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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2011-0660; FRL- ]

RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The United States EPA is proposing new source performance 

standards for emissions of carbon dioxide (CO2) for new affected 

fossil fuel-fired electric utility generating units (EGUs). The EPA 

is proposing these requirements because CO2 is a greenhouse gas (GHG) 

and fossil fuel-fired power plants are the country’s largest 

stationary source emitters of GHGs. The EPA in 2009 found that by 

causing or contributing to climate change, GHGs endanger both the 

public health and the public welfare of current and future 

generations. The proposed requirements, which are strictly limited to 

new sources, would require new fossil fuel-fired EGUs greater than 25 

megawatt electric (MWe) to meet an output-based standard of 1,000 

pounds of CO2 per megawatt-hour (lb CO2/MWh), based on the performance 

of widely used natural gas combined cycle (NGCC) technology. Because 
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of the economics of the energy sector, EPA and others project that 

NGCC is will be the predominant choice for new fossil fuel-fired 

generation even absent this rule. In its base case analysis, the EPA 

does not project any new coal-fired EGUs without CCS to be built in 

the absence of this proposal through 2030. New coal-fired or pet 

coke-fired units could meet the standard either by employing carbon 

capture and storage (CCS)1 of approximately 50% of the CO2 in the 

exhaust gas at startup, or through later application of more 

effective CCS to meet the standard on average over a 30-year period. 

The 30-year averaging option could also provide flexibility for 

owners and operators of coal or pet coke units implementing CCS at 

the outset of the unit’s operation that were designed and operated to 

emit at less than 1,000 lb CO2/MWh to address startup concerns or 

short term interruptions in their ability to sequester captured 

carbon dioxide. The EPA is not proposing standards of performance for 

existing EGUs whose CO2 emissions increase as a result of installation 

of pollution controls for conventional pollutants, or for proposed 

 

1 Throughout this preamble, we refer to ‘carbon capture and storage’ 

or CCS. By this, we mean the use of a technology for separating and 

capturing CO2 from the flue gas or syngas stream with subsequent 

compression and transportation to a suitable location for long term 

storage and monitoring. Many references refer to CCS as ‘carbon 

capture and sequestration’. In this preamble, ‘storage’ and 

‘sequestration’ mean the same thing and the words are used 

interchangeably.
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EGUs, which are referred to here as transitional sources, that have 

acquired a complete preconstruction permit by the time of this 

proposal and that commence construction within 12 months of this 

proposal. As a result, those sources would not be subject to the 

standards of performance proposed in today’s rule. 

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 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. The EPA will hold public hearings on this 

proposal. The dates, times, and locations of the public hearings will 

be announced separately. Oral testimony will be limited to 5 minutes 

per commenter. The EPA encourages commenters to provide written 

versions of their oral testimonies either electronically or in paper 

copy. Verbatim transcripts and written statements will be included in 

the rulemaking docket. If you would like to present oral testimony at 
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one of the hearings, please notify Ms. Pamela Garrett, Sectors 

Policies and Programs Division (C504–03), U.S. EPA, Research Triangle 

Park, NC 27711, telephone number (919) 541–7966; email: 

garrett.pamela@epa.gov. Persons wishing to provide testimony should 

notify Ms. Garrett at least 2 days in advance of the public hearings. 

The public hearings will provide interested parties the opportunity 

to present data, views, or arguments concerning the proposed rule. 

The EPA officials may ask clarifying questions during the oral 

presentations, but will not respond to the presentations or comments 

at that time. Written statements and supporting information submitted 

during the comment period will be considered with the same weight as 

any oral comments and supporting information presented at the public 

hearing. For updates and additional information on the public 

hearings, please check the EPA’s website for this rulemaking, 

http://www.epa.gov/airquality/carbonpollutionstandards.

ADDRESSES: Comments. Submit your comments, identified by Docket ID 

No. EPA-HQ-OAR-2011-0660, 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 web site.
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E-mail: Send your comments by electronic mail (e-mail) to a-andr-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2011-0660.

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

No. EPA-HQ-OAR-2011-0660.

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-2011-0660. Please include a total of 

two copies. In addition, please mail a copy of your comments on the 

information collection provisions to the Office of Information and 

Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St. NW, 

Washington, DC 20503.

Hand Delivery or Courier: Deliver your comments to the EPA 

Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, Room 

3334, Washington, DC, 20460, Attn: Docket ID No. EPA-HQ-OAR-2011-

0660. Such deliveries are accepted only during the Docket’s normal 

hours of operation (8:30 a.m. to 4:20 p.m., Monday through Friday, 

excluding legal holidays), and special arrangements should be made 

for deliveries of boxed information.

Instructions: All submissions must include agency name and 

docket ID number (EPA-HQ-OAR-2011-0660). The EPA’s policy is that all 

comments received will be included in the public docket without 

change and may be made available online at 
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http://www.regulations.gov, including any personal information 

provided, 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 e-mail. Send or deliver information 

identified as CBI only to the following address: Roberto Morales, 

OAQPS Document Control Officer (C404-02), Office of Air Quality 

Planning and Standards, U.S. EPA, Research Triangle Park, North 

Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2011-0660. Clearly 

mark the part or all of the information that you claim to be CBI. For 

CBI information in a disk or CD-ROM that you mail to the EPA, mark 

the outside of the disk or CD-ROM as CBI and then identify 

electronically within the disk or CD-ROM the specific information 

that is claimed as CBI. In addition to one complete version of the 

comment that includes information claimed as CBI, a copy of the 

comment that does not contain the information claimed as CBI must be 

submitted 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 a separate copy of your comments also be 

sent to the contact person identified below (see FOR FURTHER 
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INFORMATION CONTACT). If the comment includes information you 

consider to be CBI or otherwise protected, a copy of the comment that 

does not contain the information claimed as CBI or otherwise 

protected should be sent.

The www.regulations.gov website is an “anonymous access” system, 

which means the EPA will not know your identity or contact 

information unless you provide it in the body of your comment. If you 

send an email comment directly to the EPA without going through 

http://www.regulations.gov, your email address will be automatically 

captured and included as part of the comment that is placed in the 

public docket and made available on the Internet. If you submit an 

electronic comment, the EPA recommends that you include your name and 

other contact information in the body of your comment and with any 

disk or CD-ROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, the 

EPA may not be able to consider your comment. Electronic files should 

avoid the use of special characters, any form of encryption, and be 

free of any defects or viruses.

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the index, some 

information is not publicly available (e.g., CBI or other information 

whose disclosure is restricted by statute). Certain other material, 
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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, EPA 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 legal holidays. The 

telephone number for the Public Reading Room is (202) 566-1744, and 

the telephone number for the Air Docket is (202) 566-1742. Visit the 

EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm 

for additional information about the EPA’s public docket.

In addition to being available in the docket, an electronic copy 

of this proposed rule will also 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/. The TTN 

provides information and technology exchange in various areas of air 

pollution control.

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy 

Strategies Group, Sector Policies and Programs Division (D243-01), 

U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 

541-4003, facsimile number (919) 541-5450; email address: 
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fellner.christian@epa.gov or Dr. Nick Hutson, Energy Strategies 

Group, Sector Policies and Programs Division (D243-01), U.S. EPA, 

Research Triangle Park, NC 27711; telephone number (919) 541-2968, 

facsimile number (919) 541-5450; email address: hutson.nick@epa.gov.

SUPPLEMENTARY INFORMATION: Acronyms. A number of acronyms and 

chemical symbols are used in this preamble. While this may not be an 

exhaustive list, to ease the reading of this preamble and for 

reference purposes, the following terms and acronyms are defined as 

follows:

AB Assembly Bill

AEP American Electric Power

AEO Annual Energy Outlook

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing of Materials

BACT Best Available Control Technology

BDT Best Demonstrated Technology

BSER Best System of Emission Reduction

Btu/kWh British Thermal Units per Kilowatt Hour

Btu/lb British Thermal Units per Pound

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CBI Confidential Business Information

CCS Carbon Capture and Storage (or Sequestration)

CDX Central Data Exchange

CEDRI Compliance and Emissions Data Reporting

CEMS Continuous Emissions Monitoring System

CH4 Methane

CHP Combined Heat and Power

CO2 Carbon Dioxide

CSAPR Cross-State Air Pollution Rule

DOE Department of Energy

DOT Department of Transportation

ECMPS Emissions Collection and Monitoring Plan System
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EERS Energy Efficiency Resource Standards

EGU Electric Utility Generating Units

EIA Energy Information Administration

EO Executive Order

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

FR Federal Register

GHG Greenhouse Gas

H2 Hydrogen Gas

HAP Hazardous Air Pollutant

HFC Hydrofluorocarbon

HRSG Heat Recovery Steam Generator

IGCC Integrated Gasification Combined Cycle

IPCC Intergovernmental Panel on Climate Change

IPM Integrated Planning Model

kg/MWh Kilogram per Megawatt-hour

kJ/kg Kilojoules per Kilogram

kWh Kilowatt Hour

lb CO2/MMBtu Pound of CO2 per Million British Thermal Unit

lb CO2/MWh Pound of CO2 per Megawatt-hour

lb CO2/yr Pound of CO2 per Year

lb/lb-mole Pound per Pound-Mole

MATS Mercury and Air Toxic Standards

MW Megawatt

MWe Megawatt Electric

MWh Megawatt-hour

N2O Nitrous Oxide

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NAS National Academy of Sciences

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NRC National Research Council

NSPS New Source Performance Standards

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

O2 Oxygen Gas

OMB Office of Management and Budget

PC Pulverized Coal

PFC Perfluorocarbon

PM Particulate Matter

PM2.5 Fine Particulate Matter

PRA Paperwork Reduction Act
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PSD Prevention of Significant Deterioration

RCRA Resource Conservation and Recovery Act

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

RPS Renewable Portfolio Standard

SBA Small Business Administration

SCC Social Cost of Carbon

SCR Selective Catalytic Reduction

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

SSM Startup, Shutdown, and Malfunction

Tg Teragram

Tpy Tons per Year

TSD Technical Support Document

TTN Technology Transfer Network

UIC Underground Injection Control

UMRA Unfunded Mandates Reform Act of 1995

U.S. United States

USGCRP U.S. Global Climate Research Program

VCS Voluntary Consensus Standard

WWW Worldwide Web

Organization of This Document. The information presented in this 

preamble is organized as follows:

I. General Information

A. Executive Summary

B. Does this action apply to me?

II. Background

A. Statutory Background for this Rule

B. Overview of Climate Change Impacts from GHG Emissions

C. GHGs from Fossil Fuel-Fired EGUs

D. Litigation Directly Leading to this Rule

E. Coordination with Other Rulemakings

III. Summary of the Proposed Requirements for New Sources

A. What is the affected source?

B. What emissions limitations must I meet?

C. What are the startup, shutdown, and malfunction requirements?

D. What are the continuous monitoring requirements?
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E. What are the emissions performance testing requirements?

F. What are the continuous compliance requirements?

G. What are the notification, recordkeeping, and reporting 

requirements?

IV. Rationale for the Proposed Standards: New Sources

A. How did the EPA establish the emission limits?

B. How did the EPA determine the other requirements for the proposed 

standards?

V. Implications for PSD and Title V Programs

A. Overview

B. Implications for PSD Program

C. Implications for Title V Program

VI. Discussion of Modified Sources

A. CAA Section 111 Requirements

B. Timing for Promulgation of Standards of Performance for 

Modifications

VII. Impacts of the Proposed Action

A. What are the air impacts?

B. What are the energy impacts?

C. What are the compliance costs?

D. How will this proposal contribute to climate change protection?

E. What are the economic and employment impacts?

F. What are the benefits of the proposed standards?

VIII. Request for Comments

IX. 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 as Amended by the Small Business 

Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq.

D. Unfunded Mandates Reform Act of 1995

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination With Indian 

Tribal Governments

G. Executive Order 13045: Protection of Children From Environmental 

Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations

I. General Information
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A. Summary 

1. Executive Summary

In this rulemaking, the EPA proposes to limit GHG emissions from 

new fossil fuel-fired power plants by limiting CO2 emissions. The 

proposed rule is undertaken pursuant to section 111 of the Clean Air 

Act, which establishes a several step process for the EPA and the 

States to regulate air pollutants from stationary sources. Under 

section 111, EPA must regulate emissions from new sources in the 

source category by issuing a standard of performance, which is 

defined as “a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the application 

of the best system of emission reduction which (taking into account 

... cost [and other factors]) ... has been adequately demonstrated.” 

In today’s action, the EPA is proposing to combine electric 

utility steam generating units (boilers and IGCC units, which are 

currently included in the Da category) and combined cycle units that 

generate electricity for sale and meet certain size criteria (which 

are currently included in the KKKK category), into a new category for 

new sources (the TTTT category) for the purposes of GHG emissions. 

The EPA is proposing standards of performance that require that all 

new fossil fuel-fired EGUs meet an electricity-output-based emission 

rate of 1,000 lb CO2/MWh of electricity generated on a gross basis. 
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This proposed standard is based on the demonstrated performance of 

natural gas combined cycle (NGCC) units, which are currently in wide 

use throughout the country, and are likely to be the predominant 

fossil fuel-fired technology for new generation in the future. 

New coal-, coal refuse-, oil- and petroleum coke-fired boilers 

and IGCC units should also be able to meet this standard by employing 

carbon capture and storage (CCS) technology. While a coal unit with 

CCS may be more expensive to construct than NGCC generation, for 

reasons explained below, we expect the difference to decrease over 

time as CCS becomes more mature and less expensive. 

We include in today’s proposed rulemaking a 30-year averaging 

compliance option under which affected coal- and pet coke-fired 

sources could comply with the 1,000 lb CO2/MWh standard on a 30-year 

average basis. Coal- and pet coke-fired EGUs that use this compliance 

alternative must meet an immediate performance standard of 1,800 lb 

CO2/MWh (gross) on a 12-month annual average basis, which can be 

achieved by a “supercritical” efficiency level, during the period 

before installation of CCS. By no later than the beginning of the 11th

year, the facility would be required to meet a reduced CO2 emission 

limit of no more than 600 lb CO2/MWh (gross) on a 12-month annual 

average basis for the remaining 20 years of the 30-year period, such 

that the weighted average CO2 emissions rate from the facility over 
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the 30-year time period would be equivalent to the proposed standard 

of performance of 1,000 lb CO2/MWh. 

Today’s proposal to require an emission rate of 1,000 lb CO2/MWh 

meets the requirements for a “standard of performance,” as defined 

under CAA section 111(a)(1). This proposed standard is based on the 

degree of emission limitation achievable through natural gas combined 

cycle generation. NGCC qualifies as the “best system of emission 

reduction” (BSER) that the EPA has determined has been adequately 

demonstrated. New natural gas-fired EGUs are less costly than new 

coal-fired EGUs, and as a result, our Integrated Planning Model (IPM)

model projects that for economic reasons, natural gas-fired EGUs will 

be the facilities of choice until at least 2020, which is the 

analysis period for this rulemaking. 

Indeed, our IPM model does not project construction of any new 

coal-fired EGUs during that period. This state of affairs has come 

about primarily because technological developments and discoveries of 

abundant natural gas reserves have caused natural gas prices to 

decline precipitously in recent years and have secured those 

relatively low prices for the near-future. We emphasize that, in 

light of a number of economic factors, including the increased 

availability and significantly lower price of natural gas, energy 
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industry modeling forecasts uniformly predict that few, if any, new 

coal-fired power plants will be built in the foreseeable future. 

We recognize that some owners/operators may nevertheless seek to 

construct new coal-fired capacity. This may be beneficial from the 

standpoint of promoting energy diversity, and today’s proposal does 

not interfere with construction of new coal-fired capacity. At 

present, while CCS would add considerably to the costs of a new coalfired power plant, there are sources of funding available to support 

the deployment of CCS, including a limited number of government 

demonstration programs. Even if companies decide to construct a few 

new coal-fired power plants under any circumstance, those few may 

well have access to those government programs. We expect that the 

costs of CCS will decline in the future as CCS matures and is 

utilized more widely.

For purposes of today’s action, the EPA does not have a 

sufficient base of information to develop a proposal for the 

anticipated relatively few affected sources that may be expected to 

take actions that would constitute “modifications” (as defined under 

the EPA’s NSPS regulations) and therefore be subject to requirements 

for new sources. As a result, the EPA is not proposing requirements 

for NSPS modifications.
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The EPA is aware that approximately 15 proposed EGUs have 

received CAA permitting authority approval for their preconstruction 

permits, but may not have “commenced construction” by the date of 

today’s proposed rulemaking. For this proposed rule, these sources 

that, as of the date of this proposal, have a PSD permit and are 

poised to commence construction within the very near future are 

referred to as “transitional sources.” In today’s proposed 

rulemaking, the EPA is not proposing a standard of performance for 

transitional sources, which we define as sources that have been 

issued a PSD permit by the date of proposal (including sources that

have approved permits that are in the process of being amended, if 

those sources are intending to install CCS as evidenced by 

participating in any of the DOE CCS funding programs, either loan 

guarantee or grant programs) and that commence construction within 12 

months of the date of publication of this proposal in the Federal 

Register. Upon finalization of this rulemaking without a standard of 

performance applicable to these sources, they will not be treated as 

new sources subject to the specific limitations set forth in the 

final new source standards. 

Our IPM modeling, using Energy Information Administration (EIA) 

reference case assumptions, projects that there will be no 

construction of new coal-fired generation without CCS by 2030. Under 
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these assumptions, the proposed rule will not impose costs by 2030. 

We also examined a scenario with both increased future natural gas 

prices and increased future electric demand. In this sensitivity 

case, we saw small amounts of coal-fired generation being built in 

2030. Even under this sensitivity analysis with small amounts of new 

coal generation under conditions of high natural gas prices and 

simultaneously high electricity demand in 2030, we do not project 

that this proposed rule will impose notable costs upon sources. 

We seek comments on all aspects of this proposal and identify a 

number of aspects of the proposal on which comments are specifically 

requested.

B. Overview and Outline

1. Overview

In this rulemaking, the EPA proposes to limit GHG emissions from 

new fossil fuel-fired power plants by limiting CO2 emissions. In 2009, 

the EPA issued a finding that GHG air pollution may reasonably be 

anticipated to endanger Americans’ public health and welfare, now and 

in the future, by contributing to climate change. Fossil fuel-fired

power plants emit more GHG emissions than any other stationary source 

category in the United States, and among new GHG emissions sources, 

the largest individual sources are in this source category. This 
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rulemaking proposes federal standards of performance for new fossil 

fuel-fired power plants that can be met with existing technology. 

Note that in this preamble, while we refer to these sources, 

interchangeably, as power plants, steam generating units, affected 

sources, fossil fuel-fired electric generating units, covered EGUs, 

or, simply, EGUs, the proposed standards apply to only those sources 

identified in Section III.A. as the affected source category.

2. Why is the EPA proposing this rule? 

This proposed rule reflects the EPA’s common-sense approach to 

reducing CO2 and other GHG emissions, which by causing climate change,

pose a serious threat to public health and welfare. The EPA is 

focusing first on reducing emissions from the largest emitters 

through measures with reasonable costs. The EPA is proposing to 

control CO2 pollution from fossil fuel-fired power plants because they 

are responsible for approximately 40 percent of all U.S. 

anthropogenic CO2 emissions.2 Individual new coal-fired power plants 

are among the largest individual new sources of GHGs. Furthermore, 

design and technology choices exist that can be readily and costeffectively used to reduce GHG emissions from new fossil fuel-fired 

 

2 Or 32.4% of all anthropogenic GHG emissions; from information in 

Table 2-1 from ‘Inventory of U. S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2009’, U. S. Environmental Protection Agency, EPA 430-

R-11-005, April 2011.
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power plants. Thus, this proposed rule is a rational first step to 

control GHG emissions from the largest-emitting stationary sources 

under CAA section 111.

a. The Serious Threat of Climate Change to the Public’s Health and 

Welfare. Climate change, including global warming, is a significant 

threat to the global environment. The National Research Council (NRC) 

of the National Academies3 stated in a 2011 report, “Each additional 

ton of greenhouse gases emitted commits us to further change and 

greater risks. In the judgment of the [NRC] Committee on America's 

Climate Choices, the environmental, economic, and humanitarian risks 

of climate change indicate a pressing need for substantial action to 

limit the magnitude of climate change and to prepare to adapt to its 

impacts.”4

Action to reduce emissions is warranted because, as the EPA 

stated in its 2009 Endangerment Finding5, GHGs endanger the public 

health and public welfare of current and future generations. The 

 

3 The National Academies comprise the National Academy of Sciences, 

National Academy of Engineering, Institute of Medicine and National 

Research Council.

4 National Research Council (2011) America’s Climate Choices, 

Committee on America’s Climate Choices, Board on Atmospheric Sciences 

and Climate, Division on Earth and Life Studies, The National 

Academies Press, Washington, DC.

5 EPA, “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases under Section 202(a) of the Clean Air Act” (74 FR 66,496; Dec. 

15, 2009). http://epa.gov/climatechange/endangerment.html.
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anthropogenic buildup of GHGs in the atmosphere is very likely (90 to 

99 percent probability) the cause of most of the observed global 

warming over the last 50 years.6 Based on the Endangerment Finding and 

its underlying technical support document (TSD)

7, reasons to reduce 

GHG emissions include the following:

 The key effects of climate change observed to date and projected 

to occur in the future include, but are not limited to, more 

frequent and intense heat waves, more severe wildfires, degraded 

air quality, heavier and more frequent downpours and flooding, 

increased drought, greater sea level rise and storm surge, more 

intense storms, harm to water resources, continued ocean 

acidification, harm to agriculture, and harm to wildlife and 

ecosystems. 

 These effects are anticipated to result in premature deaths, 

illnesses, damage to property and infrastructure, and other harm 

to people’s welfare in the U.S.

 

6 Endangerment Finding at 74 FR 66,518, which notes that the 2007 

conclusion of the Intergovernmental Panel on Climate Change was reconfirmed by the June 2009 assessment by the U.S. Global Change 

Research Program. 

7 EPA, “Technical Support Document for Endangerment and Cause or 

Contribute Findings for Greenhouse Gases under Section 202(a) of the 

Clean Air Act, Dec. 9, 2009.” Both the Federal Register Notice and 

the TSD for Endangerment and Cause or Contribute Findings are found 

in the public docket established for the endangerment rulemaking, 

Docket No. EPA–OAR–2009–0171 and at 

http://epa.gov/climatechange/endangerment.html.
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 Those “most vulnerable” to climate related health effects, such 

as children, the elderly and the poor – and future generations -

- face disproportionate risks.8

 Human-induced climate change impacts have the potential to be 

far-reaching and multidimensional, though not all risks and 

potential impacts can be quantified.9

 A supporting consideration is that climate change impacts in 

certain regions of the world (potentially leading, for example,

to food scarcity, conflicts or mass migration) may exacerbate 

problems that raise humanitarian, trade and national security 

issues for the United States.10

 The TSD further notes that some risks, such as the extinction of 

many species, would be irreversible.11 Also, the TSD points to 

research on the potential for “abrupt changes”12 which have uncertain 

or low probability but high potential impact. The NRC has said abrupt 

changes are an important consideration because, if triggered, they 

 

8 Endangerment Finding, 74 FR 66498.

9 Endangerment Finding, 74 66497.

10 Endangerment Finding, 74 FR 66535.

11 Endangerment TSD, p. 136

12 Endangerment TSD, p. 75-78. The U.S. Climate Change Science Program 

defined “abrupt change” as a “large-scale change in the climate 

system that takes place over a few decades or less, persists (or is 

anticipated to persist) for at least a few decades, and causes 

substantial disruptions in human and natural systems.” Synthesis and 

Assessment Product (SAP) 3.4: Abrupt Climate Change (2008).
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could occur so quickly and unexpectedly that human or natural systems 

would have difficulty adapting to them.13 Examples include severe 

drought in subtropical areas, release of large amounts of GHGs stored 

in the sea floor and frozen Arctic soils, and rapid disintegration of 

Greenland ice sheet or collapse of the West Antarctic ice sheet 

leading to many feet of sea level rise.14 

The special characteristics of GHGs make it important to take 

initial steps to control the largest emissions categories without 

delay. Unlike most traditional air pollutants, GHGs persist in the 

atmosphere for time periods ranging from decades to millennia, 

depending on the greenhouse gas. Greenhouse gases will continue to 

accumulate in the atmosphere at higher and higher concentrations each 

year unless substantial reductions in global greenhouse gas emissions 

are achieved. The NRC notes that emissions reduction choices made 

today matter in determining the level of impacts experienced not just 

over the next few decades, but in the coming centuries and 

millennia.15 Also, the longer that the U.S. and other countries take 

to reduce emissions, the greater the future emissions reductions that 

 

13 Endangerment TSD, p. 75, citing National Research Council (2002)

14 Endangerment TSD , pp. 76-78 

15 National Research Council (NRC) (2011). Climate Stabilization 

Targets. Committee on Stabilization Targets for Atmospheric 

Greenhouse Gas Concentrations; Board on Atmospheric Sciences and 

Climate, Division of Earth and Life Sciences, National Academy Press. 

Washington, DC.
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will be required to limit global temperature increase to any given 

level.

This proposed rule to limit GHG emissions from the largest U.S. 

stationary source category will contribute to the emissions 

reductions required to slow or reverse the accumulation of GHG 

concentrations in the atmosphere, which is necessary to protect 

against projected climate change impacts and risks. Reducing GHG 

emissions reduces the impacts and risks articulated in the 

Endangerment Finding and TSD.

b. The High Level of GHG Emissions from Fossil-Fuel-Fired Power 

Plants and the Opportunities to Reduce these Emissions. Fossil fuelfired power plants comprise the largest category of stationary source 

GHG emissions in the U.S. These sources account for approximately 40

percent of total U.S. anthropogenic CO2 emissions, based on 2009 

data.16 Among all stationary sources of GHG emissions, fossil-fuelfired power plants generally constitute the largest individual 

sources.

Furthermore, a range of options are available to reduce 

emissions of new power plants. For economic reasons, most new power 

 

16 Or 32.4% of all anthropogenic GHG emissions; from information in 

Table 2-1 from ‘Inventory of U. S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2009’, U. S. Environmental Protection Agency, EPA 430-

R-11-005, April 2011.
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plants being built in the U.S. today are either natural gas-fired or 

are powered by renewable sources of energy, such as wind and solar, 

and therefore generally produce significantly fewer CO2 emissions than 

uncontrolled coal-fired power plants. Natural gas combustion 

inherently emits less CO2 than coal combustion and the technology of 

choice for generating electricity with natural gas, stationary 

combined cycle gas turbines, is also more efficient. Almost all the 

stationary combined cycle gas turbines built in the U.S. in the last 

five years can meet the proposed standard of 1,000 lb CO2/MWh. New 

coal-fired power plants can install CCS technology and can thereby 

limit their CO2 emissions per MWh generated to levels similar to, or 

even lower than, those of natural gas-fired combined cycle plants 

without CCS. New coal-fired power plants with CCS are being permitted 

and built today, albeit usually with considerable financial 

assistance from the federal government.

c. Alignment with Industry’s Other CAA Obligations. Establishing the 

overall regulatory requirements for GHG emissions from new fossil

fuel-fired power plants at this time is efficient because the EPA has 

recently issued regulations to limit criteria and hazardous air 

pollutants from these sources. Aligning the timing of these GHG rules 

with the rules for criteria and air toxics pollutants gives the 

industry more regulatory certainty, will facilitate the industry’s 
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investment decisions, and will help inform its compliance decisions 

to meet all of its CAA obligations.

d. Promotion of Energy Diversity. This proposed rule is consistent 

with the President’s goal to ensure that “by 2035 we will generate 

80% of our electricity from a diverse set of clean energy sources -

including renewable energy sources like wind, solar, biomass and 

hydropower, nuclear power, efficient natural gas and clean coal.”17

The proposed rule will assist the deployment of CCS technology for 

new coal-fired power plants and reinforce incentives for the use of 

efficient natural gas-fired generation. Regulatory uncertainty may be 

hindering the development and deployment of CCS, as evidenced by 

American Electric Power (AEP)’s recent deferral of a large-scale CCS 

retrofit demonstration project on one of its coal-fired power plants 

because the State’s utility regulators would not approve CCS without 

a regulatory requirement to reduce CO2.

18 The standard established in 

 

17 “Blueprint for a Secure Energy Future”, March 30, 2011.

18 In a July 17, 2011, press release, AEP’s chairman said, “We are 

placing the project on hold until economic and policy conditions 

create a viable path forward ... We are clearly in a classic ‘which 

comes first?’ situation. The commercialization of this technology is 

vital if owners of coal-fueled generation are to comply with 

potential future climate regulations without prematurely retiring 

efficient, cost-effective generating capacity. But as a regulated 

utility, it is impossible to gain regulatory approval to recover our 

share of the costs for validating and deploying the technology 

without federal requirements to reduce greenhouse gas emissions 
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this proposal would help create the regulatory certainty that CCS is 

the path forward for new coal-fired generation.

3. Legal Proceedings Leading up to this Rulemaking

In April 2007, the U.S. Supreme Court ruled, in Massachusetts v. 

EPA,

19 that GHGs meet the definition of “air pollutant” in the CAA. 

This decision clarified that the authorities and requirements of the 

CAA, including section 111, apply to GHG emissions.

As a result of this decision, the EPA obtained a voluntary 

remand from the U.S. Court of Appeals for the District of Columbia 

Circuit (the “Court”) to reconsider the EPA’s actions in a 2006 

rulemaking for EGUs under CAA section 111, in which the EPA had 

promulgated standards for criteria air pollutants, but had declined 

to regulate GHG emissions. In part in response to threatened 

litigation over the EPA’s failure to act on the remand, the EPA 

agreed to propose today’s action to regulate GHG emissions from new 

fossil fuel-fired EGUs. 

4. Legal Basis for CAA Standards for Fossil-Fired Power Plants

a. General Legal Requirements. Clean Air Act section 111 establishes 

a several step process for the EPA and the States to regulate air 

pollutants from stationary sources. First, the EPA must list 

 

already in place. The uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.”

19 549 U.S. 497 (2007).
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categories of stationary sources that cause or contribute 

significantly to air pollution that may reasonably be anticipated to 

endanger public health or welfare. Then, the EPA must regulate 

emissions from new sources in the source category by issuing a 

standard of performance, which is defined as “a standard for 

emissions of air pollutants which reflects the degree of emission 

limitation achievable through the application of the best system of 

emission reduction which (taking into account ... cost [and other 

factors]) ... has been adequately demonstrated.” New sources include 

new construction, and, as discussed below, modifications to existing 

sources as well as reconstructed sources. Standards of performance 

for new sources are often referred to as new source performance 

standards (NSPS).

b. Cause-or-Contribute-Significantly Finding for Fossil Fuel-Fired 

Power Plants and Endangerment Finding for GHG Air Pollution. The EPA 

is authorized to regulate GHGs from power plants based on earlier 

actions concerning endangerment. Before today’s rulemaking, the EPA 

listed different types of fossil fuel-fired EGUs as source categories 

that caused or contributed significantly to air pollution that may 

reasonably be anticipated to endanger public health or welfare. 

Specifically, the EPA listed electric utility steam generating 

boilers, including coal-fired boilers, and initially regulated them 
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in subpart D of its regulations under CAA section 111. Subsequent 

regulation of utility boilers has been under subpart Da. The EPA 

listed stationary combustion turbine engines and initially regulated 

them under subpart GG. The stationary combustion turbine engine 

portions of combined cycle facilities were also regulated under 

subpart GG. Heat recovery steam generators (HRSG) associated with 

combined cycle facilities with duct burners were regulated under 

either subpart Da or one of the industrial boiler regulations, 

depending on the specific characteristics of the HRSG. To minimize 

the compliance burden for owners/operators of combined cycle 

facilities some monitoring harmonization was done, but the two 

subparts were still applicable. In 2005, the EPA proposed subpart 

KKKK as a replacement for subpart GG and specifically covered the 

entire combined cycle facility under subpart KKKK such that only a 

single set of requirements would apply. In that same year, the EPA 

proposed to include Integrated Gasification Combined Cycle (IGCC) 

facilities under the applicability of subpart Da. The EPA is 

authorized to promulgate the rulemaking proposed today -- which would 

establish standards of performance for CO2 emissions from EGUs 

currently in the Da and KKKK source categories -- because the EPA has 

already determined that both those source categories cause or 

contribute significantly to air pollution that may reasonably be 
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expected to endanger public health or welfare. Clean Air Act section 

111 does not require the EPA, as a prerequisite to regulating any 

particular air pollutant, to issue an endangerment finding or a 

cause-or-contribute-significantly finding for that air pollutant from 

that source category. 

As an alternative, the EPA is considering whether CAA section 

111 should be interpreted to require that the EPA base its regulation 

of CO2 emissions from EGUs on two findings: (i) a finding that GHG air 

pollution may reasonably be anticipated to endanger public health or 

welfare; and (ii) a finding that CO2 emissions from EGUs cause or 

contribute significantly to that air pollution. If section 111 were 

so interpreted, the EPA believes that (a) the 2009 Endangerment 

Finding, along with the EPA’s 2010 action denying petitions to 

reconsider that finding (which action reviewed scientific 

developments after the Endangerment Finding) would fulfill any 

requirement to make the endangerment finding concerning GHG air 

pollution; and (b) the large amount of CO2 emissions from EGUs clearly 

exceeds the low applicability threshold upon which the EPA would make 

the cause-or-contribute-significantly finding.

As another alternative, the EPA is also considering whether CAA 

section 111 should be interpreted to require that the EPA base its 

regulation of CO2 emissions from EGUs on a rational basis for 
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protection of the public health or welfare. If section 111 were so 

interpreted, the EPA believes that (i) its 2009 Endangerment Finding 

and 2010 denial of petitions to reconsider, by themselves, and 

particularly in conjunction with the National Academy of Sciences’ 

assessment reports issued since then, coupled with (ii) the fact that 

EGUs are the largest stationary source emitters of CO2, provide a 

rational basis for regulating CO2 emissions from EGUs. There is no 

reason to revisit the 2009 Endangerment Finding given recent 

scientific findings that strengthen the scientific conclusion that 

GHG air pollution endangers public health and welfare.20

5. Summary of Today’s Proposed Requirements to Reduce GHG Emissions 

from New Fossil Fired Power Plants, and Rationale for Those 

Requirements

a. Summary of Proposed Revisions to Categories and Requirements for 

New Sources 

i. Revisions to Categories of EGUs. In today’s action, the EPA is 

proposing to combine electric utility steam generating units (boilers

and IGCC units, which are currently included in the Da category) and 

combined cycle units that generate electricity for sale and meet 

 

20 These recent scientific findings are described in section II of 

this notice, titled “Background.” See subsection II.B.3., “Climate 

Impacts Detailed in Recent NRC Assessments.” The legal options 

introduced here are presented in detail below in section IV.A.2, 

“Endangerment and Cause-or-Contribute-Significantly Finding.”
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certain size criteria (which are currently included in the KKKK 

category), into a new category for new sources (the TTTT category)

for the purposes of GHG emissions. Today’s proposed rulemaking would 

not affect criteria air pollutants, simple cycle turbines or EGUs 

located in non-continental areas.

21 It also would not affect biomassfired boilers (including those that sell electricity to the grid)

that co-fire with less than 250 MMBtu/h of any fossil fuel (biomass 

boilers currently subject to subpart Db, the Industrial-CommercialInstitutional Steam Generating Unit NSPS).

ii. Control Requirements for New Sources. The EPA is proposing 

standards of performance that require that all new fossil fuel-fired 

EGUs meet an electricity-output-based emission rate of 1,000 lb 

CO2/MWh of electricity generated on a gross basis. This proposed 

standard is based on the demonstrated performance of natural gas 

combined cycle (NGCC) units, which are currently in wide use 

throughout the country, and are likely to be the predominant fossil

fuel-fired technology for new generation in the future. 

New coal-, coal refuse-, oil- and petroleum coke-fired boilers 

and IGCC units should also be able to meet this standard by employing 

CCS technology. There are currently a number of coal- and pet coke-

 

21 Thus, today’s rulemaking does not affect the Da and KKKK categories 

for conventional pollutants and does not affect the KKKK category for 

simple cycle turbines. 
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fired EGU projects under development that include CCS. While a coal 

unit with CCS may be more expensive to construct than NGCC 

generation, for reasons explained below, we expect the difference to 

decrease over time as CCS becomes more mature and less expensive. 

We include in today’s proposed rulemaking a 30-year averaging 

compliance option under which affected coal- and pet coke-fired 

sources could comply with the 1,000 lb CO2/MWh standard on a 30-year 

average basis. Coal- and pet coke-fired EGUs that use this compliance 

alternative must meet an immediate performance standard of 1,800 lb 

CO2/MWh (gross) on a 12-month annual average basis, which can be 

achieved by a “supercritical” efficiency level, during the period 

before installation of CCS. By no later than the beginning of the 11th

year, the facility would be required to meet a reduced CO2 emission 

limit of no more than 600 lb CO2/MWh (gross) on a 12-month annual 

average basis for the remaining 20 years of the 30-year period, such 

that the weighted average CO2 emissions rate from the facility over 

the 30-year time period would be equivalent to the proposed standard 

of performance of 1,000 lb CO2/MWh. 

We seek comment on this compliance option and on reasonable 

variations on the framework we propose to establish, and in 

particular on a mechanism for establishing practicably enforceable 

short term limits during the 30-year period. The potential approaches 
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here include (1) requiring the owner/operator to identify and obtain 

approval of, at the time of construction, an alternative 30-year 

emission trajectory to the 10- and 20-year limits described 

immediately above; and (2) specifying the emission rate for each year 

during the 30-year period consistent with meeting a 30-year average 

emission rate of 1,000 lb CO2/MWh. Such an option would provide coalfired sources that intend to use a reduction technology, such as CCS,

significant flexibility in how that reduction technology is 

implemented. They could install the technology as part of the 

original project but use some or all of the initial ten year period 

to optimize the system. Such flexibility could be particularly useful 

to early adopters (i.e., “first movers”) of the technology. 

Alternatively, they could delay installation of the technology for a 

period of up to ten years to take advantage of advancements in the 

technology that could reduce costs and enhance performance. Under CAA 

section 111(b)(1)(B), the EPA is required to conduct a review of the 

new source standards in eight years and we intend at that time to 

review the availability and cost of CCS. As proposed, this 30-year 

averaging compliance option is available only to new coal- and pet 

coke-fired EGUs. We do not believe that it is necessary for NGCC 

units, as they should be able to meet the proposed performance with 

no need for add-on technology. We also solicit comment on the need to 
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extend the applicability for the 30-year averaging compliance option 

to other fossil fuels beyond just coal and pet coke.

b. Rationale. Today’s proposal to combine the relevant parts of the 

Da and KKKK categories is authorized under CAA section 111(b)(1)(A) 

because that provision authorizes the EPA, after drawing up the list 

of affected source categories, to “revise” that list from time to 

time. Combining the relevant parts of the categories, as the EPA 

proposes to do, is one method to “revise” the list. Moreover, the 

EPA’s action to combine the relevant parts of the categories is 

reasonable because with the combination, all new fossil fuel-fired 

electricity generating units that meet specified minimum criteria 

will be subject to the same requirements, and therefore will be 

treated alike because they serve the same function, that is 

production of baseload or intermediate load power. The EPA is not 

including stationary simple cycle turbines in this rule because they 

generally operate differently than the other units covered by today’s 

rule. The units covered by today’s rule are generally used for 

baseload or intermediate power generation, while simple cycle 

turbines are generally used much less often (and thus have lower GHG 

emissions) and are generally used to meet peak rather than base or 

intermediate load requirements.
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Today's proposal does not apply to new sources in noncontinental areas, which include Hawaii and the territories. This is 

because non-continental areas do not have available pipeline quality 

natural gas and, accordingly, a natural-gas-fired plant that could 

comply with the 1,000 lb CO2/MWh may not be feasible. At present, we 

do not have information to identify what types of new power plants 

may be constructed in those areas. Those types of power plants may 

range from liquified natural gas (LNG)-, to oil-, to coal-fired to 

renewables. Our lack of more specific information precludes us from 

proposing, at this time, a standard for new sources in noncontinental areas.

Today’s proposal to require an emission rate of 1,000 lb CO2/MWh 

meets the requirements for a “standard of performance,” as defined 

under CAA section 111(a)(1). This proposed standard is based on the 

degree of emission limitation achievable through natural gas combined 

cycle generation. NGCC qualifies as the “best system of emission 

reduction” (BSER) that the EPA has determined has been adequately 

demonstrated because NGCC emits the least amount of CO2 and does so at 

the least cost. We propose that a NGCC facility is the best system of 

emission reduction for two main reasons. First, natural gas is far 

less polluting than coal. Combustion of natural gas emits only about 

50 percent of the CO2 emissions that the combustion of coal does per 
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unit of energy generated. Second, new natural gas-fired EGUs are less 

costly than new coal-fired EGUs, and as a result, our Integrated 

Planning Model (IPM) model projects that for economic reasons, 

natural gas-fired EGUs will be the facilities of choice until at 

least 2020, which is the analysis period for this rulemaking. Indeed, 

our IPM model does not project construction of any new coal-fired 

EGUs during that period. This state of affairs has come about 

primarily because technological developments and discoveries of 

abundant natural gas reserves have caused natural gas prices to 

decline precipitously in recent years and have secured those 

relatively low prices for the near-future. Importantly, because the 

IPM modeling shows that natural gas-fired plants are the facilities 

of choice, the proposed standard of performance in today’s rulemaking 

–– which is based on the emission rate of a new NGCC unit –– does not 

add costs. In addition, compared to coal-fired EGUs, natural gasfired EGUs have fewer nonair quality health and environmental 

impacts.

The just-described reasons are sufficient as a legal matter to 

justify today’s proposed actions to combine source categories and 

establish the 1,000 lb CO2/MWh standard. Such a standard could also be 

met today by new coal-fired units using CCS. In addition, we propose 

to include the compliance alternative of allowing new coal- and pet 
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coke-fired power plants to meet the 1,000 lb CO2/MWh standard over a 

30-year period so that plant developers can take advantage of future 

advancements cost savings in CCS technology that could lower its 

cost. This compliance alternative allows owners/operators to install 

CCS when the unit is first constructed but also provides the 

operational flexibility that may be necessary to optimize the 

performance and to have additional time to address any startup 

challenges related to issues such as business arrangements related to 

the sale or storage of the captured CO2. 

We recognize that, in light of a number of economic factors, 

including the increased availability and significantly lower price of 

natural gas, energy industry modeling forecasts uniformly predict 

that few, if any, new coal-fired power plants will be built in the 

foreseeable future. For these economic reasons, and independent of

this proposed standard, the fossil fuel-fired electricity generating 

industry has been trending towards increased use of natural gas and 

decreased use of coal for new generating capacity. Today’s proposed 

action is consistent with that trend; but, at the same time, today’s 

proposal is not intended to affect that apparent trend. 

We recognize that some owners/operators may nevertheless seek to 

construct new coal-fired capacity. This may be beneficial from the 

standpoint of promoting energy diversity, and today’s proposal does 
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not interfere with construction of new coal-fired capacity. In the 

first instance, a new coal-fired power plant may be able to meet the 

1,000 lb CO2/MWh standard by installing CCS at the time of 

construction. At present, while CCS would add considerably to the 

costs of a new coal-fired power plant, there are sources of funding 

available to support the deployment of CCS, including a limited 

number of government demonstration programs.22 Even if companies 

decide to construct a few new coal-fired power plants under any 

circumstance, those few may well have access to those government 

programs.

The proposed 30-year averaging compliance option adds additional 

flexibility for new coal- and pet coke-fired power plants by allowing 

them to construct and begin operations without CCS, and then to

install and operate CCS at some time in the future, as long as they 

install CCS within ten years and operate it in a manner that allows 

them to meet the 1,000 lb CO2/MWh standard, on a weighted average

basis, over the 30-year period. 

 

22 A number of the sources that EPA has identified as transitional 

sources have received some form of DOE financial assistance to 

demonstrate CCS. In addition, several additional projects have 

received funding but have not yet received air permits. Beyond 

these projects, prospects for additional federal funding are

dependent on the overall budget process.
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We expect that the costs of CCS will decline in the future as 

CCS matures and is utilized more widely. Today’s action, if 

finalized, would promote utilization and further development of CCS 

by making it clear that CCS would be necessary for new coal-fired 

power plants to meet the performance standard. The prospect of 

declining CCS costs, in conjunction with the possibility of continued 

availability of additional funding mechanisms (e.g. demonstration

funding such as Department of Energy (DOE) grants, tax credits (for 

investment and/or EOR), State incentives such as clean energy 

standards), and sale of other usable products such as CO2, sulfur and 

hydrogen based products, indicates that CCS may well be sufficiently 

accessible in the near term to the few coal-fired power plants that 

are expected to commence construction. Thus, the 30-year averaging 

compliance option, along with the current opportunities for funding 

to implement CCS immediately, helps to alleviate any concerns that 

today’s action could restrict new coal-fired construction.

It should be noted that we are not required to justify the 30-

year averaging compliance option on grounds that it qualifies as the 

“best system of emission reduction” adequately demonstrated, and we 

are not stating in this action whether that compliance alternative 

does or does not qualify as such. Thus, it is not necessary to 

determine that our expectation that costs will go down meets the 
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standards for determining that CCS is “adequately demonstrated.” 

Rather, to reiterate, the 30-year averaging compliance option, along 

with the opportunity to implement CCS to meet the 1,000 lb CO2/MWh 

standard immediately upon startup, make CCS an available option for 

the limited number of new coal-fired power plants that may construct 

to serve the policy goals of promoting energy diversity, as well as 

other policy objectives.

23 Indeed, by clarifying that, in the future, 

new coal-fired power plants will need to implement CCS, this 

rulemaking eliminates uncertainty about the status of new coal and 

may well enhance the prospects for new coal-fired generation.

In addition, there may also be other potential compliance 

options available that were not considered in this proposal. In the 

analysis for today’s proposal, the EPA did not include unique 

treatment of CO2 emissions from biologically-based material, otherwise 

called biogenic CO2 emissions.24

 

23 EIA analysis (AEO 2012 early release) shows that “coal remains the 

dominant energy source for electricity generation.”

24 Biologically-based material is defined as non-fossilized and 

biodegradable organic material originating from modern or 

contemporaneously grown plants, animals or micro-organisms (including 

products, by-products, residues and waste from agriculture, forestry 

and related industries as well as the non-fossilized and 

biodegradable organic fractions of industrial and municipal wastes, 

including gases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material).
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In 2011, the EPA prepared and submitted the draft Accounting 

Framework for Biogenic CO2 Emissions from Stationary Sources 

(http://www.epa.gov/climatechange/emissions/biogenic_emissions/study.

html). The draft Framework includes both a detailed examination of 

the scientific and technical issues related to accounting for 

biogenic CO2 emissions from stationary sources, and a proposed method 

to account for a stationary source’s onsite CO2 emissions, taking the 

biological cycling of carbon into consideration, in a scientifically 

and technically rigorous manner. The independent Science Advisory 

Board (SAB) has convened a Biogenic Carbon Emissions Panel 

(http://yosemite.epa.gov/sab/sabproduct.nsf/0/2F9B572C712AC52E8525783

100704886?OpenDocument) to conduct a peer review of the draft 

Framework. The peer review report will be finalized later in 2012.

The SAB’s peer review of the EPA’s discussion on the science 

related to the impacts of biogenic CO2 is not yet finalized and the 

EPA looks forward to the SAB’s conclusions later in 2012. Given that 

the SAB’s peer review is ongoing, EPA is not suggesting specific 

methods of accounting or otherwise making particular proposals for 

treatment of biogenic CO2 emissions in any stationary source program, 

including NSPS. As more information, including the SAB peer review, 

becomes available, EPA will consider its options and move forward as 

warranted. 
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c. Requirements and Rationale for Modifications. For purposes of 

today’s action, the EPA does not have a sufficient base of 

information to develop a proposal for the anticipated relatively few 

affected sources that may be expected to take actions that would 

constitute “modifications” (as defined under the EPA’s NSPS 

regulations) and therefore be subject to requirements for new 

sources. As a result, the EPA is not proposing requirements for NSPS 

modifications.25

The EPA’s current regulations define an NSPS “modification” as a 

physical or operational change that increases the source’s maximum 

achievable hourly rate of emissions, but specifically exempt from 

that definition pollution control projects, which are projects that 

entail the installation of pollution control equipment or systems. 

The significant majority of projects that we believe EGUs are most 

likely to undertake in the foreseeable future that could increase the 

maximum achievable hourly rate of CO2 emissions would constitute 

pollution control projects. In many cases, those projects would 

involve the installation of add-on control equipment required to meet 

CAA requirements for criteria and air toxics air pollutants. These 

 

25 Note that any analysis of the cost and feasibility of CCS that EPA 

has undertaken for purposes of this proposal has focused solely on 

new sources. In today's action, EPA has not undertaken any analysis 

of the cost or feasibility of CCS for existing units that undergo 

modifications.
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increases in CO2 emissions would generally be small and would occur as 

a chemical byproduct of the operation of the control equipment. In 

other cases, those projects would involve equipment changes to 

improve efficiency to meet the requirements of a future 111(d) 

rulemaking for existing sources and would have the effect of 

increasing a source’s maximum achievable hourly emission rate (lb

CO2/hr), even while decreasing its actual output based emission rate 

(lb CO2/MWh). Because all of these actions would be treated as 

pollution control projects under the EPA’s current NSPS regulations, 

they would be specifically exempted from the definition of 

modification.

In the past, there have been a small number of instances in 

which power plants have undertaken actions that, in the EPA’s view, 

should be treated as modifications. The sources that took these 

actions vary widely one from another, and the types of actions were 

disparate. In light of this, we do not have adequate information as 

to the types of actions that qualify as modifications, the amount of 

increase in CO2 emissions they cause, the types of control measures, 

or the costs and effectiveness of control measures, on which to base 

a proposed standard of performance. Therefore, in today’s action, we 

are not proposing a standard of performance for modifications. As a 

result, sources that undertake modifications will be treated as 
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existing sources and thus not subject to the requirements proposed in 

this notice, although they would be subject to requirements that the 

EPA intends to propose separately for existing EGUs. 

In today’s action, we solicit comment on the types of 

modifications power plants may undertake and the appropriate control 

measures. Depending on the information we develop, we may issue 

proposed standards of performance in the future.

d. Requirements for Transitional sources. The EPA is aware that 

approximately 15 proposed EGUs have received CAA permitting authority 

approval for their preconstruction permits, but may not have 

“commenced construction” by the date of today’s proposed rulemaking.

 A few of these sources have taken additional action preparatory 

to commencing construction. For this proposed rule, these sources 

that, as of the date of this proposal, have a PSD permit and are 

poised to commence construction within the very near future are 

referred to as “transitional sources.” We are aware that 

approximately six of these sources have plans to implement CCS to 

some degree. 

CAA section 111 provides by its terms that sources that have not 

“commenced construction” before the date of proposed standards for 

new sources will be subject to the NSPS when they do commence 

construction. The EPA’s regulations define “commenced construction” 
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as, in general, undertaking a continuous program of construction or 

entering into a binding contract to do so. 40 CFR 60.2.

Commenters26 have pointed out that absent different treatment, 

transitional sources will be subject to the same requirements that 

apply to new sources that did not obtain their permit before the date 

of proposal. These commenters have suggested that today’s proposed 

rule should treat transitional sources differently, especially in 

light of the substantial redesign that meeting such the proposed 

standard would have and the impact that redesign would have on the 

schedule for a project that was nearly ready to commence 

construction. The transitional sources at issue are coal-fired EGUs 

that, absent special treatment, would be subject to the standard of 

performance proposed in this rulemaking. 

In today’s proposed rulemaking, the EPA is not proposing a 

standard of performance for transitional sources, which we define as 

sources that have been issued a PSD permit by the date of proposal 

(including sources that have approved permits that are in the process 

of being amended, if those sources are intending to install CCS as 

 

26 As mentioned elsewhere, the EPA held a series of listening sessions 

and allowed for a period of additional comment after announcing it 

was moving forward with development of new source performance 

standards for GHGs emitted from fossil fuel-fired EGUs. The term 

“commenters” here refers to those who commented during the listening 

sessions or during the subsequent comment period.
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evidenced by participating in any of the DOE CCS funding programs, 

either loan guarantee or grant programs) and that commence 

construction within 12 months of the date of publication of this 

proposal in the Federal Register. Upon finalization of this 

rulemaking without a standard of performance applicable to these 

sources, they will not be treated as new sources subject to the 

specific limitations set forth in the final new source standards. 

These sources would remain obligated, by the terms of their permits,

to construct and operate in accordance with their permits. In 

addition, these sources will be treated as existing sources and would 

be subject to any requirements that a State promulgates to meet its 

obligations under section 111(d). Sources that do not commence 

construction within 12 months of the date of this proposed action 

will be subject to this standard of performance for new sources. 

e. Requirements for Reconstructed Sources, and Rationale. The EPA’s 

CAA section 111 regulations provide that reconstructed sources are to 

be treated as new sources and, therefore, subject to new source 

standards of performance. The regulations define reconstructed 

sources as, in general, existing sources (i) that replace components 

to such an extent that the capital costs of the new components exceed 

50 percent of the capital costs of an entirely new facility, and (ii) 
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for which compliance with standards of performance for new sources is 

technologically and economically feasible. 40 CFR 60.15. 

Historically, we believe that very few power plants have 

undertaken reconstructions. The EPA is not aware that any power 

plants are presently planning any project that could meet the 

requirements for a reconstruction. In light of this limited 

experience concerning reconstructions, we lack adequate information 

about the type of source; the type of changes; the extent of 

emissions increases; and the type of control measures, including 

their cost and emissions reductions, that we need to propose a 

standard of performance for reconstructions.

As a result, in today’s action, the EPA is not including a 

proposal for reconstructed units. Instead, we solicit comment on how 

we should approach reconstructions and, depending on the information 

we receive, we may propose and finalize a standard for 

reconstructions at a later time. 

6. Summary of Emissions Impacts, Costs and Benefits

 Our IPM modeling,using Energy Information Administration (EIA) 

reference case assumptions, projects that there will be no 

construction of new coal-fired generation without CCS. In addition we 

examined a case with higher future electric demand and another case 

with higher future natural gas prices. We did not see any additional 
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new construction of coal-fired generation through 2030 in either of 

these cases. Under the relevant assumptions, we do not project that 

this rule will impose notable costs. 

We also examined a scenario with both increased future natural 

gas prices and increased future electric demand. In this sensitivity 

case we saw small amounts of coal-fired generation being built in 

2030. Even under this sensitivity analysis with small amounts of new 

coal generation under conditions of high natural gas prices and 

simultaneously high electricity demand in 2030, we do not project 

that this proposed rule will impose notable costs upon sources. (See 

the RIA for further discussion of sensitivities). 

While this proposed rule also will not have direct impact on 

U.S. emissions of greenhouse gases under expected economic 

conditions, it provides assurance that emission rates from new fossil 

fuel-fired generation will not exceed the level of the standard and 

will send a strong signal both domestically and internationally. 

Domestically, this proposed rule can further stimulate investment in 

CCS and other clean coal technologies, by making it clear that such 

technologies do provide a clear path forward for new coal-fired 

generating capacity. Internationally, this rule may encourage others 

to consider less GHG-intensive forms of power generation.

B. Does this action apply to me?
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The entities potentially affected by the proposed standards are 

shown in Table 1 below.

Table 1. Potentially Affected Entitiesa

Category NAICS 

Code

Examples of Potentially Regulated 

Entities

Industry 221112 Fossil fuel electric power generating 

units.

Federal 

Government

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government

221112b Fossil fuel electric power generating 

units owned by municipalities.

Tribal 

Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include NAICS categories for source categories that own and operate 

electric power generating units (including boilers and stationary 

combined cycle combustion turbines).

b Federal, state, or local government-owned and operated 

establishments are classified according to the activity in which they 

are engaged.

This table is not intended to be exhaustive but rather to 

provide a guide for readers regarding entities likely to be affected 

by this proposed action. To determine whether your facility, company, 

business, organization, etc., would be regulated by this proposed 

action, you should examine the applicability criteria in 40 CFR 60.1. 
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If you have any questions regarding the applicability of this action 

to a particular entity, consult either the air permitting authority 

for the entity or your EPA regional representative as listed in 40 

CFR 60.4 or 40 CFR 63.13 (General Provisions). 

II. Background

A. Statutory Background for this Rule

Clean Air Act section 111 establishes mechanisms for controlling 

emissions of air pollutants from stationary sources. As a preliminary 

step, CAA section 111(b)(1)(A) requires the EPA to list categories of 

stationary sources that the Administrator, in his or her judgment, 

finds “cause[], or contribute[] significantly to, air pollution which 

may reasonably be anticipated to endanger public health or welfare.”27

Once it has listed a source category, the EPA establishes 

“standards of performance” that apply to new sources, which are 

sources that are constructed, or that undertake modifications or 

reconstruction, after the EPA proposes the standards of performance 

for the relevant source category. CAA section 111(b)(1)(B). Specific 

statutory and regulatory provisions define what constitutes a 

modification or reconstruction of a facility. An existing facility 

undertakes a modification if it undergoes “any physical change ... or 

 

27 The EPA has made endangerment findings under this section for more 

than 60 stationary source categories and subcategories that are now 

subject to NSPS.
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change in the method of operation . . . which increases the amount of 

any air pollutant emitted by such source or which results in the 

emission of any air pollutant not previously emitted.” CAA section 

111(a)(4). The EPA’s NSPS regulations provide exemptions for several 

types of changes, including the installation of pollution control 

projects. 40 CFR 60.2, 60.14(e). An existing facility undertakes a 

reconstruction if it replaces components to such an extent that the 

capital costs of the new equipment or components exceed 50 percent of 

what is believed to be the cost of a completely new facility. 40 CFR 

60.15. In promulgating standards of performance, the EPA has 

significant discretion to create subcategories based on source type, 

class or size. CAA section 111(b)(2).

Clean Air Act section 111(a)(1) defines a “standard of 

performance” as –

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated. 

We call this level of control the best system of emission reduction 

(BSER).28 The standard that the EPA develops, based on the BSER, is 

 

28 This level of control has historically been referred to as best 

demonstrated technology (BDT).
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commonly a numerical emissions limit, expressed as a performance 

level (e.g., a rate-based standard). Generally, the EPA does not 

prescribe a particular technological system that must be used to 

comply with a standard of performance. Rather, sources remain free to 

elect whatever combination of measures will achieve equivalent or 

greater control of emissions.

B. Overview of Climate Change Impacts from GHG Emissions

In 2009, the EPA Administrator issued the 2009 Endangerment 

Finding,29 under CAA section 202(a)(1), as part of the process for 

promulgating the Light Duty Vehicle Rule.30 With the Endangerment 

Finding, the Administrator found that elevated concentrations of GHGs 

in the atmosphere may reasonably be anticipated to endanger public 

health and welfare. These adverse effects on public health and 

welfare are summarized here, and described in more detail in the RIA. 

As explained in the Endangerment Finding, the EPA made this 

determination based primarily upon the recent, major assessments by 

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

Panel on Climate Change (IPCC), and the National Research Council 

 

29 "Endangerment and Cause or Contribute Findings for Greenhouse Gases 

Under Section 202(a) of the Clean Air Act." 74 FR 66496 (December 15, 

2009).

30 "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate 

Average Fuel Economy Standards; Final Rule." 75 FR 25324 (May 7, 

2010).
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(NRC).31 In brief, these assessments addressed the scientific issues 

that the EPA was required to examine, were comprehensive in their 

coverage of the GHG and climate change problem, and underwent 

rigorous and exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review and acceptance. Below is a 

brief, non-comprehensive summary of effects noted in the Endangerment 

Finding and the assessment reports.

1. Public Health Impacts Detailed in the 2009 Endangerment Finding

Climate change threatens public health through a number of 

impacts such as increases in hot weather, ozone pollution, and the 

severity and frequency of extreme weather events. Children, the 

elderly, and the poor are among the most vulnerable to these climaterelated health effects.

By increasing higher average temperatures, climate change 

increases the likelihood of heat waves, which are associated with 

increased deaths and illnesses. While climate change also leads to 

decreases in cold-related mortality, some evidence suggests that the 

net impact on mortality is more likely to be adverse. Heat is already 

the leading cause of weather-related deaths in the U.S.

 

31 74 FR 66510-66511.
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Climate change is expected to increase ozone pollution over broad 

areas of the country including large population areas with unhealthy 

surface ozone levels. Ozone health studies indicate that elevated 

surface ozone increases risks of premature death, acute bronchitis, 

heart attacks, asthma aggravation, and other respiratory effects.

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. The assessment literature indicates that 

there is the potential for hurricanes to become more intense, and 

there is some evidence that Atlantic hurricanes have already become 

more intense. Hurricanes and floods from human-induced climate change 

can cause deaths, injuries, waterborne diseases, and mental health 

problems such as post-traumatic stress disorders. Drownings and other 

health impacts from coastal storms and storm surges are expected to 

increase due to rising sea levels. 

2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding

Climate change is expected to have numerous effects on public 

welfare. Large areas of the country are at serious risk of reduced 

water supplies, increased water pollution, and increased occurrence 

of extreme events such as floods and droughts. Coastal areas face 

increased risks from storm and flooding damage to property, as well 
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as adverse impacts from sea level rise 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 changes in extreme weather threaten energy, 

transportation, and water resource infrastructure. Climate changes 

may exacerbate ongoing environmental pressures in certain 

settlements, particularly in Alaskan indigenous communities. Over the 

21st century, climate change will fundamentally rearrange U.S. 

ecosystems. 

It is possible that in the next few decades, adverse effects in 

certain parts of the agriculture and forestry sectors -- such as 

enhanced pest and weed growth, increased surface ozone, changes in 

the intensity and frequency of droughts and heavy storms, and 

increased wildfires -- may be offset by benefits resulting from a 

stimulatory carbon dioxide effect and a longer growing season. 

However, the body of evidence points towards increasing risks of net 

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

productivity as temperatures continue to rise, with the potential for 

significant disruptions and crop failure.

Human-induced climate change has the potential to be far-reaching 

and multidimensional. Given the long atmospheric lifetime of the six 
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GHGs32, which range from roughly a decade to centuries, future 

atmospheric greenhouse gas concentrations for the remainder of this 

century and beyond will be influenced not only by future emissions 

but indeed by present-day emissions. The severity of all the 

described risks and impacts is likely to increase over time with 

accumulating GHG concentrations and the associated temperature 

increases and precipitation changes. Finally, these impacts are 

global, and may exacerbate problems that raise humanitarian, trade, 

and national security issues for the U.S.

3. Climate Impacts Detailed in Recent NRC Assessments

Since the EPA issued the 2009 Endangerment Finding, the NAS, 

which is a society established by an Act of Congress that is composed 

of distinguished scholars engaged in scientific and engineering 

research, has issued assessments with similar conclusions to those of 

the assessments upon which the EPA based the Endangerment Finding. In 

May 2010, the NRC, which is the operating arm of the National Academy 

of Sciences (NAS) that conducts most of the science policy and 

technical work, published its comprehensive assessment, “Advancing 

 

32 Carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), 

perflurocarbons (PFCs), hydrofluorocarbons (HFCs), and sulfur 

hexafluoride (SF6).
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the Science of Climate Change” (the 2010 NRC Assessment).33 It 

concluded that “climate change is occurring, is caused largely by 

human activities, and poses significant risks for -- and in many 

cases is already affecting -- a broad range of human and natural 

systems.”34 Furthermore, the NRC stated that this conclusion is based 

on findings that are “consistent with the conclusions of recent 

assessments by the U.S. Global Change Research Program, the 

Intergovernmental Panel on Climate Change’s (IPCC) Fourth Assessment 

Report, and other assessments of the state of scientific knowledge on 

climate change.”35 These are the same assessments that served as the 

primary scientific references underlying the 2009 Endangerment 

Finding. The 2010 NRC Assessment also warned of risks associated with 

abrupt changes and surprises that might occur when certain thresholds 

are crossed, such as the release of large quantities of GHGs stored 

in frozen soils in the Arctic or irreversible drying and 

desertification in the subtropics; and of potential for broad, 

“catastrophic” impacts on marine ecosystems resulting from ocean 

acidification. 

 

33 NRC (2010). Advancing the Science of Climate Change. National 

Academy Press. Washington, DC.

34 NRC (2010). Advancing the Science of Climate Change. National 

Academy Press. Washington, DC. Page 3.

35 NRC (2010). Advancing the Science of Climate Change. National 

Academy Press. Washington, DC. Page 286.
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Another NRC assessment, “Climate Stabilization Targets: 

Emissions, Concentrations, and Impacts over Decades to Millenia”, was 

published in 2011 (the 2011 NRC Assessment). This report found that 

climate change due to CO2 emissions will persist for many centuries. 

The report also estimates a number of specific climate change 

impacts, finding that every degree Celsius (oC) of warming could lead 

to increases in heavy rainfall and decreases in crop yields and 

Arctic sea ice extent, along with other precipitation and stream flow 

changes. The assessment also found that with an increase of 4 oC, the 

average summer would be as warm as the warmest summers of the past 

century, that for an increase of 1 to 2 oC the area burnt by 

wildfires in western North America will likely more than double, that 

coral bleaching and erosion will increase due both to warming and 

ocean acidification, and that sea level will rise 1.6 to 3.3 feet by 

2100 in a 3 oC scenario. The assessment notes that many important 

aspects of climate change are difficult to quantify but that the risk 

of adverse impacts is likely to increase with increasing temperature, 

and that the risk of surprises can be expected to increase with the 

duration and magnitude of the warming. Importantly, these recent NRC 

assessments represent another independent and critical inquiry of the 

state of climate change science, separate and apart from the previous 

IPCC, NRC, and USGCRP assessments.
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C. GHGs from Fossil Fuel-Fired Power Plants

Fossil fuel-fired electric utility generating units are by far the 

largest emitters of GHGs, primarily in the form of CO2, among 

stationary sources in the U.S. This section describes the amount of 

those emissions and places that amount in the context of the national 

inventory of GHGs.

The EPA prepares the official U.S. Inventory of Greenhouse Gas 

Emissions and Sinks36 (the U.S. GHG Inventory) to comply with existing 

commitments under the United Nations Framework Convention on Climate 

Change. This inventory, which includes recent trends, is presented by 

industrial sectors. It is the source for the information provided in 

Table 2 below concerning total U.S. anthropogenic emissions and sinks 

of GHGs and CO2 emissions, by industrial sector -- including fossil

fuel-fired EGUs -- for the years 1990, 2000, and 2009.

Table 2. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))37

SECTOR 1990 2000 2009

Energy 5,287.8 6,168.0 5,751.1 

Industrial Processes 315.8 348.8 282.9 

Solvent and Other 

Product Use 4.4 4.9 4.4 

Agriculture 383.6 410.6 419.3 

 

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

2009”, Report EPA 430-R-11-005, United States Environmental 

Protection Agency, April 15, 2011.

37 From Table 2-3 of the EPA GHG Emissions and Sinks Inventory, EPA 

430-R-11-005.
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Land Use, Land-Use 

Change and Forestry 

(Emissions) 15.0 36.3 25.0 

Waste 175.2 143.9 150.5 

Total Emissions 6,181.8 7,112.7 6,633.2 

Land Use, Land-Use 

Change and Forestry 

(Sinks) (861.5) (576.6) (1,015.1)

Net Emissions (Sources 

and Sinks) 5,320.3 6,536.1 5,618.2 

Energy-related CO2 emissions are the largest contributor to total 

U.S. GHG emissions, representing 86.7 percent of total 2009 GHG 

emissions. In 2009, the electric power sector –- consisting of those 

entities whose primary business is the generation of electricity –-

accounted for 40 percent of all energy-related CO2 emissions. The 

transportation sector, with emissions principally from the combustion 

of gasoline, diesel, and jet fuel, was the second-largest source, at 

32 percent of the total. Other energy-related CO2 emission sources 

included industrial, residential, and commercial fossil fuel 

combustion, natural gas and petroleum systems, and incineration of 

waste.

Direct fuel use in the residential and commercial sectors 

accounted for 26 percent of total CO2 emissions in 2009. Total CO2

emissions from fossil fuel-fired EGUs, for years 1990, 2000 and 2009, 

are shown below in Table 3. 
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Table 3. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2 Eq.)

We are aware that nitrous oxide (N2O) (and to a lesser extent, 

methane (CH4)) may be emitted from fossil fuel-fired EGUs, especially 

from coal-fired circulating fluidized bed (CFB) combustors and from 

units with selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) systems installed for NOX control. We are

not proposing separate N2O or CH4 emission limits or an equivalent CO2

emission limit in today’s action because of a lack of available data 

for these affected sources. Additional information on the quantity 

and significance of emissions and on the availability of costeffective controls would be needed before proposing standards for 

these pollutants. The estimated emissions for N2O and CH4 from fossil

fuel-fired EGUs (9.0 and 0.7 Tg of CO2 equivalent, respectively) is 

about 0.4 percent of total CO2 equivalent emissions from fossil fuelGHG EMISSIONS 1990 2000 2009

Total CO2 from fossil fuel 

combustion 1,820.8 2,296.9 2,154.0 

 - from coal 1,547.6 1,927.4 1,747.6 

 - from natural gas 175.3 280.8 373.1 

 - from petroleum 97.5 88.4 32.9 

From use of limestone and 

dolomite 2.6 2.5 3.8 

Total CH4 - stationary 

combustion 0.6 0.7 0.7 

Total N2O - stationary 

combustion 8.1 10.0 9.0
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fired electric power generating units. We are requesting comment on 

this approach and on the need to collect additional data on N2O and 

CH4 emissions from these affected sources.

D. Litigation Directly Leading to this Rule

As discussed below, in section II.E., on February 27, 2006, the 

EPA published a final rule that revised the standards of performance 

for criteria pollutant emissions of EGUs included in the Da category. 

”Standards of Performance for Electric Utility Steam Generating 

Units, Industrial-Commercial-Institutional Steam Generating Units, 

and Small Industrial-Commercial-Institutional Steam Generating 

Units,” 71 FR 9866 (Feb. 27, 2006) (the “2006 Final Rule”). The 2006 

Final Rule did not establish standards of performance for GHG 

emissions. Two groups of petitioners filed petitions for judicial 

review of this rule in the U.S. Court of Appeals for the District of 

Columbia Circuit (the Court), contending, among other things, that 

the rule was required to include standards of performance for GHG 

emissions from EGUs. The two groups of petitioners were (1) the 

States of New York, California, Connecticut, Delaware, Maine, New 

Mexico, Oregon, Rhode Island, Vermont, and Washington, the 

Commonwealth of Massachusetts, the District of Columbia, and the City 

of New York (collectively ‘‘State Petitioners’’); and (2) Natural 
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Resources Defense Council (NRDC), Sierra Club, and Environmental 

Defense Fund (EDF)(collectively ‘‘Environmental Petitioners’’). 

The portions of State and Environmental Petitioners’ petitions 

for review of the 2006 Final Rule that related to GHG emissions were 

severed from other petitions for review of that rule, and were 

formally pending before the Court under the caption State of New 

York, et al. v. EPA, No. 06–1322. Following the U.S. Supreme Court’s 

decision in Massachusetts, discussed above, the Court, upon motion 

from the EPA, remanded the 2006 Final Rule for further consideration 

of the issues related to GHG emissions in light of Massachusetts. The 

EPA did not act on that remand. To avoid further litigation, the 

State and Environmental Petitioners and the EPA negotiated a proposed 

settlement agreement that set deadlines for the EPA to propose and 

take final action on (1) a rule under CAA section 111(b) that 

includes standards of performance for GHGs for new and modified EGUs 

that are subject to 40 CFR part 60, subpart Da; and (2) a rule under 

CAA section 111(d) that includes emission guidelines for GHGs from 

existing EGUs that would have been subject to 40 CFR part 60, subpart 

Da if they were new sources. Pursuant to CAA section 113(g), the EPA 

published a notice of the proposed settlement agreement in the 

Federal Register, and provided for a public comment period. 75 FR 
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82392 (December 30, 2010).38 The EPA considered the comments received 

and concluded that they did not disclose facts or considerations 

indicating that the proposed settlement agreement was inappropriate, 

improper, inadequate or inconsistent with the CAA. Therefore, the EPA 

concluded that the proposed settlement agreement should be finalized. 

E. Coordination with Other Rulemakings

EGUs are the subject of several CAA rulemakings that have been 

recently completed. The EPA recognizes that it is important that all 

of these efforts achieve their intended environmental objectives in a 

common sense manner. The confluence of these rulemakings allows the 

industry to look across the regulatory requirements and design cost 

effective integrated compliance strategies.39

On July 6, 2011, the EPA finalized the Cross-State Air Pollution 

Rule (CSAPR)40. 76 FR 48208 (August 8, 2011). Also known as the 

Transport Rule, the CSAPR requires a total of 28 states and the 

 

38 Copies of the Federal Register notice, the settlement agreement, 

other supporting documents and the comments received are available 

online at fdms.gov under docket EPA-HQ-2010-1057.

39 We include this discussion of other rulemakings for background 

purposes. The effort to coordinate rulemakings does not provide a 

defense to a violation to the CAA. Sources cannot defer compliance 

with existing requirements because of other upcoming regulations.

40 On December 15, 2011, EPA finalized a supplemental rule (76 FR 

80760, December 27, 2012) to include five additional states in the 

CSAPR ozone season NOX program. On February 7, 2012, EPA issued two 

sets of minor adjustments to the CSAPR (77 FR 10324, February 21, 

2012).
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District of Columbia to improve air quality by reducing power plant 

emissions that contribute to ozone and fine particle pollution in 

other States. The CSAPR applies to 3,642 EGUs at 1,081 coal-, gasand oil-fired facilities in the eastern half of the U.S. By 2014, 

combined with other final state and EPA actions, the CSAPR will 

reduce power plant SO2 emissions by 73 percent and NOX emissions by 54 

percent from 2005 levels in the CSAPR region. The CSAPR was scheduled 

to begin on January 1, 2012. However, on December 30, 2011, the U.S. 

Court of Appeals for the D.C. Circuit issued a ruling to stay the 

rule pending judicial review. This decision is not a ruling on the 

merits of the CSAPR. While this decision delays implementation of the 

CSAPR and the significant health benefits associated with the rule, 

it leaves the Clean Air Interstate Rule (CAIR), the predecessor 

regulation to CSAPR, in place while the Court considers the merits of 

the challenges to the CSAPR. Oral arguments are scheduled for April 

13, 2012.

On December 16, 2011, the EPA signed the Mercury and Air Toxic 

Standards (MATS) rule to reduce emissions of mercury and other HAP 

emissions from coal- and oil-fired power plants. This regulation 

requires investments in pollution controls to reduce emissions of 

mercury, other metals and acid gases by 2015 or 2016. In the same 

notice, EPA also revised the NSPS for criteria pollutants from these 
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sources. Because the control technologies and strategies that reduce 

SO2, can also reduce or help to reduce HAP emissions, coordinating 

compliance strategies for the CSAPR and MATS rules, including the 

revised NSPS for criteria pollutants, will allow cost-effective 

compliance options.

In April, 2011, the EPA proposed standards under the Clean Water 

Act (CWA) to reduce injury and death of fish and other aquatic life 

caused by cooling water intake structures existing at power plants 

and factories. 76 FR 22174 (April 20, 2011). These facilities pull in 

large volumes of cooling water from lakes, rivers, estuaries or 

oceans to cool their machinery. The EPA is currently considering a 

wide range of comments to this proposal.

The EPA recognizes that it is important that each of these 

efforts achieves its intended environmental objectives in a commonsense, cost effective manner, that is consistent with the underlying 

statutory requirements and that allows the industry to comply with 

all of its obligations under these rules as efficiently as possible 

and to do so by making coordinated investment decisions and, to the 

greatest extent possible, by adopting integrated compliance 

strategies. In addition, EO 13563 states that ‘‘[i]n developing 

regulatory actions and identifying appropriate approaches, each 

agency shall attempt to promote ... coordination, simplification, and 
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harmonization. Each agency shall also seek to identify, as 

appropriate, means to achieve regulatory goals that are designed to 

promote innovation.’’ Recent guidance from the Office of Information 

and Regulatory Affairs has emphasized the importance of, where 

appropriate and feasible, considering cumulative effects and of 

seeking to harmonize rules in terms of both content and timing.

Thus, the EPA recognizes that it needs to approach these 

rulemakings, to the extent that its legal obligations permit, in ways 

that allow the industry to make practical investment decisions that 

minimize costs in complying with all of the final rules, while still 

achieving the fundamentally important environmental and public health 

benefits that the rulemakings must achieve.

F. PSD and Title V Implications

Commenters have asked whether the rulemaking the EPA is 

proposing today has implications for EGUs and other stationary 

sources under the prevention of significant deterioration (PSD) and 

Title V programs. We discuss this issue in section VI, below, and we 

include relevant background information in that discussion.

G. Stakeholder Input

The EPA has been engaged in extensive interactions with many 

different stakeholders on the subjects of climate change, source 

contributions, and potential emission reduction opportunities. These 
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stakeholders have included industries, environmental organizations, 

and many regional, State, and local air quality management agencies 

that have been actively engaged in efforts to address GHG emissions 

over a period of several years. In addition to these conversations, 

as part of developing this proposed rule, the EPA held five listening 

sessions in February and March 2011 to obtain additional information 

and input from key stakeholders and the public. Each of the five 

sessions had a particular target audience: the electric power 

industry, environmental and environmental justice organizations, 

States and Tribes, coalition groups, and the petroleum refinery 

industry. Each session lasted two hours and featured a facilitated 

round table discussion among stakeholder representatives who were 

identified and selected for their expertise in the CAA standardsetting process. The EPA had asked key stakeholder groups to identify 

these round table participants in advance of the listening sessions. 

The EPA accepted comments from the public at the end of each session 

and via the electronic docket system.

From the listening sessions and written submissions, the EPA 

received a wide range of comments and ideas for this proposed rule. 

The main topics of the comments, which concerned requirements for 

both new and existing sources, included the following: 

 Feasibility and availability of control technologies 
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 Output-based standards

 Subcategorization factors

 Fleet-wide averaging 

 Neutrality of fuels

 Role of efficiency improvements

 Equivalency of state and regional reduction programs 

 Recognition of early action by industries and states achieving 

reductions

 Use of a multi-pollutant, multi-media approach

 Market-based flexibility 

 Use of a tiered structure, with requirements evolving over time 

 Credit for replacement of older, less efficient generation units

 Role of biomass

 Consideration of compliance issues arising from conflicts with 

other regulatory programs

 Schedule for proposing and promulgating this rule

 Small business impacts

Comments submitted via the electronic docket system concerning 

development of this proposed rule are available at 

www.regulations.gov (docket number EPA-HQ-OAR-2011-0090).

III. Proposed Requirements for New Sources
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This section describes the proposed requirements in this 

rulemaking for new sources. Our rationale for these proposed 

requirements is provided in Section IV of this preamble.

A. What is the affected source?

Sources affected by today’s proposal for new source provisions

are sources that are considered both covered EGUs as defined by this 

rule and “new” sources as defined under the provisions of CAA section 

111. 

1. Covered EGUs, Generally

The EPA is proposing to define a covered EGU, which is a source 

that is subject to this rule, as any fossil fuel-fired combustion 

unit that supplies more than one-third of its potential annual 

electric output and more than 25 MW net-electrical output (MWe) to 

any utility power distribution system for sale, with certain 

exceptions noted below. For this proposed rule, covered EGUs include 

electric utility steam generating units (“boilers”), stationary 

combined cycle combustion turbines and their associated HRSG) and 

duct burners; and IGCC units, including their combustion turbines and 

associated HRSG. However, for purposes of this rule, covered EGUs do 

not include stationary simple cycle combustion turbines or EGUs 

located in Hawaii or other non-continental areas. In addition, units 

subject to emission requirements under CAA section 129 would not be 
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subject to requirements under this proposed rule.

2. CO2 Emissions Only

This action proposes to regulate covered EGU emissions of CO2, 

and not other constituent gases of the air pollutant GHG, although we 

identify the pollutant we propose to regulate as GHGs. Note that 

emissions of criteria pollutants for covered EGUs remain covered 

under 40 CFR part 60 subparts Da and KKKK.

3. “New” sources

CAA section 111(a)(2) defines a “new source” as “any stationary 

source, the construction or modification of which is commenced after 

publication of regulations (or, if early, proposed regulations) 

prescribing a standard of performance under [CAA section 111] which 

will be applicable to such source.” In contrast, CAA section 

111(a)(6) defines an “existing source” as “any stationary source 

other than a new source.” The definition of a “new source” applies 

according to its terms for purposes of this rulemaking, except that 

special considerations come into play for sources undertaking 

physical or operational changes, transitional sources, and sources 

undertaking reconstruction, as discussed below in Section V of this 

preamble.

B. What emissions limitations must I meet?

In this rulemaking, the EPA is proposing a standard of 
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performance (NSPS), and we are requesting comment on an 30-year 

averaging compliance option, for CO2 emissions from affected sources, 

which are new fossil fired EGUs described above in Section III.A,. 

1. Standard of performance

The standard of performance is a gross output-based CO2 emission 

limit expressed in units of emissions mass per unit of useful 

recovered energy (specifically, in pounds per megawatt-hour 

(lb/MWh)). This emission limit would be effective upon the effective 

date of the final action. 

We are not proposing any subcategories for new affected sources. 

Instead, we are proposing a single output-based CO2 emission limit 

that must be met by all affected sources.41 Specifically, the EPA is 

proposing a standard of 1,000 lb CO2/MWh, but, as discussed below, is 

taking comment on a range from 950 lb CO2/MWh to 1,100 lb CO2/MWh. 

As discussed below, the proposed method to calculate compliance 

is to sum the emissions for all operating hours and to divide that 

value by the sum of the electrical energy output and useful thermal 

energy output, where applicable for combined heat and power (CHP)

EUGs, over a rolling 12-month period. In the alternative, we solicit 

comment on requiring calculation of compliance on an annual (calendar 

 

41 As discussed below, we are not proposing such a limit for 

modifications, transitional sources, or reconstructed sources.
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year) period.

Under this proposal, no averaging or emissions trading among 

affected sources would be allowed.

We seek comment on all aspects of the proposed standard of 

performance, including using net, instead of gross, generation-based 

emissions rate measurement.

2. 30-year Averaging Compliance Option

We also propose a 30-year averaging compliance option that would 

be available only for affected coal- and pet coke-fired sources that 

comply with the standard through the use of CCS. This approach 

involves a performance standard that includes both a 12-month annual 

average limit and a longer-term limit that may be met on an average 

basis by the end of a 30-year period. The 12-month limit is important 

because it is a practicably enforceable mechanism to ensure that the 

source is on a path to comply with the 30-year average limit. The 

annual limit will ensure that the source takes timely action to meet 

a 30-year limit. For instance, if meeting the 30-year limit was 

predicated on installing CCS technology before year eleven of 

operation, the annual compliance limits would provide an enforceable 

measure to ensure that CCS was installed and operating well before a 

30-year average could be calculated. Note that after the 30th year, 

the source would be required to meet the 12-month annual average 
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1,000 lb CO2/MWh emission limit.

Specifically, for the first ten years of operation, the affected 

source would be required to comply with a 12-month annual average CO2

emissions limit based on the best demonstrated performance of a coalfired facility without CCS, which is 1,800 lb CO2/MWh (816 kg CO2/MWh) 

(gross). This proposed emission limit can be met by modern coal-fired 

facilities using supercritical steam conditions, IGCC facilities, and 

pressurized CFBs boilers. By no later than the 11th year from the 

effective date of the rule, the facility would be required to meet a 

reduced emission limit of no more than 600 lb CO2/MWh (272 kg CO2/MWh) 

(gross) on a 12-month annual average basis for the remaining 20 years 

of the 30-year averaging period, such that the weighted average CO2

emissions rate from the facility over the 30-year time period would 

be equivalent to the proposed standard of performance of 1,000 lb 

CO2/MWh. This reduced emissions standard during the remainder of the 

30-year period would be met with some level of CCS.42

For added flexibility, under this option, we are taking comment 

on allowing the owner/operator to select a different emission 

 

42 As discussed elsewhere, EPA is soliciting comment on whether the 

emissions standard that reflects CCS should be somewhat higher or 

lower than 1,000 lb CO2/MWh, and whether the emissions standard that 

reflects supercritical efficiency should be somewhat higher or lower 

than 1,800 lb CO2/MWh. If EPA does promulgate a higher or lower 

standard in either case, then EPA may revise the 600 lb CO2/MWh amount 

accordingly.
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trajectory to achieving the 30-year average as long as the 

owner/operator obtains EPA approval of that rate before beginning 

operations. Such a trajectory would have to assure that, assuming 

similar amounts of operation in each year, the overall overage 

emission rate would be at or below the required 30-year average of 

1,000 lb CO2/MWh. For instance, if an owner or operator wished to 

operate at a rate of 2,000 lb CO2/MWh for the first period, it would 

have to commit to something more stringent than achieving a 600 lb

CO2/MWh standard by the 11th year. Potential compliance pathways could 

include committing to a limit of 500 lb CO2/MWh by the 11th year or 

committing to a limit of 600 lb CO2/MWh by the 8th year.

The EPA is also soliciting comment on what additional 

requirements would be necessary to implement the 30-year averaging 

requirement. Specifically, if the owners or operators did not intend 

to install CCS when the unit commenced operation, they could be 

required to submit a plan that includes a location to store CO2 and a 

schedule for construction and operation of their carbon capture 

system. The schedule would include key milestone dates such as 

soliciting proposals, obtaining financing, beginning construction, 

and beginning operation. The EPA requests comment on the

appropriateness of including these, and/or other requirements to 

ensure that the owners or operators of the facility have adequate 
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plans in place to meet the 30-year average emission rate requirement. 

Further, the shorter term emission limits for the entire 30-year 

period must be included in the source’s title V permit. We solicit 

comment on the enforceability of the 30-year averaging period, how we 

can ensure that the owner/operator will comply with the second phase 

of the standard, and what sort of compliance demonstrations are 

appropriate with such a long-term standard. We also solicit comment 

on whether this alternative compliance mechanism should automatically 

terminate in 2020 such that only facilities that commenced 

construction prior to 2020 would be able to use the 30-year average. 

The EPA suggests that this 30-year averaging compliance option

may be warranted for at least two reasons. First, it provides power 

companies with the option of building a coal-fired power plant in the 

near term and installing CCS at a later time when costs will likely 

be lower and further experience from demonstration projects will have 

been gained. The 30-year averaging period is sufficiently long to 

allow sources, before they install CCS, to benefit from the 

experience that will be gained from commercial-scale CCS 

demonstration projects operating over the next decade from a number 

of DOE-funded demonstration projects. A new coal- or pet coke-fired 

unit could operate for at least a decade before installing CCS and 

still have enough years operating at a controlled emission rate to 
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reach a 1,000 lb CO2/MWh standard on a 30-year basis. A second reason 

that this alternative may be practicable is that, even for sources 

installing and operating CCS at the beginning of a project, there may 

be startup issues (other than those related to the capture technology 

or the arrangements for sequestration). For instance, a company’s 

ability to sequester CO2 may be dependent upon construction by a third 

party of a pipeline that will be transporting the CO2 to a site to be 

used for enhanced oil recovery or permanent sequestration. Because 

the owner or operator does not have direct control over this part of 

the project, there may be concerns that it will not be completed on 

time and that even after spending all of the money to construct a 

coal-fired unit capable of capture, it will have to remain nonoperational for a period of time until the pipeline project or

sequestration destination is completed. The 30-year averaging 

compliance option could provide flexibility to operate the unit until 

the pipeline was completed as long as the carbon capture system is 

designed to meet a rate sufficiently below 1,000 lb CO2/MWh to allow 

for compliance with a 30-year averaging period. Such flexibility is 

likely to be most important for the first several CCS projects (i.e., 

“first movers”) because of the complexity of integration of the 

technologies and the fact that the business model is new for the 

power sector. Because the policy purpose of this 30-year averaging 
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compliance option is to leave open the option of building a coalfired unit in the near term and installing CCS after several years or 

to allow for flexibility during startup of the system, a long-term 

averaging period is needed to allow time for such a unit to achieve 

the 1,000 lb CO2/MWh level.

We note that under CAA section 111(b)(1)(B), “the Administrator 

shall, at least every 8 years, review and, if appropriate, revise 

[the] standards [of performance] ... ”. This review is required to 

take place in 2020, if not sooner. In the event that the EPA adopts 

the 30-year averaging compliance option, then at the time of the next 

required review, the EPA will evaluate the state of development or 

commercialization of CCS technologies and make a determination as to 

whether or not the 30-year averaging approach is still warranted for 

new sources. Because we expect CCS technology to advance 

significantly over the next several years, we believe that it may not 

be necessary to include this type of compliance option for a 30-year 

average the next time we review this NSPS. In light of this, we 

further solicit comment as to whether the 30-year averaging 

compliance option should automatically terminate in 2020, so that it 

would be available only for facilities that commenced construction 

prior to 2020.

We recognize that this compliance option, by authorizing sources 
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to average the emission level over a 30-year period, is unique. We 

recognize that the uniqueness of this approach may give rise to new 

issues concerning compliance and enforcement. We solicit comment on 

any practical difficulties in compliance and enforcement. Along these 

lines, although we propose that sources be required to retain records 

to demonstrate compliance with the emission limits for at least 30-

years following the date of initial startup of the affected EGU, we 

solicit comment on the merits of extending this period to 50 years. 

As with the proposed standard of performance, no averaging or 

emissions trading among affected sources would be allowed for this 

30-year averaging compliance option. 

This 30-year averaging compliance option is available only to 

new coal- and pet coke-fired EGUs. We do not believe that it is 

necessary for NGCC units, as they should be able to meet the proposed 

performance with no need for add-on technology. We also solicit 

comment on the need to extend the applicability for the 30-year 

averaging compliance option to other fossil fuels beyond just coal 

and pet coke. We seek comment on all other aspects of this 30-year 

averaging compliance option.

C. What are the startup, shutdown, and malfunction requirements?

1. Startups and Shutdowns

The NSPS that the EPA is proposing in this action would apply at 
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all times, including during startups and shutdowns. In establishing 

the level of the proposed NSPS, the EPA has taken into account 

startup and shutdown periods. The EPA is not proposing different 

standards for those periods.

To establish the proposed NSPS’s output-based CO2 standard, we 

accounted for periods of startup and shutdown by considering periods 

of part-load operation. As noted above, the proposed method to 

calculate compliance is to sum the emissions for all operating hours 

and to divide that value by the sum of the electrical energy output

and useful thermal energy output, where applicable for CHP EUGs, over 

a rolling 12-month period. This averaging approach gives more weight 

to high-load hours and more accurately reflects overall environmental 

performance. In addition, because low-load hours do not factor as 

heavily into the calculated average, the impact of including periods 

of startup and shutdown is minimized when calculating emission rates.

We solicit comment on the alternative of requiring compliance 

through an annual (calendar year) average.

We propose that these same requirements for startups and 

shutdowns would apply to the 30-year averaging compliance option.

2. Malfunctions

The NSPS that the EPA is proposing in this action would apply at 

all times, including during malfunctions. Periods of startup, normal 
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operations, and shutdown are all predictable and routine aspects of a 

source’s operations. By contrast, malfunction is defined as a 

“sudden, infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment or a 

process to operate in a normal or usual manner * * * ’’(40 CFR 60.2). 

The EPA has determined that CAA section 111 does not require that 

emissions that occur during periods of malfunction be factored into 

development of CAA section 111 standards. Further, nothing in section 

111 or in case law requires that the EPA anticipate and account for 

the innumerable types of potential malfunction events in setting 

emission standards. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 

(DC Cir. 1978) (‘‘In the nature of things, no general limit, 

individual permit, or even any upset provision can anticipate all 

upset situations. After a certain point, the transgression of 

regulatory limits caused by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement discretion, not 

for specification in advance by regulation.”)

Further, it is reasonable to interpret CAA section 111 as not 

requiring the EPA to account for malfunctions in setting emissions 

standards. For example, we note that section 111 provides that the 
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EPA set standards of performance which reflect the degree of emission 

limitation achievable through ‘‘the application of the best system of 

emission reduction’’ that the EPA determines is adequately 

demonstrated. Applying the concept of ‘‘the application of the best 

system of emission reduction’’ to periods during which a source is 

malfunctioning presents difficulties. The ‘‘application of the best 

system of emission reduction’’ is more appropriately understood to 

include operating units in such a way as to avoid malfunctions.

Further, accounting for malfunctions would be difficult, if not 

impossible, given the myriad different types of malfunctions that can 

occur across all sources in the category and given the difficulties 

associated with predicting or accounting for the frequency, degree, 

and duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v EPA, 167 F.3d 658, 662 (D.C. 

Cir. 1999) (The EPA typically has wide latitude in determining the 

extent of data-gathering necessary to solve a problem. We generally 

defer to an agency's decision to proceed on the basis of imperfect 

scientific information, rather than to "invest the resources to 

conduct the perfect study."). In addition, the goal of a best 

controlled or best performing source is to operate in such a way as 

to avoid malfunctions of the source and accounting for malfunctions 
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could lead to standards that are significantly less stringent than 

levels that are achieved by a well-performing non-malfunctioning 

source. The EPA’s approach to malfunctions is consistent with section 

111 and is a reasonable interpretation of the statute.

In the event that a source fails to comply with the applicable 

CAA section 111 standards as a result of a malfunction event, the EPA 

would determine an appropriate response based on, among other things, 

the good faith efforts of the source to minimize emissions during 

malfunction periods, including preventative and corrective actions, 

as well as root cause analyses to ascertain and rectify excess 

emissions. The EPA would also consider whether the source's failure 

to comply with the CAA section 111 standard was, in fact, “sudden, 

infrequent, not reasonably preventable” and was not instead “caused 

in part by poor maintenance or careless operation.” 40 CFR section 

60.2 (definition of malfunction).

Finally, the EPA recognizes that even equipment that is properly 

designed and maintained can sometimes fail and that such failure can 

sometimes cause an exceedance of the relevant emission standard. 

(See, e.g., “State Implementation Plans: Policy Regarding Excessive 

Emissions During Malfunctions, Startup, and Shutdown” (Sept. 20, 

1999); Policy on Excess Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 15, 1983), which are both 
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included in the docket for this rulemaking.) The EPA is therefore 

proposing to add to the final rule an affirmative defense to civil 

penalties for exceedances of emission limits that are caused by 

malfunctions. See 40 CFR 60.10042 (defining “affirmative defense” to 

mean, in the context of an enforcement proceeding, a response or 

defense put forward by a defendant, regarding which the defendant has 

the burden of proof, and the merits of which are independently and 

objectively evaluated in a judicial or administrative proceeding.). 

We also are proposing other regulatory provisions to specify the 

elements that are necessary to establish this affirmative defense: 

the source must prove by a preponderance of the evidence that it has 

met all of the elements set forth in 60.10001. (See 40 CFR 22.24). 

The criteria ensure that the affirmative defense is available only 

where the event that causes an exceedance of the emission limit meets 

the narrow definition of malfunction in 40 CFR 60.2 (sudden, 

infrequent, not reasonably preventable and not caused by poor 

maintenance and or careless operation). For example, to successfully 

assert the affirmative defense, the source must prove by a 

preponderance of the evidence that excess emissions “[w]ere caused by 

a sudden, infrequent, and unavoidable failure of air pollution 

control and monitoring equipment, process equipment, or a process to 

operate in a normal or usual manner....” The criteria also are designed 
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to ensure that steps are taken to correct the malfunction, to 

minimize emissions in accordance with section 60.10001 and to prevent 

future malfunctions. For example, the source must prove by a 

preponderance of the evidence that “[r]epairs were made as 

expeditiously as possible when the applicable emission limitations 

were being exceeded...” and that “[a]ll possible steps were taken to 

minimize the impact of the excess emissions on ambient air quality, 

the environment and human health....” In any judicial or administrative 

proceeding, the Administrator may challenge the assertion of the 

affirmative defense and, if the respondent has not met its burden of 

proving all of the requirements in the affirmative defense, 

appropriate penalties may be assessed in accordance with section 113 

of the CAA (see also 40 CFR part 22.77).

The EPA is including an affirmative defense in an attempt to 

balance a tension, inherent in many types of air regulation, to 

ensure adequate compliance while simultaneously recognizing that 

despite the most diligent of efforts, emission limits may be exceeded 

under circumstances beyond the control of the source. The EPA must 

establish emission standards that “limit the quantity, rate, or 

concentration of emissions of air pollutants on a continuous basis.” 

42 U.S.C. §7602(k)(defining “emission limitation and emission 

standard”). See generally Sierra Club v. EPA, 551 F.3d 1019, 1021 
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(D.C. Cir. 2008) Thus, the EPA is required to ensure that section 112 

emissions limitations are continuous. The affirmative defense for 

malfunction events meets this requirement by ensuring that even where 

there is a malfunction, the emission limitation is still enforceable 

through injunctive relief.43 While “continuous” limitations, on the 

one hand, are required, there is also case law indicating that in 

many situations it is appropriate for the EPA to account for the

practical realities of technology. For example, in Essex Chemical v. 

Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit 

acknowledged that in setting standards under CAA section 111 “variant 

provisions” such as provisions allowing for upsets during startup, 

shutdown and equipment malfunction “appear necessary to preserve the 

reasonableness of the standards as a whole and that the record does 

not support the ‘never to be exceeded’ standard currently in force.” 

See also, Portland Cement Association v. Ruckelshaus, 486 F.2d 375 

(D.C. Cir. 1973). Though intervening case law such as Sierra Club v. 

EPA and the CAA 1977 amendments undermine the relevance of these 

cases today, they support the EPA’s view that a system that 

incorporates some level of flexibility is reasonable. The affirmative 

 

43 Note that the Ninth Circuit recently upheld EPA’s decision to apply 

this affirmative defense approach to only actions seeking civil 

penalties, and not also to actions seeking injunctive relief. Montana 

Sulfur & Chemical Co. v. EPA, No. 02-71657 (9th Cir. August 31, 2011) 

(slip op. at 456).
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defense simply provides for a defense to civil penalties for excess 

emissions that are proven to be beyond the control of the source. By 

incorporating an affirmative defense, the EPA has formalized its 

approach to upset events. In a Clean Water Act setting, the Ninth 

Circuit required this type of formalized approach when regulating 

“upsets beyond the control of the permit holder.” Marathon Oil Co. v. 

EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an 

informal approach is adequate). The affirmative defense provisions 

give the EPA the flexibility to both ensure that its emission 

limitations are “continuous” as required by 42 U.S.C. §7602(k), and 

account for unplanned upsets and thus support the reasonableness of 

the standard as a whole.

We propose that these same requirements for malfunctions would 

apply to the 30-year averaging compliance option; however, we take 

comment on whether it is appropriate to have an affirmative defense 

for the 30-year averaging portion of that compliance option, given 

that we would expect malfunctions to only impact shorter emissions 

limits, and the longer the compliance period, the less likely 

malfunction events are to impact a source’s ability to meet the 

standard.

D. What are the continuous monitoring requirements?
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The EPA is proposing that a CO2 mass rate CEMS and the associated 

automatic data acquisition and handling system must be installed and 

operated in accordance with the requirements below.

1. Prepare a site-specific monitoring plan that addresses the 

monitoring system design, data collection, and the quality assurance 

and quality control elements consistent with the requirements in 40 

CFR part 75. 

2. Use all the data collected during all other required data 

collection periods in assessing the operation of the control device 

and associated control system.

3. Report any periods for which the monitoring system failed to 

collect required data.

4. Except for periods of monitoring system malfunctions, repairs 

associated with monitoring system malfunctions, and required 

monitoring system quality assurance or quality control activities 

(including, as applicable, calibration checks and required zero and 

span adjustments); failure to collect required data is a deviation of 

the monitoring requirements.

 We propose that owners/operators would install the CEMS and 

complete the CEMS certification in accordance with the schedule 

required in 40 CFR part 75, section 75.4(b). 
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We also request comment on the appropriateness of applying the 

backup monitor requirements in 40 CFR part 75.10(e), the missing data 

procedures in 40 CFR part 75, sections 75.31 through 75.37, and 

appendix C for this proposed rule.

We propose that these same monitoring requirements would apply 

to the 30-year averaging compliance option.

E. What are the emissions performance testing requirements?

Consistent with the performance testing requirements in the CAA 

section 111 regulatory general provisions (40 CFR part 60.8) and CEMS 

certification requirements (40 CFR part 75.4(b)), we propose that 

owners/operators of a new unit, conduct an initial performance test 

to demonstrate compliance with the CO2 emissions limits beginning in 

the calendar month following initial certification of the CO2 and flow 

rate monitoring CEMS.

We propose that the initial performance test consist of collection 

of hourly CO2 average concentration, mass flow rate (standard cubic 

feet per hour) recorded with the certified CO2 concentration and flow 

rate CEMS and the corresponding electrical power generation data for 

all of the hours of operation for the first calendar year beginning 

on the first day of the first month following completion of the CEMS 

installation and certification. For all of the operating hours during 

each monthly period, including startup and shutdown, you would 
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calculate compliance with the emissions limit by dividing the sum of 

the hourly CO2 mass values by the sum of the hourly useful energy 

output produced over the first 12 months of data.

We propose that these same emissions performance testing 

requirements would apply to the 30-year averaging compliance option.

F. What are the continuous compliance requirements?

In this rulemaking, we propose that compliance with the 

applicable average CO2 mass emissions rate (lb/MWh) must be calculated 

as a 12-month rolling average, updated monthly, using the reported 

hourly CO2 average concentration and flow rate values from the 

certified CEMS data collected for the previous month’s process 

operating days along with generation data tracked by the facility for 

the unit. We propose that compliance with the emissions limit must be 

calculated by dividing the sum of the hourly CO2 mass emissions values 

by the sum of the useful energy output produced for each calendar 

month period and that the 12-month rolling average must be updated as 

the average of the previous 12 months’ calculations. Affected sources 

will continue to be subject to the standards and maintenance 

requirements in the section 111 regulatory general provisions. 40 CFR 

part 60, subpart A.

We solicit comment on, in the alternative, an annual (calendar 

year) average emission limit, which would be calculated through 
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comparable methodology as just described.

We propose that these same continuous compliance requirements 

would apply to the 30-year averaging compliance option.

G. What are the notification, recordkeeping, and reporting 

requirements?

In this rulemaking, the EPA is proposing that you, as the owner 

or operator of a new unit, must comply with the notification and 

recordkeeping requirements in the section 111 regulatory general 

provisions, 40 CFR part 60, subpart A, and need to report results of 

performance testing and excess emissions; as well as record and 

maintain hourly average CO2 emissions concentration, hourly average 

flow rate, and hourly useful electrical generation. Note that the 

summary form identified as Figure 1 in 40 CFR part 60.7(d) will be 

revised to include CO2 as a pollutant. We are also seeking comments on 

whether the EPA should require initial notification of compliance 

status reports. In most rules, an initial notification of compliance 

status report, where owners and operators of sources subject to a 

particular rule notify the EPA and State and Local Air Pollution 

Control Agencies that their source is subject to the rule and how 

they intend to comply with the rule, is required. Regulators find 

this information very helpful in implementing and enforcing 

particular rules. In this case, most, if not all, of the sources that 
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are potentially subject to this rule have already been identified 

because they are subject to other New Source Performance Standards 

and Part 75 Acid Rain provisions. 

As part of an Agency-wide effort to facilitate reporting of 

environmental data and reports, we are requiring electronic reporting 

of selected reports, required by this regulation, to the EPA. We are 

proposing that owners and operators subject to this regulation must 

electronically submit excess emissions, continuous monitoring systems 

performance and-or summary reports required under section 60.7(c). 

Owners and operators would need to submit these reports to the EPA’s 

WebFIRE database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed in the Central Data Exchange 

(CDX). The CDX is the EPA’s portal for submitting and managing

electronic environmental data and reports and is accessed at

www.epa.gov/cdx. The CDX is needed to meet the EPA standards for 

electronic reporting set by the Cross-Media Electronic Reporting 

Rule. For more information, please see http://www.epa.gov/cromerr/.

Owners and operators required to submit electronic reports would need 

to register to use the CDX and for the CEDRI node at 

http://cdx.epa.gov/epa_home.asp. Once a user has access to CDX and 

CEDRI, the owners and operators would use the subpart specific forms

in CEDRI to enter the information for the 60.7(c) required reports. 
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In most New Source Performance Standards owners and operators 

are required to keep records of their reports on site for at least 2 

years. Since the owner or operator would be submitting the data in 

these reports to be housed in CDX and WebFIRE, we are proposing to 

forgo recordkeeping requirements for those reports required to be 

submitted in proposed section 60.5555(a)(1). We believe that since 

the WebFIRE database is public that the need for recordkeeping onsite 

for certain information will not be needed as the information will be 

readily available for all stakeholders to access.

We are aware that owners or operators of many existing EGUs are 

required to submit some emissions data through the EPA Acid Rain 

Program’s Emissions Collection and Monitoring Plan System (ECMPS) for 

SO2, NOx, CO2, and other related data. We propose for affected sources 

to continue to use ECMPS with modifications to allow for collecting 

CO2 mass emissions data and the CEMS relative accuracy reports 

proposed in this rule.

We request comment on these and other modifications to ECMPS 

appropriate for implementing this rule and any other EPA rules that 

apply to EGUs in order to streamline and focus all applicable 

emissions data reporting requirements. We request comment on 

modification of the ECMPS system to collect, track, and calculate CO2

emissions rates based on hourly useful energy output for the unit. We 
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also request comment on tracking and making use of useful steam data 

for new facilities.

We are also aware that owners or operators of existing units are 

required to submit electrical generation data according to procedures 

required by the DOE’s Energy Information Administration (EIA) for its 

reports. We request comment on the appropriateness of using these 

electrical generation data in this proposed rule.

The EPA proposes that these same notice, recordkeeping, and 

reporting requirements would apply to the 30-year averaging 

compliance option. The EPA requests comment on whether any 

alterations or additions are appropriate for the notice, 

recordkeeping, and reporting requirements that would apply to the 30-

year averaging compliance option. The EPA also requests comment on 

whether sources that utilize the 30-year averaging compliance option

should include, as applicable requirements in their title V permits,

a specific explanation of their compliance plan, including when CCS 

would be deployed, what capture rate(s) would be achieved, how the CO2

would be sequestered, and whether the company anticipates receiving 

government financial assistance or other incentives for the CCS.

IV. Rationale for the Proposed Standards for New Sources

A. How did the EPA establish the emission limits?

1. Rationale for Proposing to Combine the Subpart Da Category and a 
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Component of the Subpart KKKK Category into a New Category for 

Purposes of Regulating GHG Emissions

The EPA is proposing to create a new subpart in 40 CFR part 60 

by combining the sources in subpart Da (the Da category) and a subset

of the sources in subpart KKKK (the KKKK category) –– stationary 

combined cycle units, but not stationary simple cycle units -- for 

purposes of promulgating standards of performance for emissions of 

GHGs from new sources. This new subpart will be numbered TTTT. 

Consistent with standard practice and Executive Order 13563, and in 

particular its emphasis on “the open exchange of information and 

perspectives” and “providing an opportunity for public comment on all 

pertinent parts of the rulemaking docket, including relevant 

scientific and technical findings” and on consideration of 

alternatives, we invite comments on our decision to combine the two 

source categories. 

At this time, the EPA is not proposing to subcategorize new 

sources and is not proposing to combine the Da category and 

components of the KKKK category for purposes of regulating criteria

pollutants. 

CAA section 111 provides legal authority for combining the 

categories into a new category. Clean Air Act section 111(b)(1)(A) 
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provides:

The Administrator shall, within 90 days after December 31, 

1970, publish (and from time to time thereafter shall 

revise) a list of categories of stationary sources. He 

shall include a category of sources in such a list if in 

his judgment it causes or contributes significantly to air 

pollution which may reasonably be anticipated to endanger 

public health or welfare. 

(Emphasis added.)

As quoted, this provision grants to the Administrator the 

authority to “revise” the list of categories. Combining 

categories, in whole or in part, is a form of “revis[ing]” the 

list of categories (along with taking other actions, such as 

adding more categories or delisting categories), and accordingly 

is authorized. 

For three principal reasons, it is appropriate for the EPA to 

combine the Da category and the stationary combined cycle component 

of the KKKK category at this time for purposes of regulating GHGs. 

First, all of the plants covered by the new combined category 

(including fossil fuel-fired boilers, IGCC units and NGCC units) 

perform the same essential function, which is to generate baseload or 

intermediate load electricity. It is sensible to treat as part of the 
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same category units that generate baseload or intermediate 

electricity, regardless of their design or fossil fuel type. 

Second, all newly constructed sources have options in selecting 

their design (although it is true that natural gas-fired plants are 

inherently lower emitting with regard to CO2 than coal-fired plants. 

As a result, prospective owners and operators of new sources could

readily comply with the proposed emission standards by choosing to 

construct a NGCC unit. These two factors provide sufficient legal 

rationale for the EPA to combine the Da category and the combined 

cycle component of the KKKK category for purposes of establishing a 

standard of performance for GHG emissions. 

The agency has previously combined one type of baseload and 

intermediate load combined cycle unit (IGCC, previously covered under 

Subpart GG) with Da units for the purposes of setting a standard [40 

CFR 60.41Da(b), Feb. 28, 2005]. This action now similarly combines 

another type of baseload and intermediate load combined cycle unit 

(NGCC, previously covered under Subpart KKKK) with Subpart Da units 

for the purposes of setting a standard.

A third factor lends additional support. Combining the 

categories does not raise adverse policy concerns. On the basis of 

comments made during the listening sessions, we anticipate that some 

commenters may question whether combining the categories and applying 
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the NGCC standard to all new plants within the combined category may 

limit construction of new coal-fired power plants, and thereby have a 

disruptive effect on the electric power industry, increase 

electricity prices and/or have adverse implications for energy 

diversity in new generation. We do not believe that this action would 

have those effects. As discussed below, and importantly, economic 

models forecast no new construction of coal-fired generation without 

CCS through the analysis period, which extends until 2020 (when the 

standard will be revisited). Accordingly, economic conditions are 

expected to be the main driver precluding, or at least limiting, 

construction of coal-fired EGUs. Because of those economic 

conditions, there is a strong independent movement of baseload power 

plants toward NGCC. In light of that movement, it is appropriate for 

the EPA to focus on this technology in developing the standard, 

rather than subcategorizing and providing a separate standard for new 

coal units. See Portland Cement Ass'n v. EPA, 665 F.3d 177, 190 

(D.C. Cir. 2011) (affirming EPA's decision not to subcategorize in 

part because of "the universal movement in the 

portland cement industry towards adoption of preheater/precalciner 

technology"). 

Notwithstanding these points, we recognize the possibility that 

a limited amount of new coal-fired construction may nevertheless 
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occur. Today’s action would not foreclose construction of new coalfired EGUs. Rather, the of new coal-fired EGUs that may be expected 

to be built in the foreseeable future (and for reasons stated above, 

this is anticipated to be a relatively small number) may install CCS 

control equipment (if not at the time of construction, then not long 

thereafter) By doing so, they may achieve the same average CO2

emission rate (at least over time) as a natural gas-fired combined 

cycle unit. It is reasonable to expect that some coal-fired power 

plants may be able to implement CCS at the present time, and thereby 

achieve the 1,000 lb CO2/MWh standard immediately. As noted elsewhere, 

CCS has been demonstrated to be technologically achievable, and, even 

though it is costly, there are some State and Federal programs that 

can make CCS more affordable. Several power companies have announced 

plans to incorporate CCS at six already permitted coal-fired EGU 

construction projects in this country (as we discuss below in section 

V.B., concerning transitional sources). Programs exist that provide 

some funding for CCS through pilot or other demonstration programs, 

and we expect those to continue. In addition, we reasonably expect 

the costs of CCS to decline over time. As discussed below, we are not 

proposing that CCS does or does not qualify as the “best system of 

emission reduction” that “has been adequately demonstrated” for new 

coal-fired power plants. Rather, the feasibility of CCS and its 
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availability for the limited amount of new coal-fired construction 

that may be expected, means that this action to combine the 

categories and establish the NSPS at the proposed 1,000 lb CO2/MWh 

emission limit will not have notable adverse effects on new coalfired construction or, therefore, on the electric utility industry, 

electricity prices, or energy diversity. We welcome public comments 

on this discussion.

On the other hand, at this time, we do not consider it 

appropriate to include simple cycle facilities as an affected source 

in the new 40 CFR part 60, subpart TTTT for GHG emissions from new 

facilities. The reason for this is that the function of a new simple 

cycle power plant is different than that of a new combined cycle 

plant or coal-fired plant. Combined cycle plants and coal-fired 

plants are typically designed to provide baseload or intermediateload power, while simple cycle turbines are designed to provide 

peaking power. Because combined cycle power plants and coal-fired 

power plants both serve the same purpose and have design options to 

emit CO2 at similar levels, we believe it is appropriate to combine 

them. Because peaking turbines operate less and because it would be 

much more expensive to lower their emission profile to that of a 

combined cycle power plant or a coal-fired plant with CCS, the EPA 

does not believe it is appropriate to include them in this source
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category.

As noted above, some commenters in the listening sessions did 

suggest that EPA not combine the two source categories. EPA has 

rejected that option for all the reasons outlined above: 1)Fossilfuel-fired boilers, combined cycle natural gas units, and IGCC units 

all serve the same basic function, generating baseload or 

intermediate load power; 2)the proposed standards can be met by 

different types of units in the category (NGCC units or coal-fired 

units with CCS); and 3)it is consistent with industry trends (as 

further explained elsewhere in this notice: due largely to current 

and projected gas and coal price trends, new fossil-fuel-fired builds 

are projected to be natural gas combined cycle units or coal-fired 

units with CCS supported by federal funding). There is an additional 

reason for rejecting the option of retaining (and establishing 

separate standards for) separate source categories. EPA’s analysis 

(in Section 5.10 of the RIA) suggests that over a wide range of 

market conditions, constructing a new unit that meets a limit of 1000 

lbs CO2/MWh instead of an advanced coal-fired unit without CCS would 

likely produce net social benefits. For all of these reasons, 

retaining separate source categories would be unlikely to generate 

substantial private cost savings, but at the same time, would create 

the risk of significantly higher GHG emissions and other air 
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pollutants from some new units, resulting, in turn, in higher social

costs. 

By the same token, at this time, we do not consider it 

appropriate to combine the Da category and the combined cycle 

component of the KKKK category for any pollutants other than GHGs, 

that is, for criteria pollutants. This is because although coal-fired 

EGUs have an array of control options for criteria and air toxic air 

pollutants to choose from, those controls generally do not reduce 

their criteria and air toxic emissions to the level of conventional 

emissions from natural gas-fired EGUs.

2. Endangerment and Cause-or-Contribute-Significantly Finding

a. Overview. In today’s rulemaking, we propose or solicit comment on 

alternative interpretations for whether section 111 includes 

prerequisites to rulemaking that involve an endangerment finding and 

a cause-or-contribute-significantly finding. By its terms, CAA 

section 111 provides that once the EPA lists a source category for 

regulation because the category causes or contributes significantly 

to air pollution that may reasonably be anticipated to endanger 

public health or welfare, the EPA then establishes requirements for 

new sources in that source category. The EPA proposes to interpret 

these provisions so that it is authorized to promulgate the 

rulemaking proposed today because it has already determined that both 
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the Da and KKKK source categories cause or contribute significantly 

to air pollution that may reasonably be anticipated to endanger 

public health or welfare. The EPA solicits comment on interpreting 

CAA section 111 in the alternative so as to require (i) an 

endangerment finding for air pollution not specifically covered by 

the endangerment finding the EPA made when listing the source 

category, but that in this case, the EPA’s 2009 Endangerment Finding 

for GHGs under Section 202(a) of the CAA (along with the EPA’s 2010 

denial of petitions to reconsider (2010 Reconsideration Denial)), 

fulfills that requirement; and (ii) a cause-or-contributesignificantly finding for air pollutants not specifically covered by 

the cause-or-contribute-significantly finding the EPA made when 

listing the source category, and that in this case, the large amounts 

of CO2 emissions from power plants provide a compelling basis allowing 

the EPA to propose that finding. The EPA also solicits comment on 

another alternative, which is interpreting CAA section 111 so as not 

to require a specific endangerment finding or cause or contribute 

finding, but simply to require the EPA to establish a rational basis 

for regulating an air pollutant from a source category. In this case, 

the EPA’s 2009 Endangerment Finding for GHGs and the 2010 denial of 

petitions to reconsider the Endangerment Finding, as well as the 

large amounts of CO2 emissions from power plants, provide that 
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rational basis. Finally, as an alternative for the basis for a 

rational basis determination, the 2010 and 2011 Assessment Reports 

from the National Academies confirm the Endangerment Finding and the 

denial of petitions to reconsider.

b. Proposal: Previous Source Category Findings Meet Any Endangerment 

Prerequisite to Regulation. In this rulemaking, the EPA proposes to 

interpret CAA section 111 so that we are not required, as a 

prerequisite to regulating CO2 emissions from EGUs, to issue a new 

finding as to the health or welfare impacts of GHG air pollution or a 

finding as to the extent that affected sources contribute to that air 

pollution.

Clean Air Act section 111(b)(1)(A), by its terms, requires that 

the Administrator list a source category for regulation if the 

“category ...in [the Administrator’s] judgment, ... causes or 

contributes significantly to air pollution which may reasonably be 

anticipated to endanger public health or welfare.” Clean Air Act 

section 111(b)(1)(B) goes on to provide that after listing the source 

category, the EPA must promulgate regulations “establishing federal 

standards of performance for new sources within such category.” In 

turn, CAA section 111(a)(1) defines a “standard of performance” as a 

“standard for emissions of air pollutants which reflects the degree 

of emission reduction which (taking into account ... cost ... and any 
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nonair quality health and environmental impact and energy 

requirements) ... has been adequately demonstrated.”

Thus, although CAA section 111 clearly requires the EPA to list 

a source category if its emissions contribute significantly to air 

pollution that endangers public health or welfare, and then to 

promulgate standards of performance for particular pollutants, 

section 111 does not by its terms require that the EPA make any 

endangerment finding with respect to those particular pollutants, or 

any cause-or-contribute-significantly finding with respect to the 

source category, at the time the EPA promulgates the standards of 

performance for those pollutants. The lack of any such requirement 

contrasts with (i) the definition of “standard of performance,” which 

specifically requires the EPA to consider “nonair quality health and 

environmental impact,” CAA section 111(a)(1) (emphasis added); and 

(ii) other CAA provisions that do require the EPA to make 

endangerment and cause-or-contribute findings for the particular 

pollutant that the EPA regulates under those provisions. E.g., CAA 

sections 202(a)(1), 211(c)(1), 231(a)(2)(A).

Accordingly, under our proposal, once the EPA has listed a 

source category, and the EPA proceeds to regulate particular 

pollutants from that source category, CAA section 111 does not 

require that the EPA make an endangerment finding for the relevant 
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air pollution or a cause-or-contribute-significantly finding for the 

relevant air pollutants from that source category. The fact that the 

EPA is, in this rulemaking, proposing to partially combine the Da and 

KKKK source categories does not alter this outcome. As noted above, 

under CAA section 111(b)(1)(A), the EPA may add a source category to 

the list of categories only after determining that the source 

category “causes, or contributes significantly to, air pollution 

which may reasonably be anticipated to endanger public health or 

welfare.” The EPA has previously determined that each of the Da and 

KKKK categories causes or contributes significantly to such air 

pollution. Combining the Da category and some of the sources in the 

KKKK category does not necessitate that the EPA make a new cause-orcontribute-significantly finding for the expanded Da category. This 

is because the EPA has already found that at least one component of 

the new category -– the former Da sources -- by itself causes or 

contributes significantly to such air pollution. There is no reason 

why this expansion of the Da category to include the pre-existing Da 

sources plus additional sources could be considered to contribute to 

such air pollution to an extent that is less than the contribution 

from the pre-existing Da sources alone. As a result, the new category 

must necessarily be considered to cause or contribute significantly 

to such air pollution.
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In addition to proposing this interpretation, we also solicit 

comment on alternative interpretations under CAA section 111, 

including those described next.

c. First Alternative Interpretation: Endangerment Finding 

Prerequisite. We solicit comment on an alternative interpretation 

under which the EPA is required, as a prerequisite to promulgating 

standards of performance under CAA section 111(b), to have issued an 

endangerment finding specifically for the relevant air pollution and 

a cause-or-contribute-significantly finding specifically for the 

relevant source category and air pollutant. In particular, what would 

be the legal basis for such an interpretation?

Even if CAA section 111 is interpreted to require those 

findings, then, in a case in which the EPA did not make those 

findings under CAA section 111, it is the EPA’s view that the EPA 

would satisfy the need for a CAA section 111 endangerment finding 

through an endangerment or comparable finding that the EPA made or 

that Congress adopted under any other provision of the CAA. For 

example, the EPA may regulate, under CAA section 111, (i) NAAQS 

pollutants because of the determinations the EPA made under CAA 

sections 108 and 109 and (ii) HAPs that Congress listed under CAA 

section 112(b)(1). It is the EPA’s interpretation that once an 

endangerment or comparable finding is made with respect to the 
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relevant air pollution under another CAA provision, regulation under 

CAA section 111 of source categories that cause or contribute 

significantly to that same air pollution may proceed without any need 

for the EPA to revisit or update that endangerment finding as part of 

the CAA section 111 regulatory process. Instead, any concerns about 

the continued validity of that endangerment finding may be resolved 

through a petition to reconsider that finding under the applicable 

CAA provision.

Applying this alternative interpretation of CAA section 111 to 

this rulemaking, the 2009 Endangerment Finding for GHG air pollution 

fulfills any requirement under CAA section 111 that the EPA issue a 

finding that GHG air pollution may reasonably be anticipated to 

endanger public health or welfare in order for the EPA to establish 

standards of performance for GHG emissions from EGUs. As discussed 

above, the EPA already issued this endangerment finding under CAA 

section 202(a)(1), as part of its process for promulgating the Light 

Duty Vehicle Rule.

The EPA recognizes that under this alternative interpretation, 

the EPA could be required to issue a cause-or-contributesignificantly finding for CO2 emissions from the fossil fuel-fired

EGUs, as a prerequisite to regulating such emissions under CAA 

section 111. Therefore, under this alternative interpretation, in 
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today’s rulemaking, the EPA proposes to find that CO2 emissions from 

fossil fuel-fired EGUs cause or contribute significantly to the GHG 

air pollution. The EPA’s basis for this proposed finding is, in part, 

that the large amounts of CO2 emitted by fossil fuel-fired EGUs 

clearly exceed the low hurdle necessary for the cause-or-contributesignificantly finding. As noted above in Tables 2 and 3, fossil fuelfired EGUs emit almost one-third of all U.S. GHG emissions, and 

constitute by far the largest single stationary source category of 

GHG emissions. Indeed, so great is the contribution of CO2 air 

pollutants from EGUs to GHG air pollution, that it is simply not 

necessary in this rulemaking to determine thresholds for when a 

contribution may be considered to be a “significant[]” contribution. 

If it were necessary, the EPA proposes that a limited amount of 

contribution would meet that standard in light of the fact that GHG 

air pollution is caused by a large number of types of sources and 

that no one source category dominates the entire inventory.

d. Second alternative interpretation: Rational Basis Prerequisite. As 

a second alternative interpretation, the lack of any requirement in 

CAA section 111 addressing whether and how the EPA is to evaluate 

emissions of particular pollutants from sources in the listed source 

category as a prerequisite for regulation may be viewed as a 

statutory gap that requires a Chevron step 2 interpretation. In this 
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case, the EPA is authorized to develop an interpretation that 

reasonably effectuates the purposes of CAA section 111. Under this 

alternative interpretation, the EPA must demonstrate a rational basis 

for controlling the emissions of the particular pollutants. That 

rational basis may consist of some type of factual showing that is 

consistent with the purposes of CAA section 111, but may be something 

short of an endangerment and a cause-or-contribute-significantly 

finding. 

There are several options for the factual showings that comprise 

a rational basis. Under the first option, the EPA would be justified 

in the present case in taking action with respect to GHG air 

pollution because of the EPA’s 2009 Endangerment Finding that GHG air 

pollution may reasonably be anticipated to endanger public health and 

welfare. The EPA issued that Endangerment Finding quite recently, in 

December, 2009, and by notice dated August 13, 2010, the EPA denied 

ten petitions to reconsider that Finding, an action that entailed 

further review of scientific information. 

Under the second option, the EPA could conclude that the recent 

Endangerment Finding and denial of reconsideration, coupled with the 

even more recent assessments from the NAS, published in 2010 and 

2011, which lend further credence to the science supporting the 

Endangerment Finding, suffice to provide a rational basis for 
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promulgating regulations under CAA section 111 designed to address 

contributions to the GHG air pollution. 

Under either of these options, the EPA would need to establish a 

rational basis for regulating CO2 emissions from affected EGUs. The 

fact that affected EGUs emit almost one-third of all U.S. GHGs and 

comprise by far the largest stationary source category of GHG 

emissions, as discussed above, would readily provide such a rational 

basis. 

3. Rationale for Emission Limits

a. Few New Coal-fired Power Plants. An important part of the basis 

for the EPA’s proposal for new sources in this rulemaking is that all 

indications suggest that very few new coal-fired power plants will be 

constructed in the foreseeable future. Although a small number of new 

coal-fired power plants have been built recently, the industry 

generally is not building these kinds of power plants at present and 

is not expected to do so for the foreseeable future. The reasons 

include the current economic environment, which has lead to lower 

electricity demand, and competitive natural gas prices. Natural gas 

prices have stabilized over the past few years as new drilling 

techniques have brought additional supply to the marketplace. As a 

result, natural gas prices are expected to be competitive for the 

foreseeable future and utilities are likely to rely heavily on 
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natural gas to meet new demand for electricity generation. On 

average, the cost of generation from a new NGCC power plant is 

expected to be lower than the cost of generation from a new coalfired power plant.44 

Other drivers that may influence decisions to build new power 

plants are State and Federal energy and tax policies. Many states 

have adopted renewable portfolio standards (RPS), which require that 

a certain portion of electricity come from renewable energy sources 

like solar or wind. The federal government has also adopted 

incentives for electric generation from renewable energy sources and 

loan guarantees for new nuclear power plants.

These economic, cost, and policy factors create an environment 

in which natural gas-fired power plants, renewable energy, and 

nuclear power are the forms of energy generation that are most often 

predicted to be built to meet new electricity demand over the coming 

years. 

Various energy sector modeling efforts, including projections 

from both the EIA and the EPA, show results that are consistent with 

these findings. The Annual Energy Outlook (AEO) for 2011 shows a very 

modest amount of new coal-fired power coming online beyond 2012, 

 

44 Levelized Cost of New Generation in the Annual Energy Outlook 2011 

http://205.254.135.24/oiaf/aeo/electricity_generation.html.
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although there are a number of coal-fired power plants that are 

currently under construction and expected to begin operation in the 

next year or two. According to the AEO 2011, the majority of new 

generating capacity will be either natural gas-fired or renewable, 

with some lesser amounts of nuclear power. The AEO 2011 is based on 

existing policy and regulations, such as state RPS programs and 

Federal tax credits for renewables.45 The new generation that EIA does 

show coming on-line after 2012 fits into one of three categories:

generation that is currently under construction, generation that will 

include CCS or industrial CHP. Units in the first group would not be 

subject to this rule because, since they have commenced construction,

they are considered existing sources. Units in the second group would 

include either units in the transitional category or new units. In 

either case, they could be built consistent with this action. Units 

in the third group would not be subject to this rule because CHP 

units that generate primarily on-site power are not considered EGUs 

and are thus not affected by the rule. 

The EPA modeling using the Integrated Planning Model (IPM), a 

detailed power sector model that the EPA uses to support power sector 

regulations, is keyed to the AEO in a number of respects and shows 

similar patterns of little future construction of new coal-fired 

 

45 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
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power plants under the base case.46 The EPA’s projections from IPM can 

be found in the RIA.

As discussed below, the fact that the expected number of coalfired power plants is so limited supports both (i) basing the 

standard of performance on NGCC, which is expected to be the most 

commonly built new fossil fuel-fired generating technology; and (ii) 

allowing 30-year averaging as an alternative compliance option for 

coal- and pet coke-fired power plants because CCS is feasible and 

sufficiently available for the few such plants expected, in light of 

the demonstration programs or other incentives available for CCS, 

coupled with the prospects that the costs of CCS will decline over 

time.

b. Basis for the Proposed Standard of Performance. In this section, 

we describe our basis for proposing a standard of 1,000 lb/MWh, and 

for taking comment on a range of 950 to 1,100 lb/MWh (430 to 500 

kg/MWh). We first describe our method for calculating these levels of 

CO2 emissions, and then note that several states are already requiring 

these levels of CO2 emissions. 

(1) Calculation of the Standard. For reasons explained below (see “d. 

Legal Justification for the Standard of Performance and 30-year 

 

46 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation.
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averaging compliance option”), a NGCC facility is the best system of 

emission reduction for new baseload and intermediate load EGUs. To 

establish an appropriate, natural gas-based standard, we reviewed the 

emissions rate of natural gas-fired (non-CHP) combined cycle 

facilities used in the power sector that commenced operation between

2006 and 2010 and that report complete generation data to EPA. Based 

on this analysis, nearly 95% of these facilities meet the proposed 

standards on an annual basis. These units represent a wide range of 

geographic locations (with differing elevations and ambient 

temperatures), operational characteristics, and sizes.

We are requesting comment on a range of 950 to 1,100 lb/MWh (430 

to 500 kg/MWh) for the final rule. The upper limit would incorporate 

essentially all available new combined cycle designs and would have 

limited impact on improving efficiency of combined cycle facilities. 

This upper limit would also be consistent with standards promulgated 

by some states, as noted elsewhere. The stricter standard would in 

general eliminate designs without a steam reheat cycle and similar 

lower efficiency designs for use in electric-only generation, and 

could limit presently available options for generation below 

approximately 40 MW. However, an owner/operator of combined cycle 

facilities with higher heat rates could either implement CHP or 
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integrated solar thermal for feedwater heating to achieve the 

proposed standard. 

(2) States Implementing a Comparable Standard. Several states have 

recently established emission performance standards or other measures 

to limit emissions of GHGs from new EGUs that are comparable to the 

proposal in this rulemaking. For example, in September 2006, 

California Governor Schwarzenegger signed into law Senate Bill 1368. 

The law limits long-term investments in baseload generation by the 

state's utilities to power plants that meet an emissions performance 

standard jointly established by the California Energy Commission and 

the California Public Utilities Commission. The Energy Commission has 

designed regulations that establish a standard for new and existing 

baseload generation owned by, or under long-term contract to publicly 

owned utilities, of 1,100 lb CO2/MWh.

In May 2007, Washington Governor Gregoire signed Substitute 

Senate Bill 6001, which established statewide GHG emissions reduction 

goals, and imposed an emission standard that applies to any baseload 

electric generation that commenced operation after June 1, 2008 and 

is located in Washington, whether or not that generation serves load 

located within the state. Baseload generation facilities must 

initially comply with an emission limit of 1,100 lb CO2/MWh.
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In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, 

which mandated that facilities generating baseload electricity, 

whether gas- or coal-fired, must have emissions equal to or less than 

1,100 lb CO2/MWh, and prohibited utilities from entering into longterm purchase agreements for baseload electricity with out-of-state 

facilities that do not meet that standard. Natural gas- and petroleum 

distillate-fired facilities that are primarily used to serve peak 

demand or to integrate energy from renewable resources are 

specifically exempted from the performance standard.

c. Basis for CCS as a Feasible Technology Option. In this section, we 

describe the basis for our position that CCS is a feasible technology 

option for new coal-fired power plants because CCS is technically 

feasible and sufficiently available in light of the limited amount of 

new coal-fired construction expected in the foreseeable future. In 

brief, first, at present, CCS is technologically feasible for 

implementation at new coal-fired power plants and its core components 

(CO2 capture, compression, transportation and storage) have already 

been implemented at commercial scale. Second, although the costs of 

CCS are presently high, we have reason to expect that the costs of 

CCS will decrease over time. This action will itself contribute to 

downward pressure on CCS costs by shifting the regulatory landscape 

towards CCS, consistent with the recent report by the Interagency 
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Task Force on Carbon Capture and Storage, established by President 

Obama on February 3, 2010, which we describe below. Third, we expect 

construction of no more than a few new coal-fired power plants by 

2020 and those plants may well be able to take advantage of 

demonstration programs or other sources of funding for CCS. Fourth, 

several states have set emission standards that will make 

implementation of CCS necessary for new coal-fired power plants, some

projects that implement CCS or components of it are proceeding, and 

other CCS projects are in the planning stages.

(1) Technological Feasibility of CCS. The current state of affairs 

concerning CCS was described and analyzed by the Interagency Task 

Force on Carbon Capture and Storage, established by President Obama 

on February 3, 2010, co-chaired by the DOE and the EPA, and composed 

of 14 executive departments and federal agencies. The Task Force was 

charged with proposing a plan to overcome the barriers to the 

widespread, cost-effective deployment of CCS within 10 years, with a 

goal of bringing five to ten commercial demonstration projects online 

by 2016. The Task Force found that, although early CCS projects face 

economic challenges related to climate policy uncertainty, first-ofa-kind technology risks, and the current high cost of CCS relative to 

other technologies, there are no insurmountable technological, legal, 

institutional, regulatory or other barriers that prevent CCS from 
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playing a role in reducing GHG emissions. The Task Force also 

identified the need for comprehensive review of the overall 

environmental impacts of CCS.

(a) Capture and Compression Technologies and Costs. Capture of CO2

from industrial gas streams has occurred since the 1930s using a 

variety of approaches to separate CO2 from other gases. These 

processes have been used in the natural gas industry and to produce 

food and chemical-grade CO2. Although current capture technologies are 

feasible, the costs of CO2 capture and compression represent the 

largest stumbling block to widespread commercialization of CCS. 

Currently available CO2 capture and compression processes are 

estimated to represent seventy to ninety percent of the overall CCS 

costs47.

In general, CO2 capture technologies applicable to coal-fired 

power generation can be categorized into three approaches48:

 Pre-combustion systems are designed to separate CO2 and H2 in the 

high-pressure syngas produced at IGCC power plants.

 Post-combustion systems are designed to separate CO2 from the 

flue gas produced by fossil-fuel combustion in air.

 Oxy-combustion uses high-purity O2, rather than air, to combust 

 

47 Report of the Interagency Task Force on Carbon Capture and Storage 

(August 2010)

48 IPCC, 2005; DOE, 2007.
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coal and therefore produces a highly concentrated CO2 stream.

Each of these three carbon capture approaches (pre-combustion, postcombustion, and oxy-combustion) is technologically feasible. However, 

each results in increased capital and operating costs and decreased 

electricity output (that is, an energy penalty), with a resulting 

increase in the cost of electricity. The energy penalty occurs 

because the CO2 capture process uses some of the energy produced from 

the plant.

(b) Current Availability of Transportation and Sequestration. The 

remaining steps for CCS (i.e., pipeline transportation and storage), 

are also well established but less expensive than capture and 

compression. 

Carbon dioxide has been transported via pipelines in the U.S. 

for nearly 40 years. Approximately 50 million metric tons of CO2 are 

transported each year through 3,600 miles of pipelines. Moreover, a 

review of the 500 largest CO2 point sources in the U.S. shows that 95 

percent are within 50 miles of a possible geologic sequestration 

site,49 which would lower transportation costs. For these reasons, the 

 

49 JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL 

Malone (2006), Carbon Dioxide Capture and Geologic Storage: A Key 

Component of a Global Energy Technology Strategy to Address Climate 

Change. Joint Global Change Research Institute, Battelle Pacific 

Northwest Division. PNWD-3602. College Park, MD.
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transportation component of CCS is not expected to be a significant 

stumbling block to the commercial availability of CCS in the future.

With respect to sequestration, globally, there are at least four 

commercial integrated CCS facilities sequestering captured CO2 into 

deep geologic formations and applying a suite of technologies to 

monitor and verify that the CO2 remains sequestered.50 These four 

sites represent over 25 years of cumulative experience on safely and 

effectively storing anthropogenic CO2 in appropriate deep geologic 

formations.51 Estimates based on DOE studies indicate that areas of 

the U.S. with appropriate geology have a storage potential of 1,800 

billion to more than 20,000 billion metric tons of CO2 in deep saline 

formations, oil and gas reservoirs and un-mineable coal seams.52 The 

U.S. experience with large-scale CO2 injection, such as at enhanced 

oil and gas recovery projects, combined with ongoing research, 

development, and demonstration programs in the U.S. and throughout 

the world, provide confidence that the storage –- along with capture, 

compression and transport -- of large amounts of CO2 can be achieved.

 

50 These projects are: Sleipner in the North Sea, Snøhvit in the 

Barents Sea, In Salah in Algeria, and Weyburn in Canada.

51 Dooley, J. J., et al. (2009). An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage Technologies as of 

June 2009. U.S. Department of Energy, Pacific Northwest National 

Laboratory, under Contract DE-AC05-76RL01830.

52 U.S. Department of Energy National Energy Technology Laboratory 

(2010). Carbon Sequestration Atlas of the United States and Canada, 

Third Edition.
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It should be noted that the EPA recently finalized two rules 

that aim to protect drinking water and track the amount of CO2 that is 

sequestered from facilities that carry out geologic sequestration. 

The Underground Injection Control (UIC) Class VI rule, established 

under authority of the Safe Drinking Water Act, sets requirements to 

ensure that geologic sequestration wells are appropriately sited, 

constructed, tested, monitored, and closed in a manner that ensures 

protection of underground sources of drinking water.53 The UIC Class 

VI regulations contain monitoring requirements to protect underground 

sources of drinking water, including the development of a 

comprehensive testing and monitoring plan. This includes testing of 

the mechanical integrity of the injection well, ground water 

monitoring, and tracking of the location of the injected CO2 using 

direct and indirect methods. Projects are also required to do 

extended post-injection monitoring and site care to track the 

location of the injected CO2 and monitor subsurface pressures until it 

can be demonstrated that underground sources of drinking water are no 

longer endangered. Subpart RR of the Greenhouse Gas Reporting 

Program, which was established under authority of the CAA and builds 

on UIC requirements, provides requirements for quantifying the amount 

 

53 Federal Requirements under the Underground Injection Control (UIC) 

Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, 

Final Rule, 75 FR 77230 (Dec. 10, 2010).
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of CO2 sequestered by these facilities.54 In addition, the EPA 

recently proposed a rule that would conditionally exclude CO2 streams 

from the definition of hazardous waste under RCRA, where these 

streams are being injected for purposes of geologic sequestration, 

provided that they are managed in accordance with certain 

conditions.55 That proposed rule is based upon the EPA's conclusion 

that the management of CO2 streams, under the proposed conditions, 

does not present a substantial risk to human health or the 

environment, and was based upon a review of existing regulatory 

programs applicable to the transportation of CO2 streams, and their 

injection into permitted UIC Class VI wells. Together, these actions 

help create a consistent national framework to ensure the safe and 

effective deployment of geologic sequestration.

(2) Expected reduction in CCS costs. Research is underway to reduce 

CO2 capture costs and to improve performance. The DOE/National Energy 

Technology Laboratory (NETL) sponsors an extensive research,

development and demonstration program that is focused on developing 

advanced technology options that will dramatically lower the cost of 

 

54 Mandatory Reporting of Greenhouse Gases: Injection and Geologic 

Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 (Dec. 1, 

2010).

55 Hazardous Waste Management System: Identification and Listing of 

Hazardous Waste: Carbon Dioxide (CO2) Streams in Geologic 

Sequestration Activities, Proposed Rule, 76 FR 48073 (Aug. 8, 2011).
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capturing CO2 from fossil-fuel energy plants compared to today’s 

available capture technologies. The DOE/NETL estimates that using 

today’s commercially available CCS technologies would add around 80 

percent to the cost of electricity for a new pulverized coal (PC) 

plant, and around 35 percent to the cost of electricity for a new 

advanced gasification-based (IGCC) plant. The CCS research,

development and demonstration program is aggressively pursuing 

efforts to reduce these costs to a less than 30 percent increase in 

the cost of electricity for PC power plants and a less than 10 

percent increase in the cost of electricity for new gasificationbased power plants.56 The large-scale CO2 capture demonstrations that 

are currently planned and in some cases underway, under DOE’s 

initiatives, as well as other domestic and international projects, 

will generate operational knowledge and enable continued

commercialization and deployment of these technologies.

Gas absorption processes using chemical solvents, such as 

amines, to separate CO2 from other gases have been in use since the 

1930s in the natural gas industry and to produce food and chemical 

grade CO2. The advancement of amine-based solvents is an example of 

technology development that has improved the cost and performance of 

 

56 DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, U.S. 

Department of Energy National Energy Technology Laboratory, December 

2010.
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CO2 capture. Most single component amine systems are not practical in 

a flue gas environment as the amine will rapidly degrade in the 

presence of oxygen and other contaminants. The Fluor Econamine FG 

process uses a monoethanolamine (MEA) formulation specially designed 

to recover CO2 and contains a corrosion inhibitor that allows the use 

of less expensive, conventional materials of construction. Other 

commercially available processes use sterically hindered amine 

formulations (for example, the Mitsubishi Heavy Industries KS-1 

solvent) which are less susceptible to degradation and corrosion 

issues. The DOE/NETL and private industry are continuing to sponsor 

research on advanced solvents (including new classes of amines) to 

improve the CO2 capture performance and reduce costs.

Significant reductions in the cost of CO2 capture would be 

consistent with overall experience with the cost of pollution control 

technology. A significant body of literature suggests that the perunit cost of producing or using a given technology declines as 

experience with that technology increases over time,57 and this has 

 

57 These studies include John M. Dutton and Annie Thomas, "Treating 

Progress Functions as a Managerial Opportunity," 2, 235-247; Dennis 

Epple, Linda Argote, and Rukmini Devadas, "Organizational Learning 

Curves: A Method for Investigating Intra-plant Transfer of Knowledge 

Acquired Through Learning by Doing," Organizational Science, Vol. 2, 

No. 1, February 1991; International Energy Agency, Experience Curves 

for Energy Technology Policy, 2000; and Paul L. Joskow and Nancy L. 

Rose, "The Effects of Technological Change, Experience, and 
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certainly been the case with air pollution control technologies. 

Reductions in the cost of air pollution control technologies as a 

result of learning-by-doing, research and development investments, 

and other factors have been observed over the decades. 

We expect that the costs of capture technology will follow this 

pattern. Rubin et al. assessed the historical rates of cost 

reductions achieved by other energy and environmental process 

technologies and then, by analogy, estimated future cost reductions 

that might be achieved by four types of new power plants employing CO2

capture58. The results of the study suggested that total costs of CO2

capture can be expected to decline by the following percentages: NGCC 

by 40 percent, PC by 26 percent, IGCC by 13 percent, and Oxyfuel by 

13 percent after installation of the first 100 GW of capacity.

In a subsequent study, the model used in the initial study was 

extended with learning curves for several key performance variables, 

including overall energy loss in power plants, the energy required 

for CO2 capture, the CO2 capture ratio (removal efficiency) and the 

 

Environmental Regulation on the Construction Cost of Coal-Burning 

Generating Units," RAND Journal of Economics, Vol. 16,Issue 1, 1-27, 

1985. See discussion in “The Benefits and Costs of the Clean Air Act 

from 1990 to 2020,” U.S. EPA, Office of Air and Radiation, April 

2011.

58 Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison, J.; “Use 

of experience curves to estimate the future cost of power plants with 

CO2 capture”, Intl. J. of Greenhouse Gas Control, 1, 188 (2007).
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power plant availability. The model predicted continued reductions in 

cost with increased implementation.59

In addition, we note that the Administration’s CCS Task Force 

report recognized that CCS would not become more widely available 

without the advent of a regulatory framework that promoted CCS or a 

strong price signal for CO2. Today’s action is an important component 

in developing that framework.

(3) Limited amount of construction of new coal-fired power plants; 

opportunities for CCS funding. A third factor that supports CCS as a 

feasible technology option is that through the IPM model period of up 

to 2020, we expect few, if any, new builds of coal-fired EGUs, beyond 

those that already have approved PSD permits. We also expect 

continued opportunities for financial support for some CCS projects 

through a variety of potential mechanisms such as direct grants, tax 

incentives and/or regulatory programs (e.g. Clean Energy Standards or

guaranteed electricity purchase price agreements)60. Accordingly, the 

few new coal-fired generation projects that may occur over this 

timeframe may well find that financial support for CCS is available.

 

59 Van den Broek, M.; Hoefnagels, R.; Rubin, E.; Turkenburg, W.; 

Faaij, A.; “Effects of technological learning on future cost and 

performance of power plants with CO2 capture”, Progress in Energy and 

Combustion Science 35 (2009) 457-480.

60 See Center for Climate and Energy Solutions, “Financial Incentives 

for CCS” -

http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=8380.
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(4) State Requirements for CCS; Projects and Permits for CCS. Several 

states have recently established requirements that new coal-fired 

EGUs must implement CCS, and a number of projects with CCS have been 

approved and/or are under construction.

In May 2007, Montana Governor Schweitzer signed House Bill 25, 

adopting a CO2 emissions performance standard for electric generating 

units in the state. House Bill 25 prohibits the state Public Utility 

Commission from approving new electric generating units primarily 

fueled by coal unless a minimum of 50 percent of the CO2 produced by 

the facility is captured and sequestered.

On January 12, 2009, Illinois Governor Blagojevich signed Senate 

Bill 1987, the Clean Coal Portfolio Standard Law. The legislation 

establishes emission standards for new power plants that use coal as 

their primary feedstock. From 2009-2015, new coal-fueled power plants 

must capture and store 50 percent of the carbon emissions that the 

facility would otherwise emit; from 2016-2017, 70 percent must be 

captured and stored; and after 2017, 90 percent must be captured and 

stored. 

The following is a brief summary of currently operating or 

planned CO2 capture or storage systems, including, in some cases, 

components necessary for coal-based power plant CCS applications.

AES’s coal-fired Warrior Run (Cumberland, MD) and Shady Point 
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(Panama, OK) power plants are equipped with amine scrubbers developed 

by ABB/Lummus. They were designed to process a relatively small 

percentage of each plant’s flue gas. At Warrior Run, approximately 

110,000 tonnes of CO2 per year are captured, whereas at Shady Point 

66,000 tonnes of CO2 per year are captured. The CO2 from both plants 

is subsequently used in the food processing industry61.

At the Searles Valley Minerals soda ash plant in Trona, CA, 

approximately 270,000 tonnes of CO2 per year are captured from the 

flue gas of a coal power plant via amine scrubbing and used for the 

carbonation of brine in the process of producing soda ash.62

A pre-combustion Rectisol® system is used for CO2 capture at the 

Dakota Gasification Company’s synthetic natural gas production plant 

located in North Dakota, which is designed to remove approximately 

1.6 million tonnes of CO2 per year from the synthesis gas. The CO2 is 

purified, transported via a 200-mile pipeline, and injected into the 

Weyburn oilfield in Saskatchewan, Canada. 

In September 2009, American Electric Power Co. (AEP) began a 

pilot-scale CCS demonstration at its Mountaineer Plant in New Haven, 

WV. The Mountaineer Plant is a 1,300 MWe coal-fired unit that was 

 

61 Dooley, J. J., et al. (2009). An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage Technologies as of 

June 2009. U.S. DOE, Pacific Northwest National Laboratory, under 

Contract DE-AC05-76RL01830.

62 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.
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retrofitted with Alstom’s patented chilled ammonia CO2 capture 

technology on a 20 MWe portion, or “slipstream”, of the plant’s 

exhaust flue gas. In May 2011, Alstom Power announced the successful 

operation of the chilled-ammonia CCS validation project. The AEPAlstom project, the world’s first facility to both capture and store 

CO2 from a coal-fired power plant, represents a successful scale-up of 

ten times the size of previous field pilots (e.g., at We Energies 

Pleasant Prairie). The demonstration achieved capture rates from 75 

percent (design value) to as high as 90 percent, produced CO2 at 

purity of greater than 99 percent, with energy penalties within a few 

percent of predictions. The facility reported robust steady-state 

operation during all modes of power plant operation including load 

changes, and saw an availability of the CCS system of greater than 90 

percent. 

AEP, with assistance from the DOE, had planned to expand the 

slipstream demonstration to a commercial scale, fully integrated 

demonstration at the Mountaineer facility. The commercial-scale 

system was designed to capture at least 90 percent of the CO2 from 235 

MW of the plant's 1,300 MW total capacity. Plans were for the project 

to be completed in four phases, with the system to begin commercial 

operation in 2015. However, in July 2011, AEP announced that it is 

terminating its cooperative agreement with the DOE and placing its 
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plans to advance CO2 capture and storage technology to commercial 

scale on hold, citing the current uncertain status of U.S. climate 

policy and the continued weak economy as contributors to the 

decision.

Oxy-combustion of coal is being demonstrated in a 10 MWe 

facility in Germany. The Vattenfall plant in eastern Germany 

(Schwarze Pumpe) has been operating since September 2008. It is 

designed to capture 70,000 tonnes of CO2 per year 

In June 2011, Mitsubishi Heavy Industries, an equipment 

manufacturer, announced the successful launch of operations at a 25 

MW coal-fired carbon capture facility at Southern Company's Alabama 

Power Plant Barry. The demonstration is planned to capture 

approximately 150,000 tons of CO2 annually at a CO2 capture rate of 

over 90 percent. The captured CO2 will be permanently stored 

underground in a deep saline geologic formation. 

Southern Company has begun construction of Mississippi Power 

Plant Ratcliffe (formerly the Kemper County IGCC Project). Plant 

Ratcliffe is a 582 MW IGCC plant that will utilize local Mississippi 

lignite and include pre-combustion carbon capture to reduce CO2

emissions by 65 percent. Operation is expected to begin in 2014. The 

CO2 captured from Plant Ratcliffe will be used for enhanced oil 

recovery (EOR) in the Heidelberg Oil Fields in Jasper County, MS.
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The Texas Clean Energy Project, a 400 MW IGCC facility located 

near Odessa, TX will capture 90 percent of its CO2, which is 

approximately 3 million tonnes annually. The captured CO2 will be used 

for EOR in the West Texas Permian Basin. (Additionally, the plant 

will produce urea and smaller quantities of commercial-grade sulfuric 

acid, argon, and inert slag, all of which will also be marketed.) 

Construction is expected to begin in 2012.

d. Legal Justification for the Standard of Performance and 30-year 

Averaging Compliance Option. This section describes our legal 

justification for proposing that new affected facilities in the TTTT 

category –- which combines the Da and part of the KKKK categories –-

(i) must limit their CO2 emissions to 1,000 lb CO2/MWh, which an 

affected facility could achieve by constructing a NGCC unit or by 

constructing a coal-fired boiler that implements CCS immediately; or 

(ii) in the case of a coal- or pet coke-fired power plant, may either 

meet the 1,000 lb CO2/MWh standard or implement an 30-year averaging 

compliance option that allows an affected facility to meet an initial 

CO2 emission limit of 1,800 lb CO2/MWh (gross), and then –- through 

the implementation of CCS -- meet the 1,000 lb CO2/MWh standard, on a 

time-averaged basis, over no longer than a 30-year period. 

(1) Legal Justification for the Standard of Performance. The EPA 

proposes that the emission limit of 1,000 lb CO2/MWh meets the 
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requirements for a “standard of performance” applicable to new 

sources under CAA section 111(b)(1)(B). The term “standard of 

performance” is defined under CAA section 111(a)(1) as follows:

Definitions. For purposes of this section: (1) The term 

“standard of performance” means a standard for emissions of 

air pollutants which reflects the degree of emission 

limitation achievable through the application of the best 

system of emission reduction which (taking into account the 

cost of achieving such reduction and any nonair quality 

health and environmental impact and energy requirements) 

the Administrator determines has been adequately 

demonstrated.

We apply this definition, in effect, from the bottom up. That 

is, first, we determine the “best system of emission reduction which 

(taking into account * * * cost [and other factors]) the 

Administrator determines has been adequately demonstrated.” For EGUs, 

that is a NGCC facility, for reasons discussed below. Then, we 

calculate the “degree of emission limitation achievable through the 

application of” such best system; and after that, we formulate “a 

standard for emissions of air pollutants which reflects” that degree 

of emission limitation. This standard is 1,000 lb of CO2/MWh. These 

analytical steps are also discussed further below.

In determining the “best system of emission reduction” for this 

category of boilers and combined cycle units, we considered a range 

of natural gas-fired and coal-fired generation technologies, with 

available controls. We considered modern supercritical and ultra-
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supercritical coal-fired boilers. This technology is available –- it 

is currently deployed in Europe and is now being widely deployed in 

Asia (especially China) –- and it offers much more efficient 

operation than the subcritical boilers that have more often been 

constructed in the U.S. These supercritical and ultra-supercritical 

boilers have CO2 emissions of approximately 1,800 lb/MWh and provide 

the lowest overall costs for conventional coal-based electricity. We 

also considered new IGCC, or “coal gasification” facilities, which 

can have CO2 emissions levels very similar to those of ultrasupercritical coal-fired units –– albeit at a higher price.

We also considered natural gas-fired boilers which have CO2

emissions of approximately 1,350 lb/MWh, obviously much lower than 

the advanced coal-fired or coal gasification technologies. However, 

it seems unlikely that utilities would choose a natural gas-fired 

boiler as the generation technology of choice when NGCC is a much 

more efficient, less expensive, and more widely used technology. 

We propose that a NGCC facility is the best system of emission 

reduction for two main reasons. First, natural gas is far less 

polluting than coal. Combustion of natural gas emits only about 50 

percent of the CO2 emissions that combustion of coal does per unit of 

energy generated. Second, new natural gas-fired EGUs are less costly 

than new coal-fired EGUs, and as a result, our IPM model projects 
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that for economic reasons, natural gas-fired EGUs will be the 

facilities of choice until at least 2020, which is the analysis

period. Indeed, those models do not project construction of any new 

coal-fired EGUs during that period that would not comply with the 

proposed standard. This state of affairs has come about primarily 

because technological development and discoveries of abundant 

reserves have caused natural gas prices to decline precipitously in 

recent years and have secured those relatively low prices for the 

near-future. Importantly, because the IPM modeling shows that natural 

gas-fired plants are the facilities of choice, the proposed standard 

of performance in today’s rulemaking –– which is based on the 

emission rate of a new NGCC unit –– does not add costs. In addition, 

compared to coal-fired EGUs, natural gas-fired EGUs have fewer nonair

quality health and environmental impacts.

Essentially because natural gas generation is cleaner and 

cheaper than coal, natural gas-fired EGUs qualify as the “best system 

of emission reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health and 

environmental impact and energy requirements) the Administrator 

determines has been adequately demonstrated.”

We recognize that today’s proposed approach of combining the Da 

category and a portion of the KKKK category, and applying as the 
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standard of performance the rate that natural gas-fired EGUs can 

meet, represents a departure from prior agency practice. We consider 

this departure warranted in light of both the emissions benefits and 

the changed economic circumstances, notably the lowered prices of 

natural gas due to technological development and recent discoveries 

that have boosted recoverable reserves. We are aware that in theory, 

those economic circumstances could change and if they do, then a 

change in the standard of performance may be warranted. In this 

regard, we note that CAA section 111(b)(1)(B) requires that the EPA 

“shall, at least every 8 years, review and, if appropriate, revise 

[the] standards [of performance].” This 8-year review cycle provides 

a mechanism for the EPA to assure that the standard of performance 

for any particular source category continues to reflect the “best 

system.” 

(2) Legal Justification for the 30-year Averaging Compliance Option.

Although the IPM model projects that for economic reasons, new coalor pet coke-fired EGUs will not be built in the foreseeable future

(beyond early CCS projects), we recognize that in a few instances, 

owners or operators may in fact seek to build coal- or pet coke-fired 

EGUs. As discussed in detail below, those owners or operators could 

avail themselves of CCS as a 30-year averaging compliance option. In 

addition, today’s proposed rulemaking offers flexibility for CCS 
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installation: The owners or operators could (i) achieve the 

supercritical efficiency level for an initial period (e.g., up to the 

first 10 years), and (ii) after that, implement CCS so as to achieve 

a 600 lb CO2/MWh rate on a 12-month annual average during the latter 

period (i.e., the back 20 years) and thereby achieve the 1,000 lb 

CO2/MWh rate on an average annual basis over the 30-year period. The 

alternative compliance option could also allow them to install and 

operate CCS much earlier and use the 10 year period to address any 

startup challenges related to being an early adopter of the 

technology.

Because CO2 is long-lived in the atmosphere, the 30-year 

averaging period, as structured, with shorter term compliance 

requirements, is not expected to have a different impact on climate 

compared to meeting the standard of performance. 

(a) CCS. The significance of CCS as a compliance alternative is 

several-fold. As a practical matter, it offers a vehicle for the 

construction of new coal- fired EGUs in those few instances in which 

owners or operators decide to construct such EGUs, notwithstanding 

the underlying economics. Also, it offers a vehicle for the continued 

scaling of CCS, a process that can be expected to lower the costs of 

CCS in the future. In addition, this compliance alternative provides 

further support for the reasonableness of the EPA’s proposals in this 
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rulemaking to combine the Da category and a portion of the KKKK 

category and to determine that a NGCC facility is the “best system of 

emission reduction.” This is because this compliance alternative, by 

providing a vehicle for new coal-fired power plant builds, would 

minimize any disruptions that the EPA’s proposals might, at least in 

theory, otherwise entail to the power plant industry. 

CCS as a compliance alternative does not achieve these goals by 

necessarily qualifying, under the CAA section 111(a)(1) definition of 

“standard of performance,” as the “best system of emission reduction 

which (taking into account cost [and other factors]) the 

Administrator determines has been adequately demonstrated.” Instead, 

this compliance alternative is feasible and sufficiently available 

for the limited amount of new coal-fired construction that is 

expected, whether or not it would qualify as the “best system.”

First, it is reasonable to expect that some coal-fired power 

plants may be able to implement CCS at the present time, and thereby 

achieve the 1,000 lb CO2/MWh standard immediately. As noted elsewhere, 

CCS has been demonstrated to be technologically achievable, and, even 

though it is costly, there are some state and Federal subsidy 

programs that can make CCS more affordable, particularly in tandem 

with use of captured CO2 for enhanced oil recovery, and those programs 

may be sufficient for the very few new coal-fired plants that are 
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expected to be constructed in the foreseeable future. Some of these 

programs are discussed above.

We note that the need for governmental subsidies to reduce the 

costs of CCS is hardly unique in the electricity generation sector. 

Each of the major types of energy used to generate electricity has 

been or is currently supported by some type of government subsidy --

such as tax benefits, loan guarantees, low-cost leases, or direct 

expenditures -- for some aspect of development and utilization, 

ranging from exploration to control installation. This is true of

fossil fuel-fired; as well as nuclear-, geothermal, wind-, and solargenerated electricity. These subsidies have been designed to overcome 

cost barriers to the utilization of the energy. In this context, the 

need for subsidies for CCS to overcome cost barriers does not mean 

that CCS cannot be considered an alternative compliance method in 

this rulemaking. 

Second, it is reasonable to expect that some coal-fired power 

plants may be able to implement the supercritical efficiency standard 

for an initial period of time (the first 10 years) and then implement 

CCS and achieve lower 12-month annual average rates after that, so 

that the source achieves the 1,000 lb CO2/MWh standard on average over 
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the 30-year period following construction. 63 This is because, again, 

CCS is feasible and can be expected to be sufficiently available – in 

light of continued subsidies and lower future costs – in light of the 

limited demand. 

Third, although we do not propose that the 30-year averaging 

compliance option meets the definition of the “best system of 

emission reduction [(BSER)] ... adequately demonstrated,” under CAA 

section 111, we note that identifying CCS as a compliance option 

based in part on the expectation that CCS will cost less in the 

future is consistent with the section 111 requirements for 

determining the BSER adequately demonstrated. In determining what 

emissions controls qualify as the BSER adequately demonstrated –

which must take costs into account – the EPA is authorized under CAA 

section 111 to anticipate that technology that is costly at present 

will come down in price in the future. It is clear from the 

legislative history of section 111 and relevant case law that the EPA 

may anticipate future developments –- as long as supported by an 

adequate record –- in determining whether a particular system of 

emission reduction is the BSER adequately demonstrated. The Senate 

 

63 Note that under today’s proposed rulemaking, the 30-year averaging 

proposal is associated only with the implementation of CCS at new 

coal- or pet coke-fired EGUs. This proposal does not allow 30-year 

averaging for any other purpose.
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Committee Report to the 1970 CAA Amendments, which first enacted CAA 

section 111, made clear that the EPA may anticipate future 

developments in determining the BSER adequately demonstrated:

As used in this section, the term “available control 

technology” is intended to mean that the Secretary should 

examine the degree of emission control that has been or can 

be achieved through the application of technology which is 

available or normally can be made available. This does not 

mean that the technology must be in actual, routine use 

somewhere. It does mean that the technology must be 

available at a cost and at a time which the Secretary 

determines to be reasonable. The implicit consideration of 

economic factors in determining whether technology is 

“available” should not affect the usefulness of this 

section. The overriding purpose of this section would be to 

prevent new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the most 

effective and, in the long run, the least expensive 

approach. 

Sen. Rep. 91-1196 at 16 (emphasis added). As quoted, this statement 

makes clear that a standard of performance may be based on a 

technology that is not “in actual routine use somewhere,” but that 

“normally can be made available.” Moreover, the technology need not 

be available until “a time which the Secretary determines to be 

reasonable.” Id.

In addition, the D.C. Circuit has been explicit that in setting 

a CAA section 111 standard of performance, the EPA may make 

reasonable projections of what technology will be available to the 
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regulated industry in the future. The Court stated, in Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):

We begin by rejecting the suggestion of the cement 

manufacturers that the Act's requirement that emission 

limitations be "adequately demonstrated" necessarily 

implies that any cement plant now in existence be able to 

meet the proposed standards. Section 111 looks toward what 

may fairly be projected for the regulated future, rather 

than the state of the art at present, since it is addressed 

to standards for new plants -- old stationary source 

pollution being controlled through other regulatory 

authority. It is the "achievability" of the proposed 

standard that is in issue. * * * 

The * * * standard is analogous to the one examined in 

International Harvester * * *. The Administrator may make a 

projection based on existing technology, though that 

projection is subject to the restraints of reasonableness 

and cannot be based on "crystal ball" inquiry.

64

Id. at 391 (emphasis added). Again, although these statements in the 

legislative history and case law are in the context of establishing 

the basis for a standard of performance, the same principle –- that 

the EPA may reasonably project the path of technological development 

–- supports treating CCS as a compliance alternative.

Although, for the reasons noted above, we do expect the costs of 

CCS to decline, we recognize that the amount of the decrease is 

uncertain. Even so, the presence of cost uncertainty by itself does 

not mean that prospective power plants cannot be expected to adopt 

 
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the 30-year averaging compliance option. We note that prospective 

power plants face significant cost uncertainties in any event. 

For example we note that recently, several owner/operators have 

announced that they do not intend to construct coal-fired power 

plants without CCS. They have explained that they anticipate more 

widespread CO2 control requirements in the future, so that 

constructing coal-fired plants at this time without CCS could leave 

them subject to liability for high retrofit control costs in the 

future. This sentiment indicates that some sources may avail 

themselves of the 30-year averaging compliance option.

The inclusion of a 30-year averaging compliance option has 

precedent in EPA rulemaking under the CAA. In the past, the EPA has 

promulgated rules that adopt an emission limit based on a particular 

technology (such as, in the present rulemaking, NGCC), but has 

supported that action on grounds that sources have compliance 

alternatives, even though higher priced. See “Finding of Significant 

Contribution and Rulemaking for Certain States in the Ozone Transport 

Assessment Group Region for Purposes of Reducing Regional Transport 

of Ozone: Final Rule” 63 FR 57356, 57378 (Oct. 27, 1998) (in the 

rule that became known as the “NOx SIP Call,” the EPA based NOx 

emission limits that states were required to meet on the assumption 

that states could adopt specified control measures that were “highly 
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cost-effective,” but the EPA identified other control measures that, 

even though not as cost-effective, the states could adopt instead).

(b) 30-year Period. We propose a 30-year period because (i) we 

generally expect that ten years provides sufficient time either for 

owners/operators who are interested in considering cost improvements 

that occur as a result of the lessons learned from early adopters, or 

provides early adopters sufficient time to address any startup 

challenges; and (ii) as noted above, 30 years provides enough time 

for sources to achieve the 1,000 lb CO2/MWh emission limit following 

an elevated level of emissions over the first 10-year period.

(c) Supercritical Efficiency Level. According to the Depart of Energy 

Cost and Performance Baseline for Fossil Energy Plants reports, the 

use of supercritical steam is the most cost effective option for new 

conventional coal-fired generation and results in the lowest overall 

costs. In addition, the increased efficiency results in reduced 

cooling water requirements and reduced environmental impacts

associated with coal mining, delivery, and handling. Furthermore, 

climate change impacts result from the cumulative amount of emissions 

so reduced near term emissions provide additional benefits. 

Therefore, considering the benefits and minimal, if any, cost of 

using supercritical steam conditions, as opposed to subcritical steam 
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conditions, we have concluded that an annual standard based on the 

best performing conventional coal-fired generation is appropriate. 

There are a dozen bituminous-fired and 2 subbituminous-fired

EGUs that have demonstrated the proposed annual standard is 

achievable on a long term basis. Furthermore, we have concluded that 

with coal drying technology, which is being used on a number of power 

plants today, the annual standard is achievable by a wide range of 

units firing a variety of coal types, including lignites. There are 

multiple vendors that offer processes to upgrade lignites to heating 

values that are equal to or greater than those of subbituminous 

coals. The best performing subbituminous-fired EGU has maintained a 

12-month emissions rate of 1,730 lb CO2/MWh. A new EGU using a similar 

design would be able to burn upgraded lignite and be in compliance 

with the proposed annual standard.

We solicit comment on all aspects of the alternative compliance 

option, including the 30-year averaging period we propose in this 

action. Although we are not proposing that CCS, including the 30-year 

averaging compliance option, does or does not qualify as the BSER 

adequately demonstrated, we also solicit comment on that issue.

B. How did the EPA determine the other requirements for the proposed 

standards?

1. Compliance Requirements
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The proposed compliance requirements, to the extent possible, 

incorporate monitoring already being performed as part of existing 

part 60 and part 75 requirements. 

In addition, we intend to recognize the environmental benefit of 

electricity generated by CHP facilities to account for the increased 

end use efficiency resulting from avoided transmission and 

distribution losses. Actual line losses vary from location to 

location, but we intend to assume a benefit of 5 percent avoided 

transmission and distribution losses when determining the electric 

output for CHP facilities. This provision would be restricted to 

facilities where the useful thermal output is at least 20 percent of 

the total output. 

We also propose to base compliance requirements on a 12-month 

rolling average basis. The variability in GHG emissions rates is such 

that establishing a shorter averaging period would necessitate 

establishing a standard to account for the conditions that result in 

the lowest efficiency and therefore the highest GHG emissions rate. A 

12-month rolling average accounts for variable operating conditions, 

allows consistent emissions rate averaging, allows for a more 

protective standard and decreased compliance burden, and simplifies 

compliance for state permitting authorities. Because the 12-month 

rolling average can be calculated each month, this form of standard 
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makes it possible to assess compliance and take any needed corrective 

action on a monthly basis. The EPA proposes that it is not necessary 

to have a shorter averaging period for CO2 from these sources because 

the effect of GHGs on climate change depends on global atmospheric 

concentrations which are dependent on cumulative total emissions over 

time, rather than hourly or daily emissions fluctuations or local 

pollutant concentrations.

Even so, we solicit comment on, in the alternative basing 

compliance requirements on an annual (calendar year) average basis.

V. Requirements for Modifications, Transitional Sources, 

Reconstructions

A. Requirements for Modifications

1. Overview

Under CAA section 111, existing sources are treated as new 

sources if they undertake “modification[s],” which are generally 

defined as physical or operational changes that increase emissions. 

CAA section 111(a)(2) and (4). The EPA’s regulations exempt certain 

types of changes from the definition of modification. 40 CFR 

60.14(e). Available information does not provide an adequate basis 

for the EPA to develop proposed standards of performance for 

modifications. That is because the types of projects that these EGUs 

are most likely to undertake that could increase GHG emissions are 
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projects that put on pollution controls required under other CAA 

provisions and that emit CO2 as a byproduct, and those types of 

projects are specifically exempted from the definition of 

“modifications” under 40 CFR 60.14(e)(5). In contrast, based on past 

experience, we expect no more than a relatively small number of 

actions that do constitute modifications, and we expect them to be 

from different types of sources and to take different forms. In light 

of this, the EPA does not have sufficient information to develop 

standards of performance for modifications, and therefore the EPA is 

not proposing any standards for modifications. As a result, EGUs that 

undertake pollution control projects or other physical or operational 

changes would continue to be treated as existing sources.

2. Statutory and Regulatory Requirements

Clean Air Act section 111(b)(1)(B) requires the EPA to 

promulgate “standards of performance” for “new sources” within source 

categories. For certain pollutants, CAA section 111(d)(1) requires 

the EPA to prescribe regulations for state plans covering “existing 

source[s]” in a category regulated for that pollutant under section 

111(b). Clean Air Act section 111(a)(2) defines a “new source” as 

“any stationary source, the construction or modification of which is 

commenced after the publication of regulations (or, if earlier, 

proposed regulations) prescribing a standard of performance under 
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this section which will be applicable to such source.” Clean Air Act 

section 111(a)(6)defines an “existing source” as “any stationary 

source other than a new source.” Clean Air Act section 111(a)(4) 

defines “modification” as “any physical change in, or change in the 

method of operation of, a stationary source which increases the 

amount of any air pollutant emitted by such source or which results 

in the emission of any air pollutant not previously emitted.” 

The EPA’s regulations provide that under CAA section 111(a)(4), 

for purposes of determining whether an existing electric utility 

steam generating unit undertakes a modification, a physical or 

operational change is treated as increasing emissions only when it 

increases the “maximum hourly emissions” above the “maximum hourly 

emissions achievable” at the unit. 40 CFR 60.14(h). In addition, the 

EPA’s regulations exempt certain physical or operational changes from 

the definition of modification. 40 CFR 60.14(e)(5). The exemptions 

include pollution control projects: 

(e) The following shall not, by themselves, be 

considered modifications ...:

...

(5) The addition or use of any system or device whose 

primary function is the reduction of air pollutants, except 

when an emission control system is removed or is replaced 

by a system which the Administrator determines to be less 

environmentally beneficial.

40 CFR 60.14(e)(5). Thus, the EPA’s current regulations define a 
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modification as a physical or operational change that increases an 

existing affected EGU’s maximum achievable hourly rate of emissions, 

but specifically exempt from that definition pollution control 

projects, which are projects that entail the installation of 

pollution control equipment or systems.

3. The EPA’s Proposed Course of Action

We expect EGUs to undertake changes in the foreseeable future 

that would increase their maximum achievable hourly rate of CO2

emissions. We expect that the most of those actions would constitute 

pollution control projects. In many cases, those projects would

involve the installation of add-on control equipment required to meet 

CAA requirements for conventional air pollutants. We expect that 

these increases in CO2 emissions would occur as a chemical byproduct 

of the operation of the control equipment, and would be small. In 

other cases, those projects will involve equipment changes to meet 

the requirements of this rulemaking and that may have the effect of 

increasing the sources’ maximum hourly achievable emission rate, even 

while decreasing actual emission rate. Because such actions would be 

treated as pollution control projects under the EPA’s current NSPS 

regulations, they would be specifically exempted from the definition 

of modification.
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Aside from pollution control projects, in the past, there have 

also been a small number of instances, on an annual basis, in which 

power plants have undertaken actions that, in the EPA’s view, should 

be treated as modifications. The sources that took these actions vary 

widely, one from another, depending on, among other things, size, 

fuel type, and physical plant configuration. The diversity of sources 

undertaking modifications has reflected the diversity among power 

plants as a whole. Moreover, the types of modifications they have 

undertaken have also varied widely. 

Because of the small number of modifications, their disparate 

nature, and the disparate type of sources, we do not at present have 

an adequate base of information to propose standards of performance 

for modifications. For example, we do not have adequate information 

as to the types of physical or operational changes sources may 

undertake or the amount of increase in CO2 emissions from those 

changes. Nor do we have adequate information as to the types of 

control actions sources could take to reduce emissions, including the 

types of controls that may be available or the cost or effectiveness 

of those controls. The most likely candidates for control actions 

would be efficiency measures and we do not have adequate information 

as to the types of sources and types of changes at issue that could 

provide the basis for a proposal for efficiency measures. If a larger 
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number of facilities of a particular type had undertaken

modifications of a particular kind, the EPA may be able to develop a 

standard of performance for that type. But, as noted, that is not the 

case here.

As a result, in this action, the EPA is not proposing standards 

of performance for modifications. The EPA is soliciting comment on 

the types of sources that may be expected to undertake modifications, 

the types of modifications, the types of control measures, and all 

other aspects of this issue. This solicitation of comment is in the 

nature of an advance notice of proposed rulemaking. If we receive 

sufficient additional information, we may issue a proposal for 

modifications in the future. However, to reiterate, we are not 

proposing any standards of performance for these modifications at 

this time. Accordingly, the EPA does not expect to promulgate any 

standards of performance for modifications when it takes final action 

on this rulemaking.

The definitional provisions of CAA section 111, quoted above, 

make clear that a stationary source that undertakes construction or 

modification is considered a “new source” only if there is a proposed 

or final “standard of performance under this section which will be 

applicable to such source.” CAA section 111(a)(2). Accordingly, if 

there is no proposed or promulgated standard of performance 
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applicable to a particular source, then the source cannot be 

considered a “new source” and therefore will not be subject to any 

standards of performance we finalize for new sources. 

Further, under the definitional provisions, any source that is 

not a “new” source is an “existing source.” CAA section 111(a)(6). 

Therefore, affected EGUs that undertake modifications will continue 

to be treated as existing sources. Although modified sources would 

not be subject to the 1000 lb CO2/MWh standard for new sources, the 

EPA anticipates that modified sources would become subject to the 

requirements the EPA would promulgate at the appropriate time, for 

existing sources under 111(d). It is important to note that at the 

same time that the EPA promulgated the pollution control provision in 

EPA’s regulations under CAA section 111, the EPA promulgated a 

similar provision in EPA’s NSR regulations. The D.C. Circuit, in New 

York v. EPA, 413 F.3d 3, 40 (D.C. Cir. 2005), vacated the NSR 

pollution-control-project exemption. Because of the similarities 

between the NSR and the section 111 pollution control project 

regulatory provisions, the Court’s vacatur of the NSR regulatory 

provision may call into question the continued validity of the 

section 111 regulatory provision. As a result, we are soliciting 

comment on whether this exemption from the definition of 

“modification” for pollution control projects, under 40 CFR 
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60.14(e)(5), continues to be valid or not, and what course of action, 

if any, would be appropriate for the EPA to take.

B. Requirements for Transitional Sources

1. Overview

In this action, EPA is not proposing a standard of performance 

for transitional sources. We define these sources as coal-fired power 

plants that, by the date of this proposal, have received approval for 

their PSD preconstruction permits that meet CAA PSD requirements (or 

that have approved PSD permits that expired and are in the process of 

being extended, if those sources are participating in a Department of 

Energy CCS funding program), and that commence construction within a 

year of the date of this proposal. For convenience, we refer to the 

new sources for which we are proposing a standard of performance as 

non-transitional sources. 

Transitional sources are a distinct set of sources with unique 

circumstances. We have identified 15 proposed sources that may 

qualify as transitional sources based on the above criteria. These 

proposed sources differ considerably one from another. They range in 

size from as small as 80 megawatts (MW) to as large as 1320 MWs; they

will burn different fuels: conventional coal, waste coal, or petcoke; 

and they will use different technologies: circulating fluidized bed 
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(CFB), integrated gasification combined cycle (IGCC), supercritical 

pulverized coal, or sub-critical pulverized coal. 

Recent industry practice raises the probability that no more than a 

few of these 15 proposed sources will in fact be constructed. 

We recognize that by the date of this proposal, some of the 15 

proposed sources may have incurred substantial sunk costs and may 

have progressed in their preconstruction planning to the point where 

they are poised to commence construction in the very near future. 

Under these circumstances, the 1,000 lb CO2/MWh standard of 

performance that applies to non-transitional sources would not be 

appropriate for these proposed sources. As noted, that standard is 

based on natural gas combined cycle (NGCC) as the “best system of 

emission reduction ... adequately demonstrated” because NGCC is the 

least expensive and lowest emitting design for a fossil-fuel fired 

power plant, and because a proposed new source may choose to 

construct as a NGCC facility. However, proposed coal-fired power 

plants that have already received a PSD permit and that have incurred 

substantial sunk costs and developed plans to commence construction 

in the very near future are not in the same position as nontransitional sources. Applying the 1,000 lb CO2/MWh standard would 

likely result in the loss of their sunk costs and would likely cause 

multi-year delays, or even abandonment, of their plans to construct. 
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(Nor is the 1,000 lb CO2/MWh standard appropriate for CCS sources, as 

discussed below.) This is not within the scope of BSER.

However, we do not have sufficient information concerning the 15 

proposed sources to identify which ones may be in this position. 

Specifically, we do not have information as to the extent of their 

sunk costs, their preconstruction planning, or their overall business 

plans.

Accordingly, we propose to include a requirement that proposed 

sources must commence construction within 12 months of today’s 

rulemaking proposal as a mechanism for revealing which of these 

sources qualifies as a transitional source. We believe that any of 

these 15 proposed sources that commences construction within 12 

months of today’s rulemaking proposal should be considered to have 

incurred substantial sunk costs and will have engaged in sufficient 

preconstruction planning so that the 1,000 lb CO2/MWh standard should 

not apply. Any of these 15 proposed sources that do not commence 

construction within this period should not be considered to be 

similarly situated. For any of these latter sources that ultimately 

are constructed, the 1,000 lb CO2/MWh standard would apply.

Having identified which proposed sources could qualify as 

transitional sources, we further believe that for several reasons, it 

is not appropriate to propose any standard of performance for those 
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sources. As noted above, we necessarily lack information specifically 

as to which of the 15 proposed sources will actually qualify as 

transitional sources, and, given the range of size, fuel types, and 

technologies among these proposed sources, that renders it 

problematic to propose standards of performance. In addition, for the 

proposed sources that are planning to install CCS, we lack important 

information concerning the extent to which they are planning to 

capture CO2 or their costs to do so. We also lack information as to 

whether they have made contractual arrangements for the sale of the 

CO2 or carbon credits, which may be critical to their financing 

arrangements. In addition, attempting to propose a standard of 

performance would give rise to serious practical problems that would 

undermine the usefulness of the requirement that sources commence 

construction within 12 months of today’s rulemaking proposal as a 

mechanism for revealing which of these sources qualifies as a 

transitional source. These include creating uncertainty as to the 

level of the final standard of performance to which the proposed 

sources would be subject, which may have the effect of forcing them 

to delay commencing construction until after we finalize the 

standards, at which time they would have missed their 12-month window 

to commence construction and as a result, would fail to qualify as 

transitional sources. We note that CAA section 111 does not require 
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that we propose or promulgate standards of performance for all 

sources in a source category, and on numerous occasions in past 

rulemakings EPA has taken the similar approach of not proposing 

standards of performance for all sources in the source category.

Even without an applicable standard of performance, transitional 

sources will remain constrained in their emissions of CO2 by the 

requirements of their PSD permits. In addition,although transitional 

sources would not be subject to the 1000 lb CO2/MWh standard for new 

sources, the EPA anticipates that transitional sources would become 

subject to the requirements the EPA would promulgate at the 

appropriate time, for existing sources under 111(d). 

2. Identification of transitional sources 

For purposes of this action, we define a transitional source as 

a coal-fired power plant that has received approval for its complete 

PSD preconstruction permit by the date of this proposal (or that has 

an approved PSD permit that expired and for which the source is 

seeking an extension, if the source has been issued or awarded a DOE 

CCS loan guarantee or grant) for the project, and that commences

construction within 12 months of the date of this proposal. For this 

purpose, the date of this proposal is the date of publication in the 

Federal Register of this notice of proposed rulemaking. The 12-month 

period would not be extended for any reason, including because of any 
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challenges to the permit that may be brought in any Federal or State 

court or agency.

The EPA is aware of approximately 15 sources that could 

potentially qualify as transitional sources because, except as 

otherwise noted, they have obtained PSD permits but have not yet 

commenced construction. These proposed sources vary considerably one 

from another. They range in size from as small as 80 megawatts (MW) 

to as large as 1320 MWs; they will burn different fuels: conventional 

coal, waste coal, or petcoke; and they will use different 

technologies: circulating fluidized bed (CFB), integrated 

gasification combined cycle (IGCC), supercritical pulverized coal, or 

sub-critical pulverized coal. 

Based on recent industry practice, it appears that no more than 

a few of these sources will be constructed.65 

Of these 15 identified potential transitional sources, six have 

indicated that they plan to install CCS (and in most if not all cases

have been issued or awarded a DOE CCS loan guarantee or grant). These 

six projects are: The Texas Clean Energy Project in Texas, the 

Trailblazer project in Texas, the Taylorville project in Illinois, 

 

65 Since 2008, some 15 proposed coal-fired power plants with approved 

PSD permits have cancelled plans to construct, and since 2009, only 

one coal-fired power plant has constructed (Southern Company’s Kemper 

County Project, which installed CCS and received DOE funding). 
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the Good Spring facility in Pennsylvania, the Power County Advanced 

Energy Center in Idaho and the Cash Creek Generation Plant in 

Kentucky. The remaining nine plants, which are without CCS, are: 

Limestone 3, White Stallion and Coletto Creek in Texas, Holcomb 2 in 

Kansas, James De Young and Wolverine in Michigan, Washington County 

in Georgia, Bonanza in Utah, and Two Elk in Wyoming.66

We request that during the public comment period on this 

rulemaking, each of these EGUs confirm to us that we have correctly 

identified the status of their PSD permits and, in the case of any 

sources that had approved permits that are in the process of being 

extended, and that plan to install CCS, that they have been issued or 

awarded a DOE CCS loan guarantee or grant. We also request that the 

sources indicate whether their permits are undergoing challenges 

before Federal or state authorities or courts. We further request 

that any other EGU not listed above that has a complete PSD permit 

and that otherwise meets the parameters for transitional sources 

described in this section identify itself to us (including indicating 

whether its PSD permit is undergoing challenge before Federal or 

 

66 We note that there may be some proposed natural gas-fired EGUs that 

are similarly situated to the coal-fired transitional sources because 

the natural-gas fired sources have received PSD permits but have not 

commenced construction by the date of this proposal. Because they are 

new gas-fired EGUs, we expect that they will be able to meet the 

requirements of the proposed new source standard of performance. 
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state authorities or courts). In our final rulemaking, we intend to 

include a confirmed list of sources that would qualify as 

transitional sources if they commence construction within the 12-

month period following publication of this proposal in the Federal 

Register.

As commenters have noted, among these 15 proposed sources, some 

may have incurred substantial sunk costs associated with processing 

their permits as well as taking additional preconstruction steps 

(e.g., purchasing land) so that they may be able to commence 

construction within the near term. As examples of these types of 

steps, several sources, such as the Texas Clean Energy Project, have 

signed contracts for the sale of electricity, the sale or disposal of 

CO2 or other enabling products, or supporting systems.

67 Although the 

Taylorville project’s PSD permit has expired, the source is seeking 

to extend it, and the source has entered into CCS funding 

arrangements with DOE. These actions indicate that this proposed 

source, too, has sunk costs and may be in a position to commence 

construction within the near term, and therefore is similarly 

situated to the other 14 proposed plants.

Even so, we face major gaps in our information about these 

sources that would inform us at this point as to which of these 

 

67 http://www.texascleanenergyproject.com/news-room/.
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sources have incurred costs and material commitments to the extent 

that a 1000 lb CO2/MWh standard would be so costly and disruptive as 

not to be BSER. For example, we do not have specific information as 

to those sources’ specific sunk costs, specific project development

actions to date, or overall business plan. Accordingly, we are not 

able to determine which ones are in a position to commence 

construction in the near term. In addition, for the sources whose PSD 

permit indicates that they will install CCS, we do not have specific 

information as to the amount of CO2 that they plan to capture; their 

costs to operate CCS; or their possible revenue streams associated 

with CCS, such as from the sale or use of CO2 in enhanced oil recovery 

or the possible sale of carbon credits in voluntary or other carbon 

markets.

Instead, the 12-month period, serving as a surrogate for the 

missing information, provides a mechanism for revealing the 

qualification of proposed sources for treatment as transitional 

sources. In light of the complex of requirements, which range from 

siting to financing, needed to commence construction of a project as 

large and expensive as a power plant, any proposed source that does 

commence construction within the relatively short period of 12 months 

of the date of proposal can be said to have incurred substantial sunk 

costs and to have taken preconstruction steps by the time of this 
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proposal. It is these sources that would be most disadvantaged by 

being subjected to the standards of performance proposed in today’s 

rulemaking. The one-year period serves as a type of surrogate for a 

more precise information as to the amount of sunk costs sources must 

incur or steps leading to commencement of construction that sources 

must undertake in order to qualify as transitional sources, as well 

as which sources have incurred those costs or taken those steps, 

which information is not available at this time. In addition, 12 

months is long enough to give these sources a reasonable period to 

commence construction in accordance with the terms of their permit. 

Any proposed source that does not commence construction within 12 

months cannot be said to be similarly situated.

3. EPA’s treatment of transitional sources

In this action, EPA is treating transitional sources as a 

distinct set of sources. We make clear that the proposed standard of 

performance for non-transitional sources of 1,000 lb CO2/MWh is not 

applicable to transitional sources because that standard is not based 

on the BSER adequately demonstrated for transitional sources. In

addition, in light of the unique circumstances of transitional 

sources, including of a lack of information and other considerations, 
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we do not propose any other standard of performance for transitional 

sources.68

Although a transitional source would not be subject to new 

source CO2 emissions controls under CAA section 111(b), it would be 

subject to CO2 emissions limits due to any CO2 limits in the source’s 

PSD permit. If the source received the permit prior to January 2, 

2011, the permit will not include CO2 limits, but in that case, as a 

practical matter, CO2 emissions would be limited by whatever design or 

operating constraints are imposed on the source under the PSD permit. 

We also note that because transitional sources would not be 

subject to any proposed standard of performance, they would not be 

considered “new source[s],” under CAA section 111(a)(2). Instead, 

they would be considered to be “existing source[s],” under section 

111(a)(6). As a result, they would be subject to any requirements 

applicable to existing sources under section 111(d) and related state 

plans.

4. Legal basis for EPA’s treatment of transitional sources

 

68 EPA intends that its treatment of transitional and non-transitional 

sources be severable from each other and considers that severability 

is logical because of the record-based differences between the two 

types of sources and because there is no interdependency in EPA’s 

treatment of the two types of sources. This statement concerning 

severability for these components in this rulemaking should not be 

construed to have implications for whether other components in this 

rulemaking are severable. 
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In this section, we describe the legal basis for our treatment 

of transitional sources. First, we identify the relevant CAA section 

111 provisions. Second, we explain why the standard of performance we 

propose for non-transitional sources does not apply to transitional 

sources, which is because that standard does not reflect the best 

system of emission reduction adequately demonstrated for transitional 

sources. Third, we explain why we are not proposing any other 

standard of performance for transitional sources, which is due to 

lack of information and other considerations. In the course of these 

explanations, we discuss the relevant CAA section 111 requirements 

and our interpretations of them.

a. Key CAA section 111 provisions

As the first step in the process of promulgating regulations 

under section 111, under CAA section 111(b)(1)(A), the Administrator 

must “publish ... a list of categories of stationary sources.” Then, 

the Administrator must “[propose] ... Federal standards of 

performance for new sources within [the source] category,” and then 

“promulgate ... such standards with such modifications as he deems 

appropriate.” Section 111(b)(1)(B). Section 111(b)(2) goes on to 

provide that “[t]he Administrator may distinguish among classes, 

types, and sizes within categories of new sources for the purpose of 

establishing such standards.” 
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Section 111 includes several key definitions. The provision 

defines a “new source” as “any stationary source, the construction or 

modification of which is commenced after the publication of 

regulations (or, if earlier, proposed regulations) prescribing a 

standard of performance under this section which will be applicable 

to such source.” CAA section 111(a)(2).69 A “standard of 

performance” is defined as a –

standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated.

CAA section 111(a)(2). 

Once the Administrator promulgates standards for new sources 

under CAA section 111(b), the States, consistent with EPA regulatory 

requirements, must take action under CAA section 111(d) to establish 

 

69 The CAA does not include a definition of the term “commenced” for 

these purposes, but the EPA framework regulations promulgated under 

section 111 define this term as follows:

Commenced means, with respect to the definition of new 

source in section 111(a)(2) of the Act, that an owner or 

operator has undertaken a continuous program of 

construction or modification or that an owner or operator 

has entered into a contractual obligation to undertake and 

complete, within a reasonable time, a continuous program of 

construction or modification.

40 CFR 60.2.
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requirements for “any existing source for any air pollutant (i) [that 

falls into specified categories] but (ii) to which a standard of 

performance under this section would apply if such existing source 

were a new source....” Section 111(d)(1). An “existing source” is 

defined as “any stationary source other than a new source.” Section 

111(a)(6).

b. Reasons for not applying the 1,000 lb CO2/MWh standard of 

performance to transitional sources

(i). Introduction

In this action, EPA is treating transitional sources as a 

distinct set of sources, although EPA is not establishing a specific 

subcategory for these sources in the regulatory provisions.70 Under 

CAA section 111, EPA may not apply a standard of performance to 

sources unless it reflects the “best system of emission reduction” 

(BSER) adequately demonstrated.

As noted, the EPA proposes that non-transitional source fossilfired power plants that commence construction after the date of 

 

70 Section 111(b)(2) authorizes the EPA to “distinguish among 

classes, types, and sizes within categories of new sources for the 

purpose of establishing such standards.” In other words, once the EPA 

selects the set of sources for which to propose regulations, the EPA 

may establish subcategories among those new sources and promulgate 

different standards for those subcategories. 
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proposal are subject to the standard of 1,000 lb CO2/MWh, and the EPA 

proposes to base this standard on the EPA’s identification of natural 

gas combined cycle (NGCC) as the BSER adequately demonstrated. EPA 

justifies this proposal because owners or operators contemplating 

construction of non-transitional base-load and intermediate load 

power plants have choices: they can choose the type of facility and 

therefore may choose to construct a NGCC plant. As a result, for 

these sources, NGCC constitutes the BSER, and the 1,000 lb CO2/MWh 

emission limit reflects that BSER and therefore is the appropriate 

standard of performance under section 111. Moreover, for those that 

choose to construct a coal-fired unit, they may choose to construct 

the plant in a place and a manner that allows installation of CCS –-

and thereby meet the 1,000 lb CO2/MWh standard -- either at the time 

of construction or, in accordance with the 30-year averaging 

proposal, some years later.

(ii) Transitional sources and NGCC

In contrast, the circumstances surrounding transitional sources 

are quite different. Transitional sources are a very small group of 

sources with a distinct profile of costs, preconstruction planning, 

overall business plans, technical and design concerns, and equitable 

concerns. Because they are such large facilities, their sunk costs 

and planning horizons are substantial. 
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Transitional sources have already incurred substantial costs in 

permitting and taking other steps preparatory to commencing 

construction as coal-fired power plants within 12 months of the date 

of this proposal, which may include purchasing land for the new 

facility. Considering these sunk costs, converting their plant design 

to NGCC would be significantly more expensive than for proposed nontransitional sources that have not reached the stage of development 

that transitional sources have reached. EPA is required to consider 

costs in determining the BSER adequately demonstrated, and under 

these circumstances, the costs factor points away from treating NGCC 

as BSER for transitional sources.

In addition, because transitional sources have obtained a PSD 

permit and have developed their plans to the point where they are on 

the verge of commencing construction, the converting of their plant 

design to NGCC would be significantly more disruptive to their 

business plans than for proposed non-transitional sources. It may 

require them to start over the process of developing the plant, and 

thereby render futile the planning and steps they have taken to date. 

These losses would, at a minimum, lead to delays in their commencing 

construction that realistically would be measured in years, and in 

fact may lead them to abandon the project.
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Although the potentially significant planning impacts at issue 

here are not explicitly identified as part of the definition of the 

“standard of performance,” they should nevertheless be considered in 

determining the BSER. This is because CAA section 111(a)(2), in its 

definition of “new source,” clearly contemplates that sources are 

expected to be able to commence construction after EPA proposes, and 

before EPA promulgates, a standard of performance applicable to them. 

There is nothing in CAA section 111 that suggests that Congress 

expected that EPA may determine the BSER in a way that would cause 

the kind of significant disruption to the business plans of the 

regulated sources that is implicated here. Therefore, for this 

reason, too, the 1,000 lb CO2/MWh standard cannot be considered to 

reflect the BSER for transitional sources, and therefore cannot be 

the appropriate standard of performance.

Nor can transitional sources reasonably be expected to meet the 

1,000 lb CO2/MWh standard through the installation of CCS, for the 

reasons discussed below.

Note that EPA takes the position that in this particular action, 

both of those factors –- sunk costs and extent of planning to 

commence construction -– must be considered in determining whether 

the 1,000 lb CO2/MWh standard reflects the BSER adequately 

demonstrated. That is, both are necessary conditions, and neither 
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one, by itself, is a sufficient condition. We believe that these 

reasons concerning costs and planning suffice to justify our position 

that the 1,000 lb CO2/MWh standard is not appropriate for transitional 

sources. 

(iii). Coal-fired transitional sources not designed for CCS 

As noted, while it is generally the case that proposed new 

sources could choose to build coal-fired power plants with CCS and 

thereby meet the 1,000 lb CO2/MWh standard, that is not the case for 

those transitional sources that are not designed for CCS. As a 

practical matter, it would be challenging for such a source to 

proceed with construction without substantial re-design of the 

project in order to install CCS and thereby be in compliance with the 

1,000 lb CO2/MwH standard. There are several reasons for this. First, 

captured CO2 must be sequestered or used. If this was not considered 

as part of the original site selection, the source will likely be 

significantly challenged in its efforts to adopt CCS. Second, if CCS 

was not considered in the original project design, space 

considerations may make it difficult to now accommodate it in the 

facility’s design. Third, the requirement to use CCS could 

necessitate a change in the very power generation technology that a 

source may choose to use. For instance, instead of building a 

pulverized coal boiler, IGCC technology may be more appropriate. This 
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is not to say that CCS could not be added to a project at this stage. 

Projects like the AEP Mountaineer project have shown that CCS can be 

successfully retrofitted into an existing plant. However, unlike in 

an existing facility where retrofit decisions must take into account 

previously made design decisions, in a facility in the pre-design 

phase, there is more opportunity for cost savings from re-designing 

the project, rather than having to adapt through retrofit.

It bears emphasis that the requirements created by the new 

source standard in today’s action are fundamentally different from 

post-combustion controls required to meet new source standards for 

conventional pollutants in the sense that those controls could be 

much more easily re-designed into an already planned plant without 

changing the plant’s basic underlying characteristics (such as type 

of unit or even location). In contrast, CCS is more fundamental to 

both the design and siting of a unit, and therefore would likely 

involve fundamental changes to the underlying project. This is much 

more difficult in a project that has progressed through the 

permitting stage and is very close to commencing construction than it 

would be in other types of projects. 

(iv). Coal-fired transitional sources designed for CCS

Although some of the proposed sources that may qualify as 

transitional sources are planning for CCS, that does not provide a 
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basis for concluding that the 1,000 lb CO2/MWh standard is appropriate 

for them. As noted, EPA is not, in this rulemaking, proposing that 

CCS is the BSER adequately demonstrated for coal-fired EGUs. 

Moreover, these proposed sources have established their location 

and developed their business plans without the expectation that the 

proposal in this rulemaking for CCS would apply to them. For example, 

their business plan may assume installing CCS in a manner that 

results in emissions at levels higher than 1,000 lb CO2/MWh, or it may 

assume the sale of emission reduction credits based on an allowable 

emission rate above 1,000 lb CO2/MWh. Imposition of an unexpected 

emission rate requirement at such a late date could upset carefully 

crafted financial plans, causing delay or even cancellation of the 

project.

Importantly, we do not have information as to key components of 

their proposed project and business plan, including, among other 

things, the amount of capture from the planned CCS system or possible 

revenue streams associated with CCS. Any proposal for what is BSER 

would depend on those costs and other information. Accordingly, we 

are not able to propose determinations that are essential to 

proposing the BSER for these proposed sources. As a result, we are 

not able to propose a standard of performance for these proposed 

sources.
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(v). Equitable considerations

For all transitional sources, the costs and delays discussed 

above give rise to equitable considerations that also support our 

treatment of these proposed sources. As noted, owners or operators of 

transitional sources have incurred significant expenses and 

undertaken a long planning period that has led them to being able to 

commence construction in the very near future, and, having invested 

so substantially in their current plans, should as an equitable 

matter be allowed to proceed without concern about requirements other 

than those in their PSD permits. To reiterate, they are in a posture 

that is fundamentally different from non-transitional sources. 

c. Reasons for not applying other standard of performance

Although, for the reasons described above, the 1,000 lb CO2/MWh 

standard that EPA proposes for non-transitional sources does not 

reflect BSER for transitional sources, EPA is not proposing any other 

standard of performance for transitional sources. It is reasonable to 

read section 111 not to require EPA to propose a standard of 

performance when faced with the specific circumstances presented by 

transitional sources in the context of this rulemaking. These 

circumstances include: (1) the EPA’s lack of information with regard 

to these sources and the appropriate BSER for these sources; (2) the 

unique challenges with regard to adaptation of proposed projects to 
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the requirements of this standard; (3) the small number of these 

sources and the possibility that promulgating a standard of 

performance would not have a beneficial environmental impact; and (4) 

although transitioanl sources would not be subject to the 1000 lb 

CO2/MWh standard for new sources, the EPA anticipates that 

transitional sources would become subject to the requirements the EPA 

would promulgate at the appropriate time, for existing sources under 

111(d). 

(i). CAA requirements for promulgating standards of performance for 

sources in a source category.

The EPA interprets the CAA provisions described above to 

authorize EPA not to promulgate a standard of performance for 

transitional sources. Under section 111(b)(1)(B), once the EPA lists 

a category of sources, the EPA is required to propose and promulgate 

standards of performance for new sources in that category. The EPA is 

not, however, required to promulgate standards of performance that 

cover all new sources . This is clear from the directive in section 

111(b)(1)(B), which requires that the EPA propose standards of 

performance “for new sources” within the category, but does not 

require that the EPA propose such standards for all new sources or 

for any new source. The EPA may fulfill that directive by proposing 
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standards that cover some, but not all, sources that newly commence 

construction or modification.

Similarly, the term “new source” in section 111(a)(2) is defined 

to incorporate the limitation that the EPA must propose or promulgate 

a standard applicable to the source for the source to be considered 

“new.” That is, section 111(a)(2) defines a “new source” as any 

source for which construction or modification commences after the EPA 

proposes “a standard of performance ... which will be applicable to 

such source.” By its terms, this provision contemplates that the EPA 

may not propose a standard of performance applicable to certain 

sources, and that if the EPA does not, those sources would not be 

considered to be “new source[s]” and therefore not subject to any new 

source standard of performance.

Thus, these provisions do not, by their terms, mandate that EPA 

propose standards for each and every source in the source category. 

Under Chevron step 1, these provisions do not unambiguously require 

that EPA propose standards of performance for all sources in the 

source category. We read these provisions as according EPA some 

measure of discretion for EPA to determine not to set standards for a 

particular portion of the source category, where appropriate, bounded 

by the principle of rationality. If these provisions are read to be 

ambiguous as to whether EPA has discretion to propose and promulgate 
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standards of performance for all sources in the source category, we 

believe it reasonable to read the provisions to provide such 

discretion in appropriate circumstances and that such reading is 

entitled to deference under Chevron step 2. In addition, interpreting 

these provisions to give EPA the discretion not to propose and 

promulgate standards covering all sources in a category under 

appropriate circumstances – such as those present here -- is 

consistent with the caselaw that authorizes agencies to establish a 

regulatory framework in an incremental fashion, that is, a step at a 

time.71

(ii). Precedents in prior NSPS rulemakings

In applying section 111 over the past several decades, there 

have been a number of rulemakings in which the EPA has promulgated 

new source performance standards that do not cover all sources within 

the relevant source category that newly commence construction or 

modification. Some examples include the following: (i) In an early 

NSPS, involving lime kilns, EPA promulgated an NSPS for certain types 

of kilns, but not for all types of sources that remained within the 

 

71 As the U.S. Supreme Court recently stated in Massachusetts v. EPA, 549 U.S. 497, 

524 (2007): “Agencies, like legislatures, do not generally resolve massive problems 

in one fell regulatory swoop;” and instead they may permissibly implement such 

regulatory programs over time, “refining their preferred approach as circumstances 

change and as they develop a more nuanced understanding of how best to proceed.” 

See Grand Canyon Air Tour Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), City 

of Las Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), National Association of 

Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (D.C. Cir. 1984). 
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relevant source category. The D.C. Circuit, in its opinion reviewing

the rule, noted this state of affairs, without expressing concerns.

National Lime Ass’n v. EPA, 627 F.2d 416, 426 & n. 28 (D.C. Cir. 

1980) (noting that “of the various types of kilns that may be used in 

the calcinations of limestone, only rotary kilns are regulated by the 

standards,” and not “the vertical kiln; the rotary hearth kiln; and 

the fluidized bed kiln”). (ii) In EPA’s initial promulgation of NSPS 

regulations for petroleum refineries, EPA did not promulgate 

standards of performance for certain units, including fluid coking 

units, delayed coking units, and process heaters, instead

promulgating standards of performance for those units subsequently. 

See 40 CFR 60.100a(a); “Standards of Performance for Petroleum 

Refineries: Proposed Rules,” 72 Fed. Reg. 27178 (May 14, 2007). (iii) 

Similarly, in EPA’s recent revision of the NSPS regulations for coal 

preparation and processing plants, EPA “expand[ed] applicability of 

the existing NSPS by revising the definitions of thermal dryers, 

pneumatic coal-cleaning equipment, and coal. It also establishe[d] 

work practice standards for open storage piles. The final rule 

amend[ed] the definition of thermal dryer for units constructed, 

reconstructed, or modified after May 27, 2009, to include both direct 

and indirect dryers drying all coal ranks (i.e., bituminous, 

subbituminous, lignite, and anthracite coals) and coal refuse.” 
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“Standards of Performance for Coal Preparation and Processing 

Plants,” 74 Fed. Reg. 51950, 51952 (Oct. 8, 2009). (iv) In subpart 

KKKK of the NSPS regulations, EPA promulgated regulations for the 

source category of stationary combustion turbines. EPA did not 

promulgate regulations for turbines with smaller than 10 MMBtu/hr 

heat input, emergency units, or combustion turbine test cells. 40 CFR 

60.4305(a), 60.4310(a), (d). (v) For other source categories, EPA 

also declined to propose and promulgate standards of performance for 

the smaller sources. For example, for the source category of metal 

furniture coating operations, EPA did not apply standards of 

performance to metal furniture surface coating operations that use 

less than 3.842 liters of coating (as applied) per year. 40 CFR 

60.310(b). (vi) In proposing standards of performance for natural gas 

processing plants, EPA proposed standards for only two of the three 

emission points in the plants (“storage emission sources” and 

“equipment leaks”) and declined to propose standards for the third 

emission point (“process emission sources”) on grounds that “[b]est 

demonstrated control technology has not been identified for [the 

latter] sources.” “Standards of Performance for New Stationary 

Sources; Onshore Natural Gas Processing Plants in the Natural Gas 

Production Industry, Equipment Leaks of VOC,” 49 Fed. Reg. 2636, 2637 

(January 20, 1984).
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(iii). Lack of basis for specifying information

A major reason why EPA is not proposing a standard of 

performance for transitional sources is that it is relying, in part, 

on the one-year commence-construction limit to qualify a source as 

transitional: EPA does not have sufficient information about the 

proposed sources’ sunk costs and preconstruction steps to be able to 

identify which of these proposed sources may qualify as transitional 

sources. In addition, even if EPA could determine that a particular 

proposed source would in fact become a transitional source, EPA lacks 

information that, under these circumstances, may be important for 

determining BSER. For example, EPA lacks information as to the amount 

of the proposed source’s sunk costs, which may be relevant in 

determining BSER for these proposed sources. In addition, for 

proposed CCS sources, as noted above, EPA does not have information 

as to key components of their proposed project and business plan, 

including, among other things, the amount of capture from the planned 

CCS system or possible revenue streams associated with CCS.

Moreover, because transitional sources are defined by reference 

to the fact that they will commence construction within 12 months of 

the date of this proposal, it would be futile for EPA to attempt to 

develop that information and then issue a proposal. By the time EPA 

could do this, which would likely take at least a year, this set of 
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sources will have become a null set: they either will have commenced 

construction, such that they would no longer be deemed “new sources”

for purposes of CAA section 111, or they will not have commenced 

construction, such that they would be subject to the new source 

standard for non-transitional sources we are proposing today.72

(iv). Practical problems 

In addition, EPA’s lack of information and other considerations 

give rise to several serious practical problems that would arise were 

EPA to propose a standard of performance for transitional sources. 

Importantly, were EPA to propose a standard of performance, all 

transitional sources would face substantial uncertainty as to what 

final standard the EPA would promulgate. This uncertainty would arise 

for several reasons. As noted, EPA lacks information concerning 

transitional sources. In addition, transitional sources differ one 

from another in terms of design and in other respects, which would 

 

72 Note that because the basic rationale for EPA’s treatment of 

transitional sources is that they have already incurred substantial

sunk costs and have positioned themselves to be close to commencing 

construction, and the one-year period for commencing construction is 

a surrogate for that, this treatment of transitional sources cannot 

logically be stretched to cover sources that do not commence within a 

substantially longer period. There is no reason to believe those 

latter sources would have, by the time of the proposal for the rest 

of the source category, already incurred significant costs and moved 

close to commencing construction. 
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render EPA’s task more complex. As a result, there is risk that EPA 

might finalize standards of performance different from what EPA 

proposed. The final standards of performance may be more difficult 

for a given transitional source to meet.

Other forms of uncertainty may arise as well. For example, a 

possible standard of performance that the EPA would consider would be 

based on identifying the BSER for transitional sources as the 

controls to which they would be subject under the terms of their PSD 

permits, with no further controls under section 111.73 With this 

approach, the EPA would need to determine the emission rate for each 

source that would reflect that source’s level of CO2 emissions in 

accord with the terms of its PSD permit. This emission rate would 

constitute the “no-further-control” standard of performance. Note 

that under such an approach, each source would receive an emission 

limit unique to that source. However, some of the transitional 

sources may have a PSD permit that does not regulate CO2 because GHGs 

were not subject to PSD until the January 2, 2011 effective date of 

the first regulatory action controlling CO2 emissions under the CAA. 

Particularly for those sources, this approach could create

 

73 This type of standard of performance could take one of several 

different forms, such as a standard that would not limit the source’s 

CO2 emissions, or a standard that the transitional source itself 

would identify as equaling the emission limit it would achieve 

through compliance with the applicable terms of its permit.
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uncertainty as to what the EPA would promulgate as the emission rate 

in the final standard of performance. This is because since these 

sources’ permits do not specify a CO2 limit, the EPA would have to 

develop limits based on the design of the unit (including the 

project’s type of technology and fuels). 

The uncertainties that the sources could experience as to what 

the final standards of performance would entail could well deter 

those sources from commencing construction until the EPA promulgated 

the final standard of performance. Such delay would undermine the 

usefulness of the requirement that sources commence construction 

within 12 months of today’s rulemaking proposal as a mechanism for 

revealing which of these sources qualifies as a transitional source, 

and thus defeat the policy underlying the EPA’s approach to 

transitional sources, which, for the reasons explained above, is to 

exclude from coverage by this new source standard only those sources 

that commence construction within 12 months of proposal. If sources 

are deterred from commencing construction until after the final rule, 

they will have lost the benefit of the 12-month window. As another 

practical problem, we also note concern with attempting to promulgate 

standards of performance for transitional sources at a time when it 

may reasonably be expected that some of the 15 sources with PSD 

permits may well not commence construction within 12 months (or may 
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never do so). As a result, the effort to develop a standard of 

performance for those sources would have been unnecessary. 

(v). Small number of transitional sources, lack of environmental 

benefit As part of our reasoning for not proposing a standard of 

performance for transitional sources, we also take into consideration 

the fact that we expect the number of transitional sources to be 

small, no more than a few of the 15 potential sources listed above. 

Further, if we were to propose a “no further control” standard of 

performance, as described above, that approach would provide little, 

if any, environmental benefit because that standard would not likely 

provide further control beyond the limits of the sources’ PSD 

permits. In fact, treating transitional sources as existing sources 

may achieve more reductions than a no-further-control NSPS standard 

for those sources by including them under the flexible existing 

source standard that the EPA expects to promulgate. 

(vi). Other considerations.

EPA’s approach of not proposing a standard of performance for 

transitional sources does not leave these sources uncontrolled. 

Rather, they would remain subject to whatever CO2 emission limits are 

included in, or result from compliance with, their PSD permits. And, 

although transitional sources would not be subject to the 1,000 lb 

CO2/MWh for new sources, the EPA anticipates that transitional sources 
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would become subject to the requirements the EPA would promulgate at 

the appropriate time for existing sources under 111(d).

In notable contrast, in the previous rulemakings cited above in 

which EPA did not propose coverage of all sources within the relevant 

source category, because of the pollutants at issue in these actions, 

the decision not to propose coverage of all sources within the 

relevant source category operated without the assurance afforded by 

section 111(d) that uncovered sources would necessarily be picked up 

as existing sources subject to existing source guidelines. Where, as 

here, that assurance mechanism applies, the recognition and 

application of the Agency’s discretion to not propose coverage of all 

sources in the source category is all the more appropriate.

We recognize that this approach of not proposing a standard of 

performance for transitional sources could raise the question of 

consistency with the requirement implicit in the definition of “new 

source” under CAA section 111(a)(2) that a source be subject to a 

standard of performance when it commences construction after the date 

of proposal for that standard. We believe the approach is consistent 

with, and does not circumvent, that requirement. As noted, CAA 

section 111 does not require that all sources that newly commence 

construction be treated as new sources, and in past section 111 

rulemakings, the EPA has not applied the standards of performance 
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that it proposes and promulgates to all sources that newly commence 

construction in a source category. In addition to the reasons for not 

promulgating a standard for transitional sources provided above, 

where, as here, the pollutants covered by the proposed new source 

standard give rise to an obligation to develop section 111(d) 

guidelines for existing sources with the source category, ultimate 

coverage of the sources in question is inevitable, eliminating any 

prospect of a regulatory gap of any material concern.

C. Requirements for Reconstructions 

1. Overview

The EPA’s framework regulations under CAA section 111 provide 

that reconstructed sources –- which, in general, are existing sources 

that conduct extensive replacement of components -- are to be treated 

as new sources and, therefore, subject to new source standards of 

performance. In today’s rulemaking, we do not propose any standard of 

performance for reconstructed sources, and we take comment how to 

approach reconstructions. We note that if we do not establish a new 

standard of performance for reconstructions, as a practical matter, 

that would mean that reconstructed sources would be treated as 

existing sources.

2. Background
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a. The EPA Regulations. The EPA’s framework regulations, interpreting 

the definition of “new source” in CAA section 111(a)(2),74 provide 

that an existing source, “upon reconstruction,” becomes subject to 

the standard of performance for new sources. 40 CFR 60.15(a). The 

regulations define “reconstruction” as –

[T]he replacement of components of an existing facility to such 

an extent that:

(1) The fixed capital cost of the new components exceeds 50 

percent of the fixed capital cost that would be required to 

construct a comparable entirely new facility, and

(2) It is technologically and economically feasible to meet the 

applicable standards set forth in this part.

40 CFR 60.15(b). Thus, a reconstruction occurs if the existing source 

replaces components to such an extent that the capital costs of the 

new components exceed 50 percent of the capital costs of an entirely 

new facility, even if the existing source does not increase 

emissions. In addition, the component replacement constitutes a 

reconstruction only if it is technologically and economically 

feasible for the source to meet the applicable standards. 

The regulations go on to require the owner or operator of an 

existing source that proposes to replace components to an extent that 

exceeds the 50 percent level, to notify the EPA and to provide 

 

74 CAA section 111 does not explicitly include provisions for 

reconstructed sources.
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specified information, including “a discussion of any economic or 

technical limitations the facility may have in complying with the 

applicable standards of performance after the proposed replacements.” 

In addition, the regulations require the EPA to determine, within a 

specified time period, whether the proposed replacement constitutes a 

reconstruction. 40 CFR 60.15(d)–(e).

b. Reconstructions. Historically, very few power plants have 

undertaken reconstructions. The EPA is not aware that any power 

plants are presently planning any project that could meet the 

requirements for a reconstruction.

2. Options

In this action, the EPA is not issuing a proposal for affected 

sources that undertake reconstructions. Our reasoning is much the 

same as with modifications, which is that the lack of adequate 

information about the type of source; the type of changes; the extent 

of emissions increases; and the type of control measures, including 

their cost and emissions reductions, precludes proposing a standard 

of performance. Instead of issuing a proposal, the EPA solicits 

comment on all issues related to reconstructions, including the 

aspects just noted. Depending on the information the EPA acquires 

about reconstructions, the EPA may, in the future, propose and 

promulgate standards of performance for them.
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VI. Implications for PSD and Title V Programs

A. Overview

The proposal in this rulemaking would, for the first time, 

regulate GHGs under CAA section 111. Under the EPA’s regulations for 

the CAA PSD preconstruction permit program, and the CAA Title V 

operating permit program, regulation of GHGs under CAA section 111 

triggers the applicability of PSD. Even so, today’s proposal should 

not require any additional SIP revisions to make clear that the 

Tailoring Rule thresholds – described below -- continue to apply to 

the PSD program. 

This issue arises because States with approved PSD programs in 

their state implementation plans (SIPs) implement PSD, and most of 

these States have recently revised their SIPs to incorporate the 

higher thresholds for PSD applicability to GHGs that the EPA 

promulgated under what we call the Tailoring Rule.75 Commenters have 

queried whether under the EPA’s PSD regulations, promulgation of a 

section 111 standard of performance GHGs would require these states 

 

75 “Prevention of Significant Deterioration and Title V Greenhouse Gas 

Tailoring Rule; Final Rule,” 75 FR 31514 (June 3, 2010). In the 

Tailoring Rule, EPA established a process for phasing in PSD and 

Title V applicability to sources based on the amount of their GHG 

emissions, instead of immediately applying PSD and title V at the 100 

or 250 ton per year or thresholds included under the PSD and title V 

applicability provisions.
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to revise their SIPs again to incorporate the Tailoring Rule 

thresholds again. The EPA included an interpretation in the Tailoring 

Rule preamble, which makes clear that the Tailoring Rule thresholds 

continue to apply if and when the EPA promulgates requirements under 

CAA section 111. Even so, in today’s proposal, the EPA is including a 

provision in the CAA section 111 regulations that confirms this 

interpretation. 

However, if a state with an approved PSD SIP program that 

applies to GHGs believes that were the EPA to finalize the rulemaking 

proposed today, the state would be required to revise its SIP to make 

clear that the Tailoring Rule thresholds continue to apply, then (i) 

the EPA encourages the state to do so as soon as possible, and (ii) 

the EPA will proceed with a separate rulemaking action to narrow its 

approval of that state’s SIP so as to assure that for federal 

purposes, the Tailoring Rule thresholds will continue to apply as of 

the effective date of today’s rulemaking.

In the alternative, if the Tailoring Rule thresholds did not 

continue to apply when the EPA promulgates requirements under CAA 

section 111, then the EPA would shortly proceed with a separate 

rulemaking action to narrow its approval of all of the State’s 

approved SIP PSD programs to assure that for federal purposes, the 

Tailoring Rule thresholds will continue to apply as of the effective 
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date of today’s proposal.

As discussed below, in the case of title V, today’s rulemaking 

does not have implications for the Tailoring Rule thresholds 

established with respect to sources subject to title V requirements. 

B. Implications for PSD Program

Under the PSD program in part C of title I of the CAA, in areas 

that are classified as attainment or unclassifiable for NAAQS 

pollutants, a new or modified source that emits any air pollutant 

subject to regulation at or above specified thresholds, is required 

to obtain a preconstruction permit. This permit assures that the 

source meets specified requirements, including application of best 

available control technology. States authorized for the PSD program 

may issue PSD permits. If a state is not authorized, then the EPA 

issues the PSD permits.

Regulation of GHG emissions in the Light Duty Vehicle Rule (75 

FR 25324) triggered applicability of stationary sources to 

regulations for GHGs under the PSD and title V provisions of the CAA. 

Hence, on June 3, 2010 (75 FR 31514), the EPA issued the “Tailoring 

Rule,” which establishes thresholds for GHG emissions in order to 

define and limit when new and modified industrial facilities must 

have permits under the PSD and title V programs. The rule addresses 

emissions of six GHGs: CO2, CH4, N2O, HFCs, PFCs and SF6. On January 2, 
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2011, large industrial sources, including power plants, became 

subject to permitting requirements for their GHG emissions if they 

were already are required to obtain PSD or title V permits due to 

emissions of other (non-GHG) air pollutants.

Commenters have queried whether, because of the way that the 

EPA’s PSD regulations are written, promulgating the rule we propose 

today may raise questions as to whether the EPA must revise its PSD 

regulations –- and, by the same token, whether states must revise 

their SIPs –- to assure that the Tailoring Rule thresholds will 

continue to apply to sources subject to PSD. That is, under the EPA’s 

regulations, PSD applies to a “major stationary source” that 

undertakes construction, 40 CFR 51.166(a)(7)(i), and to a “major 

modification.” 40 CFR 51.166(a)(7)(iii). A “major modification” is 

defined as “any physical change in or change in the method of 

operation of a major stationary source that would result in a 

significant emissions increase . . . and a significant net emissions 

increase . . . .” Thus, for present purposes, the key component of 

these applicability provisions is that PSD applies to a “major 

stationary source.” This term is the regulatory replacement for the 

term “major emitting facility,” which is central to the PSD 

applicability requirements established in the CAA itself, under 

sections 165(a)(1) and 169(1).
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The EPA’s regulations define the term “major stationary source” 

as a “stationary source of air pollutants which emits, or has the 

potential to emit, 100 [or, depending on the source category, 250] 

tons per year or more of any regulated NSR pollutant.” 40 CFR 

51.166(b)(1)(i)(a). The EPA’s regulations go on to define “regulated 

NSR pollutant” as follows, in relevant part: 

(b)(49) Regulated NSR pollutant, for purposes of this 

section, means the following:

(i) Any pollutant for which a national ambient air 

quality standard has been promulgated and any 

pollutant identified under this paragraph (b)(49)(i) 

as a constituent or precursor to such pollutant.... 

(ii) Any pollutant that is subject to any standard 

promulgated under section 111 of the Act;

(iii) Any Class I or II substance subject to a 

standard promulgated under or established by title VI 

of the Act;

(iv) Any pollutant that otherwise is subject to 

regulation under the Act as defined in paragraph 

(b)(48) of this section....

40 CFR 51.166(b)(49). Thus, the PSD regulations contain a separate 

PSD trigger for pollutants regulated under the NSPS, 40 CFR 

51.166(b)(49)(ii) (the “NSPS trigger provision”), so that as soon as 

the EPA promulgates the first NSPS for a particular air pollutant, as 

we are doing in this rulemaking with respect to the GHG air 

pollutant, then PSD is triggered for that air pollutant. 
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The Tailoring Rule, on the face of its regulatory provisions, 

incorporated the revised thresholds it promulgated into only the 

fourth prong (“[a]ny pollutant that otherwise is subject to 

regulation under the Act”), and not the second prong (“[a]ny 

pollutant that is subject to any standard promulgated under section 

111 of the Act”). For this reason, a question may arise as to whether 

the Tailoring Rule thresholds apply to the PSD requirement as 

triggered by the NSPS that the EPA is promulgating in this 

rulemaking.

However, although the Tailoring Rule thresholds on their face 

apply to only the term, “subject to regulation” in the definition of 

“regulated NSR pollutant,” the EPA stated in the Tailoring Rule 

preamble that the thresholds should be interpreted to apply to other 

terms in the definition of “major stationary source” and in the 

statutory provision, “major emitting facility.” Specifically, the EPA 

stated:

3. Other Mechanisms

As just described, we selected the “subject to 

regulation” mechanism because it most readily accommodated 

the needs of States to expeditiously revise – through 

interpretation or otherwise -- their state rules. Even so, 

it is important to recognize that this mechanism has the 

same substantive effect as the mechanism we considered in 

the proposed rule, which was revising numerical thresholds 

in the definitions of major stationary source and major 

modification. Most importantly, although we are codifying 
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the “subject to regulation” mechanism, that approach is 

driven by the needs of the states, and our action in this 

rulemaking should be interpreted to rely on any of several 

legal mechanisms to accomplish this result. Thus, our 

action in this rule should be understood as revising the 

meaning of several terms in these definitions, including: 

(1) the numerical thresholds, as we proposed; (2) the term, 

“any source,” which some commenters identified as the most 

relevant term for purposes of our proposal; (3) the term, 

“any air pollutant; or (4) the term, “subject to 

regulation.” The specific choice of which of these 

constitutes the nominal mechanism does not have a 

substantive legal effect because each mechanism involves 

one or another of the components of the terms “major 

stationary source” - which embodies the statutory term, 

“major emitting facility” -- and “major modification,” 

which embodies the statutory term, “modification,” and it 

is those statutory and regulatory terms that we are 

defining to exclude the indicated GHG-emitting sources.

[Footnote] 

[Footnote: We also think that this approach better 

clarifies our long standing practice of interpreting openended SIP regulations to automatically adjust for changes 

in the regulatory status of an air pollutant, because it 

appropriately assures that the Tailoring Rule applies to 

both the definition of “major stationary source” and 

“regulated NSR pollutant.” ] 

75 FR 31582.

Thus, according to the preamble, the definition of “major 

stationary source” itself already incorporates the Tailoring Rule 

thresholds, and not just through one component (the “subject to 

regulation” prong of the term “regulated NSR pollutant”) of that 

definition. For this reason, it is the EPA’s position that the 

Tailoring Rule thresholds continue to apply even when the EPA 
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promulgates the first NSPS for GHGs (which, as noted above, triggers 

the PSD requirement under the NSPS trigger provision in the 

definition of “regulated NSR pollutant”).76 To clarify and confirm 

that the Tailoring Rule thresholds apply to the section 111 prong of 

the definition of regulated NSR pollutant, in this proposed 

rulemaking, the EPA is proposing to revise the NSPS regulations, 

although not the PSD regulations, to explicitly make clear that the 

NSPS trigger provision in the PSD regulations incorporate the 

Tailoring Rule thresholds.

As a result, the EPA believes that states that incorporated the 

Tailoring Rule thresholds into their SIPs may take the position that 

they also incorporated the EPA’s interpretation in the preamble that 

the thresholds apply to the definition “major stationary source.” 

The EPA requests that all States with approved SIP PSD programs 

that apply to GHGs indicate during the comment period on this rule 

 

76 This position reads the regulations to be consistent with the CAA 

PSD provisions themselves. Under those provisions, PSD applies to any 

“major emitting facility,” which is defined to mean stationary 

sources that emit or have the potential to emit “any air pollutant” 

at either 100 or 250 tons per year, depending on the source category. 

CAA section 165(a), 169(1). EPA has long interpreted these provisions 

to apply PSD to a stationary source that emits the threshold amounts 

of any air pollutant subject to regulation. See Tailoring Rule, 75 FR 

31579. Under these provisions, at present, PSD is already applicable 

to GHGs because GHGs are already subject to regulation, and 

regulating GHGs under CAA section 111 does not any additional type of 

PSD trigger.
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whether they can interpret their SIPs already to apply the Tailoring 

Rule thresholds to the NSPS prong or whether they must revise their 

SIPs. For any State that says it must revise its SIP (or that does 

not respond), the EPA expects to propose a rule that is comparable to 

the SIP PSD Narrowing Rule shortly after the close of the comment 

period, and expects to finalize that rule at the same time that it 

finalizes this NSPS rule.

C. Implications for Title V Program

Under the title V program, a source that emits any air pollutant 

subject to regulation at or above specified thresholds (along with 

certain other sources) is required to obtain an operating permit. 

This permit includes all of the CAA requirements applicable to the 

source. These permits are generally issued through EPA-approved State 

title V programs.

As the EPA explained in the Tailoring Rule preamble, title V 

applies to a “major source,” CAA section 502(a), which is defined to 

include, among other things, certain sources, including any “major 

stationary source,” CAA section 501(2)(B), which, in turn, is defined 

to include a stationary source of “any air pollutant” at or above 100 

tpy. CAA section 302(j). The EPA’s regulations under title V define 

the term “major source,” and in the Tailoring Rule, the EPA revised 

that definition to make clear that the term is limited to stationary 
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sources that emit any air pollutant “subject to regulation.” The EPA 

incorporated the Tailoring Rule threshold within this definition of 

“subject to regulation.” The EPA described its action as follows in 

the preamble to the Tailoring Rule:

Thus, EPA is adding the phrase “subject to regulation” 

to the definition of “major source” under 40 CFR 70.2 and 

71.2. EPA is also adding to these regulations a definition 

of “subject to regulation.” Under the part 70 and part 71 

regulatory changes adopted, the term “subject to 

regulation,” for purposes of the definition of “major 

source,” has two components. The first component codifies 

the general approach EPA recently articulated in the 

“Reconsideration of Interpretation of Regulations That 

Determine Pollutants Covered by Clean Air Act Permitting.” 

75 FR 17704. Under this first component, a pollutant 

“subject to regulation” is defined to mean a pollutant 

subject to either a provision in the CAA or regulation 

adopted by EPA under the CAA that requires actual control 

of emissions of that pollutant and that has taken effect 

under the CAA. See id. at 17022-23; Wegman Memorandum at 4-

5. To address tailoring for GHGs, EPA includes a second 

component of the definition of “subject to regulation,” 

specifying that GHGs are not subject to regulation for 

purposes of defining a major source, unless as of July 1, 

2011, the emissions of GHGs are from a source emitting or 

having the potential to emit 100,000 tpy of GHGs on a CO2e 

basis.

75 Fed. Reg. at 31,583. 

Unlike the PSD regulations described above, the title V 

definition of “major source”, as revised by the Tailoring Rule, does 

not on its face distinguish among types of regulatory triggers for 

title V. Because title V has already been triggered for GHG-emitting 

sources, the promulgation of CAA section 111 requirements has no 
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further impact on title V requirements for major sources of GHGs. 

Accordingly, today’s rulemaking has no title V implications with 

respect to the Tailoring Rule threshold. Of course, unless exempted 

by the Administrator through regulation under CAA section 502(a), 

sources subject to a NSPS are required to apply for, and operate 

pursuant to, a title V permit that assures compliance with all 

applicable CAA requirements for the source, including any GHG-related 

requirements. We have concluded that this rule will not affect nonmajor sources and there is no need to consider whether to exempt nonmajor sources

VII. Impacts of the Proposed Action

A. What are the air impacts?

 The EPA believes that electric power companies would choose to 

build new EGUs that comply with the regulatory requirements of this 

proposal even in the absence of this proposal, because of existing 

and expected market conditions. We do not project any new coal-fired 

EGUs without CCS to be built in the absence of this proposal. 

Accordingly, the EPA believes that this proposed rule is not likely 

to produce changes in emissions of greenhouse gases or other 

pollutants although it does encourage the current trend towards 

cleaner generation. 

B. What are the energy impacts?
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 This proposed rule is not anticipated to have a notable effect 

on the supply, distribution, or use of energy. As previously stated, 

we believe that electric power companies would choose to build new 

EGUs that comply with the regulatory requirements of this proposal

even in the absence of the proposal, because of existing and expected 

market conditions. In addition, we do not project any new coal-fired 

EGUs without CCS to be built in the absence of this proposal.

C. What are the compliance costs?

 The EPA believes this proposed rule will have no notable

compliance costs associated with it, because electric power companies 

would be expected to build new EGUs that comply with the regulatory 

requirements of this proposal even in the absence of the proposal, 

due to existing and expected market conditions. The EPA does not 

project any new coal-fired EGUs without CCS to be built in the 

absence of the proposal. 

D. How will this proposal contribute to climate change protection?

 As previously explained, the special characteristics of GHGs 

make it important to take initial steps to control the largest 

emissions categories without delay. Unlike most traditional air 

pollutants, GHGs persist in the atmosphere for time periods ranging 

from decades to millennia, depending on the gas. Fossil-fueled power 

plants emit more GHG emissions than any other stationary source 
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category in the United States, and among new GHG emissions sources, 

the largest individual sources are in this source category. 

This proposed rule will limit GHG emissions from new sources in 

this source category to levels consistent with current projections 

for new fossil-fuel-fired generating units. The proposed rule will 

also serve as a necessary predicate for the regulation of existing 

sources within this source category under CAA section 111(d). In 

these ways, the proposed rule will contribute to the actions required 

to slow or reverse the accumulation of GHG concentrations in the 

atmosphere, which is necessary to protect against projected climate 

change impacts and risks.

E. What are the economic and employment impacts?

The EPA does not anticipate that this proposed rule will result 

in notable CO2 emission changes, energy impacts, monetized benefits, 

costs, or economic impacts by 2020. Essentially the EPA believes that 

owners of newly built electric generating units will choose 

technologies that meet these standards even in the absence of this 

proposal due to existing economic conditions as normal business 

practice. Likewise, we believe this rule will not have any impacts on 

the price of electricity, employment or labor markets, or the US 

economy.
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F. What are the benefits of the proposed standards?

As previously stated, the EPA does not anticipate that the power 

industry will incur compliance costs as a result of this proposal and 

we do not anticipate any notable CO2 emission changes resulting from 

the rule. Therefore, there are no direct monetized climate benefits 

in terms of CO2 emission reductions associated with this rulemaking.

However, by clarifying that in the future, new coal-fired power 

plants will be required to install CCS, this rulemaking eliminates 

uncertainty about the status of coal and may well enhance the 

prospects for new coal-fired generation and the deployment of CCS, 

and thereby promote energy diversity.

VIII. Request for Comments

We request comments on all aspects of the proposed rulemaking

including the RIA. All significant comments received will be 

considered in the development and selection of the final rule. We 

specifically solicit comments on additional issues under 

consideration as described below.

CEMS. We are considering and requesting comment on requiring the 

use of CO2 CEMS including stack gas flow rate monitoring for all new 

affected facilities, including those burning exclusively natural gas 

and/or distillate oil. In addition, we are requesting comment on 
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requiring the use the following measurement procedures in conducting 

CEMS relative accuracy testing:

a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during 

the relative accuracy test audit and performance testing. Method 2F 

provides velocity data for three dimensions and provides measurements 

more representative of actual gas flow rates than EPA Method 2 or 2G 

of 40 CFR part 60.

b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method (CTM)-

041 (see: http://www.epa.gov/airmarkets/emissions/docs/square-ductswall-effects-test-method-ctm-041.pdf) to account for wall effects on 

for stack gas flow rate calculations during CEMS relative accuracy 

determinations and for performance testing.

c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow rate 

during CEMS relative accuracy determinations and for performance test 

calculations.

d. EPA Method 3A of 40 CFR part 60 for CO2 concentration measurement 

and for molecular weight determination during CEMS relative accuracy 

determinations or for performance testing. Account for ambient air 

argon concentration of 0.93 percent77 and a molecular weight of 39.9 

lb/lb-mol in calculating the dry gas molecular weight.

 

77 http://www.physicalgeography.net/fundamentals/7a.html.
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e. Measure the stack diameter at the CEMS measurement site and the 

reference method sampling site with a laser distance measurement 

device. Determine the mean average of three separate diameter 

measurements for circular stack areas or the mean average of three 

depth and width measurements for rectangular measurement areas. 

Calculate the effective stack area for all flow rate measurements, 

both CEMS system and Reference Method, using this measurement data. 

This would be a one-time measurement that would fix the effective 

area of the stack emissions point unless a new location is chosen for 

the CEMS or Reference Method measurement point. All calculations 

involving pi would use a value of 3.14159.

f. Apply a daily calibration drift criteria not to exceed 0.3 percent 

CO2 for CO2 CEMS.

g. Do not exceed a relative accuracy specification of 2.5 percent for 

both CO2 and flow rate measurement CEMS.

We also request comment on whether Method 3B of 40 CFR part 60 

(integrated bag sample), in addition to Method 3A, should be allowed 

for CO2 concentration measurement and for molecular weight 

determination during CEMS relative accuracy determinations or for 

performance testing.

Coal refuse. Due to the multiple environmental benefits of 

remediating coal refuse piles, we are considering and requesting 
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comment on subcategorizing EGUs that burn over 75 percent coal refuse 

on an annual basis. As part of the GHG listening sessions, one 

commenter mentioned the advantages of utilizing coal refuse to create 

electricity. The commenter stated that if net emissions caused by 

using mining waste to generate electricity are calculated, then 

mining waste facility would produce no net GHG emissions in the long 

term and emissions would be no greater than the short term emissions

of a combined cycle gas plant in. The comment states that due to the 

size of the piles, mining waste pile exposure to atmospheric oxygen 

and pressure promotes heat-generating reactions, primarily oxidation 

of the mining waste itself (i.e., the coal refuse piles are slowly 

burning). This process emits CO2 and other air pollutants. Remediation 

would stop current and future CO2 emissions resulting from the 

uncontrolled combustion of waste piles.

Coordinates. We realize that geographic latitude and longitude 

coordinates of each stack in terms of decimal degrees are presently 

reported to the EPA’s Clean Air Markets Division in terms of four 

decimal points to the right of the decimal point. We are requesting 

comment on whether we should require owners/operators of affected 

facilities to submit to the EPA Administrator the geographic latitude 

and longitude coordinates of each stack to have at least six values 

to the right of the decimal for each location. By way of example, the 
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coordinates for the monument next to Zachary Taylor’s tomb in 

Louisville, KY are 38.279401 latitude and -85.643751 longitude.

Combined Heat and Power. We are also considering and requesting 

comment on if exempting all CHP facilities where useful thermal 

output accounts for at least 20 percent of the total useful output 

from this proposed rule would recognize the environmental benefit of 

CHP and result in additional installations that would otherwise no 

occur. In considering exemption of CHP units, the EPA is particularly 

interested in the overall impact this would have on the composition 

of new builds. The definition of affected sources under this rule 

already exempts CHP sources that primarily generate on-site power. 

Therefore, as explained earlier, today’s proposal does not impact any 

of the small amount of projected coal-fired CHP in EIA’s AEO 2011. 

CHPs that would be covered by this rule generate and sell large 

quantities of electricity. While building such units is more energy 

efficient and results in some GHG reductions, building new coal-fired 

units to meet a standard of 1,000 lb/MWh would likely result in 

greater reductions. If potential developers of new coal-fired 

generation opted instead to build coal-fired CHP to avoid the CO2

limitations proposed under today’s rule, it could result in greater 

emissions of CO2. Furthermore, requiring such units to meet a standard 
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of 1,000 lb/MWh does not preclude new coal-fired units from being CHP 

units.

Format of the Proposed Standards. Although we have proposed 

gross output-based emission standards, the EPA believes that the net 

power supplied to the end user is a better indicator of environmental 

performance than gross output from the power producer. Net output is 

the combination of the gross electrical output of the electric 

generating unit minus the parasitic power requirements. A parasitic 

load for an electric generating unit is any of the loads or devices 

powered by electricity, steam, hot water, or directly by the gross 

output of the electric generating unit that does not contribute 

electrical, mechanical, or thermal output. In general, less than 7.5 

percent of coal-fired station power output, and about 2.5 percent of 

a combined cycle station power output, is used internally by 

parasitic energy demands, but the amount of these parasitic loads 

vary from source to source. Reasons for using net output include 1) 

recognizing the efficiency gains of selecting EGU designs and control 

equipment that require less auxiliary power, 2) selecting fuels that 

require less emissions control equipment, and 3) recognizing the 

environmental benefit of higher efficiency motors, pumps, and fans. 

In addition, use of a gross output-based standard could potentially 

drive the installation of electrically driven feed pumps instead of 
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steam driven feed pumps, even though from an overall net efficiency 

basis, it may be more efficient to use steam-driven feed pumps. 

Further, monitoring net output for new and reconstructed facilities 

can be designed into the facility at low costs. Thus, we are 

requesting comment on the use of net output-based emission standards 

for owners/operators of new facilities.

Stationary Simple Cycle Turbines. As stated in the preamble, the 

intent of the proposed regulations is to cover stationary combustion 

turbines use for intermediate and base load electric power generation 

and to exempt stationary combustion turbines used for peaking 

operations (i.e., simple cycle turbines). We are considering and 

requesting comment on not including a definition of simple cycle 

turbines in the final rule. The potential electric output requirement 

in the definition of electric generating unit would already exclude

facilities with permit restricting limiting operation to less than 

1/3 of their potential electric output, approximately 2,900 hours of 

full load operation annually. The peaking season is generally 

considered to be less than 2,500 hours annually, and we are 

requesting comment on if the capacity factor exemption is sufficient 

such that specifically exempting simple cycle turbine is unnecessary. 

We are also requesting comment on whether the exemption would provide 

a perverse incentive to build less efficient simple cycle combustion 
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turbines in order to avoid applicability with the proposed rule. 

While few existing simple cycle turbines presently generate greater 

than 1/3 of their potential electric output for sale, we are 

requesting comment on whether the exemption for simple cycle turbines 

would result in the greater use of simple cycle turbines for 

intermediate load applications when more efficient combined cycle 

facilities would have otherwise been built. In addition, it is our 

understanding that combined cycle facilities are sometimes built in 

stages with the combustion turbine engine installation occurring 

first and the heat recovery steam generator being installed in later 

years as electricity demand increases. We are requesting comment on 

whether the exemption would potentially delay the installation of the 

heat recovery steam generator portion of new combined cycle 

facilities. Finally, in the event we use the definition approach in 

the final rule, we are requesting comment on whether a CHP facility 

that uses the recovered exhaust heat for purposes other than to 

generate steam and recuperated combustion turbines should be 

considered simple or combined cycle combustion turbines.

IX. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory Review
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 Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 

1993), this action is a “significant regulatory action” because it 

“raises novel legal or policy issues arising out of legal mandates”. 

Accordingly, the EPA submitted this action to the Office of 

Management and Budget (OMB) for review under Executive Orders 12866 

and 13563 (76 FR 3821, January 21, 2011) and any changes made in 

response to OMB recommendations have been documented in the docket 

for this action. In addition, the EPA prepared an analysis of the 

potential costs and benefits associated with this action. This 

analysis is contained in the Regulatory Impact Analysis for the 

Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units. 

 The EPA believes this rule will have no notable compliance costs 

associated with it over a range of likely sensitivity conditions 

because electric power companies would choose to build new EGUs that 

comply with the regulatory requirements of this proposal even in the 

absence of the proposal, because of existing and expected market 

conditions. (See the RIA for further discussion of sensitivities.) 

Because our modeling shows that natural gas-fired plants are the 

facilities of choice, the proposed standard of performance –– which 

is based on the emission rate of a new NGCC unit –– would not add 
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costs. The EPA does not project any new coal-fired EGUs without CCS 

to be built in the absence of this proposal.

B. Paperwork Reduction Act

The information collection requirements in this proposed rule 

have been submitted for approval to the Office of Management and 

Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. The Information Collection Request (ICR) document prepared by 

the EPA has been assigned EPA ICR number 2465.01.

This proposed action would impose minimal new information 

collection burden on affected sources beyond what those sources would 

already be subject to under the authorities of CAA parts 75 and 98.

OMB has previously approved the information collection requirements 

contained in the existing part 75 and 98 regulations (40 CFR part 75 

and 40 CFR part 98) under the provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 

2060-0626 and 2060-0629, respectively. Apart from certain reporting 

costs based on requirements in the NSPS General Provisions (40 CFR 

part 60, subpart A), which are mandatory for all owners/operators 

subject to CAA section 111 national emission standards, there are no 

new information collection costs, as the information required by this 

proposed rule is already collected and reported by other regulatory 

programs. The recordkeeping and reporting requirements are 
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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 EPA believes that electric power companies will choose to 

build new EGUs that comply with the regulatory requirements of this 

proposal because of existing and expected market conditions. The EPA 

does not project any new coal-fired EGUs that commence construction 

after this proposal to commence operation over the 3-year period 

covered by this ICR. We estimate that 17 new affected NGCC units 

would commence operation during that time period. As a result of this 

proposal, those units would be required to prepare a summary report, 

which includes reporting of excess emissions and downtime, every 6 

months.

 When a malfunction occurs, sources must report them according to 

the applicable reporting requirements of 40 CFR part 60, subpart 

TTTT. An affirmative defense to civil penalties for exceedances of 

emission limits that are caused by malfunctions is available to a 

source if it can demonstrate that certain criteria and requirements 

are satisfied. The criteria ensure that the affirmative defense is 

available only where the event that causes an exceedance of the 
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emission limit meets the narrow definition of malfunction (sudden, 

infrequent, not reasonable preventable, and not caused by poor 

maintenance and or careless operation) and where the source took 

necessary actions to minimize emissions. In addition, the source must 

meet certain notification and reporting requirements. For example, 

the source must prepare a written root cause analysis and submit a 

written report to the Administrator documenting that it has met the 

conditions and requirements for assertion of the affirmative defense. 

To provide the public with an estimate of the relative magnitude 

of the burden associated with an assertion of the affirmative defense 

position adopted by a source, the EPA has estimated what the 

notification, recordkeeping, and reporting requirements associated 

with the assertion of the affirmative defense might entail. The EPA’s 

estimate for the required notification, reports, and records, 

including the root cause analysis, associated with a single incident 

totals approximately totals $3,141, and is based on the time and 

effort required of a source to review relevant data, interview plant 

employees, and document the events surrounding a malfunction that has 

caused an exceedance of an emission limit. The estimate also includes 

time to produce and retain the record and reports for submission to 

the EPA. The EPA provides this illustrative estimate of this burden, 
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because these costs are only incurred if there has been a violation, 

and a source chooses to take advantage of the affirmative defense.

 The EPA provides this illustrative estimate of this burden 

because these costs are only incurred if there has been a violation 

and a source chooses to take advantage of the affirmative defense. 

Given the variety of circumstances under which malfunctions could 

occur, as well as differences among sources' operation and 

maintenance practices, we cannot reliably predict the severity and 

frequency of malfunction-related excess emissions events for a 

particular source. It is important to note that the EPA has no basis 

currently for estimating the number of malfunctions that would 

qualify for an affirmative defense. Current historical records would 

be an inappropriate basis, as source owners or operators previously 

operated their facilities in recognition that they were exempt from 

the requirement to comply with emissions standards during 

malfunctions. Of the number of excess emissions events reported by 

source operators, only a small number would be expected to result 

from a malfunction (based on the definition above), and only a subset 

of excess emissions caused by malfunctions would result in the source 

choosing to assert the affirmative defense. Thus, we believe the 

number of instances in which source operators might be expected to 

avail themselves of the affirmative defense will be extremely small. 
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In fact, we estimate that there will be no such occurrences for any 

new sources subject to 40 CFR part 60, subpart TTTT over the 3-year 

period covered by this ICR. We expect to gather information on such 

events in the future, and will revise this estimate as better 

information becomes available.

 The annual information collection burden for this collection 

consists only of reporting burden as explained above. The reporting 

burden for this collection (averaged over the first 3 years after the 

effective date of the standards) is estimated to be $15,570 and 396 

labor hours. This estimate includes semi-annual summary reports which 

include reporting of excess emissions and downtime. All burden 

estimates are in 2010 dollars. Average burden hours per response are 

estimated to be 16.5 hours. The total number of respondents over the 

3-year ICR period is estimated to be 36. Burden is defined at 5 CFR 

1320.3(b).

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 EPA's regulations in 40 CFR are listed in 40 CFR part 9.

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 
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docket for this rule, which includes this ICR, under Docket ID number 

EPA-HQ-OAR-2011-0660. Submit any comments related to the ICR to EPA 

and OMB. See ADDRESSES section at the beginning of this notice for 

where to submit comments to the EPA. Send comments to OMB at the 

Office of Information and Regulatory Affairs, Office of Management 

and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Officer for 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 as Amended by the Small Business 

Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq.

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 
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small businesses, small organizations, and small governmental 

jurisdictions.

For purposes of assessing the impacts of this rule on small 

entities, small entity is defined as: 

(1) A small business that is defined by the SBA’s regulations at 

13 CFR 121.201 (for the electric power generation industry, the small 

business size standard is an ultimate parent entity defined as having 

a total electric output of 4 million MWh or less in the previous 

fiscal year. The NAICS codes for the affected industry are in Table 4 

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 4. Potentially Regulated Categories and Entitiesa

Category NAICS 

Code

Examples of Potentially Regulated 

Entities

Industry 221112 Fossil fuel electric power generating 

units.
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Federal 

Government

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government

221112b Fossil fuel electric power generating 

units owned by municipalities.

Tribal 

Government 921150 Fossil fuel electric power generating units in Indian Country.

a Include NAICS categories for source categories that own and operate 

electric power generating units (includes boilers and stationary 

combined cycle combustion turbines).

b Federal, 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.

We do not include an analysis of the illustrative impacts on 

small entities that may result from implementation of this proposed 

rule because we do not anticipate any compliance costs over a range 

of likely sensitivity conditions as a result of this proposal. Thus 

the cost-to-sales ratios for any affected small entity would be zero 

costs as compared to annual sales revenue for the entity. The EPA 

believes that electric power companies will choose to build new EGUs 

that comply with the regulatory requirements of this proposal because 

of existing and expected market conditions. (See the RIA for further 
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discussion of sensitivities.) Because our modeling shows that natural 

gas-fired plants are the facilities of choice, the proposed standard 

of performance –– which is based on the emission rate of a new NGCC 

unit –– would not add costs. The EPA does not project any new coalfired EGUs without CCS to be built. Accordingly, there are no 

anticipated economic impacts as a result of this proposal. 

Nevertheless, the EPA is aware that there is substantial 

interest in this rule among small entities (municipal and rural 

electric cooperatives). In light of this interest, the EPA determined 

to seek early input from representatives of small entities while 

formulating the provisions of this proposed regulation. Such outreach 

is also consistent with the President’s January 18, 2011 Memorandum 

on Regulatory Flexibility, Small Business, and Job Creation, which 

emphasizes the important role small businesses play in the American 

economy. This process has enabled the EPA to hear directly from these 

representatives, at a very preliminary stage, about how it should 

approach the complex question of how to apply Section 111 of the CAA 

to the regulation of GHGs from these source categories. The EPA’s

outreach regarded planned actions for new and existing sources, but 

only new sources would be affected by this proposed action.

The EPA conducted an initial outreach meeting with small entity 

representatives on April 6, 2011. The purpose of the meeting was to 
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provide an overview of recent EPA proposals impacting the power 

sector. Specifically, overviews of the Transport Rule, the Mercury 

and Air Toxics Standards, and the Clean Water Act 316(b) Rule 

proposals were presented.

The EPA conducted outreach with representatives from 20 various 

small entities that potentially would be affected by this rule. The 

representatives included small entity municipalities, cooperatives, 

and private investors. We distributed outreach materials to the small 

entity representatives; these materials included background, an 

overview of affected sources and GHG emissions from the power sector, 

an overview of CAA section 111, an assessment of CO2 emissions control 

technologies, potential impacts on small entities, and a summary of 

the listening sessions. We met with eight of the small entity 

representatives, as well as three participants from organizations 

representing power producers, on June 17, 2011, to discuss the 

outreach materials, potential requirements of the rule, and 

regulatory areas where the EPA has discretion and could potentially 

provide flexibility.

A second outreach meeting was conducted on July 13, 2011. We met 

with nine of the small entity representatives, as well as three 

participants from organizations representing power producers. During 

the second outreach meeting, various small entity representatives and 
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participants from organizations representing power producers 

presented information regarding issues of concern with respect to 

development of standards for GHG emissions. Specifically, topics 

suggested by the small entity representatives and discussed included: 

boilers with limited opportunities for efficiency improvements due to 

NSR complications for conventional pollutants; variances per 

kilowatt-hour and in heat rates over monthly and annual operations; 

significance of plant age; legal issues; importance of future 

determination of carbon neutrality of biomass; and differences 

between municipal government electric utilities and other utilities.

 Small entities expressed concern regarding units making 

modifications being regulated as new sources. As explained above, we 

are not proposing a standard of performance for modifications. As a 

result, sources that undertake modifications would be treated as 

existing sources and thus would not be subject to the requirements 

proposed in this notice. As also explained above, the EPA is not 

proposing standards of performance for existing proposed EGUs, which 

are referred to as transitional sources, that have acquired a

complete preconstruction permit by the time of this proposal and that 

commence construction within 12 months of this proposal. As a result, 

any transitional sources owned by small entities would not be subject 

to the standards of performance proposed in today’s rule.
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 We invite comments on all aspects of the proposal and its 

impacts, including potential adverse impacts, on small entities.

D. Unfunded Mandates Reform Act of 1995

This proposed rule 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. The EPA believes this proposed rule will have no compliance costs 

associated with it over a range of likely sensitivity conditions 

because electric power companies will choose to build new EGUs that 

comply with the regulatory requirements of this proposal because of 

existing and expected market conditions. (See the RIA for further 

discussion of sensitivities.) As previously explained, because our

modeling shows that natural gas-fired plants are the facilities of 

choice, the proposed standard of performance –– which is based on the 

emission rate of a new NGCC unit –– would not add costs. The EPA does 

not project any new coal-fired EGUs without CCS to be built. Thus, this 

proposed rule is not subject to the requirements of sections 202 or 205 

of UMRA.

 This proposed rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory requirements 

that might significantly or uniquely affect small governments.

In light of the interest in this rule among governmental 
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entities, the EPA initiated consultations with governmental entities. 

The EPA invited the following 10 national organizations representing 

state and local elected officials to a meeting held on April 12, 

2011, in Washington DC: 1) National Governors Association; 2) 

National Conference of State Legislatures, 3) Council of State 

Governments, 4) National League of Cities, 5) U.S. Conference of 

Mayors, 6) National Association of Counties, 7) International 

City/County Management Association, 8) National Association of Towns 

and Townships, 9) County Executives of America, and 10) Environmental 

Council of States. These 10 organizations representing elected state 

and local officials have been identified by the EPA as the “Big 10” 

organizations appropriate to contact for purpose of consultation with 

elected officials. The purposes of the consultation were to provide 

general background on the proposal, answer questions, and solicit 

input from state/local governments. The EPA’s consultation regarded 

planned actions for new and existing sources, but only new sources 

would be affected by this proposed action.

During the meeting, officials asked clarifying questions 

regarding CAA section 111 requirements and efficiency improvements 

that would reduce CO2 emissions. In addition, they expressed concern 

with regard to the potential burden associated with impacts on state 

and local entities that own/operate affected utility boilers, as well 
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as on state and local entities with regard to implementing the rule. 

Subsequent to the April 12, 2011 meeting, the EPA received a letter 

from the National Conference of State Legislatures. In that letter, 

the National Conference of State Legislatures urged the EPA to ensure 

that the choice of regulatory options maximizes benefit and minimizes 

implementation and compliance costs on state and local governments; 

to pay particular attention to options that would provide states with 

as much flexibility as possible; and to take into consideration the 

constraints of the state legislative calendars and ensure that 

sufficient time is allowed for state actions necessary to come into 

compliance.

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. Thus, Executive 

Order 13132 does not apply to this action. The EPA consulted with 

state and local officials in the process of developing the proposed 

rule to permit them to have meaningful and timely input into its 
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development. The EPA’s consultation regarded planned actions for new 

and existing sources, but only new sources would be affected by this 

proposed action. The EPA met with 10 national organizations 

representing state and local elected officials to provide general 

background on the proposal, answer questions, and solicit input from 

state/local governments. The UMRA discussion in this preamble 

includes a description of the consultation. In the spirit of EO 

13132, and consistent with EPA policy to promote communications 

between the EPA and state and local governments, the EPA specifically 

solicits comment on this proposed action from state and local 

officials.

F. Executive Order 13175, Consultation and Coordination with Indian 

Tribal Governments

Subject to the EO 13175 (65 FR 67249, November 9, 2000) the EPA 

may not issue a regulation that has tribal implications, that imposes 

substantial direct compliance costs, and that is not required by 

statute, unless the Federal government provides the funds necessary 

to pay the direct compliance costs incurred by tribal governments, or 

the EPA consults with tribal officials early in the process of 

developing the proposed regulation and develops a tribal summary 

impact statement. 
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The EPA has concluded that this proposed action would not have 

tribal implications. It would neither impose substantial direct 

compliance costs on tribal governments, nor preempt Tribal law. This 

proposed rule would impose requirements on owners and operators of 

new EGUs. The EPA is aware of three coal-fired EGUs located in Indian 

Country but is not aware of any EGUs owned or operated by tribal 

entities. The EPA notes that this proposal does not affect existing 

sources such as the three coal-fired EGUs located in Indian Country, 

but addresses CO2 emissions for new EGU sources only.

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 this 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, 

but only new sources would be affected by this proposed action.

Consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA’s development of NSPS 

and emission guidelines for EGUs and offered consultation. A 

consultation/outreach meeting was held on May 23, 2011, with the 

Forest County Potawatomi Community, the Fond du Lac Band of Lake 

Superior Chippewa Reservation, and the Leech Lake Band of Ojibwe. 

Other tribes participated in the call for information gathering 
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purposes. In this meeting, the EPA provided background information on 

the GHG emission standards to be developed and a summary of issues 

being explored by the Agency. Tribes suggested that the EPA consider 

expanding coverage of the GHG standards to include combustion 

turbines, lowering the 250 MMBtu per hour heat input threshold so as 

to capture more EGUs, and including credit for use of renewables. The 

tribes were also interested in the scope of the emissions averaging 

being considered by the Agency (e.g., over what time period, across 

what units). In addition, the EPA held a series of listening sessions 

on this proposed action. Tribes participated in a session on February 

17, 2011 with the state agencies, as well as in a separate session 

with tribes on April 20, 2011.

The EPA will also hold additional meetings with tribal 

environmental staff to inform them of the content of this proposal as 

well as provide additional consultation with tribal elected officials 

where it is appropriate. We specifically solicit additional comment 

on this proposed rule from tribal officials.

G. Executive Order 13045, Protection of Children from Environmental 

Health Risks and Safety Risks

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that concern health or safety 
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risks, such that the analysis required under section 5-501 of the 

Order has the potential to influence the regulation. This proposed 

action is not subject to EO 13045 because it is based solely on 

technology performance. The proposal is not expected to produce

notable changes in emissions of greenhouse gases or other pollutants 

but does encourage the current trend towards cleaner 

generation, helping to protect air quality and children's health. The 

Agency recognizes that children are among the groups most vulnerable 

to climate change impacts and the public is invited to submit 

comments or identify peer reviewed studies relevant to this proposal.

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This proposed action is not a “significant energy action” as 

defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it is not 

likely to have a significant adverse effect on the supply, 

distribution, or use of energy. This proposed action is not 

anticipated to have notable impacts on emissions, costs or energy 

supply decisions for the affected electric utility industry.

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 
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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 involves technical standards. The EPA 

cites the following standards in this proposed rule: D5287-08 

(Standard Practice for Automatic Sampling of Gaseous Fuels), D4057-06 

(Standard Practice for Manual Sampling of Petroleum and Petroleum 

Products), and D4177-95(2010) (Standard Practice for Automatic 

Sampling of Petroleum and Petroleum Products). The EPA is proposing 

use of Appendices B, D, F, and G to 40 CFR part 75; these Appendices 

contain standards that have already been reviewed under the NTTAA.

 The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable VCS and to explain why such standards should 

be used in this action.

J. Executive Order 12898: Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations
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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.

 The EPA has determined that this proposed rule would not result 

in disproportionately high and adverse human health or environmental 

effects on minority or low-income populations, because it would 

increase the level of environmental protection for all affected 

populations without having any disproportionately high and adverse 

human health or environmental effects on any population, including 

any minority or low-income population. 

These proposed standards would improve public health and welfare 

in the future by providing legal assurance that primary CO2 emissions 

from newly constructed electric generating units potentially 

contributing to climate change and ocean acidification are limited to 

the levels proposed in this rulemaking. Reduced CO2 emissions from the 

power sector would benefit all populations. However, within 

communities experiencing climate change, certain parts of the 
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population may be especially vulnerable to its adverse effects; these 

include the poor, the elderly, those already in poor health, the 

disabled, and indigenous populations dependent on one or a few 

resources. In addition, the U.S. Climate Change Science Program 

stated as one of its conclusions: ”The United States is certainly 

capable of adapting to the collective impacts of climate change. 

However, there will still be certain individuals and locations where 

the adaptive capacity is less and these individuals and their 

communities will be disproportionately impacted by climate change.” 

These specific sub-populations may receive particularly important 

benefits from reductions in GHGs.
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List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and 

procedure, Air pollution control, Incorporation by reference, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

___________________

Dated:[add signature date]

____________________

Lisa P. Jackson,

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:

PART 60 -- [AMENDED]

1. The authority citation for part 60 continues to read as 

follows:

Authority: 42 U.S.C. 7401, et seq.

2. Part 60 is amended by adding subpart TTTT to read as follows:

Subpart TTTT Standards of Performance for Greenhouse Gas Emissions 

for Electric Utility Generating Units 

Sec.

Applicability

§60.5508 What is the purpose of this subpart?

§60.5509 Am I subject to this subpart?

§60.5510 What is the affected EGU of this subpart?

Emissions Standards

§60.5515 What greenhouse gases are regulated by this subpart?

§60.5520 What CO2 emissions standards must I meet?

General Compliance Requirements

§60.5525 What are my general requirements for complying with this 

subpart? 

§60.5530 Affirmative Defense for Exceedance of Emission Limit During 

Malfunction

Monitoring and Compliance Determination Procedures 

§60.5535 How do I monitor and collect data to demonstrate 
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compliance? 

§60.5540 How do I demonstrate compliance and determine excess 

emissions with my CO2 emissions limit?

Notifications, Reports, and Records

60.5550 What notifications must I submit and when?

60.5555 What reports must I submit and when?

60.5560 What records must I keep?

60.5565 In what form and how long must I keep my records?

Other Requirements and Information

§60.5570 What parts of the General Provisions apply to me?

§60.5575 Who implements and enforces this subpart?

§60.5580 What definitions apply to this subpart?

Applicability

§60.5508 What is the purpose of this subpart?

This subpart establishes emission standards and compliance 

schedules for the control of greenhouse gas (GHG) emissions from 

electric utility generating units that commenced construction after 

[INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL

REGISTER].

§60.5509 Am I subject to this subpart?

You are subject to this subpart if you own or operate an 

electric utility generating unit that commences construction after 

[INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL 

REGISTER] with a base load rating of more than 73 megawatts (MW) (250 

million British thermal units per hour (MMBtu/h)) heat input of 
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fossil fuel except as specified under §60.5510(b).

§60.5510 What is the affected source of this subpart?

(a) The affected facility to which this subpart applies is each 

electric utility generating unit (EGU) except as provided for in 

paragraph (b) of this section.

(b) An electric utility generating unit that meets the 

conditions specified in paragraphs (b)(1) through (b)(3) of this 

section is exempt from this subpart.

(1) A steam electric generating unit that meets the definition 

of municipal waste combustor unit and is subject to subpart Eb of 

this part.

(2) A steam electric generating unit that meets the definition 

of a commercial or industrial solid waste incineration unit and is 

subject to subpart CCCC of this part.

(3) Transitional sources.

(i) You are not subject to this subpart if you own or operate a 

transitional source that commences construction within 12 months 

after [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE 

FEDERAL REGISTER].

(ii) For purposes of this subsection, a “transitional source” 

is defined as an EGU with a base load rating of more than 73 

megawatts (MW) (250 million British thermal units per hour (MMBtu/h)) 
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heat input of fossil fuel, except as provided for in §60.5510(b)(1) 

and (2), and that received a complete permit that meets the 

requirements of the Prevention of Significant Deterioration Program 

under part C of Title I of the Clean Air Act prior to [INSERT DATE OF 

THIS PROPOSED RULE IN THE FEDERAL REGISTER] (or that had an approved 

PSD permit that has expired and is in the process of being extended, 

if the source is participating in a Department of Energy CCS funding 

program).

Emissions Standards

§60.5515 What greenhouse gases are regulated by this subpart?

The greenhouse gas regulated by this subpart is carbon dioxide 

(CO2).

§60.5520 What CO2 emissions standards must I meet?

(a) You must not discharge any gases that contain CO2 from any 

affected EGU into the atmosphere in excess of 454 kilograms (kg) of 

CO2 per gross output in Megawatt-hours (MWh) (454 kg/MWh) (1,000 

lb/MWh) on a 12-operating month annual average basis, except as 

provided for in paragraphs (b) through (d) of this section.

(b) If the affected EGU utilizes coal or petroleum coke for fuel 

and is designed to allow installation and operation of a carbon 

capture and storage (CCS) system, you may comply with each standard 

in paragraphs (b)(1)-(3) as an alternative to complying with 
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paragraph (a) of this section.

(1) For each year until the 11th year of operation, you must not 

discharge any gases that contain CO2 from the affected EGU into the 

atmosphere in excess of 816 kg/MWh (1,800 lb/MWh) gross output on a 

12-operating month annual average basis, and

(2) Beginning with the 11th year of operation, the CCS system 

must be operational and you must not discharge any gases that contain 

CO2 from the affected EGU into the atmosphere in excess of 272 kg/MWh 

(600 lb/MWh) gross output on a 12-operating month annual average

basis, and

(3) You must not discharge any gases that contain CO2 from the 

affected EGU into the atmosphere in excess of 454 kg/MWh gross output 

on a 30-year average basis.

(c) Electric utility generating units located in a noncontinental area are not subject to the requirements of this subpart.

(d) Simple cycle combustion turbines are not subject to the 

requirements of this subpart.

General Compliance Requirements

§60.5525 What are my general requirements for complying with this 

subpart?

(a) You must be in compliance with the emissions limits in this 

subpart applicable to your affected EGU. These limits apply at all 
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times.

(b) At all times you must operate and maintain each affected 

EGU, including associated equipment and monitoring equipment, in a 

manner consistent with safety and good practices for minimizing CO2

emissions. Determination of whether such operation and maintenance 

procedures are being used will be based on information available to 

the Administrator which may include, but is not limited to, fuel use 

records, monitoring results, review of operation and maintenance 

procedures, review of operation and maintenance records, review of 

reports required by this subpart, and inspection of the facility.

(c) For each affected EGU subject to the CO2 emissions limits in 

§60.5520, you must measure or calculate a 12 month rolling average CO2

emission rate, calculated per calendar month, in terms of tons/MWh.

(1) If your EGU is subject to the requirements of 40 CFR part 

75.10(a)(3)(i), you must use the CO2 CEMS to measure the 12 month 

rolling average CO2 emissions rate.

(d) You must conduct an initial compliance determination for 

your affected EGU according to the requirements in this subpart 

within 30 days following the first day of the 13th operating month 

following the date of initial operations. Thereafter, you must 

demonstrate continuous compliance according to the requirements in 

this subpart each calendar month determined to be an operating month.
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§60.5530 Affirmative Defense for Exceedance of Emission Limit During 

Malfunction.

In response to an action to enforce the standards you may assert 

an affirmative defense to a claim for civil penalties for exceedances 

of such standards that are caused by malfunction, as defined at 40 

CFR 60.2. Appropriate penalties may be assessed, however, if the 

respondent fails to meet its burden of proving all of the 

requirements in the affirmative defense. The affirmative defense 

shall not be available for claims for injunctive relief.

(a) To establish the affirmative defense in any action to 

enforce such a limit, the owners or operators of facilities must 

timely meet the notification requirements in paragraph (b) of this 

section, and must prove by a preponderance of evidence that:

(1) The excess emissions:

(i) Were caused by a sudden, infrequent, and unavoidable failure 

of air pollution control and monitoring equipment, process equipment, 

or a process to operate in a normal or usual manner; 

(ii) Could not have been prevented through careful planning, 

proper design or better operation and maintenance practices; and

(iii) Did not result from any activity or event that could have 

been foreseen and avoided, or planned for; and

(iv) Were not part of a recurring pattern indicative of 
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inadequate design, operation, or maintenance;

(2) Repairs were made as expeditiously as practicable when the 

applicable emission limitations were being exceeded. Off-shift and 

overtime labor were used, to the extent practicable to make these 

repairs;

(3) The frequency, amount and duration of the excess emissions 

(including any bypass) were minimized to the maximum extent 

practicable during periods of such emissions;

(4) If the excess emissions resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to prevent 

loss of life, personal injury, or severe property damage;

(5) All practicable steps were taken to minimize the impact of 

the excess emissions on ambient air quality, the environment and 

human health;

(6) All emissions monitoring and control systems were kept in 

operation if at all practicable, consistent with safety and good air 

pollution control practices;

(7) All of the actions in response to the excess emissions were 

documented by properly signed, contemporaneous operating logs;

(8) At all times, the facility was operated in a manner 

consistent with good practices for minimizing emissions; and

(9) A written root cause analysis has been prepared, the purpose 
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of which is to determine, correct, and eliminate the primary causes 

of the malfunction and the excess emissions resulting from the 

malfunction event at issue. The analysis shall also specify, using 

best monitoring methods and engineering judgment, the amount of 

excess emissions that were the result of the malfunction.

(b) The owner or operator of an affected EGU experiencing an 

exceedance of its emission limit(s) during a malfunction shall notify 

the Administrator by telephone or facsimile (FAX) transmission as 

soon as practicable, but no later than two (2) business days after 

the initial occurrence of the malfunction, if it wishes to avail 

itself of an affirmative defense to civil penalties for that 

malfunction. The owner or operator seeking to assert an affirmative 

defense shall also submit a written report to the Administrator 

within 45 days of the initial occurrence of the exceedance of the 

standard to demonstrate, with all necessary supporting documentation, 

that it has met the requirements set forth in paragraph (a) of this 

section. The owner or operator may seek an extension of this deadline 

for up to 30 additional days by submitting a written request to the 

Administrator before the expiration of the 45-day period. Until a 

request for an extension has been approved by the Administrator, the 

owner or operator is subject to the requirement to submit such report 

within 45 days of the initial occurrence of the exceedances.
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Monitoring and Compliance Determination Procedures 

§60.5535 How do I monitor and collect data to demonstrate compliance?

(a) You must prepare a site-specific monitoring plan that 

addresses the monitoring system design, data collection and the 

quality assurance and quality control elements consistent with the 

applicable requirements in §60.13, 40 CFR part 75, and this section.

(b) Follow the applicable quality assurance procedures for CO2 

emissions in appendices B, D, and G to 40 CFR part 75.

(c) If you determine the your affected EGU’s CO2 mass emissions 

rate by monitoring fuel combusted in the affected EGU and periodic 

fuel sampling as allowed under §60.5525(c)(2), you must use the 

procedures specified in 40CFR Part 75, Appendix G.

(1) Determine a site-specific F factor using the ultimate 

analysis and GCV in equation F-7a of 40 CFR part 75, Appendix F; and

(2) Monitor and determine the affected EGU’s daily fuel 

consumption for each type of fuel combusted in the affected EGU.

(3) Use ASTM D5287-08 (Standard Practice for Automatic Sampling 

of Gaseous Fuels) to collect a representative gaseous fuel sample.

(4) Use one of the following methods to collect a representative 

liquid oil fuel sample:

(i) ASTM D4057-06 (Standard Practice for Manual Sampling of 

Petroleum and Petroleum Products) or
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(ii) ASTM D4177-95(2010) (Standard Practice for Automatic 

Sampling of Petroleum and Petroleum Products).

(d) You must monitor and record the applicable data needed to 

determine your affected EGU’s gross output for each operating month.

(e) Follow the applicable missing data substitution procedures 

in 40 CFR part 75 for CO2 concentration, stack gas flow rate, fuel 

flow rate, high heating value, and fuel carbon content.

§60.5540 How do I demonstrate compliance and determine excess 

emissions with my CO2 emissions limit?

(a) If you use a CO2 CEMS to demonstrate compliance you must use 

the procedure specified in paragraphs (a)(1) through (5) of this 

section to determine the 12-operating month rolling average CO2

emissions rate for your affected EGU.

(1) Calculate hourly CO2 mass emissions for each hour of the 

operating month in terms of kilograms CO2 using CFR 40 Part 75 

Appendix G.

(2) Determine hourly gross output in terms of MWh for each hour 

of the operating month.

(3) Sum the hourly CO2 mass emissions for the operating month, 

and sum the hourly gross output for the operating month.

(4) Divide the total CO2 mass emissions calculated for the month 

by the total hourly gross output calculated for the operating month.
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(5) Add the quotient to the sum of the quotients of the previous 

11 operating months and divide by 12 to determine the 12-operating 

month rolling average.

(6) If the 12-operating month rolling average value does not 

exceed the applicable emissions limit in §60.5520, your affected EGU 

is determined to be in compliance with the emissions limit. 

Otherwise, your affected EGU is determined to have excess emissions.

(b) If you use fuel sampling to demonstrate compliance, you must 

use the procedure specified in paragraphs (b)(1) through (5) of this 

section to determine the 12-operating month rolling average CO2

emissions rate for your affected EGU.

(1) Calculate monthly CO2 mass emissions by multiplying the 

monthly F factor by the monthly fuel consumption.

(2) Sum the hourly gross output in terms of MWh for the month.

(3) Divide the monthly CO2 mass emissions by the sum of the 

hourly gross output for the month.

(4) Add the quotient to the sum of the quotients of the previous 

11 operating months to determine the 12-operating month rolling 

average.

(5) If the 12-operating month rolling average value does not 

exceed the applicable emissions limit in §60.5520, your affected EGU 

is determined to be in compliance with the emissions limit. 
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Otherwise, your affected EGU is determined to have excess emissions.

(c) If you elect to comply with §60.5520(b), the 30-year average 

CO2 emissions rate for your affected EGU is the sum of the monthly CO2

emissions for each operating month for the 30-year period divided by 

the sum of the monthly gross output in terms of MWh for the 30-year 

period. Use the procedure specified in paragraphs (c)(1) through (4) 

of this section to determine the 12-month annual average CO2 emissions 

rate for your affected EGU.

(1) If you do not use a CO2 CERMS to demonstrate compliance with 

§60.5520(b), you must calculate hourly CO2 mass emissions for each 

hour of the 12-month annual period in terms of kilograms CO2 using CFR 

40 Part 75 Appendix G. If you use a CO2 CERMS to demonstrate 

compliance with §60.5520(b) you must calculate hourly CO2 mass 

emissions for each hour of the 12-month annual period in terms of 

kilograms CO2 using the CERMS hourly mass emissions measurements.

(2) Determine hourly gross output in terms of MWh for each hour 

of the 12-month annual period.

(3) Sum the hourly CO2 mass emissions for the 12-month annual 

operating period, and sum the hourly gross output for the 12-month 

annual operating period.

(4) Divide the total CO2 mass emissions calculated for the 12-

month annual operating period by the total hourly gross output 
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calculated for the 12-month annual operating period.

(5) If the 12-month annual average value does not exceed the 

applicable emissions limit in §60.5520, your affected EGU is 

determined to be in compliance with the emissions limit. Otherwise, 

your affected EGU is determined to have excess emissions.

Notification, Reports, and Records

§60.5550 What notifications must I submit and when?

(a) You must prepare and submit notifications specified in 

§60.7(a) and §60.19, as applicable to your affected EGU.

(b) You must prepare and submit notifications specified in 40 

CFR part 75.61, as applicable to your affected EGU.

§60.5555 What reports must I submit and when?

(a) You must prepare and submit reports specified in §60.7(c) 

through (e) and §60.19, as applicable to your affected EGU. All 

reports required under §60.7 must be submitted by the 30th day 

following the end of each 6-month period.

(1) The excess emissions and continuous monitoring systems 

performance reports and-or summary report forms required in §60.7(c) 

must be submitted to EPA’s WebFIRE database by using the Compliance 

and Emissions Data Reporting Interface (CEDRI) that is accessed 

through EPA’s Central Data Exchange (CDX)(www.epa.gov/cdx). In CEDRI, 
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the owner or operator shall use the appropriate electronic reporting 

form for this subpart or provide an alternate electronic file 

consistent with EPA’s form output format.

(b) You must follow the applicable reporting requirements and 

submit reports as required in subpart G of 40 CFR part 75. You must 

report CO2 mass emissions data, and other related data electronically 

using the Emissions Collection and Monitoring Plan System (ECMPS).

§60.5560 What records must I maintain?

(a) You must maintain records of your information used to 

demonstrate compliance with this subpart as specified in §60.7 (b) 

and (f).

(1) Notwithstanding the requirements of this section you do not 

need to maintain records of the reports that have been submitted to 

EPA’s WebFIRE database as required in §60.5555(a)(1).

(b) You must follow the applicable recordkeeping requirements 

and maintain records as required in subpart F of 40 CFR part 75.

(c) If you determine the CO2 mass emissions rate by monitoring 

fuel combusted in an affected EGU and periodic fuel sampling 

according to the requirements in this rule then you must maintain 

records of fuel type and quantity combusted in the affected EGU for 

each operating month the information specified in paragraphs (c) (1) 

and (2) of this section.
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(1) Records of fuel type and quantity combusted in the affected 

EGU for each operating month.

(2) Records of the calculations performed to determine the sitespecific F factor and monthly total CO2 mass emissions rates.

(d) Records of the applicable data recorded and calculations 

performed used to determine your affected EGU’s gross output for each 

operating month.

§60.5565 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily 

available for expeditious review.

(b) You must keep each record for 5 years following the date of 

each occurrence, measurement, maintenance, corrective action, report, 

or record except those records required to demonstrate compliance 

with the emissions limits in §60.5520(b). Records required to 

demonstrate compliance with the emissions limits in §60.5520(b) must 

be kept for at least 40 years following the date of initial startup 

of the affected EGU.

(c) You must keep each record on site for at least 2 years after 

the date of each occurrence, measurement, maintenance, corrective 

action, report, or record, according to §60.10. You can keep the 

records off site for the remaining years as required by this subpart.

Other Requirements and Information
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§60.5570 What parts of the General Provisions apply to me?

Table 1 to this subpart shows which parts of the General 

Provisions in §§60.1 through 60.19 apply to you.

§60.5575 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by EPA, or a 

delegated authority such as your state, local, or tribal agency. If 

the Administrator has delegated authority to your state, local, or 

tribal agency, then that agency (as well as the EPA) has the 

authority to implement and enforce this subpart. You should contact 

your EPA Regional Office to find out if this subpart is delegated to 

your state, local, or tribal agency.

(b) In delegating implementation and enforcement authority of 

this subpart to a state, local, or tribal agency, the authorities 

listed in paragraphs (b)(1) through (5) of this section are retained 

by the Administrator and are not transferred to the state, local, or 

tribal agency; however, the EPA retains oversight of this subpart and 

can take enforcement actions, as appropriate.

(1) Approval of alternatives to the emission standards.

(2) Approval of major alternatives to test methods.

(3) Approval of major alternatives to monitoring.

(4) Approval of major alternatives to recordkeeping and 

reporting.
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(5) Performance test and data reduction waivers under §60.8(b).

§60.5580 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 subpart A (General 

Provisions of this part.

Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the merits 

of which are independently and objectively evaluated in a judicial or 

administrative proceeding.

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 means 100 percent of the design heat input capacity 

of the stationary combustion turbine engine at ISO conditions.

Carbon capture and storage (CCS) means a process that includes 

capture and compression of CO2 produced by an electric utility 

generating unit before release to the atmosphere; transport of the 

captured CO2 (usually in pipelines); and storage of that CO2 in 

geologic formations, such as deep saline formations, oil and gas 

reservoirs, and unmineable coal seams.
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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.

Coal refuse means waste products of coal mining, physical coal 

cleaning, and coal preparation operations ( e.g. culm, gob, etc.) 

containing coal, matrix material, clay, and other organic and 

inorganic material.

Combined cycle means a stationary turbine combustion system 

where heat from the turbine exhaust gases is recovered by a heat 

recovery steam generating unit.

Combined heat and power, also known as “cogeneration,” means a 

steam-generating unit that simultaneously produces both electric (and 

mechanical) and useful thermal energy from the same primary energy 

source.

Distillate oil means fuel oils that contain 0.05 weight percent 

nitrogen or less and comply with the specifications for fuel oil 

numbers 1 and 2, as defined by the American Society of Testing and 
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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 

blends as defined by the American Society of Testing and Materials in 

ASTM D7467 (incorporated by reference, see §60.17).

Electric utility generating unit or EGU means any steam electric 

generating unit or stationary combustion turbine that is constructed 

for the purpose of supplying more than one-third of its potential 

electric output capacity and more than 25 MW net-electrical output to 

any utility power distribution system for sale. Also, any steam 

supplied to a steam distribution system for the purpose of providing 

steam to a steam-electric generator that would produce electrical 

energy for sale is considered in determining the electrical energy 

output capacity of the affected EGU.

Excess emissions means a specified averaging period over which 

the CO2 emissions rate are higher than the applicable emissions

standard.

Federally enforceable means all limitations and conditions that 
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are enforceable by the Administrator, including the requirements of 

40 CFR parts 60 and 61, requirements within any applicable State 

implementation plan, and any permit requirements established under 40 

CFR 52.21 or under 40 CFR 51.18 and 51.24.

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 standard 

conditions and includes, but is not limited to, natural gas, refinery 

fuel gas, process gas, coke-oven gas, synthetic gas, and gasified 

coal.

Gross output means the gross electrical or mechanical output 

from the unit plus 75 percent of the useful thermal output measured 

relative to ISO conditions that is not used to generate additional 

electrical or mechanical output or to enhance the performance of the 

unit (i.e., steam delivered to an industrial process). 

Integrated gasification combined cycle electric utility 

generating unit means an electric utility combined cycle gas turbine 

that is designed to burn fuels containing 50 percent (by heat input) 

or more solid-derived fuel not meeting the definition of natural gas. 

The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system construction or 
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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.

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

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

by volume or that has a gross calorific value between 35 and 41 

megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per 

dry standard cubic foot), that maintains a gaseous state under ISO 

conditions. In addition, natural gas contains 20.0 grains or less of 

total sulfur per 100 standard cubic feet. Finally, natural gas does 

not include the following gaseous fuels: landfill gas, digester gas, 

refinery gas, sour gas, blast furnace gas, 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 gross electric sales to the 

utility power distribution system minus purchased power on a calendar 

year basis.

Non-continental area means the State of Hawaii, the Virgin 

Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or 

the Northern Mariana Islands.

Operating month means a calendar month during which any fuel is 
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combusted in the electric utility generating unit at any time.

Out-of-control period means any period beginning with the 

quadrant corresponding to the completion of a daily calibration 

error, linearity check, or quality assurance audit that indicates 

that the instrument is not measuring and recording within the 

applicable performance specifications and ending with the quadrant 

corresponding to the completion of an additional calibration error, 

linearity check, or quality assurance audit following corrective 

action that demonstrates that the instrument is measuring and 

recording within the applicable performance specifications.

Potential electric output means 33 percent of the maximum design 

heat input capacity of the steam generating unit, divided by 3,413 

Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr 

(e.g., a steam generating unit with a 100 MW (340 MMBtu/h) fossilfuel heat input capacity would have a 289,080 MWh 12 month potential 

electrical output capacity). 

Simple cycle combustion turbine means a stationary combustion 

turbine that which does not recover heat from the combustion turbine 

exhaust gases for purposes other than enhancing the performance of 

the combustion turbine itself.

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 
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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, the fuel, air, lubrication and exhaust 

gas systems, control systems (except emissions control equipment), 

heat recovery system, fuel compressor, heater, and/or pump, postcombustion emission control technology, and any ancillary components 

and sub-components comprising any simple cycle stationary combustion 

turbine, any combined cycle combustion turbine, and any combined heat 

and power combustion turbine based system. 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. 

Steam electric generating unit means any furnace, boiler, or 

other device used for combusting fuel for the purpose of producing 

steam (including fossil fuel-fired steam generators associated with 

combined cycle gas turbines; nuclear steam generators are not 

included) plus any integrated device that provides electricity or 

useful thermal output to either the boiler or to power auxiliary 

equipment.

Useful thermal output means the thermal energy made available 

for use in any industrial or commercial process, or used in any 
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heating or cooling application, i.e., total thermal energy made 

available for processes and applications other than electrical 

generation or to enhance the performance of the stationary combustion 

turbine. 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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Table 1 to Subpart TTTT of Part 60 – Applicability of Subpart A 

General Provisions to Subpart TTTT

General 

Provisions 

citation

Subject of 

citation

Applies to 

subpart 

TTTT

Explanation

§60.1 Applicability Yes

§60.2 Definitions Yes

Additional terms 

defined in 

§60.5580

§60.3 Units and 

Abbreviations Yes

§60.4 Address Yes

§60.5

Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

Recordkeeping Yes

Except for the

requirements to 

submit written 

excess emissions 

reports under 

§60.7(c)

§60.8 Performance tests No

§60.9 Availability of 

Information Yes

§60.10 State authority Yes
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§60.11

Compliance with 

standards and 

maintenance 

requirements

No

§60.12 Circumvention Yes

§60.13 Monitoring 

requirements Yes

§60.14 Modification No

§60.15 Reconstruction No

§60.16 Priority list No

§60.17 Incorporations by 

reference Yes

§60.18

General control 

device 

requirements

No

§60.19

General 

notification and 

reporting 

requirements

Yes