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EO 12866 EGU GHG NSPS preamble 2060_AQ91 11_04_11.docx

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 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 

for new sources would require new fossil- fuel-fired EGUs greater 

than 25 megawatt electric to meet a standard of 1,000 pounds of CO2

per megawatt hour, based on the performance of widely used natural 

gas combined cycle technology. New coal-fired units could meet the 
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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. 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 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. At a future 

date, EPA intends to promulgate emission guidelines for states to 

develop plans reducing CO2 emissions from existing fossil-fuel-fired 

EGUs.

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 

 

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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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 3 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 

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 hearing 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 
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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, [add 

website address here].

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.

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 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, 
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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 

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 
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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 

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

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

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

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

technical difficulties and cannot contact you for clarification, the 

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

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

free of any defects or viruses.

Docket: All documents in the docket are listed in the 

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

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

whose disclosure is restricted by statute). Certain other material, 

such as copyrighted material, will be publicly available only in hard 

copy. Publicly available docket materials are available either 

electronically in http://www.regulations.gov or in hard copy at the 

EPA Docket Center, 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.
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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: 

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 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
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ASME American Society of Mechanical Engineers

ASTM American Society for Testing of Materials

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

CBI Confidential Business Information

CCS Carbon Capture and Storage

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

EERS Energy Efficiency Resource Standards

EGU Electric Utility Generating Units

EIA Energy Information Administration

EO Executive Order

EOR Enhance 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
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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

OMB Office of Management and Budget

PC Pulverized Coal

PFC Perfluorocarbon

PM Particulate Matter

PM2.5 Fine Particulate Matter

PRA Paperwork Reduction Act

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

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SO2 Sulfur Dioxide

SSM Startup, Shutdown, and Malfunction

Tg Teragram

Tpy Tons per Year

TSD Technical Support Document

TTN Technology Transfer Network

TVA Tennessee Valley Authority

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
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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 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?

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
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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

A. Executive Summary

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-fueled 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

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, 
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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 40 percent of all U.S. anthropogenic GHG 

emissions.2 Individual new power plants powered by coal are among the 

largest individual new sources of GHGs. Furthermore, technology 

exists that can be readily and cost-effectively used to reduce GHG

emissions from these sources. Thus, this proposed rule is a rational 

first step to control GHG emissions from the largest categories of 

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) 

 

2 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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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 

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 TSD7, reasons to reduce GHG emissions include the 

following:

 

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

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

of the Intergovernmental Panel on Climate Change was re-confirmed 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 
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 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.

 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 

 

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.

8 Endangerment Finding, 74 FR 66498.

9 Endangerment Finding, 74 66497.
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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 

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 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 

 

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).

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

14 Endangerment TSD , pp. 76-78 
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atmosphere for time periods ranging from decades to millennia, 

depending on the gas. Greenhouse gases will continue to accumulate in 

the atmosphere at higher and higher concentrations each year unless 

substantial reductions in global 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 steeper the future emissions reductions that will be required to 

limit global temperature increase to any given level.

This proposed rule to reduce 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 

 

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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GHG emissions in the U.S. These sources account for 60 percent of 

U.S. stationary source GHG emissions, and 32 percent of total U.S. 

GHG emissions, based on 2009 data.16

Furthermore, a range of technologies are available to reduce 

these EGU emissions. Most new power 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 therefore generally produce

significantly fewer emissions than existing coal-fired power plants.

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. Coal-fired power plants with CCS are being permitted and 

built today.

There are also opportunities to reduce emissions at existing 

fossil-fired plants. For instance, the efficiency of much of the 

existing generation can be improved, lower emitting plants can be 

dispatched more often, and higher emitting plants can co-fire fuels, 

such as natural gas, with lower CO2 intensity. 

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

overall regulatory requirements for GHG emissions from new fossilfuel-fired power plants at this time is efficient because the EPA has 

 

16 “Inventory of US GHG Emissions and Sinks” (April 2011); “Regulatory Impact 

Analysis for the Mandatory Reporting of Greenhouse Gas Emissions Final Rule 

(GHG Reporting)” (September 2009).
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recently issued regulations to limit conventional pollutants 

(criteria and hazardous air pollutants) from these sources. Aligning 

the timing of these GHG rules with the rules for conventional 

pollutants gives the industry more regulatory certainty, will 

facilitate the industry’s 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 create an incentive 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 
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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 conventional 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 

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 

 

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 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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pollutants from stationary sources. First, the EPA must list 

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).

Clean Air Act section 111 also requires regulation of existing 

sources of certain pollutants – in general, ones that are other than 

NAAQS pollutants or HAPs – and provides the states the authority to 

act as the direct regulators. Regulation of new sources of those 

pollutants triggers a requirement that EPA also promulgate emission 

guidelines for existing sources. The states must then develop 

standards of performance based on those emission guidelines and 

submit those standards in state plans to the EPA for approval. The 
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states have flexibility in applying the standards of performance to 

particular sources. CAA section 111(d)(1).

b. Cause-or-Contribute-Significantly Finding for 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 boilers, including coal-fired boilers, and initially 

regulated them in subpart D of its regulations under CAA section 111. 

Subsequent regulation of utility boilers has been under subpart Da.

The EPA listed combustion turbine engines and initially regulated 

them under subpart GG. The combustion turbine engine portions of 

combined cycle facilities were regulated under subpart GG. Heat 

recovery steam generators 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 heat recovery steam generator. To minimize the 

compliance burden for owners/operators of combined cycle facilities 

some monitoring harmonization was done, but 2 subparts were still 

applicable. In 2005, EPA proposed subpart KKKK as a replacement for 
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subpart GG and specifically covered the entire combined cycle 

facility under subpart KKKK such that only a single set or 

requirements would apply. In that same year, 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 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 solicits comment on 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 
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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 solicits comment on 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 

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

 

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-orContribute-Significantly Finding.”
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5. Summary of Today’s Proposed Requirements to Reduce GHG Emissions 

from New Fossil-Fired Power Plants

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

proposing to combine electric utility steam generating units 

(boilers) (which are currently included in the Da category) and 

combined cycle units (including IGCC 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). Today’s proposed rulemaking would not affect conventional 

air pollutants or simple cycle turbines.

21

b. 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. 

Coal-, coal refuse-, and pet-coke-fired boilers and IGCC units should 

also be able to meet this standard by employing CCS technology. There 

are a number of coal- and pet-coke-fired EGU projects under 

development that include CCS. While a coal unit with CCS may be more 

expensive than NGCC generation, for reasons explained below, we 

 

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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expect the difference to decrease over time as CCS becomes less 

expensive. Accordingly, we include in today’s proposed rulemaking a 

compliance option under which affected sources that implement CCS 

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 also meet an immediate performance standard of 1,800 

lb CO2/MWh (gross), which can be achieved by a “supercritical” 

efficiency level, during the period before installation of CCS. 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.

c. Requirements for Modifications. For purposes of today’s action, 

the EPA is not aware that any affected sources may be expected to 

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

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

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

modifications. 

The EPA’s current regulations define a “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. 
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The actions that we expect EGUs to undertake in the foreseeable 

future that could increase the maximum achievable hourly rate of CO2

emissions will constitute pollution control projects. In many cases, 

those projects will involve the installation of add-on control 

equipment required to meet CAA requirements for conventional air 

pollutants. These increases in CO2 emissions will be small and will 

occur as a chemical byproduct of the operation of the control 

equipment. In other cases, those projects will involve equipment 

changes to meet the requirements of this rulemaking and will have the 

effect of increasing a source’s maximum achievable hourly emission 

rate, even while decreasing its actual emission rate. Because all of 

these actions will be treated as pollution control projects under 

EPA’s current NSPS regulations, they will be specifically exempted 

from the definition of modification. In addition, it is conceivable 

that EGUs may undertake other changes that may increase their 

capacity and, therefore, their maximum achievable hourly emission 

rate. It is possible that those changes would be so capital intensive 

that they would fall into the category of reconstructions, which also 

are not treated as modifications. Historically, it has been rare that 

actions by sources have been treated as modifications under the NSPS 

requirements.
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As a result, the EPA is not aware that any EGUs may reasonably 

be expected to undertake actions that would be defined as 

modifications. The EPA solicits comment on that issue, but in the 

meantime, the EPA is not proposing standards for modifications. The 

EPA does not believe that it currently has adequate information as to 

the types of actions, their costs, or the amount of resulting CO2

emissions, on which to base a proposed standard of performance. 

Therefore, sources that undertake physical or operational changes 

that increase their maximum achievable hourly CO2 emission rate will 

be treated as existing sources and thus not subject to the 

requirements proposed in this notice, although they would be subject 

to requirements that EPA intends to propose separately for existing 

EGUs.

In the alternative, if these actions (i.e., projects that 

involve equipment changes to meet other CAA requirements and any 

other changes that increase maximum achievable emission rate of CO2) 

were considered to be modifications, then the EPA is soliciting 

comment on what the appropriate standard(s) of performance for these 

modifications should be. However, to reiterate, the EPA is not 

proposing any standards of performance for these modifications at 

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

approximately 18 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 are referred to as 

“transitional sources.” We are aware that approximately seven of 

these permitted sources are planning 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”

as, in general, undertaking a continuous program of construction or 

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

Commenters have pointed out that absent an exemption, 

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, and these commenters have suggested that today’s 

proposed rule should treat transitional sources specially, in light 

of the substantial redesign that meeting such a 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, 
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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 that commence 

construction within 12 months of the date of this proposal. Upon 

finalization of this rulemaking without a standard of performance 

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

and therefore will not be 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 

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 the standard of 

performance for new sources.

e. Requirements for Reconstructed sources. 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 
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of the capital costs of an entirely new facility, and (ii) for which 

compliance with standards of performance for new sources is 

technologically and economically feasible. 40 CFR 60.15. 

We are aware that in theory, existing power plants may 

reconstruct, but we are not aware of any that have announced plans to 

do. In addition, at this time the EPA does not have information to 

base a determination of what standards of performance will be 

technologically and economically feasible.

In this proposed action, the EPA is taking comment on two 

different options. Option one would treat reconstructed sources the 

same as any other new source (e.g. subject to an emission limit of 

1,000 lb CO2/MWh). The EPA believes that if the owner of a source 

plans to invest enough capital into an existing unit to reach the 

reconstructed threshold, it is likely with the intent of 

significantly increasing the life of the plant. The EPA does not 

intend to create a policy that would permit or encourage an owner to 

forego building a new clean facility, in favor of merely 

reconstructing an existing facility that operated with higher 

emissions." Alternatively, we are taking comment on a standard of 

1,800 lb CO2/MWh (gross). This would be consistent with the first 

phase requirement for new sources availing themselves of the 

alternative compliance option for new sources. It would represent 
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upgrading the unit to an efficiency level consistent with some of the 

best performing existing units.

6. Summary of Emissions Impacts, Costs and Benefits

We are projecting that there will be no construction of new 

coal-fired generation without CCS even absent this proposed rule. 

Therefore, we do not project that this proposed rule will impose 

costs upon sources. While this proposed rule will not have direct 

impact on U.S. emissions of greenhouse gases, it will send a strong 

signal both domestically and internationally. Domestically, this 

proposed rule will further stimulate investment in CCS technology, by 

making it clear that such technology does provide a clear path 

forward for coal. Internationally, this rule may encourage others to 

consider less GHG-intensive forms of power generation.

B. Does this action apply to me?

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 221112b Fossil fuel electric power generating 
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Government 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. 

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 
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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.”22

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 

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 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 

 

22 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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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).

23 The standard that the EPA develops, based on the BSER, is 

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.

When the EPA establishes standards of performance for new 

sources of a pollutant that, in general, is not regulated under the 

CAA section 109 requirements for NAAQS or regulated under the CAA 

section 112 requirements for HAPs, then, under CAA section 111(d)(1), 

the EPA must issue guidelines for states to regulate existing sources 

 

23 This level of control has historically been referred to as best demonstrated 

technology (BDT).
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in the source category for that pollutant. EPA intends to propose 

those guidelines in a separate rulemaking at a later date. Section 

111(d) provides a different mechanism to regulate existing sources 

than CAA section 111(b) provides for new sources. Instead of giving 

the EPA direct authority to set national standards applicable to 

existing sources, section 111(d)(1) provides that the EPA shall 

establish a procedure similar to the procedure required under CAA 

section 110 (concerning state submission of state implementation 

plans (SIPs) to attain the NAAQS) for states to develop plans that 

include standards of performance for those sources. Under the EPA’s 

regulations implementing section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish binding 

requirements that states are required to address when they develop 

standards of performance for their plans. 40 CFR 60.22. These state

plans must be submitted to the EPA for approval. 40 CFR 60.23. In the 

event that a state does not adopt and submit a plan, or submits a 

plan that the EPA disapproves, the EPA is then obligated to issue a 

federal plan. 40 CFR 60.27(c).

B. Overview of Climate Change Impacts from GHG Emissions
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In 2009, the EPA Administrator issued the 2009 Endangerment 

Finding,24 under CAA section 202(a)(1), as part of the process for 

promulgating the Light Duty Vehicle Rule.25 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, 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 (NRC).26 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.

 

24 "Endangerment and Cause or Contribute Findings for Greenhouse Gases 

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

2009).

25 "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel 

Economy Standards; Final Rule." 75 FR 25324 (May 7, 2010).

26 74 FR 66510-66511.
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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.

Climate change is expected to increase ozone pollution over broad 

areas of the country including large population areas with unhealthy 

ozone levels. Ozone health studies indicate that elevated 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 
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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 

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. 
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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 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 

GHGs, 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
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Since 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 EPA based the Endangerment Finding. In May 

2010, the NRC, which is the operating arm of the NAS that conducts 

most of the science policy and technical work, published its 

comprehensive assessment, “Advancing the Science of Climate Change”

(the 2010 NRC Assessment).27 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.”28 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 

Fourth Assessment Report, and other assessments of the state of 

scientific knowledge on climate change.”29 These are the same 

assessments that served as the primary scientific references 

underlying the 2009 Endangerment Finding. The 2010 NRC Assessment 

 

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

Press. Washington, DC.

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

Press. Washington, DC. Page 3.

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

Press. Washington, DC. Page 286.
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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. 

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 
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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.

C. GHGs from 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 Sinks30 (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 fossilfuel-fired EGUs -- for the years 1990, 2000, and 2009.

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

 

30 “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.
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dioxide equivalent (Tg CO2 Eq.))

31

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 

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.

 

31 From Table 2-3 of the EPA GHG Emissions and Sinks Inventory, EPA 430-R-11-005.
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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. 

Table 3. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (Tg CO2 Eq.)

We are aware that N2O (and to a lesser extent, CH4) may be 

emitted from fossil-fuel-fired EGUs, especially from coal-fired 

circulating fluidized bed combustors and from units with selective 

catalytic reduction and selective non-catalytic reduction 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 cost effective controls would be needed 

before proposing standards for these pollutants. The estimated 

GHG 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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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-fuel-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 conventional 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, 
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Vermont, and Washington, the Commonwealth of Massachusetts, the 

District of Columbia, and the City of New York (collectively ‘‘State

Petitioners’’); and (2) Natural Resources Defense Council, Sierra 

Club, and Environmental Defense Fund (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 

formerly 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 
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published notice of the proposed settlement agreement in the Federal 

Register, and provided for a public comment period. 75 FR 82392 

(December 30, 2010).32 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

Electric utility generating units 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.

1. Summary of Recent and Ongoing Rulemakings Affecting this Source 

Category

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

Rule (CSAPR). 76 FR 48208 (August 8, 2011). The CSAPR requires 27 

states and the District of Columbia to improve air quality by 

reducing power plant emissions that contribute to ozone and fine 

 

32 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.
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particle pollution in other states. On July 6, 2011, the EPA also 

issued a supplemental proposal that requires six states to make 

summertime NOX reductions under CSAPR’s ozone-season control program. 

The CSAPR covers five of these six states. The CSAPR and the 

supplemental proposal apply to 3,642 EGUs at 1,081 coal-, gas- and 

oil-fired facilities in 28 states. Emission reductions will take 

effect quickly, starting January 1, 2012 for SO2 and annual NOX

reductions, and May 1, 2012 for ozone season NOX reductions. 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.

On March 16, 2011, the EPA proposed 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,

which the EPA expects to finalize later this year, will require 

investments in pollution controls to reduce emissions of mercury, 

other metals and acid gases by 2015 or 2016. In the same notice as 

the MATS rule, EPA proposed to revise the NSPS for criteria 

pollutants from these sources and expects to finalize at the same 

time as the MATS rule. Because the control technologies and 

strategies that reduce SO2 and to a lesser extent NOX, can also reduce

or help to reduce HAP emissions, coordinating compliance strategies 
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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. By setting flexible technology 

standards, the EPA’s common sense proposal would greatly reduce 

damage to ecosystems while accommodating site-specific circumstances 

and providing cost effective options.

The EPA recognizes that it is important that each of these 

efforts achieves its intended environmental objectives in a commonsense manner 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 harmonization. Each 

agency shall also seek to identify, as appropriate, means to achieve 
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regulatory goals that are designed to promote innovation.’’ Thus, the 

EPA recognizes that it needs to approach these rulemakings, to the

extent that its legal constraints 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.

2. 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 PSD and Title V programs. We discuss this issue in 

section VI, below, and we include relevant background information in 

that discussion.

3. 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 

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 
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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. 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. 

Main topics of comments, which concerned requirements for both new 

and existing sources, included the following: 

 Feasibility and availability of control technologies 

 Output-based standards

 Subcategorization factors

 Fleet-wide averaging 

 Neutrality of fuels

 Role of efficiency improvements
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 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

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 
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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 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”), combined cycle combustion 

turbines and their associated heat recovery steam generators (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 simple cycle combustion turbines. In addition, units 

subject to emission requirements under CAA section 129 would not be 

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.
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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 

performance (NSPS), and we are requesting comment on an alternative 

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 
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(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.

33 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 CHP EUGs, over a rolling 12-month 

period. In the alternative, we solicit comment on requiring 

calculation of compliance on an annual (calendar 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. Alternative compliance option

We also solicit comment on an alternative compliance option that 

would be available only for affected sources that comply with the 

 

33 As discussed below, we are not proposing such a limit for modifications, 

transitional sources, or reconstructed sources.
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standard through the use of CCS. This approach involves a performance 

standard that includes both annual emission limits and a longer-term 

limit that may be met on an average basis over a 30-year period. 

Specifically, the affected sources would initially be required to 

meet a 12-month rolling average CO2 emissions limit based on the best 

demonstrated performance of a coal-fired facility without CCS, which 

is 1,800 lb CO2/MWh (816 kg CO2/MWh) (gross). In the alternative, EPA 

solicits comment on requiring compliance through an annual (calendar 

year) average emission limit. This proposed emission limit can be 

met by modern coal-fired facilities using supercritical steam 

conditions, IGCC facilities, and pressurized circulating fluidized 

bed boilers. At some time after commencing construction and beginning 

operations (e.g., after the first 10 years), the facility would be 

required to meet a reduced emission limit for the remainder of the 

30-year period (e.g., the subsequent 20 years) 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. 

The EPA is also soliciting comment on what additional 

requirements would be necessary to implement the 30-year averaging 

requirement. Specifically, the owners or operators of the unit could 
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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 

plans in place to meet the 30-year average emission rate requirement.

Although this alternative compliance option allows for a 30-year 

averaging period, the source should also be subject to shorter term 

compliance requirements that are practicably enforceable to ensure 

that it is on a path to comply with the 30-year average limit. The 

EPA believes that these shorter term compliance requirements must 

include specific emission limits (e.g. annual average). EPA is 

considering several different forms for these minimum requirements. 

We are requesting comment on the form of these and any other shorter 

term compliance requirements, including in the event we include a 30-

year average in the final rule if it should automatically terminate 

in 2020 such that only facilities that commenced construction prior 

to 2020 would be able to use the 30-year average.

In the first option, the source would be required to submit a 

30-year emission trajectory, specifying the emission rates it intends 
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to meet each year consistent with meeting a 30-year average emission 

rate of 1,000 lb CO2/MWh. Each of these annual emission rate 

requirements would be part of the unit’s enforceable permit, and 

therefore would be enforceable on a short-term basis. We solicit 

comment on whether the requirements should be enforceable on a 

rolling 12-month basis, which is the same period as the standard of 

performance proposed under Section III.B.1. of this preamble. This 

option would give complete discretion to the source to plan the 

timing of emissions reductions, as long as the 30-year average rate 

would be achieved.

A second option would be the same requirements of the first 

option with the addition of certain EPA-defined minimum requirements, 

or progress milestones, to assure that the source reaches certain 

emissions levels within defined time periods. The rationale for 

these milestones would be to ensure earlier emissions- reducing 

actions and interim progress, and to reduce the risk that the source 

in the end fails to achieve its required 30-year average emission 

rate by the end of the 30th year. For example, by the 11th year, the 

unit could be required to meet at least the 1,000 lb CO2/MWh 

requirement of the standard of performance on an average annual 

basis. Such a requirement would have the effect of assuring that the 

source implements CCS by the 11th year, but could allow the source to 
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phase in the amount of CO2 emissions that its CCS system captures and 

stores.

A third option would require that this minimum 11th year 

requirement must be calculated, based on the source’s performance in 

the first 10 years, to assure that the source will fully implement 

CCS by that year. For example, if the unit operated at a rate of 

1,800 lb CO2/MWh for the first 10 years, the requirement starting in 

year 11 would be 600 lb CO2/MWh, which is the level that, if 

maintained by the source for the remainder of the 30-year period, 

would assure the source would meet the required 30-year average 

limit. Of the three options, the third option would provide the 

least discretion to sources on the timing of emissions reductions.

EPA suggests that this alternative compliance option may be 

warranted to provide 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. As discussed elsewhere, 

the Administration’s interagency CCS task force report anticipates 

that CCS will become widely commercially available after 2020. 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 
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over the next decade. A new coal-fired unit could operate for at 

least a decade before installing CCS and still have enough years 

operating at a controlled emission rate to reach a 1,000 lb CO2/MWh 

standard on a 30-year basis. Because the policy purpose of this 

alternative compliance option is to leave open the option of building 

a coal-fired unit in the near term and installing CCS after several 

years, a long 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 alternative 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 over the 

next several years, we believe that it may not be necessary to 

include this type of alternative 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 alternative compliance 

option should automatically terminate in 2020, so that it would be 
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available only for facilities that commenced construction prior to 

2020.

As with the proposed standard of performance, no averaging or 

emissions trading among affected sources would be allowed for this 

alternative compliance option. We seek comment on all aspects of this 

alternative compliance option.

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

1. Startups and shutdowns

The NSPS that EPA is proposing in this action would apply at 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. 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 
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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 alternative compliance option.

2. Malfunctions

Periods of startup, normal 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 
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‘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 

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” 
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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 

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 
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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 

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 
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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 

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).
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The EPA included an affirmative defense in the final rule 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 (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. 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 
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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 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 alternative compliance option.

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. 

a. Use all the data collected during all other required data 

collection periods in assessing the operation of the control device 

and associated control system.

b. Report any periods for which the monitoring system failed to 

collect required data.

c. 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.

3. 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 alternative 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 alternative 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 
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year) average emission limit, which would be calculated through 

comparable methodology as just described.

We propose that these same continuous compliance requirements 

would apply to the 30-year alternative 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 aware that owners or operators of many existing EGUs are 

required to submit 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.
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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 

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 alternative 

compliance option. The EPA also requests comment on whether any 

alterations or additions are appropriate. For example, the EPA 

requests comment on a potential requirement that sources wishing to 

utilize the 30-year averaging option notify the permitting authority 

at the time that they submit their preconstruction permit 

application. The EPA also requests comment on whether such sources 

should be required to include in the notification an explanation of 
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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. This information would 

be available to the public through the permitting authority.

IV. Rationale for the Proposed Standards for New Sources

A. How did the EPA establish the emission limits?

1. Rationale for Combining the Subpart Da Category and a Component of 

the Subpart KKKK Category into a New Category for GHGs

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 

components of sources in subpart KKKK (the KKKK category) –– combined 

cycle units, but not simple cycle units -- for purposes of 

promulgating standards of performance for emissions of GHGs from new 

sources. This new subpart will be numbered TTTT. At this time, the 

EPA is not proposing subcategories for new sources and is not 

combining the Da category and components of the KKKK category for 

conventional pollutants. 

CAA section 111 provides legal authority for combining the 

categories into a new category. Clean Air Act section 111(b)(1)(A) 

provides:

The Administrator shall, within 90 days after December 31, 
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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. 

It is reasonable for the EPA to combine the Da category and the 

combined cycle component of the KKKK category at this time for 

purposes of GHGs, for several related reasons. First, both types of 

plants (boilers and combined cycle units) perform the same function, 

which is to generate electricity. It is sensible to treat as part of 

the same category units that generate electricity, regardless of 

their design or fuel type.

Second, although it is true that natural gas-fired plants are 

inherently less emitting than coal-fired plants, all newly 

constructed sources have options in selecting their design. As a 
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result, prospective owners and operators of new sources could comply 

with the proposed emission standards by choosing to construct a NGCC

facility.

These two factors provide sufficient rationale for EPA to 

combine the Da category and the combined cycle component of the KKKK 

category for purposes of GHGs. A third factor lends further support.

Combining the categories does not foreclose construction of new coalfired EGUs because it is feasible to control CO2 emissions from new 

coal-fired units to levels typically achieved by new gas-fired units.

Specifically, new natural gas-fired EUGs are inherently low emitting, 

and that is the source of their relatively low emissions level. New 

coal-fired power plants – that is, the small number that may be 

expected to be built in the foreseeable future -- may install CCS 

control equipment (if not at the time of construction, then 

relatively soon thereafter) and, by doing so, achieve the same 

emission rate (at least over time) as a natural gas-fired EGU. As 

discussed below, CCS is feasible as evidenced by the fact that power 

companies have announced plans to incorporate CCS at seven already 

permitted coal-fired EGU construction projects in this country (as we 

discuss below in section V.B., concerning transitional sources). Our 

modeling, which is based on economic factors, forecasts no new coalfired construction through the modeling period – until 2020 – but we 
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realize the possibility that new coal-fired construction may occur 

for other reasons. As discussed below, we reasonably expect the costs 

of CCS to decline over time. In addition, programs exist that provide

some funding for CCS through pilot or other demonstration programs. 

As a result, we propose to conclude that coal-fired generation with 

CCS is feasible, although not a least-cost generation choice. To be

clear, we are not proposing that CCS does or does not qualify as the 

“best system of emission reduction” that “has been adequately 

demonstrated” (although we do solicit comment on that issue). Rather, 

we propose to conclude that CCS is a feasible method of alternative 

compliance for coal-fired power plants to meet the proposed NSPS for 

new construction, and that this is one reason that it is reasonable 

to combine the Da category and the combined cycle component of the 

KKKK category for GHG emissions. In addition, combining the 

categories can further the emission reduction goals of section 111. 

It makes it possible to set standards that provide assurance that the 

emissions performance projected from new generating units under 

projected market conditions (which favor new NGCC over new coal-fired 

generation) will be achieved even in the event that market conditions 

shift to favor more construction of coal-fired units than currently 

anticipated.

On the other hand, at this time, we do not consider it 
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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 base-load 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 

category.

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 conventional pollutants. This is because although coalfired EGUs have an array of control options for conventional 

pollutants to choose from, those controls generally do not reduce 

their conventional emissions to the level of conventional emissions 
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from natural gas-fired EGUs. As a result, at this time, combining the 

Da and KKKK categories for purposes of non-GHG emissions could have 

the effect of foreclosing new coal-fired EGUs, thereby precluding 

further development of CCS.

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 

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 
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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 to 

require the EPA to establish a rational basis for regulating an air 

pollutant from a source category. In this case, 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 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 
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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 

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 
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endangerment finding with respect to those particular pollutants, or 

any cause-or-contribute-significantly finding with respect to the 

source category, at the time 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 

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 
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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.

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 
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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 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 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 
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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 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 

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-fuel 
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fired 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 

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 
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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 

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 
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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 time being. 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 natural gas to meet new 

demand for electricity generation. At present, the cost of generation 

from a new NGCC power plant is lower than the cost of generation from 

a new coal-fired power plant.34 

Other drivers that may influence decisions to build new power 

plants are State and Federal energy and tax policies. Many states 

 

34 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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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, 

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.35 The new generation that EIA does 

 

35 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm
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shows coming on-line after 2012 fits into one of three categories. 

It is 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 

power plants under the base case.36 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) 

treating CCS as a alternative compliance option for coal-fired power 

 

36 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation
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plants because it would be feasible for the few such plants that may 

be constructed to employ CCS, often with assistance of the 

demonstration programs or other incentives available for CCS.

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 Alternative 

Compliance Option”), a NGCC facility is the best system of emission 

reduction for new base-load and intermediate-load EGUs. To establish 

an appropriate, natural gas-based standard, we used design 

performance specifications from Gas Turbine World37 and adjusted those 

values to account for operation at non-design ambient temperatures, 

the use of post-combustion controls, normal degradation of combustion 

turbine components, and operation at part load, all of which reduce 

turbine performance. 

 

37 Gas Turbine World is an industry periodical that provides information 

concerning size, performance specifications, and other characteristics for 

gas turbines. Information was obtained from the ‘2011 Performance Specs, 27th

Edition’.
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Specifically, the impact of temperature on the efficiency of 

combined cycle power plants is relatively minor, and we increased the 

design heat rate (which is a measure of overall efficiency, 

calculated by the amount of Btu needed to generate a kilowatt hour of 

energy) by 1 percent to account for operations at other than design 

conditions. The impact of post-combustion controls (i.e., selective 

catalytic reduction) on efficiency is also relatively minor. To 

account for the increased pressure drop from the catalyst we 

increased the design heat rate by 25 Btu/ kWh. Degradation is a more 

important factor as the heat rate of the facility will gradually 

deteriorate between overhauls. Although generally estimated at less 

than 3 percent over the life of the facility, we conservatively 

estimated a 5 percent increase in heat rate due to degradation to 

account for adverse conditions and different turbine designs.

Operational load is one of the primary factors in the actual 

operating efficiency and CO2 emissions rate of a combined cycle power 

plant. Combined cycle power plants are most efficient when operating 

at full load. At 80 percent load, the actual heat rate only increases 

by approximately 1 percent relative to the design basis heat rate. 

However, below 80 percent load, the heat rate begins to increase at a 

more significant pace. At 60 percent load, the actual heat rate 

increases by approximately 10 percent above the design rate. 
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Even though most combined cycle power plants are intended to 

operate at high loads, part-load operation is inevitable with 

variable demand. We selected a 5 percent heat rate increase relative 

to the design rate to account for part-load conditions.

The overall impact of these adjustments increases the expected 

annual operating heat rate to 11 percent above the design heat rate 

plus 25 Btu/kWh. Based on these assumptions, the range of operating 

emission rates for the eighty-one facilities listed in Gas Turbine 

World is 800 to 1,040 lb/MWh /MWh (370 kg CO2/MWh to 470 kg CO2). 

Ninety-five percent of these available new combined cycle 

designs (that is, the 81 facilities mentioned earlier) could 

reasonably be expected to achieve an emissions rate of 1,000 lb/MWh

(460 kg CO2/MWh) over the life of the facility, and we therefore 

selected that as our proposed standard. This proposed standard would 

only limit the use of available combined cycle facilities with 

relatively inefficient HRSG designs. Similar designs using the same 

combustion turbine engine with a more efficient HRSG would be able to 

comply with the standard. As such, selection of combustion turbine 

engine designs would not be affected by this standard. By only 

limiting the use of less efficient HRSGs, the proposed standard would 

still provide options across the full spectrum of electric generation 

sizes of combined cycle facilities. 
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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 combined 

heat and power (CHP) or 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 
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designed regulations that establish a standard for 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.

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 Compliance Alternative. In this 

section, we describe the basis for our position that CCS is a 

feasible compliance alternative for coal-fired power plants. First, 
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at present, CCS is technologically feasible and its core components 

(CO2 capture, compression, transportation and storage) have already 

been implemented. Second, although the costs of CCS are presently too 

high for widespread deployment, we have reason to expect that the 

costs of CCS will decrease over time, and the Administration’s 

interagency CCS task force report anticipates that CCS will become 

widely deployable after 2020. Third, we expect construction of no 

more than a few new coal-fired power plants by 2020, and those may 

well be able to take advantage of demonstration programs or other 

sources of funding for CCS. Fourth, several states have required CCS, 

many projects that implement CCS or components of it are proceeding, 

and other projects for CCS are in the planning stages.

(1) Technological Feasibility and Costs 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 
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uncertainty, first-of-a-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 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 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 three quarters 

of the overall CCS costs. 

In general, CO2 capture technologies applicable to coal-fired 

power generation can be categorized into three approaches38:

 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.

 

38 IPCC, 2005; DOE, 2007.
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 Oxy-combustion uses high-purity O2, rather than air, to combust 

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. As just 

discussed, the primary costs associated with CCS are the costs of 

capturing and compressing CO2. The remaining steps for CCS, pipeline 

transportation and sequestration, are better established. 

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,

39 which would lower transportation costs. For all these reasons, 

 

39 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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the transportation component of CCS is not expected to be a 

significant stumbling block to the commercial availability of CCS.

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.40 These four sites 

represent over 25 years of cumulative experience on safely and 

effectively storing anthropogenic CO2 in appropriate deep geologic 

formations.41 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 unmineable coal seams.42 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 throughout the world, provide 

confidence that the storage –- along with capture and transport -- of 

large amounts of CO2 can be achieved.

 

40 These projects are: Sleipner in the North Sea, Snøhvit in the Barents Sea, 

In Salah in Algeria, and Weyburn in Canada.

41 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.

42 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.43 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 

 

43 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.44 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.45 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. As noted above, currently 

available CO2 capture and compression processes are estimated to 

represent three quarters of the overall CCS costs, and it is those 

costs that render CCS, at present, too costly for widespread 

deployment. However, research is underway to reduce those costs. The 

DOE/National Energy Technology Laboratory (NETL) sponsors an 

extensive research development and demonstration program that is 

 

44 Mandatory Reporting of Greenhouse Gases: Injection and Geologic 

Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 (Dec. 1, 2010).

45 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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focused on developing advanced technology options that dramatically 

lower the cost of 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 effort 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 

gasification-based power plants.46 The large-scale CO2 capture 

demonstrations that are currently planned under DOE’s initiatives, as 

well as other domestic and international projects, will generate 

operational knowledge and enable future commercialization and 

widespread cost-effective 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 

 

46 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,

47 and this has 

 

47 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 Environmental Regulation on the Construction Cost of CoalBurning Generating Units," RAND Journal of Economics, Vol. 16,Issue 1, 1-27, 
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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 have every reason to expect that the costs of capture 

technology will follow this pattern. Rubin et al. used historical 

experience curves as the basis for estimating future cost trends for 

four types of new electric power plants equipped with CO2 capture 

systems: PC and NGCC plants with post-combustion CO2 capture; coalbased IGCC plants with pre-combustion capture; and coal-fired oxyfuel 

for new PC plants.48 They 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 power plants employing CO2 capture. The 

results of the study suggested that total costs of CO2 capture can be 

expected to reduce by the following percentages: NGCC by 40 percent, 

PC by 26 percent, IGCC by 13 percent, and Oxyfuel by 13 percent.

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 

 

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.

48 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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for CO2 capture, the CO2 capture ratio (removal efficiency) and the 

power plant availability. The model predicted continued reductions in 

cost with increased implementation.49

These expected reductions in CCS costs are consistent with the

Administration’s CCS task force report, which anticipates that CCS 

will become widely commercially available after 2020.

(3) Limited amount of construction of coal-fired power plants; 

opportunities for CCS funding. A third reason that supports CCS as an 

alternative compliance option is that through the IPM model period of 

up to 2020, we expect few if any new builds of coal-fired EGUs. We 

also expect some opportunity for financial support for CCS at least 

through Federal demonstration programs. Accordingly, the few new 

coal-fired generation projects that may occur may well find that 

financial support for CCS is available.

(4) State Requirements for CCS; Projects and Permits for CCS. Several 

states have recently established requirements for CCS, and many 

projects have implemented CCS or have been permitted to do so.

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 

 

49 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.
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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 systems, including, in some cases, part of the 

components for coal-based power plant applications.

AES’s coal-fired Warrior Run (Cumberland, MD) and Shady Point 

(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 
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is subsequently used in the food processing industry50.

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.

51

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 

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 

 

50 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.

51 IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.
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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 

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 
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(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 (500 tons per day) 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.

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 
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acid, argon, and inert slag, all of which will also be marketed.)

Construction is expected to begin in late 2011.

Hydrogen Energy California, a 257 MW gasification facility in 

south-central California utilizing coal and petroleum coke, will 

capture 1.8 million tonnes per year of CO2 using a Rectisol® process, 

for use in an EOR application. The facility is expected to be 

operational in 2016. In May 2011, SCS Energy announced that it was 

agreeing to take over Hydrogen Energy California and was planning to 

modify the project to add polygeneration capabilities.

In June 2011, Alstom Power President, Philippe Joubert, 

discussed the results of a detailed study concerning carbon capture 

technology, conducted by Alstom, at the 2011 PowerGen Europe 

conference (Milan, Italy). The study was based on results from 13 

European pilot- and demonstration-scale projects and the results were 

validated by independent experts. From the results of the study, 

Joubert concluded that “We can now be confident that carbon capture 

technology works and is cost effective.”52

In its recent Integrated Resource Plan, the Tennessee Valley 

Authority (TVA) recommended new coal additions of up to 900 MW in the 

2025-2029 timeframe and further recommended that TVA "preserve [the] 

 

52 June 14, 2011 press release from Alstom, “Alstom Power study demonstrates 

carbon capture and storage (CCS) is efficient and cost competitive”, 

http://www.alstom.com/power/news-and-events/press-releases .
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option of generation with carbon capture."53 The TVA included 

supercritical pulverized coal plants with CCS technology as well as 

IGCC plants with CCS technology as resource options in its Integrated 

Resource Plan evaluation.

In addition, the EPA is aware of seven coal-fired EGUs for which 

permits have recently been issued that include CCS. As a result, 

these plants, if they are built, would likely be compliant with the 

most significant requirements of today’s proposed action. While 

today’s action may require some additional monitoring and reporting 

requirements, substantive changes to the design of the plants would 

not be necessary for compliance.

d. Legal Justification for the Standard of Performance and 

Alternative 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-fired power plant, may implement an 

alternative compliance option that allows an affected facility to 

meet an initial CO2 emission limit of 1,800 lb CO2/MWh (816 kg 

 

53 IRP, March 2011.
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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 Peformance. The EPA 

proposes that the emission limit of 1,000 lb CO2/MWh meets the 

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 
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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 ultrasupercritical 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 
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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 

that for economic reasons, natural gas-fired EGUs will be the 

facilities of choice until at least 2020, which is the model period. 

Indeed, those models do not project construction of any new coalfired EGUs during that period. 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 

less nonair quality health and environmental impacts.

Essentially because natural gas 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 
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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 

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 Alternative Compliance Option.

Although the IPM model projects that for economic reasons, new 

coal-fired EGUs will not be built in the foreseeable future, we 

recognize that in a few instances, owners or operators may in fact 
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seek to build coal-fired EGUs. As discussed in detail below, under 

today’s proposed rulemaking, those owners or operators could avail 

themselves of an alternative compliance option: They 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 the 1,000 lb CO2/MWh rate on an average annual basis 

over a 30-year period. Because CO2 is long-lived in the atmosphere, 

the 30-year averaging period is not expected to have a different 

impact on climate compared to a continuous emission rate limit or an 

annual emissions limit.

The significance of this compliance alternative being proposed 

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 and thereby allow it to become more widely available in the 

future. In addition, this compliance alternative provides further 

support for the reasonableness of the EPA’s proposals in this 

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 
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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. 

The compliance alternative does not achieve these goals by 

necessarily qualifying as the “best system of emission reduction 

which (taking into account cost [and other factors]) the 

Administrator determines has been adequately demonstrated.” Instead, 

for the reasons discussed next, this compliance alternative is a 

reasonable option, 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 other 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 expected 

to be constructed in the foreseeable future. Some of these programs 

are discussed above.

Second, it is reasonable to expect that some coal-fired power 

plants may be able to implement the supercritical efficiency standard 
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for an initial period of time (e.g., again, the first 10 years) and 

then implement CCS after that, so that the source achieves the 1,000 

lb CO2/MWh standard on average over the 30-year period following 

construction. We are soliciting comment on whether this compliance 

alternative could be considered the “best system of emission 

reduction” and therefore whether the associated standard (the 1,000 

lb CO2/MWh averaged over 30 years) would qualify as a “standard of 

performance” under CAA section 111(a)(1). But in any event, this 

proposed compliance option is reasonable.54

Third, 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 “best system 

... adequately demonstrated,” and the same should be true in 

determining whether a particular system of emission reduction 

qualifies as a reasonable alternative compliance option.

The Senate 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 best system of emission 

 

54 Note that under today’s proposed rulemaking, the 30-year averaging proposal is 

associated only with the implementation of CCS. This proposal does not allow 30-

year averaging for any other purpose.
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reduction:

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 

regulated industry in the future. The Court stated, in Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):
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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.

55

Id. at 391 (emphasis added). Again, although these statements in the 

legislative history and caselaw 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 reasonable compliance alternative.

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

standards?

1. Compliance Requirements

The proposed compliance requirements, to the extent possible, 

incorporate monitoring already being performed as part of existing 

part 60 and part 75 requirements. 

 
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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 

makes it possible to assess compliance and take any needed corrective 

action on a monthly basis. EPA proposes that it is not necessary to 

have a shorter averaging period for CO2 from these sources because 
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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 indicate that there are 

likely to be existing affected EGUs that will undertake 

modifications, as that term is defined, with respect to their GHG 

emissions. That is because the types of projects that these EGUs are 

most likely to undertake that could increase GHG emissions are 

projects that put on pollution controls required under other CAA 

provisions and that emit CO2 as a byproduct, and those types of 
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projects are specifically exempted from the definition of 

“modifications” under 40 CFR 60.14(e)(5). Because the EPA does not 

have information indicating that affected EGUs would undertake 

modifications, 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 and regulated through state plans.

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 

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 
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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, 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 

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
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We expect EGUs to undertake changes in the foreseeable future 

that will increase their maximum achievable hourly rate of CO2

emissions, but generally, those actions will constitute pollution 

control projects. In many cases, those projects will 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 will occur as a chemical byproduct of the 

operation of the control equipment, and will 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 all of these actions 

will be treated as pollution control projects under the EPA’s current 

NSPS regulations, they will be specifically exempted from the 

definition of modification. In addition, it is conceivable that some 

EGUs may undertake other changes that may increase their capacity and 

therefore their maximum achievable hourly emission rate, but that 

would be so expensive so as to fall into the category of 

reconstructions, under 40 CFR 60.15. Reconstructions also are not 

treated as modifications. Our expectation that few, if any, existing 

affected EGUs will undertake modifications within the meaning of the 

EPA’s regulations is consistent with experience under CAA section 
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111: Historically, it has been rare that actions by sources have been 

treated as modifications under CAA section 111.

As a result, the EPA does not think it is reasonably likely that 

any existing affected EGUs would undertake actions that would be 

defined as modifications under the CAA section 111 regulations. By 

the same token, the EPA is not able, at present, to determine what 

types of CO2 control requirements would be appropriate for any 

existing affected EGUs that may undertake modifications. This is 

because the EPA does not have adequate information to determine what 

type of source may undertake modifications, what types of CO2 controls 

would be appropriate, or what would be the costs of, and other 

relevant factors concerning, those controls. 

The EPA solicits comment on all of these issues. However, at 

this time, the EPA is not proposing standards of performance for 

modifications. 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.” Accordingly, if there is no proposed or 
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promulgated standard of performance applicable to a particular 

source, then the source cannot be considered a “new source.” Further, 

under the definitional provisions, any source that is not a “new”

source is an “existing source,” and as a result of that, section 

111(d) applies to that source.

Therefore, affected EGUs that undertake physical or operational 

changes that increase their maximum achievable hourly CO2 emission 

rate56 will be treated as existing sources and therefore will not be 

subject to any standards of performance we finalize for new sources, 

but will be subject to requirements for existing sources that we 

intend to promulgate through a separate rulemaking and that states 

will be required to incorporate into state plans. This approach to 

these types of physical or operational changes will allow EPA to 

gather more information about them, which will allow EPA to determine 

whether any of those changes in fact are modifications, and, if so, 

what control requirements would be appropriate. In the alternative, 

if these types of physical or operational changes were considered to 

be modifications, then the EPA is soliciting comment on what the 

appropriate standard(s) of performance for these changes should be, 

but, to reiterate, the EPA is not proposing any standards of 

performance for them at this time. 

 

56 We discuss below the treatment of sources that reconstruct.
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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 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 today’s action, the EPA is not proposing a standard of 

performance for proposed affected EGUs that have received approval 

for their complete PSD preconstruction permits, but that have not 

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

For this proposed rule, these sources are referred to as 

“transitional sources.” The EPA is aware of approximately 18 
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transitional sources, seven of which are expected to utilize CCS. The 

EPA’s regulations define “commenced construction” as, in general, 

undertaking a continuous program of construction or entering into a 

binding contract to do so.

Absent different treatment, a transitional source will be 

subject to the new source standards of performance when it does 

commence construction, even though it has already received a 

preconstruction permit that authorizes it to construct and operate 

without the controls that the EPA would now be requiring under the 

new source standards of performance. 

We are aware however that because of the specific requirements 

created as a result of this new standard, as a practical matter, it 

would be extremely difficult if not impossible for such a source to 

proceed with construction without substantial re-design of the 

project in order to be in compliance with the standard. There are 

two reasons for this. First, captured CO2 must be sequestered or 

used. If this was not considered as part of the original site 

selection, it provides additional challenges to the sources ability 

to adopt CCS. Second, if CCS was not considered in the original 

project design, space considerations may make it difficult to 

accommodate in the facility’s design. Third, the requirement to use 

CCS could necessitate a change in the very generation technology that 
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a source may choose to use. For instance, instead of building a 

pulverized coal boiler, IGCC technology may be more appropriate. 

This 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 on 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 redesigning the whole project, rather than just designing it as a 

retrofit.

The requirements created by the new source standard are very 

different to the point of being different in kind from post 

combustion controls required to meet new source standards for other 

pollutants which could be much more easily redesigned into a planned 

plant without necessitating redesign of the entire project, since the 

size of the retrofit and the issues involved in disposing of the 

captured pollutant are generally on a smaller scale than CCS. 

In light of these concerns, EPA is not proposing a standard of 

performance for transitional sources as long as they commence 

construction within 12 months from the date of this proposal. Thus, 

these sources may construct and operate consistent with the 
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otherwise applicable permit limits they received prior to the date of 

proposal of this rulemaking.57

The EPA is not proposing a standard of performance for 

transitional sources that limits their emissions to the level they 

would emit when operating in compliance with their permits because of 

concerns that any such proposal would not provide environmental 

benefits but would create uncertainty as to the final standard of 

performance, and that uncertainty could prevent transitional sources 

from commencing construction during the 12-month window available to 

them. 

By the same token, the EPA considered, but decided not to 

proceed with, soliciting comment on either a “no-control” standard of 

performance for transitional sources’ CO2 emissions or a standard that 

equals the emission limitation that the sources identify as what they 

would achieve through compliance with the otherwise applicable terms 

of their permit. Here too, the EPA is concerned that these 

approaches would not provide environmental benefits but could create 

uncertainty that could prevent the sources from commencing 

construction during the short period available to them. 

 

57 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, so that there is no need to 

consider whether they merit special treatment.
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Because EPA is not proposing a standard of performance for 

transitional sources, those sources will not be treated as “new” 

sources, and instead will be treated as “existing” sources, as those 

terms are defined under CAA section 111(a). As a result, those 

sources would become subject to requirements for existing sources 

that states promulgate in accordance with EPA emissions guidelines 

promulgated under CAA section 111(d). 

2. Background

a. CAA and the EPA Regulatory Provisions. Under CAA section 

111(a)(2), a “new source” is defined as a stationary source that has 

“commenced construction” or modification after the date that a 

standard of performance “which will be applicable to such source” is 

promulgated or, if earlier, proposed. Such a source becomes subject 

to the standard of performance that the EPA has finalized for it. 

The CAA does not include a definition of the term “commenced” 

for purposes of CAA section 111. The EPA framework regulations 

promulgated under CAA section 111 define “commenced” 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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b. Transitional Sources. The EPA is aware that in approximately 18 

cases, owners or operators of proposed new coal-fired EGUs have 

obtained permits under the CAA PSD program for the EGUs, but have not 

“commenced construction”, as that term is defined under 40 CFR 60.2. 

Seven of these newly proposed EGUs are expected to install CCS, and 

the remaining ones are not. 

3. Approach

Under the definition of a “new source” in CAA section 111(a)(2), 

if any of the approximately 18 proposed sources that have received 

preconstruction permits under the CAA PSD provisions have not 

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

then, absent anything to the contrary in this proposal, any of those 

proposed sources that ultimately do commence construction would be 

considered “new” sources and subject to whatever NSPS the EPA may 

finalize in this rulemaking. This would be true even though the 

proposed source would have already incurred the expense of obtaining 

a PSD permit before it became subject to the NSPS. Some commenters 

have suggested that any of these transitional sources that do 

construct should be exempted from the new standards of performance. 

In contrast, newly proposed sources that did not obtain PSD permit 

approval before the date of this proposal would, if they construct, 

be treated as new sources and therefore would be subject to the new 
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standards of performance.

For these transitional sources –- all of which are coal-fired --

the question of whether they are subject to the proposed new source 

standards in this rule has a significant impact because it determines 

whether or not they must be designed to accommodate CCS and, at least 

in the future, implement CCS. Commenters have stated that 

transitional sources have already incurred significant costs in 

obtaining a PSD permit and, in some cases, have taken other costly 

actions. These commenters have stated that if transitional sources, 

when they commence construction, were to become treated as new 

sources subject to the new standards of performance, these sources 

may have to revise or even redesign their proposed plans and get new 

permits, and their expenditures to date would have to be accounted 

for in investment decisions going forward. Unlike conventional 

pollutant controls that can generally be added to a power plant 

without changing its basic underlying characteristics (such as type 

of unit or even location), 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 than it 

would be in other types of projects. This may be true even for at 

least some of the seven that expect to implement CCS as they may be 
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temporarily uncertain of their ability to comply with the 

requirements, proposed under this rulemaking.

On the other hand, it is the EPA’s overall policy with this 

rulemaking that newly constructed EGUs should meet the promulgated 

new source performance standards. This is important to safeguard 

environmental values and, as discussed elsewhere, the standards are

feasible for new sources. 

Transitional sources should have a 12-month period, beginning 

from the date of proposal, to commence construction in accordance 

with the terms of the permit they received prior to the date of 

proposal of this rulemaking. The 12-month period would not be 

extended for any reason, including because of any challenges to the 

permit that may be brought in any court or agency. Transitional 

sources that commence construction within that period would not be 

subject to the final new source limitations. 

This approach is generally consistent with the purposes of CAA 

section 111 because transitional sources would, as a matter of 

practice, face limits on their CO2 emissions that stem from the 

operational limits associated with compliance with the terms of their 

otherwise applicable permits. Any more stringent limits for CO2

emissions could not be justified, for these particular sources, 

because such limits would require them to substantially redesign the 
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source to meet the new limits. As previously explained, this would 

be true if we required the source to meet a 1,000 lb/MWh standard 

requiring CCS. It would also be true if we required limits even 

slightly tighter than those that the unit was currently designed to 

meet, since efficiency (and thus CO2 emissions) are such an integral 

part of unit design.

The 12-month period is appropriate because its relatively short 

length means that the benefits of this approach would be limited to 

sources that are in essence, already “shovel-ready” or very close. 

It is those sources that would be most disadvantaged by subjecting 

them to the standards of performance proposed in today’s rulemaking. 

On the other hand, 12 months is long enough to give transitional 

sources a reasonable period to commence construction in accordance 

with the terms of their permit. Transitional sources that do not 

commence construction within this period would be treated as any 

other affected source that commences construction after the date of 

proposal of this rulemaking, and would be subject to the final new 

source standards. 

Accordingly, EPA is not proposing a standard of performance in 

this rulemaking for transitional sources that commence construction 

within 12 months of this proposal. As a result, transitional sources 

may not be treated as “new source[s]” beginning on the date of this 
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proposal, under the definition of “new source” in CAA section 

111(a)(2). Under that definition, a source may be a “new source” if 

it commences construction “after the publication of regulations (or, 

if early, proposed regulations) prescribing a standard of performance 

under this section which will be applicable to such source.” 

Without a standard of performance applicable to them, 

transitional sources that commence construction within 12 months of 

the proposal will be treated as “existing” sources, as defined under 

CAA section 111(a)(6). As a result, those sources could become 

subject to requirements for existing sources that states impose 

pursuant to emissions guidelines that EPA promulgates under CAA 

section 111(d)(1). Transitional sources that do not commence 

construction within 12 months of this proposal would be treated as 

any other affected source that commences construction after the date 

of proposal of this rulemaking, and thus would be subject to the new 

source standards that EPA finalizes in this rulemaking. 

The EPA considered, but is not pursuing, soliciting comment on 

subcategorizing transitional approaches as a separate category of new 

sources and establishing standards of performance for them that would 

reflect the amount of CO2 emissions they would emit when operating in 

accordance with the terms of their otherwise applicable permit. For 

example, the EPA considered soliciting comment on a “no-control” 
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standard of performance for their CO2 emissions, under which these 

sources would be treated as new sources subject to a standard of 

performance, but the standard of performance would not limit their CO2

emissions. The EPA also considered soliciting comment on 

establishing a source-specific standard of performance, such as one 

that each transitional sources itself would identify as equaling the 

emission limitation it would achieve through compliance with the 

terms of its otherwise applicable permit.

The EPA is not pursuing these approaches for several reasons. 

First, they do not appear to offer environmental benefits because 

they would not lead to CO2 emissions reductions. Second, the 

relatively brief period of 12 months available to transitional 

sources to commence construction limits the EPA’s ability to obtain 

sufficient information to establish the correct standard of 

performance. The process of establishing any standard of performance 

for these sources, even one that sought to finalize an emission rate 

fully consistent with their construction and operation under their 

permit, could entail some degree of uncertainty as to what precisely 

the final standard would be and whether the sources could meet it. 

That uncertainty could delay their commencing construction and 

thereby force them to miss the 12-month window, and thereby undermine 

the purpose of this approach for transitional sources. 
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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 take comment on options for 

reconstructed sources, which, in general, include (i) not taking 

final action to establish a new standard of performance, which, as a 

practical matter, would mean that reconstructed sources would be 

treated as existing sources; (ii) establishing the standard of 

performance at either the same level as for new sources or at the 

supercritical efficiency level (which is the same level proposed in 

this rulemaking for coal-fired EGUs that employ the 30-year 

alternative compliance option during the initial period after they 

construct and before they install CCS).

2. Background

a. The EPA Regulations

The EPA’s framework regulations, interpreting the definition of 

“new source” in CAA section 111(a)(2),58 provide that an existing 

source, “upon reconstruction,” becomes subject to the standard of 

 

58 CAA section 111 does not explicitly include provisions for reconstructed sources.
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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 

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 
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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 have 

proposed a 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. Instead, EPA solicits comment 

on three different options for these sources:

a. Option 1: No final action to establish a standard of 

performance.

Under the first option, at the time EPA finalizes this action, 

EPA would not include a standard of performance for reconstructions. 

This option parallels the option, described above, for modifications. 

Under this option, as a practical matter, sources undertaking 

reconstructions would be treated as existing sources, that is, they 

would not be subject to any NSPS under CAA section 111(b)(2), and 

would instead be subject to any requirements that EPA may promulgate, 

and states may impose, under CAA section 111(d)(1). 
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This option may be justified on much the same grounds as the 

option for modifications, which is that the lack of information about 

whether sources will undertake reconstructions, and about the type of 

source and the type of changes, precludes proposing a NSPS.

b. Option 2: Establish a standard of performance.

Under the second option, at the time EPA finalizes this action, 

EPA would include a standard of performance for reconstructions at, 

as one sub-option, the same level as for new sources or, as another 

sub-option, at the supercritical efficiency level. Under this option, 

sources undertaking reconstructions would be treated as new sources.

This option may be justified on grounds that a source undertaking a 

reconstruction is rebuilding its plant to such an extent that it 

should be obligated to implement a higher level of emissions control. 

This option may find further support because under the definition of 

“reconstruction” quoted above, a source’s rebuilding project becomes 

treated as a reconstruction only if it is “technologically and 

economically feasible [for the source] to meet the applicable 

standards.” 40 CFR 60.15(a). 

EPA requests comment on whether applying significantly less 

stringent emission limits to a reconstructed EGU than to an entirely 

new EGU would create perverse incentives for a company to make large 

investments (over 50 percent of the cost of a new source) in an 
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existing EGU to extend its economic life for decades rather than 

build an entirely new, lower-emitting EGU. EPA also requests comment 

on whether the alternative CCS compliance option for new sources --

which would allow the new source standard to be met on a 30-year 

average basis -- should be available to reconstructed sources under 

this option.

It should be noted that because EPA is not proposing a NSPS for 

reconstructions, even if EPA takes final action establishing a NSPS 

for reconstructions, any source that commences construction, between 

the date of this proposal and the date of final action for this 

rulemaking, on a project, would not be treated as having undertaken a 

reconstruction even if the project would have been considered a 

reconstruction had the source commenced construction after the final 

action.

The EPA solicits comment on all aspects of these options for 

reconstructions.

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 
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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 continue to apply to the PSD program. 

This issue arises because, although PSD has already been

triggered for sources and although the Tailoring Rule thresholds 

already apply, the EPA’s regulatory provisions could be read to 

suggest that the EPA’s promulgation of CAA section 111 requirements 

for a pollutant previously unregulated under CAA section 111 could, 

in effect, trigger PSD requirements again. However, 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 if the EPA were 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 
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continue to apply as of the effective date of today’s rulemaking.

In the alternative, if it is not the case that the Tailoring 

Rule thresholds continue to apply if and when the EPA promulgates 

requirements under CAA section 111, then EPA will shortly proceed 

with a separate rulemaking action to narrow its approval of all of 

the State’s approved SIP PSD programs so assure that for federal 

purposes, the Tailoring Rule thresholds will continue to apply as of 

the effective 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 are required to include an 

approved PSD program in their SIPs and to issue the PSD permits, but 

if a state does not have such a program, then the EPA issues the PSD 

permits. 
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Regulation of GHG emissions in the Light Duty Vehicle Rule, 

triggered applicability of regulatory requirements to stationary 

sources 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 existing 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, 2011, large 

industrial sources, including power plants, became subject to 

permitting requirements for their GHG emissions if they otherwise are 

required to obtain a PSD or title V permit due to emissions of other 

air pollutants.

We recognize that 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 
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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).

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;
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(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. 

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.

If, under the language of the PSD regulations, the Tailoring Rule 

thresholds do not apply to the NSPS trigger provision, then the EPA 

would have to revise its regulations to include the Tailoring Rule 

thresholds. Moreover, under these circumstances, the states that 
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apply PSD to GHG-emitting sources may have to revise their SIPs, and 

do so quite promptly.

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 

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, 
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“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 

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”). 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 
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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 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 

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.
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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 

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, 
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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 

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

G. What are the air impacts?

H. What are the energy impacts?

I. What are the compliance costs?

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

K. What are the economic and employment impacts?
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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 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.

L. What are the benefits of the proposed standards?

As previously stated, 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. 

VIII. Request for Comments

We request comments on all aspects of the proposed rulemaking. 

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 
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and/or distillate oil. In addition, we are requesting comment on 

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 percent59 and a molecular weight of 39.9 

lb/lb-mol in calculating the dry gas molecular weight.

 

59 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.

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.

Potential Electric Output. The proposed rule uses three criteria 

to determine applicability: heat input of fossil fuel must be greater 

than 250 MMBtu/h, 25 MW or more net electricity must be sold to the 

grid, and one-third of potential electric output must be sold to the 

grid. In addition, we are proposing to exempt stationary combustion 

turbines that are subject to a federally enforceable permit to limit 

operate less than 3,000 hours annually. We are proposing to base the 

potential electric output for stationary combustion turbines on an 

assumed efficiency of fifty percent instead of the thirty-three

percent used for boiler/steam turbine-based facilities. We have 

concluded that this is appropriate because the potential electric 

output factor, and not the capacity factor requirement exempting 

combustion turbines operating less than 3,000 hours annually, could 

otherwise be the controlling factor on whether combustion turbines 

used for peaking operations are considered affected facilities. If we 

used 33 percent instead of 50 percent, it could inadvertently 
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encourage the installation of less efficient peaking combustion 

turbines. For example, if an owner/operator has the option to either 

purchase a 30 or 35 percent efficient combustion turbine, the less 

efficient turbine could be permitted to operate more hours. Since 

potential electric output is based on the heat input, the potential 

electric output using a 33 percent efficiency factor would limit 

operation of the more efficient turbine to 2,800 hours annually. In 

contrast, the less efficient turbine would be permitted to operate 

3,200 hours annually before applicability based on potential electric 

output applied. Using the 50 percent efficiency assumption eliminates 

this issue and bases applicability on permitted capacity factor, 

while still accommodating for the intended exemption to combined heat 

and power facilities. 

We are requesting comment on whether the potential electric 

output should be changed or eliminated for this rule. As currently 

proposed, an owner/operator of an electric only boiler/steam turbine 

based generator could take a permit restriction that would 

essentially limit operation to less than 2,920 hours annually to 

avoid applicability with the proposed requirements. Since between 5 

to 10 percent of boiler/steam turbines presently operate less than 

3,000 hours annually, this could encourage owners/operators to take 

operating permit restrictions on their facilities primarily used for
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peaking operations to avoid applicability with the GHG requirements. 

Consequently, they would not be required to reduce their 

corresponding emission rates. While this approach reduces the 

environmental benefit of the proposed rule, it would lower compliance 

costs because facilities could be maintained for peaking applications 

and grid reliability issues without the capital improvements that 

would otherwise be required. Another alternative would be to specify 

that the potential electric output capacity exemption only applies to 

CHP facilities. 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, 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 
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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 of 1,000 lb/MWh 

does not preclude new coal-fired units from being CHP units.

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). Instead of defining a simple cycle 

turbine in the regulatory text, we base applicability of the 

stationary combustion turbine on if it is permitted to operate 3,000 

hours or more annually. The peaking season is generally considered to 

be less than 2,500 hours annually, and we have concluded the proposed 

capacity factor provides sufficient margin for operational 

flexibility. We have concluded that a permitted capacity is more 

appropriate than defining a simple cycle turbine. We are specifically 

requesting comment on if we should (1) change the capacity threshold 

or (2) add a definition and base the applicability on the definition. 

For the final rule we are considering a capacity range of 2,500 to 

3,500 hours annually. In the event we use the definition approach, we 
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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

Under 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, 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, 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 compliance costs 

associated with it, because electric power companies will choose to 

build new EGUs that comply with the regulatory requirements of this 
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proposal because of existing and expected market conditions. 

B. Paperwork Reduction Act

As required by the Paperwork Reduction Act (PRA), 44 U.S.C. 3501 

et seq., an information collection request (ICR) will be prepared by 

EPA (ICR No. XXXX.XX) and submitted for approval to the Office of 

Management and Budget (OMB). The information collection requirements 

are based on notification, recordkeeping, and reporting requirements 

in the NSPS General Provisions (40 CFR part 60, subpart A), which are 

mandatory for all operators subject to national emission standards. 

These recordkeeping and reporting requirements are specifically 

authorized by CAA section 114 (42 U.S.C. 7414). All information 

submitted to 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 information collection requirements are not enforceable 

until OMB approves them. Apart from the recordkeeping and reporting 

costs, we do not expect other compliance costs for most units, as the 

information required by this proposed rule is already collected and 

reported by other regulatory programs. 

The EPA is accepting comment on the need for this information, 

the accuracy of the provided burden estimates, and any suggested 
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methods for minimizing respondent burden, including the use of 

automated collection techniques. The EPA has established a public 

docket for this proposed rule, which includes this ICR, under Docket 

ID number EPA-HQ-OAR-2011-0660. 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 

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 
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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.

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.
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After considering the economic impacts of this proposed rule on 

small entities, I certify that this action will not have a 

significant economic impact on a substantial number of small 

entities. See, e.g.,; Michigan v. EPA, 213 F.3d 663, 689 (D.C. Cir. 

2000) ("The court has consistently held that the RFA imposes 'no 

obligation to conduct a small entity impact analysis of effects on 

entities which it does not regulate.'" (citing Motor & Equip. Mfrs. 

Ass'n. v. Nichols, 142 F.3d 449, 467 (D.C.Cir.1998) (quoting United 

Distribution Cos. v. FERC, 88 F.3d 1105, 1170 (D.C.Cir.1996)));

Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855 (D.C. Cir. 

2001); Am. Trucking Ass’n v. EPA, 175 F.3d 1027 (D.C. Cir. 1999); 

Mid-Tex Elec. Co-op, Inc. v. FERC, 773 F.2d 327 (D.C. Cir. 1985).

We do not include an analysis of the illustrative impacts on 

small entities that may result from implementation of this proposed 

rule by states because we do not anticipate any compliance costs 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 does not project any new coal-fired 

EGUs to be built, so, accordingly, there are no anticipated economic 

impacts as a result of this proposal. 

Nevertheless, the EPA is aware that there is substantial 

interest among small entities (municipal and rural electric 
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cooperatives) that will be affected by this rule. 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 conducted an initial outreach meeting with small entity 

representatives on April 6, 2011. The purpose of the meeting was to 

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 
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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 

participants from organizations representing power producers 

presented information regarding issues of concern with respect to 

development of standards for GHG emissions. Specifically, topics 

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.
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Written comments that the EPA received from, or on behalf of, 

small entities in response to discussions at the outreach meetings 

and questions posed to the small entity representatives have been 

placed in the docket for this rulemaking.

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 action contains no Federal mandates under the provisions of 

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 

1531-1538 for State, local, or tribal governments or the private 

sector. 

The action imposes no enforceable duty on any State, local or 

tribal governments or the private sector. Therefore, this action is not 

subject to the requirements of sections 202 or 205 of the UMRA.

This action 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. 

Consistent with the intergovernmental consultation provisions of 

UMRA section 204, the EPA has initiated consultations with 

governmental entities affected by this proposed rule. The EPA invited 

the following 10 national organizations representing state and local 

elected officials to a meeting held on April 12, 2011, in Washington 
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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 of 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. 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 as on state and local entities with regard 

to implementing the rule. Officials requested, and the EPA provided, 

addresses associated with the 123 state and local governments 

estimated to be potentially impacted by the proposed rule. Subsequent 

to the April 12, 2011 meeting, the EPA received a letter from the 

National Conference of State Legislatures. In that letter, the 
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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.

The EPA offered consultation to 584 tribal officials early in 

the process of developing this proposed regulation. 

Consultation/outreach was conducted with several tribes. The 

Consultation and Coordination with Indian Tribal Governments

discussion in this preamble includes a description of the 

consultation/outreach.

The EPA also conducted outreach to small entities that 

potentially would be subject to the requirements of the rule to 

obtain their advice and recommendations. The RFA discussion in this 

preamble describes the outreach.

E. Executive Order 13132, Federalism

This action does not have federalism implications. It will not 

have substantial direct effects on the States, on the relationship 

between the national government and the States, or on the 
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distribution of power and responsibilities among the various levels 

of government, as specified in Executive Order 13132. This action 

does not impose direct compliance costs on state or local 

governments. 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 development. 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 Executive Order 13175 (65 FR 67249, November 9, 

2000) 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 
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governments, or EPA consults with tribal officials early in the 

process of developing the proposed regulation and develops a tribal 

summary impact statement. 

EPA has concluded that this action may have tribal implications. 

However, it will neither impose substantial direct compliance costs 

on tribal governments, nor preempt Tribal law. This proposed rule 

would impose requirements on owners and operators of 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.

In addition, the EPA is aware of other Tribal interests that 

could be impacted by this rule. As a result, 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. Consultation letters were sent to 584 

tribal leaders. The letters provided information regarding 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 
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of Ojibwe. Other tribes participated in the call for information 

gathering 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. A few tribes were 

invited to participate in a session on February 17, 2011 with the 

state agencies, and a separate session was held with the 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

This action is not subject to EO 13045 (62 FR 19885, April 23, 
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1997) because it is not economically significant as defined in EO 

12866. This proposed rule is not subject to EO 13045 because the 

proposal likely does not produce changes in emissions of greenhouse 

gases or other pollutants (but it 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.

M. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined in 

Executive Order 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 action is not anticipated to 

have notable impacts on emissions, costs or energy supply decisions 

for the affected electric utility industry. 

N. Executive Order 12898: Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental justice. Its 

main provision directs Federal agencies, to the greatest extent 
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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.

EPA has determined that this proposed rule will not have 

disproportionately high and adverse human health or environmental 

effects on minority or low-income populations, because it increases 

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 will 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 

population may be especially vulnerable to its adverse effects; these 

include the poor, the elderly, those already in poor health, the 

disabled, those living alone, and indigenous populations dependent on 
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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. 

O. National Technology Transfer and Advancement Act 

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 

U.S.C. 272 note) directs the EPA to use Voluntary Census Standards in 

their regulatory and procurement activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. Voluntary 

consensus standards are technical standards (e.g., materials 

specifications, test methods, sampling procedures, business 

practices) developed or adopted by one or more voluntary consensus 

bodies. The NTTAA directs the EPA to provide Congress, through annual 

reports to the OMB, with explanations when an agency does not use 

available and applicable VCS.

This rulemaking involves technical standards. The EPA cites the 

following standards in this proposed rule: EPA Methods 1 (Sample and 

velocity traverses for stationary sources), 2F (Determination of 
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Stack Gas Velocity and Volumetric Flow Rate With Three-Dimensional 

Probes), 2H (Determination of Stack Gas Velocity Taking Into Account 

Velocity Decay Near the Stack Wall), 3A (Determination of O2 and CO2

Concentrations in Emissions From Stationary Sources (Instrumental 

Analyzer Procedure)), 3B (Gas analysis for the determination of 

emission rate correction factor or excess air), 4 (Determination of 

Moisture Content in Stack Gases), and 19 (Determination of SO2 Removal 

Efficiency and PM, SO2, and NOX Emission Rates) of 40 CFR part 60. In 

addition, the EPA cites ASTM Methods D240-09 (Standard Test Method 

for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, for number 2 fuel oil heat content), D1826-94 (2010) 

(Standard Test Method for Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous Recording Calorimeter, for natural 

gas heat content), D4809-09a (Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision 

Method), for number 2 fuel oil heat content), 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 

ANSI/ASME Method PTC 19.19-1981 as an acceptable alternative to EPA 

Method 3B.
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Consistent with the NTTAA, the EPA conducted searches to 

identify VCS in addition to the identified EPA methods. No applicable 

VCS were identified for EPA Methods 2F, 2H, and 19. The search and 

review results have been documented and are placed in the docket for 

this proposed rule.

The search identified eight VCS that were potentially applicable 

for this rule in lieu of EPA reference methods. After reviewing the 

available standards, the EPA determined that the eight candidate VCS 

identified would not be practical due to lack of equivalency, 

documentation, validation data, and other important technical and 

policy considerations.

The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable VCS and to explain why such standards should 

be used in this action.
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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 

compliance?
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§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 fuel.

§60.5510 What is the affected source of this subpart?
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(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)) 

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 
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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].

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 450 kilograms (kg) of 

CO2 per gross output in Megawatt hours (MWh) (450 kg/MWh) on a 12-

operating month rolling average basis, except as provided for in 

paragraphs (b) through (d) of this section.

(b) If the affected EGU is designed to allow installation and 

operation of a carbon capture and storage (CCS) system and you plan 

to do so at a time when such a system is commercially available for 

your affected EGU, you may elect to comply with both standards in 

paragraphs (b)(1) and (2) as an alternative to complying with 

paragraph (a) of this section.

(1) You must not discharge any gases that contain CO2 from the 

affected EGU into the atmosphere in excess of 820 kg/MWh gross output 

on a 12-operating month rolling average basis.
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(2) You must not discharge any gases that contain CO2 from the 

affected EGU into the atmosphere in excess of 450 kg/MWh gross output 

on a 30-year average basis.

(c) If the affected EGU is located in a noncontinental area, you 

must not discharge any gases that contain CO2 from any affected EGU

into the atmosphere in excess of 630 kg/MWh gross output on a 12-

operating month rolling average basis.

(d) Stationary combustion turbine with a federally enforceable 

permit limiting its operation to no more than 3,000 hours per 

calendar year 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 

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 
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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. 

(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.

§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 
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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 

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 
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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 

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 
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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.

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 
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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. 

(d) You must monitor and record the applicable data needed to 

and 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 
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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.

(5) Add the quotient to the sum of the quotients of the previous 

11 operating months 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 
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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. 

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.

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 hard 

copy reports required under §60.7 must be postmarked by the 30th day 

following the end of each 6-month period.
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(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).

(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.

(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 
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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 35 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

§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 
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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.

(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 
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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 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.

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 
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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 

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 
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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 

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 
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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 useful work performed is 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 

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.
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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.

Noncontinental 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 

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 
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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 for a steam electric generating unit 

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) fossil-fuel heat input capacity would 

have a 289,080 MWh 12 month potential electrical output capacity). 

For a stationary combustion turbine potential electric output means 

50 percent of the maximum design heat input capacity of the 

stationary combustion turbine, divided by 3,413 Btu/kWh, divided by 

1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a stationary 

combustion turbine with a 100 MW (340 MMBtu/h) fossil-fuel heat input 

capacity would have a 438,000 MWh 12 month potential electrical 

output capacity). 

Solid fuel means any fuel that has a definite shape and volume, 

has no tendency to flow or disperse under moderate stress, and is not 

liquid or gaseous at ISO conditions. This includes, but is not 
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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 

heating or cooling application, i.e., total thermal energy made 
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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

§60.8 Performance tests No

§60.9 Availability of 

Information Yes

§60.10 State authority Yes

§60.11

Compliance with 

standards and 

maintenance 

requirements

No

§60.12 Circumvention Yes
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Page 208 of 208

§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