]61 [or 112(b)]62... ” 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 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 

section 111, including section 111(d), applies to carbon dioxide 

emissions from those sources. 

 

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

1990).

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

1990).
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We discuss this issue in more detail in the Legal Issues 

Memorandum.

B. 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 

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 
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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 proposals concerning applicability 

are the same as the January 8, 2014 proposal, sections V.A-B. 

See 79 FR at 1,459/1 – 1,461/2. We incorporate that discussion 

by reference here. 

B. 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 2014 proposal for 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 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 
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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 was 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 
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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 

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. 
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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 

Based on the states’ experiences and the EPA’s outreach 

with stakeholders as described above, the EPA has identified the 

measures underlying its BSER determination encompassing carbon 

intensity improvements and limitations on utilization that can 

meaningfully reduce CO2 emissions from affected EGUs, with 

minimal adverse impacts on the reliability of the electricity 

system, fuel prices, assets already improved with other control 

technology, and existing CO2 reduction programs. We group these 
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measures, which reflect current and projected practice and 

trends relevant to the industry, into four categories, which we 

consider “building blocks” for developing state emission 

performance goals. We provide an overview of these building 

blocks in subsection B. and more detailed discussion of each 

block in subsection C. In subsection D, we explain why as a 

legal matter these building blocks, taken together, constitute 

the “best system of emission reduction . . . adequately 

demonstrated” (BSER), which 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 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. 
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Similarly, we recognize and appreciate that states have 

different circumstances. For example, states have differing 

access to specific fuel types and proportions of EGU types. 

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. 

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 emissions reductions 

that longer-term actions, such as demand-side energy efficiency 

programs, may achieve. 

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 
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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 supply-side 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). 

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 
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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 examination, the EPA has identified the 

following four main categories – “building blocks” – of measures 

undergirding the application of carbon intensity improvements 

and limiting CO2 emissions at EGUs: 

1. Lowering the carbon intensity of generation at individual 

affected EGUs (e.g., through heat rate improvements) 

2. Reducing emissions of the most carbon-intensive affected 

EGUs to the extent that this can be accomplished costeffectively by shifting generation to less carbon-intensive 

existing fossil fuel-fired EGUs, including NGCC units that 

are under construction 

3. Reducing emissions of affected carbon-emitting EGUs to the 

extent that this can be accomplished cost-effectively by 

expanding the amount of new, lower (or no) carbon-intensity 

generation 

4. Reducing emissions of affected carbon-emitting EGUs to the 

extent that this can be accomplished cost-effectively by 

increasing demand-side energy efficiency 

Each of the above four building blocks represents a 

demonstrated approach to addressing either carbon intensity 
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improvements or the limitation of emissions at existing EGUs. In 

the next subsection, we discuss each of these building blocks at 

length. 

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 the 

building block within the context of the BSER determination, and 

we describe how we developed the data inputs used in the 

computations of state goals. 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. 

1. Building block 1 - heat rate improvements 

 The first basic category of approaches to reducing CO2

emissions from affected fossil fuel-fired EGUs consists of 

measures that reduce the carbon intensity of generation at 

individual coal-fired steam EGUs63 by improving heat rate.64 Heat 

 

63 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 
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rate improvements are changes that increase the efficiency with 

which an EGU converts fuel energy to electric energy (and useful 

thermal energy in the case of units that cogenerate steam for 

process use as well as electricity), thereby reducing the amount 

of fuel needed to produce the same amount of electricity and 

lowering the amount of CO2 produced as a byproduct of fuel 

combustion. Heat rate improvements yield important benefits to 

affected sources by reducing their fuel costs. 

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).65 The weighted-average annual heat rate 

 

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). 

64 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. 

65 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 
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of U.S. coal-fired EGUs is approximately 10,450 Btu per net kWh. 

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.66

 Several studies have examined the opportunities to employ 

heat rate improvements as a means of reducing CO2 emissions from 

coal-fired power plants. 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 equipment upgrades, including 

upgrades to boilers, steam turbines, and control systems. Based 

on this study, the EPA believes that implementation of all 

identified 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 install the subset of the identified upgrades that were 

 

amount of electricity used at the plant to operate components 

such as pumps, fans, motors, and pollution control devices.

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

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

reagent used to capture sulfur dioxide (SO2) in a scrubber. 

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. 
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applicable to their specific designs or fuel types and that had 

not already been installed.) 

 In addition to the S&L study, which looked generically at 

the types of improvements that can be made at specific types of 

EGUs, historic 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 this data and have identified a number of 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, the analysis of 

individual EGU heat rate histories provides a strong basis for 

considering heat rate improvements 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 
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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. 

 For the best practices analysis, the EPA worked with the 

heat rate 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 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. 

We therefore controlled for variation in those factors by 

grouping the observed hourly heat rate data for each EGU into 
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subsets corresponding to ranges of hourly ambient temperatures 

and hourly load levels. We believe that the amount of residual 

variability within each data subset is an indication of the 

degree of technical potential to improve the consistency with 

which optimal heat rate performance is achieved by adopting 

operating and maintenance best practices. For example, optimal 

heat rate performance could be achieved with greater consistency 

through practices such as turning off unneeded pumps at reduced 

loads, installation of digital control systems, more frequent 

tuning of existing control systems, or earlier like-kind 

replacement of worn existing components. (Upgrades to existing 

equipment are considered below.) By applying best practices to 

their operating and maintenance procedures, owners and operators 

of EGUs could reduce heat rate variability relative to average 

heat rates and, because the deviations generally result in 

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. 
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Based on this analysis, we believe a reasonable estimate for 

purposes of developing state-specific goals is that affected 

coal-fired steam EGUs on average could achieve a four percent 

improvement in heat rate through adoption of best practices to 

reduce hourly heat rate variability. This estimate corresponds 

to the elimination, on average across the fleet of affected 

EGUs, of 30 percent of the deviation from top-decile performance 

in the hourly heat rate for each EGU not attributable to hourly 

temperature and load variation. We also solicit comment on the 

use of estimates up to 6.7 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&L study. In that 

study, S&L 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 bestpractices heat rate improvements discussed above. Based on the 

average of S&L’s ranges of potential heat rate improvements from 
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the various upgrades in this subset, implementation of the full 

subset of appropriate opportunities at a single EGU could be 

expected to result in an aggregate heat rate improvement of 

approximately four percent (incremental to the improvement 

achievable from adoption of best practices). However, we 

recognize that this total may overstate the average equipment 

upgrade opportunity across all EGUs because some EGUs may 

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 bestpractices opportunity is on average two percent rather than four 

percent. We solicit comment on increasing this figure up to four 

percent. 

 Some of the measures available to EGUs for reducing their 

carbon intensity affect net heat rates rather than gross heat 

rates. Various EGU components such as pumps, fans, motors, and 

pollution control devices use electricity, a factor that is not 

accounted for in gross heat rates (that is, fuel used per unit 

of gross energy output) but is accounted for in net heat rates 
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(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 five percent of gross MWh 

generation. 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 goalsetting 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.67 

 

67 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 
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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 

than we have projected as being achievable for purposes of our 

 

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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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, making heat rate 

improvements a highly cost-effective approach for reducing CO2

emissions from affected EGUs. 

 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&L study discussed above. The S&L study 
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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 S&L 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,68 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 

 

68 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62 per 

MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kW-year. 

Data inputs for average coal-fired EGU heat rate, average coalfired EGU utilization, and average coal price are from the IPM 

5.13 base case for 2020. 
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kW-year.69 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.70 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-effective ones, the average cost of CO2 reductions 

would fall to $5.81 per metric ton.71 

 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 

 

69 8760 hours/year * 78% utilization * 0.976 metric tons/Mwh * 6% 

improvement * 0.001 MW/kW = 0.40 metric tons of CO2 per kW-year. 

The estimated average coal-fired EGU CO2 emission rate per MWh is 

from the IPM 5.13 base case for 2020.

70 $7.75 per metric ton of CO2 * 6% / 4% = $11.63 per metric ton 

of CO2. 71 $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, on average, 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, making heat rate improvements a highly cost-effective 

approach to reducing CO2 emissions from existing fossil-fueled 

EGUs. 

 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.72 

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 

 

72 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 

6.7 percent and 4 percent, respectively, particularly in light 

of the cost-effectiveness of heat rate improvements. We also 

solicit comment on approaches for estimating an additional 

amount of heat rate improvement due to efficiency-based 

reductions in parasitic load. 

2. Building block 2 – dispatch changes among affected EGUs 

 The second basic category of approaches to reducing CO2

emissions from affected fossil fuel-fired EGUs consists of 

measures that limit utilization, and therefore emissions, of 

high carbon-intensity affected EGUs – in particular, fossil 

fuel-fired steam EGUs - by replacing demand for generation at 

such facilities 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 
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various reliability and operational constraints, 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 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, 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. 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 
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technical capability to reduce overall power sector CO2

emissions. 

b. Magnitude of re-dispatch 

 The U.S. electric generating fleet includes EGUs employing 

a variety of generating technologies. EGUs using technologies 

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

for economic reasons generally operated at their maximum output 

whenever they are available. Renewable EGUs such as wind and 

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

generally operated when wind and sun conditions permit rather 

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

EGUs have higher variable costs and are also relatively 

flexible. Fossil fuel-fired EGU 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 fuelfired 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 
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compete more with one another than with nuclear and renewable 

EGUs. The amount of re-dispatch from coal-fired EGUs to NGCC 

units that takes place as a result of this competition is highly 

relevant to overall power sector GHG emissions, because a 

typical NGCC unit produces less than half as much CO2 per MWh of 

electricity generated as a typical coal-fired EGU. 

 In order to estimate the potential magnitude of the 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.73 

 

73 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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 We also researched historic 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 

historic 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. These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal.74 The relative fuel 

prices vary by location, as do the recent patterns of redispatch. However, 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. 

 

74 Natural gas prices have fallen because of advances in 

production methods that have increased available supplies. 
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According to the historic 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. 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. Thus, on a seasonal basis, a significant number 

of NGCC units 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 the entire season. 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 
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existing high carbon-intensity EGUs, would be technically 

feasible. 

 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).75 If the current pipeline and 

transmission systems allow these utilization rates to be 

achieved in peak hours, it is reasonable to expect that similar 

 

75 EIA, Average utilization of the nation’s natural gas combinedcycle 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).
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utilization rates should also be possible in other hours when 

constraints are typically less severe. The second reason 

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 reason 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.76 Further, 

we believe the flexible nature of the goals provides time for 

infrastructure improvements to occur should they prove necessary 

in some locations. 

c. Cost of re-dispatch 

 

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

in Energy; INGAA Foundation, Pipeline and Storage Infrastrucure 

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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 The cost of the power sector CO2 emission reductions that 

can be achieved through re-dispatch among existing fossil fuelfired EGUs depends on the relative variable costs of electricity 

production at EGUs with different degrees of carbon intensity. 

These variable costs are driven by the EGUs’ respective fuel 

costs and by the efficiencies with which they can convert fuel 

to electricity (i.e., their heat rates). Historically, natural 

gas has had a higher cost per unit of energy content (e.g., 

MMBtu) than coal in most locations, but for NGCC units this 

disadvantage in fuel cost per MMBtu relative to coal-fired EGUs 

is typically offset in significant part, and sometimes 

completely, by a heat rate advantage. 

 The EPA has conducted two sets of extensive analyses to 

help inform the development of the state-specific emission goals 

described in this proposal, including 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 were used as the basis for 
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assessing the costs and benefits of the overall proposal.77 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 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 NGCC units within 

defined areas. In the most restrictive scenarios, re-dispatch 

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 extreme 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 

 

77 See Regulatory Impact Analysis for more detail.
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of NGCC units nationwide was required, on average, to achieve a 

specified annual utilization rate.78 Specifically, the scenarios 

required average NGCC unit utilization rates of 65, 70, and 75 

percent. 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’s existing fleet. 

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] per metric ton of CO2. 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. 

 

78 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. 
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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 because this 

scenario is based on the assumption that there will be no costeffective re-dispatch opportunities among EGUs in different 

states, contrary to the reality that interstate flows of 

electricity routinely change in response to economic conditions. 

As a 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 noted that 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
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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 

re-dispatch was simulated (subject to other constraints 

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

scenarios with greater 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. We invite comment on whether the regional scenarios, 

which we believe reflect a more realistic representation of how 

re-dispatch would actually occur among EGUs located in multistate 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. 

 We also conclude from our analysis that the extent of redispatch estimated in this building block can be achieved 
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without causing significant economic impacts. For example, in 

the 70 percent NGCC unit utilization rate scenario with 

restrictions on interstate re-dispatch, natural gas prices were 

projected to increase by a range of from [x] percent to [x] 

percent, which is well within the range of historic natural gas 

price variability. Projected wholesale electricity price 

increases ranged from [x] to [x] percent, which similarly is 

well within the range of historic electric price variability. We 

view these projected impacts as not unreasonable and as 

supporting use of a 70 percent NGCC utilization rate target for 

purposes of quantifying the emission reductions achievable 

through application of the BSER. 

However, for the same reasons discussed above with respect 

to estimated costs per ton of CO2, in actual implementation we 

again expect the economic impacts, including natural gas price 

impacts, described above for the most restrictive scenario to be 

considerably larger than 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 
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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 re-dispatch that can be costeffectively implemented is that electricity generation could be 

shifted from more carbon-intensive EGUs to less carbon-intensive 

EGUs within the state up to the point at which the state’s NGCC 

units would have annual utilization rates of 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 estimate of 

a 65 percent average utilization rate for NGCC units. In 2012, 

approximately 18 percent of existing NGCC units 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 
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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. 

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 the amount of new, less carbonintensive generating capacity 

 The second basic category of approaches that create a basis 

for incorporating limiting emissions as an element of the BSER 

for CO2 emissions from affected fossil fuel-fired EGUs consists 

of measures that reduce electricity demand at affected carbonemitting EGUs by expanding the amount of lower-carbon generating 

capacity available to produce replacement generation. The 

opportunity discussed above to re-dispatch from higher-carbon to 

lower-carbon EGUs within the affected fossil EGU fleet may be 

limited by the amount of underused less carbon-intensive 

capacity 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, 
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and measures that would do so constitute the third building 

block. Below we discuss several different types of generating 

capacity that could play this role: new renewable generating 

capacity, new and preserved nuclear capacity, and new NGCC 

capacity. 

a. New renewable generating capacity 

Renewable electricity (RE) generating technologies are a 

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

percent of total U.S. electricity generation was produced by 

renewable technologies, up from two 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.79 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 and costeffective way for states to reduce CO2 emissions at affected 

EGUs. 

To estimate the CO2 emission reductions from affected EGUs 

achievable through increases in renewable generation, EPA has 

 

79 Database of State Incentives for Renewables & Efficiency 

(DSIRE), 

http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0. 
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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.80 

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 establish RPS requirements that any 

state must meet. Rather, it represents a level of renewable 

resource development for individual states - with recognition of 

 

80 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. 
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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.81 By 

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

single national standard, we are able to take regional variation 

into account while still maintaining a level of rigor for the 

scenario’s targets. The grouping of states into these 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 

 

81 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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Virginia 

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

Missouri, North Dakota, South Dakota, Wisconsin 

Northeast Connecticut, Maine, Massachusetts, New 

Hampshire, New York, Rhode Island, Vermont* 

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

Texas 

Southeast Alabama, Florida, Georgia, Kentucky, 

Mississippi, North Carolina, South Carolina, 

Tennessee 

West Arizona, California, Colorado, Idaho, Montana, 

Nevada, New Mexico, Oregon, Utah, Washington, 

Wyoming 

* Because Vermont and the District of Columbia lack affected 

sources, no goals are being proposed for these jurisdictions. 

The best practices scenario for each state consists of 

growing annual levels of RE generation82 estimated based on 

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

historic RE generation, subject to a maximum RE generation 

 

82 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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target. The annual RE growth factors and maximum RE generation 

targets were developed separately for each of the six regions. 

Our procedure for determining these elements is described in the 

Greenhouse Gas Abatement Measures TSD and summarized below. 

The EPA first quantified the amount of renewable generation 

in 2012 in each state. EPA then summed these amounts for all 

states in each region to determine a regional starting level of 

renewable generation prior to implementation of the best 

practices scenario. 

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 

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 less than its RPS target 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 
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RE capacity, assuming that the new investment begins in 2017, 

the year following the initial state plan submission deadline,83

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, we used the annual amounts for the years 

2020 through 2029. For computation of the alternate state goals 

on which we are seeking comment, we used the annual amounts for 

the years 2020 through 2024. 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)84

 

83 See Section VIII below for further discussion of timing 

requirements for state plan submittals. 

84 Vermont and the District of Columbia are excluded from this 

table because we are not proposing goals for those 

jurisdictions. 
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State 2012 Proposed Goals Alternate Goals 

Interim 

Level 

Final 

Level 

Interim 

Level 

Final 

Level 

 Alaska 1% 5% 10% 2% 3% 

 Alabama 2% 6% 9% 4% 5% 

 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% 9% 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% 

 Kansas 12% 19% 20% 19% 20% 

 Kentucky 0% 1% 2% 1% 1% 

 Louisiana 2% 5% 7% 4% 4% 

 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% 

 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% 

 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% 

 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% 
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 Utah 3% 5% 6% 4% 5% 

 Virginia 3% 12% 16% 9% 12% 

 Washington 7% 12% 16% 10% 12% 

 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 

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; 
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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 cost 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" 

found 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 

the median CO2 reduction cost to be $3 per metric ton.85 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.86

While RPS requirements will continue to grow over time, EPA 

does not expect this anticipated expansion to fall outside the 

 

85 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. 

86 Galen Barbose, “Renewables Portfolio Standards in the United 

States: A Status Update,” Lawrence Berkeley National Lab, 

November 2013.
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historical norms of deployment. 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 RPSsupported renewable capacity from 2007-2012 has exceeded 6 GW 

per year.87 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.88 

We invite comment on this approach to treatment of new 

renewable capacity as an emission limitation component of the 

best system of emission reduction and a basis for part of the 

quantification of state goals. 

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 

 

87 Galen Barbose, “Renewables Portfolio Standards in the United 

States: A Status Update,” Lawrence Berkeley National Lab, 

November 2013. 

88 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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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 

purposes of setting states’ CO2 reduction goals. Completion of 

these units therefore represents a highly cost-effective 

opportunity to reduce CO2 emissions from affected fossil fuel-
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fired EGUs. For this reason, we are proposing that the emission 

reductions achievable at affected sources due to 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. 

 Another way to increase the amount of available nuclear 

capacity is to preserve existing nuclear EGUs that would 

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, Crystal River 3, 

Kewaunee, Vermont Yankee, and Oyster Creek. While each 

retirement decision is based on the unique circumstances of that 

individual unit, EPA believes that increased fixed costs 

associated with unit age play a role, particularly as the units 

approach the point of deciding whether to apply 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 U.S. nuclear generating capacity, have not yet 

submitted applications for license renewal to the Nuclear 

Regulatory Commission. Without making any judgment about the 

likelihood that any individual EGU will retire, we view this 

eight percent share of nuclear capacity as a reasonable proxy 
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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 believe 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. Retaining the estimated eight 

percent of at-risk nuclear capacity could avoid 175 to 250 

million metric tons of CO2.89 According to a recent report, 

nuclear units may be experiencing up to a $6/MWh shortfall in 

covering their operating costs with electricity sales.90 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 at-risk nuclear units to be about $12 to $17 per 

metric ton. EPA views this cost as reasonable. We therefore 

propose that the emission reductions achievable by retaining in 

operation eight percent of each state’s existing nuclear 

 

89 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). 

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

Suisse, February 2013 
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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 the 

following questions: Should we estimate an 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 carbon-
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intensity affected EGUs with generation from lower-carbon 

generation from existing NGCC units.91 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.92 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 

 

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

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

92 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. 

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 
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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 limiting 

emissions, as an element of the BSER for CO2 emissions from 

affected fossil fuel-fired EGUs consists of measures that reduce 

the demand for generation at those sources by reducing the 

overall quantity of generation demanded by end-users. 

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 have 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 
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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.93 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 

generation.94

 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 

 

93 Energy Information Administration Form 861, 2012, available at 

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

94 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 Potential from Energy Efficiency and Demand Response 

Programs in the U.S. (2010–2030): Executive Summary (2009). 
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manner, in 2011, state demand-side energy efficiency programs 

are estimated to have reduced CO2 emissions by 75 million metric 

tons.95 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. 

b. “Best practices” for demand-side energy efficiency 

 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 

 

95 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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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 represent 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 

demonstrated or required by policies (e.g., energy efficiency 

resource standards) of the leading states. The data and 

methodology used to develop the best practices scenario are 

summarized below. 

 We have not assumed any particular type of demand-side 

energy efficiency policy. States with leading energy efficiency 

performance have employed a variety of strategies that are 

implemented by a range of entities including investor-owned, 

municipal and cooperative electric utilities as well as state 

agencies and third-party administrators. These include energy 

efficiency programs,96 building energy codes, state appliance 

 

96 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 
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standards (for appliances without federal standards), tax 

credits, and benchmarking requirements for building energy use.97

Energy efficiency programs 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 standards98 (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, twelve 

 

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.

97 See the Existing State Actions TSD for descriptions of the 

full array of demand-side energy efficiency policies currently 

employed by states. 

98 EERS establish specific, long-term targets for energy savings 

that utilities or non-utility program administrators must meet 

through customer energy efficiency programs. EERS, as well as 

requirements that utilities acquire all cost-effective energy 

efficiency, have been the most impactful state energy efficiency 

strategies in recent years.
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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.99 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. 

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.100 

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. 

 

99 See the Greenhouse Gas Abatement Measures TSD for more 

information.

100 See the EM&V section of the state Plan TSD for more 

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

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. 

 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 rate101 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 savings rate 

can expand its energy efficiency programs to reach that rate 

more quickly 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.102

For states already at or above the 1.5 percent annual 

 

101 2012 is the most recent year for energy efficiency program 

incremental savings data reported using EIA Form 861.

102 See the Greenhouse Gas Abatement Measures TSD for more 

information.
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incremental savings rate, we estimate that they would sustain a 

1.5 percent rate through 2030. 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. 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. To 

determine the avoided MWh quantities of generation that 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.103 

 

103 EIA, Retail Sales of Electricity by State by Sector by 
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 As indicated above, the EPA is also taking comment on a 

less stringent alternative for goal-setting. Under this 

approach, 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 historic 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.104 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. 

 

Provider, Nov. 12, 2013, available at 

http://www.eia.gov/electricity/data/state/. The data are 

adjusted to reflect transmission and distribution losses.

104 See the Greenhouse Gas Abatement Measures TSD for more 

information.
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c. Costs of demand-side energy efficiency 

 The EPA expects implementation of demand-side energy 

efficiency programs as reflected in the best practices scenario 

to be a highly cost-effective approach to reducing greenhouse 

gas emissions from the existing fossil fuel-fired EGUs. The 

processes by which states develop funding for these programs 

typically require the application of cost-effectiveness tests to 

ensure that adopted program portfolios lead to lower costs than 

the use of generation sources that would otherwise be required 

to meet the associated electricity service demands. Indeed, a 

major reason for the widespread presence and rapid growth of 

demand-side energy efficiency programs is the strong evidence of 

their cost-effectiveness even before the additional benefit of 

CO2 reductions is considered.105 Federal and independent studies 

have found that end-users’ needs for energy-dependent services 

(e.g., heating, cooling, lighting, motor output, and information 

and entertainment services) frequently can be satisfied at lower 

cost by improving the efficiency of electricity consumption 

rather than by increasing the supply of electricity.106 In our 

 

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

their evaluations of cost effectiveness.

106 E.g., Electric Power Research Institute, Assessment of 

Achievable Potential from 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
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view, the 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 is likely to be very low and may even be less than $0 

per metric ton.107

 Another approach to evaluating the cost effectiveness of 

demand-side efficiency is to compare its cost to avoided power 

system costs. The costs associated with the best practices 

scenario were estimated based upon a synthesis of historical 

studies of 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 includes both the 

program costs paid by utilities for implementing energy 

 

ID=000000000001016987; Northwest Power and Conservation Council, 

Sixth Northwest Conservation and Electric Power Plan (Feb. 

2010), available at 

http://www.nwcouncil.org/energy/powerplan/6/plan/.

107 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 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 studies of energy efficiency program costs 

using engineering-based, bottom-up estimates of the average cost 

of saved energy under various programs.108 For example, an EPA 

review conducted in 2009 found a range of annualized costs 

between $12 and $52 per MWh of electricity saved,109 while a more 

recent review from the American Council for an Energy-Efficient 

Economy derived a cost of $51 per MWh of electricity saved.110 

 

108 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.

109 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.

110 American Council for an Energy-Efficient Economy, Saving 

Energy Cost-Effectively: A National Review of 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. 
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 We have evaluated cost effectiveness of the best-practices 

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, 

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-side 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 estimated 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. 

 Recognizing this history of demonstrated successful state 

implementation of demand-side energy efficiency programs, the 

EPA proposes to find that for purposes of establishing state 

goals, a reasonable estimate of the demand-side energy 

efficiency that can be cost-effectively achieved is the amount 

resulting from implementation of a comprehensive set of demand-
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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 reduce power sector CO2 emissions 

are provided in the Greenhouse Gas Abatement Measures TSD. We 

invite comment on all aspects of our data and methodology as 

discussed above and in the TSD, as well as on the level of 

reductions we propose to define as best practices suitable for 

inclusion in the best system of emission reduction and the level 

reflected in the less stringent scenario. We also specifically 

invite comment on increasing the annual incremental savings rate 

to 2.0 percent to reflect an estimate of the additional 

electricity savings achievable from state policies not reflected 

in the 1.5 percent rate, such as building energy codes and state 

appliance standards. 

5. Potential emission reduction measures not used to set 

proposed goals 

 There are two 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 goal-
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setting purposes, but that merit discussion here: fuel switching 

at individual EGUs, and carbon capture and storage (CCS). 

 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 $67 per metric ton to $109 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 storage111 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 noted that 

identifying CCS as BSER for new natural gas-fired stationary 

combustion turbines would likely result in higher nationwide 

electricity prices and could adversely affect the supply of 

 

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

sequestration.”
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electricity, because the majority of new fossil-fuel fired 

generating capacity is projected to consist of NGCC 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 

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. 
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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. 

Additional discussion can be found in the Greenhouse Gas 

Abatement Measures TSD. We invite comment on this proposed 

finding. 

D. Determination of the Best System of Emission Reduction 

1. Overview 

 The EPA is proposing that the measures in the 4 building 

blocks, taken together, constitute 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 alternative, but complementary, 

approaches to explaining how the building blocks provide the 

basis of the proposed determination of 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. 
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 The first 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 rate improvements), and (ii) reducing 

utilization to the extent of the availability of lower-emitting 

fossil-generation, zero-emitting generation, and demand 

reduction by means of end use energy efficiency measures 

(building blocks 2, 3, and 4, respectively). The second approach 

treats building block 1 the same as under the first approach, 

but treats building blocks 2, 3, and 4 as parts of the 

integrated electricity system that have the effect of reducing 

utilization at the affected EGUs. 

2. Statutory and regulatory provisions as well as EPA 

interpretation 

 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 
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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.112 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 emissions reductions 

that the system would generate. 

 The costs of the system must be reasonable. The EPA may 

consider the costs on 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.113 

 

112 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). 

113 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. 
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 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 

EPA must also consider energy impacts, and, as with costs, may 

consider them on the source level and on the nationwide 

structure of the power sector over time. 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. 

 In the framework regulations, the EPA interpreted CAA 

section 111(d) as giving the agency the authority to determine 

the required stringency of the standards of performance 

 

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, EPA 

stated that “these various formulations of the cost standard ... 

are synonymous,” and, for convenience, EPA used “reasonableness” 

as the formulation. EPA takes the same approach in this 

rulemaking. 
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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 fossilfired EGUs, with the amount of reduced generation corresponding 
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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 are not unreasonable when viewed either on the 

individual source level or through the lens of the electricity 

system as a whole. As noted, states and regulated entities will 

have flexibility when developing compliance strategies to 

emphasize whichever measures best suit their particular 

circumstances, and that flexibility will further improve costeffectiveness. 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 
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electricity dispatch dynamics, and seasonal electricity load 

requirements. As described below in section XI of the regulatory 

impacts analysis, the results indicate that the proposed goals 

are readily achievable with no adverse impacts on power 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. Moreover, the costs tend to decline over time 

as states and regulated entities take advantage of the available 

flexibility and deploy more cost-effective measures (notably 

demand-side energy efficiency). The EPA considers this analysis 

strong confirmation of the cost effectiveness of the 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 

that reduce emissions. 

With respect to the remaining BSER criteria, the EPA 

believes 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 
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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 with re-dispatch to less carbonintensive 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 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 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 “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. 
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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 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 zerocarbon 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 fossil-
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fired 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. 

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 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 
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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 may be undertaken by the affected EGUs. That 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 low- or zerocarbon intensive generation described in building block 3, and 

the affected EGUs may also invest in many of the demand-side 

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. 

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 
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reducing overall electric demand through DSM). In some cases 

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 2050.114 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.”115 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 

well as procurement processes and an economy-wide cap and trade 

program, along with other programs.116 

 

114 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 115 December 27, 2013 Letter from Mary D. Nichols, Chairman of 

California Air Resources Board, to EPA Administrator Gina 

McCarthy. 116 See Cal. Air Res. Bd., Climate Change Scoping Plan 31-32, 41-

46 (2008), available at: 
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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.117 

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 

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 

 

http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_pl

an.pdf. 

117 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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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 

multi-year compliance periods, allowance banking, offsets, an 

auction reserve price and cost containment reserve of 
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allowances.118 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. 

5. 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 identifying as a component of the BSER re-dispatch between 

sources in the two categories (i.e., re-dispatch between steam-

 

118 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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generating EGUs and NGCC units), or (ii) facilitating averaging 

or trading systems that include sources in both categories, 

which states may wish to adopt. 

6. Severability 

We consider our proposed findings of 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 BSER consists of 

the remaining building blocks. 

7. 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 Issues Memorandum, although, as noted, we 

are not soliciting comment on issues that were resolved by the 

framework regulations and therefore are not being re-opened 

here. In particular, we invite comment on whether any of the 

types of measures discussed above, and any other potential 

measures recommended by commenters, must, may, or may not be 

considered as the basis for the BSER for legal, technical, or 

economic reasons. With regards to comments received during the 

stakeholder comments, some commenters noted that trading 

programs like RGGI have been successful at reducing GHGs, other 
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commenters solicited 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 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 BSER solely because 

they involve actions by entities or at locations other than 

affected sources. 

VII. State Goals 

A. Overview 

In this section, the EPA sets out proposed state-specific 

CO2 emission performance goals to guide states in development of 

their state plans. The proposed goals reflect the EPA’s 

quantification of each state’s average emission rate from 

affected EGUs that could be achieved by 2030 and sustained 

thereafter, with interim goals that would apply over a 2020-2029 

phase-in period, through reasonable implementation, considering 

the unique circumstances of each individual state, of the 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 
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blocks, in this case by 2025, with interim goals that would 

apply over a 2020-2024 phase-in period. 

 The proposed goals are expressed in the form of statespecific, adjusted119 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 

 

119 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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plans reflecting a multi-state approach for complying with 

standards of performance. 

 At this time the EPA is not proposing targets for either 

tribal lands or territories. EPA does believe it is appropriate 

to eventually require targets for both tribal lands and 

territories. 

With respect to tribal lands, EPA is soliciting comment on 

the application of the four BSER building blocks to determine a 

CO2 performance standard for units on individual tribal lands. 

Also, for tribes wishing to include the EGUs on their tribal 

lands in a multi-state plan (i.e., treating the tribal lands as 

an additional state) we are soliciting comment on how to adjust 

the multi-state 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. 

With respect to territories, EPA takes comment on the 

appropriateness of the four building block approach for 

territories. In particular, the EPA takes comment on appropriate 

alternatives for territories that do not have access to natural 

gas as well as on ways to determine appropriate renewable 
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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 four 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. Finally, we describe the 

alternate set of goals offered for comment and certain other 

approaches we considered. 

 Some of the topics addressed in this section are addressed 

in greater detail in supplemental documents available in the 

docket for this rulemaking, including the Goal Computation TSD 

and the Greenhouse Gas Abatement Measures TSD. 

Specific topics addressed in the various TSDs are noted 

throughout the discussion below. 

B. Form of goals 

 The proposed goals are presented in the form of adjusted 

output-weighted-average CO2 emission rates that the affected 

fossil fuel-fired EGUs located in each state could achieve 

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 
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electricity generated), with the opportunity for the state to 

adopt a mass-based form (e.g., a cap on the tonnage of CO2

emissions); the use of output-weighted-average emission rates 

for all affected EGUs in a state rather than nationally uniform 

emission rates for all affected EGUs of particular types; the 

use of adjustments to accommodate measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation rather than by reducing the CO2 emission rate per MWh 

generated by affected sources; the use of emission rates 

expressed in terms of net rather than gross energy output; and 

the adjustability of the goals based on the severability of the 

underlying building blocks. 

 First, the EPA proposes to use an emission rate-based form 

for the state-specific goals included in the guidelines, and to 

give each state the opportunity to translate its rate-based goal 

to an equivalent mass-based form for state plan purposes. Each 

of the two types 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 
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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 

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 
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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 potentially large source of cost-effective CO2

emission reductions for the power sector. 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 lowand zero-carbon generating capacity and demand-side energy 

efficiency. We recognize that overall CO2 emissions from affected 

EGUs are reduced by reducing generation from those EGUs 

collectively rather than by reducing the CO2 emission rates of 

affected EGUs or by shifting generation from the most carbonintensive affected EGUs to less carbon-intensive affected EGUs. 
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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 emissions120 rather than on CO2 emission rates, 

because the emission-reducing effects of reduced utilization of 

affected EGUs are evident in the EGUs’ reported CO2 mass 

emissions. 

 

120 We also recognize that even under a mass-based approach, 

adjustments may be appropriate in some circumstances to address 

interstate effects, such as when measures undertaken pursuant to 

one state’s plan are expected to be associated with decreases in 

fossil fuel-fired generation and CO2 emissions in another state. 

These issues are discussed below in section VIII on state plans. 
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 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 generation measured at the 

point of delivery to the transmission grid rather than gross MWh 

generation measured at the EGU’s generator.121 (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 

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 load122 to us under 40 CFR Part 75, 

 

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

useful thermal output, in addition to either net or gross 

electric energy output. 

122 Some EGUs report gross steam output instead of gross load. 
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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 

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

the goals would be adjusted to reflect the emissions reductions 

from the remaining building blocks. 

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 
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 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 emission reductions by avoiding fossil 

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 issue of how states could demonstrate emission 

performance consistent with the goals is addressed in Section 

VIII on state plans.) The proposed goals are set forth in Table 

5 below. 

Table 5: Proposed State123 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,113 1,024 

 

123 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 tribes or U.S. territories at this 

time. 
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Alaska 1,039 878 

Arizona * 724 691 

Arkansas 1,012 950 

California 580 558 

Colorado 1,164 1,112 

Connecticut 588 533 

Delaware 922 848 

Florida 750 692 

Georgia 885 826 

Hawaii 1,388 1,304 

Idaho 241 225 

Illinois 1,391 1,293 

Indiana 1,627 1,549 

Iowa 1,351 1,310 

Kansas 1,597 1,516 

Kentucky 1,861 1,778 

Louisiana 1,080 993 

Maine 423 407 

Maryland 1,325 1,166 

Massachusetts 646 567 

Michigan 1,337 1,261 

Minnesota 891 851 
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Mississippi 717 673 

Missouri 1,621 1,544 

Montana 1,900 1,781 

Nebraska 1,587 1,471 

Nevada 697 644 

New Hampshire 542 485 

New Jersey 657 531 

New Mexico * 1,088 1,000 

New York 647 557 

North Carolina 1,064 977 

North Dakota 1,821 1,788 

Ohio 1,468 1,349 

Oklahoma 916 879 

Oregon 408 375 

Pennsylvania 1,200 1,067 

Rhode Island 816 773 

South Carolina 802 736 

South Dakota 794 731 

Tennessee 1,234 1,142 

Texas 932 855 

Utah * 1,375 1,318 

Virginia 869 793 
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Washington 294 235 

West Virginia 1,766 1,636 

Wisconsin 1,265 1,185 

Wyoming 1,801 1,701 

* Excludes EGUs located in tribal areas in 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 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 emission reductions. The 

adjustment is made by estimating the annual net MWh generation 

associated with an achievable amount of qualifying new lowcarbon 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 
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emission rate computation.124 Mathematically, this adjustment has 

the effect of spreading the measured CO2 emissions from the 

state’s affected EGUs over a larger quantity of energy output, 

thus resulting in an adjusted emission rate lower than the 

unadjusted emission rate. (As discussed below in section VIII on 

state plans, we are proposing that a state could make analogous 

adjustments to compliance measurement approaches under its state 

plan, thereby enabling the state to adopt an emission rate-based 

form of emission performance level while still being able to 

rely on low- or zero-carbon capacity deployment programs and 

demand-side energy efficiency as components of its plan.) 

 The methodology used to compute each state’s proposed goal 

is summarized on a step-by-step basis below. The methodology is 

described in more detail in the Goal Computation TSD, which 

includes a numerical example illustrating the full procedure. 

The development of the data inputs used in the computation 

procedure is discussed in section VI above and in the Greenhouse 

Gas Abatement Measures TSD. 

 Step 1 (compilation of baseline data). On a state-by-state 

basis, we obtained total annual quantities of CO2 emissions, net 

 

124 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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MWh generation, and MW capacity from reported 2012 data for all 

affected EGUs.125 For each state, we aggregated the 2012 data for 

all coal-fired steam EGUs as a group, all oil- and gas-fired 

steam EGUs as a group, all NGCC units as a group, and 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 

thresholds for qualification as affected EGUs). 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.126 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 

 

125 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.A. above. 

126 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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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 

improvements. 

 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 proportionately127

decreased, to reflect an estimated potential increase in 

 

127 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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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

emission rate, the total (across all four groups) of the state’s 

CO2 emissions was reduced.128 

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

total quantities of new renewable capacity and new or preserved 

nuclear capacity that would be made available in each state 

under “best practices” approaches to renewable and nuclear 

capacity, and we estimated the MWh generation from this 

incremental low- or zero-carbon generating capacity based on 

historic utilization rates for 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 

 

128 We did not estimate any change in utilization, generation, or 

emissions for the state’s 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 

above. We performed these computations separately for each year 
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from 2020 to 2029, using the respective cumulative annual MWh 

savings figures developed in Step 5. 

 Step 7 (computation of interim and final goals). The final 

2030 goal for each state is the annual rate computed for 2029 

for the state from Step 6 above. We computed the 2020-2029 

interim goal for each state as the simple average of the annual 

rates computed for each of the years from 2020 to 2029 for the 

state from Step 6 above. 

 It bears emphasis that the procedure described above is 

proposed to be used only to determine state goals, and the 

particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

specific requirements applicable to individual EGUs, to the EGUs 

in a given state collectively, or to other affected entities in 

the state would be based on the standards of performance 

established through that state’s plan. The details of how states 

could attain emission performance levels consistent with the 

goals through different state plan approaches that recognize 

emission reductions achieved through all the building blocks are 

discussed further in section VIII on state plans. 

 We invite comment on all aspects of the goal computation 

procedure. (Note that we also invite comment on certain specific 
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alternate data inputs to the procedure in Section VI.C. above.) 

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 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 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 
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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 

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 

 States’ ability to achieve emission performance levels 

consistent with the goals is enhanced by several distinct types 
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of flexibility: (i) choices as to the measures employed, 

including timing; (ii) the ability to translate from a ratebased form of goal to a mass-based form of goal; and (iii) the 

opportunity to pursue interstate 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 

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. 

Further, by allowing states to demonstrate compliance over a 

multi-year plan period of as long as ten years, the emission 

guideline 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 life, for example, by enabling them to defer 

imposition of requirements on EGUs that may be scheduled to 

retire after 2020 but before 2029. 

 Second, as noted earlier, while the EPA is proposing to 

establish goals in an emission rate-based form, we are also 
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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 emissions 

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 emission guidelines allow states to submit 

multi-state plans. The EPA expects this flexibility to reduce 

the cost of achieving the state goals and therefore expects it 

to be attractive to states. For example, the 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 
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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 have flexibility to quantify the level of emission 

reduction resulting from the application of BSER. Consistent 

with the existing framework regulations, we view this 

quantification as the EPA’s role,129 and we do not propose to reopen that portion of the framework regulations in this 

rulemaking. 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 states, in their 

section 111(d) plans, must meet those goals, and may not make 

them less stringent. This matter, too, is resolved by the 

framework regulations,130 and EPA is not re-opening it in this 

rulemaking. To reiterate, the goals are intended to demonstrate 

a level of performance achievable through application of the 

building blocks considering the unique circumstances of each 

individual state that would be acceptable in a state plan. 

States have flexibility regarding the selection of the measures 

upon which they choose to rely and a 10-year time period over 

 

129 40 CFR 60.22(b)(5). 130 40 CFR 60.22(b)(5). 
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which to reach full implementation, and they can use rate-based 

or mass-based approaches. In addition, we note that multi-state 

coordination offers states an opportunity to achieve additional 

emission reductions and reduce implementation costs. 

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 

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 
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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 

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 
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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 6 below. 

Table 6: Alternate State131 Goals (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs) 

State Interim Goal Final Goal 

Alabama 1,243 1,208 

Alaska 1,142 1,086 

Arizona * 767 751 

Arkansas 1,128 1,101 

California 611 599 

Colorado 1,274 1,232 

Connecticut 640 617 

Delaware 1,036 1,010 

Florida 795 771 

 

131 See footnote accompanying Table VII.C-1 above. 
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Georgia 992 958 

Hawaii 1,464 1,429 

Idaho 259 252 

Illinois 1,529 1,484 

Indiana 1,738 1,704 

Iowa 1,447 1,428 

Kansas 1,698 1,644 

Kentucky 1,971 1,937 

Louisiana 1,208 1,171 

Maine 448 440 

Maryland 1,495 1,417 

Massachusetts 708 675 

Michigan 1,470 1,434 

Minnesota 1,001 981 

Mississippi 754 729 

Missouri 1,726 1,694 

Montana 2,031 1,980 

Nebraska 1,710 1,661 

Nevada 736 714 

New Hampshire 593 553 

New Jersey 740 688 

New Mexico * 1,203 1,163 
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New York 756 715 

North Carolina 1,189 1,145 

North Dakota 1,887 1,874 

Ohio 1,611 1,566 

Oklahoma 1,022 986 

Oregon 449 418 

Pennsylvania 1,342 1,293 

Rhode Island 854 837 

South Carolina 889 858 

South Dakota 885 856 

Tennessee 1,345 1,307 

Texas 1,059 1,016 

Utah * 1,476 1,451 

Virginia 1,011 955 

Washington 350 316 

West Virginia 1,877 1,835 

Wisconsin 1,404 1,366 

Wyoming 1,902 1,862 

* Excludes EGUs located in tribal areas 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 
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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 

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 may be considered in 

assessing the cost effectiveness of state-specific goals. 

F. Reliable Affordable Electricity 
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Many stakeholders raised concerns that this regulation 

could affect the reliability of the electric power system. The 

EPA is sympathetic to this concern, and so in designing this 

program the EPA 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 of the power system. EPA staff and managers have also had 

numerous discussions with state public utility commissioners and 

their staff 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 entities, 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. These suggestions are described 

elsewhere in this preamble and we welcome comment on them. 

EPA has discussed this issue with the US Department of 

Agriculture as well to discuss how we can address the concerns 

of small isolated power generators in rural America and 
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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 BSER, 

looked specifically at the cost effectiveness of control options 

in part to assure that the option would not have a negative 

effect on system reliability. Each of the building blocks was 

determined to be cost effective. Further, the states under the 

Clean Air Act are given the flexibility to design state plans 

that include any measure or combination of measures to achieve 

that emissions limitation. 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 stringency that the EPA 

determines is achievable and 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 

achieved the reductions necessary to meeting 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, reduce costs and stress 
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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, 

actually reduce demand for centrally generated power and thus 

relieve pressure on the grid. 

Because the EPA is proposing a 10-year period over which to 

achieve the full required CO2 reductions we would expect would 

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 

as conditions change may need to make adjustments 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 

retirements, additional generation and energy efficiency. The 
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analysis did not raise concerns over regional resource adequacy. 

The EPA further examined how the policy options impacted these 

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. EPA believes 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 plans 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, then 

the EPA must establish a plan. 

In the case of a tribe that has one or more affected EGUs 

on its lands, the tribe would have the opportunity, but not the 
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obligation, to establish a CO2 performance standard and a plan 

for its tribal lands. Consequently, developing a section 111(d) 

tribal plan is optional for tribes. 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 section 111(d) tribal 

plan will actively contribute to helping reduce greenhouse gas 

emissions. Though the EPA is aware of three coal-fired EGUs 

located on tribal lands, the agency is not proposing specific 

goals for tribes with affected EGUs in this action at this time. 

EPA will coordinate with those tribes wishing to develop and 

implement a section 111(d) tribal plan by determining BSER for 

the section 111(d) affected units on tribal lands. If a tribe 

chooses not to submit a plan, or if the EPA does not approve a 

tribe’s plan, then the EPA must establish a plan for affected 

EGUs on tribal lands. 

This section is organized into five 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 

to submit, and address timing for achievement of the required 

level of emission performance. Second, we discuss the proposed 

state plan approvability criteria. Third, we summarize the 
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proposed components of an approvable state plan. Fourth, 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, we 

identify several key considerations for states in developing and 

implementing plans, including: affected entities with 

obligations under a plan; treatment of existing state programs; 

incorporation of renewable energy (RE) and demand-side energy 

efficiency (EE) programs in certain plans; quantification, 

monitoring, and verification of RE and demand-side EE measures; 

reporting and recordkeeping for responsible parties; treatment 

of interstate effects; and, projecting emission performance. 

Finally, we discuss a number of additional factors that can help 

states meet their CO2 emission performance goals, and we note 

certain resources we 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 Emission Performance: 

Mass-Based Goals and Plan Performance TSD, both of which are in 

the rulemaking docket. 

B. Approach 

 In this action, the EPA is proposing emission guidelines 

for states to use in developing plans to establish and implement 
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CO2 standards of performance for affected EGUs. In addition to 

the proposed state-specific goals described in the Section VII 

of this preamble, the proposed emission guidelines include 

twelve required components for a state plan to be approvable and 

the process and timing for state plan submittal and review and 

for 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 emission 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 state measures may impact and, in fact may be explicitly 

designed to reduce, regional EGU CO2 emissions. 

1. State plan approaches 

a. Overview 
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The diversity of measures that qualify as the BSER 

indicates that different types of state plans under section 

111(d) could be constructed, and the EPA’s outreach efforts has 

made clear that in fact, states are considering different types 

of plans. An important issue common to all types of plans is 

whether the plan should require the affected EGUs to be 

responsible for assuring that the emissions performance level is 

achieved, or instead, whether the plan could rely 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 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 

light of current state programs, along with stakeholder concerns 

over those issues and legal considerations, the EPA is proposing 

to authorize state plans that do not hold the affected EGUs 

fully responsible for achieving the emissions performance level. 

In addition, the EPA is soliciting comment on several other 

types of state plans that may assure the requisite level of 

emissions performance without rendering certain types of 

measures federally enforceable and to limit the obligations of 

the affected EGUs. 

b. Portfolio approach 
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 In assessing the types of state plans to authorize, the EPA 

reviewed existing state programs designed to reduce CO2 emissions 

from fossil-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 

reduced utilization of, and therefore reduced emissions from, 

fossil-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-fired EGUs would be required to bear 

for the required emissions 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 fossilfired EGUs, and without imposing legal responsibility for these 

emission reductions on those EGUs. 
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 Accordingly, the EPA is proposing to authorize a state plan 

to adopt what we refer to as the “portfolio approach,” in which 

the plan would include emission limits for affected EGUs along 

with other enforceable 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

emissions 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 emissions 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 ”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, 
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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.132

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

would include 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.133

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 

party or parties 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 

 

132 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.

133 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 generation assets. 
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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 §111(d)(1) as requiring that when 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 emissions reductions on the sources in the affected 

source category. Accordingly, again as noted below, we are 

soliciting comment on whether state plans must require the 

affected EGUs to be legally responsible for achieving the 

emissions performance level. 

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

the northeastern states, do impose the ultimate responsibility 

on fossil-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 cost. 
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These existing programs offer a possible precedent for another 

type of section 111(d) state plan. Such a plan could rely on CO2

emission limits enforceable against affected EGUs to ensure 

achievement of the required emission performance level, but also 

include enforceable RE and demand-side EE measures that lower 

cost and otherwise facilitate EGU emission reductions. In this 

manner, RE and demand-side EE measures could be a major 

component of a state’s overall strategy for cost-effectively 

reducing EGU CO2 emissions.134

d. Federal enforceability 

 We are also cognizant of another concern expressed by some 

stakeholders, which is that including RE and demand-side EE 

measures in state plans would render those measures federally 

 134 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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enforceable and thereby extend federal presence into areas that, 

to this point, largely have been the reserve of the state and, 

in particular, state public utility companies. These 

stakeholders point out that states could rely on RE and demandside EE programs as complementary measures to reduce costs for, 

and otherwise facilitate, EGU emission limits without including 

those measures in the section 111(d) state plan. Under those 

circumstances, the measures would not be enforceable under 

federal law, but 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 section 

111(d) state plan, even without including those measures in the 

plan. 

e. Plans with state commitments 

As a vehicle for approving 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 
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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 

emissions reductions of behalf of affected EGUs. The agency 

requests comment on the legal authority for this approach. The 

agency also requests comment on the policy ramifications of the 

following: Under this approach, the state programs upon which 

the state bases its commitment may, in turn, rely on compliance 

by third parties, and if those state programs fail to achieve 

the expected emissions 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 
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the following manner: The state plan would impose the full 

responsibility for achieving the emissions performance level on 

the affected EGUs, but the state would credit the EGUs with the 

amount of emissions 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 

discussed above. We solicit comment on whether, if the EPA were 

to conclude that section 111(d) requires state plans to include 

standards of performance applicable to affected EGUs that 

achieve the emissions performance level, this type of state plan 

would meet that requirement while also assuring those EGUs an 

important measure of support. 

f. Legal issues 

The EPA is 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 
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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 in this rulemaking concern whether 

such emission limits are the only mechanisms that state plans 

may include for achieving the emissions performance level, and 

whether only affected EGUs may be subject to requirements 

associated with reducing their emissions. The resolution of 

those issues depends on whether the state plan requirements in 

section 111(d)(1), quoted above, are interpreted so 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 

application of BSER. 

Specifically, we solicit comment on interpretations of 

these provisions that would authorize the portfolio approach 
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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. 

Second, we solicit comment on whether the requirement that 

the plan include “standards of performance for [affected 

sources]” could be interpreted to include the emissions 

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 

measures could be considered measures that implement the 

emissions 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 
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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 reducing 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 emissions 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 

they are not associated with emission reductions that affected 

sources are required, through emission limits, to make. 

Finally, 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. 
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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 types of state plans 

and measures. 

2. Timing for implementation and achievement of goals 

 This section addresses the process and timing for 

demonstrating achievement of emission performance goals and 

compliance with the emission performance levels in the state 

plans. 

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 carbon 

emissions, particularly blocks 3 (expansion of cleaner 

generation capacity) and 4 (increasing demand-side energy 

efficiency), on forward-looking, 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 RE generation over 

time. As such, 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 

reductions from those and other measures in the short-term. 

Therefore, the EPA is proposing that states begin meeting 
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interim goals, beginning in 2020. The EPA also believes that 

timing flexibility in implementing measures provides significant 

benefit to 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 reductions 

between 2020 and 2030 as long as a cumulative overall emission 

reduction target is met. 

 The subsections below contain proposals for: a) a more 

thorough discussion of the time period covered by state plans, 

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. The 

agency also is requesting comment on alternative requirements 

aimed at continued emission performance improvement after 2029. 

Section [VII. F] proposes flexibility from 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’s alternative, less stringent state goals. 

a. Time period covered by state plans 
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 As described previously, the agency is proposing final 

state-specific goals (specified in Table 5) that represent 

emission rates achievable by 2030, as well as interim goals, 

achievable on average over the 10-year period from 2020-2029. 

The agency is also proposing that the final state-specific goals 

be maintained from 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 

achievement of the emission performance levels in the plan, and 

these emission performance levels must be equivalent to the 

interim and final goals established by the EPA. In its plan, the 

state must also demonstrate that performance meeting the final 

goal will be maintained beyond 2030. 

 The rationale for this approach is that it would ensure 

that states design their plans in a way that considers both the 
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interim and final goals. If only the interim goal were 

considered, a state plan might not be sufficient to achieve the 

final goal.135 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 

interim and final goals but would not be required to demonstrate 

that the final emission performance level will be maintained 

 

135 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 emissions 

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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over time. Instead, states would be required to make a submittal 

in 2025 showing whether their plan measures would maintain the 

final-goal level of performance over time (under one of the outyear approaches described in the relevant section below). If 

not, the state submittal would be required to add to the state 

plan additional measures 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 

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 options. 
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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 performance period.136 The agency generally requests comment 

on the appropriate start date and rationale. 

In considering the start date, it is relevant to consider 

the due dates for state plan submittals and the amount of time 

available for program implementation by the start date. January 

2020 is 3.5 years from the proposed June 2016 deadline for 

initial plan submittals, 2.5 years from the proposed June 2017 

extended deadline for complete plans from states not 

participating in a multi-state plan, and 1.5 years from the 

proposed June 2018 extended deadline for complete plans from 

states participating in a multi-state plan. The EPA suggests 

that regulated entities may have greater lead time for 

compliance than might be implied by the plan submittal dates 

referenced above. Regulated 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 

 

136 The start date for a plan performance period must match the 

start date of the corresponding state emissions 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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plan to EPA. Also, as explained in detail in subsection c, 

states may choose a different emissions performance improvement 

trajectory than EPA assumes for purposes of calculating goals, 

achieving less 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 emissions performance levels. Second, in advance of 

this proposal, many states already were contemplating design of 

strategies for meeting the requirements of section 111(d). 

Third, for inclusion in the building blocks, the EPA considered 

only those abatement measures that are technically viable and 

broadly applicable, and can provide cost-effective reductions in 

CO2 emissions from affected existing EGUs. 

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 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 
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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 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 outages, 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) over a four-year period 

concluding in 2020. 

Dispatch changes, which are largely driven by the variable 

cost of operating a given electric generating unit, 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). 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 
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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 steam 

fossil units to new renewable energy 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 provide cost 

effective reductions in CO2 emissions from existing EGUs. The 

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 

savings as a percentage of retail sales. For the best practices 

scenario, all states achieve this level of performance no later 
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than 2025, with leading states reaching the goal sooner. Each 

state’s current level of performance is taken into account, with 

state’s achieving lower levels of performance being allowed more 

time to reach the best practice level. 

c. Duration of performance periods for final and interim goals 

 The EPA recognizes that a state’s circumstances and choice 

of emission reduction strategies may affect the timing of CO2 

emission performance improvement within a multi-year planning 

period. States can be expected to select various combinations of 

measures and those measures may vary in the time needed to reach 

full implementation. The agency recognizes that certain 

emissions 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 to 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. 
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 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 emissions 

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 achievable 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. 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 must initially 

achieve the final emission performance level by 2030, as 

reflected by a 3-year average over the 2030-32 period. 

 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 
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achieve the final performance level. The three-year performance 

period for initial achievement of the final performance level is 

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. 

 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 

output137 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.E. 

For a mass-based plan, 2020-2029 emission performance is total 

tons of CO2 emitted by affected EGUs over the ten-year 

performance period. 

 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 

 

137 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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types of state plans include interim progress milestones, as 

described in Section VIII.A.2.c of this preamble. 

 The EPA requests comment on a second approach, Option B, to 

state plan performance periods. Option B is the same as Option A 

except that, in addition to the requirements for Option A, a 

state plan also would need to achieve a 5-year average emission 

performance level reflecting application of BSER for the 2020-

2024 period. This 5-year performance period would nest within 

the 10-year performance period for the 2020-2029 period. The 

purpose of Option B would be to ensure greater emission 

performance improvement during the first five years by 

precluding states from significantly delaying compliance 

obligations until the last five years. However, Option B 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 plan. 

d. Interim progress milestones 

 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 
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programmatic milestones to ensure interim progress, as well as 

periodic checks on overall emissions performance leading to 

corrective action if necessary. 

 Some types of plans inherently would assure interim 

performance and full achievement of the state plan’s required 

level of performance through requirements that are enforceable 

against affected EGU, and we refer to these as “self-correcting” 

plans. One example would be a state plan with a rate-based 

emission performance level that requires affected EGUS 

collectively to meet, on a three-year average basis, a statewide 

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., limits that apply to 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 
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progress and 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 programmatic 

milestones (e.g., start of an end-use energy efficiency program, 

retirement of an affected EGUs, 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 would evaluate 

actions under CAA authorities to ensure timely program 

implementation. 

 In addition, we propose that the state and the EPA would 

check emission performance achieved versus performance projected 

in the state plan at least every two years. If actual emission 

performance is not within 10 percent of original projections, 

the state would be required to submit a report to the EPA within 

6 months of the two-year check point. The report would 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 actions that will be taken to ensure 

that the required level of emission performance in the plan will 
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be met. The state also would be required to implement those 

corrective actions 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 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. 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 emissions performance should only be maintained -- 

or instead should be further improved -- once the 2030-2032 goal 

is met. This involves questions of goal-setting as well as 

questions about state planning. In this section, the EPA 

proposes that a state must maintain the required level of 

performance, and requests comment on the alternative of 

requiring continued improvement. 
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 The EPA believes that Congress intended the emission 

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

permanent. 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. The EPA requests comment on 

mechanisms 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. 

 One implementation option would be to require the state 

plan to demonstrate that emission performance would continue to 

meet the plan period final goal on a three-year rolling average 

basis for up to 10 years (i.e., 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 
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level of performance required. The state could either continue 

to implement those limits (no new submittal required) 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 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 

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. 

 The EPA generally requests comment on appropriate 

requirements to maintain the emission performance of affected 

EGUs in years after 2032. 

 Alternatively, the EPA requests comment on whether the EPA 

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, EPA 
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would apply its goal-setting methodology based on application of 

BSER in 2030 and beyond to a specified date. The agency requests 

comment on the appropriate final year for the EPA’s calculation 

of state goals that reflect application of BSER. 

f. 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 

mass-based performance level for the 2020-2029 period, the state 

plan may still use a rate-based performance level for the 2030-

2032 performance period, 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 headroom 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 that the state demonstrates 

will meet its translated, mass-based post-2029 goal for the 

relevant performance period. 

g. Planning approach for alternative state goals 

 In Section VII, the EPA requests comment on alternative, 

five-year state emission performance goals for affected EGUs 
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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 option for state plan performance periods, 

Option C. This option would require state plans to show that the 

required emission performance level will be met on average by 

affected EGUs during the five-year 2020-2024 period. The 

required post-2024 level of emission performance would be 

initially demonstrated on a three-year average basis for 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, EPA requests comment on the same “out-year” 

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, EPA requests comment on whether 
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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. 

In addition, the agency requests comment on the appropriate date 

for any second state plan submittals 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 this preamble. We will evaluate the 

sufficiency of each plan meeting those components based 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.138 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 

 

138 Flexibilities provided to states in meeting this general 

approvability criterion are discussed below in Section 

VIII.B.2., emission performance.
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entity), CO2 emission performance outcomes, and implementation of 

corrective actions, if necessary. The EPA takes comments on all 

aspects of these general criteria and the ten specific plan 

components described below. 

1. Enforceable measures 

The first criterion 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.139 

This guidance serves as the foundation for the types of emission 

limits that 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 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 other enforceable 

 

139 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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measures that, by facilitating reduced utilization of affected 

EGUs, would avoid EGU CO2 emissions, and would be implemented by 

the state or by another party assigned responsibility by the 

state. As noted above, we are proposing that state plans need 

not be required to impose emission limits on affected EGUs that 

in themselves fully achieve the emission performance level, but 

we are seeking comment on whether state plans where emission 

limits applicable to affected EGUs alone would not assure full 

achievement of the required level of emission performance, 

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.140 

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 

 

140 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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considerations under different state plan approaches, which is 

addressed below in VIII.E. 

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 

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. 

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 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 
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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 

specify 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 
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emission guidelines. With one exception, these proposed 

requirements are consistent with those in the proposed EGU 

Carbon Pollution Standards for New Power Plants. See 79 FR 1430-

1519 (January 8, 2014). The exception is that we are proposing 

that useful energy output be measured in terms of net output 

rather than gross output, as discussed below. 

For state plans that include other measures that avoid EGU 

CO2 emissions, such as RE and demand-side EE measures, the state 

will also need to include quantification, monitoring, and 

verification provisions in its plan for these measures, which 

may vary depending on the types of requirements included in the 

specific plan, as specified in the emission guidelines. This may 

include, for example, quantification, monitoring, and 

verification of RE generation and demand-side EE energy savings 

under a rate-based approach.141

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) 

 

141 Considerations for quantification, monitoring, and 

verification of RE and demand-side EE measures are addressed in 

Section VII.E and in the State Plan Considerations TSD. 
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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 the multi-year plan period 

if emission performance is not met, or at specified interim 

stages within the multi-year plan period. For plans with selfcorrecting 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.E. 

The agency is also proposing that a state plan specify 

appropriate periodic reporting requirements for each affected 

entity in a state plan that should 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 
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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 the EPA framework 

regulations at 40 C.F.R. 60.23–60.29, and include 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 other parties 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 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
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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, 

tools, methods, and assumptions used to translate from the ratebased goal to the mass-based goal. 

We are requesting comment on whether, to assist states that 

seek to translate the rate-based goal into a mass-based limit, 

the EPA should provide a presumptive translation of rate-based 

to mass-based goal 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 ratebased goal to a mass-based goal. This could include information 

about acceptable analytical methods and tools, as well as 
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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 Emission Performance: Mass-Based Goals and Plan 

Performance 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 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 
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achieve the state’s emission performance level within the plan 

period. This demonstration will include a detailed description 

of the analytic process and tools used to project future CO2

emission performance by affected entities 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 

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 
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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 emissions 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 emissions 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 EGU in the state 

versus 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. Backstop measures 

For a plan that does not include self-correcting 

mechanisms, the plan must also specify corrective measures that 
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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. 

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 proposed Carbon 

Pollution Standard, 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 

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. To 

maximize flexibility for the states, and in recognition that 
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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, surplus, 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.142 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. 

 

142 EPA guidance on enforceability includes: September 23, 2987 

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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For each standard of performance, a plan must describe how 

it is quantifiable, surplus, 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 (i.e., scientifically based, 

peer-reviewed, and EPA-approved), in a manner that can be 

replicated. A standard of performance is surplus 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. 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 emissions could be considered surplus for 

purposes of CAA section 111(d), even if generation from that 

wind farm was also being used to generate credits to comply with 

the state’s RPS requirements. Credit from avoided CO2 emissions 

from 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 all affected 

EGUs subject to the multi-state plan.. The EPA solicits comment 

as to whether a reduction, not previously part of a plan, 
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becomes non-surplus (and therefore cannot be used for future 

crediting) if it is used as part of any state’s demonstration of 

compliance with 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 

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 are in place to enable the state and 

the Administrator to independently evaluate, measure, and verify 

compliance with it. 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 
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against violations and secure appropriate corrective actions 

pursuant to Sections 113(a)–(h) of the Act. 

9. Identification of monitoring, reporting, and recordkeeping 

requirements 

The state plan must describe the CO2 emission monitoring, 

reporting, and recordkeeping requirements for affected entities, 

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. 

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) 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 
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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.) 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. 

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.) Also, 

consistent with the requests for comment in the proposed GHG 

NSPS regulations for new, modified, and reconstructed sources, 
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we invite comment here on a range of two-thirds to 100 percent 

credit for useful thermal output in the final rule. 

 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 

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. 

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 
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 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 

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 shall 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 framework 

regulations. 

12. Supporting material 
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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 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 

utility commission orders, and any other applicable legal 

instruments. 

A state plan shall 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, under 

the framework regulations state plans would be due nine months 

after finalization of the emission guidelines. 40 CFR 
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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 

response to these concerns, the EPA is proposing a plan 

submittal process with a submittal date of June 30, 2016 (one 

year 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. 

This approach involves the option that we refer to as an initial 

submittal, followed by submittal of a complete state plan at a 

later date. 

In addition, for states wishing to participate in a multistate plan, the EPA is proposing that only one multi-state plan 

needs be submitted on behalf of all participating states, 

provided it is signed by authorized officials for each of the 

states participating in the multi-state plan and contains the 

necessary regulations, laws, etc. for each state in the multistate plan. In this instance, the joint submittal would have the 
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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,143 In view of the complexity of these plans, we are 

extending 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 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. The EPA will respond to a state letter 

requesting an extension of the plan submittal date within 45 

days through a formal letter response. 

 

143 40 CFR 60.23(a)(1). 
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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 would consider for 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 emission guidelines, then the EPA will 

notify the state by letter, within 60 days, that it has received 

the initial state plan and that it appears to meet the minimum 

requirements. The letter will also specify the date by which the 

complete plan must be submitted to the EPA. 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 
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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, 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.144 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, the state must make an initial submittal by June 

30, 2016. To be approved, the initial submittal must meet the 

following proposed criteria: It must address all components of a 

complete plan, including identifying which ones are not 

complete. For incomplete components, the 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 

 

144 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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than other options. For the EPA to approve an extension of time 

for submittal of a complete plan, the initial submittal 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 
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 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. 

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 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 

appears to meet the minimum requirements. The letter will also 

specify the date by which the complete plan must be submitted to 

the EPA. 

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 
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determination, within six months, to approve or disapprove the 

plan through a notice-and-comment rulemaking process. 

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 state will need to 

make a number of decisions that will require careful 

consideration, in order to ensure that its plan both meets a 

state’s policy objectives and is approvable by EPA. In this 

section, we identify several key decision points and factors 

that states should consider when developing their plans. 

The EPA has also drafted 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 
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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 (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 itself. 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 of standards of 

performance upon particular affected entities other than EGUS, 

and if so, which such entities, and what is the justification 

for the limitations. 

2. Treatment of existing state programs 
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a. Framing considerations 

Many state officials and stakeholders have said that the 

EPA should avoid structuring the CAA section 111(d) emission 

guidelines in a way that would disadvantage states that already 

have adopted CO2-reducing programs. 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. 
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As explained in Section VII above, the EPA’s proposed 

state-specific goals reflect many of the actions states have 

already taken to reduce or avoid EGU CO2 emissions. CO2 emission 

reductions due to shifts to lower CO2-emitting power generation 

are also represented in the 2012 base period that was used to 

assess certain building blocks that are applied in calculating a 

state emission performance goal.145

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 

 

145 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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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,146 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 period due to actions taken after the date of this 

 

146 An “existing measure” refers to a state or utility 

requirement, program, or measure that is currently “on the 

books.” For the purposes of this discussion, this may include a 

legal requirement that includes current and future obligations 

or current programs and measures that are in place and are 

anticipated to be continued or expanded in the future in 

accordance with established plans. Existing measures may have 

past, current, and future impacts on EGU CO2 emissions.
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proposal. 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 that 

the EPA used to propose state emissions 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 as a result of requirements in a state plan could be 

recognized as contributing toward meeting a state’s required 

emission performance level. 

In general, the agency has identified two broad options for 

treatment of existing state programs and measures. As noted 

above, the EPA proposes emission reductions that existing state 

requirements, programs, or measures achieve during the plan 

period due to actions taken by a specified date. 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 period, the 

date of promulgation of emission guidelines, the end date of the 

base period for the EPA’s BSER-based goals analysis (e.g., 
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beginning of 2013 for blocks 1-3 and beginning of 2017 for block 

4, end-use energy efficiency), the end of 2005, or another date. 

For this option, we are seeking comment on the point in 

time after which such measures should be able to qualify for use 

during the plan 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 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 period are premised in part on a ramping up of end-use 

energy efficiency program and cumulative energy savings prior to 

the beginning of the plan 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 
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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 emission reductions that existing state 

requirements, programs, or measures achieved starting from a 

specified date prior to the plan period, as well as emission 

reductions achieved during the plan 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 

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 
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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 a state plan 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 the plan period, and related avoided CO2

emissions, that could be applied toward meeting a required ratebased emission performance level. Under the proposed option, the 
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eligibility date would be the date of these proposed emission 

guidelines. For example, under this approach, new renewable 

energy generating capacity installed in 2015 or later to meet an 

existing, on-the-books renewable portfolio standard would be a 

qualifying measure. However, only MWh generation 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 an enduse 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.E.7. below and in the Projecting 

Emissions Performance: Mass-Based Goals and Plan Performance 

TSD. 

1. Incorporating RE and demand-side EE measures under a ratebased approach 
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 We are proposing that RE and demand-side EE measures may be 

incorporated into a rate-based approach through an adjustment or 

tradable crediting system applied to an EGU’s reported CO2

emission rate.147 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 EGUs148 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. 

 

147 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.

148 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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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 RERE 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.149 In practice, the average or 

 

149 As a result, the assumed avoided CO2 emissions from an 

individual MWh of energy savings or MWh of generation from 
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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 

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 

 

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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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 savings. 

Utilities and states have conducted ongoing evaluation of 

end-use energy efficiency and renewable energy measures and 

programs for several decades. These evaluations, which include 

quantification, monitoring, and verification of results, 

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 experience with these 
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measures and programs, and the overall magnitude of program 

impacts. 

Current state and utility quantification, monitoring, and 

verification approaches for RE and demand-side EE programs and 

mandates are discussed 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 should 

establish good practice guidance for quantification, monitoring, 

and verification of RE and demand-side EE measures for an 

approvable state plan, and on the content of such guidance. We 

are also seeking comment on the appropriate basis for and 

resources used to establish such guidance, if the EPA were to 

take this approach. This includes consideration of existing 

state and utility protocols, as well as any international, 

national, and regional consensus standards or protocols. 

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 verification of results is relatively 

straightforward and which are appropriate for inclusion in a 
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state plan. Such approaches might be subject to streamlined 

review of quantification, monitoring, and verification 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 verification 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 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, but may require 

development of appropriate quantification, monitoring, and 

verification protocols. 

5. Reporting and recordkeeping for responsible parties 

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 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 responsible 

entities implementing RE and demand-side EE measures in an 

approvable state plan are provided in the State Plan 

Considerations TSD. We are seeking comment on the examples and 

suitability of potential approaches described in the TSD and any 
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other appropriate recordkeeping and reporting requirements for 

affected entities beyond affected EGUs. 

6. Treatment of interstate effects 

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 measures 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 

consistent manner, to minimize 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 
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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 

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 
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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 emision 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 

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 
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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 

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 to include a 
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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 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, 

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, 
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such as use of a capacity planning and dispatch model.150 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 

emissions performance under different types of state plan 

approaches, are discussed in detail in the Projecting Emissions 

Performance: Mass-Based Goals and Plan Performance TSD. 

We are seeking comment on the considerations discussed in 

this technical support document, including options presented for 

how projections might be conducted in an approvable state plan, 

and how different types of state plan approaches are represented 

in these projections. We are 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 

 

150 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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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 RTO or ISO 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. 

8. 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 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.” 
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As the EPA recognized in 1975 when it adopted framework 

regulations for implementation of section 111(d) including the 

“useful life” statutory provision, application of these 

provisions may not be appropriate in every instance.151 For the 

reasons discussed below, 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 is unnecessary. The agency is requesting comment 

on its analysis below of the implications of 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. 

The section addresses the legal background, implications 

for implementation of these emission guidelines, and lack of 

relevance to 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 

 

151 The agency is not reopening or considering changes to the 

existing framework regulations. 
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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 

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, 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 
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by paragraph (c) of this section152, 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 

standard or final compliance time significantly more 

reasonable. 

The reference to “[u]nreasonable cost of control related to 

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 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 

 

152 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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alter the extent to which states may authorize relaxations to 

standards of performance that would otherwise apply to a 

particular source or source category. 

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. 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 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 

section 111(d) plans to achieve those goals, no relief for 

individual facilities is needed from requirements in the EPA’s 
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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 appears that the quoted regulatory 

text above on remaining useful life and other factors need not 

apply to implementation of this proposed emission guideline. The 

agency requests comment on its interpretation. 

c. Lack of relevance to state emissions 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 emissions 

performance goal or the state’s obligation to develop and submit 

an approvable section 111(d) plan that achieves that goal by the 

applicable deadline. 
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Under the proposed guideline, states would have the 

flexibility to adopt a state plan that relies on emissionsreducing requirements that do not require affected EGUs with a 

short remaining useful life to make major capital expenditures153

or incur unreasonable costs. Indeed, the EPA’s proposal would 

provide states with broad flexibility regarding ways to improve 

emissions 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 EGU, 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 

 

153 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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individual EGU in light of that EGU’s remaining useful life or 

any other source-specific factors that the state deemed 

appropriate to consider.154 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. 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). 

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 

 

154 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 

EPA’s BSER analysis, as long as they provide additional compensating emission 

reductions with respect to the other three building blocks. 
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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, EPA operated the 

emissions trading program for New Hampshire sources, from 

allocating allowances to compliance determination. 
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Additionally, as noted elsewhere in this preamble, more than 

25 states have mandatory renewable portfolio standards and other 

states have voluntary renewable programs and goals. There is 

considerable diversity among the states in the scope and 

coverage of these standards, in particular in how renewable 

resources are defined. At the federal level, the EPA has 

considered the greenhouse gas implications related to biomass 

use at stationary sources through several actions, including a 

call for information from stakeholders and the development and 

review of the “Accounting Framework for Biogenic CO2 Emissions 

from Stationary Sources,” issued in September 2011. That study 

was reviewed by the EPA’s Science Advisory Board in 2011 and 

2012 and the Agency continues to assess the framework and 

consider the latest scientific analyses and technical input 

received from stakeholders. The EPA expects that the framework, 

when finalized, will be a resource that could help inform States 

in the development of their 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 end-
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use 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,”155 as well 

as the State Energy Efficiency Action Network’s “Energy 

Efficiency Program Impact Evaluation Guide.”156 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 

 

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

156

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

_guide.pdf
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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,157 National Action Plan for Energy 

Efficiency (NAPEE),158 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. 

 

157 Currently under development as a TSD

158 http://www.epa.gov/cleanenergy/energyprograms/suca/resources.html
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The EPA solicits comment on this approach and the 

information currently included, and planned for inclusion, in 

the Decision Support Toolbox. 

IX. Implications for Other EPA Programs and Rules 

A. Implications for New Source Review Program 

 The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 

source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For GHG emissions, the PSD applicability 

analysis is described in the Prevention of Significant 

Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 

31514, June 3, 2010). As a general matter, a modifying major 

stationary source would trigger PSD permitting requirements for 

GHGs if it emits GHGs in excess of 100,000 tons per year (tpy) 

of carbon dioxide equivalents (CO2e), and it undergoes a change 

or change in the method of operation (modification) resulting in 
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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 

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 
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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 

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 
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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 

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 
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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 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. 

C. Interaction With Other EPA Rules 

Existing fossil fuel-fired EGUs, such as those covered in 

this proposal, are or will be potentially impacted by several 
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other recently finalized or proposed EPA rules.159 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 

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. Existing sources subject 

to the MATS rule are given until April 16, 2015 to comply with 

the rule's requirements; if an 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-bycase basis, if such additional time is necessary for the 

installation of controls. [Text on December 2011 Enforcement 

 

159 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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Response Policy and/or progress in MATS implementation will be 

added.] 

 On [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.160 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 are 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, which are not projected to impose a 

 

160 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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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 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 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, 
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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. 

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 
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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.161 While the agency is still evaluating all the 

available information and comments, and while a final risk 

assessment for the CCR rule has not yet been completed, reliance 

on data and analyses discussed in the preamble to the recent 

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 

 

161 Beneficial use involves the reuse of CCRs in a product to 

replace virgin raw materials that would otherwise be obtained 

through extraction. The EPA encourages the beneficial use of 

CCRs in an appropriate and protective manner, because this 

practice can produce environmental, economic, and performance 

benefits. The Agency recently evaluated the environmental 

impacts associated with encapsulated beneficial uses of fly ash 

used as a direct substitute for Portland cement in concrete, and 

FGD gypsum used as a replacement for mined gypsum in wallboard. 

The EPA concluded that the beneficial use of CCRs in concrete 

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). 
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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. The EPA is under a courtordered 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.” 

As discussed in Sections VII and VIII of this preamble, the 

EPA is proposing to give states broad flexibility in developing 

approvable plans under CAA section 111(d), including the ability 

to adopt rate-based or mass-based emission performance goals, 

and to rely on a wide variety of CO2 emission reduction measures. 

The EPA is also proposing to give states considerable 
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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.162

The EPA is also endeavoring to enable EGUs to comply with 

applicable obligations under other power sector rules as 

efficiently as possible (e.g., by facilitating their ability to 

coordinate planning and investment decisions with respect to 

 

162 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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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.163 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.164

 

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

34441. 

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

language from proposed the SE ELG rule as a footnote:] In 

considering how to coordinate the potential requirements between 

the SE ELG and CCR rules, the EPA stated that it is guided by 

the following policy considerations: first and foremost, the EPA 

intends to ensure that its statutory responsibilities to restore 

and maintain water quality under the CWA and to protect human 

health and the environment under RCRA are fulfilled. At the same 

time, the EPA would seek to minimize the potential for 

overlapping requirements to avoid imposing any unnecessary 

burdens on regulated entities and to facilitate implementation 

and minimize the overall complexity of the regulatory structure 

under which facilities must operate. Based on these 

considerations, the EPA stated that it is exploring two primary 

means of integrating the two rules: (1) through coordinating the 

design of any final substantive CCR regulatory requirements, and 

(2) through coordination of the timing and implementation of 

final rule requirements to provide facilities with a reasonable 

timeline for implementation that allows for coordinated planning 

and protects electricity reliability for consumers. 
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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. 

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 
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the SO2 standard. 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 future165. The EPA has proposed the data 

requirements rule for the 1-hour SO2 NAAQS to require states to 

characterize air quality more extensively using ambient 

monitoring or air quality modeling approaches. 

The EPA requires SIP updates every 10 years for regional 

haze, as required by the EPA’s Regional Haze Rule which was 

promulgated in 1999. The next 10-year SIP revision for regional 

haze, covering the time period through 2028, is due from each 

state by July 2018. Each SIP must provide for reasonable 

progress towards visibility improvement in protected scenic 

areas. 

The development of these SIPs may, where applicable, have 

significant implications for existing fossil fuel-fired EGUs, as 

well as for the states that are responsible for developing them. 

 

165 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 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 

requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 
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X. Impacts of the Proposed Action166

A. What are the air impacts? 

The EPA anticipates significant emission reductions under 

the proposed guidance. CO2 emissions are projected to be reduced, 

relative to the base case, by ___ percent in 2020 and ___ 

percent in 2030 under Option 1. Option 2 reflects reductions of 

___ percent in 2020 and ___ percent in 2025. Tables 7 and 8 show 

expected climate and other air pollutants in the base case, with 

the proposed guidance and the anticipated 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 Option 2, 

respectively. 

Table 7 – Summary of Climate and Air Pollutant Emission 

Reductions with Proposed Option 1 - 2020 

 CO2 (million 

metric 

tonnes) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

Base Case 

Proposed 

Guidance 

 

 

166 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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Change 

Table 8 – Summary of Climate and Air Pollutant Emission 

Reductions with Proposed Option 1 - 2030 

 CO2 (million 

metric 

tonnes) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

Base Case 

Proposed 

Guidance 

 

Change 

 

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 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. What are the energy impacts?
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 The proposed guidelines have important energy market 

implications. Under Option 1, average nationwide retail 

electricity prices are projected to _____ in the contiguous U.S. 

by ___ percent in 2030. While consumers average monthly 

electricity bills are anticipated to decline by ___ percent in 

2030. 

 The average delivered coal price to the power sector is 

projected to _____ by ___ percent in 2020 and ___ percent in 

2030, relative to the base case with Option 1. The EPA also 

projects that electric power sector-delivered natural gas prices 

will _____by __ percent in 2020 and _______ by __ percent in 

2030. Natural gas use for electricity generation will ______ by 

___ billion cubic feet (BCF) in 2020 relative to the base case. 

Finally, the EPA projects coal production for use by the power 

sector, a large component of total coal production, will _______ 

by ___ million tons in 2020 from base case levels, which is 

about ___ percent of 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 

projection by ___ GW. If current forecasts of either natural gas 
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prices or electricity demand are revised in the future to be 

higher, there would be greater incentive to keep these coalfired units operational. Energy impacts of the proposed 

guidelines are discussed more extensively in the RIA that is in 

the docket for this action. 

C. 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. 

 The EPA projects that the annual incremental compliance 

cost of Option 1 is estimated to be $___ billion in 2020 and 

$___ billion (2011$) in 2030, excluding the costs associated 

with monitoring, reporting, and recordkeeping (MRR). The 

incremental compliance cost of Option 2 is estimated to be $___ 

billion in 2020. In 2025, the estimated compliance cost of 

Option 2 is estimated to be $ ___ billion (with the assumed 
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levels of end-use energy efficiency). These important dynamics 

are discussed in more detail in the RIA. 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 $____ million (2011$) 

in 2020 for Option 1. More detailed cost estimates are 

available in the RIA included in the docket. 

D. What are the economic and employment impacts? 

The proposed standards are projected to result in certain 

changes to power system operation as a result of the application 

of State emission rate goals. Overall, we project dispatch 

changes, changes to fossil fuel and retail electricity prices, 

and some additional coal retirements. Natural gas prices are 

projected to ______ by roughly ___ percent in 2020 in Option 1 

and by ____percent under Option 2 in 2020, on an average 

nationwide basis. Under Option 1, natural gas prices ____ by 

percent in 2030. Coal prices are projected to ______ by roughly 

___ percent in 2020 under both Options, on a nationwide average 

basis. Retail electricity prices are projected to _____ by 

percent under Option 1 and _____ by ____ percent under Option 2, 
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both in 2020 and on an average nationwide basis. By 2030 under 

Option 1, electricity prices _____ by ___ percent. Coal 

retirements are projected to be ___ W for Option 1 in 2030 and 

___ GW under Option 2 in 2025. 

 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 a ___ reduction on overall electricity demand 

levels in 2030 for Option 1, and a ___ reduction in 2025 for 

Option 2. In response, there are anticipated to be notable 

changes to costs, prices, and electricity generation in the 

power sector as more end-use efficiency is realized. 

Changes in price or demand for electricity, natural gas, coal, 

can impact markets for goods and services produced by sectors 

that use these energy inputs in the production process or supply 

those sectors. Changes in cost of production may result changes 

in price, changes in quantity produced, and changes in 

profitability of firms affected. 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 production 
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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. 

 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, 

quantifying the associated employment impacts is 

difficult. EPA’s employment analysis includes projected 

employment impacts associated these guidelines for the electric 

power industry, coal and natural gas production, and demand side 
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Page 341 of 421

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 XXXXXX to XXXXXX jobyears in 2020. Demand side energy efficiency employment impacts 

may range from approximately YYYYY to YYYYY job-years in 2020. 

E. 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 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 $__ billion to $__ billion in 2020 and $__ 

billion to $__ billion in 2030 (2011 dollars at a 3-percent 

discount rate [model average]). We also estimate the total 
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combined climate benefits and health co-benefits for Option 2 to 

be $__ billion to $__ billion in 2020 and $__ billion to $__ 

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 12 of 

this preamble. 
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Table 11. Summary of the Monetized Global Climate Benefits for 

the Proposed Standards (billions of 2011 dollars)a

CO2 Emission 

Reductions (metric 

tons) 

Discount Rate 

(Statistic) 

Monetized Climate 

Benefits 

Option 1 in 2020 

5 percent (average SCC) 

3 percent (average SCC) 

2.5 percent (average 

SCC) 

3 percent (95th

percentile SCC) 

Option 1 in 2030 

5 percent (average SCC) 

3 percent(average SCC) 

2.5 percent (average 

SCC) 

3 percent (95th

percentile SCC) 

Option 2 in 2020 

5 percent (average SCC) 

3 percent(average SCC) 

2.5 percent (average 

SCC) 

3 percent (95th

percentile SCC) 

Option 2 in 2025 

5 percent (average SCC) 

3 percent(average SCC) 

2.5 percent (average 

SCC) 

3 percent (95th

percentile SCC) 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 12. Summary of the Monetized Health Co-Benefits for the 

Proposed Standards in the U.S. (billions of 2011 dollars)a

Pollutant 

National 

Emission 

Reductions 

(short tons) 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

Monetized 

Health Cobenefits 

(7 percent 

discount) 

Option 1 in 2020 

PM2.5 precursors b 

SO2 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 

Ozone precursor c 

NOx 

Total Monetized Health Co-benefits 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

 

Option 1 in 2030 

PM2.5 precursors b 

SO2 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 

Ozone precursor c 

NOx 

Total Monetized Health Co-benefits 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

 

Option 2 in 2020 
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PM2.5 precursors b

SO2 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 

Ozone precursor c

NOx 

Total Monetized Health Co-benefits 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

 

Option 2 in 2025 

PM2.5 precursors b 

SO2 

Directly emitted 

PM2.5 (Elemental 

Carbon and Organic 

Carbon) 

 

Directly emitted 

PM2.5 (crustal) 

NOx 

Ozone precursor c 

Nox 

Total Monetized Health Co-benefits 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

 

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. 
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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 to develop SCC estimates and selected four 

global values for use in regulatory analyses. The U.S. 

government recently updated these estimates using new versions 
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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.167,168 

 

167 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>. 

168 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by the 

Council of Economic Advisers, Council on Environmental Quality, 

Department of Agriculture, Department of Commerce, Department of 

Energy, Department of Transportation, Environmental Protection 
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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).169 The first three values are based on 

the average SCC from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. SCCs at several discount rates 

are included because the literature shows that the SCC is quite 

sensitive to assumptions about the discount rate, and because no 

consensus exists on the appropriate rate to use in an 

intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SCC from all three models at a 3 percent 

 

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>. 

169 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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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 because 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. The new versions of the models used to 

estimate the values presented below offer some improvements in 

these areas, although further work is warranted. Accordingly, 

the EPA and other parties continue to conduct research on 
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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 

instead 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 et al. (2012),170 but they have since been 

updated to reflect the studies and population data in the 2012 

 

170 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. 
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PM NAAQS RIA and were separated into regional estimates to 

provide greater spatial resolution.171 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.172,173 To calculate the co-benefits for the proposed 

standards, we multiplied the regional benefit-per-ton estimates 

for the EGU sector by the corresponding emission reductions.174

 

171 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>. 

172 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>. 

173 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>. 

174 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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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 function 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 
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based on the American Cancer Society cohort study175 and the 

extended Six Cities cohort study.176 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)177

as a characterization of uncertainty regarding the PM2.5-

mortality relationship. For the ozone co-benefits, we present the 

results as a range reflecting the use of several different 

concentration-response functions for mortality, with the lower 

end of the range based on a function from Bell, et al. (2004)178

and the upper end based on a function from Levy, et al. 

 

175 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. 

176 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. 

177 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. 

178 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. 
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(2005)179. 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,180 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. 

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. 

 

179 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. 

180 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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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,181 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 

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 

 

181 In addition, site-specific emission reductions will depend upon how states 

implement the guidelines. 
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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 

various assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 
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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 docket. 

XI. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review 

Under Section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an "economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more or 

adversely affect in a material way the economy, a sector of the 

economy, productivity, competition, jobs, the environment, 

public health or safety, or state, local, or tribal governments 

or communities. The $100 million threshold can be triggered by 

either costs or benefits, or a combination of them. Accordingly, 

the EPA submitted this action to OMB for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011),) and any 
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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 scenarios 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 

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 
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benefits associated with the SCC value deemed to be central by 

the USG: the model average at 3% discount rate. The EPA 

estimates that in 2020 this Option 1 proposal will yield 

monetized climate benefits (in 2011$) of approximately $__ 

billion (3 percent model average). The air pollution health cobenefits in 2020 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 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). 

 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 
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MRR costs, are approximately $__ billion (2011$) in 2030. The 

quantified net benefits (the difference between monetized 

benefits and costs) in 2030 are estimated to be $__ billion to 

$__ billion (2011$) using a 3 percent discount rate (model 

average). Based upon the foregoing discussion, it remains clear 

that the benefits of the proposal Option 1 are substantial in 

2020 and 2030 and far exceed the costs. 

TABLE 13—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 1 IN 2020a

[Billions of 2011$] 

 3% Discount rate 7% Discount rate 

Climate benefits b 

Air pollution health 

co-benefits c

 

Total Compliance 

Costs d

 

Net Monetized 

Benefits e

 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___ tons of Hg and ___ tons of HCl 

Ecosystem Effects 

Visibility impairment 

a

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

figures, so figures may not sum. 
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b

 The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

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

are applied to SCC than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SCC estimated 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 

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 14—SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 1 IN 2030a

[Billions of 2011$] 

 3% Discount rate 7% Discount rate 

Climate benefits b 

Air pollution health 
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co-benefits c

Total Compliance 

Costs d

 

Net Monetized 

Benefits e

 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___ tons of Hg and ___ 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, 

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 
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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 are shown in Tables 15 and 16. As these 

tables reflect, net benefits in 2020 are estimate to be $__ to 

$__ billion assuming a 3 percent discount rate and from $__ to 

$__ billion assuming a discount rate of 7 percent. In 2025, net 

benefits are estimated to be $___ billion to $__ billion (3 

percent discount rate) and from $__ billion to $__ billion (7 

percent discount rate). 

 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 15 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 2 IN 2020a

[Billions of 2011] 
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 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, 

 3% Discount rate 7% Discount rate 

Climate benefits b 

Air pollution health 

co-benefits c

 

Total Compliance 

Costs d

 

Net Monetized 

Benefits e

 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2

___ tons of Hg and __ tons of HCl 

Ecosystem Effects 

Visibility impairment 
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regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

proposed option and a discount rate of approximately 5%. 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 16 — SUMMARY OF THE MONETIZED BENEFITS, COMPLIANCE COSTS, 

AND NET BENEFITS FOR THE FINAL RULE – OPTION 2 IN 2025a 

[Billions of 2011] 

 3% Discount rate 7% Discount rate 

Climate benefits b 

Air pollution health 

co-benefits c

 

Total Compliance 

Costs d

 

Net Monetized 

Benefits e

 

Non-monetized 

Benefits 

Direct exposure to SO2 and NO2___ tons of 

Hg and ___ tons of HCl 

Ecosystem Effects 

Visibility impairment 
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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 

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, 
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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 

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 government (averaged over the 

first 3 years following promulgation of this proposed action) is 

estimated to be 23,377 hours at a total annual labor cost of 

$1,201,952. 

Burden means the total time, effort, or financial resources 

expended by persons to generate, maintain, retain, or disclose 
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Page 368 of 421

or provide information to or for a Federal agency. This includes 

the time needed to review instructions; develop, acquire, 

install, and utilize technology and systems for the purposes of 

collecting, validating, and verifying information, processing 

and maintaining information, and disclosing and providing 

information; adjust the existing ways to comply with any 

previously applicable instructions and requirements; train 

personnel to be able to respond to a collection of information; 

search data sources; complete and review the collection of 

information; and transmit or otherwise disclose the information. 

An agency may not conduct or sponsor, and a person is not 

required to respond to a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations are listed in 40 CFR part 9 

and 48 CFR chapter 15. 

To comment on the agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID Number EPA-HQ-OAR-2013-0602. Submit any 

comments related to the ICR to the EPA and 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 
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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. 

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 
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entity with less than 750 employees. The NAICS codes for the 

affected industry are in Table 17 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 17. 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. 

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 
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Page 371 of 421

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 

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 
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of stakeholder outreach on setting emission guidelines for 

existing EGUs. While formulating the provisions of the proposed 

rule, the EPA considered the input provided over the course of 

the stakeholder outreach. Section III.B. of this preamble 

describes the key messages from stakeholders. In addition, as 

described in the RFA section of the preamble to the proposed 

standards of performance for GHG emissions from new EGUs (79 FR 

1499-1500, January 8, 2014), the EPA conducted outreach to 

representatives of small entities while formulating the 

provisions of the proposed standards. Although only new EGUs 

would be affected by those proposed standards, the outreach 

regarded planned actions for new and existing sources. We invite 

comments on all aspects of the proposal and its impacts, 

including potential impacts on small entities. 

D. Unfunded Mandates Reform Act

This proposed action does not contain a federal mandate that 

may result in expenditures of $100 million or more for State, 

local, and tribal governments, in the aggregate, or the private 

sector in any one year. Specifically, 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. 
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This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

In light of the interest among governmental entities, the 

EPA initiated consultations with governmental entities while 

formulating the provisions of the proposed standards for new 

EGUs. Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new and 

existing sources. As described in the UMRA discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1500-1501, January 8, 2014), the 

EPA consulted with the following 10 national organizations 

representing state and local elected officials: 1) National 

Governors Association; 2) National Conference of State 

Legislatures, 3) Council of State Governments, 4) National 

League of Cities, 5) U.S. Conference of Mayors, 6) National 

Association of Counties, 7) International City/County Management 

Association, 8) National Association of Towns and Townships, 9) 

County Executives of America, and 10) Environmental Council of 

States. On February 26, 2014, the EPA re-engaged with those 

governmental entities to provide a pre-proposal update on the 

emission guidelines for existing EGUs and emission standards for 
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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 proposed action does not 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 impose substantial direct compliance 

costs on state or local governments, nor would it preempt state 

law. Specifically, emission guidelines established under CAA 

section 111(d) do not impose any direct compliance costs on 

regulated entities. Thus, Executive Order 13132 does not apply 

to this action. 

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 on their lands. 
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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 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, 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 
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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. For this proposed action for existing 

EGUs, a tribe that has one or more affected EGUs on its lands182

would have the opportunity, but not the obligation, to establish 

a CO2 performance standard and a plan for its tribal lands. 

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 

summary of issues being explored by the agency. Tribes have 

 

182 The EPA is aware of at least three affected sources located 

in Indian Country, two on [Navajo] lands -- the Navajo 

Generating Station and the Four Corners Generating Station -- 

and one on [Ute] lands – the Bonanza Generating Station. 
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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. 

G. Executive Order 13045, Protection of Children from 
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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 reductions resulting from implementation of the proposed 

guidelines 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 

estimate a ___ percent price increase for retail electricity 

prices nationwide in 2020 and a ___ percent reduction in coalfired power production as a result of this rule. The EPA 
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projects that electric power sector delivered natural gas prices 

will increase by about ___ percent in 2020. For more 

information on the estimated energy effects, please refer to the 

economic impact analysis for this final rule. 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. 

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. 
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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).183 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 

 

183 “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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weight on the fact that certain groups, including children, the 

elderly, and the poor, are most vulnerable to climate-related 

health effects. 

Strong scientific evidence that the potential impacts of 

climate change raise environmental justice issues is found in 

the major assessment reports by the U.S. Global Change Research 

Program (USGCRP), the Intergovernmental Panel on Climate Change 

(IPCC), and the National Research Council (NRC) of the National 

Academies, summarized in the record for the Endangerment 

Finding. Their conclusions include that poor communities can be 

especially vulnerable to climate change impacts because they 

tend to have more limited adaptive capacities and are more 

dependent on climate-sensitive resources such as local water and 

food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly 

those on established reservations that are restricted to 

reservation boundaries and therefore have limited relocation 

options. Tribal communities whose health, economic well-being, 

and cultural traditions depend upon the natural environment will 

likely be affected by the degradation of ecosystem goods and 

services associated with climate change. Southwest native 

cultures are especially vulnerable to water quality and 

availability impacts. Native Alaskan communities are likely to 
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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 standard184, the EPA identified 

persons with lower socioeconomic status as an at risk population 

for experiencing adverse health effects related to PM exposures. 

Persons with lower socioeconomic status have been generally 

found to have a higher prevalence of pre-existing diseases, 

limited access to medical treatment, and increased nutritional 

deficiencies, which can increase this population’s risk to PM-

 

184 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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related and ozone-related effects.185 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 increase 

as a result of the proposed emission guidelines for existing 

fossil fuel-fired EGUs. 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 

 

185 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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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, 

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 
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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. Increased 

utilization generally would not cause high concentrations around 

such EGUs than is already occurring, but may make periods of 

relatively high concentration 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 

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 state 111(d) plan, the state may be able to 

predict which EGUs and communities may be in this type of 

situation and to address any concerns about localized NO2

concentrations in the design of the 111(d) program, or 

separately from the 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 
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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. 

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 
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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 388 of 421

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 emissions performance 

goals? 

60.5770 What is the procedure for converting my state ratebased CO2 emissions 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 emissions 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 for the control of greenhouse gas emissions from an 
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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)(10) 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 emissions performance level 

for affected entities that will be achieved through 

implementation of the plan, during the plan performance period. 

(i) The identified emissions performance level must be 

equivalent to or better than the levels of the rate-based CO2

emissions performance goal in Table 1 of this Subpart for 

affected entities in your state. The emissions performance 

levels may be in either a rate-based form or a mass based form 

which is calculated according to § 60.5770. The CO2 emissions 

performance level specified must include either of the following 

as applicable: 

(a) For a rate-based CO2 emissions 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 
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performance that will be achieved within the plan performance 

period. 

(b) For a mass-based CO2 emissions performance level, the 

identified level of performance must represent the total tons of 

CO2 that will be emitted by affected entities during the plan 

performance period, including identification of any increments 

of performance that will be achieved within the plan performance 

period. 

(4) A demonstration that the plan is projected to achieve 

the state’s emissions performance levels for affected entities 

according to § 60.5740(a)(3). 

(5) Identification of emissions standards for each affected 

entity, compliance period for each emissions standard, and 

demonstration that the emissions standards are, when taken 

together, sufficiently protective to meet the state emissions 

performance level. 

(6) A demonstration that each emissions standard is 

quantifiable, surplus, permanent, verifiable, and enforceable 

with respect to an affected entity. 

(7) 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.
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(8) Description of the process, contents, and schedule for 

annual state reporting to the EPA about plan implementation and 

progress including information required under § 60.5820. 

(9) 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. 

(10) 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 

emissions 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 
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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 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 
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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). 

 (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 
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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. 

(c) For states in a multi-state plan seeking a two year 

extension for a complete plan submittal you must include the 

information in § 60.5760(a) in a submittal by June 30, 2016 to 

receive an extension to submit your complete multi-state plan by 

June 30, 2018. 

§ 60.5760 What must I include in an initial submittal in lieu of 

a complete state plan? 

(a) You must include the following required elements in an 

initial submittal in lieu of a complete state plan: 
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(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 emissions 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 emissions 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 
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(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 emissions 

performance goals for the plan performance periods of 2020 

through 2029, and in 2030 and thereafter are respectively listed 

in Table 1 of this Subpart. The state rate-based CO2 emissions 

performance goal may be converted to a mass-based emissions 

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 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 ratebased 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 for 

each affected entity regulated under the plan. 

(c) Your state plan must show that it will achieve the 

state emissions performance level by end of the performance 

period and as well as at increments of performance within the 

performance period. Additionally you must include provisions to 

demonstrate progress toward the state emissions performance 

level in a state’s annual report. 

§ 60.5780 What emissions standards and enforcing measures must I 
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include in my plan? 

(a) Your state plan shall include emissions standard(s) 

that are quantifiable, verifiable, surplus, permanent, and 

enforceable with respect to each affected entity. The plan shall 

include the methods by which each emissions standard meets each 

of the following requirements in paragraphs (b)-(f). 

(b) An emissions standard is quantifiable with respect to 

an affected entity if it can be reliably measured, in a manner 

that can be replicated. 

(c) An emissions 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 emissions standard. 

(d) An emissions standard is surplus with respect to an 

affected entity if it is not already incorporated as an 

emissions standard in another state plan unless incorporated in 

multi-state plan. 

(e) An emissions standard is permanent with respect to an 

affected entity if the emissions standard must be met for each 

compliance period, or unless it is replaced by another emissions 

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 
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meet its state level of performance. 

(f) An emissions 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 emissions 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 emissions 

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 

of 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 

emissions 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 each 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 emissions 

performance goals. 
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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 a report no later than 60 days after 

completing each annual performance period as defined in your 

state plan regarding the following: 

(1) The level of emissions performance achieved by all 

affected entities and identification of whether affected 

entities are on schedule to meet the applicable level of 

emissions performance for affected entities during the plan 

performance period and compliance periods, as specified in the 

plan. 

(2) The level of emissions performance achieved by all 

affected EGUs during the reporting period, and prior reporting 
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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. 

 (2) A list of affected entities and their compliance status 

with the applicable emissions standards specified in the state 

plan. 

(3) A list of all affected EGUs and their reported CO2

emissions performance for each compliance period during the 

reporting period, and prior reporting periods. 

 (3) All other required information, as specified in your 

state plan according to §60.5740(a)(8). 

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 

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 
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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, 

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 
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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 

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 
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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 

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, 
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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 input of greater than 73 MW (250 MMBtu/h), that 

supplies 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 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 
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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 

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 
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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 

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). 
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(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, 

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 
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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 input of greater than 73 MW (250 MMBtu/h) and that supplies 

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 

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. 
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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).