From: Frey, Nathan J.

To: Culligan, Kevin

Cc: Wayland, Robertj; Hutson, Nick; Fellner, Christian; Johnson, Mary

Subject: RE: Updated preamble

Date: Monday, September 16, 2013 12:39:35 PM

Thanks Kevin. Can you let me know when/if additional changes will be made? I would like to avoid

sending out multiple versions to reviewers. Many thanks,

Nathan

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

Sent: Friday, September 13, 2013 9:23 PM

To: Frey, Nathan J.

Cc: Wayland, Robertj; Hutson, Nick; Fellner, Christian; Johnson, Mary

Subject: Updated preamble

Nathan,

Per our discussion earlier today, here is an updated version of the preamble. We believe this

addresses the vast majority of the comments we have received (including the most substantive). In

my final review tonight, I noticed a few that we had not addressed. We will address them on

Monday. Further, as I noted, at the staff level, we will be re-reviewing for any typos or other

inadvertent errors and we expect that while our upper management has been involved in any of

the more substantive issues and in many cases has reviewed at least a draft of the text, when they

review the full package, they may have a few more edits.

I will be sending the reg text shortly. If you need to contact me this weekend, I will check e-mail

occasionally, but you can also call 240-426-1025.

- Kevin
EO 12866_EGU GHG NSPS 2060-AQ91 NPRM_20130628

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0495; FRL-9839-4]

RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissions from New 

Stationary Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: On April 13, 2012, the EPA proposed a new source 

performance standard for emissions of carbon dioxide for new 

affected fossil fuel-fired electric utility generating units. 

The EPA received more than 2.5 million comments on the proposed 

rule. After consideration of information provided in those 

comments, as well as consideration of continuing changes in the 

electricity sector, the EPA determined that revisions in its 

proposed approach are warranted. Thus, in a separate action, the 

EPA is rescinding the April 13, 2012 proposal, and in this 

action, the EPA is proposing new standards of performance for 

new affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. This action proposes a 

separate standard of performance for fossil fuel-fired electric 

utility steam generating units and integrated gasification 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Page 2 of 397

combined cycle units that burn coal, petroleum coke and other 

fossil fuels that is based on partial implementation of carbon 

capture and storage as the best system of emission reduction. 

This action also proposes standards for natural gas-fired 

stationary combustion turbines based on modern, efficient 

natural gas combined cycle technology as the best system of 

emission reduction.

DATES: Comments. Comments must be received on or before [INSERT 

THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL 

REGISTER OF THIS PROPOSED RULE]. Under the Paperwork Reduction 

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

required to make a decision concerning the information 

collection request between 30 and 60 days after [INSERT THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE], a 

comment to the OMB is best assured of having its full effect if 

the OMB receives it by [INSERT THE DATE 30 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER OF THIS PROPOSED RULE].

Public Hearing. The EPA will hold a public hearing (or 

hearings) on this proposal. The date, time, and location of the 

public hearing (or hearings) will be announced separately in a 

subsequent Federal Register notice. Oral testimony will be 

limited to five minutes per commenter. The EPA encourages 

commenters to submit written versions of their oral testimonies 
***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

Page 3 of 397

either electronically or in paper copy. The rulemaking docket 

will include verbatim transcripts and written statements. If you 

would like to present oral testimony at one of the hearings, 

please notify Ms. Pamela Garrett, Sector 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 two days in advance of the public hearings. The public 

hearings will provide interested parties the opportunity to 

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

EPA officials may ask clarifying questions during the oral 

presentations but will not respond to the presentations or 

comments at that time. Written statements and supporting 

information submitted during the comment period will be 

considered with the same weight as any oral comments and 

supporting information presented at the public hearing. For 

updates and additional information on the public hearings, 

please check the EPA’s website for this rulemaking, 

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

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID No. EPA-HQ-OAR-2013-0495, by one of the following methods:

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

instructions for submitting comments. 
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Page 4 of 397

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-and-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-

0495.

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

Docket ID No. EPA-HQ-OAR-2013-0495.

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

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

20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0495. Please include 

a total of two copies. In addition, please mail a copy of your 

comments on the information collection provisions to the Office 

of Information and Regulatory Affairs, OMB, Attn: Desk Officer 

for EPA, 725 17th St. NW, Washington, DC 20503.

Hand Delivery or Courier: Deliver your comments to the EPA 

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

Room 3334, Washington, DC, 20460, Attn: Docket ID No. EPA-HQOAR-2013-0495. Such deliveries are accepted only during the 

Docket Center’s normal hours of operation (8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding federal holidays), and 

special arrangements should be made for deliveries of boxed 

information.
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Instructions: All submissions must include the agency name 

and docket ID number (EPA-HQ-OAR-2013-0495). The EPA’s policy is 

to include all comments received without change, including any 

personal information provided, in the public docket, available 

online at http://www.regulations.gov, unless the comment 

includes information claimed to be Confidential Business 

Information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or 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-2013-0495. Clearly mark the part or all of the 

information that you claim to be CBI. For CBI information on a 

disk or CD-ROM that you mail to the EPA, mark the outside of the 

disk or CD-ROM as CBI and then identify electronically within 

the disk or CD-ROM the specific information you claim as CBI. In 

addition to one complete version of the comment that includes 

information claimed as CBI, you must submit a copy of the 

comment that does not contain the information claimed as CBI for 

inclusion in the public docket. Information so marked will not 
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Page 6 of 397

be disclosed except in accordance with procedures set forth in 

40 CFR part 2.

The EPA requests that you also submit a separate copy of 

your comments to the contact person identified below (see FOR 

FURTHER INFORMATION CONTACT). If the comment includes 

information you consider to be CBI or otherwise protected, you 

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

information claimed as CBI or otherwise protected.

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

system, which means the EPA will not know your identity or 

contact information unless you provide it in the body of your 

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

without going through http://www.regulations.gov, your email 

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

available on the Internet. If you submit an electronic comment, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption, and be free of any defects or viruses.
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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 federal holidays. 

The telephone number for the Public Reading Room is (202) 566-

1744, and the telephone number for the Air Docket is (202) 566-

1742. Visit the EPA Docket Center homepage at 

http://www.epa.gov/epahome/dockets.htm for additional 

information about the EPA’s public docket.

In addition to being available in the docket, an electronic 

copy of this proposed rule will be available on the Worldwide 

Web (WWW) through the Technology Transfer Network (TTN). 

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

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

promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. 
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FOR FURTHER INFORMATION CONTACT: 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 or 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.

SUPPLEMENTARY INFORMATION: Comments on the April 13, 2012 

proposal. The EPA previously proposed a new source performance 

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

fossil fuel-fired electric utility generating units (EGUs) on 

April 13, 2012 (77 FR 22392). The EPA considered comments 

submitted in response to the original April 13, 2012 proposal in 

developing this new proposal. However, we are rescinding the 

original proposal. If you would like consideration of comments 

submitted on the April 13, 2012 rulemaking to be considered in 

connection with this new proposal, you should submit new 

comments or re-submit your previous comments. Commenters who 

submitted public comments concerning any aspect of the previous 

original proposal will need to consider the applicability of 

those comments to this current proposal and submit them again, 
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if applicable, even if the comments are exactly or substantively 

the same as those previously submitted, to ensure consideration 

in the development of the final rulemaking.

Acronyms. A number of acronyms and chemical symbols are 

used in this preamble. While this may not be an exhaustive list, 

to ease the reading of this preamble and for reference purposes, 

the following terms and acronyms are defined as follows:

AB Assembly Bill

AEP American Electric Power

AEO Annual Energy Outlook

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing of Materials

BACT Best Available Control Technology

BDT Best Demonstrated Technology

BSER Best System of Emission Reduction

Btu/kWh British Thermal Units per Kilowatt-hour

Btu/lb British Thermal Units per Pound

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CBI Confidential Business Information

CCS Carbon Capture and Storage (or Sequestration)

CDX Central Data Exchange

CEDRI Compliance and Emissions Data Reporting Interface

CEMS Continuous Emissions Monitoring System

CFB Circulating Fluidized Bed

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 Generating Unit

EIA Energy Information Administration

EO Executive Order

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency
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FB Fluidized Bed

FGD Flue Gas Desulfurization

FOAK First-of-a-kind

FR Federal Register

GHG Greenhouse Gas

GW Gigawatts

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

IRPs Integrated Resource Plans

kg/MWh Kilogram per Megawatt-hour

kJ/kg Kilojoules per Kilogram

kWh Kilowatt-hour

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

lb CO2/MWh Pounds of CO2 per Megawatt-hour

lb CO2/yr Pounds of CO2 per Year

lb/lb-mole Pounds per Pound-Mole

MATS Mercury and Air Toxic Standards

MMBtu/hr Million British Thermal Units per Hour

MW Megawatt

MWe Megawatt Electrical

MWh Megawatt-hour

N2O Nitrous Oxide

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NAS National Academy of Sciences

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NOAK n

th-of-a-kind 

NRC National Research Council

NSPS New Source Performance Standards

NSR New Source Review

NTTAA National Technology Transfer and Advancement Act

O2 Oxygen Gas

OMB Office of Management and Budget

PC Pulverized Coal

PFC Perfluorocarbon

PM Particulate Matter

PM2.5 Fine Particulate Matter

PRA Paperwork Reduction Act

PSD Prevention of Significant Deterioration

PUC Public Utilities Commission
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RCRA Resource Conservation and Recovery Act

RFA Regulatory Flexibility Act

RGGI Regional Greenhouse Gas Initiative

RIA Regulatory Impact Analysis

RPS Renewable Portfolio Standard

RTC Response to Comments

RTP Response to Petitions

SBA Small Business Administration

SCC Social Cost of Carbon

SCR Selective Catalytic Reduction

SF6 Sulfur Hexafluoride

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

SSM Startup, Shutdown, and Malfunction

Tg Teragram (one trillion (1012) grams)

Tpy Tons per Year

TSD Technical Support Document

TTN Technology Transfer Network

UIC Underground Injection Control

UMRA Unfunded Mandates Reform Act of 1995

U.S. United States

USGCRP U.S. Global Change Research Program

VCS Voluntary Consensus Standard

WGS Water Gas Shift 

WWW Worldwide Web

Organization of This Document. The information presented in 

this preamble is organized as follows:

I. General Information

A. Executive summary

B. Overview 

C. Does this action apply to me?

II. Background

A. Climate change impacts from GHG emissions

B. GHG emissions from fossil fuel-fired EGUs

C. The utility power sector and how its structure is changing 

D. Statutory background

E. Regulatory and litigation background

F. Coordination with other rulemakings

G. Stakeholder input

III. Proposed Requirements for New Sources

A. Applicability requirements

B. Emission standards
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C. Startup, shutdown, and malfunction requirements

D. Continuous monitoring requirements

E. Emissions performance testing requirements

F. Continuous compliance requirements

G. Notification, recordkeeping, and reporting requirements

IV. Rationale for Reliance on Rational Basis to Regulate GHGs 

from Fossil-fired EGUs

A. Overview

B. Climate Change Impacts from GHG Emissions; Amounts of GHGs 

from fossil fuel-fired EGUs

C. CAA § 111 requirements

D. Interpretation of CAA § 111 requirements

E. Rational basis to promulgate standards for GHGs from fossilfired EGUs

F. Alternative findings of endangerment and significant 

contribution

G. Comments on the state of the science of climate change 

V. Rationale for Applicability Requirements

A. Applicability requirements - original proposal and comments

B. Applicability requirements – today’s proposal

VI. Legal Requirements for Establishing Emission Standards

A. Overview

B. CAA requirements and Court interpretation

C. Technical feasibility

D. Factors to consider in determining the “best system”

E. Nationwide component of factors in determining the “best 

system”

F. Chevron framework

G. Agency discretion

H. Lack of requirement that standard be able to be met by all 

sources

VII. Rationale for Emission Standards for New Fossil Fuel-fired 

Boilers and IGCCs

A. Overview

B. Identification of the best system of emission reduction

C. Determination of the level of the standard

D. Extent of reductions in CO2 emissions

E. Technical feasibility

F. Costs

G. Promotion of technology

H. Nationwide, longer-term perspective

I. Deference

J. CCS and BSER in locations where costs are too high to 

implement CCS

K. Compliance period

L. Geologic sequestration
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VIII. Rationale for Emission Standards for Natural Gas-fired 

Stationary Combustion Turbines

A. Best system of emission reduction

B. Determination of the standards of performance

IX. Rationale for Compliance Requirements

IX. Implications for PSD and Title V Programs

A. Overview

B. Applicability of tailoring rule thresholds under the PSD 

program

C. Implications for BACT determinations under PSD

D. Implications for title V program

E. Implications for title V fee requirements for GHGs

XI. 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?

XII. Request for Comments

XIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act as Amended by the Small Business 

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

seq.

D. Unfunded Mandates Reform Act of 1995

E. Executive Order 13132, Federalism

F. Executive Order 13175, Consultation and Coordination With 

Indian Tribal Governments

G. Executive Order 13045, Protection of Children From 

Environmental Health Risks and Safety Risks

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

XIII. Statutory Authority

I. General Information

A. Executive summary
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1. Purpose of the regulatory action 

On April 13, 2012, under the authority of Clean Air Act 

(CAA) section 111, the EPA proposed a new source performance 

standard (NSPS) to limit emissions of carbon dioxide (CO2) from 

new fossil fuel-fired electric utility generating units (EGUs), 

including, primarily, coal- and natural gas-fired units (77 FR 

22392). After consideration of the information provided in more 

than 2.5 million comments on the proposal, as well as 

consideration of continuing changes in the electricity sector,

the EPA is issuing a new proposal. Today’s action proposes to 

establish separate standards for fossil fuel-fired electric 

steam generating units (utility boilers and Integrated 

Gasification Combined Cycle (IGCC) units) and for natural gasfired stationary combustion turbines. These proposed standards 

reflect separate determinations of the best system of emission 

reduction adequately demonstrated (BSER) adequately demonstrated 

for utility boilers and IGCC units and for natural gas-fired 

stationary combustion turbines. Because, iIn contrast, the April 

2012 proposal relied on a single standard and a single BSER 

determination for all new fossil fuel-fired units. In addition, 

the applicability requirements proposed today differ from the 

applicability requirements in the original proposal. In light of 

these and other differences, the EPA is issuing, as a final 
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Page 15 of 397

action, a notice (published separately in today’s Federal 

Register) that rescinds the original proposal, as well as 

issuing this new proposal.

2. Summary of the major provisions 

This action proposes a standard of performance for utility 

boilers and IGCC units based on partial implementation of carbon 

capture and storage (CCS) as the BSER. The proposed emission 

limit for those sources is 1,100 lb CO2/MWh.1 This action also 

proposes standards of performance for natural gas-fired 

stationary combustion turbines based on modern, efficient 

natural gas combined cycle (NGCC) technology as the BSER. The 

proposed emission limits for those sources are 1,000 lb CO2/MWh 

for larger units and 1,100 lb CO2/MWh for smaller units. At this 

time, the EPA is not proposing standards of performance for 

modified or reconstructed sources.

3. Costs and benefits

As explained in the Regulatory Impact Analysis (RIA) for 

this proposed rule, available data – including utility

announcements and EIA modeling - indicate that, even in the 

absence of this rule, (i) existing and anticipated economic 

conditions mean that few, if any, solid fossil fuel-fired EGUs 

 

1 In this rulemaking, all references to lb CO2/MWh are on a gross 

output basis, unless specifically noted otherwise.
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will be built in the foreseeable future; and (ii) electricity 

generators are expected to choose new generation technologies 

(primarily natural gas combined cycle) that would meet the 

proposed standards. Therefore, based on the analysis presented 

in Chapter 5 of the RIA, the EPA projects that this proposed 

rule will result in negligible CO2 emission changes, quantified 

benefits, and costs by 2022.2 These projections are in line with 

utility announcements and Energy Information Administration 

(EIA) modeling that indicate that coal units built between now 

and 2020 would have CCS, even in the absence of this rule. 

However, for a variety of reasons, some companies may consider 

coal units that the modeling does not anticipate. Therefore, in 

Chapter 5 of the RIA, we also present an analysis of the 

project-level costs of a new coal-fired unit with partial CCS 

alongside the project-level costs of a new coal-fired unit 

without CCS.

B. Overview 

1. Why is the EPA issuing this proposed rule?

Greenhouse gas (GHG) pollution3 threatens the American 

public's health and welfare by contributing to long-lasting 

 

2 Conditions in the analysis year of 2022 are represented by a 

model year of 2020.

3 Greenhouse gas pollution is the aggregate group of the 

following gases: CO2, methane (CH4), nitrous oxide (N20), sulfur 
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Page 17 of 397

changes in our climate that can have a range of negative effects 

on human health and the environment. The impacts could include:

longer, more intense and more frequent heat waves; more intense 

precipitation events and storm surges; less precipitation and 

more prolonged drought in the West and Southwest; more fires and 

insect pest outbreaks in American forests, especially in the 

West; and increased ground level ozone pollution, otherwise 

known as smog, which has been linked to asthma and premature 

death. Health risks from climate change are especially serious 

for children, the elderly and those with heart and respiratory 

problems. 

The U.S. Supreme Court ruled that GHGs meet the definition 

of “air pollutant” in the CAA, and this decision clarified that 

the CAA’s authorities and requirements apply to GHG emissions. 

Unlike most other air pollutants, GHGs may persist in the 

atmosphere from decades to millennia, depending on the specific 

greenhouse gas. This special characteristic makes it crucial to

take initial steps now to limit GHG emissions from fossil fuelfired power plants, specifically emissions of CO2, since they are 

the nation’s largest sources of carbon pollution. This rule will 

ensure that the next generation of fossil fuel-fired power 

 

hexafluoride (SF6), hydrofluorocarbons (HFCs), and 

perfluorocarbons (PFCs).
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plants in this country will use modern technologies that limit 

harmful carbon pollution.

On April 13, 2012, the EPA issued a proposed rule to limit 

GHG emissions from fossil fuel-fired power plants by 

establishing a single standard applicable to all new fossil 

fuel-fired EGUs serving intermediate and base load power demand. 

After consideration of the information provided in more than 2.5 

million comments on the proposal, as well as consideration of 

continuing changes in the electricity sector4, the EPA is issuing 

a new proposal to establish separate standards for fossil fuelfired electric steam generating units (utility boilers and IGCC 

units) and for natural gas-fired stationary combustion turbines.

These proposed standards reflect separate determinations of the 

BSER adequately demonstrated for utility boilers and IGCC units

and for natural gas-fired stationary combustion turbines. 

Because, in contrast, the April 2012 proposal relied on a single 

standard for all new fossil fuel-fired units, the EPA is 

issuing, as a final action, a notice (published separately in 

today’s Federal Register) that rescinds the original proposal, 

 

4 For example, since April 2012, there has been significant 

progress on two CCS projects (Kemper County and Boundary Dam), 

and they are now both over 75 percent complete. Two other 

projects have continued to make progress toward construction

(Texas Clean Energy Project and Hydrogen Energy California 

Project).
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as well as issuing this new proposal.

2. What authority is the EPA relying on to address power plant 

CO2 emissions?

Congress established requirements under section 111 of the 

1970 CAA to control air pollution from new stationary sources 

through NSPS. Specifically, section 111 requires the EPA to set 

technology-based standards for new stationary sources to 

minimize emissions of air pollution to the environment. For more 

than four decades, the EPA has used its authority under section 

111 to set cost-effective emission standards that ensure newly 

constructed sources use the best performing technologies to 

limit emissions of harmful air pollutants. In this proposal, the 

EPA is following the same well-established, customary 

interpretation and application of the law under section 111 to 

address GHG emissions from new fossil fuel-fired power plants. 

3. What sources should the EPA include as it develops proposed 

standards for GHGs for power plants?

Before determining the appropriate technologies and levels 

of control that represent BSER for GHG emissions, the EPA must 

first identify the appropriate sources to control.

The starting point is to consider whether, given current 

trends concerning coal-fired and natural gas-fired power plants 

and the nature of GHGs, the EPA’s should regulate CO2 from these Formatted: Subscript
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power plants through the same current NSPS regulatory structure

is appropriatethat EPA has established for conventional 

pollutants. The EPA’s NSPS regulations already regulate 

conventional pollutants from these sources under two 40 CFR part 

60 subparts: subpart Da, electric utility steam generating 

units, which includes both steam electric utility boilers and 

IGCC units, and subpart KKKK, stationary combustion turbines, 

which includes both simple cycle and combined cycle stationary 

combustion turbines. 

For sources covered under subpart Da, the original proposal 

relied on analyses, primarily undertaken by EIA, indicating 

that, while substantial reliance on coal-fired electricity 

generation would continue in the future, few, if any, new coalfired power plants without CCS were likely to be built by 2025. 

Based in part on these results, the EPA concluded that it was 

appropriate to propose in April 2012 a single fuel-neutral 

standard covering all intermediate and base load units based on 

the performance of recently constructed NGCC units. In light of 

developments in the electricity sector since the April 2012 

proposal, and in response to numerous comments on the proposal 

itself, the EPA is changing the approach in today's notice and 
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proposing to set separate standards for new sources covered by 

subpart Da.

5

The EPA notes that, since the original April 2012 proposal, 

a few coal-fired units have reached the advanced stages of 

construction and development, which suggests that proposing a 

separate standard for coal-fired units is appropriate. Since the 

original proposal, progress on Southern Company's Kemper County 

Energy Facility, an IGCC facility which that will implement 

partial CCS, has continued, and the project is now over 75

percent complete. Similarly, SaskPower’s Boundary Dam CCS 

Project in Estevan, Saskatchewan, a project that will fully 

integrate the rebuilt 110 MW coal-fired Unit #3 with available 

CCS technology to capture 90 percent of its CO2 emissions, is 

more than 75 percent complete. Performance testing is expected 

to commence in late 2013 and the facility is expected to be 

fully operational in 2014.

Additionally, two other IGCC projects, Summit Power's Texas 

Clean Energy Project (TCEP) and the Hydrogen Energy California 

Project (HECA) – both of which are IGCC units with CCS –

continue to move forward. Further, NRG Energy is developing a 

commercial-scale post-combustion carbon capture project at the 

 

5 While the emphasis of EPA’s BSER determination is on coal- and 

petcoke-fired units, the subpart covers all fossil fuel-fired 

EGU boilers and IGCC units, including those burning oil and gas.
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Company's WA Parish generating station southwest of Houston, 

Texas. The facility is expected to be operational in 2015.

Continued progress on these projects is consistent with the EIA 

modeling which projects that few, if any, new coal-fired EGUs 

would be built in this decade and that those that are built 

would include CCS.6 The existence and apparent ongoing viability 

of these projects which include CCS justify a separate BSER 

determination for new fossil fuel-fired utility boilers and IGCC 

power plants.

In addition to these projects, a number of commenters (to 

on the April 2012 proposal) noted that, if natural gas prices 

increase, there could be greater interest in the construction of 

additional coal-fired generation capacity. This, too, is 

consistent with the EIA analysis, which also suggests that, in a 

limited number of potential scenarios generally associated with 

both significantly higher than anticipated electric demand and 

significantly higher than expected natural gas prices, some 

additional new coal-fired generation capacity may be built 

 

6 Even in its sensitivity analysis, the EIA does not project any 

additional coal projects beyond its reference case until 2023, 

in a case where power companies assume no emission limitations 

for GHGs, and until 2024 in any sensitivity analysis in which

there are emission limitations for GHGs.
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beyond 2020. It is also consistent with publicly available 

electric utility Integrated Resource Plans (IRPs).

7

Many of those IRPs indicated the utilities’ interest in 

developing some amount of generating capacity using other 

intermediate-load and base load technologies, in addition to new 

NGCC capacity, to meet future demand (albeit, almost always at a 

higher cost than NGCC technology). Only a few utilities’ IRPs 

indicated that new coal-fired generation without CCS was a 

technology option that was being considered to meet future 

demand. Finally, a number of commenters suggested that it was 

important to set standards that preserve options for fuel 

diversity, particularly if natural gas prices exceed projected 

levels. Given this information, the EPA believes that it is 

appropriate to set a separate standard for solid fossil fuelfired EGUs, both to address the small number of coal plants that 

evidence suggests might get built and to set a standard that is 

robust across a full range of possible futures in the energy and 

electricity sectors.

Utility announcements (about the status of coal projects), 

IRPs, and EIA projections suggest that, by far, the largest 

 

7 IRPs are planning documents that many Public Utility 

Commissions require utilities to file outlining their plans to 

meet future demand. Many of the IRPs that the EPA has reviewed 

included planning horizons of ten years or more.
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sources of new fossil fuel-fired electricity generation are 

likely to be NGCC units. The EPA believes, therefore, that it is 

also appropriate to set a standard for stationary combustion 

turbines used as EGUs. These units are currently covered under 

subpart KKKK (stationary combustion turbines). 

The EPA also proposes to maintain the definition of EGUs 

under the NSPS that differentiates between EGUs (sources used 

primarily for generating electricity for sale to the grid) and 

non-EGUs (turbines primarily used to generate steam and/or 

electricity for on-site use). That definition defines EGUs as 

units that sell more than one-third of their potential electric 

output to the grid. Under this definition, most simple cycle 

“peaking” stationary combustion turbines, which typically sell 

significantly less than one-third of their potential electric 

output to the grid, would not be affected by today’s proposal.

Finally, the EPA is not proposing standards today for one 

conventional coal-fired EGU project which, based on current 

information, appears to be the only such project under 

development that has an active air permit and that has not 

already commenced construction for NSPS purposes. If the EPA 

observes that the project is truly proceeding, it may propose a 

new source performance standard specifically for that source at 

the time the EPA finalizes today’s proposed rule.
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4. What is the EPA’s general approach to setting standards for 

new sources under Section 111(b)?

Section 111(b) requires the EPA to identify the “best 

system of emission reduction ... adequately demonstrated” (BSER) 

available to limit pollution. The CAA and subsequent court 

decisions (detailed later in this notice) identify the factors 

for the EPA to consider in a BSER determination. For this 

rulemaking, the following factors are key: feasibility, costs, 

size of emission reductions and technology. 

Feasibility: The EPA considers whether the system of 

emission reduction is technically feasible.

Costs: The EPA considers whether the costs of the system 

are unreasonable. 

Size of emission reductions: The EPA considers the amount 

of emissions reductions that the system would generate.

Technology: The EPA considers whether the system promotes 

the implementation and further development of technology.

After considering these four factors, we propose that

partial implementation of CCS technology is the BSER for new 

affected fossil fuel-fired boilers and IGCC units (subpart Da 

sources) and modern, efficient NGCC units is the BSER for new 

affected combustion turbines (subpart KKKK sources). The 
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foundations for these determinations are described in sections

VII and VIII.

5. What is BSER for new fossil fuel-fired utility boilers and 

IGCC units?

Power generated from the combustion or gasification of coal 

emits more CO2 than power generated from the combustion of 

natural gas or by other means, such as solar or wind. If any new 

coal-fired unit is built, its CO2 emissions would be 

approximately double that of a new NGCC unit of comparable 

capacity. Thus, it is important to set a standard for any new 

coal plant that might be built. 

The three alternatives the EPA considered in the BSER 

analysis for new fossil fuel-fired utility boilers and IGCC 

units are: (1) highly efficient new generation that does not 

include CCS technology, (2) new generation with “full capture” 

CCS and (3) new generation with “partial capture” CCS. 

Generation technologies representing enhancements in 

operational efficiency (e.g., supercritical or ultrasupercritical coal-fired boilers or IGCC units) are clearly 

technically feasible and present little or no incremental cost 

compared to the types of technologies that some companies are 

considering for new coal-fired generation capacity. However, 

they do not provide meaningful reductions in CO2 emissions from 
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new sources. Efficiency-improvement technologies alone result in 

only very small reductions (several percent) in CO2 emissions, 

especially in contrast to those achieved by the application of 

CCS. Determining that these high-efficiency generating 

technologies represent the BSER for CO2 emissions from coal-fired 

generation would fail to promote the development and deployment 

of CO2 pollution-reduction technology from power plants. In fact, 

a determination that this efficiency-enhancing technology alone, 

as opposed to CCS, is the BSER for CO2 emissions from new coalfired generation likely would inhibit the development of 

technology that could reduce CO2 emissions significantly, thus 

defeating one of the purposes of the CAA's NSPS provisions. For 

example, during its pilot-scale CCS demonstration at the 

Mountaineer Plant in New Haven, WV, American Electric Power 

(AEP) announced in 2011 that it was placing on hold its plans to 

scale-up the CCS system, citing the uncertain status of U.S. 

climate policy as a key contributing factor to its decision.

An assessment of the technical feasibility and availability 

of CCS indicates that at least halfnearly all of the coal-fired 

power plants that are currently under development are designed 

to use some type of CCS. In most cases, the projects will sell 

or use the captured CO2 to generate additional revenue. These 

projects include the following (note that each of the U.S. 
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projectswhich has obtained some governmental financial 

assistance):

Southern Company’s Kemper County Energy Facility, a 582 MW 

IGCC power plant that is currently under construction in 

Kemper County, Mississippi. The plant will include a CCS 

system designed to capture approximately 65 percent of the 

produced CO2.

SaskPower’s Boundary Dam CCS Project, in Estevan, 

Saskatchewan, Canada, is a commercial-scale CCS project 

that will fully integrate the rebuilt 110 MW coal-fired 

Unit #3 with available CCS technology to capture 90 percent

of its CO2 emissions. 

Texas Clean Energy Project (TCEP), an IGCC plant near 

Odessa, Texas, that is under development by the Summit 

Power Group, Inc. (Summit). TCEP is a 400 MW IGCC plant 

that expects to capture approximately 90 percent of the 

produced CO2.

Hydrogen Energy California, LLC (HECA), is proposing to 

build a plant similar to TCEP in western Kern County, 

California. The HECA plant is an IGCC plant fueled by coal 

and petroleum coke that will produce 300 MW of power and 

will capture CO2 for use in enhanced oil recovery (EOR) 
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operations. They expect to capture approximately 90 percent 

of the produced CO2.

The above examples suggest that project developers who are 

incorporating CCS generally considered two variants: either a 

partial CCS system or a full CCS system (i.e., usually 90 

percent capture or greater). Therefore, the EPA considered both 

options.

In assessing whether the cost of a certain option is 

reasonable, the EPA first considered the appropriate frame of 

reference. Power companies often choose the lowest cost form of 

generation when determining what type of new generation to 

build. Based on both the EIA modeling and utility IRPs, there 

appears to be a general acceptance that the lowest cost form of 

new power generation is NGCC. 

Many states find value in coal investments and have 

policies and incentives to encourage coal energy generation. 

Utility IRPs (as well as comments on the April 2012 proposal) 

suggest that many companies also find value in other factors, 

such as fuel diversity, and are often willing to pay a premium 

for it. Utility IRPs suggest that a range of technologies can 

meet the preference for fuel diversity from a dispatchable form 

of generation that can provide intermediate or base-load power, 

including coal without CCS, coal with CCS and nuclear. Biomass-
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fired power generation8 and geothermal power generation are other 

technologies that are dispatchable and that could potentially 

meet this objective. These technologies all cost significantly 

more than natural gas-fired generation, which ranges from a 

levelized cost of electricity (LCOE)9 of $59/MWh to $86/MWh, 

depending upon assumptions about natural gas prices. In 

assessing whether the cost of coal with CCS would have an 

unreasonable impact on the cost of power generation, the EPA 

believes it is appropriate to compare coal with CCS to this 

range of non-natural gas-fired electricity generation options. 

Based on data from the EIA and the DOE National Energy and 

Technology Laboratory (NETL), the EPA believes that the 

levelized cost of technologies other than coal with CCS and NGCC 

range from $80/MWh to $130/MWh. These include nuclear, from

$103/MWh to $114/MWh;, biomass, from $97/MWh to $130/MWh;, and 

geothermal, from $80/MWh to $99/MWh.

The EPA believes the cost of “full capture” CCS without EOR 

is outside the range of costs that companies are considering for 

 

8 The proposed CO2 emission standards would only apply to new 

fossil fuel-fired EGUs. New EGUs that primarily fire biomass 

would not be subject to these proposed standards. 

9 The levelized cost of electricity is an economic assessment of 

the cost of electricity from a new generating unit or plant, 

including all the costs over its lifetime: initial investment, 

operations and maintenance, cost of fuel, and cost of capital.

The LCOE value presented here are in $2007.
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comparable generation and therefore should not be considered

BSER for CO2 emissions for coal-fired power plants. The EPA 

projects the LCOE of generation technologies with full capture 

CCS to be in the range of $136/MWh to $147/MWh (without EOR 

benefits).

10 Because these ”full capture” CCS costs without EOR 

are significantly above the price range of potential alternative 

generation options, the EPA believes that full capture CCS does 

not meet the cost criterion of BSER.

Finally, the EPA considered whether implementation of 

“partial capture” CCS should be proposed to be BSER for new 

fossil fuel-fired utility boilers and IGCC units. 

Partial capture CCS has been implemented successfully in a 

number of facilities over many years. The Great Plains Synfuels 

Facility11 is a coal gasification facility that has captured at 

 

10 The cost assumptions and technology configurations for these 

cost estimates are provided in the DOE/NETL “Cost and 

Performance Baseline” reports. For these cost estimates, we used 

costs for new SCPC and IGCC units utilizing bituminous coal from 

the reports “Cost and Performance Baseline for Fossil Energy 

Plants Volume 1: Bituminous Coal and Natural Gas to 

Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 

2010) and “Cost and Performance of PC and IGCC Plants for a 

Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 

2011. Additional cost and performance information can be found

in additional volumes that are available at 

http://www.netl.doe.gov/energy-analyses/baseline_studies.html.

11 While this facility is not an EGU, it has significant 

similarities to a coal gasification combined cycle EGU, and the 

implementation of the partial CCS technology would be similar 

enough for comparison.

Comment [A1]: Are there any international 

facilities that can be referenced here?

EPA: A reference is provided.
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least 50 percent of its produced CO2 for use in EOR operations 

since 2000. Projects such as AEP Mountaineer have successfully 

demonstrated the performance of partial capture CCS on a 

significant portion of their exhaust stream. The Southern 

Company Kemper County Energy Facility will use partial CCS to 

capture approximately 65 percent of the produced CO2 for use in 

nearby EOR operations. The facility is now more than 75 percent 

complete and is expecting to begin operation in 2014. The Global 

CCS Institute maintains a database of international CCS projects 

in various stages of development.12

The EPA analysis shows that the costs of partial CCS are 

comparable to costs of other non-NGCC generation. The EPA 

projects LCOE generation ranging from $92/MWh to $110/MWh, 

depending upon assumptions about technology choices and the 

amount, if any, of revenue from sale of CO2 for EOR. This range 

compares to levelized costs in a range of $80/MWh to $130/MWh 

for various forms of other non-natural gas-fired electricity 

generation. When considered against the range of costs that 

would be incurred by projects deploying non-natural gas-fired 

electricity generation, the implementation costs of partial CCS 

are, clearly, not unreasonable.

 

12 The Global CCS Institute, 

http://www.globalccsinstitute.com/projects/browse
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The projects in development for new coal-fired generation 

are few in number, and most would already meet an emission limit 

based on implementation of partial CCS.13 As a result, a standard 

based on partial CCS would not have a significant impact on 

nationwide energy prices. Moreover, the fact that IGCC 

developers could meet the requirements of the standard through 

the use of a conventional turbine (i.e., a syngas turbine, 

rather than a more advanced hydrogen turbine) reinforces both 

the technical feasibility and cost basis of today’s proposal to 

determine that CCS with partial capture is the BSER. 

Partial CCS designed to meet an emission standard of 1,100 

lb CO2/MWh would also achieve significant emission reductions, 

emitting on the order of 30 to 50 percent less CO2 than a coalfired unit without CCS. Finally, a standard based on partial CCS 

clearly promotes implementation and further development of CCS 

technologies, and does so as much as, and perhaps even more 

than, a standard based on a full capture CCS requirement would. 

After conducting a BSER analysis of the three options 

described above, the EPA proposes that new fossil fuel-fired 

utility boilers and IGCC units implementing partial CCS best 

meets the requirements for BSER. It ensures that any new fossil 

 

13 For example, the Kemper County IGCC facility (though not 

subject to these proposed standards) plans to capture 

approximately 65% of the CO2 in the emission stream.

Comment [dj2]: Per OMB:

Add a FN noting which facilities would already meet 

an emission limit based on partial CCS

EPA: Footnote added.
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fuel-fired utility boiler or IGCC unit will achieve meaningful 

emission reductions in CO2, and it will also encourage greater 

use, development, and refinement of CCS technologies. CCS 

technology has been adequately demonstrated, and its 

implementation costs are reasonable. Therefore, the EPA is 

basing the standards for new fossil fuel-fired utility boilers 

and IGCC units on partial CCS technology operating to a level of 

1,100 lb CO2/MWh. 

6. What is BSER for natural gas-fired stationary combustion 

turbines? 

We considered two alternatives in evaluating the BSER for 

new fossil fuel-fired stationary combustion turbines: (1) 

modern, efficient NGCC units and (2) modern, efficient NGCC 

units with CCS.

NGCC units are the most common type of new fossil fuelfired units being planned and built today. The technology is in 

wide use. Nearly all new fossil fuel-fired EGUs being 

constructed today are using this advanced, efficient system for 

generating intermediate and base load power. Importantly, NGCC 

is an inherently lower CO2-emitting technology. Almost every 

natural gas-fired stationary combined cycle unit built in the 

U.S. in the last five years emits approximately 50 percent less 

CO2 per MWh than a typical new coal-fired plant of the same size. 
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The design is technically feasible, and evidence shows that NGCC 

units are currently the lowest-cost, most efficient option for 

new fossil fuel-fired power generation.

By contrast, NGCC with CCS is not a configuration that is 

being planned and built today. The EPA considered whether NGCC 

with CCS could be identified as the BSER adequately demonstrated 

for new stationary combustion turbines, and we decided that it 

could not be identified for several reasons. At this time, CCS 

has not been implemented for NGCC units, and we believe there is 

insufficient information to make a determination regarding the 

technical feasibility of implementing CCS at these types of 

units. The EPA is aware of only one NGCC unit that has 

implemented CCS on a very small portion of its exhaust stream. 

This contrasts with coal units where, in addition to 

demonstration projects, there are several full-scale projects

under construction and a coal gasification plant which has been 

demonstrating much of the technology needed for an IGCC to

capture CO2 for more than ten years. The EPA is not aware of any 

demonstrations of NGCC units implementing CCS technology that 

would justify setting a national standard. Further, the EPA does 

not have sufficient information on the prospects of transferring 

the coal-based experience with CCS to NGCC units. In fact, CCS 

technology has primarily been applied to gas streams that have a 

Comment [dj3]: Per OMB:

Why is it not enough to say that there isn’t sufficient 

information? It seems odd to question the technical 

feasibility of implementing CCS at NGCC units. Is 

there a way to talk about the potential for emissions 

reductions from CCS at NGCC units, and compare 

that to the cost? Or note that there is not enough 

data to do such an analysis? Having one NGCC unit 

indicates that it is technically feasible.

EPA: We indicate that there is insufficient 

information to determine the technical feasibility.

Comment [dj4]: Per OMB:

Clarify the percent involved in “a very small portion 

of its exhaust stream”

EPA: We have edited that statement.
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relatively high to very high concentration of CO2 (such as that 

from a coal combustion or coal gasification unit). The 

concentration of CO2 in the flue gas stream of a coal combustion 

unit is normally about four times higher than the concentration 

of CO2 in a natural gas-fired unit. Natural gas-fired stationary 

combustion turbines also operate differently from coal-fired 

boilers and IGCC units of similar size. The NGCC units are more 

easily cycled (i.e., ramped up and down as power demands 

increase and decrease). Adding CCS to a NGCC may limit the 

operating flexibility in particular during the frequent startups/shut-downs and the rapid load change requirements.14 This 

cyclical operation, combined with the already low concentration 

of CO2 in the flue gas stream, means that we cannot assume that 

the technology can be easily transferred to NGCC without larger 

scale demonstration projects on units operating more like a 

typical NGCC. This would be true for both partial and full 

capture. 

After considering both technology options, the EPA is 

proposing to find modern, efficient NGCC technology to be the 

BSER for stationary combustion turbines, and we are basing the 

proposed standards on the performance of recently constructed 

 

14 “Operating Flexibility of Power Plants with CCS”, 

International Energy Agency (IEAGHG) report 2012/6, June 2012.
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NGCC units. The EPA is proposing that larger units be required 

to meet a standard of 1,000 lb CO2/MWh and that smaller units 

(typically slightly less efficient, as noted in comments on the 

original proposal) be required to meet a standard of 1,100 lb 

CO2/MWh.

7. How is EPA proposing to codify the requirements? 

The EPA is considering two options for codifying the 

requirements. Under the first option EPA is proposing to 

issuecodify the standards of performance for the respective 

sources within existing 40 CFR part 60 subparts. Applicable GHG 

standards for electric utility steam generating units would be 

listed underincluded in subpart Da and applicable GHG standards 

for standards for stationary combustion turbines would be listed 

underincluded in subpart KKKK. In the second option, the EPA is

co-proposing to create a new subpart TTTT (as in the original 

proposal for this rulemaking) and to listinclude all GHG 

standards of performance for covered sources in that newly 

created subpart. Unlike the original proposal, the subpart would 

contain two different categories, one for utility boilers and 

IGCC units and one for natural gas-fired stationary combustion 

turbines.

8. What is the organization and approach for the proposal?
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This action presents the EPA’s proposed approach for 

setting standards of performance for new affected fossil fuelfired electric utility steam generating units (utility boilers) 

and stationary combustion turbines. The rationale for regulating 

GHG emissions from the utility power sector, including related 

regulatory and litigation background and relationship to other 

rulemakings, is presented below in section II. The specific 

proposed requirements for new sources are described in detail in 

section III. The rationale for reliance on a rational basis to 

regulate GHG emissions from fossil fuel-fired EGUs is presented 

in section IV, followed by the rationale for applicability 

requirements in section V. The legal requirements for 

establishing emission standards are discussed in detail in 

section VI. Sections VII and VIII describe the rationale for 

each of the proposed emission standards, including an 

explanation of the determination of BSER for new fossil fuelfired utility boilers and IGCC units and for natural gas-fired 

stationary combustion turbines, respectively. Rationale for 

other proposed requirements is discussed in section IX. 

Implications for Prevention of Significant Deterioration (PSD)

and title V programs are described in section X, and impacts of 

the proposed action are described in section XI. In section XII, 

the agency specifically requests comments on the proposal. A 
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discussion of statutory and executive order reviews is provided 

in section XIII. Also published today in the Federal Register is 

the notice rescinding the original April 13, 2012 proposal.

Today’s proposal outlines an approach for setting standards 

of performance for emissions of carbon dioxide for new affected 

fossil fuel-fired electric utility steam generating units 

(utility boilers) and stationary combustion turbines.

C. 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 Affected 

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 Includes 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 
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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

In this section we discuss climate change impacts from GHG 

emissions, both on public health and public welfare, and the 

science behind the agency’s conclusions. We present information 

about GHG emissions from fossil-fuel fired EGUs, and we describe 

the utility power sector and its changing structure. We then 

provide the statutory, regulatory, and litigation background for 

this proposed rule. We close this section by discussing how this 

proposed rule coordinates with other rulemakings and describing 

actions to obtain stakeholder input on this topic and the 

original proposed rule.

A. Climate change impacts from GHG emissions
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In 2009, the EPA Administrator issued the document we refer 

to as the Endangerment Finding under CAA section 202(a)(1).15 In 

the Endangerment Finding, which focused on public health and 

public welfare impacts within the United States, the 

Administrator found that elevated concentrations of GHGs in the 

atmosphere may reasonably be anticipated to endanger public 

health and welfare of current and future generations. We 

summarize these adverse effects on public health and welfare 

briefly here and in more detail in the RIA. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding

Anthropogenic emissions of GHGs and consequent climate 

change threaten public health in multiple aspects. By raising 

average temperatures, climate change increases the likelihood of 

heat waves, which are associated with increased deaths and 

illnesses. While climate change also leads to reductions in 

cold-related mortality, evidence indicates that the increases in 

heat mortality will be larger than the decreases in cold 

mortality. Climate change is expected to increase ozone 

pollution over broad areas of the country, including large 

population areas with already unhealthy surface ozone levels, 

 

15 “Endangerment and Cause or Contribute Findings for Greenhouse 

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

66,496 (Dec. 15, 2009) (“Endangerment Finding”).
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and thereby increase morbidity and mortality. Other public 

health threats also stem from increases in intensity or 

frequency of extreme weather associated with climate change,

such as increased hurricane intensity, increased frequency of 

intense storms and heavy precipitation. Increased coastal storms 

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

increased drownings and other health impacts. Children, the 

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

climate-related health effects.

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding

Anthropogenic emissions of GHGs and consequent climate 

change also threaten public welfare in multiple aspects. Climate 

changes are expected to place large areas of the country at 

serious risk of reduced water supplies, increased water 

pollution, and increased occurrence of extreme events such as 

floods and droughts. Coastal areas are expected to face 

increased risks from storm and flooding damage to property, as 

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

due to inundation, erosion, wetland submergence and habitat 

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

peak electricity demand, and extreme weather from climate change 

threatens energy, transportation, and water resource 
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infrastructure. Climate change may exacerbate ongoing 

environmental pressures in certain settlements, particularly in 

Alaskan indigenous communities. Climate change also is very 

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

century. Though some benefits may balance adverse effects on 

agriculture and forestry in the next few decades, the body of 

evidence points towards increasing risks of net adverse impacts 

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

temperature continues to rise. These impacts are global and may 

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

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

3. The science upon which the Agency relies

The EPA received comments in response to the April 2012 

proposed NSPS rule (77 FR 22392) that addressed the scientific 

underpinnings of the EPA’s 2009 Endangerment Finding and hence 

the proposed rule. The EPA carefully reviewed all of those 

comments. It is important to place these comments in the context 

of the history and associated voluminous record on this subject 

that has been compiled over the last few years, including: 1) 

the process by which the Administrator reached the Endangerment 

Finding in 2009; 2) the EPA’s response in 2010 to ten 

administrative petitions for reconsideration of the Endangerment 
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Finding (the Reconsideration Denial)16; and 3) the decision by 

the United States Court of Appeals for the District of Columbia 

Circuit (the D.C. Circuit or the Court) in 2012 to uphold the 

Endangerment Finding and the Reconsideration Denial.17,18

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

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

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

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

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

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

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. The EPA received 

 

16 “EPA’s Denial of the Petitions to Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under 

Section 202(a) of the Clean Air Act, 75 Fed. Reg. 49,557 (Aug. 

13, 2010) (“Reconsideration Denial”).

17 Coalition for Responsible Regulation, Inc. v. Environmental 

Protection Agency (CRR), 684 F.3d at 102 (D.C. Cir.), reh’g en 

banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir. 2012), 

petitions for cert. filed, No. 12-1253 (U.S. Apr. 2013).

18 We discuss litigation history involving this rulemaking in 

more detail later in this section.

Comment [dj5]: Per OMB:

FN 13 should include “CRR” as an abbreviation if 

the agency intends to later use it in FN 35

EPA: Agreed, it has been added.
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thousands of comments on the proposed Endangerment Finding and 

responded to them in depth in an 11-volume Response to Comments 

(RTC) document.19 While the EPA gave careful consideration to all 

of the scientific and technical information received, the agency 

placed less weight on the much smaller number of individual 

studies that were not considered or reflected in the major 

assessments; often these studies were published after the 

submission deadline for those larger assessments. Primary 

reliance on the major scientific assessments provided the EPA 

greater assurance that it was basing its judgment on the best 

available, well-vetted science that reflected the consensus of 

the climate science community. The EPA reviewed individual 

studies not incorporated in the assessment literature largely to 

see if they would lead the EPA to change its interpretation of, 

or place less weight on, the major findings reflected in the 

assessment reports. From its review of individual studies 

submitted by commenters, the EPA concluded that these studies 

did not change the various conclusions and judgments the EPA 

drew from the more comprehensive assessment reports. The major 

 

19 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases under Section 202(a) of the Clean Air Act: EPA's Response 

to Public Comments,” 

http://www.epa.gov/climatechange/endangerment/#comments 

(“Response to Comments” or “RTC”).
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findings of the USGCRP, IPCC, and NRC assessments supported the 

EPA’s determination that GHGs threaten the public health and 

welfare of current and future generations. The EPA presented 

this scientific support at length in the Endangerment Finding, 

in its Technical Support Document (which summarized the findings 

of USGCRP, IPCC and NRC)20 and in the RTC.

The EPA then reviewed ten administrative petitions for 

reconsideration of the Endangerment Finding in 2010. In the 

Reconsideration Denial, the Administrator denied those petitions 

on the basis that the Petitioners failed to provide substantial 

support for the argument that the EPA should revise the 

Endangerment Finding and therefore their objections were not of 

“central relevance” to the Finding. The EPA prepared an 

accompanying three-volume Response to Petitions (RTP) document 

to provide additional information, often more technical in 

nature, in response to the arguments, claims, and assertions by 

the petitioners to reconsider the Endangerment Finding.21

The 2009 Endangerment Finding and the 2010 Reconsideration 

Denial were challenged in a lawsuit before the D.C. Circuit. On 

 

20 “Technical Support Document for Endangerment and Cause or 

Contribute findings for Greenhouse Gases under Section 202(s) of 

the Clean Air Act (Dec. 7, 2009), 

http://www.epa.gov/climatechange/Downloads/endangerment/Endanger

ment_TSD.pdf (TSD).

21 http://www.epa.gov/climatechange/endangerment/petitions.html
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June 26, 2012, the Court upheld the Endangerment Finding and the 

Reconsideration Denial, ruling that the Finding (including the 

Reconsideration Denial) was not arbitrary or capricious, was 

consistent with the U.S. Supreme Court’s decision in 

Massachusetts v. EPA, which granted to the EPA the authority to 

regulate GHGs,22 and was adequately supported by the 

administrative record.23 The Court found that the EPA had based 

its decision on “substantial scientific evidence” and noted that 

the EPA’s reliance on assessments was consistent with the 

methods decision-makers often use to make a science-based 

judgment.24 The Court also agreed with the EPA that the 

Petitioners had “not provided substantial support for their 

argument that the Endangerment Finding should be revised.”25 

Moreover, the Court supported the EPA’s reliance on the major 

scientific assessment reports conducted by USGCRP, IPCC, and NRC 

and found that:

The EPA evaluated the processes used to develop 

the various assessment reports, reviewed their 

contents, and considered the depth of the scientific 

consensus the reports represented. Based on these 

evaluations, the EPA determined the assessments 

represented the best source material to use in 

 

22 549 U.S. 497 (2007).

23 CRR, 684 F.3d at 117-27.

24 Id. at 121.

25 Id. at 125.
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deciding whether GHG emissions may be reasonably 

anticipated to endanger public health or welfare.26

As the Court stated –

It makes no difference that much of the 

scientific evidence in large part consisted of 

‘syntheses’ of individual studies and research. Even 

individual studies and research papers often 

synthesize past work in an area and then build upon 

it. This is how science works. The EPA is not required 

to re-prove the existence of the atom every time it 

approaches a scientific question.27

In the context of this extensive record and the recent 

affirmation of the Endangerment Finding by the Court, the EPA 

considered all of the submitted comments and reports for the 

April 2012 proposed NSPS rule. As it did in the Endangerment 

Finding, the EPA gave careful consideration to all of the 

scientific and technical comments and information in the record. 

The major peer-reviewed scientific assessments, however, 

continue to be the primary scientific and technical basis for 

the Administrator’s judgment regarding the threats to public 

health and welfare posed by GHGs.

Commenters submitted two major peer-reviewed scientific 

assessments released after the administrative record concerning 

the Endangerment Finding closed following the EPA’s 2010 

 

26 Id. at 120.

27 Id. at 120.
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Reconsideration Denial: the IPCC’s 2012 “Special Report on 

Managing the Risks of Extreme Events and Disasters to Advance 

Climate Change Adaptation” (SREX) and the NRC’s 2011 “Report on 

Climate Stabilization Targets: Emissions, Concentrations, and 

Impacts over Decades to Millennia” (Climate Stabilization 

Targets). 

According to the IPCC in the SREX, “A changing climate 

leads to changes in the frequency, intensity, spatial extent, 

duration, and timing of extreme weather and climate events, and 

can result in unprecedented extreme weather and climate 

events.28” The SREX documents observational evidence of changes 

in some weather and climate extremes that have occurred globally 

since 1950. The assessment also provides evidence regarding the 

cause of some of these changes to elevated concentrations of 

GHGs, including warming of extreme daily temperatures, 

intensified extreme precipitation events, and increases in 

extreme coastal high water levels due to rising sea level. The 

SREX projects further increases in some extreme weather and 

climate events during the 21st century. Combined with increasing 

vulnerability and exposure of populations and assets, changes in 

extreme weather and climate events have consequences for 

 

28 SREX, p. 7.
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disaster risk, with particular impacts on the water, agriculture 

and food security and health sectors. 

In the Climate Stabilization Targets assessment, the NRC 

states:

Emissions of carbon dioxide from the burning of

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe.29

The assessment concludes that carbon dioxide emissions will 

alter the atmosphere’s composition and therefore the climate for 

thousands of years; and attempts to quantify the results of 

stabilizing GHG concentrations at different levels. The report 

also projects the occurrence of several specific climate change 

impacts, finding warming could lead to increases in heavy 

rainfall and decreases in crop yields and Arctic sea ice extent, 

along with other significant changes in precipitation and stream 

flow. For an increase in global average temperature of 1 to 2 oC 

above pre-industrial levels, the assessment found that the area 

burnt by wildfires in western North America will likely more 

than double and coral bleaching and erosion will increase due 

both to warming and ocean acidification. An increase of 3 oC 

 

29 Climate Stabilization Targets, p. 3.
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will lead to a sea level rise of 0.5 to 1 meter by 2100. With an 

increase of 4 oC, the average summer in the United States would 

be as warm as the warmest summers of the past century. The 

assessment notes that although many important aspects of climate 

change are difficult to quantify, the risk of adverse impacts is 

likely to increase with increasing temperature, and the risk of 

surprises can be expected to increase with the duration and 

magnitude of the warming.

Several other National Academy assessments regarding 

climate have also been released recently. The EPA has reviewed 

these assessments and finds that in general, the improved 

understanding of the climate system they and the two assessments 

described above present strengthens the case that GHGs are 

endangering public health and welfare. Three of the new NRC 

assessments provide estimates of projected global sea level rise 

that are larger than, and in some cases more than twice as large 

as, the rise estimated in a 2007 IPCC assessment of between 0.18 

and 0.59 meters by the end of the century, relative to 1990 

(thoughIt should be noted that in 2007, the IPCC in 2007 had 

notedstated that including poorly understood ice sheet processes 

could lead to an increase in their projections.).

30 While these 

 

30 Climate Stabilization Targets; “National Security Implications 

for U.S. Naval Forces” (2011) (National Security Implications); 
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three NRC assessments continue to recognize and characterize the 

uncertainty inherent in accounting for ice sheet processes, 

these revised estimates strongly support and strengthen the 

existing finding that GHGs are reasonably anticipated to 

endanger public health and welfare. Other key findings of the 

recent assessments are described briefly below:

One of these assessments projects a global sea level rise 

of 0.5 to 1.4 meters by 2100, which is sufficient to lead to 

rising relative sea level even in the northern states.31 Another

assessment considers potential impacts of sea level rise and 

suggests that “the Department of the Navy should expect roughly 

0.4 to 2 meters global average sea-level rise by 2100.32 This 

assessment also recommends preparing for increased needs for 

humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

addressing changing security needs in the Arctic as sea ice 

retreats. A third NRC assessment found that it would be “prudent 

for security analysts to expect climate surprises in the coming 

 

“Sea Level Rise for the Coasts of California, Oregon, and 

Washington: Past, Present, and Future” (2012) (Sea Level Rise).

31 Sea Level Rise, p. 4.

32 National Security Implications, p. 9.
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decade . . . and for them to become progressively more serious 

and more frequent thereafter[.]”33

Another NRC assessment finds that “the magnitude and rate 

of the present greenhouse gas increase place the climate system 

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

forcing of the global climate system in Earth history.”34 This 

assessment finds that CO2 concentrations by the end of the 

century, without a reduction in emissions, isare projected to 

increase to levels that Earth has not experienced for more than

30 million years.

35 The report draws potential parallels with 

non-linear events such as the Paleo-Eocene Thermal Maximum, a 

rapid global warming event about 55 million years ago associated 

with mass extinctions and other disruptions. The assessment 

notes that acidification and warming caused by GHG increases 

similar to the changes expected over the next hundred years 

likely caused up to four of the five major coral reef crises of 

the past 500 million years. 

Similarly, another NRC assessment finds that “[t]he 

chemistry of the ocean is changing at an unprecedented rate and 

magnitude due to anthropogenic carbon dioxide emissions; the 

 

33 “Climate and Social Stress: Implications for Security 

Analysis” (2012), p.3.

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

Future” (2011), p.138.

35 Ibid, p. 1.
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rate of change exceeds any known to have occurred for at least 

the past hundreds of thousands of years.”36 The assessment notes 

that the full range of consequences is still unknown, but the 

risks “threaten coral reefs, fisheries, protected species, and 

other natural resources of value to society.”37

Comments were submitted in support of the Endangerment 

Finding, which provided additional documentation showing that 

climate change is a threat to public health and welfare. 

Commenters provided several individual studies and documentation 

of observed or projected climate changes of local importance or 

concern to commenters. The EPA appreciates these comments, but 

as previously stated, we place lesser weight on individual 

studies than on major scientific assessments. Local observed 

changes must be assessed in the context of the broader 

scientific picture, as it is more difficult to draw robust 

conclusions regarding climate change over short time scales and 

in small geographic regions.

The EPA plans to continue relying on the major assessments 

by the USGCRP, the IPCC, and the NRC. Studies from these bodies 

address the scientific issues that the Administrator must 

examine, represent the current state of knowledge on the key 

 

36 “Ocean Acidification: A National Strategy to Meet the 

Challenges of a Changing Ocean” (2010), p. 5.

37 Id.
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elements for the endangerment analysis, comprehensively cover 

and synthesize thousands of individual studies to obtain the 

majority conclusions from the body of scientific literature and 

undergo a rigorous and exacting standard of review by the peer 

expert community and U.S. government. 

Several commenters argued that the Endangerment Finding 

should be reconsidered or overturned based on those commenters’ 

reviews of specific climate science literature, including 

publications that have appeared since the EPA’s 2010 

Reconsideration Denial. Some commenters presented their own 

compilations of individual studies and other documents to 

support their assertions that climate change will have 

beneficial effects in many cases and that climate impacts will 

not be as severe or adverse as the EPA, and the assessment 

reports upon which the EPA relied, have stated. Some commenters 

also concluded that U.S. society will easily adapt to climate 

change and that it therefore does not threaten public health and 

welfare, and some commenters questioned the Endangerment Finding 

based on a 2011 EPA Inspector General’s report. 

The EPA reviewed the submitted information and found that 

overall, the commenters’ critiques of the rule’s scientific 

basis were addressed in the EPA’s response to comments for the 

2009 Endangerment Finding, the EPA’s responses in the 2010 
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Reconsideration Denial, or the D.C. Circuit’s 2012 decision 

upholding the EPA’s 2009 Endangerment Finding. The EPA 

nonetheless carefully reviewed these comments and associated 

documents and found that nothing in them would change the 

conclusions reached in the Endangerment Finding. These recent 

publications submitted by commenters, and any new issues they 

may present, do not undermine either the significant body of 

scientific evidence that has accumulated over the years or the 

conclusions presented in the substantial peer-reviewed 

assessments of the USGCRP, NRC, and IPCC.

One commenter submitted e-mails between climate change 

researchers from the period 1999 to 2009 that were 

surreptitiously obtained from a University of East Anglia server

in 2009 and publicly released in 2011. According to the 

commenter, these e-mails showed that the climatologists 

distorted their research results to prove that climate change 

causes adverse effects. The EPA reviewed these emails and found 

that they raised no issues that Petitioners had not already 

raised concerning other emails from the same incident, released 

in 2009. The commenter’s unsubstantiated assumptions and 

subjective assertions regarding what the e-mails purport to show 

about the state of climate change science is not adequate 
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evidence to challenge the voluminous and well-documented body of 

science that underpins the Administrator’s Endangerment Finding.

Some commenters argued for reconsideration based on 

uncertainty regarding climate science. However, the EPA made the 

decision to find endangerment with full and explicit recognition 

of the uncertainty involved, stating that “[t]he Administrator 

acknowledges that some aspects of climate change science and the 

projected impacts are more certain than others.”38 The D.C. 

Circuit subsequently noted that “the existence of some 

uncertainty does not, without more, warrant invalidation of an 

endangerment finding.”

39

Some commenters also argued that the U.S. will adapt to 

climate change impacts and that therefore climate change impacts 

pose no threat. However, the D.C. Circuit, in CRR, held that 

considerations of adaption are irrelevant to the Endangerment 

determination. The Court stated, “These contentions are 

foreclosed by the language of the statute and the Supreme 

Court's decision in Massachusetts v. EPA” because “predicting 

society’s adaptive response to the dangers or harms caused by 

 

38 74 FR 66524.

39 CRR, 684 F.3d at 121.

Comment [A6]: Please check citations to this 

case; although abbreviated here, it is fully spelled out 

in later footnotes 89 and 97.

EPA: We are still addressing this comment.
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climate change” does not inform the “scientific judgment” that 

the EPA is required to make regarding an Endangerment Finding.40

Some commenters raised issues regarding the EPA Inspector 

General’s report, Procedural Review of EPA’s Greenhouse Gases 

Endangerment Finding Data Quality Processes.

41 These commenters 

mischaracterized the report’s scope and conclusions and thus 

overstated the significance of the Inspector General’s 

procedural recommendations. Nothing in the Inspector General’s 

report questions the scientific validity of the Endangerment 

Finding, because that report did not evaluate the scientific 

basis of the Endangerment Finding. Rather, the Inspector General 

offers recommendations for clarifying and standardizing internal 

procedures for documenting data quality and peer review 

processes when referencing existing peer reviewed science in the 

EPA actions.42 

 

40 Id. at 117. The EPA took a similar position in the 

Endangerment Finding, in which we responded to similar comments 

regarding society’s ability to adapt to climate change by 

stating: “Risk reduction through adaptation and GHG mitigation 

measures is of course a strong focal area of scientists and 

policy makers, including the EPA; however, the EPA considers 

adaptation and mitigation to be potential responses to 

endangerment, and as such has determined that they are outside 

the scope of the endangerment analysis.” 74 FR 66512.

41 Report No. 11-P-0702 (September 26, 2011).

42 Unrelated to the Endangerment Finding and its validation by 

the Court, the EPA has made progress towards implementing the 

recommendations from the Inspector General.
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In addition, some commenters argued that the Endangerment 

Finding should be overturned because of the carbon dioxide 

fertilization effect, that is, the proposition that increased 

amounts of carbon dioxide can spur growth of vegetation. 

However, these commenters did not show how the science they 

provide on the subject differs from the carbon dioxide 

fertilization science already considered by the Administrator in 

the Endangerment Finding or how the existence of some benefits 

from the carbon dioxide fertilization effect could outweigh the 

numerous negative impacts of climate change. 

In sum, the EPA reviewed all of the comments purporting to 

refute the Endangerment Finding to determine whether they 

provide evidence that the Administrator’s judgment that climate 

change endangers public health and welfare was flawed, because 

the Administrator misinterpreted the underlying assessments, 

because the science in new peer reviewed assessments differs 

from that in previous assessments, or because new individual 

studies provide compelling reasons for the EPA to change its 

interpretation of, or place less weight on, the major findings 

reflected in the assessment reports. In all cases, the 

commenters failed to demonstrate that the science that the 

Administrator relied on was inaccurate or that the additional 

information from the commenter is of central relevance to the 
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Administrator’s judgment regarding endangerment. For these 

reasons, the commenters on the original proposal that criticized 

the Endangerment Finding have not provided a sufficient basis to 

cast doubt on the Finding.

B. GHG emissions from fossil fuel-fired EGUs

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., and among fossil fuelfired units, coal-fired units are by far the largest emitters. 

This section describes the amounts of those emissions and places 

those amounts in the context of the national inventory of GHGs.

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

Gas Emissions and Sinks43 (the U.S. GHG Inventory) to comply with 

commitments under the United Nations Framework Convention on 

Climate Change (UNFCCC). This inventory, which includes recent 

trends, is organized by industrial sectors. It provides the 

information in Table 2 below, which presents total U.S. 

anthropogenic emissions and sinks of GHGs, including CO2

emissions, for the years 1990, 2005 and 2011.44

 

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

2011”, Report EPA 430-R-13-001, United States Environmental 

Protection Agency, April 15, 2013.

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

forests or underground or deep sea reservoirs of carbon dioxide.
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Table 2. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))45

SECTOR 1990 2005 2011

Energy

 

5,267.3 

 

6,251.6 

 

5,745.7

Industrial Processes

 

316.1 

 

330.8 

 

326.5 

Solvent and Other 

Product Use

 

4.4 

 

4.4 

 

4.4 

Agriculture

 

413.9 

 

446.2 

 

461.5 

Land Use, Land-Use 

Change and Forestry

 

13.7 

 

25.4 

 

36.6 

Waste

 

167.8 

 

136.9 

 

127.7 

Total Emissions

 

6,183.3 

 

7,195.3 

 

6,702.3 

Land Use, Land-Use 

Change and Forestry 

(Sinks)

 

(794.5)

 

(997.8) (905.0)

Net Emissions (Sources 

and Sinks)

 

5,388.7 

 

6,197.4 

 

5,797.3 

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 78.7 percent of total 

2011 GHG emissions. In 2011, fossil fuel combustion by the 

electric power sector –-entities that burn fossil fuel and whose 

primary business is the generation of electricity –- accounted 

 

45 From Table 2-3 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2011”, April 15, 2013, EPA 430-R-13-001. 
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for 39.6 percent of all energy-related CO2 emissions. Table 3 

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005 and 2011.46

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

Combustion of Fossil Fuels (Tg CO2 Eq.)

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

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

 

46 Note that for the purposes of reporting national GHG emissions 

under the UNFCCC, the U.S. GHG Inventory is calculated using 

internationally accepted methodological guidance from the 

Intergovernmental Panel on Climate Change (IPCC). In accordance 

with IPCC guidance, CO2 emissions from combustion of biogenic 

feedstocks are not reported in the energy sector, but are 

instead reported separately as a "Memo item" in the U.S. GHG 

Inventory. Consistent with the IPCC guidance, any carbon stock 

changes related to the use of biogenic feedstocks in the energy 

sector, and the CO2 emissions associated with those carbon stock 

changes, are accounted for under the forestry and/or 

agricultural sectors of the U.S. GHG Inventory. Attribution of 

CO2 emissions from the combustion of biogenic feedstocks by 

stationary sources in the energy sector to the forestry and/or 

agricultural sectors, in the context of U.S. GHG emissions 

reporting to the UNFCCC, should not be interpreted as an 

indication that such emissions are “carbon neutral.”

GHG EMISSIONS 1990 2005 2011

Total CO2 from fossil fuel 

combustion EGUs

 

1,820.8 

 

2,402.1 

 

2,158.5 

 - from coal

 

1,547.6 

 

1,983.8

 

1,722.7

 - from natural gas

 

175.3 

 

318.8 

 

408.8 

 - from petroleum

 

97.5 

 

99.2 

 

26.6 
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especially from coal-fired circulating fluidized bed (CFB) 

combustors and from units with selective catalytic reduction 

(SCR) and selective non-catalytic reduction (SNCR) systems 

installed for NOX control. The estimated emissions for N2O and 

CH4 from fossil fuel-fired EGUs are about 17.9 and 0.4 Tg of CO2

equivalent in 2011, respectively, which is about 0.8 percent of 

total CO2 equivalent emissions from fossil fuel-fired electric 

power generating units. However, we are not proposing separate 

N2O or CH4 emission limits or an equivalent CO2 emission limit in 

today’s notice because we lack more precise data on the quantity 

of these emissions and information on cost-effective controls. 

We request comment on this approach and we solicit information 

about the quantity of N2O and CH4 emissions from these affected 

sources and possible controls.

C. The utility power sector and how its structure is changing

1. Utility power sector.

The majority of power in the U.S. is generated from the 

combustion of coal, natural gas and other fossil fuels.

Natural gas-fired EGUs typically use one of two technologies: 

NGCC and simple cycle. NGCC units first generate power from a 

combustion turbine (the combustion cycle). The unused heat from 

the combustion turbine is then routed to a Heat Recovery Steam 

Generator (HRSG) which generates steam which is used to generate 
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power using a steam turbine (the steam cycle). The combining of 

these generation cycles increases the overall efficiency of the 

system. 

Simple cycle combustion turbines only use a single 

combustion turbine to produce electricity (i.e., there is no 

heat recovery). The power output from these simple cycle 

combustion turbines can be easily ramped up and down making them 

ideal for “peaking” operations.

Coal-fired utility boilers are primarily either pulverized 

coal (PC) boilers or fluidized bed (FB) boilers. At a PC boiler, 

the coal is crushed (pulverized) into a powder in order to 

increase its surface area. The coal powder is then blown into a 

boiler and burned. In a coal-fired boiler using fluidized bed 

combustion, the coal is burned in a layer of heated particles 

suspended in flowing air.

Power can also be generated using gasification technology. 

An IGCC unit gasifies coal to form a syngas composed of carbon 

monoxide (CO) and hydrogen (H2), which can be combusted in a 

combined cycle system to generate power. 

2. Changing structure of the power sector

a. Technological developments and costs

Since the April 2012 proposal, a few coal-fired units have 

reached the advanced stages of construction and development, 
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which suggests that setting a separate standard for new fossil 

fuel-fired boilers and IGCC units is appropriate. Progress on

Southern Company's Kemper County Energy Facility, which will 

deploy IGCC with partial CCS, has continued, and the project is 

now over 75% complete. Additionally, two other projects, Summit 

Power's Texas Clean Energy Project (TCEP) and the Hydrogen 

Energy California Project (HECA) – both of which will deploy 

IGCC with CCS – continue to move forward. The EIA modeling 

projects that coal-fired power generation will remain the single 

largest portion of the electricity sector beyond 2030. The EIA 

modeling also projects that few, if any, new coal-fired EGUs 

would be built in this decade and that those that are built 

would have CCS.

47 Continued progress on these projects is 

consistent with the EIA modeling that suggests that a small 

number of coal-fired power plants may be constructed. The 

primary reasons for this rate of current and projected future 

development of new coal projects include highly competitive 

natural gas prices, lower electricity demand, and increases in 

the supply of renewable energy. 

 

47 Even in its sensitivity analysis that assumes higher natural 

gas prices and electricity demand, EIA does not project any 

additional coal beyond its reference case until 2023, in a case 

where power companies assume no GHGs emission limitations, and 

until 20252024 in a case where power companies do assume GHGs 

emission limitations.

Comment [dj7]: Per OMB:

FN 44 references a sensitivity analysis with the year 

2025, but earlier in the text 2024 is referenced. 

Which year is accurate?

EPA: The correct year is 2024. FN has been 

corrected.
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Natural gas prices have decreased dramatically and 

generally stabilized in recent years, as new drilling techniques 

have brought additional supply to the marketplace and greatly 

increased the domestic resource base. As a result, natural gas 

prices are expected to be competitive for the foreseeable future 

and EIA modeling and utility announcements confirm that 

utilities are likely to rely heavily on natural gas to meet new 

demand for electricity generation. On average, as discussed 

below, the cost of generation from a new natural-gas fired power 

plant (a NGCC unit) is expected to be significantly lower than 

the cost of generation from a new coal-fired power plant.48

Other drivers that may influence decisions to build new 

power plants are increases in renewable energy supplies, often 

due to state and federal energy policies. Many states have 

adopted renewable portfolio standards (RPS), which require a 

certain portion of electricity to come from renewable energy 

sources such as 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. 

Due to these factors, the EIA projections from the last 

several years show that natural gas is likely to be the most 

 

48 Levelized Cost of New Generation Resources in the Annual 

Energy Outlook 2011 

http://www.eia.gov/forecasts/aeo/electricity_generation.html.
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widely-used fossil fuel for new construction of electric 

generating capacity through 2020, along with renewable energy, 

nuclear power, and a limited amount of coal with CCS.49

b. Energy sector modeling

Various energy sector modeling efforts, including 

projections from the EIA and the EPA, forecast trends in new 

power plant construction and utilization of existing power 

plants that are consistent with the above-described 

technological developments and costs. The EIA forecasts the 

structure and developments in the power sector in its annual 

report, the Annual Energy Outlook (AEO). These reports are based 

on economic modeling that reflects existing policy and 

regulations, such as state RPS programs and federal tax credits 

for renewables.50 The current report, AEO 201351, (i) shows that 

although some a modest amount of coal-fired power plants that 

are currently under construction andare expected to begin 

operation in the next several years (referred to as “planned”);,

and (ii) projects in the reference case, no new model-projected 

 

49 http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf;

http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf;

http://prod-http-80-800498448.us-east1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pdf.

50 http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.

51 Energy Information Adminstration’s Annual Energy Outlook for 

2013, Final Release available at 

http://www.eia.gov/forecasts/aeo/index.cfm.
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(“unplanned”) conventional coal-fired capacity will come online 

after 2012, and through 2035. Instead, according to the AEO 

2013, the vast majority of new generating capacity will be 

either natural gas-fired or renewable, with a very small amount 

of new coal with CCS that is included in the AEO reference case 

in response to Federal and State incentives. The EIA projections 

from the last several years show that natural gas is likely to 

be the most widely-used fossil fuel for new construction of 

electric generating capacity through 2020.52 However, coal will 

remain an important part of the fuel mix for power generation, 

particularly for existing sources. Modeling from both the EIA 

and the EPA predict that coal-fired generation will remain the 

largest single source of electricity in the U.S. through 2040. 

In the EIA’s AEO 2013, coal will supply 39 percent of all 

electricity in both 2020 and 2025.

Specifically, Tthe AEO 2013 projects the need for 25.9 GW 

of additional base load or intermediate load generation capacity 

by 2020 (this includes projects that are under development –-

(i.e., being constructed or in advance planning --) and modelprojected nuclear, coal, and NGCC projects). The vast majority 

of this new electric capacity (22.5 GW) is already under 

development (under construction or in advanced planning); it 

 

52 Annual Energy Outlook 2010, 2011, 2012, and 2013.
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includes about 6.1 GW of new coal-fired capacity, 5.5 GW of new 

nuclear capacity, and 10.9 GW of new NGCC capacity. The EPA 

believes that most current fossil fuel-fired projects are 

already designed to meet limits consistent with today’s proposal 

(or they have already commenced construction and are thus not 

impacted by today’s notice). The AEO 2013 also projects an 

additional 3.4 GW of new base load capacity additions, which are 

model-projected (unplanned). This consists of 3.1 GW of new NGCC 

capacity, and 0.3 GW of new coal equipped with CCS (incentivized 

with some government funding). Therefore, the AEO 2013 

projection suggests that this proposal would only impact small 

amounts of new power generating capacity through 2020, all of 

which is expected to already meet the proposed emissions 

standards without incurring further control costs. In AEO 2013, 

this is also true through 2030, where new model-projected

(unplanned) intermediate and base load capacity is expected to 

be compliant with the proposed standard without incurring 

further control costs (i.e., an additional 45.148.2 GW of NGCC 

and no additional0.3 GW of coal, for a total, from 2013 through 

2030, of 48.2 GW of NGCC and 0.3 GW of coal with CCS, 

cumulative).

It should be noted that under the EIA projections, existing 

coal-fired generation will remain an important part of the mix 
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for power generation. Modeling from both the EIA and the EPA 

predict that coal-fired generation will remain the largest 

single source of electricity in the U.S. through 2040. 

Specifically, in the EIA’s AEO 2013, coal will supply 39 percent 

of all electricity in both 2020 and 2025.

The EPA modeling using the Integrated Planning Model (IPM), 

a detailed power sector model that the EPA uses to support power 

sector regulations, also shows limited future construction of 

new coal-fired power plants under the base case.53 The EPA’s 

projections from IPM can be found in the RIA.

c. Integrated Resource Plans

The trends in the power sector described above are also 

apparent in publicly available long-term resource plans, termed 

known as IRPs.

The EPA has reviewed publicly available IRPs from a range 

of companies (e.g., varying in size, location, current fuel 

mix), and these plans are generally consistent with both EIA and 

EPA modeling projections. Companies seem focused on demand-side 

management programs to lower future electricity demand and 

mostly reliant on a mix of new natural gas-fired generation and 

renewable energy to meet increased load demand and to replace 

 

53 http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation.
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retired generation capacity.

Notwithstanding this clear trend towards natural gas-fired 

generation and renewables, many of the IRPs raise fuel diversity 

concerns and include options to diversify new generation 

capacity beyond natural gas and renewable energy. Several IRPs 

indicate that companies are considering new nuclear generation, 

including either traditional nuclear power plants or small 

modular reactors, and new coal-fired generation capacity with 

and without CCS technology.Based on these IRPs, the EPA 

acknowledges that a small number of new coal-fired power plants 

may be built in the near future. While this is contrary to the 

economic modeling predictions, the Agency understands that 

economic modeling may not fully reflect the range of factors 

that a particular company may consider when evaluating new 

generation options, such as fuel diversification. By the same 

token, as discussed below, it is possible that some of this 

potential new coal-fired construction may occur because 

developers are able to design projects that can provide 

competitively priced electricity for a specific geographic 

region.

D. Statutory background

Section 111 of the Clean Air Act sets forth the standards 

of performance for new sources (NSPS) program, and with this 

Comment [A8]: Please add a reference for this 

block quote.

EPA: This paragraph was mistakenly formatted as a 

block quote. It is not and it has been changed to the 

proper format.

Has EPA considered referencing the Minnesota 

PUC’s recent decision on Great River Energy’s 

resource plan? 

EPA: It is EPA’s understanding that the decision 

was related to existing sources and not new sources. 

While interesting from a CO2 context, EPA is not 

sure how the commenter is suggesting it should be 

referenced here?
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program, establishes mechanisms for regulating emissions of air 

pollutants from stationary sources that are key in this 

rulemaking.

54 As a preliminary step to regulation, the EPA must 

list categories of stationary sources that the Administrator, in 

his or her judgment, finds “cause[], or contribute[] 

significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare.”

Once the EPA has listed a source category, the EPA proposes 

and then promulgates “standards of performance” for “new 

sources” in the category.

55 A “new source” is “any stationary 

source, the construction or modification of which is commenced

after,” in general, the date of the proposal.56 A modification is 

“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.”57 The EPA, through 

regulations, has determined that certain types of changes are

exempt from consideration as a modification.58 The EPA’s 

regulations also provide that Aan existing facility is also 

 

54 CAA §111(b)(1)(A). The EPA has regulated more than 60 

stationary source categories under CAA section 111. See 

generally 40 CFR subparts D-MMMM.

55 CAA §111(b)(1)(B).

56 CAA §111(a)(2).

57

 CAA §111(a)(4).

58 40 CFR 60.2, 60.14(e).

Comment [A9]: EPA previously made 

endangerment findings for Subpart Da and KKKK 

sources when they were originally listed. citations to 

those should be added in this FN.

EPA: Footnotes 94 and 96 are citations to the 

endangerment findings:

94 “Air Pollution Prevention and 

Control: List of Categories of 

Stationary Sources,” 36 FR 5931 

(March 31, 1971).

96 42 FR 53,657 (Oct. 3, 1977).
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considered a new source if it undertakes a “reconstruction,” 

which is the replacement of 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.59 In establishing standards of performance, the EPA has 

significant discretion to create subcategories based on source 

type, class or size.60

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. 

This definition makes clear that the standard of 

performance must be based on controls that constitute “the best 

system of emission reduction ... adequately demonstrated” (BSER).

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

commonly a numerical emissions limit, expressed as a performance 

 

59 40 CFR 60.15.

60 CAA, §111(b)(2).

61 As noted, we generally refer to this system of control as the 

best system of emission reduction, or BSER, but we may 

occasionally refer to it as the “best demonstrated system.” In 

the past, this level of control was frequently referred to as 

the “best demonstrated technology” (BDT). 
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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 generally 

can select any measure or combination of measures that will 

achieve the emissions level of the standard.

Regarding other titles in the CAA, this rulemaking has 

implications for EGUs and other stationary sources in the CAA 

PSD program under Title I, part C, and the operating permits 

program under Title V. We discuss these implications in section 

X of this preamble.

E. Regulatory and litigation background 

The EPA initially included fossil fuel-fired EGUs (which 

includes EGUs that burn fossil fuel including coal, gas, oil and 

petroleum coke and that use different technologies, including 

boilers and combustion turbines) in a category that it listed 

under section 111(b)(1)(A), and the EPA promulgated the first 

set of standards of performance for EGUs in 1971, codified in 

subpart D.62 As discussed in Section IV.D. of this preamble, the 

EPA has revised those regulations, and in some instances, 

revised the subparts, several times over the ensuing decades. 

 

62 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17,

1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 

60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971).

Comment [A10]: Has EPA considered adding 

examples of other NSPS that do prescribe a 

particular technological system?

EPA: We have considered this suggestion and do not 

feel that providing examples here is necessary as we 

are not prescribing a particular technology in this 

rule.
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None of these rulemakings or codifications, however, have 

constituted a new listing under CAA § 111(b)(1)(A).

In 1979, the EPA revised subpart D of 40 CFR part 60; as 

part of this revision, the EPA formed subpart Da and promulgated 

NSPS for electric utility steam generating units.63 These NSPS on 

June 11, 1979 apply to units capable of firing more than 73 

megawatts (MW) (250 MMBtu/h) heat input of fossil fuel that 

commenced construction, reconstruction, or modification after 

September 18, 1978. The NSPS for EGUs also apply to industrialcommercial-institutional cogeneration units that sell more than 

25 MW and more than one-third of their potential output capacity 

to any utility power distribution system. 

The EPA promulgated amendments to subpart Da in 2006, 

resulting in new criteria pollutant limitations for EGUs (the 

2006 Final Rule).64 The 2006 Final Rule did not establish 

standards of performance for GHG emissions. Two groups of 

petitioners – 13 governmental entities and three environmental 

groups – filed petitions for judicial review of this rule by the 

 

63 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979)

64 ”Standards of Performance for Electric Utility Steam 

Generating Units, Industrial-Commercial-Institutional Steam 

Generating Units, and Small Industrial-Commercial-Institutional 

Steam Generating Units, Final Rule.” 71 Fed. Reg. 9866 (Feb. 27, 

2006).
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D.C. Circuit.65 These petitioners contended, among other issues, 

that the rule was required to include standards of performance 

for GHG emissions from EGUs. 

The Court severed portions of the petitions for review of 

the 2006 Final Rule that related to GHG emissions. Following the 

U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA, 

which gave authority to the EPA to regulate GHGs, the D.C. 

Circuit remanded the 2006 Final Rule to the EPA upon its own 

motion for further consideration of the issues related to GHG 

emissions in light of Massachusetts. The EPA did not act on that 

remand. Rather, these 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 

 

65State of New York, et al. v. EPA, No. 06–1322. The two groups 

of petitioners were (1) the States of New York, California, 

Connecticut, Delaware, Maine, New Mexico, Oregon, Rhode Island, 

Vermont and Washington; the Commonwealth of Massachusetts; the 

District of Columbia and the City of New York (collectively 

‘‘State Petitioners’’); and (2) Natural Resources Defense 

Council (NRDC), Sierra Club, and Environmental Defense Fund 

(EDF)(collectively ‘‘Environmental Petitioners’’).
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if they were new sources. Pursuant to CAA section 113(g), the 

EPA provided for a notice-and-comment opportunity on the 

proposed settlement agreement and, after reviewing the comments 

received, finalized the agreement in late 2010.

In June 2012, the D.C. Circuit, in Coalition for 

Responsible Regulation v. EPA, upheld the EPA’s Endangerment 

Finding concerning GHGs and the EPA’s companion finding that 

GHGs from motor vehicles contribute to the air pollution that 

endangers public health and welfare.66 The Court also upheld 

standards for motor vehicles that limited GHG emissions.67 In 

addition, the Court affirmed the EPA’s view that the CAA PSD and 

title V permitting requirements became applicable to GHGemitting stationary sources when the EPA regulated GHG emissions 

from motor vehicles, because PSD and title V are automatically 

applicable to a pollutant when that pollutant is regulated under 

any part of the Act. The Court also dismissed challenges to what 

we refer to as the Timing Decision,

68 which established the 

 

66 Coalition for Responsible Regulation, Inc. v. Environmental 

Protection Agency,CRR, 684 F.3d at 102 (D.C. Cir.), reh’g en 

banc denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir. 2012), 

petitions for cert. filed, No. 12-1253 (U.S. Apr. 2013).

67 "Light-Duty Vehicle Greenhouse Gas Emission Standards and 

Corporate Average Fuel Economy Standards; Final Rule." 75 FR 

25324 (May 7, 2010).

68 "Interpretation of Regulations that Determine Pollutants 

Covered by Clean Air Act Permitting Programs." 75 FR 17004 

(April 2, 2010).

Comment [dj11]: Per OMB:

Note FN 65 also includes full citation, yet FN 113 

does not. Need to make consistent throughout.

EPA: FN 65 has been revised.
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January 2, 2011 date when the PSD and title V permitting 

requirements applied to GHG-emitting stationary sources; and the 

Tailoring Rule,69 which is the EPA’s common sense approach to 

phasing in GHG permitting requirements to avoid an initial 

increase in the number of PSD and title V permit applications 

that would overwhelm the permitting authorities’ administrative 

capacities.

In June 2012, several companies filed petitions for review 

of the original proposal for this rulemaking action in the D.C. 

Circuit.70 In December 2012, the D.C. Circuit dismissed these 

petitions on grounds that the challenged proposed rule is not 

final agency action subject to judicial review.71

In April, 2013, EPA completed rulemaking to regulate power 

plants in the Mercury and Air Toxics rule (“MATS”)72. In this 

same rulemaking, EPA promulgated revised standards of 

 

69 Prevention of Significant Deterioration and Title V Greenhouse 

Gas Tailoring Rule; Final Rule. 75 FR 31514 (June 3, 2010). 

70 Las Brisas Energy Center, LLC v. Environmental Protection 

Agency, No. 12-1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 

13, 2012).

71 Las Brisas Energy Center v. EPA, No. 12-1248, Order (D.C. 

Cir., Dec. 13, 2012).

72 “Reconsideration of Certain New Source Issues: National 

Emission Standards for Hazardous Air Pollutants From Coal- and 

Oil-Fired Electric Utility Steam Generating Units and Standards 

of Performance for Fossil-Fuel-Fired Electric Utility, 

Industrial-Commercial-Institutional, and Small IndustrialCommercial-Institutional Steam Generating Units, Final 

Rulemaking, ” 78 Fed. Reg. 24073 (April 24, 2013).
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performance under CAA §111(b) for criteria pollutant emissions 

from EGUs.

F. Coordination with other rulemakings

EGUs are the subject of several recent CAA rulemakings.73 In 

general, most EPA rulemakings affecting the power sector focus 

on existing sources. Therefore, few interactions are likely 

between other power sector rules and this rule, which focuses 

only on new sources.

We note that the EPA recently finalized revisions to the 

MATS rule as related to new sources.74 The revised MATS new 

source emission standards for air toxics and new source 

performance standards for criteria pollutants, coupled with GHG 

performance standards in this proposed rule, provide a clear 

regulatory structure for new fossil fuel-fired generation. 

The EPA recognizes that it is important that each of these 

regulatory efforts achieves its intended environmental 

objectives in a common-sense, cost-effective manner consistent 

with the underlying statutory requirements and assures a 

reliable power system. Executive Order (EO) 13563 states that 

 

73 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations.

74 78 FR 24073.
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‘‘[i]n developing regulatory actions and identifying appropriate 

approaches, each agency shall attempt to promote ... 

coordination, simplification, and harmonization. Each agency 

shall also seek to identify, as appropriate, means to achieve 

regulatory goals that are designed to promote innovation.’’ 

Recent guidance from the Office of Management and Budget’s 

Office of Information and Regulatory Affairs has emphasized the 

importance of, where appropriate and feasible, the consideration 

of cumulative effects in regulated industries and seeks tothe

harmonizeation of rules in terms of both content and timing. We 

believe that these recent finalized and proposed rules will 

allow industry to comply with its obligations as efficiently as 

possible, by making coordinated investment decisions and, to the 

greatest extent possible, adopting integrated compliance 

strategies.

G. Stakeholder input

The EPA has extensively interacted with many different 

stakeholders regarding climate change, source contributions, and 

emission reduction opportunities. These stakeholders included 

industry entities, environmental organizations and many 

regional, state, and local air quality management agencies, as 

well as the general public. As part of developing the original 

proposed rule, the EPA held five listening sessions in February 
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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; these were 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 roundtable discussion among stakeholder 

representatives. The EPA asked key stakeholder groups to 

identify these roundtable participants in advance of the 

listening sessions. The EPA accepted comments from the public at 

the end of each session and via the electronic docket system.75

On May 3, 2012, the EPA announced that it would hold two 

public hearings on the original proposed rule. The hearings were 

both held on May 24, 2012, in Washington, D.C. and Chicago, IL. 

Also on May 3, 2012, the EPA announced an extension of the 

public comment period for the original proposed rule, until June 

25, 2012. The EPA received more than 2.5 million public comments 

on the original proposed rule.76 While the Agency is not 

preparing a RTC document responding to the comments it received 

as part of that process, the EPA has taken into consideration 

 

75 Comments related to the listening sessions submitted via the 

electronic docket system are available at www.regulations.gov 

(docket number EPA-HQ-OAR-2011-0090).

76 Those comments are available at www.regulations.gov (docket 

number EPA-HQ-OAR-2011-0660).
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those comments, as well as information received in the listening 

sessions, in developing this new proposal.

III. Proposed Requirements for New Sources

This section describes the proposed requirements in this 

rulemaking for new sources. We describe Oour rationale for 

several of these proposed requirements – the applicability 

requirements, the basis for the standards of performance for 

fossil-fuel fired boilers, and the basis for the standards of 

performance for combustion turbines -is provided in Sections IVX of this preamble.

A. Applicability requirements

We generally refer to sources that would be subject to the 

standards of performance in this rulemaking as “affected” or 

“covered” sources, units, facilities, or simply as EGUs. These 

sources meet both the definition of “affected” and “covered” 

EGUs subject to an emission standard as provided by this rule, 

and the requirements for “new” sources as defined under the 

provisions of CAA section 111. 

1. Covered EGUs, generally

Subpart Da currently defines an EGU as a boiler that is: 1) 

“capable of combusting” more than 250 MMBtu/h heat input of 
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fossil fuel,77 2) “constructed for the purpose of supplying more 

than one-third of its potential net- electric output capacity ... 

to any utility power distribution system for sale”

78 (that is, to 

the grid), and 3) “constructed for the purpose of supplying ... 

more than 25 MW net-electric output” to the grid.”

79 We are 

proposing to define an EGU slightly differently than it is 

currently defined in subpart Da or in the original proposal for 

this rulemaking. First, we are proposing to revise the second 

criteria to be met if the EGU “supplies more than one-third of 

its potential electric output” to the grid instead of ofif the 

EGU is “constructed for the purpose of supplying more than onethird of its potential electric output capacity” to the grid.

This approach to applicability with the CO2 standard is similar 

to criteria pollutant emission standards included in both 

subparts Da and KKKK that vary depending on the fuels combusted. 

In this caseThus, when EGUs do not supply more than one-third of 

their potential electric output to the grid, no CO2 emissions 

standard would be applicable. Second, we are proposing to revise 

the third criteria to be met if the EGU supplies “more than 

219,000 MWh,” as opposed to “25 MW,” net-electrical output to 

 

77 E.g., 40 CFR 60.40Da(a)(1).

78 40 CFR 60.41Da (definition of (“Electric utility steamgenerating unit”).

79 Id.
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the grid. Theis proposed change of 25 MW net sales to 219,000 

MWh net sales is consistent with the EPA Acid Rain Program (ARP) 

definition, and we have concluded that it is functionally 

equivalent to the 25 MW net sales language. The 25 MW sales 

value has been interpreted to be the continuous sale of 25 MW of 

electricity on an annual basis, which is equivalent to 219,000 

MWh. We are also proposing to revise the averaging period for 

electric sales from an annual basis to a three-year rolling 

average for stationary combustion turbines. Lengthening this 

period will ensure that the CO2 standards only apply to the 

intended facilities, which are intermediate and base load EGUs. 

In addition, we are proposing to add a new applicability 

criterion that is not currently in subpart Da: for the CO2

standard. Similar to the applicability requirements in the 

Mercury and Air Toxics Standard, we are proposing that EGUs, for 

whichwhere 10 percent or less of the heat input over a threeyear period is derived from a fossil fuel, are not subject to 

any of the proposed CO2 standards. 

For the purposes of this rule, we are proposing several 

additional changes to the way applicability is currently 

determined under subpart Da. First, we are proposing a different 

definition of potential electric output from the current 

definition in subpart Da. To assure that the applicability does 
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not discourage the installation of the most efficient simple 

cycle turbines, we areTthe proposeding a definition of potential 

electric output that includes “or the design net electric output 

efficiency on a net output basis” as an alternative to the 

default one-third efficiency value (i.e., potential electrical 

output capacity means 33 percent or the design net electric 

output efficiency times 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 35 

percent efficient steam generating unit with a 100 MW (341 

MMBtu/h) fossil-fuel heat input capacity would have a 310,000 

MWh 12 month potential electrical output capacity) (emphasis 

added)). Next, we are proposing to add “of the thermal host 

facility or facilities” to the definition of net-electric output

(i.e., Net-electric output would read “... the gross electric 

sales to the utility power distribution system minus purchased 

power of the thermal host facility or facilities on a calendar 

year basis” (emphasis added)). This would make applicability 

consistent for both facility-owned CHP and qualifying thirdparty-owned CHP, since the owner of the CHP does not need to 

also own the thermal host facility. Finally, consistent with our 

approach in the NSPS part of the MATS rule and the original

proposal for this rulemaking, we are proposing to amend the 
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definition of a steam generating unit to include “plus any 

integrated equipment that provides electricity or useful thermal 

output to either the boiler affected facility or to power

auxiliary equipment” and instead of delete the existing language 

“plus any integrated combustion turbines and fuel cells.” The 

proposed definition would read “any furnace, boiler, or other 

device used for combusting fuel for the purpose of producing 

steam (nuclear steam generators are not included) plus any 

integrated equipment that provides electricity or useful thermal 

output to either the affected facility or auxiliary equipment” 

(emphasis added). We are also proposing to add the additional 

language to the definition of IGCC and stationary combustion 

turbine.

2. CO2 emissions only

This action proposes to regulate covered EGU emissions of 

CO2, and not other constituent gases of the air pollutant GHGs. 

We identify the pollutant we propose to regulate as GHGs, but, 

again, only CO2 emissions are subject to the proposed standard of 

performance. We are not proposing separate emission limits for 

other GHGs (such as methane, CH4, or nitrous oxide, N2O) as they 

represent less than 1 percent of total estimated GHG emissions 

from fossil fuel-fired electric power generating units.

The proposed CO2 emission standards do not apply a unique 

Comment [dj12]: Per OMB:

Suggest adding another sentence explaining why 

CO2 emissions are the only entity subject to the 

proposed standard of performance. Why not include 

other GHGs?

EPA: Sentence has been added.
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accounting method for biogenic CO2 emissions for the purpose of 

determining compliance with the standards. However, the proposed 

CO2 emission standards only apply to new fossil fuel-fired EGUs. 

Based on the applicability provisions in the proposal, as 

discussed above, an EGU that primarily fires biomass would not 

be subject to the CO2 emission standards. Such units could fire 

fossil fuels up to 10 percent on a three-year average annual 

heat input basis (e.g., for start-up and combustion 

stabilization) without becoming subject to the standards. 

Issues related to accounting for biogenic CO2 emissions from 

stationary sources are currently being evaluated by the EPA 

through its development of an Accounting Framework for Biogenic 

CO2 Emissions from Stationary Sources (Accounting Framework).80

In general, the overall net atmospheric loading of CO2 resulting 

from the use of a biogenic feedstock by a stationary source, 

such as an EGU, will ultimately depend on the stationary source 

process and the type of feedstock used, as well as the 

conditions under which that feedstock is grown and harvested. In 

September 2011, the EPA submitted a draft of the Accounting 

Framework to the Science Advisory Board (SAB) Biogenic Carbon 

Emissions (BCE) Panel for peer review. The SAB BCE Panel 

 

80 The EPA’s draft accounting framework is available at 

<http://www.epa.gov/climatechange/ghgemissions/biogenicemissions.html>.
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delivered its Peer Review Advisory to the EPA on September 28, 

2012.81 In its Advisory, the SAB recommended revisions to the 

EPA’s proposed accounting approach, and also noted that biomass 

cannot be considered carbon neutral a priori, without an 

evaluation of the carbon cycle effects related to the use of the 

type of biomass being considered. The EPA is currently reviewing 

the SAB peer review report, and will move forward as warranted 

once the review is complete.

3. Sources not subject to this rulemaking

We are not proposing standards for certain types of 

sources. These include new steam generating units and stationary 

combustion turbines that sell one-third or less of their 

potential output to the grid;, new non-natural gas-fired 

stationary combustion turbines;,

82 existing sources undertaking 

modifications or reconstructions;, or certain projects under 

development ,including the proposed Wolverine EGU project in 

Rogers City, Michigan (and, perhaps, up to two others) as 

discussed below. As a result, under the CAA §111(a) definitions 

 

81 The text of the SAB Peer Review Advisory is available at 

<http://yosemite.epa.gov/sab/sabproduct.nsf/0/2f9b572c712ac52e85

25783100704886!OpenDocument&TableRow=2.3#2>.

82 Oil-fired stationary combustion turbines including both simple 

and combined cycle units are not subject to these proposed 

standards. These units are typically used only in areas that do 

not have reliable access to pipeline natural gas (for example, 

in non-continental areas).

Comment [dj13]: Per OMB:

Suggest adding FN regarding liquid oil-fired CC 

units to provide more clarity to public

EPA: A FN has been added.
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of “new source” and “existing source,”83 if those types of 

sources commence construction or modification, they would not be 

treated as “new source[s]” subject to the standards of 

performance proposed today, and instead, they would be treated 

as existing sources.

4. Certain projects under development

This proposal does not apply to the proposed Wolverine EGU 

project in Rogers City, Michigan . Based on current information, 

the Wolverine project appears to be the only fossil fuel-fired 

boiler or IGCC EGU project presently under development that may 

be capable of “commencing construction” for NSPS purposes in the 

very near future and, as currently designed, could not meet the 

1,100 lb CO2/MWh standard proposed for other new fossil fuelfired boiler and IGCC EGUs. The EPA has not formulated a view 

as to the project’s status in the development process or as to 

whether the proposed 1,100 lb CO2/MWh standard or some other CO2

standard of performance would be representative of BSER for this 

project and invites comment on these questions.

84 At the time of 

 

83 CAA §111(a)(2), (6).

84 The EPA’s lack of view regarding the appropriate CO2 standard 

is closely related to the existence of conflicting information 

on where the project stands in the development process. The 

developer has claimed that the project was delayed by issues 

related to the standards of performance for hazardous air 

pollutants promulgated in December 2011, 77 FR 9304 (Feb. 16, 

2012) (Mercury and Air Toxics Standards, or MATS). Specifically, 

Comment [M14]: Moved to a later section.
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finalization of this proposal (but not sooner than one year 

following Federal Register publication of this proposal), if the 

Wolverine project remains under development and has not either 

commenced construction or been canceled, we anticipate proposing 

that the project either be made subject to the 1,100 lb CO2/MWh 

standard or be assigned to a subcategory with an alternate CO2

standard. Further discussion is provided in the technical 

support document in the docket entitled “Fossil Fuel-Fired 

Boiler and IGCC EGU Projects under Development: Status and 

Approach.” 

There are two other fossil fuel-fired boiler or IGCC EGU 

projects without CCS – the Washington County project in Georgia 

and the Holcomb project in Kansas – that appear to remain under 

development but whose developers have recently represented that 

the projects have commenced construction for NSPS purposes. 

Based solely on the developers’ representations, the projects 

 

the developer cited a perceived inability to obtain guarantees 

from pollution control equipment vendors that the plant would 

achieve the MATS standards. See Jim Dulzo, As Coal Plant 

Teeters, Groups Mount Legal Attack, Michigan Land Use Institute 

blog, Feb. 13, 2012, http://www.mlui.org/energy/news-views/newsviews-articles/as-coal-plant-teeters-groups-mount-legalattack.html. While some of the MATS new-unit standards were

revised upon reconsideration in March 2013, 78 FR 24073 (Apr. 

24, 2013), the developer’s claims raise the possibility that the 

EPA’s own actions may have delayed the project and contributed 

to the present uncertainty as to the project’s development 

status.
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would be existing sources, and thus not subject to this 

proposal. However, neither developer has sought a formal EPA 

determination of NSPS applicability; and, if upon review it was 

determined that the projects have not commenced constructions, 

the projects could be situated similarly to the Wolverine 

project. Accordingly, if either developer seeks a formal EPA 

determination of applicability85 within 120 days following 

Federal Register publication of this proposal and the EPA finds 

that the project has not “commenced construction,”86 as of the 

date of the Federal Register publication of this proposal, then 

that project automatically – without, for example, any 

supplemental proposal or re-proposal – would be addressed in the 

same manner as the Wolverine project.87 Further discussion is 

 

85 Under the NSPS regulations, the EPA will respond within 30 days 

to any request by an owner or operator for “a determination of 

whether action taken or intended to be taken by such owner or 

operator constitutes construction . . . or the commencement 

thereof within the meaning of this part.” 40 CFR 60.5.

86 The NSPS regulations include the following definitions of 

“commenced” and “construction”: 

Commenced means . . . that an owner or operator has 

undertaken a continuous program of construction . . . 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 . . . . 

Construction means fabrication, erection, or installation 

of an affected facility. 

40 CFR 60.2.

87 In this event, there will not be any proposed standard “which 

will be applicable to such source” within the meaning of CAA 

section 111(a)(2), and to the extent that this proposal did, 
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provided in the technical support document in the docket 

referenced above.88 

We invite comment on all aspects of this approach for 

addressing the Wolverine project (and the Washington County and 

Holcomb projects, if applicable).89

 

until the time of the applicability determination, apply to that 

project, this proposal will be considered automatically to be 

withdrawn as it applies to that project as of the time of the 

applicability determination. The purpose of this automatic 

withdrawal is to ensure that the project is placed on the same 

footing as the Wolverine project as soon as possible. It is 

worth noting that, if the developers do not seek applicability 

determinations within the 120 day timeframe, nothing in this 

rulemaking binds the EPA to the position that the projects have 

“commenced construction” for NSPS purposes.

88 In the April 2012 GHG NSPS proposal, the Wolverine, Washington 

County, and Holcomb projects were among a group of 15 projects 

distinguished from other EGU projects as “potential transitional 

sources.” This proposal does not continue that distinction. 

Except as described above for the Wolverine project, and 

possibly the Washington County and Holcomb projects, any former 

“potential transitional source” that commences construction 

after publication of this proposal (and meets any other 

applicability criteria) will be subject to the final CO2

standards established in this rulemaking. Any former “potential 

transitional source” that commenced construction prior to 

publication of this proposal is an existing source not subject 

to the CO2 standards established in this rulemaking, but instead 

subject to the CO2 standards that are required to be established 

for existing sources pursuant to CAA section 111(d).

89 The EPA intends that its treatment of the Wolverine project 

(and the Washington County and Holcomb projects, if applicable) 

be severable from its treatment of differently situated sources 

and considers that severability is logical because of the 

record-based differences between these sources and differently 

situated sources and because there is no interdependency in the 

EPA’s treatment of the different types of sources. This 

statement concerning severability should not be construed to 
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B. Emission standards

In this rulemaking, the EPA is proposing NSPS for CO2

emissions from several subcategories of affected sources, which 

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

1. Standards of performance for affected sources

a. Emission standard

The proposed standard of performance for each subcategory 

is in the form of a gross energy output-based CO2 emission limit 

expressed in units of emissions mass per unit of useful 

recovered energy, specifically, in pounds per megawatt-hour 

(lb/MWh). This emission limit would apply to affected sources 

upon the effective date of the final action. In this notice, we 

sometimes refer to “gross energy output” as “gross output” or 

“adjusted gross output.”

The subcategories, for which the EPA is proposing separate 

standards of performance, are (1) natural gas-fired stationary 

combustion turbines with a heat input rating that is greater 

than 850 MMBtu/h;90 (2) natural gas-fired stationary combustion 

turbines with a heat input rating that is less than or equal to 

 

have implications for whether other components in this 

rulemaking are severable.

90 This subcategorization of stationary combustion turbines is 

consistent with the subcategories used in the combustion turbine 

(subpart KKKK) criteria pollutant NSPS. The size limit of 850 

MMBtu/h corresponds to approximately 100 MWe.
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850 MMBtu/h; and (3) all fossil fuel-fired boilers and IGCC 

units, which generally are solid-fuel fired. 

We are proposing that all affected new fossil fuel-fired 

EGUs are required to meet an output-based emission rate of a 

specific mass of CO2 per MWh of useful output. Specifically, new 

combustion turbines with a heat input rating greater than 850 

MMBtu/h would be required to meet a standard of 1,000 lb CO2/MWh. 

New combustion turbines with a heat input rating less than or 

equal to 850 MMBtu/h would be required to meet a standard of 

1,100 lb CO2/MWh. As discussed below, these proposed standards 

are based on the demonstrated performance of recently 

constructed NGCC units, which are currently in wide use 

throughout the country, and are currently the predominant fossil 

fuel-fired technology for new electric generating units in the 

near future.

While the EPA is proposing specific standards of 

performance for each subcategory, we are also taking comment on 

a range of potential emission limitations. We solicit comment on 

a range of 950 – 1,100 lb CO2/MWh for new stationary combustion 

turbines with a heat input rating greater than 850 MMBtu/h. We 

also solicit comment on an emission limitation range of 1,000 –

1,200 lb CO2/MWh for new stationary combustion turbines with a 

heat input rating less than or equal to 850 MMBtu/h. In 

Comment [HJH15]: This is moved here from 

below.
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addition, we solicit comment on an emission limitation for new 

fossil fuel-fired boilers and IGCC units in the range of 1,000 –

1,200 lb CO2/MWh.

New fossil fuel-fired boilers and IGCC units would be 

required, based on the performance of currently available CCS 

technology, to meet a standard of 1,100 lb CO2/MWh on a 12-

operating-month rolling average, or alternatively a lower 

standard, which we propose as between 950 lb CO2/MWh and 1,050 lb 

CO2/MWh, on an 60-operating84-operating-month rolling average as 

an equivalently stringent standard. The EPA has previously

offered sources optional, longer-term emission standards that 

are discounted from the primary emissions standard in 

combination with a longer averaging period. We are requesting 

comment on the appropriate numerical standard such that the 60-

operating84-operating-month standard would be as stringent as or 

more stringent than the 12-operating-month standard. We also 

request comment on whether an appropriate 12-operating-month 

standard that owners/operators electing to comply with the 60-

operating84-operating-month standard should also be required to 

comply with a maximum 12-operating-month standard. This standard 

would be between the otherwise applicable proposed 1,100 lb 

CO2/MWh standard and an emissions rate of a coal-fired EGU 

without CCS (e.g., 1,800 lb CO2/MWh), and we solicit comment on 

Comment [M16]: Moved to below.
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what the standard should be. This shorter term standard would be 

more easily enforced and assure adequate emission reductions.

While the EPA is proposing specific standards of performance 

for each subcategory, we are also taking comment on a range of 

potential emission limitations. We solicit comment on a range of 

950 – 1,100 lb CO2/MWh for new stationary combustion turbines 

with a heat input rating greater than 850 MMBtu/h. We also 

solicit comment on an emission limitation range of 1,000 –

1,1501,200 lb CO2/MWh for new stationary combustion turbines with 

a heat input rating less than or equal to 850 MMBtu/h. In 

addition, we solicit comment on an emission limitation for new 

fossil fuel-fired boilers and IGCC units in the range of 1,000 –

1,200 lb CO2/MWh.

As discussed below, tThe proposed method to calculate 

compliance is to sum the emissions for all operating hours and 

to divide that value by the sum of the useful energy output over 

a rolling 12-operating-month period. In the alternative, we 

solicit comment on requiring calculation of compliance on an 

annual (calendar year) period.

To recognize the environmental benefit of reduced electric 

transmission and distribution losses of CHP, we are proposing 

that CHP facilities where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

Comment [E17]: We are still considering the 

ccmment to revise this range to 900 to 1,200 

lb/MWh.

EPA: We believe the range of 1,000 – 1,200 lb/MWh 

is still appropriate.

Comment [M18]: Moved to below.
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mechanical output and 20.0 percent of the total gross useful 

energy output consists of useful thermal output on a rolling 

three calendar year basis receive similar credit as currently in 

subpart Da and the proposed amendments to subpart KKKK (77 FR 

52554). Specifically, the measured electric output would be 

divided by 0.95 to account for a five percent avoided energy 

loss in the transmission of electricity. The minimal electric 

and thermal output requirements are to avoid owners/operators 

from selling trivial amounts of thermal output and claiming a 

line loss benefit when in reality they are similar to a central 

power station. 

b. Gross output

Subpart Da currently defines “gross electricenergy output”

from new units as the “gross electrical or mechanical output 

from the affected facility minus any electricity used to power 

the feedwater pumps and any associated gas compressors (air 

separation unit main compressor, oxygen compressor, and nitrogen 

compressor) plus 75 percent of the useful thermal output 

measured relative to ISO conditions” (referred to in today’s 

notice as “adjusted gross output”). The current criteria 

pollutant emission standards for new subpart Da units were 

developed by analyzing the gross emission rates of PC and CFB 

facilities, and were finalized on February 16, 2013 (77 FR 
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9304). In that rulemaking, we did not have emissions data from 

modern IGCC designs. We therefore concluded that a technology

neutral approach was appropriate and applied the same standards 

to traditional coal-fired and IGCC EGUs. The adjusted gross 

output definition accounts for the largest gas compressors at an 

IGCC facility. ConsequentlySubsequently, IGCC facilities 

complying with the NSPS requirements would emit at approximately 

the same net output based emissions rate (i.e., gross output 

minus auxiliary power requirements) as a comparable traditional 

coal-fired EGU. Therefore, with theUsing this definition of 

gross output for criteria pollutant emission standards (i.e., 

adjusted gross output), both IGCC and traditional coal-fired 

EGUs at that have the same gross output-based emissions rate 

would have a similar net output-based efficienciesemissions 

rate. If we did not include the parasitic load from the primary 

gas compressors when determining the gross emissions 

rateefficiency of an IGCC facility, it would emit more 

pollutants to the atmosphere than a traditional coal-fired EGU 

when complying with the criteria pollutant NSPS.

In contrast, in the April 2012 proposal, we proposed a 

definition of gross output as “the gross electrical or 

mechanical output from the unit plus 75 percent of the useful 

thermal output measured relative to standard reference (ISO)
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conditions (288 Kelvin (15 oC), 60 percent relative humidity, and 

101.325 kilopascals (kPa) pressure) 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).” This definition was appropriate since NGCC was the 

BSER for the combined subcategory and auxiliary loads associated 

with feedwater pumps and associated compressors (air separation 

unit main compressor, oxygen compressor, and nitrogen 

compressor) are not relevant to the gross efficiency of an NGCC. 

However, we requested comment on requiring the use of net output 

based standards. Part of the rationale behind the use of net 

output-based standards is that the use of a gross output-based 

standard as defined could have potentially driven the 

installation of electrically driven feed pumps instead of steam 

driven feed pumps at a steam generating unit, even though from 

an overall net efficiency basis it may be more efficient to use 

steam-driven feed pumps.

After further consideration and because many of the 

proposed IGCC facilities are actually co-production facilities 

(i.e., they produce useful byproducts and chemicals along with 

electricity), we have concluded that measuring the electricity 

used by the primary gas compressors associated with electricity 
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production at IGCC facilities could be more challenging to 

implement. 

Therefore, we are proposing to define the gross 

energyelectric output for traditional steam generating units to 

includebe the electricity measured at the generator terminals 

minus electric power used to run the feedwater pumps and the 

associated gas compressors, and to define the gross electric 

output for IGCC and subpart KKKK affected facilities would beto 

include the electricity measured at the generator terminals. We 

are considering and requesting comment on if (1) whether the 

gross output definition of “gross energy output” in subpart Da 

should be consistent for both criteria and GHG purposes, (2) if 

we should adopt the proposed definition of “gross energy output” 

or the current adjusted gross output definition of the term 

currently in subpart Da, and (3) whetherif the definition should 

be the same for both traditional and IGCC facilities. If we do 

finalize the adjusted gross output definition, wWe take 

requestseek comment on howissues related to accounting for power 

energy consumption associated with products other than 

electricity and steam useful thermal output created at a polygeneration facility and the impact of that energy use on the 

numerical emissions standard, relevant to possible adoption of 

an adjusted gross output definition.
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We are also considering and requesting comment on either 

adding as a compliance alternative or requiring the use of netoutput based standards without a gross-output based alternative 

for each subcategory. In the compliance alternative approach, 

owners/operators would elect to comply with either a grossoutput based standard or an alternate net-output based standard. 

As described in the original proposal for this rulemaking, net 

output is the combination of the gross electrical output of the 

electric generating unit minus the parasitic (i.e., auxiliary) 

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 non-IGCC and non-CCS coal-fired station power output, 

approximately 15 percent of non-CCS IGCC-based coal-fired 

station power output and about 2.5 percent of non-CCS 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, 

Comment [CF19]: Moved from request for 

comment section
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and (3) recognizing the environmental benefit of higher 

efficiency motors, pumps, and fans. While the EPA has concluded 

that the net power supplied to the end user is a better 

indicator of environmental performance than gross output from 

the power producer, we only have CEMS emissions data reported on 

a gross output basis because that is the way the data is 

currently reported under 40 CFR Part 75. As can be seen 

switching from gross output to net or adjusted gross output 

would have little or no impact on the required rates for gasfired NGCC plants, which as has been explained earlier are 

likely to be the dominant fossil-fuel-fired technology. Since 

the change would have little impact on these units in terms of 

environmental performance, EPA has proposed to use a standard 

consistent with current reporting protocols. However, as is 

noted in table 4, the use of gross vs net output could have a 

much larger impact on coal-fired power plants.

Table 4: Subpart Da Emission Rates91

Gross Output 

Based Standard

Approximant 

Equivalent 

Adjusted Gross 

Output Based 

Standard

Approximant 

Equivalent Net 

Output Based 

Standard

450 kg/MWh 

(1,000 lb/MWh)

510 kg/MWh 

(1,100 lb/MWh)

560 kg/MWh 

(1,200 lb/MWh)

 

91 Rounding to 2 significant figures results in the same standard 

in units of lb/MWh in some cases.

Comment [A20]: It would be helpful if EPA 

could explain why it only has CEMS emission data 

reported on a gross output basis and why the agency 

is not able to move to a more optimal parasitic 

accounting approach.

EPA: Have added text

Formatted Table

Formatted: Font: 11 pt

Formatted: Font: 11 pt

Formatted: Font: (Default) Courier New, 12 pt

Formatted: Font: (Default) Courier New, 12

pt, Not Superscript/ Subscript

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500 kg/MWh 

(1,100 lb/MWh)

570 kg/MWh 

(1,300 lb/MWh)

620 kg/MWh 

(1,400 lb/MWh)

540 kg/MWh 

(1,200 lb/MWh)

610 kg/MWh 

(1,300 lb/MWh)

670 kg/MWh 

(1,500 lb/MWh)

Table 5: Subpart KKKK Emission Rates

Gross Output 

Based Standard

Approximant 

Equivalent Net 

Output Based 

Standard

430 kg/MWh 

(950 lb/MWh)

440 kg/MWh 

(970 lb/MWh)

450 kg/MWh 

(1,000 lb/MWh)

460 kg/MWh 

(1,000 lb/MWh)

500 kg/MWh 

(1,100 lb/MWh)

510 kg/MWh 

(1,100 lb/MWh)

540 kg/MWh 

(1,200 lb/MWh)

560 kg/MWh 

(1,200 lb/MWh)

Requiring or including an optional net-output based 

standard would provide more operational flexibility and expand 

the technologies options available to comply with the standard 

for coal-fired PC and CFB EGUs.

In addition, We are proposing that with respect to CO2

emissions, 75 percent credit is the appropriate discount factor 

for useful thermal output. However, we are requesting comment on 

a range of two-thirds to three-fourths credit for useful thermal 

output in the final rule.

2. 60-operating84-operating-month rolling average compliance 

option

Formatted: Font: 11 pt

Formatted: Font: 11 pt

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Formatted Table
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We also propose an 60-operating84-operating-month rolling 

averageing compliance option that would be available for 

affected subpart Da boilers and IGCC facilities. The EPA 

suggests that this 60-operating84-operating-month rolling 

average compliance option will offer operational flexibility and 

will tend to dampen short-term emission excursions, which may be 

warranted especially at the initial startup of the facility and 

the CCS system.

Thus, under our proposed approach, new fossil fuel-fired 

boilers and IGCC units would be required, based on the 

performance of currently available CCS technology, to meet a 

standard of 1,100 lb CO2/MWh on a 12-operating-month rolling 

average, or alternatively a lower – but equivalently stringent -

- standard on an 84-operating-month rolling average, which we 

propose as between 950 lb CO2/MWh and 1,050 lb CO2/MWh. The EPA 

has previously offered sources optional, longer-term emission 

standards that are discounted from the primary emissions 

standard in combination with a longer averaging period. We are 

requesting comment on the appropriate numerical standard such 

that the 84-operating-month standard would be as stringent as or 

more stringent than the 12-operating-month standard. We also 

request comment on whether owners/operators electing to comply 

with the 84-operating-month standard should also be required to 

Comment [HJH21]: This paragraph is moved 

here from above, with some edits.
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comply with a maximum 12-operating-month standard. This standard 

would be between the otherwise applicable proposed 1,100 lb 

CO2/MWh standard and an emissions rate of a coal-fired EGU 

without CCS (e.g., 1,800 lb CO2/MWh), and we solicit comment on 

what the standard should be. This shorter term standard would 

promote enforcability and assure adequate emission reductions.

We have concluded that this alternative compliance option 

is not necessary for new stationary combustion turbine EGUs, as 

they should be able to meet the proposed performance standard 

with no need for add-on technology. We seek comment on all other 

aspects of this 60-operating84-operating-month rolling averaging 

compliance option.

3. Combined heat and power

To recognize the environmental benefit of reduced electric 

transmission and distribution losses of CHP, we are proposing 

that CHP facilities where at least 20.0 percent of the total 

gross useful energy output consists of electric or direct 

mechanical output and 20.0 percent of the total gross useful 

energy output consists of useful thermal output on a rolling 

three calendar year basis receive similar credit as currently in 

subpart Da and the proposed amendments to subpart KKKK (77 FR 

52554). Specifically, the measured electric output would be 

divided by 0.95 to account for a five percent avoided energy 
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loss in the transmission of electricity. The minimal electric 

and thermal output requirements are to avoid owners/operators 

from selling trivial amounts of thermal output and claiming a 

line loss benefit when in reality they are similar to a central 

power station.

Actual transmission and distribution losses vary from 

location to location, but we propose that this 5 percent of 

actual MWh represents a reasonable average amount for the 

avoided transmission and distribution losses for CHP facilities. 

Note that we propose to limit this 5 percent adjustment to 

facilities for which the useful thermal output is at least 20 

percent of the total output.

C. Startup, shutdown, and malfunction requirements

1. Startups and shutdowns

Consistent with Sierra Club v. EPA,

92 the EPA is proposing 

standards in this rule that apply at all times, including during 

startups and shutdowns. In proposing the standards in this rule, 

the EPA has taken into account startup and shutdown periods and, 

for the reasons explained below has not proposed alternate 

standards for those periods. In the compliance calculation, 

periods of startup and shutdown are included as periods of 

partial load. To establish the proposed NSPS’s output-based CO2

 

92 551 F.3d 1019 (D.C. Cir. 2008).

Comment [M22]: Moved from below.

Comment [A23]: This case is referenced below, 

but this appears to be the first reference. Please add 

full cite.

EPA: Citation added.
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standard, we accounted for periods of startup and shutdown by 

incorporating them as periods of partial 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 EGUs, over a 

rolling 12-operating-month period. The EPA is proposing that 

sources incorporate in their compliance determinations emissions 

from all periods, including startup or shutdown, that fuel is 

combusted and emissions monitors are not out-of-control, as well 

as all power produced over the periods of emissions 

measurements. Given that the duration of startup or shutdown 

periods are expected to be small relative to the duration of 

periods of normal operation and that the fraction of power 

generated during periods of startup or shutdown is expected to 

be very small during startup or shutdown periods, the impact of 

these periods on the total average is expected to be 

minimal.This averaging approach gives more weight to high-load 

hours and more accurately reflects overall environmental 

performance. Periods of startup and shutdown will be short, 

relative to total operating time. Since we are primarily 

concerned with overall environmental performance over extended 

periods of time, incorporating relatively short periods of 
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partial load is believed to have a negligible effect on the has 

a negligible effect on measuring performance of the source with 

respect to long-term efficiency. Thus we allowed that low-load 

hours do not factor as heavily into the calculated average 

performance of the source.

We solicit comment on any alternative to our proposal that

the periods of startup and shutdown be included as periods of 

partial load in the 12- and 60-operating84-operating-month

rolling averaging compliance option.

2. Malfunctions

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, 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. Failures that 

are caused in part by poor maintenance or careless operations 

are not malfunctions.’’(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. Nothing in CAA section 111 or in case 

law requires that the EPA anticipate and account for the 

innumerable types of potential malfunction events in setting 
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emission standards. CAA 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” 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 datagathering 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."). See also, Weyerhaeuser v. Costle,
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590 F.2d 1011, 1058 (DC Cir. 1978) (“In the nature of things, no 

general limit, individual permit, or even any upset provision 

can anticipate all upset situations. After a certain point, the 

transgression of regulatory limits caused by ‘uncontrollable 

acts of third parties,’ such as strikes, sabotage, operator 

intoxication or insanity, and a variety of other eventualities, 

must be a matter for the administrative exercise of case-by-case 

enforcement discretion, not for specification in advance by 

regulation”). In addition, the goal of a source that uses the 

best system of emission reduction 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 
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EPA would also consider whether the source's failure to comply 

with the CAA section 111 standard was, in fact, “sudden, 

infrequent, not reasonably preventable” and was not instead 

“caused in part by poor maintenance or careless operation.” 40 

CFR section 60.2 (definition of malfunction).

Finally, the EPA recognizes that even equipment that is 

properly designed and maintained can sometimes fail and that 

such failure can sometimes cause a violation of the relevant 

emission standard. (See, e.g., State Implementation Plans: 

Response to Petition for Rulemaking; Finding of Excess Emissions 

During Periods of Startup, Shutdown, and Malfunction; Proposed 

Rule, 78 FR 12460 (Feb. 22, 2013): (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)). The EPA is therefore proposing to 

add an affirmative defense to civil penalties for violations of 

emission standards 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 
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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 

60.5530. (See 40 CFR 22.24). The criteria are designed in part 

to ensure that the affirmative defense is available only where 

the event that causes a violation of the emission standard 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 the violation 

“[w]as caused by a sudden, infrequent, and unavoidable failure 

of air pollution control, 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 a 

violation occurred...” and that “[a]ll possible steps were taken 

to minimize the impact of the violation on ambient air quality, 

the environment and human health....” In any judicial or 
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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 

22.27).

The EPA included an affirmative defense in the proposed 

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 standards may be violated 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 111 emissions standards are continuous. The 

affirmative defense for malfunction events meets this 

requirement by ensuring that even where there is a malfunction, 

the emission standard is still enforceable through injunctive 

relief. The United States Court of Appeals for the Fifth Circuit 

recently upheld the EPA’s view that an affirmative defense 
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provision is consistent with section 113(e) of the Clean Air 

Act. Luminant Generation Co. LLC v. United States EPA, 2013 U.S. 

App. LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 427(5th Cir. 

Oct. 12, 2012) (upholding the EPA’s approval of affirmative 

defense provisions in a CAA State Implementation Plan). While 

“continuous” standards, on the one hand, are required, there is 

also case law indicating that in many situations it is 

appropriate for the EPA to account for the practical realities 

of technology. For example, in Essex Chemical v. Ruckelshaus, 

486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit 

acknowledged that in setting standards under CAA section 111 

“variant provisions” such as provisions allowing for upsets 

during startup, shutdown and equipment malfunction “appear 

necessary to preserve the reasonableness of the standards as a 

whole and that the record does not support the ‘never to be 

exceeded’ standard currently in force.” See also, Portland 

Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973). Though intervening case law, such as Sierra Club v. EPA 

and the CAA 1977 amendments, call into question 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 violations that are proven to be beyond the 

Comment [A24]: The relevance is questioned 

with respect to other issues? Add clarifying 

statement.

EPA: We are still considering this comment.

Per OMB: Please address comment
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control of the source. By incorporating an affirmative defense, 

the EPA has formalized its approach to malfunctions. 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). See also, Mont. Sulphur & Chem. Co. v. 

United States EPA, 666 F.3d. 1174 (9th Cir. 2012)(rejecting 

industry argument that reliance on the affirmative defense was 

not adequate). 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 

standards 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, an affirmative 

defense to civil penalties for violations of emission limits 

that are caused by malfunctions, would apply to both the 12-

operating-month standard and the 60-operating84-operating-month

rolling average compliance option; however, we will take comment 

on whether it is appropriate to have an affirmative defense for 

the 60-operating84-operating-month rolling average portion of 

that compliance option, given that we would expect malfunctions 
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to only impact shorter averaging periods, and the longer the 

compliance period, the less likely malfunction events are to 

impact a source’s ability to meet the standard.

D. Continuous monitoring requirements

Today’s proposed rule would require owners or operators of 

EGUs that combust solid fuel to install, certify, maintain, and 

operate continuous emission monitoring systems (CEMS) to measure 

CO2 concentration, stack gas flow rate, and (if needed) stack gas 

moisture content in accordance with 40 CFR Part 75, in order to 

determine hourly CO2 mass emissions rates (tons/hr).

The proposed rule would allow owners or operators of EGUs 

that burn exclusively gaseous or liquid fuels to install fuel 

flow meters as an alternative to CEMS and to calculate the 

hourly CO2 mass emissions rates using Equation G-4 in Appendix G 

of Part 75. To implement this option, hourly measurements of 

fuel flow rate and periodic determinations of the gross 

calorific value (GCV) of the fuel are also required, in 

accordance with Appendix D of Part 75.

In addition to requiring monitoring of the CO2 mass emission 

rate, the proposed rule would require EGU owners or operators to 

monitor the hourly unit operating time and “gross output”, 

expressed in megawatt hours (MWh). The gross output includes 
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electrical output plus any mechanical output, plus 75 percent of 

any useful thermal output.

The proposed rule would require EGU owners or operators to 

prepare and submit a monitoring plan that includes both 

electronic and hard copy components, in accordance with §§

75.53(g) and (h). The electronic portion of the monitoring plan 

would be submitted to the EPA’s Clean Air Markets Division 

(CAMD) using the Emissions Collection and Monitoring Plan System 

(ECMPS) Client Tool. The hard copy portion of the plan would be

sent to the applicable State and EPA Regional office. Further, 

all monitoring systems used to determine the CO2 mass emission 

rates would have to be certified according to § 75.20 and 

section 6 of Part 75, Appendix A within the 180-day window of 

time allotted under § 75.4(b), and would be required to meet the 

applicable on-going quality assurance procedures in Appendices B 

and D of Part 75.

The proposed rule would require all valid data collected 

and recorded by the monitoring systems (including data recorded 

during startup, shutdown, and malfunction) to be used in 

assessing compliance. Failure to collect and record required 

data is a violation of the monitoring requirements, except for 

periods of monitoring system malfunctions, repairs associated 

with monitoring system malfunctions, and required monitoring 
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system quality assurance or quality control activities that 

temporarily interrupt the measurement of stack emissions (e.g., 

calibration error tests, linearity checks, and required zero and 

span adjustments). An affirmative defense to civil penalties for 

malfunctions is available to a source if it can demonstrate that 

certain criteria and requirements are satisfied.

The proposed rule would require only those operating hours 

in which valid data are collected and recorded for all of the 

parameters in the CO2 mass emission rate equation to be used for 

compliance purposes. Additionally for EGUs using CO2 CEMS, only 

unadjusted stack gas flow rate values would be used in the 

emissions calculations. In this proposal, Part 75 bias 

adjustment factors (BAFs) would not be applied to the flow rate 

data. These restrictions on the use of Part 75 data for Part 60 

compliance are consistent with previous NSPS regulations and 

revisions. 

The following variations from and additions to the basic Part 75 

monitoring would be required:

If you determine compliance using CEMS, you would be 

required to use a laser device to measure the stack 

diameter at the flow monitor and the reference method 

sampling locations prior to the initial setup 

(characterization) of the flow monitor. For circular 
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stacks, you would need to make measurements of the 

diameter at 3 or more distinct locations and average the 

results. For rectangular stacks or ducts, you would need 

to make measurements of each dimension (i.e., depth and 

width) at 3 or more distinct locations and average the 

results. If the flow rate monitor or reference method 

sampling site is relocated, you would repeat these 

measurements at the new location. 

If you elect to use Method 2 in Appendix A-1 of Part 60 to 

perform the required relative accuracy test audits (RATAs) 

of the Part 75 flow rate monitoring system, you would have 

to use a calibrated Type-S pitot tube or pitot tube 

assembly. Use of the default Type-S pitot tube coefficient 

would not be permitted. 

If your EGU combusts natural gas and/or fuel oil and you 

elect to measure the CO2 mass emissions rate using Equation 

G-4 in Appendix G of Part 75, you would be allowed to 

determine site-specific carbon-based F-factors using 

Equation F-7b in section 3.3.6 of Appendix F of Part 75, 

and you could use these Fc values in the emissions 

calculations instead of using the default Fc values in the 

Equation G-4 nomenclature.
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Today’s proposed rule includes the following special 

compliance provisions for units with common stack or multiple 

stack configurations; these provisions are consistent with §

60.13(g):

If two or more of your EGUs share a common exhaust stack, 

are subject to the same emission limit, and you are 

required to (or elect to) determine compliance using CEMS, 

you would be allowed to monitor the hourly CO2 mass 

emission rate at the common stack instead of monitoring 

each EGU separately. If this option is chosen, the hourly 

gross electrical load (or steam load) would be the sum of 

the hourly loads for the individual EGUs and the operating 

time would be expressed as “stack operating hours” (as 

defined in 40 CFR 72.2). Then, if compliance with the 

applicable emission limit is attained at the common stack, 

each EGU sharing the stack would be in compliance with the 

CO2 emissions limit.

If you are required to (or elect to) determine compliance 

using CEMS and the effluent from your EGU discharges to 

the atmosphere through multiple stacks (or, if the 

effluent is fed to a stack through multiple ducts and you 

choose to monitor in the ducts), you would be required to 

monitor the hourly CO2 mass emission rate and the “stack 
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operating time” at each stack or duct separately. In this 

case, compliance with the applicable emission limit would 

be determined by summing the CO2 mass emissions measured at 

the individual stacks or ducts and dividing by the total 

gross output for the unit. 

The proposed rule would require 95 percent of the operating 

hours in each compliance period (including the compliance 

periods for the intermediate emission limits) to be valid hours, 

i.e., operating hours in which quality-assured data are 

collected and recorded for all of the parameters used to 

calculate CO2 mass emissions. EGU owners or operators would have 

the option to use backup monitoring systems, as provided in §§

75.10(e) and 75.20(d), to help meet this proposed data capture 

requirement. 

E. Emissions performance testing requirements

In accordance with § 75.64(a), the proposed rule would 

require an EGU owner or operator to begin reporting emissions 

data when monitoring system certification is completed or when 

the 180-day window in § 75.4(b) allotted for initial 

certification of the monitoring systems expires (whichever date 

is earlier). For EGUs subject to the 450 kg/MWh (1,000 lb/MWh)

standard or the 500 kg/MWh (1,100 lb/MWh) emission standard, the 

initial performance test would consist of the first 12-
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operating-months of data, starting with the month in which 

emissions are first required to be reported. The initial 12-

operating-month compliance period would begin with the first 

month of the first calendar year of EGU operation in which the 

facility exceeds the capacity factor applicability threshold.

The traditional 3-run performance tests (i.e., stack tests) 

described in § 60.8 would not be required for this rule. 

Following the initial compliance determination, the emission 

standard would be met on a 12-operating-month rolling average 

basis. For EGUs that combust coal and/or petroleum coke and 

whose owners or operators elect to comply with the alternative 

60-operating84-operating-month rolling average emissions

standard, the first month in the compliance period would be the 

month in which emissions reporting is required to begin under §

75.64(a).

F. Continuous compliance requirements

Today’s proposed rule specifies that compliance with the 

1,000 lb/MWh (450 kg/MWh) and 1,100 lb/MWh (500 kg/MWh) CO2 mass 

emissions rate limits would be determined on a 12-operatingmonth rolling average basis, updated after each new operating

month. For each 12-operating-month compliance period, qualityassured data from the certified Part 75 monitoring systems would 
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be used together with the gross output over that period of time 

to calculate the average CO2 mass emissions rate. 

The proposed rule specifies that the first operating month 

included in either the initial 12- or 60-operating84-operatingmonth compliance period would be the month in which reporting of 

emissions data is required to begin under § 75.64(a), i.e., 

either the month in which monitoring system certification is 

completed or the month in which the 180-day window allotted to 

finish certification testing expires (whichever month is 

earlier). 

We are proposing that initial compliance with the 

applicable emissions limit in kg/MWh be calculated by dividing 

the sum of the hourly CO2 mass emissions values by the total 

gross output for the 12- or 60-operating84-operating-month

period. Affected EGUs would continue to be subject to the 

standards and maintenance requirements in the section 111 

regulatory general provisions contained in 40 CFR part 60, 

subpart A.

G. Notification, recordkeeping, and reporting requirements

Today’s proposed rule would require an EGU owner or 

operator to comply with the applicable notification requirements 

in § 75.61, §§ 60.7(a)(1) and (a)(3) and § 60.19. The proposed 

rule would also require the applicable recordkeeping 
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requirements in subpart F of Part 75 to be met. For EGUs using 

CEMS, the data elements that would be recorded include, among 

others, hourly CO2 concentration, stack gas flow rate, stack gas 

moisture content (if needed), unit operating time, and gross 

electric generation. For EGUs that exclusively combust liquid 

and/or gaseous fuel(s) and elect to determine CO2 emissions using 

Equation G-4 in Appendix G of Part 75, the key data elements in 

subpart F that would be recorded include hourly fuel flow rates, 

fuel usage times, fuel GCV, gross electric generation. 

The proposed rule would require EGU owners or operators to 

keep records of the calculations performed to determine the 

total CO2 mass emissions and gross output for each operating 

month. Records would be kept of the calculations performed to 

determine the average CO2 mass emission rate (kg/MWh) and the 

percentage of valid CO2 mass emission rates in each compliance 

period. The proposed rule would also require records to be kept 

of calculations performed to determine site-specific carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G 

(if applicable). 

For EGU owners or operators who would elect to comply with 

the 60-operating84-operating-month rolling average emissions 

standard, records must be kept for 10 years. All other records 

would be kept for a period of three years. All required records 
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would be kept on-site for a minimum of two years, after which 

the records could be maintained off-site. 

The proposed rule would require all affected EGU 

owners/operators to submit quarterly electronic emissions 

reports in accordance with subpart G of Part 75. The proposed 

rule would require these reports to be submitted using the ECMPS 

Client Tool. Except for a few EGUs that may be exempt from the 

Acid Rain Program (e.g., oil-fired units), this is not a new 

reporting requirement. Sources subject to the Acid Rain Program 

are already required to report the hourly CO2 mass emission rates 

that are needed to assess compliance with today’s rule.

Additionally, in the proposed rule and as part of an 

Agency-wide effort to streamline and facilitate the reporting of 

environmental data, the rule would require selected data 

elements that pertain to compliance under this rule, and that 

serve the purpose of traditional excess emissions reports, to be 

reported periodically using ECMPS. 

Specifically, for EGU owners/operators who would comply 

with a 12-operating-month rolling average standard, quarterly 

electronic “excess emissions” reports must be submitted, within 

30 days after the end of each quarter. The first report would be 

for the quarter that includes the final (12th) operating month of 

the initial 12-operating-month compliance period. For that 
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initial report and any subsequent report in which the twelfth 

operating month of a compliance period (or periods) occurs 

during the calendar quarter, the average CO2 mass emissions rate 

(kg/MWh) would be reported for each compliance period, along 

with the dates (year and month) of the first and twelfth 

operating months in the compliance period and the percentage of 

valid CO2 mass emission rates obtained in the compliance period. 

The dates of the first and last operating months in the 

compliance period would clearly bracket the period used in the 

determination, which facilitates auditing of the data. Reporting 

the percentage of valid CO2 mass emission rates is necessary to 

demonstrate compliance with the requirement to obtain valid data 

for 95 percent of the operating hours in each compliance period. 

Any excess emissions that occur during the quarter would be 

identified. If there are no compliance periods that end in the 

quarter, a definitive statement to that effect would be included 

in the report. If one or more compliance periods end in the 

quarter but there are no excess emissions, a statement to that 

effect would be included in the report. 

For EGU owners or operators that would comply with an 60-

operating84-operating-month rolling average basis, quarterly 

electronic “excess emissions” reports would be submitted, within 

30 days after the end of each quarter. The first report would be 
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for the quarter that includes the final (60th) operating month of 

the initial 60-operating84-operating-month compliance period. 

For that initial report and any subsequent report in which the 

sixtieth operating month of a compliance period (or periods) 

occurs during the calendar quarter, the average CO2 mass 

emissions rate (kg/MWh) must be reported for each compliance 

period, along with the dates (year and month) of the first and 

sixtieth operating months in the compliance period and the 

percentage of valid CO2 mass emission rates obtained in the 

compliance period. The dates of the first and last operating 

months in the compliance period would clearly bracket the period 

used in the determination, which facilitates auditing of the 

data. Reporting of the percentage of valid CO2 mass emission 

rates is necessary to demonstrate compliance with the

requirement to obtain valid data for 95 percent of the operating 

hours in each compliance period. Any excess emissions that occur 

during the quarter would be identified. If there are no 

compliance periods that end in the quarter, a definitive 

statement to that effect would be included in the report. If one 

or more compliance periods end in the quarter but there are no 

excess emissions, a statement to that effect would be included 

in the report. 
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Currently, ECMPS is not programmed to receive excess 

emission report information from EGUs. However, we will make the 

necessary modifications to the system in order to fully 

implement the reporting requirements of this rule upon

promulgation.

For EGU owners or operators that would assert an 

affirmative defense for a failure to meet a standard due to 

malfunction, the owner or operator must follow the reporting 

requirements for affirmative defense. Those requirements are 

found in 40 CFR 60.5530. The report to the Administrator, with 

all necessary supporting documentation, explains how the source 

has met the requirements set forth in Da to assert affirmative 

defense. This report must be submitted on the same schedule as

the next quarterly report required after the initial occurrence 

of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If the quarterly report is 

due less than 45 days after the initial occurrence of the 

violation, the affirmative defense report may be included in the 

second quarterly report due after the initial occurrence of the 

violation of the relevant standard.

IV. Rationale for Reliance on Rational Basis to Regulate GHGs 

from Fossil-fired EGUs

A. Overview
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In our original proposal, we proposed and solicited comment 

on what basis we are required to have concerning the health and 

welfare impacts of GHG emissions from fossil-fuel fired power 

plants in order to regulate those emissions under CAA § 111. 

However, we took the position that we are not required to make 

findings that GHGs from fossil-fired power plants “cause[], or 

contribute[] significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare,” 

under CAA § 111(b)(1)(A). 

We have reconsidered that proposal in light of the numerous 

comments we received. In today’s notice, we propose that under 

§111, the EPA is required to have a rational basis for 

promulgating standards for GHG emissions from electricity 

generating plants, and that the EPA has such a basis because the 

EPA has already determined that GHG emissions may reasonably be 

anticipated to endanger public health and welfare, and because 

electricity generating plants, as an industry, constitute, by a 

significant margin, the largest emitters in the inventory. In 

the April 2012 proposal, the EPA discussed whether CAA section 

111 requires that the EPA issue, as a prerequisite for this 

rulemaking, another “endangerment” finding. After reviewing the 

comments, recent scientific developments, the amount of 

emissions from the power plant sector, and the case law, the EPA 
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has concluded that even if § 111 requires an endangerment 

finding, the rational basis described in today’s action would 

qualify as an endangerment finding as well. 

As related matters, in this notice, we are proposing to 

establish regulatory requirements for CO2 emissions of affected 

units, which are included in source categories (both steamgenerating units and turbines) that the EPA already listed under 

CAA § 111(b)(1)(A) for regulation under CAA and we are not 

proposing a listing of a new source category. We are, however, 

proposing to subcategorize different sets of sources, and 

establish different CO2 standards of performance for them, in 

accordance with CAA § 111(b)(2). To avoid confusion, we are 

proposing to codify the CO2 standards of performance in the same 

subparts – Da and KKKK, depending on the types of units – that 

currently include the standards of performance for conventional 

pollutants. We are also co-proposing, in the alternative, to

codify the CO2 standards in a new subpart, TTTT, as we proposed 

in the original proposal for this rulemaking in April, 2012.

93

 

93 It should be noted that CAA §111 clearly applies to GHGs. The 

U.S. Supreme Court has made this clear because (i) §111 applies 

to “any air pollutant,” CAA §111(a)(3), see §111(d)(1)(A) 

(exempting, for purposes of §111(d), certain air pollutants); 

and in Massachusetts v. EPA, 549 U.S. 497 (2007), the Supreme 

Court held that the term “air pollutant,” as defined under CAA 

§302(g), includes GHGs; and (ii) in American Electric Power 

Company v. Connecticut, 131 S.Ct. 2527 (2011), the Supreme Court 
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B. Climate change impacts from GHG emissions; Amounts of GHGs 

from fossil fuel-fired EGUs

In 2009, the EPA Administrator issued the Endangerment 

Finding under CAA section 202(a)(1). 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 of current and future generations, and 

focused on public health and public welfare impacts within the 

United States. Fossil fuel-fired EGUs are by far the largest 

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

sources in the U.S. These adverse effects of GHGs on public 

health and welfare, and the amounts of GHGs emitted by fossil 

fuel-fired EGUs are briefly summarized in the section II of this 

preamble and described in more detail in the RIA, and need not 

be recited here.

C. CAA § 111 requirements

To review the key CAA § 111 requirements: CAA §

111(b)(1)(A), by its terms, requires that the Administrator --

shall publish (and from time to time thereafter shall 

revise) a list of categories of stationary sources. He 

 

based its holding that “the Clean Air Act and the EPA actions it 

authorizes displace any federal common law right to seek 

abatement of carbon-dioxide emissions from fossil fuel-fired 

power plants” on the grounds that CAA §111 “provides a means to 

seek limits on emissions of carbon dioxide from domestic power 

plants....” Id. at 2538.
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shall include a category of sources in such list if in 

his judgment it causes, or contributes significantly

to air pollution which may reasonably be anticipated 

to endanger public health or welfare.

CAA § 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 § 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.” CAA § 111(b)(2) provides that “The 

Administrator may distinguish among classes, types, and sizes 

within categories of new sources for the purpose of establishing 

such standards.”

D. Interpretation of CAA § 111 requirements

CAA § 111(b)(1)(A) requires the EPA to list a source 

category if it contributes significantly to air pollution that 

endangers public health or welfare. The EPA must necessarily 

conduct this listing by making determinations as to the health 

or welfare impacts of the pollution to which the source 

category’s pollutants contribute, and as to the significance of 

the amount of such contribution. However, by the terms of CAA §

111(b)(1)(A), the EPA may make these determinations on the basis 
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of the impacts of the air pollution as a whole to which the 

source category’s pollutants, taken as a whole, contribute. 

Nothing in CAA § 111(b)(1)(A) requires that the EPA make 

separate determinations for each type of pollution or each 

pollutant. 

After listing a source category, the EPA must proceed to 

promulgate standards of performance for the source category’s 

pollutants under CAA § 111(b)(1)(B) and 111(a)(1). However, 

nothing in those provisions requires that, at the time when the 

EPA promulgates the standards of performance for the individual 

pollutants, the EPA must make a determination as to the health 

or welfare effects of those particular pollutants or as to the 

significance of the amount of the source category’s emissions of 

those pollutants. Clearly, CAA § 111 does not by its terms 

require that as a prerequisite for the EPA to promulgate a 

standard of performance for a particular pollutant, the EPA must 

first find that the pollutant causes or contributes 

significantly to air pollution that endangers public health or 

welfare. The lack of any such requirement contrasts with 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).
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The lack of any express requirement in CAA section 111 

addressing whether and how the EPA is to evaluate emissions of a 

particular pollutant from the listed source category as a 

prerequisite for promulgation of a standard of performance is 

properly viewed as a statutory gap that requires the EPA to make 

what we refer to as a Chevron step 2 interpretation. Under the 

U.S. Supreme Court’s 1984 decision in Chevron U.S.A. Inc. v. 

NRDC,

94 to interpret how a statute applies to a particular 

question, an agency must, at Step 1, determine whether 

Congress’s intent as to the specific question is clear, and, if 

so, the agency must give effect to that intent. If congressional 

intent is not clear, then the agency, at Step 2, has discretion 

to fashion an interpretation that is a reasonable construction 

of the statute.95 In this case, the EPA is authorized to develop 

a reasonable interpretation. 

Our interpretation is that in order to promulgate a § 111 

standard of performance for a particular pollutant, we do not 

need to make a pollutant-specific endangerment finding, but 

instead must demonstrate a rational basis for controlling the 

emissions of the pollutant. That rational basis may be based on 

information concerning the health and welfare impacts of the air 

 

94 467 U.S. 837 (1984).

95 Id. at 842-43.
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pollution at issue, and the amount of contribution that the 

source category’s emissions make to that air pollution. 

Commenters on the April 2012 proposal stated that the EPA 

is required to make an endangerment finding for CO2 because when 

the EPA listed this source category, it was on the basis of 

other pollutants, and not CO2. However, to reiterate, CAA §

111(b)(1)(A) by its terms requires that the EPA “shall publish 

(and from time to time thereafter, shall revise) a list of 

categories of stationary sources,” and that the EPA shall list 

“a category of sources” based on the EPA’s judgment that the 

category “causes, or contributes significantly to, air 

pollution” that endangers public health or welfare. Thus, this 

provision requires that the EPA make the listing decision on a 

category basis, and not on a pollutant-by-pollutant basis. That 

is, this provision does not require that the EPA establish 

separate lists of source categories, with each list covering a 

different pollutant. Therefore, this provision does not require 

that the EPA make an endangerment finding on a pollutant by 

pollutant basis. 

Commenters on the April 2012 proposal stated that the EPA 

was required to make an endangerment finding because by creating 

the new subpart TTTT in 40 CFR part 60, the EPA was listing a 

new source category that included the affected units. However, 
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in neither the original April 2012 proposal nor this new 

proposal has EPA proposed to list a new source category. The EPA 

initially included fossil fuel-fired electric steam generating 

units (which included boilers) in a category that it listed 

under section 111(b)(1)(A)96 and the EPA promulgated the first 

set of standards of performance for this source category in 

1971, which the EPA codified in subpart D.97 Subsequently, the 

EPA included fossil-fuel-firedfossil fuel-fired combustion 

turbines in a category that the EPA listed under section 

111(b)(1)(A),98 and the EPA promulgated standards of performance 

for this source category in 1979, which the EPA codified in 

subpart GG.99

The EPA has revised those regulations, and in some 

instances, revised the codifications (that is, the subparts), 

several times over the ensuing decades. In 1979, the EPA divided 

subpart D into 3 subparts – Da (“Standards of Performance for 

Electric Utility Steam Generating Units for Which Construction 

 

96 “Air Pollution Prevention and Control: List of Categories of 

Stationary Sources,” 36 FR 5931 (March 31, 1971).

97 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17, 

1971,” 36 Fed. Reg. 24875 (Dec. 23, 1971) codified at 40 CFR 

60.40-46; 36 Fed. Reg. 5931 (Mar. 31, 1971).

98 42 FR 53,657 (Oct. 3, 1977).

99 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978 ,” 44 Fed. Reg. 33580 (June 11, 1979).
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is Commenced After September 18, 1978”), Db (“Standards of 

Performance for Industrial-Commercial-Institutional Steam 

Generating Units”) and Dc (“Standards of Performance for Small 

Industrial-Commercial-Institutional Steam Generating Units”) –

in order to codify separate requirements that it established for 

these subcategories.100 In 2006, the EPA created subpart KKKK, 

”Standards of Performance for Stationary Combustion Turbines,” 

which applied to certain sources previously regulated in 

subparts Da and GG.

101 None of these rulemakings, including the

revised codifications, however, constituted a new listing under 

CAA § 111(b)(1)(A). 

In today’s rulemaking, the EPA is promulgating new 

standards of performance for CO2 emissions from certain sets of 

sources, e.g., steam-generating boilers (except for liquid-fired 

boilers) and turbines. Moreover, we are establishing different 

requirements for different sets of sources, including steamgenerating boilers as well as smaller and larger combustion 

turbines, in accordance with CAA § 111(b)(2). That provision 

authorizes the EPA to “distinguish among classes, types, and 

 

100 44 Fed. Reg. 33,580 (June 11, 1979)

101 71 Fed. Reg. 38497 (July 6, 2006), as amended at 74 Fed. Reg. 

11861 (Mar. 20, 2009).
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sizes within categories of new sources for the purpose of 

establishing ... standards [of performance.]”

In today’s rulemaking, we are including a proposal and, in 

the alternative, a co-proposal, which take two different 

approaches to the source categories and their codification.102Our 

proposal is to codify the new CO2 standards in the same subparts 

in which the standards of performance for conventional 

pollutants are codified. Thus, we propose to codify the GHG 

standards for steam-generating boilers as a new section in 

subpart Da, and the GHG standards for combustion turbines as new 

sections in subpart KKKK. This proposal does not list a new 

category under section 111(a)(1)(A). Nor does this proposal 

revise either of the two source categories – steam-generating 

boilers and combustion turbines – that EPA has already listed, 

or revise the codification of the new source requirements for 

 

102 In the original proposal for this rulemaking, the EPA proposed 

to create within 40 CFR part 60 a new subpart that would include 

GHG emission regulatory requirements for electric utility steam 

generating units (i.e., boilers and IGCC units), whose

conventional pollutant regulatory requirements are codified 

under subpart Da; as well as stationary combustion turbines that 

generate electricity for sale and meet certain size and 

operational criteria, conventional pollutant regulatory 

requirements are codified under subpart KKKK. The EPA proposed 

to number this newly created subpart as subpart TTTT. The EPA 

explained that combining the GHG regulatory requirements for 

those sources in TTTT was appropriate because the EPA was 

establishing the same limit for all those sources based on the 

same BSER, which was NGCC. 77 Fed. Reg. at 22,410/2 – 22,411/3.
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those categories in subparts Da, GG, and KKKK. Under this 

proposal, the establishment of different requirements for 

different sets of sources – for example, coal-fired power 

plants, larger NGCC plants, and smaller NGCC plants – constitute 

subcategorizations within the existing categories.

In the alternative, we co-propose to combine the two source 

categories – again, steam-generating boilers and combustion 

turbines -- for purposes of regulating CO2 emissions (but not for 

regulating emissions of conventional pollutants), and to codify 

all of the proposed regulatory requirements in a new subpart, 

TTTT.103 This combined category, created by combining two 

existing categorie cannot be considered a new source category

that EPA is placing on the list of categories for regulation 

under CAA §111(b)(1)(A). Under this co-proposal, the 

establishment of different requirements for different sets of 

sources continues to constitute subcategorizations within the 

existing category.

We solicit comment on the relative merits of each approach. 

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

combine the categories and codify the GHG standards for all new 

 

103 Under this co-proposal, these regulatory requirements are 

substantively the same as the requirements proposed for 

inclusion in subparts Da and KKKK, and are simply collected in a 

separate subpart, TTTT.

Comment [dj25]: Per OMB:

Redraft the following “This combined category 

cannot be considered a new category”.

EPA: Sentence has been revised.
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affected sources in subpart TTTT will offer any additional 

flexibility for any future emission guidelines for existing 

sources, for example, by facilitating a system-wide approach, 

such as emission rate averaging, that covers fossil-fuel fired 

steam generating units and combustion turbines. 

E. Rational basis to promulgate standards for GHGs from fossilfired EGUs

In this rulemaking, the EPA has a rational basis for 

concluding that emissions of CO2 from fossil-fired power plants, 

which are the major U.S. source of greenhouse gas air pollution,

merits taking action under CAA § 111. As noted, in 2009, the EPA 

made a finding that GHG air pollution may reasonably be 

anticipated to endanger public health or welfare, and in 2010, 

the EPA denied petitions to reconsider that finding. The EPA 

extensively reviewed the available science concerning GHG 

pollution and its impacts in taking those actions. In 2012, the 

U.S. Court of Appeals for the D.C. Circuit upheld the finding 

and denial of petitions to reconsider. In addition, assessments 

from the NRC and the IPCC, published in 2010, 2011, and 2012 

lend further credence to the validity of the Endangerment 

Finding. As discussed below, no information that commenters have 

presented or that the EPA has reviewed provides a basis for 

rescinding that finding. In addition, as noted, the high level 
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of GHG emissions from the fossil-fired EGUs makes clear that it 

is rational for the EPA to regulate GHG emissions from this 

sector. This information amply supports that the EPA has a 

rational basis for promulgating regulations under CAA § 111 

designed to address GHG air pollution. 

Our conclusion is consistent with the case law handed down 

by the D.C. Circuit. In its 1980 decision in National Lime 

Association v. EPA,

104 the Court upheld EPA’s determination that 

lime manufacturing plants emit particulates that contribute 

significantly to air pollution that endangers public health or 

welfare. The Court noted that (i) EPA’s basis was its prior 

determination that “the significant production of particulate 

emissions ... cause[s] or contribute[s] to air pollution (which 

may reasonably be anticipated to endanger public health or 

welfare);” and (ii) “[t]he Agency has made this determination 

for purposes of establishing national primary and secondary 

ambient air quality standards under [CAA § 109].” The Court 

held: 

We think the danger of particulate emissions' effect 

on health has been sufficiently supported in the 

Agency's (and its predecessor's) previous 

determinations to provide a rational basis for the 

Administrator's finding in this case. 105

 

104 627 F.2d 416 (D.C. Cir. 1980).

105 Id. at 431-32 n.48.
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Similarly, in National Asphalt Pavement Ass’n v. Train,106 the 

D.C. Circuit upheld a determination by the EPA that asphalt 

cement plants contribute significantly to particulate matter air 

pollution that endangers public health and welfare. The Court 

indicated that the EPA’s determination that particulate matter 

endangers is valid simply on grounds that the EPA established a 

NAAQS for that pollutant.107

These cases support our relying primarily on the analysis 

and conclusions in our previous Endangerment Finding, and the 

subsequent assessments, as providing a rational basis for our 

decision to impose standards of performance on GHG emissions 

from fossil-fuel fired EGUs.

In comments on the original proposal, commenters state that 

because the proposed rulemaking limits emissions of only CO2, and 

not other GHGs, the EPA cannot rely on the analysis and 

conclusions in the 2009 Endangerment Finding because it 

concerned a mix of six GHGs: carbon dioxide and five others. 

These commenters assert that as a prerequisite for regulating CO2

emissions alone, the EPA must make an endangerment finding for 

CO2 alone. Because the present proposal also limits emissions of 

only CO2, and not the other GHGs, we expect that the same issue 

 

106 539 F.2d 775 (D.C. Cir. 1976)

107 Id. at 784
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may arise with respect to this proposal. Commenters’ assertion 

is incorrect for two reasons. First, as discussed above, the EPA 

does not need to make an formal endangerment finding with 

respect to a particular pollutant to set standards for that 

pollutant under section 111(b)(1)(B). Second, the EPA may 

reasonably rely on the analysis and conclusions in the 2009 

Endangerment Finding on GHGs even when regulating only CO2. With 

respect to this proposed rulemaking, the air pollution at issue

here is the mix of six GHGs. It is that air pollution that has 

caused the various impacts on health and welfare that formed the 

basis for the Endangerment Finding. The CO2 emissions from EGUs 

are a major component of that air pollution. As we noted in the 

2009 Endangerment Finding, CO2 is the “dominant anthropogenic 

greenhouse gas.”108 The fact that we are not regulating the 

other five GHGs in this rulemaking does not mean that we are 

required to identify the air pollution as CO2 alone rather than 

the mix of six GHGs. This is consistent with the EPA’s past 

actions. In the 2010 Light Duty Vehicle Rule for which the 

Endangerment Finding served as the predicate, the EPA regulated 

only four of the GHGs, not all six.109

 

108 74 Fed. Reg. 66,496, 66,519 (Dec. 15, 2009)

109 75 Fed. Reg. 25,324, 25,396-97 (May 7, 2010). 

Comment [dj26]: Per OMB:

Clarify with a quantity or percent what “a major 

component of that air pollution” means.

EPA: We have quantified the amount of GHGs form 

fossil fuel EGUs in other locations in the preamble.
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Further, the fact that affected EGUs emit almost 1/3onethird of all U.S. GHGs and comprise by far the largest 

stationary source category of GHG emissions, along with the fact 

that the CO2 emissions from even a single new coal-fired power 

plant may amount to millions of tons each year, provide a 

rational basis for regulating CO2 emissions from affected EGUs.110

This is consistent with previous EPA actions that have been 

upheld by the D.C. Circuit. In the National Lime Association v. 

EPA case, noted above, the Court upheld the EPA’s regulation of 

lime plants on grounds that they were one of the largest --

although not within the largest 10 percent -- emitting 

industries of particulates. The Court stated, 

EPA ... focused ...on the sheer quantity of dust generated 

by lime plants. 42 Fed. Reg. 22507 (“A study performed for 

EPA in 1975 by the Research Corporation of New England 

ranked the lime industry twenty-fifth on a list of 112 

stationary sources categories which are emitters of 

particulate matter”); SSEIS 8-2 (“In a study performed for 

EPA by Argonne National Laboratory in 1975, the lime 

industry ranked seventh on a list of the 56 largest 

particulate source categories in the U.S.”).111

 

110 Commenters on the original proposal stated that new solidfuel fired power plants made no contribution to air pollution 

because EPA’s modeling projected no new construction of those 

types of plants. However, CAA §111(b)(1)(A) is clear by its 

terms that the source category listing that is the prerequisite 

to regulation is based on the contribution of the “category” to 

air pollution, and therefore is not based on the contribution of 

only new sources in the category. The same reasoning applies to 

the rational basis determination.

111 627 F.2d at 432, n.48.
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In the National Asphalt Pavement Ass’n v. Train case, noted 

above, the Court upheld the EPA’s determination that the asphalt 

industry contributed significantly to the air pollution based on 

“the number of existing plants, the expected rate of growth in 

the number of plants, the rate of uncontrolled emissions, and 

the level of emissions currently tolerated.”112 

F. Alternative findings of endangerment and significant 

contribution

Even if CAA section 111 is interpreted to require that the 

EPA make endangerment and cause-or-contribute significantly 

findings as prerequisites for today’s rulemaking, then our 

rational basis, as described, should be considered to constitute 

those findings. 

As noted above, the EPA’s rational basis for regulating 

under § 111 GHGs is based primarily on the analysis and 

conclusions in the EPA’s 2009 Endangerment Finding and 2010 

denial of petitions to reconsider that Finding, coupled with the 

2010, 2011, and 2012 assessments from the IPCC and NRC that 

describe scientific developments since those EPA actions. In 

addition, as noted above, we would review comments presenting 

other scientific information to determine whether that 

information has any meaningful impact on our primary basis. 

 

112 539 F.2d at 784-85.
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This rational basis approach is substantially similar to 

the approach the EPA took in the 2009 Endangerment Finding and 

the 2010 denial of petitions to reconsider. As noted, the D.C. 

Circuit upheld that approach in the CRR case. Accordingly, that 

approach would support an endangerment finding for this 

rulemaking.

By the same token, if the EPA were required to make a 

cause-or-contribute-significantly finding for CO2 emissions from 

the fossil fuel-fired EGUs, as a prerequisite to regulating such 

emissions under CAA § 111, the same facts that support our 

rational basis determination would support such a finding. In 

particular, as noted, fossil fuel-fired EGUs emit almost onethird of all U.S. GHG emissions, and constitute by far the 

largest single stationary source category of GHG emissions; and 

the CO2 emissions from even a single new coal-fired power plant 

may amount to millions of tons each year. It should be noted 

that at present, it is not necessary for the EPA to decide 

whether it must identify a specific threshold for the amount of 

emissions from a source category that constitutes a significant 

contribution. Under any reasonable threshold or definition, the 

emissions from EGUs are a significant contribution.113

 

113 Indeed, it is literally true that if fossil-fuel fired EGUs 

cannot be found to contribute significantly to GHG air 
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G. Comments on the state of the science of climate change 

The EPA received a number of comments in response to the 

original proposed NSPS rule addressing the scientific 

underpinnings of the EPA’s 2009 Endangerment Finding and, in 

essence, the scientific justification for this rule. Because 

this action is not a final action, we are not required to 

respond to those comments. Even so, we have carefully reviewed

all of those comments, and we do provide some responses in this 

action. It is important to place these comments in the context 

of the voluminous record on this subject that has been compiled 

over the last few years. This includes: 1) the process by which 

the Administrator reached the 2009 finding that GHGs are 

reasonably anticipated to endanger the public health and welfare 

of current and future generations; 2) the EPA’s response in 2010 

to ten administrative petitions for reconsideration of the 

Endangerment Finding, the “Reconsideration Denial”; and, 3) the 

decision by the United States Court of Appeals for the D.C.

Circuit (D.C. Circuit Court) in 2012 to uphold the Endangerment 

Finding and the Reconsideration Denial.

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

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

 

pollution, then there is no source category in the U.S. that 

does contribute significantly to GHG air pollution, a result 

that would defeat the purposes of CAA §111.
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scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger human health and 

welfare was to rely primarily upon the recent, major assessments 

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

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies. 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, in which the EPA took part. The EPA received 

thousands of comments on the proposed Endangerment Finding and 

responded to them in depth in an 11-volume RTC document. While 

the EPA gave careful consideration to all of the scientific and 

technical information received, it placed less weight on the 

much smaller number of individual studies that were not 

considered or reflected in the major assessments—often these 

studies were published after the submission deadline for those 

larger assessments. Primary reliance on the major scientific 

assessments provided the EPA greater assurance that it was 

basing its judgment on the best available, well-vetted science 

that reflected the consensus of the climate science community, 
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rather than selecting the studies it would rely on. 

Nonetheless, the EPA reviewed individual studies not 

incorporated in the assessment literature to see if they would 

lead the EPA to change its interpretation of, or place less 

weight on, the major findings reflected in the assessment 

reports. From its review of individual studies submitted by 

commenters, the EPA concluded that these studies did not change 

the various conclusions or judgments the EPA would draw based on 

the more comprehensive assessment reports. The major findings of 

the USGCRP, IPCC, and NRC assessments supported the EPA’s 

determination that GHGs threaten the public health and welfare 

of current and future generations. The EPA demonstrated this 

scientific support at length in the Endangerment Finding itself, 

in its Technical Support Document (which summarized the findings 

of USGCRP, IPCC and NRC), and in its RTC document.

The EPA then reviewed ten administrative petitions for 

reconsideration of the Endangerment Finding in 2010. The 

Administrator denied those petitions in the “Reconsideration 

Denial” on the basis that the Petitioners failed to provide 

substantial support for the argument that the Endangerment 

Finding should be revised and therefore their objections were 
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not of “central relevance” to the Finding.114 The EPA prepared 

an accompanying 3-volume RTP document to provide additional 

information, often more technical in nature, in response to the 

arguments, claims, and assertions by the petitioners to 

reconsider the Endangerment Finding.

The 2009 Endangerment Finding and the 2010 Reconsideration 

Denial were challenged in a lawsuit, and on June 26, 2012, the 

D.C. Circuit upheld them, ruling that they were neither 

arbitrary nor capricious, were consistent with Massachusetts v. 

EPA,115 and were adequately supported by the administrative 

record.116 The Court found that the EPA had based its decision on 

“substantial scientific evidence,”117 and noted that the EPA’s 

reliance on assessments was consistent with the methods 

decision-makers often use to make a science-based judgment.

118

The Court also found that the Petitioners had “not provided 

substantial support for their argument that the Endangerment 

Finding should be revised.”119 Moreover, the Court assessed the 

EPA’s reliance on the major scientific assessment reports that 

 

114 EPA’s Denial of the Petitions To Reconsider the Endangerment 

and Cause or Contribute Findings for Greenhouse Gases Under 

Section 202(a) of the Clean Air Act (“Reconsideration Denial”),

75 Fed. Reg. 49,556, 58 (Aug. 13, 2010).

115 Massachusetts v. EPA, 549 U.S. 497.

116 CRR, 684 F.3d at 102.

117 Id at 121.

118 Id at 120.

119 Id at 125.
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were conducted by USGCRP, IPCC, and NRC, and subjected to 

rigorous expert and government review, and found that --

EPA evaluated the processes used to develop the 

various assessment reports, reviewed their contents, 

and considered the depth of the scientific consensus 

the reports represented. Based on these evaluations, 

the EPA determined the assessments represented the 

best source material to use in deciding whether GHG 

emissions may be reasonably anticipated to endanger 

public health or welfare.120

As the Court stated,

It makes no difference that much of the 

scientific evidence in large part consisted of 

‘syntheses’ of individual studies and research. Even 

individual studies and research papers often 

synthesize past work in an area and then build upon 

it. This is how science works. The EPA is not required 

to re-prove the existence of the atom every time it 

approaches a scientific question.121

It is within the context of this extensive record, and 

recent affirmation of the Endangerment Finding by the Court, 

that the EPA has considered all of the submitted science-related 

comments and reports for the April 2012 proposed rule, and will 

consider any further comments in response to today’s proposed 

rule. As we did in the original Endangerment Finding, the EPA is 

giving careful consideration to all of the scientific and 

technical information in the record. However, the major peer-

 

120 Id at 120.

121 Id at 120.
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reviewed scientific assessments continue to provide the primary 

scientific and technical basis upon which the Administrator’s 

judgment relies regarding the threat to public health and 

welfare posed by GHGs.

Commenters on the April 2012 proposed rule submitted two 

major peer-reviewed scientific assessments that were released 

since the administrative record concerning the Endangerment 

Finding was closed after the EPA’s 2010 Reconsideration Denial: 

the IPCC Special Report on Managing the Risks of Extreme Events 

and Disasters to Advance Climate Change Adaptation (2012) (SREX) 

and the NRC Report on Climate Stabilization Targets: Emissions, 

Concentrations, and Impacts over Decades to Millennia (2011)

(Climate Stabilization Targets). The EPA has reviewed these 

assessments and they are briefly characterized here: 

SREX.The IPCC SREX assessment states that, “A changing 

climate leads to changes in the frequency, intensity, 

spatial extent, duration, and timing of extreme weather and 

climate events, and can result in unprecedented extreme 

weather and climate events.” The SREX documents 

observational evidence of changes in some of the weather 

and climate extremes that have occurred globally since 

1950. The SREX assessment provides evidence regarding the 

attribution of some of these changes to elevated 

concentrations of GHGs, including warming of extreme daily 

temperatures, intensification of extreme precipitation 

events, and rising extreme coastal high water due to 

increases in sea level. The assessment notes that further 

increases in some extreme weather and climate events are 

projected over the 21st century. The assessments also 

concludes that, combined with increasing vulnerability and 

exposure of populations and assets, changes in extreme 

weather and climate events have consequences for disaster 
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risk, with particular impacts on the water, agriculture and 

food security, and health sectors. 

Climate Stabilization Targets.

The NRC Climate Stabilization Targets assessment states 

that, “Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of Earth’s 

climate. Because carbon dioxide in the atmosphere is long 

lived, it can effectively lock Earth and future generations 

into a range of impacts, some of which could become very 

severe.” The assessment addresses the fact that emissions 

of carbon dioxide will alter the composition of the 

atmosphere, and therefore the climate, for thousands of 

years and attempts to quantify the implications of 

stabilizing GHG concentrations at different levels. The 

report also estimates a number of specific climate change 

impacts, finding warming could lead to increases in heavy 

rainfall and decreases in crop yields and Arctic sea ice 

extent, along with other important changes in precipitation 

and stream flow. For an increase in global average 

temperature of 1 to 2 oC above pre-industrial levels, the 

assessment found that the area burnt by wildfires in 

western North America will likely more than double and 

coral bleaching and erosion will increase due both to 

warming and ocean acidification; an increase of 3 oC will 

lead to a sea level rise of 0.5 to 1.0 meters by 2100; and 

with an increase of 4 oC, the average summer in the United 

States would be as warm as the warmest summers of the past 

century. The assessment notes that although many important 

aspects of climate change are difficult to quantify, the 

risk of adverse impacts is likely to increase with 

increasing temperature, and the risk of dangerous surprises 

can be expected to increase with the duration and magnitude 

of the warming.

A number of other National Academy assessments regarding 

climate have also been released recently. The EPA has reviewed 

these assessments, and finds that the improved understanding of 

the climate system resulting from the two assessments described 

above and the National Academy assessments strengthens the case 

Comment [A27]: Add cites?

EPA: These are cited and discussed extensively 

elsewhere in the preamble.

Climate Stabilization Targets; “National Security 

Implications for U.S. Naval Forces” (2011) (National 

Security Implications); 

“Sea Level Rise for the Coasts of California, Oregon, 

and Washington: Past, Present, and Future” (2012) 

(Sea Level Rise).

“Climate and Social Stress: Implications for Security 

Analysis” (2012), p.3.

“Understanding Earth’s Deep Past: Lessons for Our 

Climate Future” (2011), p.138.

“Ocean Acidification: A National Strategy to Meet 

the Challenges of a Changing Ocean” (2010), p. 5.
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that GHGs are endangering public health and welfare. Perhaps the 

most dramatic change relative to the prior assessments concern 

sea level rise. The previous 2007 IPCC AR4 assessment projected 

a rise in global sea level of between 7 and 23 inches by the end 

of the century relative to 1990 (with an acknowledgment that 

inclusion of ice sheet processes that were poorly understood 

would likely increase those projections). Three new NRC 

assessments have provided estimates of projected sea level rise 

that are much larger, in some cases more than twice as large as 

the previous IPCC estimates. Climate Stabilization Targets; 

National Security Implications for U.S. Naval Forces (2011); Sea 

Level Rise for the Coasts of California, Oregon, and Washington: 

Past, Present, and Future (2012). While the three NRC

assessments continue to recognize and characterize the 

uncertainty inherent in accounting for ice sheet processes, 

these revised estimates strongly support and strengthen the 

existing finding that GHGs are reasonably anticipated to 

endanger human health and welfare. Other key findings of the 

recent assessments are described briefly below:

The Sea Level Rise for the Coasts of California, Oregon, 

and Washington: Past, Present, and Future (2012) assessment 

notes that observations have shown that sea level rise on 

the West Coast has risen south of Cape Mendocino over the 

past century but dropped north of that point during that 

time due to tectonic uplift and other factors in Oregon and 

Washington. However, the assessment projects a global sea 

level rise of 1.6 to 4.6 feet by 2100, which is sufficient 
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to lead to rising relative sea level even in the northern 

states. The National Security Implications of Climate 

Change for U.S. Naval Forces also considers potential 

impacts of sea level rise, using a range of 1.3 to 6.6 feet 

by 2100. This assessment also suggests preparing for 

increased needs for humanitarian aid, responses to climate 

change in geopolitical hotspots including possible mass 

migrations, and addressing changing security needs in the 

Arctic as sea ice retreats. The Climate and Social Stress: 

Implications for Security Analysis (2012) assessment found 

that it would be “prudent for security analysts to expect 

climate surprises in the coming decade . . . and for them 

to become progressively more serious and more frequent 

thereafter[.]” Understanding Earth’s Deep Past: Lessons for 

Our Climate Future (2011) examines the period of Earth’s 

history prior to the formation of the Antarctic and 

Greenland Ice Sheets because CO2 concentrations by the end 

of the century will have exceeded levels seen in the 30 

million years since that time. The assessment discusses the 

possibility that analogous paleoclimate states might 

suggest higher climate sensitivity, less well regulated 

tropical surface temperatures, higher sea level rise, more 

anoxic oceans, and more potential for non-linear events 

such as the Paleo-Eocene Thermal Maximum than previously 

estimated. The assessment notes that three or four out of 

the five major coral reef crises of the past 500 million 

years were probably driven by acidification and warming 

caused by GHG increases similar to the changes expected 

over the next hundred years. The assessment states that 

“the magnitude and rate of the present greenhouse gas 

increase place the climate system in what could be one of 

the most severe increases in radiative forcing of the 

global climate system in Earth history.” Similarly, the 

Ocean Acidification: A National Strategy to Meet the 

Challenges of a Changing Ocean (2010) assessment found that 

“[t]he chemistry of the ocean is changing at an 

unprecedented rate and magnitude due to anthropogenic 

carbon dioxide emissions; the rate of change exceeds any 

known to have occurred for at least the past hundreds of 

thousands of years.” The assessment notes that the full 

range of consequences is still unknown, but the risks 

“threaten coral reefs, fisheries, protected species, and 

other natural resources of value to society.” 
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Several commenters on the April 2012 proposed rule argue 

that the Endangerment Finding should be reconsidered or 

overturned based on those commenters’ reviews of specific 

climate science literature, particularly newer publications that 

have appeared since the EPA’s 2010 Denial of Petitions. Some 

commenters have presented their own compilations of individual 

studies as support for their assertions that climate change will 

have beneficial effects in many cases and that climate impacts 

will not be as severe or adverse as the EPA and assessments like 

the USGCRP (2009) report have stated. These commenters conclude

that U.S. society will continue to easily adapt to climate 

change and that climate change therefore does not pose a threat 

to human health and welfare. 

The EPA has reviewed the information submitted and finds 

that, the fundamental issues raised in the comments that 

critique the scientific justification for the rule have been 

addressed by the EPA’s 11-volume response to comments for the 

2009 Endangerment Finding, the EPA’s responses to all issues 

raised by Petitioners in the Reconsideration Denial, or the D.C. 

Circuit in its 2012 decision to uphold the EPA’s 2009 

Endangerment Finding. These comments do not change the various 

conclusions or judgments that the EPA would draw based on the 

assessment reports relied upon in the recent 2009 Finding.
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These comments often highlight uncertainty regarding 

climate science as an argument for reconsideration. However, 

uncertainty was explicitly recognized in the 2009 Endangerment 

Finding: “The Administrator acknowledges that some aspects of 

climate change science and the projected impacts are more 

certain than others”,122 and the decision to find endangerment 

was made with full recognition of the uncertainty involved. In 

addition, the D.C. Circuit Court decision noted that, “the 

existence of some uncertainty does not, without more, warrant 

invalidation of an endangerment finding.”123 In short, these 

recent publications submitted by commenters, and any new issues 

that are extracted from them, do not undermine either the 

significant body of scientific evidence that has accumulated 

over the years or the conclusions presented in the substantial 

peer-reviewed assessments of the USGCRP, NRC, and IPCC.

Regarding the contentions that the U.S. will adapt to 

climate change impacts and that therefore climate change impacts 

pose no threat, the EPA stated in the 2009 Endangerment Finding,

Risk reduction through adaptation and GHG mitigation 

measures is of course a strong focal area of 

scientists and policy makers, including the EPA; 

however, the EPA considers adaptation and mitigation 

to be potential responses to endangerment, and as such 

 

122 74 FR 66524.

123 CRR, 684 F.3d at 121.
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has determined that they are outside the scope of the 

endangerment analysis.124

The D.C. Circuit upheld this position, ruling that “These 

contentions [that the U.S. can adapt] are foreclosed by the 

language of the statute and the Supreme Court's decision in 

Massachusetts v. EPA” because “predicting society’s adaptive 

response to the dangers or harms caused by climate change” does 

not inform the “scientific judgment” that the EPA is required to 

take regarding Endangerment.125 

Some commenters raise issues regarding the EPA Inspector 

General’s report, Procedural Review of EPA’s Greenhouse Gases 

Endangerment Finding Data Quality Processes (2011). These 

commenters mischaracterize the report’s scope and conclusions 

and, thus, vastly overstate the significance of the Inspector 

General’s procedural recommendations. Ultimately, nothing in the 

Inspector General report questions the validity of the EPA’s 

Endangerment Finding because that report did not evaluate the 

scientific basis of the Endangerment Finding. Rather, the 

Inspector General offers recommendations for clarifying and 

standardizing internal procedures for documenting data quality 

and peer review processes when referencing existing peer 

 

124 74 FR 66512 (emphasis added).

125 984 F.3d at 117. 
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reviewed science in the EPA actions. Unrelated to the 

Endangerment Finding and its validation by the Court, the EPA 

has made progress towards implementing the recommendations by 

the Inspector General.

One commenter submitted a number of emails from the period 

1999 to 2009 that were obtained from a University of East Anglia 

server in 2009 and publicly released in 2011. After reviewing 

these emails, the EPA finds that they raise no issues that were 

not previously raised by Petitioners in regard to an earlier 

group of emails from the same incident, released in 2009. The 

commenter makes unsubstantiated assumptions and subjective 

assertions regarding what the e-mails purport to show about the 

state of climate change science; this provides inadequate 

evidence to challenge the voluminous and well documented body of 

science that is the technical foundation of the Administrator’s 

Endangerment Finding.

A number of comments were also submitted in support of the 

Endangerment Finding and/or providing further evidence that 

climate change is a threat to human health and welfare. A number 

of individual studies were submitted and a number of observed or 

projected climate changes of local importance or concern to 

commenters were documented. Again, the EPA places lesser weight 

on individual studies than on the major scientific assessments. 
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Local observed changes can be of great concern to individuals 

and communities but must be assessed in the context of the 

broader science, as it is more difficult to draw robust 

conclusions regarding climate change over short time scales and 

in small geographic regions.

V. Rationale for Applicability Requirements 

A. Applicability requirements - original proposal and comments

The original proposal was designed to apply to new 

intermediate and base load EGUs, specifically, 1) fossil fuelfired utility boilers and IGCC EGUs subject to subpart Da for 

criteria pollutant emissions, and 2) natural gas combined cycle 

EGUs subject to subpart KKKK for criteria pollutant emissions. 

The original proposal explicitly did not apply to simple cycle 

turbines because we concluded that they were operated 

infrequently and therefore only contributed small amounts to 

total GHG emissions. (For convenience, we occasionally refer to 

this explicit statement that the original proposed NSPS did not 

apply to a type of source as an exclusion.)

We received comments that supported the simple cycle 

exclusion and others that opposed it. Commenters in support 

stated that a new simple cycle power plant serves a different 

purpose than a new combined cycle plant and that economics will 

drive the use of combined cycle facilities over simple cycle 
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plants. They also stated that the original proposed standard is 

not achievable by, and therefore is not BSER for, simple cycle 

turbines. Commenters opposing the exclusion stated that it 

creates an opportunity to evade the standard and could thereby 

increase GHG emissions. According to these commenters, any 

applicability distinctions should be based on utilization and 

function rather than purpose or technology. 

After considering these comments, we are proposing a 

different approach to the applicability provisions with respect 

to simple cycle turbines.

B. Applicability requirements – today’s proposal

In today’s rulemaking, we propose that applicability should 

be based on electric sales alone, so that the proposed standards 

of performance apply to a facility if the facility supplies more 

than 1/3one-third of its potential electric output and more than 

219,000 MWh net electric output to the grid per year. (We refer 

to a facility’s sale of more than one-third of its potential 

electric output as the one-third sales criterion, and we refer 

to the amount of potential electric output supplied to a utility 

power distribution system, expressed in MWh, as the capacity 

factor.) This proposed definition does not explicitly exclude 

simple cycle combustion turbines, but as a practical matter, it 

would exclude most of them because the vast majority of simple 
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cycle turbines sell less than one-third of their potential 

electric output. The few simple-cycle combustion turbines that 

sell more than one-third of their potential electric output to 

the grid would be subject to the proposed standards of 

performance. As explained below, we have concluded that at this 

level of output, there are less expensive and lower emitting 

technologies that could be constructed consistent with today’s 

proposed standards. Although, as noted, today’s proposal does 

not explicitly exclude simple cycle combustion turbines, we 

solicit comment on whether to provide an explicit exclusion. 

We are proposing to apply the one-third sales criterion on 

a rolling three year basis instead of an annual basis for 

stationary combustion turbines for multiple reasons. First, 

extending the period to three years would ensure that the CO2 

standards apply only to intermediate and base load EGUs by 

allowingpermit facilities intended to generally operate at low 

capacity factors (e.g. simple cycle turbines that generally sell 

less than one-third of their potential electric output) to avoid 

applicability even though they may provide system capacity and, 

in fact, operate at high capacity factors during individual 

years with abnormally high electric demand. Second, only 0.2 

percent of existing simple cycle turbines had a three-year 

average capacity factor of greater than one-third between 2000 
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and 2012. Therefore, as noted, from a practical standpoint, few 

new simple cycle turbines will be subjected to the standards of 

performance in this rulemaking. 

The 2013 AEO cost and performance characteristics for new 

generation technologies include costs for advanced and 

conventional combined cycle facilities and advanced simple cycle 

turbines. According to the AEO 2013 values, advanced combined 

cycle facilities have a lower cost of electricity than advanced 

simple cycle turbine facilities above approximately a 20 percent 

capacity factor. Therefore, the use of a combined cycle 

technology would be BSER for higher capacity factor stationary 

combustion turbines. However, advanced combined cycle facilities 

do not have a lower cost of electricity than less capital 

intensive conventional combined cycle facilities until above 

approximately a 40 percent capacity factor. Between 

approximately 20 to 40 percent capacity factors, conventional 

combined cycle facilities offer the lowest cost of electricity, 

and below approximately 20 percent capacity factors advanced 

simple cycle turbines offer the lowest cost of electricity. A 

capacity factor exemption at 40 percent (i.e., sellsales of less 

than two-fifths of potential electric output per year) would 

allow conventional combined cycle facilities built with the 

intent to operate at relatively low capacity factors as an 
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alternative technology to simple cycle turbines because neither 

would be subject to the NSPS requirements. Based on these cost 

considerations, we are specifically requesting comment on a 

range of 20 to 40 percent of potential electric output sales on 

a three-year basis for the capacity factor exemption. The 20 

percent applicability limit is consistent with generating the 

lowest cost of electricity for advanced combined cycle turbines

compared to advanced simple cycle turbines, and based on 

historical capacity factors would impact the operation of only 

approximately two percent of simple cycle turbines. The 40 

percent applicability limit would be more consistent with the 

annual run hour limitations currently contained in many simple 

cycle operating permits.

We are also requesting comments on whether applicability 

for stationary combustion turbines should be defined on a single 

calendar year basis, similar to the current subpart Da 

applicability provisions for criteria pollutants, instead of a 

three-year basis. With a single year basis, we are considering 

an applicability level of up to 40 (instead of 33 and one-third) 

percent sales. Only 0.4 percent of existing simple cycle 

turbines had an annual capacity factor of greater than 40 

percent between 2000 and 2012. Assuming the average hourly 

output of a simple cycle turbine is 80 percent of the maximum 
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rated output, a simple cycle turbine could operate up to 4,400 

hours annually before exceeding the capacity factor threshold. 

This is consistent with the operation hour limitation in many 

permits. Therefore, with this 40 percent sales criterion on a 

single-year basis, as a practical matter, it is anticipated that 

few new simple cycle turbines would be subject to the proposed 

standards of performance. Thus, we are specifically requesting 

comment on a range of one-third to two-fifths of potential 

electric output annual sales. The lower range would be 

consistent with how an EGU is currently defined in the EPA 

rules, and would mean that the proposed standards of performance 

would impact approximately one percent of new simple cycle 

turbines. 

We are also proposing a different definition of potential 

electric output from the current definition that determines the 

potential electric output (in MWh on an annual basis) 

considering only the design heat input capacity of the facility 

and does not account for efficiency. It assumes a 33 percent net 

electric efficiency, regardless of the actual efficiency of the 

facility and could discourage the installation of more efficient 

facilities. For example, a 33 percent efficient 100 MW facility 

would have a heat input of 1,034 MMBtu/h and a 40 percent

efficient 100 MW facility would have a heat input of 853 
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MMBtu/h.

126 The 33 percent efficient facility would have become 

subject to the NSPS requirements when it sells more than onethird of its potential electric output, 880,000 MWh. The 40 

percent efficient facility would become subject to the NSPS 

requirements when it sells more than 730,000 MWh.127 This could 

potentially encourage the construction of less efficient 

facilities, since they could have a higher actual capacity 

factor than a more efficient unit, while still not being an EGU 

subject to a CO2 standard. Therefore, we are proposing a 

definition of potential electric output that allows the source 

the option of calculating its potential electric output on the 

basis of its actual design electric output efficiency on a net 

output basis, as an alternative to the default one-third value. 

The proposed definition would permit the 40 percent efficient 

facility to use the actual efficiency of the facility so that 

the electric sales applicability criteria would be 880,000 MWh 

and applicability would be determined the same as for the less 

efficient facility.

 

126 (100 MW)*(3.412 MMBtu/h/ 1 MWh)*(1/0.33) = 1,034 MMBtu/h.

(100 MW)*(3.412 MMBtu/h/ 1 MWh)*(1/0.40) = 853 MMBtu/h.

127 (1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) = 

880,000 MWh.

(853 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) = 730,000 

MWh.
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The April 2012 proposal would have applied to facilities 

that primarily burn non-fossil fuels but also co-fire a fossil 

fuel. We have concluded that it is not appropriate to subject 

these facilities to the standards in today’s proposal. The EPA 

believes tThis is appropriate because these types of units more 

closely resemble the non-fossil fuel-fired boilers and 

stationary combustion turbines that are not covered by today’s 

proposed rule, than they do the fossil fuel-fired boilers and 

stationary combustion turbines that are covered by this rule. 

This approach is similar to the approach used in the Mercury and 

Air Toxics Standards, another CAA regulatory effort focused on 

fossil fuel-fired power plants. Therefore, we are proposing to 

limit the applicability of the standard to facilities where the 

heat input is comprised of more than 10.0 percent fossil fuel on 

a three-year rolling average basis. To simplify determining 

applicability with the CO2 standard, we also request comment on 

whether the applicability for facilities that co-fire non-fossil 

fuels should be made on an annual average basis, instead of a 

three-year rolling average basis.

In the original proposal, we requested comment on the 

applicability of the GHG NSPS to combined heat and power (CHP) 

facilities and if applicability should be changed from how it is 

currently determined in subpart Da. In today’s action, we 
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proposeWe have concluded that if CHP facilities meet the general 

applicability criteria they should be subject to the same 

requirements as electric-only generators. However, one potential 

issue that we have identified is inequitable applicability to 

third-party CHP developers compared to CHP facilities owned by 

the facility using the thermal output from the CHP facility. As 

noted above, we propose that the proposed CO2 standard of 

performance apply to a facility that supplies more than onethird of its potential electricity output and more than 219,000 

MWh “net electric output” to the grid per year. The current 

definition of net electric output for purposes of criteria 

pollutants (used in the 1/3one-third sales applicability 

criteria) is “the gross electric sales to the utility power 

distribution system minus purchased power on a calendar year 

basis.” 40 CFR 60.41Da. Owners/operators of a CHP facility under 

common ownership as an adjacentlocated at a facility using the 

thermal output from the CHP facility (i.e., the thermal host) 

they own can subtract out power purchased by the adjacent at 

that facility on an annual basis when determining applicability. 

However, third-party CHP developers would not be able to benefit 

from the “minus purchased power on a calendar year basis” 

provision in the definition of net electric output when 

determining applicability since the CHP facility and the thermal 
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host(s) are not under common ownershippart of the same affected 

facility. We are therefore proposing to add “of the thermal host 

facility or facilities” (so that the clause would read,i.e., 

“the gross electric sales to the utility power distribution 

system minus purchased power of the thermal host facility or 

facilities on a calendar year basis” to the definition of netelectric output for qualifying CHP facilities(emphasis added))

(i.e., the clause would read, “the gross electric sales to the 

utility power distribution system minus purchased power of the 

thermal host facility or facilities on a calendar year basis”

(emphasis added)). This would make applicability consistent for 

both facility-owned CHP and third-party-owned CHP.

This proposal includes within the definition of a steam 

electric generating unit, IGCC, and stationary combustion 

turbine that are subject to the proposed requirements, any 

integrated device that provides electricity or useful thermal 

output to the boiler, the stationary combustion turbine or to 

power auxiliary equipment. The rationale behind including 

integrated equipment recognizes that the integrated equipment 

may be a type of combustion unit that emits GHGs, and that it is 

important to assure that those GHG emissions are included as 

part of the overall GHG emissions from the affected source. 

Including integrated equipment avoids circumvention of the 
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requirements by having a boiler not subject to the standard 

supplying useful energy input (e.g., an industrial boiler 

supplying steam for amine regeneration in a CCS system) without 

accounting for the GHG emissions when determining compliance 

with the NSPS. In addition, the proposed definition would 

provide additional compliance flexibility similar to when the 

HRSG was included in the combustion turbine NSPS by recognizing 

the environmental benefit of integrated equipment that lowers 

the overall emissions rate of the affected facility. Even 

without this specific language, the original 1979 steam electric 

generating unit definition in subpart Da allows the use of solar 

thermal equipment for feedwater heating as an approach to 

integrating non-emitting generation to reduce environmental 

impact and lower the overall emissions rate. The current 

definition expands the flexibility to include combustion 

turbines, fuel cells, or other combustion technology for 

reheating or preheating boiler feedwater, preheating combustion 

air, producing steam for use in the steam turbine or to power 

the boiler feedpumps, or using the exhaust directly in the 

boiler to generate steam. This in theory could lower generation 

costs as well as lower the GHG emissions rate for an EGU.

C. Certain projects under development

This proposal does not apply to the proposed Wolverine EGU 
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project in Rogers City, Michigan. Based on current information, 

the Wolverine project appears to be the only fossil fuel-fired 

boiler or IGCC EGU project presently under development that may 

be capable of “commencing construction” for NSPS purposes in the 

very near future and, as currently designed, could not meet the 

1,100 lb CO2/MWh standard proposed for other new fossil fuelfired boiler and IGCC EGUs. The EPA has not formulated a view 

as to the project’s status in the development process or as to 

whether the proposed 1,100 lb CO2/MWh standard or some other CO2

standard of performance would be representative of BSER for this 

project and invites comment on these questions.128 At the time of 

finalization of this proposal (but not sooner than one year 

 

128 The EPA’s lack of view regarding the appropriate CO2 standard 

is closely related to the existence of conflicting information 

on where the project stands in the development process. The 

developer has claimed that the project was delayed by issues 

related to the standards of performance for hazardous air 

pollutants promulgated in December 2011, 77 FR 9304 (Feb. 16, 

2012) (Mercury and Air Toxics Standards, or MATS). Specifically, 

the developer cited a perceived inability to obtain guarantees 

from pollution control equipment vendors that the plant would 

achieve the MATS standards. See Jim Dulzo, As Coal Plant 

Teeters, Groups Mount Legal Attack, Michigan Land Use Institute 

blog, Feb. 13, 2012, http://www.mlui.org/energy/news-views/newsviews-articles/as-coal-plant-teeters-groups-mount-legalattack.html. While some of the MATS new-unit standards were

revised upon reconsideration in March 2013, 78 FR 24073 (Apr. 

24, 2013), the developer’s claims raise the possibility that the 

EPA’s own actions may have delayed the project and contributed 

to the present uncertainty as to the project’s development 

status.
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following Federal Register publication of this proposal), if the 

Wolverine project remains under development and has not either 

commenced construction or been canceled, we anticipate proposing 

that the project either be made subject to the 1,100 lb CO2/MWh 

standard or be assigned to a subcategory with an alternate CO2

standard. Further discussion is provided in the technical 

support document in the docket entitled “Fossil Fuel-Fired 

Boiler and IGCC EGU Projects under Development: Status and 

Approach.” 

There are two other fossil fuel-fired boiler or IGCC EGU 

projects without CCS – the Washington County project in Georgia 

and the Holcomb project in Kansas – that appear to remain under 

development but whose developers have recently represented that 

the projects have commenced construction for NSPS purposes. 

Based solely on the developers’ representations, the projects 

would be existing sources, and thus not subject to this 

proposal. However, neither developer has sought a formal EPA 

determination of NSPS applicability; and, if upon review it was 

determined that the projects have not commenced constructions, 

the projects could be situated similarly to the Wolverine 

project. Accordingly, if either developer seeks a formal EPA 
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determination of applicability129 within 120 days following 

Federal Register publication of this proposal and the EPA finds 

that the project has not “commenced construction,”130 as of the 

date of the Federal Register publication of this proposal, then 

that project automatically – without, for example, any 

supplemental proposal or re-proposal – would be addressed in the 

same manner as the Wolverine project.131 Further discussion is 

provided in the technical support document in the docket 

 

129 Under the NSPS regulations, the EPA will respond within 30 days 

to any request by an owner or operator for “a determination of 

whether action taken or intended to be taken by such owner or 

operator constitutes construction . . . or the commencement 

thereof within the meaning of this part.” 40 CFR 60.5.

130 The NSPS regulations include the following definitions of 

“commenced” and “construction”: 

Commenced means . . . that an owner or operator has 

undertaken a continuous program of construction . . . 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 . . . . 

Construction means fabrication, erection, or installation 

of an affected facility. 

40 CFR 60.2.

131 In this event, there will not be any proposed standard “which 

will be applicable to such source” within the meaning of CAA 

section 111(a)(2), and to the extent that this proposal did, 

until the time of the applicability determination, apply to that 

project, this proposal will be considered automatically to be 

withdrawn as it applies to that project as of the time of the 

applicability determination. The purpose of this automatic 

withdrawal is to ensure that the project is placed on the same 

footing as the Wolverine project as soon as possible. It is 

worth noting that, if the developers do not seek applicability 

determinations within the 120 day timeframe, nothing in this 

rulemaking binds the EPA to the position that the projects have 

“commenced construction” for NSPS purposes.
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referenced above.132 

We invite comment on all aspects of this approach for 

addressing the Wolverine project (and the Washington County and 

Holcomb projects, if applicable).133

VI. Legal Requirements for Establishing Emission Standards 

A. Overview

In this section, we describe the principal legal 

requirement for the standards of performance under CAA § 111 

that we propose in this rulemaking, which is that the standards 

must consist of emission limits that are based on the “best 

 

132 In the April 2012 GHG NSPS proposal, the Wolverine, 

Washington County, and Holcomb projects were among a group of 15 

projects distinguished from other EGU projects as “potential 

transitional sources.” This proposal does not continue that 

distinction. Except as described above for the Wolverine 

project, and possibly the Washington County and Holcomb 

projects, any former “potential transitional source” that 

commences construction after publication of this proposal (and 

meets any other applicability criteria) will be subject to the 

final CO2 standards established in this rulemaking. Any former 

“potential transitional source” that commenced construction 

prior to publication of this proposal is an existing source not 

subject to the CO2 standards established in this rulemaking, but 

instead subject to the CO2 standards that are required to be 

established for existing sources pursuant to CAA section 111(d).

133 The EPA intends that its treatment of the Wolverine project 

(and the Washington County and Holcomb projects, if applicable) 

be severable from its treatment of differently situated sources 

and considers that severability is logical because of the 

record-based differences between these sources and differently 

situated sources and because there is no interdependency in the 

EPA’s treatment of the different types of sources. This 

statement concerning severability should not be construed to 

have implications for whether other components in this 

rulemaking are severable.
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system of emission reduction ... adequately demonstrated,” 

taking into account cost and other factors (BSER). In this 

manner, CAA § 111 provides that the EPA’s central task is to 

identify the BSER. The D.C. Circuit has handed down case law, 

which we review in detail, that interprets this CAA provision, 

including its component elements. The Court’s interpretation 

indicates the technical, economic, and energy-related factors 

that are relevant for determining the BSER, and provides the 

framework for analyzing those factors. 

According to the D.C. Circuit, EPA determines the best 

demonstrated system based on the following key considerations, 

among others: 

The system of emission reduction must be technically 

feasible. 

EPA must consider the amount of emissions reductions that 

the system would generate.

The costs of the system must be reasonable. EPA may 

consider the costs on the source level, the industry-wide 

level, and, at least in the case of the power sector, on 

the national level in terms of the overall costs of 

electricity and the impact on the national economy over 

time. 

EPA must also consider that CAA § 111 is designed to 
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promote the development and implementation of technology.

Other considerations are also important, including that EPA 

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

consider them on the source level and on the nationwide 

structure of the power sector over time. Importantly, EPA has 

discretion to weigh these various considerations, may determine 

that some merit greater weight than others, and may vary the 

weighting depending on the source category.

B. CAA requirements and Court interpretation

1. Clean Air Act Requirements

The EPA’s basis for proposing that partial capture CCS is 

the BSER for new fossil fuel-fired utility boilers and IGCC 

units, and that NGCC is the BSER for natural gas-fired 

stationary combustion turbines, is rooted in the provisions of 

CAA § 111 requirements, as interpreted by the United States 

Court of Appeals for the D.C. Circuit (“D.C. Circuit” or 

“Court”), which is the federal Court of Appeals with 

jurisdiction over the EPA’s CAA rulemaking.

As the first step towards establishing standards of 

performance, the EPA “shall publish ... a list of categories of 

stationary sources ... [that] cause[], or contribute[] 

significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare.” §
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111(b)(1)(A). Following that listing, the EPA “shall publish 

proposed regulations, establishing federal standards of 

performance for new sources within such category” and then 

“promulgate ... such standards” within a year after proposal. §

111(b)(1)(B). The EPA “may distinguish among classes, types, and 

sizes within categories of new sources for the purpose of 

establishing such standards.” § 111(b)(2). The term “standard of 

performance” is defined to “mean[] 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.” § 111(a)(1).

2. Court interpretation

For present purposes, the key § 111 provisions are the 

definition of “standard of performance,” under CAA § 111(a)(1), 

and, in particular, the “best system of emission reduction which 

(taking into account ... cost ... nonair quality health and 

environmental impact and energy requirements) ... has been 

adequately demonstrated.” The D.C. Circuit has reviewed 

rulemakings under § 111 on numerous occasions during the past 40 
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years, handing down decisions dated from 1973 to 2011,134 through 

which the Court has developed a body of case law that interprets 

the term “standard of performance.” These interpretations are of 

central importance to the EPA’s justification for the standards 

of performance in the present rulemaking.

At the outset, it should be noted that Congress first 

included the definition of “standard of performance” when 

enacting CAA § 111 in the 1970 Clean Air Act Amendments (CAAA), 

and then amended it in the 1977 CAAA, and then amended it again 

in the 1990 CAAA, generally repealing the amendments in the 1977 

CAAA and, therefore, reverting to the version as it read after 

the 1970 CAAA. The legislative history for the 1970 and 1977 

CAAAs explained various aspects of the definition as it read at 

those times. Moreover, the various decisions of the D.C. Circuit 

interpreted the definition that was applicable to the 

rulemakings before the Court. Notwithstanding the amendments to 

the definition, the D.C. Circuit’s interpretations discussed 

below remain applicable to the current definition.135

 

134 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011).

135 In the 1970 CAAA, Congress defined “standard of performance,” 

under §111(a)(1), as—
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3. Overview of interpretation

By its terms, the definition of “standard of performance” 

under CAA § 111(a)(1) provides that the emission limit that the 

EPA promulgates must be “achievable” and must be based on a 

system of emission reduction – generally, but not required to be 

always, a technological control -- that the EPA determines to be 

 

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) the Administrator determines 

has been adequately demonstrated.

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard (i) be based 

on, in lieu of the “best system of emission reduction ... 

adequately demonstrated,” the “best technological system of 

continuous emission reduction ... adequately demonstrated;” and 

(ii) require a percentage reduction in emissions. In addition, 

in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 

consider “any nonair quality health and environment impact and 

energy requirements.”

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

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

This 1990 CAAA version is the current definition, which is 

applicable at present. Even so, because parts of the definition 

as it read under the 1977 CAAA were retained in the 1990 CAAA, 

the explanation in the 1977 CAAA legislative history, and the 

interpretation in the case law, of those parts of the definition 

remain relevant to the definition as it reads today.
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the “best system” that is “adequately demonstrated,” “taking 

into account ... cost ... nonair quality health and environmental 

impact and energy requirements.” The D.C. Circuit has stated 

that in determining the “best” system, the EPA must also take 

into account “the amount of air pollution”136 and “technological 

innovation.”137

As discussed below, the D.C. Circuit has elaborated on the 

criteria and process for determining whether a standard is 

“achievable,” based on an “adequately demonstrated” technology 

or system. In addition, the Court has identified limits on the 

costs and other factors that are acceptable for the technology 

or system to qualify as the “best.” The Court has also held that 

the EPA may consider the costs and other factors on a regional 

or national level (e.g., the EPA may consider impacts on the 

national economy and the affected industry as a whole) and over 

time, and not just on a plant-specific level at the time of the 

rulemaking.138 In addition, the Court has emphasized that the EPA 

has a great deal of discretion in weighing the various factors 

to determine the “best system.”139 Moreover, the Court has 

 

136 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981). 

137 See Sierra Club v. Costle, 657 F.2d at 347.

138 See Sierra Club v. Costle, 657 F.2d at 330.

139 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999).
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stated that in considering the various factors and determining 

the “best system,” the EPA must be mindful of the purposes of §

111, and the Court has identified those purposes as “not 

giv[ing] a competitive advantage to one State over another in 

attracting industry[,]... “reducing emissions as much as 

practicable[,]”... “forc[ing] the installation of all the control 

technology that will ever be necessary on new plants at the time 

of construction[,]...” and “forc[ing] the development of improved 

technology.”140 Finally, based on cases the D.C. Circuit has 

handed down under related provisions of the CAA and the EPA’s 

regulatory precedent under § 111, the EPA may promulgate a 

standard of performance for a particular category of sources 

even if not every type of new source in the category would be 

able to achieve that standard.141

We next discuss in more detail each of these components of 

the interpretation of “standard of performance.” 

C. Technical feasibility 

The D.C. Circuit’s first decision under § 111, Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), 

concerned whether EPA’s standard of performance for the cement 

 

140 Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 

Fed.Reg. 33,580, 33,581/3-33,582/1).

141 See, e.g., International Harvester Co. v. EPA, 478 F.2d 615, 

640 (D.C. Cir. 1973).
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industry met the requirement to be “achievable,” which, in turn, 

depended on whether the technology on which EPA based the 

standard was “adequately demonstrated.”142 In this case, the 

Court interpreted these provisions to require that the 

technology must be technically feasible for the source category, 

and established criteria for determining technical feasibility.

The Court explained that a standard of performance is 

“achievable” if a technology can reasonably be projected to be 

available to new sources at the time they are constructed that 

will allow them to meet the standard. Specifically, the D.C. 

Circuit explained: 

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....- It is the 

“achievability” of the proposed standard that is in 

issue....

The Senate Report made clear that it did not 

intend that the technology “must be in actual routine 

use somewhere.” The essential question was rather 

whether the technology would be available for 

installation in new plants.... 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.143

In subsequent cases, the D.C. Circuit has consistently 

 

142 486 F.2d at 390.

143 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted).
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reiterated this formulation of “achievable.”144

It should be noted that in another of the early cases, 

Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 

1973), the D.C. Circuit upheld a standard of performance as 

“achievable” on the basis of test data showing that the tested 

plant emitted less than or at the standard on three occasions 

and emitted above the standard on 16 occasions, and that, on 

average, it emitted 15% above the standard on a total of 19 

occasions.145 The fact that the plant had achieved the standard 

on at least a few occasions, even though the plant had not done 

so on the great majority of occasions, “adequately demonstrated” 

that the standard was “achievable.” 

D. Factors to consider in determining the “best system” 

1. Amount of emissions reductions

Although the definition of “standard of performance” does 

not by its terms identify the amount of emissions from the 

category of sources and the amount of emission reductions 

achieved as factors the EPA must consider in determining the 

“best system of emission reduction,” the D.C. Circuit has stated 

that the EPA must do so. See Sierra Club v. Costle, 657 F.2d 

 

144 See, e.g., National Asphalt Pavement Ass’n v. Train, 539 F.2d 

775, 785 (D.C. Cir. 1976); Lignite Energy Council v. EPA, 109 

F.3d 930, 934 (D.C. Cir. 1999).

145 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 27.
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298, 326 (D.C. Cir. 1981) (“we can think of no sensible 

interpretation of the statutory words “best ... system” which 

would not incorporate the amount of air pollution as a relevant 

factor to be weighed when determining the optimal standard for 

controlling ... emissions”).146 This is consistent with the Court’s 

statements in Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 

(D.C. Cir. 1973) that it is necessary to “[k]eep[] in mind 

Congress' intent that new plants be controlled to the ‘maximum 

practicable degree.’”147

2. Costs

In several cases, the D.C. Circuit has elaborated on the 

cost factor that the EPA is required to consider under CAA §

111(a)(1), and has identified limits to how costly a control 

technology may be before it no longer qualifies as the “best 

system of emission reduction ... adequately demonstrated.” As a 

related matter, although no D.C. Circuit case addresses how to 

 

146 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system” to read, 

“best technological system.” The 1990 CAAA deleted 

“technological,” and thereby returned the phrase to how it read 

under the 1970 CAAA. The Sierra Club v. Costle’s interpretation 

of this phrase to require consideration of the amount of air 

emissions remains valid for the phrase “best system.”

147 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 27 

(citing “Summary of the Provisions of Conference Agreement on 

the Clean Air Amendments of 1970,” 116 Cong. Rec. 42384, 42385 

(1970)).
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account for revenue generated from the byproducts of pollution 

control, it is logical and a reasonable interpretation of the 

statute that any expected revenues from the sale of pollutants 

or pollution control byproducts associated with those controls 

may be considered when determining the overall costs of 

implementation of the control technology. Clearly, such a sale 

would offset regulatory costs and so must be included to 

accurately assess the costs of the standard.

a. Criteria for costs

(i) Formulation

In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433 

(D.C. Cir. 1973), the D.C. Circuit stated that to be “adequately 

demonstrated,” the system must be “reasonably reliable, 

reasonably efficient, and ... reasonably expected to serve the

interests of pollution control without becoming exorbitantly 

costly in an economic or environmental way.” The Court has 

reiterated this limit in subsequent case law, including Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999), in 

which it stated: “EPA's choice will be sustained unless the 

environmental or economic costs of using the technology are 

exorbitant.” In Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 

(D.C. Cir. 1975), the Court elaborated by explaining that the 

inquiry is whether the costs of the standard are “greater than 
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the industry could bear and survive.”148

In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 

1981), the Court provided a substantially similar formulation of 

the cost standard when it held: “EPA concluded that the Electric 

Utilities' forecasted cost was not excessive and did not make 

the cost of compliance with the standard unreasonable. This is a 

judgment call with which we are not inclined to quarrel.” We 

believe that these various formulations of the cost standard –

“exorbitant,” “greater than the industry could bear and 

survive,” “excessive,” and “unreasonable” – are synonymous; the 

D.C. Circuit has made no attempt to distinguish among them. For 

 

148 The 1977 House Committee Report noted:

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business.

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated:

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.

S. Comm. Rep. No. 91-1196 at 16.
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convenience, in this rulemaking, we will use the “unreasonable” 

formulation, so that a control technology cannot be considered 

the “best system of emission reduction ... adequately 

demonstrated” if its costs are “unreasonable.” 

(ii) Examples

In the case law under CAA § 111, the D.C. Circuit has never 

invalidated a standard of performance on grounds that it was too 

costly. In several cases, the Court upheld standards that 

entailed high costs. In Portland Cement Association v. 

Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the Court considered 

a standard of performance that the EPA promulgated for 

particulate matter emissions from new and modified Portland 

cement plants. According to the Court, the cost for the control 

technologies that a new facility would need to install to meet 

the standard was about 12 percent of the capital investment for 

the total facility, and annual operating costs for the control 

equipment would be 5-7 percent of the total plant operating 

costs. The Court found that these costs “could be passed on 

without substantially affecting competition” because the demand 

for the product was not “highly elastic with regard to price and 

would not be very sensitive to small price changes.” The Court 

held that the EPA gave appropriate consideration to the 
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“economic costs to the industry.”149

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

the D.C. Circuit upheld a standard of performance imposing 

costly controls on SO2 emissions from coal-fired power plants. 

The Court noted:

The importance of the challenged standards arises 

not only from the magnitude of the environmental and 

health interests involved, but also from the critical 

implications the new pollution controls have for the 

economy at the local and national levels.

 

Coal is the dominant fuel used for generating 

electricity in the United States .... In 1976 power 

plant emissions accounted for 64 percent of the total 

estimated sulfur dioxide emissions and 24 percent of 

the total estimated particulate matter emissions in 

the entire country.

EPA's revised NSPS are designed to curtail these 

emissions. EPA predicts that the new standards would 

reduce national sulfur dioxide emissions from new 

plants by 50 percent and national particulate matter 

emissions by 70 percent by 1995. The cost of the new 

controls, however, is substantial. EPA estimates that 

utilities will have to spend tens of billions of 

dollars by 1995 on pollution control under the new 

NSPS. Consumers will ultimately bear these costs, both 

directly in the form of residential utility bills, and 

indirectly in the form of higher consumer prices due 

to increased energy costs.150

b. Revenue enhancements

In determining the costs of pollution control technology, 

it is reasonable to take into account any revenues generated by 

 

149 Portland Cement Association v. Ruckelshaus, 486 F.2d at 387-

88.

150 Sierra Club v. Costle, 657 F.2d at 313 (citations omitted) 

(emphasis added).
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the sale of any by-products of the control process. Many types 

of pollution control technology generate byproducts that must be 

disposed, and the costs of that disposal are considered part of 

the costs of the control technology. For example, CCS generates 

a stream of CO2 that must be disposed of through sequestration.

In some instances, however, the by-products of pollution 

control have marketable value. In these cases, revenues from 

selling the by-products would defray the costs of pollution 

control. For example, in a recent rulemaking under the CAA 

regional haze program that entailed determining the “best 

available retrofit technology” (BART) for power plants, revenue 

from fly ash generated during boiler combustion and sold for use 

in concrete production factored into the State’s selection of 

BART).151

3. Expanded use and development of technology

In Sierra Club v. Costle, the Court made clear that 

technological innovation was grounded in the terms of section 

111 itself, and therefore should be considered one of the 

factors to be considered in determining the “best system of 

 

151 Similarly, the EPA has taken into account the value of fuel 

savings in determining the costs of rules that limit emissions 

from motor vehicles, which limits manufacturers are expected to 

achieve by reducing the rates of fuel consumption by the 

vehicles. See, e.g., 77 Fed. Reg. 62,624, 62,628-29; 62,923-27; 

62,942-46 (October 15, 2012) (rulemaking setting GHG emissions 

standards for Light-Duty Vehicles for Model Years 2017-2025). 
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emission reduction:”

Our interpretation of section 111(a) is that the 

mandated balancing of cost, energy, and nonair quality 

health and environmental factors embraces 

consideration of technological innovation as part of 

that balance. The statutory factors which EPA must 

weigh are broadly defined and include within their 

ambit subfactors such as technological innovation.152

The Court’s interpretation finds firm grounding in the 

legislative history. For example, the 1970 Senate Committee 

Report stated: 

Standards of performance should provide an 

incentive for industries to work toward constant 

improvement in techniques for preventing and 

controlling emissions from stationary sources, since 

more effective emission control will provide greater 

latitude in the selection of sites for new 

facilities.153

Similarly, the 1977 Senate Committee Report stated:

In passing the Clean Air Amendments of 1970, the 

Congress for the first time imposed a requirement for 

 

152 Sierra Club v. Costle, 657 F.2d at 347.

153 S.Rep. 91-1196 at 16 (1970). The technology-forcing nature of 

§111 is consistent with the technology-forcing nature of the 

1970 CAAA as a whole. The principal Senate author of the 1970 

CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor debate, 

described the overall requirements of the 1970 CAAA and then 

observed: 

These five sets of requirements will be difficult 

to meet. But the committee is convinced that industry 

can make compliance with them possible or impossible. 

It is completely within their control. Industry has 

been presented with challenges in the past that seemed 

impossible to meet, but has been made possible.

116 Cong. Rec. 32902 (Sept. 21, 1970) (statement of Sen. 

Muskie).
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specified levels of control technology. The section 

111 Standards of Performance for New Stationary 

Sources required the use of the “best system of 

emission reduction which (taking into account the cost 

of achieving such reduction) the Administrator 

determines has been adequately demonstrated.” This 

requirement sought to assure the use of available 

technology and to stimulate the development of new 

technology.154

The legislative history just quoted identifies three 

different ways that Congress designed section 111 to authorize 

standards of performance that promote technological improvement: 

(i) the development of technology that may be treated as the 

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

under section 111(a)(1)155; (ii) the expanded use of the best 

demonstrated technology;156 and (iii) the development of emerging 

 

154 S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. Costle, 

657 F.2d at 346 n. 174. The 1977 CAAA legislative history is 

replete with other references to the technology forcing nature 

of §111 or the CAAA as a whole. See “1977 Clean Air Act 

Conference Report: Statement of Intent; Clarification of Select 

Provisions,” 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club 

v. Costle, 657 F.2d at 346 n. 174) (one of the enumerated 

purposes of section 111 was to “create incentives for new 

technology”); 123 Cong. Reg. 16195 (May 24, 1977) (statement of 

Rep. Meads) (”The main purposes of the Clean Air Act Amendments 

of 1977 are as follows: ... tenth, to promote the utilization of 

new technologies for pollution choice”).

155 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”).

156 See 1970 Senate Committee Report No. 91-1196 at 15 (“The 

maximum use of available means of preventing and 

controlling air pollution is essential to the elimination 

of new pollution problems”). 
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technology.157

E. Nationwide component of factors in determining the “best 

system”

Another component of the D.C. Circuit’s interpretations of 

section 111 is that the EPA may consider the various factors it 

is required to balance on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.158 As the D.C. Circuit stated in Sierra Club v. 

Costle:

The language of [the definition of ‘standard of 

performance’ in] section 111 ... gives EPA authority 

when determining the best ... system to weigh cost, 

energy, and environmental impacts in the broadest 

sense at the national and regional levels and over 

time as opposed to simply at the plant level in the 

immediate present.159

In that case, in upholding the EPA’s variable standard for 

SO2 emissions, the D.C. Circuit justified and elaborated on that 

interpretation of the definition of “standard of performance” 

and then went on to evaluate the EPA’s justification for its 

rulemaking in light of that interpretation. It is useful to set 

out these parts of the Court’s opinion at some length in order 

to make clear the scope of the factors and the nature of the 

 

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

standard of performance designed to promote the use of an 

emerging technology).

158 Sierra Club v. Costle, 657 F.2d at 351.

159 Sierra Club v. Costle, 657 F.2d at 330.
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balancing exercise that the Court held section 111(a)(1) 

authorizes the EPA to take.

The Court first recited the terms of the definition of 

“standard of performance,” as it read following the 1977 CAA 

Amendments:

The pertinent portion of section 111 reads:

A standard of performance shall reflect the 

degree of emission limitation ... achievable through 

application of the best ... system of ... emission 

reduction which (taking into consideration the cost of 

achieving such emission reduction, any nonair quality 

health and environmental impact and energy 

requirements) the Administrator determines has been 

adequately demonstrated.160

The Court then stated that these terms could reasonably be 

read to authorize the EPA to establish the standard of 

performance based on environmental, economic, and energy 

considerations “on the grand scale:” 

Parsed, section 111 most reasonably seems to 

require that EPA identify the emission levels that are 

“achievable” with “adequately demonstrated 

technology.” After EPA makes this determination, it 

must exercise its discretion to choose an achievable 

emission level which represents the best balance of 

economic, environmental, and energy considerations. It 

 

160 Sierra Club v. Costle, 657 F.2d at 330. Note that the elipses 

in the quotation of the definition of “standard of performance” 

in the text indicate the omission of terms repealed by the 1990 

CAAA. The Court’s analysis of the meaning of this definition did 

not turn on those repealed terms, and as a result, the Court’s 

analysis remains relevant for the current definition of 

“standard of performance.”
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follows that to exercise this discretion EPA must 

examine the effects of technology on the grand scale 

in order to decide which level of control is best. For 

example, an efficient water intensive technology 

capable of 95 percent removal efficiency might be 

“best” in the East where water is plentiful, but 

environmentally disastrous in the water-scarce West 

where a different technology, capable of only 80 

percent reduction efficiency might be “best.” ... The 

standard is, after all, a national standard with longterm effects.161

The Court then justified its “reading of ... section 111 as 

authorizing the EPA to balance long-term national and regional 

impacts of alternative standards” on the 1977 CAAA legislative 

history:

The Conferees defined the best technology in 

terms of “long-term growth,” “long-term cost savings,” 

effects on the “coal market,” including prices and 

utilization of coal reserves, and “incentives for 

improved technology.” Indeed, the Reports from both 

Houses on the Senate and House bills illustrate very 

clearly that Congress itself was using a long-term 

lens with a broad focus on future costs, environmental 

and energy effects of different technological systems 

when it discussed section 111.162

The Court then examined the EPA’s justification for the 

 

161 Sierra Club v. Costle, 657 F.2d at 330 (emphasis added). As 

noted, after the 1990 CAAA -- which changed the term “best 

technological system ... of emission reduction ... adequately 

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

adequately demonstrated” -- the Court’s discussion of 

“adequately demonstrated technology” should be considered to 

hold true for adequately demonstrated system of emission 

reduction.

162 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).
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variable standard, and held that the justification was 

reasonable.

163 The Court quoted at length the EPA’s discussion of 

how it “justified the variable standard in terms of the policies 

of the Act,” including balancing long-term national and regional 

impacts, in part:

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

and industrial sources.

By substantially reducing SO2 emissions, the 

standard will enhance the potential for long term 

economic growth at both the national and regional 

levels. 164

The D.C. Circuit then held that it found this explanation to be 

reasonable.165 

F. Chevron framework

Above, we discuss how in Sierra Club v. Costle the D.C. 

Circuit interpreted the definition of “standard of performance” 

in CAA § 111(a)(1), among other things, to authorize the EPA to 

balance economic, environmental, or energy factors through a 

 

163 Sierra Club v. Costle, 657 F.2d at 337-39.

164 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg. at 33,583/3 - 33,584/1).

165 Sierra Club v. Costle, 657 F.2d at 337-39. 

Comment [A28]: Elaborate this sentence or add 

another sentence to summarize the point you are 

trying to make here, which seems to be about EPA 

balancing factors on a national or regional level and 

over time (as opposed to about the fact that EPA 

selected a variable standard). The conclusion needs 

to be more robust to keep the reader oriented.

EPA: Edits were made.
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nationwide lens, and to encompass technology forcing. The D.C. 

Circuit handed down this decision in 1981, and therefore it did 

not employ the two-step framework for statutory construction in 

federal rulemaking that the U.S. Supreme Court mandated in 1984, 

in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837 (1984). However, 

the D.C. Circuit’s interpretations are fully consistent with the 

Chevron framework.

In Chevron, the Supreme Court held that an agency must, at 

Step 1, determine whether Congress’s intent as to the specific 

matter at issue is clear, and, if so, the agency must give 

effect to that intent. If congressional intent is not clear, 

then, at Step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of the 

statute.166

As noted, under CAA section 111(a)(1), a standard of 

performance must be based on 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) ... has been adequately demonstrated.” 

The terms “best system of emission reduction,” “cost,” and 

“energy requirements,” on their face, can be interpreted to 

apply on a regionwide or nationwide basis, and are not limited 

 

166 Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984).
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to the individual source. Thus, this interpretation is 

supportable under Chevron step 1, but even if not, then the EPA 

considers the interpretation supportable under step 2 because it 

is reasonable and consistent with the purposes of the CAA. 

Similarly, the technology-development interpretation is 

supportable under Chevron step 1 because encouraging the 

utilization or development of improved technology is a logical 

consideration in determining the “best system of emission 

reduction” and, as noted, was clearly a focus of the legislative 

history. Even if that interpretation is not supportable under 

Chevron step 1, however, then the EPA considers the 

interpretation supportable under step 2 because it is reasonable 

and consistent with the purposes of the CAA.

G. Agency discretion 

The D.C. Circuit has made clear that the EPA has broad 

discretion in determining the appropriate standard of 

performance under the definition in CAA § 111(a)(1), quoted 

above. Specifically, in Sierra Club v. Costle, 657 F.2d 298 

(D.C. Cir. 1981), the Court explained that “section 111(a) 

explicitly instructs the EPA to balance multiple concerns when 

promulgating a NSPS,”167 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

 

167 Sierra Club v. Costle, 657 F.2d at 319. 
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the standard.”168 In Lignite Energy Council v. EPA, 198 F.3d 930 

(D.C. Cir. 1999), the Court reiterated:

Because section 111 does not set forth the weight 

that should be assigned to each of these factors, we 

have granted the agency a great degree of discretion 

in balancing them.... EPA's choice [of the ‘best 

system’] will be sustained unless the environmental or 

economic costs of using the technology are 

exorbitant.... EPA [has] considerable discretion under 

section 111.169

The important point is that Courts acknowledge that there 

are several factors to be considered and what is “best” depends 

on how much weight to give the factors. In promulgating certain 

standards of performance, EPA may give greater weight to 

particular factors than it may do so in promulgating other 

standards of performance. Thus, the determination of what is 

“best” is complex and necessarily requires an exercise of 

judgment. By analogy, the question of who is the “best” sprinter 

in the 100-meter dash primarily depends on only one criterion –

speed – and therefore is relatively straightforward, while the 

question of who is the “best” baseball player depends on a more 

complex weighing of several criteria and therefore requires a 

greater exercise of judgment. 

H. Lack of requirement that standard be able to be met by all 

 

168 Sierra Club v. Costle, 657 F.2d at 321.

169 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience).

Comment [A29]: Suggest this is not necessary.

EPA: We believe that the sentence helps to 

crystallize the point and make it more persuasive.
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sources

Under CAA § 111, an emissions standard may meet the 

requirements of a “standard of performance” even if it cannot be 

met by every new source in the source category that would have 

constructed in the absence of that standard. As discussed below, 

this is clear in light of (i) the legislative history of CAA §

111, read in conjunction with the legislative history of the CAA 

as a whole; (ii) case law under analogous CAA provisions; and 

(iii) long-standing precedent in the EPA rulemakings under CAA §

111.1.

1. Legislative history

As noted, Congress, in enacting section 111 in the 1970 

CAAA, intended that the EPA promulgate uniform, nationwide 

controls. Congress was explicit that this meant that large 

industrial sources, including electric generating power plants, 

would be required to implement controls meeting the requirements 

regardless of their location. According to the 1970 Senate 

Committee Report:

Major new facilities such as electric generating 

plants, kraft pulp mills, petroleum refineries, steel 

mills, primary smelting plants, and various other 

commercial and industrial operations must be 

controlled to the maximum practicable degree 

regardless of their location and industrial 
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operations....170

Congress’s purposes in designing a standard that called for 

uniform national controls were to prevent pollution havens –

caused by some states seeking competitive advantage by limiting 

their pollution control requirements – and to assure that areas 

that had good air quality would be able to maintain good air 

quality even after new industrial sources located there, which, 

in turn, would allow more sources to locate there as well.171

At the same time, Congress recognized that in light of the 

attainment provisions of the CAAA of 1970, sources –

particularly large industrial sources, again, including electric 

generating plants -- may not be able to construct new facilities 

anywhere in the country; that is, an area with air quality at or 

above the NAAQS limits might not have enough room in its airshed 

to accommodate these new facilities. The 1970 Senate Committee 

Report stated, “[l]and use policies must be developed to prevent 

location of facilities which are not compatible with 

implementation of national standards.”172 Senator Muskie added:

Land use planning and control should be used by State, 

local, and regional agencies as a method of minimizing 

 

170 S. Rep. 91-1116 at 16 (1970). See 116 Cong. Rec. 42,384 

(statement of Sen. Muskie) (summarizing the House-Senate 

Conference agreement). )

171 See S. Rep. 91-1196 at 16 (1970).

172 1970 Senate Commitee Report at 2.
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air pollution. Large industries and power generating 

facilities should be located in places where their 

adverse effect on the air is minimal. There is a need 

for State or regional agencies to revise proposed 

power plant sites to assure that a number of 

environmental values, including air pollution, are 

considered.173

The 1970 CAAA legislative history includes other statements that 

also recognize that under the newly required air pollution 

control requirements, new sources may not be able to build 

anywhere in the country and, in fact, some existing sources 

might have to be shut down.174

Thus, in 1970, Congress designed section 111 to require 

uniform national controls for large industrial facilities, while 

recognizing that those facilities could not necessarily 

construct in every place in the country. Although at the time, 

Congress expected that the reason why some sources would not be 

able to locate in certain places was related to local air 

quality concerns, if the reason turns out to be related to the 

emission limits that the EPA promulgates under section 111, that 

should not be viewed as inconsistent with congressional intent 

for section 111. For example, if the EPA promulgates section 111 

emission limits based on a particular type of technology, and 

 

173 116 Cong. Rec. 32,917 (1970) (statement of Sen. Muskie).

174 _See 116 Cong. Rec. 42,385 (Dec. 18, 1970) (statement of Sen. 

Muskie) (sources of hazardous air pollutants could be required 

to close due to absence of control techniques).
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for economic or technical reasons, sources are able to utilize 

that technology in only certain parts of the country and not 

other parts, that result should not be viewed as inconsistent 

with congressional intent for CAA section 111. Rather, that 

result is consistent with Congress’s recognition that certain 

sources may be precluded from locating in certain areas.

2. Case law under analogous CAA provisions

Under analogous CAA provisions, the D.C. Circuit has 

recognized that the EPA may promulgate uniform standards that 

apply to new sources in a group or category of sources, even 

though some types of those new sources that would otherwise 

construct would no longer be able to construct because they 

could not meet the standard. One of these cases was 

International Harvester Co. v. EPA, 478 F.2d 615 (D.C. Cir. 

1973). There, the EPA declined to exercise its discretion under 

the CAA mobile source provisions, as they read at that time (42 

USC 1857f-1(b)(5)(D) (1970 CAAA)), to grant automakers a oneyear extension to comply with exhaust standards. The EPA stated 

that the automakers had failed to meet their burden of 

establishing that controls were not available. The EPA based its 

decision on grounds that certain technology was available for 

the motor vehicles in question. The EPA dismissed the 

automakers’ objections that this technology could not feasibly 
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be installed in all models or engine types, and the EPA 

explained that the public’s “basic demand” for automobiles could 

be met by the models and engine types that could feasibly 

install that technology. 478 F.2d at 626.

Although the Court remanded the EPA’s decision not to grant 

the one-year extension, it agreed with the EPA on this point, 

stating:

We are inclined to agree with the Administrator 

that as long as feasible technology permits the demand 

for new passenger automobiles to be generally met, the 

basic requirements of the Act would be satisfied, even 

though this might occasion fewer models and a more 

limited choice of engine types. The driving 

preferences of hot rodders are not to outweigh the 

goal of a clean environment.175

Similarly, in a 2007 decision under CAA § 112, NRDC v. EPA, 

489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circuit upheld the 

EPA’s decision to apply the same hazardous air pollutant 

requirements to different types of plywood and composite wood 

products facilities – even though one of those types of 

facilities faced greater difficulties meeting the requirements 

than the other types of facilities – in part on the grounds that 

the facilities “compet[ed] in the same markets.”176

Thus, these decisions supported EPA’s emissions 

 

175 International Harvester Co. v. EPA, 478 F.2d at 640.

176 NRDC v. EPA, 489 F.3d at 1376.

Comment [A30]: This is helpful – is there any 

further elaboration that could be made on this point, 

particularly to connect this with the electricity 

market?

EPA: Text has been added.
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requirements, even though certain types of sources could meet 

those requirements more readily than others, on grounds that the 

requirements would not impede the manufacture of products that 

would satisfy overall consumer demand. By the same token, the 

inability of some coal-fired sources to locate in certain areas 

would not create reliability problems or prevent the 

satisfaction of overall demand for electricity.

3. Section 111 rulemaking precedent

Through long-standing rulemaking precedent, the EPA has 

taken the position that section 111 authorizes a standard of 

performance for a source category that may not be feasible for 

all types of new sources in the category, as long as there are 

other types of sources in the category that can serve the same 

function and meet the standard. Specifically, in a 1976 

rulemaking under section 111 covering primary copper, zinc, and 

lead smelters, the EPA established, as the standard of 

performance, a single standard for SO2 emissions for new 

construction or modifications of reverberatory, flash, and 

electric smelting furnaces in primary copper smelters that 

process materials with low levels of volatile impurities. The 

EPA acknowledged that although for flash and electric smelting 

furnaces, the cost of the controls was “reasonable,” for 

reverberatory smelting furnaces, the cost of the standard was 
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“unreasonable in most cases.” Even so, the EPA determined that 

this standard would not adversely affect new construction or 

modification of primary copper smelters processing materials 

containing low levels of volatile impurities because new 

construction could use flash and electric smelting furnaces, and 

existing sources could expand without increasing emissions.177

The EPA explained:

[T]he Agency believes that section 111 authorizes 

the promulgation of one standard applicable to all 

processes used by a class of sources, in order that 

the standard may reflect the maximum feasible control 

for that class. When the application of a standard to 

a given process would effectively ban the process, 

however, a separate standard must be prescribed for it 

unless some other process(es) is available to perform 

the function at reasonable cost....

The Administrator has determined that the flash 

copper smelting process is available and will perform 

the function of the reverberatory copper smelting 

process at reasonable cost....178

VII. Rationale for Emission Standards for New Fossil Fuel-fired 

Boilers and IGCCs

A. Overview 

In this section we explain our rationale for emission 

standards concluding that partial implementation of CCS is the 

BSER adequately demonstrated for new fossil fuel-fired boiler 

 

177 Standards of Performance for New Stationary Sources, Primary 

Copper, Zinc, and Lead Smelters, 41 FR 2331, 2333 (Jan. 15, 

1976).

178 41 FR at 2333.
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and IGCC EGUs by concluding that partial implementation of CCS 

is the BSER adequately demonstrated for those sources. 

As noted, CAA § 111 and subsequent court decisions 

establish a set of factors for the EPA to consider in a BSER 

determination, including criteria listed in CAA § 111 or 

identified in the court decisions and the underlying purposes of 

§ 111. Key factors include: emission reductions, technical 

feasibility, costs, and encouragement of technology. Other

factors, such as energy impacts, may also be important. As also 

noted, the EPA has discretion in balancing those factors, and 

may balance them differently in promulgating standards for 

different source categories.

The EPA considered three alternative control technology 

configurations as potentially representing the BSER for new 

fossil fuel-fired boilers and IGCC units. Power company 

announcements indicate that the few new coal-fired projects that 

may occur will likely consider one or more of these three 

configurations. The three alternatives are: (1) highly efficient 

new generation technology that does not include any level of 

CCS, (2) new generation technology with “full capture” CCS (that 

is, CCS with capture of at least 90 percent CO2 emissions) and 

(3) new generation technology with “partial capture” CCS (that 

is, CCS with capture of a lower level of CO2 emissions). 

Comment [A31]: Should this reference standards 

of performance instead of BSER? Or, both?

EPA: This has been edited.
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We discuss each of these alternatives below, and explain 

why we propose that partial capture CCS qualifies as the BSER. 

We first discuss the technical systems that we considered for 

the BSER, our evaluations of them, and our reasons for 

determining that only partial CCS meets the criteria to qualify 

as the BSER. We include in this discussion our rationale for 

selecting 1,100 lb CO2/MWh as the emission limitation for these 

sources and why we are considering a range from 1,000 to 1,200 

lb CO2/MWh for the final rule. We next discuss our rationale for 

allowing an 60-operating84-operating-month averaging period as 

an alternative compliance method, with the requirement that 

sources choosing that method meet a limit of between 1,000 lb 

CO2/MWh and 1,050 lb CO2/MWh.179 We then explain our rationale for 

the requirements for geologic sequestration.180

B. Identification of the best system of emission reduction

 

179 This is on a gross output basis. All emission rates in this 

section are on a gross output basis unless specifically noted 

otherwise.

180 It should be noted that the standard of performance that we 

propose in this rulemaking for new fossil-fired utility steamgenerating units of 1,100 lb CO2/MWh applies to new oil- and 

natural-gas fired units, as well as solid-fuel fired units. 

However, we are not conducting a separate analysis of the best 

system of emission reduction for new oil- and natural-gas fired 

units. That is because no new utility steam-generating units 

designed to be fired primarily with oil or natural gas have been 

built for many years, and none are expected to be built in the 

foreseeable future, due to the significantly lower costs of 

building combustion turbines to be fired with those fuels.
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1. Highly efficient new generation without CCS technology

Some commenters on the April 2012 proposal suggested that 

the emission limitation for new coal-fired EGUs should be based 

on the performance of highly efficient generation technology 

that does not include CCS, such as (i) a supercritical181

pulverized coal (SCPC) or CFB boiler, or (ii) a modern, wellperforming IGCC unit.

These options are technically feasible. However, we do not 

consider them to qualify as the BSER for the following reasons: 

a. Lack of significant CO2 reductions

Because of the large amount of CO2 emissions from solid-fuel 

fired power plants, it is important, in promulgating a standard 

of performance for these sources, to give effect to the purpose 

of CAA § 111 of providing “as much [emission reduction] as 

practicable.”

182 Accordingly, we reviewed the emission rates of 

efficient PC and CFB units. According to the DOE/NETL estimates, 

a new subcritical PC unit firing bituminous coal would emit 

 

181 Subcritical coal-fired boilers are designed and operated with 

a steam cycle below the critical point of water. Supercritical 

coal-fired boilers are designed and operated with a steam cycle 

above the critical point of water. Increasing the steam pressure 

and temperature increases the amount of energy within the steam, 

so that more energy can be extracted by the steam turbine, which 

in turn leads to increased efficiency and lower emissions.

182 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 –

33,582/1).
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approximately 1,800 lb CO2/MWh,183 a new SCPC unit using 

bituminous coal would emit nearly 1,700 lb CO2/MWh, and a new 

IGCC unit184 would emit about 1,450 lb CO2/MWh.185

New power sector projects using coal as a primary fuel that 

have been proposed or are currently under construction are 

generally SCPC or IGCC projects. For example, since 2007, almost 

all coal-fueledcoal-fired EGUs that have broken ground have been 

high performing versions of SCPC or IGCC projects.186 Among those 

plants are: (1) AEP’s John W. Turk, Jr. Power Plant, a 600 MW 

ultra-supercritical187 PC (USCPC) facility located in the 

southwest corner of Arkansas; (2) Duke Power’s Edwardsport 

plant, a 618 MW coal IGCC unit located in Knox County, Indiana; 

and (3) Southern Company’s Kemper County Energy Facility, a 582 

MW lignite IGCC unit located in Kemper County, Mississippi. 

 

183 Exhibit ES-2 from “Cost and Performance Baseline for Fossil 

Energy Plants Volume 1: Bituminous Coal and Natural Gas to 

Electricity”, Revision 2, Report DOE/NETL-2010/1397 (November 

2010).

184 “Case 1” from Exhibit ES-2 from “Cost and Performance 

Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and 

Natural Gas to Electricity”, Revision 2, Report DOE/NETL2010/1397 (November 2010).

185 The comparable emissions on a net basis are: subcritical PC –

1,888 lb CO2/MWh; supercritical PC – 1,768 lb CO2/MWh; and IGCC –

1,723 lb CO2/MWh.

186 The only exception that we are aware of is the Virginia City 

subcritical CFB unit.

187 Ultra-supercritical (USC) and advanced ultra-supercritical 

(A-USC) are terms often used to designate a coal-fired power 

plant design with steam conditions well above the critical 

point.

Comment [A32]: What are the CO2 emissions of 

the subcritical CFB? The FN contains only minimal 

discussion; should elaborate.

EPA: We are considering this suggestion.
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These facilities all use advanced generation technology: Turk, 

as noted, is an ultra-supercritical boiler; Edwardsport is an 

IGCC unit that is “CCS ready;” and Kemper is an IGCC unit that 

will implement partial CCS.

Under these circumstances, in this rule, identifying a new 

supercritical unit as the BSER and requiring the associated 

emission limitation, would provide little meaningful CO2 emission 

reductions for this source category. As noted, for the most 

part, new sources are already designed to achieve at least that 

emission limitation. Identifying IGCC as the BSER and requiring 

the associated emission limitation, would provide some CO2

emission reductions from the segment of the industry that would 

otherwise construct new PC units, but not from the segment of 

the industry that would already construct new IGCC units. 

As a result, emission reductions in the amount that would 

result from an emission standard based on SCPC/USCPC or even 

IGCC as the BSER would not be consistent with the purpose of CAA 

§ 111 to achieve “as much [emission reduction] as 

practicable.”188 As we discuss below, identifying CCS-partial 

capture as the BSER would provide for significantly greater 

emissions reductions.

 

188 Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR at 33,581/3 –

33,582/1).
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b. Lack of incentive for technological innovation

Identifying highly efficient generation technology as the 

BSER would not achieve another purpose of CAA § 111, to 

encourage the development and implementation of control 

technology. At present, CCS technologies are the most promising 

options to achieve significant reductions in CO2 emissions from 

fossil-fuel fired utility boilers and IGCC units. A standard 

based on the performance of highly efficient coal-fired 

generation does not advance the development and implementation 

of control technologies that reduce CO2 emissions. FurtherIn 

addition, highly efficient generation technology does not 

develop control technology that is transferrable to existing 

EGUs. Further, highly efficient generation technology does not 

necessarily promote the development of generation technologies 

that would minimize the auxiliary load requirements and costs of 

future CCS requirements (e.g., developing an IGCC design where 

the costs and auxiliary load requirements of adding CCS are 

minimized).

On the contrary, such a standard could impede the 

advancement of CCS technology by creating regulatory 

disincentives for such technology. In 2011, AEP deferred 

construction of a large-scale CCS retrofit demonstration project 

on one of their coal-fired power plants because the state’s 
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utility regulators would not approve cost recovery for CCS 

investments without a regulatory requirement to reduce CO2

emissions. AEP’s chairman was explicit on this point, stating in 

a July 17, 2011 press release announcing the deferral:

We are placing the project on hold until economic 

and policy conditions create a viable path forward ... 

We are clearly in a classic ‘which comes first?’ 

situation. The commercialization of this technology is 

vital if owners of coal-fueled generation are to 

comply with potential future climate regulations 

without prematurely retiring efficient, cost-effective 

generating capacity. But as a regulated utility, it is 

impossible to gain regulatory approval to recover our 

share of the costs for validating and deploying the 

technology without federal requirements to reduce 

greenhouse gas emissions already in place. The 

uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.

189

As we discuss below, regulatory requirements for CO2

reductions with some level of CCS as the BSER will promote 

further development of the technology.

2. Carbon capture and storage

We have also considered whether the emission limitation for 

new coal-fired EGUs should be based on the performance of CCS, 

including either “full capture” CCS that treats the entire flue 

gas or syngas stream to achieve on the order of 90 percent 

reduction in CO2 emissions, or “partial capture” CCS that 

achieves some level less than 90 percent of capture. 

 

189 http://www.aep.com/newsroom/newsreleases/?id=1704
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We propose that implementation of partial capture CCS 

technology is the BSER for new fossil fuel-fired boilers and 

IGCC units because it fulfills the criteria established under 

CAA § 111. In the sections that follow, we explain the technical 

configurations that facilitate full and partial capture, 

describe the operational flexibilities that partial capture 

offers, and then identify and justify the emission rate that we 

propose based on partial capture. After that, we discuss the 

criteria for BSER, and describe why partial capture meets those 

criteria and why full capture does not. Among other things, 

partial capture provides meaningful emission reductions, it has 

been adequately demonstrated to be technically feasible, it can 

be implemented at a reasonable cost, and it promotes deployment 

and further development of the technology.

3. Technical configurations for CCS

The DOE’s National Energy Technology Laboratory (NETL) 

performed a study to establish the cost and performance for a 

range of CO2 capture levels for new SCPC and IGCC power plants.190

The study identified technical configurations that were tailored 

to achieve a specific level of carbon capture.

a. SCPC

 

190 “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011.
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For the new SCPC case, the study assumed a new SCPC boiler 

with a combination of low-NOx burners (LNB) with overfire air 

(OFA) and a selective catalytic reduction (SCR) system for NOx 

control. The plant was assumed to have a fabric filter and a wet 

limestone flue gas desulfurization (FGD) scrubber for 

particulate matter and sulfur dioxide (SO2) control, 

respectively. The plant was also assumed to have a sodium 

hydroxide (NaOH) polishing scrubber to ensure that the flue gas 

entering the CO2 capture system has a SO2 concentration of 10 

ppmv or less. The SCPC plant was equipped with Fluor’s Econamine 

FG PlusSM process for post-combustion CO2 capture via temperature 

swing absorption with a monoethanolamine (MEA) solution as the 

chemical solvent.

The study’s authors identified two options for achieving 

partial capture (i.e., less than 90 percent CO2 capture) in the 

SCPC unit. The first option was to process the entire flue gas 

stream through the MEA capture system at reduced solvent 

circulation rates. The second option was to maintain the same 

high solvent circulation rate and steam stripping requirement as 

would be used for full capture but only treat a portion of the 

total flue gas stream. The authors determined that the second 

approach – the “slip stream” approach - was the most economical. 

The authors further noted that the cost of CO2 capture with an 
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amine scrubbing process is dependent on the volume of gas being 

treated, and a reduction in flue gas flow rate will: (1) 

decrease the quantity of energy consumed by flue gas blowers, 

(2) reduce the size of the CO2 absorption columns, and (3) trim 

the cooling water requirement of the direct contact cooling 

system. The slip stream approach leads to lower capital and 

operating costs. All of the partial capture cases in the NETL 

study assumed this approach.

b. IGCC

For a new IGCC unit, the product syngas would contain 

primarily H2, CO and some lesser amount of CO2.

191 The amount of

CO2 can be increased by “shifting” the composition via the 

catalytic water-gas shift (WGS) reaction. This process involves 

the catalytic reaction of steam (“water”) with CO (“gas”) to 

form H2 and CO2. An emission standard that requires partial 

capture of CO2 from the syngas could be met by adjusting the 

level of CO2 in the syngas stream by controlling the level of 

syngas “shift” prior to treatment in the pre-combustion acid gas 

treatment system.

 

191 The amount of CO2 in un-shifted syngas depends upon the 

specific gasifier technology used, the operating conditions, and 

the fuel used; but is typically less than 20 volume percent 

(http://www.netl.doe.gov/technologies/coalpower/gasification/gas

ifipedia/4-gasifiers/4-3_syngas-table2.html).
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For a new IGCC EGU, the study’s authors assumed the use of 

the GE gasifier coupled with a variety of potential 

configurations (i.e., no WGS reactor, single-stage WGS, twostage WGS, varying WGS bypass ratios, and CO2 scrubber removal 

efficiency). The study evaluated a number of IGCC plant 

configurations. The first was an IGCC that used the SelexolTM 

process for acid gas control (i.e., hydrogen sulfide (H2S) and 

CO2) but no WGS reactor. This unit was capable of CO2 capture 

ranging from zero up to 25 percent. The no-CO2 capture case 

employed a one-stage SelexolTM unit for H2S control and the 25 

percent CO2 capture case utilized a two-stage SelexolTM unit to 

maximize CO2 capture from the unshifted syngas (i.e., >90 percent 

of the CO2 from the unshifted syngas was captured in the second 

stage SelexolTM scrubber). 

To achieve moderate levels of partial CO2 capture –

approximately 25 to 75 percent - the IGCC was configured with a 

single-stage WGS reactor with bypass and a two-stage SelexolTM 

unit. Varying the extent of the WGS reaction by controlling the 

amount of syngas that was processed through the WGS reactor (by 

controlling the amount that bypassed the WGS reactor) 

manipulated the level of CO2 capture. As more syngas is processed 

through the WGS reactor, the steam demand increases. The 

SelexolTM removal efficiency was manipulated by varying the 
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solvent circulation rate. Thus, a facility using this 

configuration could select or “dial in” a level of control of 

between 25 – 75 percent.

To achieve higher CO2 capture levels – levels greater than 

75 percent - the IGCC was configured with a two-stage WGS with 

bypass and the two-stage acid gas (SelexolTM) scrubbing system. 

The facility could “dial in” a level of control of between 25 to 

greater than 90 percent by controlling the WGS bypass and the 

SelexolTM scrubber recirculation rates.

The water-gas shift involves the catalytic reaction of 

carbon monoxide and steam. Since the syngas initially contains 

primarily CO and H2, this shift reaction diminishes the 

concentration of CO and enriches the concentration of H2 in the 

pre-combustion syngas stream via the following reaction:

CO + H2O CO2 + H2

An unshifted or partially shifted syngas can be combusted 

using a typical combustion turbine. However, as the level of H2

in the syngas increases, the more the syngas must be diluted 

with N2 or air. Very high levels of H2 in the syngas stream 

require use of a specialty hydrogen turbine.

4. Operational and design flexibility

To this point, most of the studies involving research, 

development and demonstration of carbon capture technology, 
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along with most of the studies that have modeled the costs and 

implementation of such technology have assumed capture 

requirements of 90 percent for fossil fuel-fired power plants 

(“full capture”). However, the EPA believes that partial capture 

provides significant benefits because an emission limit based on 

partial capture offers operators considerable operational 

flexibility. With such emission limits, project developers would 

have the option of designing and installing CO2 capture 

technology at a size sufficient to treat the entire flue gas 

stream, with the capability to meet CO2 emission limits that are 

much lower than required. The operator of the plant could then 

choose to achieve those deeper capture rates during non-peak 

electricity demand periods and to achieve lesser capture rates 

(and thus generate more electricity) during peak electricity 

demand periods. This type of operational flexibility provides 

owners and operators the opportunity to optimize the operation 

and minimize the cost of CCS in new fossil fuel-fired projects.

In addition, an emission standard that can be met with 

partial capture offers the opportunity for design flexibility. A 

project developer of a new conventional coal-fired plant (i.e., 

a new supercritical PC or CFB) could install post-combustion CO2

scrubbers that have been designed and sized to treat only a 

portion of the flue gas stream.
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For a new IGCC unit, as noted, an emission standard that 

requires partial capture of CO2 offers operational flexibility 

because the standard could be met by adjusting the level of CO2

in the syngas stream by controlling the level of syngas “shift” 

prior to treatment in the pre-combustion acid gas treatment 

system. 

C. Determination of the level of the standard

Once the EPA has determined that a technology has been 

adequately demonstrated based on cost and other factors, 

including the impact a standard will have on further technology 

development, and therefore represents BSER, the EPA must 

establish an emission standard. In this case, for new fossil 

fuel-fired boiler and IGCC EGUs, the EPA proposes to find that

the level of partial capture of CO2 that qualifies as the BSER 

supports a standard of 1,100 lb CO2/MWh on a gross basis. The 

level of the standard is based on the emission reductions that 

can be achieved by an IGCC with a single-stage WGS reactor and a 

two-stage acid gas removal system. According to the DOE/NETL 

partial capture study, an IGCC with this configuration would be 

expected to achieve a CO2 emission reduction of 25 to 75 percent, 

which corresponds to emissions of approximately 1,060 and 380 lb 

CO2/MWh-gross, respectively. The EPA is proposing a standard of 
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performance of 1,100 lb CO2/MWh-gross, which is the high end of 

this range, for several reasons. 

First, both a new IGCC and a conventional coal-fired boiler 

(PC or CFB), can achieve this emission standard at a reasonable 

cost and the standard is based on technology that has been 

adequately demonstrated.

The partial capture requirement and standard of performance 

will allow new IGCC project developers to minimize the need for 

multi-stage water-gas shift reactors (and the associated steam 

requirement) and will allow for the continued use of 

conventional syngas combustion turbines (rather than requiring 

the use of advanced hydrogen turbines). Second, this partial 

capture configuration will provide operators with operational 

flexibility. Third, this level of the standard best promotes 

further enhancement of the performance of existing technology 

and promotes continued development of new, better performing 

technology. Because the proposed emission standard would require 

only partial implementation of CCS, it will provide developers 

with the opportunity to investigate new emerging technologies 

that may achieve deeper reductions at lower or comparable cost. 

For instance, developers could build plants with the capacity to 

achieve deeper CO2 reductions and choose to employ those greater 

capture rates during non-peak periods, and then employ lower 
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capture rates (and thus generate more electricity) during peak 

periods.

While the EPA is proposing an emission rate of 1,100 lb 

CO2/MWh, we are also soliciting comment on whether the emission 

limit may be more appropriately set at a different level. Based 

on the rationale included in this proposal, we are considering a

range of 1,000 to 1,200 lb CO2/MWh-gross for the final rule. An 

emission rate of 1,200 lb CO2/MWh-gross could potentially be met 

by an IGCC unit that does not include a WGS reactor (although an 

owner/operator might still use a WGS reactor or co-fire natural 

gas to maintain operational flexibility), thus further reducing 

the capital and operating costs. An emission limit of 1,000 lb 

CO2/MWh-gross would provide greater emission reductions, could 

still be achieved with a single WGS reactor, and would also 

advance CCS technology but would offer less operational 

flexibility and increase costs.

We are not currently considering a standard below 1,000 lb 

CO2/MWh. At an emissions rateWith a standard of 1,000 lb CO2/MWhgross or higher, an owner/operator of an IGCC facility could 

burn natural gas during periods when the gasifier is unavailable 

while still maintaining an annual emissions rate that is below 

the NSPS. In addition, an owner/operator could elect to co-fire 

natural gas as an option to reduce the amount of CCS required to 
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comply with the NSPS. With a standard below 1,000 lb CO2/MWh, 

those operational flexibilities may not be available. We request 

that commenters who suggest emission rates below 1,000 lb CO2/MWh 

address potential concerns about operational flexibility.

We are not currently considering a standard above 1,200 lb 

CO2/MWh because at that level, the NSPS would not necessarily 

promote the development of CO2 emissions control technology or 

provide significant CO2 reductions. At an emissions rate of 1,300 

lb CO2/MWh-gross, IGCC facilities would only be required to 

capture approximately 10 percent of the CO2, and many designs 

would have a sufficient compliance margin that they would not 

need to use a WGS reactor. Further, an owner/operator of an IGCC 

facility could comply with this standard without the use of any 

CCS. For example, aA new IGCG IGCC facility designed to co-fire 

20 percent natural gas or using fuel cells instead of combustion 

turbines could comply with an emissions rate of 1,300 lb CO2/MWhgross without the use of CCS. An emissions rate of 1,400 lb 

CO2/MWh-gross would provide even less technology development and 

emissions reductions. At an emissions rate of 1,400 lb CO2/MWhgross, an IGCC facility could comply with no WGS reactor and by 

(i) capturing less than 5% of the CO2, (ii) co-firing less ten 

percent natural gas with no CCS, or (iii) using integrated solar 

thermal for supplemental steam production without CCS. In 
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addition, at an emissions rate of 1,400 lb CO2/MWh-gross a PC or 

CFB could use integrated combustion turbines or fuel cells for 

boiler feedwater heating, supplemental steam production, or for 

preheated air for the boiler as an alternative to CCS. We 

request that commenters who suggest emission rates above 1,200 

lb CO2/MWh-gross address potential concerns about providing 

adequate reductions and technology development to be considered 

BSER.

The next several sections review the factors for 

determining BSER and explain why partial capture at the level we 

are proposing meets those requirements, as well as why full 

capture does not meet some of them.

D. Extent of reductions in CO2 emissions

The proposed standard of 1,100 lb CO2/MWh will provide 

meaningful reductions in emissions. As mentioned earlier, the 

DOE/NETL has estimated that a new SCPC boiler using bituminous 

coal would emit 1,675 lb CO2/MWh. The DOE/NETL has also estimated 

that a new IGCC unit would emit 1,434 lb CO2/MWh. The emissions 

would be higher for units utilizing subbituminous coal or 

lignite and will vary when utilizing other fossil fuels such as 

petroleum coke or mixtures of fuels. We estimate that this 

standard will result in reduction in emissions of at least 40 

percent when compared to the expected emissions of a new SCPC 
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boiler.

E. Technical feasibility

The EPA proposes to find that partial CCS is feasible 

because each step in the process has been demonstrated to be 

feasible through an extensive literature record, fossil fuelfired industrial plants currently in commercial operation and 

pilot-scale fossil fuel-fired EGUs currently in operation, and 

the progress towards completion of construction of fossil fuelfired EGUs implementing CCS at commercial scale. This literature 

record and experience demonstrate that partial CCS is achievable 

for all types of new boiler and IGCC configurations. Although 

much of this information also serves to demonstrate the 

technical feasibility of full capture, we note that several of 

the CCS projects that are the furthest along are partial capture 

projects, which further supports our view that partial capture 

is BSER.

1. Literature

The current status of CCS technology was described and 

analyzed by the 2010 Interagency Task Force on CCS, 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 
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deployment of CCS within 10 years, with a goal of bringing five 

to ten commercial demonstration projects online by 2016. The 

Task Force found that, although early CCS projects face economic 

challenges related to climate policy uncertainty, first-of-akind technology risks, and the current 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.192

The Pacific Northwest National Laboratory (PNNL) recently 

prepared a study that evaluated the development status of 

various CCS technologies for the DOE.

193 The study addressed the 

availability of capture processes, transportation options (CO2

pipelines), injection technologies, and measurement, 

verification and monitoring technologies. The study concluded 

that, in general, CCS is technically viable today and that key 

component technologies of complete CCS systems have been 

deployed at scales large enough to meaningfully inform 

discussions about CCS deployment on large commercial fossilfired power plants. 

In addition, DOE/NETL has prepared other reports – in 

 

192 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010), page 7.

Comment [A33]: Does the task force findings 

say anything about leakage from geological storage 

and ways to manage for leakage? Suggest that this 

information could be cited somewhere in the 

rulemaking, if it exisits.

EPA: The CCS Task Force report states that the 

existing regulatory framework can serve to minimize

he risk of leakage at GS sites and in the event there 

is surface leakage, it would be reported under 

subpart RR of the Greenhouse Gas Reporting 

Program. The existing regulatory framework for GS 

is described in section VII.L.2. Information on 

secure geologic storage including monitoring for 

leakage was added text to section VII.E.2.c.1.
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particular their “Cost and Performance Baseline” reports,

194

including one on partial capture195 -- that further support our 

determination of the technical feasibility of partial capture.

2. Capture, transportation and storage technologies 

Each of the core components of CCS -- CO2 capture, 

compression, transportation and storage -- has already been 

implemented and, in fact, in some instances, implemented on a 

commercial scale. The U.S. experience with large-scale CO2

injection, including injection at enhanced oil and gas recovery 

projects, combined with ongoing CCS research, development, and 

demonstration programs in the U.S. and throughout the world, 

provide confidence that the capture, transport, compression, and 

storage of large amounts of CO2 can be achieved. 

a. CO2 capture technology

Capture of CO2 from industrial gas streams has occurred 

since the 1930s, through use of 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.

 

194 The “Cost and Performance Baseline” reports are a series of 

reports by DOE/NETL that establish estimates for the cost and 

performance of combustion- and gasification-based power plants -

all with and without CO2 capture and storage. Available at 

www.netl.doe.gov/energy-analyses/baseline_studies.html.

195 “Cost and Performance of PC and IGCC Plants for a Range of 

Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011.

Comment [A34]: It would be helpful to 

summarize the reports to substantiate the statement 

that these reports support the technical feasibility 

determination by EPA. 

EPA: We cite and describe the results of these 

reports pretty extensively in other parts of the 

preamble.
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Although current capture technologies are feasible, the 

costs of CO2 capture and compression represent the largest 

barriers to widespread commercialization of CCS. Currently 

available CO2 capture and compression processes are estimated to 

represent 70 to 90 percent of the overall CCS costs.196

In general, CO2 capture technologies applicable to coalfired power generation can be categorized into three 

approaches:197

Pre-combustion systems that are designed to separate CO2 and 

H2 in the high-pressure syngas produced at IGCC power 

plants.

Post-combustion systems that are designed to separate CO2

from the flue gas produced by fossil-fuel combustion in 

air.

Oxy-combustion that uses high-purity O2, rather than air, to 

combust coal and thereby produce a highly concentrated CO2

stream.

Each of these three carbon capture approaches (precombustion, post-combustion, and oxy-combustion) is 

technologically feasible. However, each results in increased 

 

196 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010).

197 IPCC, 2005; DOE, 2007.
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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 (e.g., electricity, 

steam, heat) produced from the plant.

b. CO2 transportation

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,198 which would lower 

transportation costs. There are multiple factors that contribute 

to the cost of CO2 transportation via pipelines including but not 

limited to; availability and acquisition of rights-of-way for 

new pipelines, capital costs, operating costs, length and 

diameter of pipeline, terrain, flow rate of CO2, and the number 

of sources utilizing the pipeline. At the same time, studies and 

DOE quality guidelines have shown CO2 pipeline transport costs in 

 

198 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 $1 to $4 dollar per ton of CO2 range. 199,200,201,202 For these 

reasons, the transportation component of CCS is well-established 

as technically feasible and is not a significant component of 

the cost of CCS.

c. CO2 storage

(i) Current availability of geologic sequestration

Existing project and regulatory experience (including EOR), 

research, and analogs (e.g. naturally existing CO2 sinks, natural 

gas storage, and acid gas injection), indicate that geologic 

sequestration is a viable long term CO2 storage option. While EPA 

has confidence that geologic sequestration is technically 

feasible and available, EPA recognizes the need to continue to 

advance the understanding of various aspects of the technology, 

including, but not limited to, site selection and 

 

199 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010).

200 McCollum, D., Ogden, J., 2006. Techno-Economic Models for 

Carbon Dioxide Comprssion, Transport, and Storage & Correlations 

for Estimating Carbon Dioxide Density and Viscosity. Institute 

of Transportation Studies, University of California, Davis, 

Davis, CA

201 McCoy, S., E.S. Rubin and M.B. Berkenpas, 2008. Technical 

Documentation: The Economics of CO2 Transport by Pipeline 

Storage in Saline Aquifers and Oil Reserves. Final Report, 

Prepared by Carnegie Mellon University, Pittsburgh, PA for U.S. 

Department of Energy, National Energy Technology Center, 

Pittsburgh, PA

202 DOE/NETL. (2013). Carbon Dioxide Transport and Storage Costs 

in NETL Studies, Quality Guidelines for energy system studies. 

March 2013. DOE/NETL-2013/1614.
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characterization, CO2 plume tracking, and monitoring. On-going 

Federal government efforts such as DOE/NETL’s activities to 

enhance the commercial development of safe, affordable, and 

broadly deployable CCS technologies in the United States, 

including: Rresearch, development, and demonstration of CCS 

technologies and the assessment of the country's geologic 

capacity to store carbon dioxide, are particularly important.203

Furthermore, this rule, including the information collected 

through the GHG Reporting Program, will facilitate further 

deployment of CCS and advancements in the technology. 

Information collected under the GHG Reporting Program will 

provide a transparent means for EPA and the public to continue 

to evaluate the effectiveness of CCS, including improvements 

needed in monitoring technologies.

The viability of geologic sequestration of CO2 is based on a 

demonstrated understanding of the fate of CO2 in the subsurface. 

Geologic sequestration occurs through a combination of 

structural and stratigraphic trapping (trapping below a low 

permeability confining layer), residual CO2 trapping (retention 

as an immobile phase trapped in the pore spaces of the storage 

formation), solubility trapping (dissolution in the in situ 

 

203 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010).
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formation fluids), mineral trapping (reaction with the minerals 

in the storage formation and confining layer to produce 

carbonate minerals), and preferential adsorption trapping 

(adsorption onto organic matter in coal and shale).204,205 These 

mechanisms are functions of the physical and chemical properties 

of CO2 and the geologic formations into which the CO2 is 

injected. 

Project and research experience continues to add to the 

confidence in geologic sequestration as a viable CO2 reduction 

technology. In addition to the four existing commercial CCS 

facilities in other countriesworldwide206, multiple studies have 

been completed that have demonstrated geologic sequestration of 

CO2 as well as have improved technologies to monitor and verify 

that the CO2 remains sequestered.207 For example, CO2 has been

injected in the SACROC Unit in the Permian basin since 1972 for 

enhanced oil recovery purposes. A study of this site evaluated 

this project, and estimated that about 93 million metric tons of 

CO2 were injected and about 38 million metric tons were produced 

 

204 Intergovernmental Panel on Climate Change. (2005). Special 

Report on Carbon Dioxide Capture and Storage. Retrieved from 

http://www.ipcc.ch/pdf/special-reports/srccs/srccs_chapter5.pdf

205 Benson, Sally M. and David R. Cole. (2008). CO2 Sequestration 

in Deep Sedimentary Formations. Elements , Vol. 4, pp. 325–331. 

206 Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah 

in Algeria, and Weyburn in Canada.

207

 Report of the Interagency Task Force on Carbon Capture and 

Storage (August 2010).
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from 1972 to 2005, resulting in a geologic CO2 accumulation of 55 

million metric tons of CO2.

208 This study evaluated the ongoing 

and potential CO2 trapping occurring through various mechanisms 

using modeling and simulations, and collection and analysis of

seismic surveys and well logging data. The monitoring at this 

site demonstrated that CO2 can indeed become trapped in geologic 

formations. Studies on the permanence of CO2 storage in geologic 

sequestration have been conducted internationally as well. For 

example, the Gorgon Carbon Dioxide Injection Project and CollieSouth West CO2 Geosequestration Hub project in Australia have 

both demonstrated geologic CO2 trapping mechanisms.209

Numerous other field studies, for example those conducted 

by the DOE/NETL Regional Carbon Sequestration Partnerships, have 

been completed that demonstrate CO2 trapping mechanisms working 

in geologic formations in smaller scale projects (other similar 

projects are underway). Examples of these DOE/NETL studies 

 

208 Han, Weon Shik et al. (2010). Evaluation of trapping mechanisms 

in geologic CO2 sequestration: Case study of SACROC northern 

platform, a 35-year CO2 injection site. American Journal of 

Science Online April 2010 vol. 310 no. 4 282-324. Retrieved 

from: http://www.ajsonline.org/content/310/4/282.abstract

209 Sewell, Margaret, Frank Smith and Dominique Van Gent. Western 

Australia Greenhouse Gas Capture and Storage: A tale of two 

projects. (2012). Australian Department of Resources, Energy and 

Tourism and Western Australia Government of Western Australia. 

Retrieved from 

http://cdn.globalccsinstitute.com/sites/default/files/publicatio

ns/39961/ccsinwareport-opt.pdf
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include:210

Midwest Regional Carbon Sequestration Partnership Michigan 

Basin Phase II Validation Test, which injected 

approximately 60,000 metric tons of CO2 over two periods

from February to March 2008 (~10,000 metric tons) and from 

January to July 2009 (~50,000 metric tons). 

Midwest Geologic Sequestration Consortium Loudon, Mumford 

Hills, and Sugar Creek Phase II Validation Test, which 

consisted of injecting over 14,000 tons of CO2 across three 

EOR-scale field tests.

Southwest Regional Partnership on Carbon Sequestration 

(SWP) San Juan Basin Phase II Validation Test, which 

injected 16,700 metric tons into the coal layers of the 

Fruitland Formation.

Geologic storage potential for CO2 is widespread and 

available throughout the U.S. and Canada. Estimates based on DOE 

studies indicate that areas of the U.S. with appropriate geology 

have a storage potential of 2,300 billion to more than 20,000 

 

210 DOE/NETL. (2012). Best Practices for: Monitoring, 

Verification, and Accounting of CO2 Stored in Deep Geologic 

Formations – 2012 Update. DOE/NETL-2012/1568. Retrieved from 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/BPMMVA-2012.pdf.
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billion metric tons of CO2 in deep saline formations, oil and gas 

reservoirs and un-mineable coal seams.211 Other types of geologic 

formations such as organic rich shale and basalt may also have 

the ability to store CO2; and the DOE is currently evaluating 

their potential storage capacity. While these are estimates, 

each potential geologic sequestration site must undergo 

appropriate site characterization to ensure that the site can 

safely and securely store CO2. Estimates of CO2 storage resources 

by state/province are compiled by the DOE’s National Carbon 

Sequestration Database and Geographic Information System 

(NATCARB).

Further evidence of the widespread availability CO2 storage 

reserves in the U.S. comes from the Department of Interior’s 

U.S. Geological Survey (USGS) which has recently completed a 

comprehensive evaluation of the technically accessible storage 

resource for carbon storage for 36 sedimentary basins in the 

onshore areas and State waters of the United States.212 The USGS 

assessment estimates a mean of 3,000 billion metric tons of 

subsurface CO2 storage potential across the United States. For 

 

211 The United States 2012 Carbon Utilization and Storage Atlas, 

Fourth Edition, U.S Department of Energy, Office of Fossil 

Energy, National Energy Technology Laboratory (NETL).

212 U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013, National assessment of geologic 

carbon dioxide storage resources – Results: U.S. Geological 

Survey Circular 1386, 41 p., http://pubs.usgs.gov/fs/2013/1386/.
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comparison, this amount is 500 times the 2011 annual U.S. 

energy-related CO2 emissions of 5.5 Gigatons (Gt).213

Nearly every state in the U.S. has or is in close proximity 

to formations with carbon storage potential including vast areas 

offshore. 

(ii) Current availability of enhanced oil and gas recovery

Geologic storage options also include use of CO2 in EOR, 

which is the injection of fluids into a reservoir to increase 

oil production efficiency. EOR is typically conducted at a 

reservoir after production yields have decreased from primary 

production. Fluids commonly used for EOR include brine, fresh 

water, steam, nitrogen, alkali solutions, surfactant solutions, 

polymer solutions, and CO2. EOR using CO2, sometimes referred to 

as ’CO2 flooding’ or CO2-EOR, involves injecting CO2 into an oil 

reservoir to help mobilize the remaining oil and make it 

available for recovery. The crude oil and CO2 mixture is 

produced, and sent to a separator where the crude oil is 

separated from the gaseous hydrocarbons and CO2. The gaseous CO2-

rich stream then is typically dehydrated, purified to remove 

hydrocarbons, recompressed, and re-injected into the oil or 

 

213 U.S. Geological Survey Geologic Carbon Dioxide Storage 

Resources Assessment Team, 2013, National assessment of geologic 

carbon dioxide storage resources – Summary: U.S. Geological 

Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/.
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natural gas reservoir to further enhance recovery.

CO2-EOR has been successfully used at many production fields 

throughout the U.S. to increase oil recovery. The oil and 

natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep 

subsurface for the purposes of enhancing oil and natural gas 

production. This experience provides a strong foundation for the 

injection and monitoring technologies that will be needed for 

successful deployment of CCS.

Monitoring CO2 at EOR sites can be an important part of the 

petroleum reservoir management system to ensure the CO2 is 

effectively sweeping the oil zone, and can be supplemented by 

techniques designed to detect CO2 leakage. Recently many studies 

have been conducted to better understand the fate of injected CO2

at well-established, operational EOR sites. A large number of 

methods are available to monitor surface and subsurface leakage 

at EOR sites. Some recent studies are presented below.

At the SACROC field in the Permian Basin, the Texas Bureau 

of Economic Geology conducted an extensive groundwater 

sampling program to look for evidence of CO2 leakage in the 

shallow freshwater aquifers. At the time of the study 

(2011), the SACROC field had injected 175 million metric 

tons of CO2 over 37 years. No evidence of leakage was 
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detected.214

An extensive CO2 leakage monitoring program was conducted by 

a third party (International Energy Agency Greenhouse Gas 

Programme) for 10 years at the Weyburn oil field in 

Saskatchewan, during which time over 16 million tonnes of 

CO2 have been stored. A comprehensive analysis of surface 

and subsurface monitoring methods was conducted and 

resulted in a best practices manual for CO2 monitoring at 

EOR sites.215 

The Texas Bureau of Economic Geology has also been testing 

a wide range of surface and subsurface monitoring tools and 

approaches to document storage efficiency and storage 

permanence at a CO2 EOR site in Mississippi.216 The Cranfield 

 

214 K.D. Romanak, R.C. Smyth, C. Yang, S.D. Hovorka, M. Rearick, 

J. Lu. (2011). Sensitivity of groundwater systems to CO2: 

Application of a site-specific analysis of carbonate monitoring 

parameters at the SACROC CO2-enhanced oil field. GCCC Digital 

Publication Series #12-01. Retrieved from 

http://www.beg.utexas.edu/gccc/forum/codexdownloadpdf.php?ID=190

215 Geoscience Publishing. (2012). Best Practices for Validating 

CO2 Geological Storage: Observations and Guidance from the IEAGHG 

Weyburn-Midale CO2 Monitoring and Storage Project. Brian Hitchon 

(Ed.), 

216 Hovorka, S.D., et al. (2011). Monitoring a large volume CO2

injection: Year two results from SECARB project at Denbury’s 

Cranfield, Mississippi, USA: Energy Procedia, v. 4, Proceedings 

of the 10th International Conference on Greenhouse Gas Control 

Technologies GHGT10, September 19-23, 2010, Amsterdam, The 

Netherlands, p. 3478-3485. GCCC Digital Publication #11-16. 

Retrieved from 
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Field, under CO2 flood by Denbury Onshore LLC, is a depleted 

oil and gas reservoir that injected greater than 1.2 

million tons/year during the tests. The preliminary 

findings demonstrate the availability and effectiveness of 

many different monitoring techniques for tracking CO2

underground and detecting CO2 leakage.

The Department of Energy has conducted numerous evaluations 

of CO2 monitoring techniques at EOR pilot sites throughout the 

U.S. as part of the Regional Sequestration Partnership Phase II 

and III programs. For example, in the Illinois Basin surface and 

subsurface monitoring techniques were tested at three short 

duration CO2 injections. At one of the Illinois Basin sites, a 

landowner became concerned when excessive odor in a water well 

was observed. The ongoing groundwater monitoring program results 

were used to verify the odor was from a different origin.217 

The EPA anticipates that many early geologic sequestration 

projects may be sited in active or depleted oil and gas 

reservoirs because these formations have been previously well 

characterized for hydrocarbon recovery, likely already have 

 

http://www.sciencedirect.com/science/article/pii/S18766102110047

11

217 DOE/NETL. (2012). Best Practices for: Monitoring, 

Verification, and Accounting of CO2 Stored in Deep Geologic 

Formations – 2012 Update. DOE/NETL-2012/1568. Retrieved from 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/BPMMVA-2012.pdf.
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suitable infrastructure (e.g., wells, pipelines, etc.), and have 

an associated economic benefit of oil production. EOR sites 

including those that inject CO2, are typically selected and 

operated with the intent of oil production; however, they may 

also be suitable for long term containment of CO2. Although deep 

saline formations provide the largest CO2 storage opportunity 

(2,102 to 20,043 billion metric tons), oil and gas reservoirs 

are currently estimated to have 226 billion metric tons of CO2

storage resource.218

CO2-EOR is the fastest-growing EOR technique in the U.S., 

providing approximately 281,000 barrels of oil per day in the 

U.S. which equals about 6 percent of U.S. crude oil production. 

The vast majority of CO2-EOR is conducted in oil reservoirs in 

the U.S. Permian Basin, which extends through southwest Texas 

and southeast New Mexico. Other U.S. states where CO2-EOR is 

utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, 

Michigan, Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. 

A well-established and expanding network of pipeline 

infrastructure supports CO2-EOR in these areas. The CO2 supply 

for EOR operations currently is largely obtained from natural 

 

218 U.S. Department of Energy National Energy Technology 

Laboratory (2012). United States Carbon Utilization and Storage 

Atlas, Fourth Edition.
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underground formations or domes that contain CO2. While natural 

sources of CO2 comprise the majority of CO2 supplied for EOR 

operations, recent developments targeting anthropogenic sources 

of CO2 (e.g., ethanol plants, gas processing plants, refineries, 

power plants) have expanded or led to planned expansions in 

existing infrastructure related to CO2-EOR. Several hundred miles 

of dedicated CO2 pipeline is under construction, planned, or 

proposed that would allow continued growth in CO2 supply for EOR. 

Potential sources of CO2 for EOR continue to increase as new 

projects are being planned or implemented. Based on an 

evaluation of publicly available sources, the EPA notes there 

are currently twenty-three industrial source CCS projects in 

twelve states that are either operational, under-construction, 

or actively being pursued which are or will supply captured CO2

for the purposes of EOR. 219 This further demonstrates that CCS 

projects associated with large point sources are occurring due 

to a demand for CO2 by EOR operations. Nationally, approximately

60 million metric tons of CO2 were received for injection at EOR

operations in 2012.220 A recent study by DOE found that the 

 

219 “See technical supporting memo document (Docket EPA-HQ-OAR2013-0495) Documentation for the Summary of Carbon Dioxide 

Industrial Capture to Enhanced Oil Recovery Projects”See memo to 

docket “abc”

220 “Opportunities for Utilizing Anthropogenic CO2 for Enhanced 

Oil Recovery and CO2 Storage”, Michael L. Godec, Advanced 

Comment [A35]: Is there a reference that can be 

added that summarizes these projects?

EPA: A reference is given. 
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market for captured CO2 emissions from power plants created by 

economically feasible CO2-EOR projects would be sufficient to 

permanently store the CO2 emissions from 93 large (1,000 MW) 

coal-fired power plants operated for 30 years.221 Based on all of 

these factors, the EPA anticipates opportunities to utilize CO2-

EOR operations for geologic storage will continue to increase. 

Based on a recent resource assessment by the DOE, the 

application of next generation CO2-EOR technologies would 

significantly increase oil production areas, further expanding 

the geographic extent and accessibility of CO2-EOR operations in 

the U.S.222 Additionally, oil and gas fields now considered to be 

‘depleted’ may resume operation because of increased 

availability and decreased cost of anthropogenic CO2, and 

developments in EOR technology, thereby increasing the demand 

for and accessibility of CO2 utilization for EOR. 

3. The use of CO2 for EOR can significantly lower the net cost 

of implementing CCS. The opportunity to sell the captured CO2

for EOR, rather than paying directly for its long-term 

storage, improves the overall economics of the new generating 

 

Resources International, June 11, 2013 presentation at the 

Introduction to CO2 EOR Workshop, http://na2050.org/introductionto-carbon-dioxide-enhanced-oil-recovery-co2-eor.

221 “Improving Domestic Energy Security and Lowering CO2 Emissions 

with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR)”, 

DOE/NETL-2011/1504 (June 20, 2011).

222 Ibid.
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unit. According to the International Energy Agency (IEA), of 

the CCS projects under construction or at an advanced stage of 

planning, 70 percent intend to use captured CO2 to improve 

recovery of oil in mature fields.223 Examples of CCS 

demonstration projects

The following is a brief summary of some examples of 

currently operating or planned CO2 capture or storage systems, 

including, in some cases, components necessary for coal-fired

power plant CCS 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 slip stream of each plant’s flue gas. At Warrior Run, 

approximately 110,000 metric tons of CO2 per year are captured.

At Shady Point 66,000 metric tons of CO2 per year are captured. 

The CO2 from both plants is used in the food processing 

industry.224

At the Searles Valley Minerals soda ash plant in Trona, CA, 

approximately 270,000 metric tons of CO2 per year are captured 

 

223 Tracking Clean Energy Progress 2013, International Energy 

Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 

2013.

224 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.
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from the flue gas of a coal-fired power plant via amine 

scrubbing and used for the carbonation of brine in the process 

of producing soda ash.225

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 metric tons of CO2 per year from 

the synthesis gas. The CO2 is purified and transported via a 200-

mile pipeline for use in EOR operations in the Weyburn oilfield 

in Saskatchewan, Canada.

In September 2009, 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 slip stream of the plant’s exhaust flue 

gas. In May 2011, Alstom Power announced the successful 

operation of the chilled-ammonia CCS validation project. The 

demonstration achieved capture rates from 75 percent (design 

value) to as high as 90 percent, and produced CO2 at purity of 

greater than 99 percent, with energy penalties within a few 

percent of predictions. The facility reported robust steadystate operation during all modes of power plant operation 

 

225 IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
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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 slip stream 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 would terminate its 

cooperative agreement with the DOE and place its plans to 

advance CO2 capture and storage technology to commercial scale on 

hold, citing the uncertain status of U.S. climate policy as a 

contributor to the decision.

Oxy-combustion of coal is being demonstrated in a 10 MWe 

facility in Germany. The Vattenfall plant in eastern Germany 

(Schwarze Pumpe) has been operating since September 2008. It is 

designed to capture 70,000 metric tons of CO2 per year. A larger 

scale project – the FutureGen 2.0 Project – is in advanced 

stages of planning in the U.S.226

 

226 In cooperation with the U.S. Department of Energy (DOE), the 

FutureGen 2.0 project partners will upgrade a power plant in 

Meredosia, IL with oxy-combustion technology to capture 

Comment [dj36]: Per OMB: Any 2013 update?

EPA: No update that we are aware of.

Comment [dj37]: Per OMB:

Are there any further details that can be added?

EPA: Additional detail has been added.
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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 captures 

approximately 165,000 metric tons of CO2 annually at a CO2

capture rate of over 90 percent. The captured CO2 is being 

permanently stored underground in a deep saline geologic 

formation. 

Southern Company has begun construction of Mississippi 

Power Kemper County Energy Facility. This is a 582 MW IGCC plant 

that will utilize local Mississippi lignite and include precombustion carbon capture to reduce CO2 emissions by 65 percent. 

The captured CO2 will be used for EOR in the Heidelberg Oil 

Fields in Jasper County, MS. The project is now more than 75 

percent complete with start-up and operation expected to begin 

in 2014.

SaskPower’s Boundary Dam CCS Project in Estevan, a city in 

Saskatchewan, Canada. The project is the world’s largest 

commercial-scale CCS project of its kind. The project will fully 

integrate the rebuilt 110 MW coal-fired Unit #3 with available 

CCS technology to capture 90% of its CO2 emissions. The facility 

 

approximately more than 90 percent of the plant’s carbon 

emissions. http://www.futuregenalliance.org/.
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is currently under construction. Performance testing is expected 

to commence in late 2013 and the facility is expected to be 

fully operational in 2014.

The Texas Clean Energy Project, a 400 MW IGCC facility 

located near Odessa, Texas will capture 90 percent of its CO2, 

which is approximately 3 million metric tons annually. The 

captured CO2 will be used for EOR in the West Texas Permian 

Basin. Additionally, the plant will produce urea and smaller 

quantities of commercial-grade sulfuric acid, argon, and inert 

slag, all of which will also be marketed. The developer expects 

financing to be fully arranged in 2013.

There are other CCS projects – domestic and worldwide --

that are helping to further develop the CCS technology. They are 

noted in the DOE/NETL’s Carbon Capture, Utilization, and Storage 

(CCUS) Database.227 The database includes active, proposed, 

canceled, and terminated CCUS projects worldwide.

F. Costs

As noted, according to the D.C. Circuit case law, control 

 

227 Available at 

http://www.netl.doe.gov/technologies/carbon_seq/global/database/

Information in the database regarding technologies being 

developed for capture, evaluation of sites for carbon dioxide 

(CO2) storage, estimation of project costs, and anticipated dates 

of completion is sourced from publically available information. 

The CCUS Database provides the public with information regarding 

efforts by various industries, public groups, and governments 

towards development and eventual deployment of CCUS technology.
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costs are considered acceptable as long as they are reasonable, 

meaning that they can be accommodated by the industry.228 To 

determine reasonableness, the Court has looked to the amount of 

the control costs, whether they could be passed on to the 

consumer, and how much they would lead prices to increase. As we 

discuss below, where EOR opportunities are available, the sale 

of captured CO2 offers the opportunity to defray much of the 

costs. However, we recognize that there are places where 

opportunities to sell captured CO2 for utilization in EOR 

operations may not be presently available. Nevertheless, as 

discussed below, our analysis shows that this cost structure –

with and without EOR - is consistent with the D.C. Circuit’s 

criteria for determining that costs are reasonable. 

At the outset, it should be noted that even though the 

costs of coal-fired electricity generation – even when not 

incorporating CCS technology – are high when compared to the 

current costs of new NGCC generation, some utilities and other 

project developers have indicated a willingness to proceed with 

new fossil fuel-fired boilers and IGCC units. They have 

indicated the need for energy and fuel diversity. They have also 

indicated a skepticism regarding long-term projections for low 

 

228 In addition, the EPA may consider costs through a national 

lens, as discussed below.
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natural gas prices and high availability. And there may be other 

reasons why developers have indicated a willingness to build new 

coal-fired plants, even if they currently do not appear to be 

the most economic choice.

1. Cost estimates for implementation of partial CCS

The EPA has examined costs of new power generation options. 

These options are shown in Table 64. The table shows the costs 

of new NGCC technology at two different natural gas prices: at 

$56.11/MMBtu, which is reasonably consistent with current and 

projected prices; and at $10/MMBtu, which would be well above 

current and projected natural gas prices. We also show costs for 

SCPC and IGCC units with no CCS (i.e., units that would not meet 

the proposed emission standard) and for those units with partial 

capture CCS installed such that their emissions would meet the 

proposed 1,100 lb CO2/MWh standard. We have also included costs 

for those same units when EOR opportunities are available. We 

have included a “low EOR” case assuming a low EOR price of $20 

per ton of CO2, and a “high EOR” of $40/ton. (These EOR prices 

are net of the costs of transportation, storage, and monitoring 

(TSM). We also show the projected costs for implementation of 

full capture CCS (i.e., 90 percent capture). 

Table 64. Levelized Cost of Electricity for Electric Generating 

Technologies, Excluding Transmission Costs Comment [A38]: Probably worth a footnote 

explaining that this does not include savings from 

direct subsidies like tax credits.

EPA: A footnote has been added.
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Technology

Levelized Cost of 

Electricity 

($2011/MWh)

229,230,231

NGCC @ $6.11/MMBtu 59

NGCC @ $10.0/MMBtu 86 

SCPC w/o CCS232 92 

SCPC (1,100 lb/MWh; no EOR) 110 

SCPC (1,100 lb/MWh; low EOR) 96 

SCPC (1,100 lb/MWh; high EOR) 88 

SCPC (full, 90 percent CCS) 147 

 

229 Data for fossil fuel-fired generation comes from DOE/NETL: 

(1) Cost and Performance Baseline for Fossil Energy Plants 

Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev 2, 

DOE/NELT-2010/1397 (Nov 2010); (2) Updated Costs (June 2011 

Basis) for Selected Bituminous Baseline Cases” DOE/NETL341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC 

Plants for a Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 

(May 2011). Data for non-fossil fuel-fired generation comes from 

DOE Energy Information Administration (EIA) Annual Energy 

Outlook (AEO) 2013. Levelized Cost of Electricity (LCOE)

estimates come from 

http://www.eia.gov/forecasts/aeo/electricity_generation.cfm. To 

maintain consistency with DOE/NETL estimates, EIA estimates 

provided in this table do not include transmission investment.

230 LCOE point estimates are provided for coal-fired capacity 

types; all other LCOE estimates are presented as a range that 

reflects EIA’s view on the regional variation in local labor 

markets, cost and availability of fuel, and renewable resources. 

The capacity factor ranges for renewable non-dispatchable 

technologies are as follows: Wind – 30% to 39%, Wind Offshore –

33% to 42%, Solar PV- 22% to 32%, and Solar Thermal – 11% to 

26%. Capacity factors for dispatchable technologies are as 

follows: Coal and NGCC – 85%, Nuclear – 90%, Biomass – 83%, 

Geothermal – 92%, and Combustion Turbine – 30%. There is no 

capacity credit provided to dispatchable resources. 

231 These costs do not include the impact of subsidies that may 

potentially be available to developers of new projects that 

include CCS.

232 SCPC LCOE includes a 3% increase to the weighted average cost 

of capital to reflect EIA’s climate uncertainty adder (CUA).
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IGCC w/o CCS 97 

IGCC (1,100 lb/MWh; no EOR) 109 

IGCC (1,100 lb/MWh; low EOR) 101 

IGCC (1,100 lb/MWh; high EOR) 97 

IGCC (full, 90 percent CCS) 136 

Nuclear 103 - 114

Biomass 97 - 130

Geothermal 80 – 99

Combustion Turbine 87 – 116

Onshore Wind 70 – 97

Offshore Wind 177 – 289

Solar PV233 109 – 220

Solar Thermal 184 – 412

The cost estimates from the DOE/NETL studies carry an 

accuracy of -15% ± 30%, consistent with a “feasibility study” 

level of design engineering applied to the various cases in this 

study. The value of the studies lies not in the absolute 

accuracy of the individual case results but in the fact that all 

cases were evaluated under the same set of technical and 

economic assumptions. This consistency of approach allows 

meaningful comparisons among the cases evaluated.

For an emerging technology like CCS, costs can be estimated 

for a “first-of-a-kind” (FOAK) plant or an “nth-of-a-kind” (NOAK) 

plant, the latter of which has lower costs due to the “learning 

 

233 Costs are expressed in terms of net AC power available to the 

grid for the installed capacity.
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by doing” and risk reduction benefits that result from serial 

deployments as well as from continuing research, development and 

demonstration projects.234 The estimates provided in Table 6 for 

a new NGCC unit and for a SCPC plant without CO2 capture are 

based on mature technologies and are thus NOAK costs. For plants 

that utilize technologies that are not yet fully mature, such 

the IGCC or any plant that includes CO2 capture, the cost 

estimates in Table 4 represent a plant that is somewhere between 

FOAK and NOAK, sometimes referred to as “next-of-a-kind”.

Because there are a number of projects currently under 

development, the EPA believes it is reasonable to focus on the 

next-of-a-kind costs provided in Table 6. The lessons learned 

from design, construction and operation of those projects, as 

well as for that of Duke Energy’s Edwardsport IGCC (which does 

not include CCS) will help lower costs for future gasification 

facilities implementing CCS. The TCEP project and the HECA 

project are both in advanced stages of design and 

development. Summit Power, the developer of TCEP, is also 

 

234 Elsewhere in this preamble, we describe the evidence that as 

technology matures, its costs decrease. Note also that EPA 

regulations of mobile source air emissions incorporate the 

decreasing costs of technology over time. See, e.g., “2017 and 

Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and 

Corporate Average Fuel Economy Standards – Final Rule,” 77 Fed. 

Reg. 62624, 62984/1 to 62985/1 (October 15, 2012) (incorporating 

“cost reductions, due to learning effects”).
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pursuing a number of additional projects that would benefit from 

lessons learned from TCEP. These include the Captain Clean 

Energy Project in the United Kingdom (UK) and another polygeneration project in Texas.

235 For a new conventional PC plant 

implementing post-combustion CCS, the Boundary Dam project will 

perhaps represent a FOAK project while the W.A. Parish project 

may represent a second-of-a-kind project - or perhaps even a 

next-of-a-kind project.

Further, as discussed elsewhere in this preamble, many of 

the individual components of a new generation project with CCS 

have been previously demonstrated. For example, capturing CO2

from a coal gasification syngas stream has been occurring for 

more than ten years at the Dakota Gasification facility. 

Experience gained at that facility can inform design and 

operational choices of a new IGCC implementing partial CCS. 

For all these reasons, the next IGCC and SCPC facilities 

with CCS can be expected to be less expensive than the current 

FOAK projects, if somewhat more expensive than the NOAK 

facilities with CCS that construct when CCS has become a fully 

mature technology. The costs in Table 6 reflect those next-of-akind costs.

 

235 (http://ghgnews.com/index.cfm/summit-even-without-uk-demofunding-project-will-move-forward/?mobileFormat=true).
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It is important to note here that both the EIA and the EPA 

apply a climate uncertainty adder (CUA) - represented by a three 

percent increase to the weighted average cost of capital - to 

certain coal-fired capacity types. The EIA developed the CUA to 

address the disconnect between power sector modeling absent GHG 

regulation and the widespread use of a cost of CO2 emissions in 

power sector resource planning.

The CUA reflects the additional planning cost typically 

assigned by project developers and utilities to GHG-intensive 

projects in a context of climate uncertainty. The EPA believes 

the CUA is consistent with the industry’s planning and 

evaluation framework (demonstrable through IRPs and PUC orders) 

and is therefore necessary to adopt in evaluating the cost 

competitiveness of alternative generating technologies.

EPA believes the CUA is relevant in considering the range 

of costs that power companies are willing to pay for generation 

alternatives to natural gas. To the extent that a handful of 

project developers are still considering coal without CCS, EPA 

believes, based both on the analysis the EIA undertook in 

developing the CUA approach and the EPA’s review of IRPs236, they 

must fall into one of two classes. The first, which is the 

 

236 See Technical Support Document: “Review of Electric Utility 

Integrated Resource Plans”, available in the rulemaking 

docket EPA-HQ-OAR-2013-0495.

Comment [A39]: This may benefit an 

explanation of why this uncertainty will still exist 

after this new source rulemaking (new sources will 

someday be subject to different standards, whether 

it’s existing source standards after the 8-yr review or 

a potentially new legislative regime).

EPA: We have used the CUA only for new units 

that do not include CCS. It would be speculative for 

EPA to discuss uncertainty beyond this rulemaking.
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minority, is not factoring in any form of a CUA. The second, 

which is the majority, assume that coal-fired power plants 

without CCS entail additional costs due to the risk of future 

regulation of CO2. Factoring in risk associated with CO2 suggests 

that these companies are, in fact, willing to pay the higher 

cost for coal without CCS (even if they are not actually 

incurring those costs today). For these reasons, EPA believes 

that it is appropriate to consider the cost of coal without CCS 

to include the CUA in the range of costs that utilities are 

willing to pay for alternatives to natural gas.

The EPA is requesting comment on all aspects of the CUA,

including its magnitude and technology-specific application, to

ensure that the EPA’s supporting analysis best reflects the 

current standards and practices of the power sector’s long-term 

planning process.

2. Comparison with the costs of other new power generation 

options

As table 4 above shows, Wwhile new coal-fired generation 

that includes CCS is more expensive than either new coal-fired 

generation without CCS or new NGCC generation, it is competitive 

with new nuclear power, which, besides natural gas combustion 

turbines, is one of the principal other options often considered 

for providing new base load power., It is also competitiveand
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with biomass-fired generation, which is another low-GHG emitting 

generation technologyies often considered for base load power.

237

A review of utility IRPs shows that a number of companies are 

considering new nuclear power as an option for new base load

generation capacity in lieu of new coal-fired generation with or 

without CCS, because, according to the IRPs, nuclear power is a 

cost-effective way to generate base load electricity that 

addresses risks associated with potential future carbon 

liabilities. New fossil fuel-fired generation that includes CCS 

serves the same basic function as new nuclear power: providing 

base load power with a lower carbon footprint. New coal-fired 

generation that incorporates partial CCS that is sufficient to 

meet the CO2 emission limitation that we are proposing in today’s 

action (1,100 lb CO2/MWh) would have a similar levelized cost of 

electricity (LCOE) as a new nuclear power plant (about $103/MWh 

- $114/MWh). This indicates that, at the proposed emission 

limitation of 1,100 lb CO2/MWh, the cost of new coal-fired 

generation that includes CCS is reasonable today.

3. Costs of “Full capture” CCS

 

237 Although geothermal energy is also generally considered for 

base load power, it is limited in availability. The other lowGHG emitting generation listed in – solar and wind – are not 

used for base load.

Comment [A40]: In light of Fukushima, is this 

still accurate? Consider adding a footnote to 

acknowledge Fukushima context.

EPA: We reviewed the most recent IRP available. 

EPA can’t speculate on how Fukushima will affect 

utilities’ long term plans.
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As noted in Table 46, above, and discussed in the RIA238 for 

this rulemaking, implementation of CCS to achieve 90 percent CO2

capture adds considerably to the LCOE from a new SCPC or IGCC 

unit. The LCOE for a new SCPC and a new IGCC, both without CCS, 

are estimated to be $92/MWh and $97/MWh, respectively. The 

corresponding costs with implementation of “full capture” CCS 

are $147/MWh for the new SCPC unit and $136/MWh for the new IGCC 

unit. These costs exceed what project developers have been 

willing to pay for other low GHG-emitting base load generating 

technologies (e.g., nuclear) that also provide energy diversity. 

For that reason alone, we do not believe that the costs of full 

implementation of CCS are reasonable at this time.

4. Reasonableness of costs of partial CCS

As noted, the current costs of coal, natural gas, and 

construction of coal-fired or natural gas-fired EGUs have led to 

little currently announced or projected new coal-fired 

generating capacity. This very likely reflects the large price 

differential between the cost of a new NGCC (cost of 

electricity: $59/MWh at a natural gas price of $6.11/MMBtu) and 

SCPC without CCS (cost of electricity: $92/MWh) and IGCC without 

 

238 Regulatory Impact Analysis for the Standards of Performance 

for Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric 

Utility Steam Generating Units and Stationary Combustion 

Turbines (available in the rulemaking docket EPA-HQ-OAR-2013-

0495)
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CCS (cost of electricity: $97/MWh), coupled with a leveling of 

demand for electricity and the recent increase in renewable 

sources. 

We observe that most of the industry appears to take the 

view that the price of natural gas will remain sufficiently low 

for at least a long enough period into the future that new 

natural-gas fired electricity generation will be less expensive 

than new coal-fired generation. As a result, in most cases, 

customers or utilities that contract for new generation are 

doing so for natural gas-fired generation. Long-term contracts 

for electricity supply are commonly for a 25-year period; thus, 

most of the industry appears to consider contracting for new 

natural gas-fired generation for a 25-year period to be the most 

economical of their choices.

As shown in Table 64, we estimate that a new SCPC plant 

costs $92/MWh, which is $33/MWh, or about 56 percent higher than 

the new NGCC cost of $59/MWh. Limiting the emission rate to 

1,100 lb CO2/MWh (which can be achieved by adding partial CCS), 

without sale of captured CO2 for EOR, would add another $18/MWh 

to the cost of electricity, for a total of $110/MWh. Thus, the 

total additional cost to meet the proposed standard by 

implementing partial capture CCS (without revenues from CO2 sales 

for EOR) is about half the additional cost of coal-fired 
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generation, compared to natural-gas fired generation.

We are aware of another segment of the industry, which 

includes electricity suppliers who have indicated a preference 

for new coal-fired generation to establish or maintain fuel 

diversity in their generation portfolio because their customers 

have expressed a willingness to pay a premium for that 

diversity. It appears these utilities and project developers see 

lower risks to long-term reliance on coal-fired generation and 

greater risks to long-term reliance on natural gas-fired 

generation, compared to the rest of the industry.

We consider the costs of CCS to be reasonable for this 

segment of the industry as well. The additional costs of CCS for 

new SCPC of $18/MWh LCOE ($110/MWh for SCPC with partial CCS 

compared to $92/MWh for SCPC without CCS) are only about half as 

much as the additional costs that are already need to be 

incurred to develop coal-fired electricity as compared to new 

NGCC generation ($92 MWH for SCPC without CCS compared to $59

MWh for NGCC at a natural gas price of $6.11/MMBtu). Moreover, 

it is possible that under these circumstances, the demand for 

the electricity would be inelastic with respect to the price 

because it may not depend on cost as much as on a demand for 

energy diversity. These circumstances would be similar to the 

Portland Cement (1975) case, discussed above, in which the D.C. 
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Circuit upheld NSPS controls that increased capital and 

operating costs by a substantial percentage because the demand 

for the goods was inelastic with respect to price, so that the 

industry could pass along the costs.239

In addition, we consider the costs of partial CCS to be 

reasonable because a segment of the industry is already

accommodating them. As noted, a segment of the industry consists 

of the several coal-fired EGU projects that already incorporate 

at least partial CCS. These projects, which are each 

progressing, include Kemper, TCEP, and HECA. Each is an IGCC 

plant that expects to generate profits from the sale of products 

that result from coal gasification, in addition to the sale of 

electricity. It is true that each of these projects has received 

DOE grants to encourage the development of CCS technology, but 

we do not consider such government subsidies to mean that the 

costs of CCS would otherwise be unreasonable. As we noted in the 

original proposal for this rulemaking,240 many types of 

electricity generation receive government subsidies. For 

example, nuclear power is the beneficiary of the Price-Anderson 

Act, which partially indemnifies nuclear power plants against 

 

239 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975).

240 77 Fed. Reg. at 22,418/3.
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liability claims arising from nuclear incidents,241 and domestic 

oil and gas production,242 coal exploration and development,243

and renewable energy generation244 are each the beneficiary of 

Federal tax incentives.

5. Opportunities to further reduce the costs of partial CCS

a. Enhanced oil recovery

While the reasons noted above are sufficient to justify the 

reasonableness of the costs of partial CCS, in most cases, we 

believe that the actual costs will be less. One reason is the 

availability of EOR. As noted, EOR is being actively used in 

various counties in the U.S., and CO2 pipelines extend into those 

counties from, in some cases, hundreds of miles away. We 

consider areas in close proximity to active EOR locations, 

including the pipelines that extend into those locations, to be 

places where EOR is available.

We recognize that, at present, certain locations are far 

enough away from either oilfields with EOR availability or 

pipelines to those oil fields that any coal-fired power plants 

 

241 See Duke Power Co. v. Carolina Environmental Study Group, 438 

U.S. 59 (1978).

242 See Internal Revenue Code §263.

243 See “General Explanations of the Administration’s Fiscal Year 

2013 Revenue Proposals,” pp. 120-24 

http://www.treasury.gov/resource-center/taxpolicy/Documents/General-Explanations-FY2013.pdf.

244 See Internal Revenue Code §45.

Comment [A41]: Is there a reference that could 

be used here to show existing subsidies. It appears 

this citation is about proposals.

EPA – footnote has been added
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that build in those locations would incur costs to build 

pipeline extensions that may render EOR non-economical. Those 

locations are relatively limited when legal or practical limits 

on building coal-fired power plants are taken into account. For 

example, some states with locations that are not located near 

EOR availability are not expected to have new coal-fired builds 

without CCS in any event, for legal or practical reasons. A 

number of States, at least in the short term, already have high 

reserve margins and/or have large renewable targets which push 

new decisions towards renewables and quick starting natural gas 

to provide backup to renewables over coal-fired generation. 

In addition, it is important to note that coal-fired power 

plants that build in any particular location may serve demand in 

a wide area. There are many examples where coal-fired power 

generated in one state is used to supply electricity in other 

states. For instance, historically, nearly 40 percent of the 

power for the City of Los Angeles was provided from two coalfired power plants located in Arizona and Utah. In another 

example, Idaho Power, which serves customers in Idaho and 

Eastern Oregon, meets its demand in part from coal-fired power 

plants located in Wyoming and Nevada.

As a result, the geographic scope of areas in which EOR is 

available to defray the costs of CCS should be considered to be 
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large. The costs provided in Table 4 6 show how the ability to 

sell CO2 for utilization in EOR can significantly affect the 

overall costs of the project. 

We also considered how the opportunity to sell captured CO2

for EOR may affect the costs for new units implementing full 

capture CCS. We previously indicated that the costs – $147/MWh 

for the new SCPC unit and $136/MWh for the new IGCC unit – are 

not reasonable and we rejected that option as BSER on that 

basis. We estimated that the SCPC with full capture LCOE could

be reduced to between $93 and $115/MWh (depending on selling 

price of the CO2) and the IGCC with full capture could be reduced 

between $91 and $109/MWh (again, depending upon the selling 

price of the CO2). These costs are similar with the reasonable 

costs for partial capture similar units with no opportunity to 

sell captured CO2 for EOR. This indicates that in some cases 

(Summit’s TCEP, for example), developers may determine that a 

new unit with full capture is economically viable. However, this 

factor alone does not lead us to conclude that full capture 

should be BSER. When considered in conjunction with other 

factors including the cost of full CCS where EOR is not 

available, the fact that more projects using partial CCS than 

full CCS are underway and the implications for technology 

development, EPA believes that partial CCS should be considered 
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BSER.

b. Government subsidies

In some instances, the costs of CCS can be defrayed by 

grants or other benefits provided by the DOE or the states. 

Although, for the reasons noted earlier, we consider the current 

costs of CCS even without subsidization to be reasonable, the 

availability of these governmental subsidies supports the 

reasonableness of the costs.

The 2010 Interagency Task Force Report on CCS report 

described the DOE program as follows:

The DOE is currently pursuing multiple 

demonstration projects using $3.4 billion of available 

budgetary resources from the American Recovery and 

Reinvestment Act in addition to prior year 

appropriations. Up to ten integrated CCS demonstration 

projects supported by DOE are intended to begin 

operation by 2016 in the United States. These 

demonstrations will integrate current CCS technologies 

with commercial-scale power and industrial plants to 

prove that they can be permitted and operated safely 

and reliably. New power plant applications will focus 

on integrating pre-combustion CO2 capture, transport, 

and storage with IGCC technology. Power plant retrofit 

and industrial applications will demonstrate 

integrated post-combustion capture.245

DOE allocated some $3.4 billion for 5-10 projects, and has 

committed $2.2 billion for 5 projects to date. In addition, 

various other federal and state incentives are also available to 

 

245 Task Force Report on CCS, p. 76
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many projects. The 2010 Interagency Task Force on CCS, in 

surveying all of the federal and state benefits available, 

concluded that the DOE grants, “plus ... federal loan guarantees, 

tax incentives, and state-level drivers, cover a large group of 

potential CCS options.” 246

In addition, regulatory programs may serve to defray the 

costs of CCS, including, for example, Clean Energy Standards or 

guaranteed electricity purchase price agreements.

247

As noted above and in the April 2012 proposal, the need for 

subsidies to support emerging energy systems and new control 

technologies is not unusual. Each of the major types of energy 

used to generate electricity has been or is currently being 

supported by some type of government subsidy such as tax 

benefits, loan guarantees, low-cost leases, or direct 

expenditures for some aspect of development and utilization, 

ranging from exploration to control installation. This is true 

for fossil fuel-fired; as well as nuclear-, geothermal-, wind-, 

and solar-generated electricity.248

c. Expected reductions in the costs of CCS

 

246 Task Force Report on CCS, p. 76

247 See Center for Climate and Energy Solutions, “Financial 

Incentives for CCS” -

http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=838

0.

248 77 Fed. Reg. at 22,418/3.

Comment [A42]: Please elaborate further on 

these elements. More information should be 

provided.

EPA: A citation has been provided – readers can 

seek additional information in that reference.
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The EPA reasonably projects that the costs of CCS will 

decrease over time as the technology becomes more widely used. 

Although, for the reasons noted earlier, we consider the current 

costs of CCS to be reasonable, the projected decrease in those 

costs further supports their reasonableness. The D.C. Circuit 

case law that authorizes determining the “best” available 

technology on the basis of reasonable future projections 

supports taking into account projected cost reductions as a way 

to support the reasonableness of the costs.

As noted above, the D.C. Circuit, in the 1973 Portland 

Cement Ass’n v. Ruckelshaus case, stated that the EPA, in 

identifying the “best system of emission reduction ... adequately 

demonstrated,” may “look[] toward what may fairly be projected 

for the regulated future, rather than the state of the art at 

present....”249 In the 1999 Lignite Energy Council v. EPA case, the 

Court elaborated: 

Of course, where data are unavailable, EPA may 

not base its determination that a technology is 

adequately demonstrated or that a standard is 

achievable on mere speculation or conjecture....but EPA 

may compensate for a shortage of data through the use 

of other qualitative methods, including the reasonable 

extrapolation of a technology's performance in other 

industries.250

 

249 Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973), quoted in Lignite Energy Council v. EPA, 198 F.3d 

930, 933-34 (D.C. Cir. 1999).

250 Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. 
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It is logical to read these statements in the D.C. Circuit case 

law to apply as well to the cost component of the “best system 

of emission reduction ... adequately demonstrated.” 

We expect the costs of CCS technologies to decrease for 

several reasons. We expect that significant additional knowledge 

will be gained from deployment and operation of at least two new 

coal-fired generation projects that include CCS. These projects 

are the Southern Company’s Kemper County Energy Facility IGCC 

with CCS and the Boundary Dam CCS project on a conventional 

coal-fired power plant in Canada. They are currently under 

construction and are expected to commence operation next year. 

In addition there are several other CCS projects in advanced 

stages of development in the U.S. (e.g., the Texas Clean Energy 

Project, the Hydrogen Energy California Project, and the Future 

Gen project in Illinois) that may also provide additional 

information. In addition, research is underway to reduce CO2

capture costs and to improve performance. The DOE/NETL sponsors 

an extensive research, development and demonstration program 

 

Cir. 1999). Based on this view that EPA may extrapolate 

from other industries, the Court in the Lignite Energy 

Council v. EPA case upheld a control technology as being 

“adequately demonstrated” for coal-fired industrial boilers 

because the technology was utilized by utility boilers.

Comment [A43]: Any citations to provide further 

support?

EPA: Our reasons are provided in the following 

text.
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that is focused on developing advanced technology options 

designed to 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 

available CCS technologies would add around 80 

percentsignificantly to the cost of electricity for a new 

pulverized coal plant, and around 35 percent to the cost of 

electricity for a new advanced gasification-based plant would be 

increased by approximately half of the increase at a comparable 

PC facility. (Note that these cost increases would be 

significantly less for the partial capture standard being 

proposed in today’s notice.) The CCS research, development and 

demonstration program is aggressively pursuing efforts to reduce 

these costs to a less than 30 percent increase in the cost of 

electricity for PC power plants and a less than 10 percent 

increase in the cost of electricity for new gasification-based 

power plants.251 The large-scale CO2 capture demonstrations that 

are currently planned and in some cases underway, under the 

DOE’s initiatives, as well as other domestic and international 

projects, will generate operational knowledge and enable 

continued commercialization and deployment of these 

 

251 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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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 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 FGSM 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 per-unit cost of producing or using a given technology 
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declines as experience with that technology increases over 

time,252 and this has 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, 

reductions in financial premiums related to risk, research and 

development investments, and other factors have been observed 

over the decades. 

In addition, we note that the 2010 Interagency Task Force 

on CCS report recognized that CCS would not become more widely 

available without a regulatory framework that promoted CCS or a 

strong price signal for CO2. Today’s action is an important 

component in developing that framework.

G. Promotion of technology

It is clear that identifying partial CCS as the BSER 

promotes the utilization of CCS because any new fossil fuel-

 

252 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 (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).
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fired utility boiler or IGCC unit will need to install partial 

capture CCS in order to meet the emission standard. Particularly 

because the technology is relatively new, additional utilization 

is expected to result in improvements in the performance 

technology and in cost reductions. Moreover, identifying partial 

capture CCS as the BSER will encourage continued research and 

development efforts, such as those sponsored by the DOE/NETL. In 

contrast, not identifying partial CCS as the BSER could 

potentially impede further utilization and development of CCS. 

It is important to promote deployment and further development of 

CCS technologies because they are the only technologies that are 

currently available or are expected to be available in the 

foreseeable future that can make meaningful reductions in CO2

emissions from fossil fuel-fired utility boilers and IGCC units. 

Identifying partial CCS as the BSER also promotes further 

use of EOR because, as a practical matter, we expect that new 

fossil fuel-fired EGUs that install CCS will generally make the 

captured CO2 available for use in EOR operations. The use of EOR 

lowers costs for production of domestic oil, which promotes the 

important goal of energy independence.

H. Nationwide, longer-term perspective

As noted, the D.C. Circuit in Sierra Club held:

The language of [the definition of “standard of 

performance” in] section 111 ... gives EPA authority 
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when determining the best ... system to weigh cost, 

energy, and environmental impacts in the broadest 

sense at the national and regional levels and over 

time as opposed to simply at the plant level in the 

immediate present.253

Considering on “the national and regional levels and over 

time” the criteria that go into determining the “best system of 

emission reduction ... adequately demonstrated” also supports

identifying partial CCS as that best system because doing so 

would not have adverse impacts on the power sector, national 

electricity prices, or the energy sector.

1. Structure of the power sector

Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with the 

current and projected future structure of the power sector. As 

noted, we project that in light of the current and projected 

trends in coal and natural gas costs, virtually all new electric 

generating capacity will employ NGCC technology or renewable 

energy, and very little new capacity will be coal-fired. 

As noted above, the recent history of solid fossil fuelfired projects suggest that these new coal-fired builds, if they 

occur, may (i) consist of an IGCC unit, including features such 

as sale of additional byproducts (e.g., plants such as the Texas 

 

253 Sierra Club v. Costle, 657 F.2d at 330.
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Clean Energy Project, which intends to manufacture fertilizer

products for sale and sell captured CO2 for EOR in addition to 

selling electricity), use of lower cost opportunity fuels (such 

as petcoke proposed to be used at the Hydrogen Energy California 

facility) and/or rely on additional local regulatory drivers 

(such as California’s AB-32 program which incentivizes lower CO2

generating technologies), all of which would be designed to 

offset enough of the additional coal-related costs to be able to 

compete with natural-gas fired electricity in the marketplace; 

and (ii) be designed to offer fuel diversity to a group of 

customers that are willing to pay a premium in electricity 

prices (such as the Power4Georgians project in Washington 

County, Georgia). 

Projects in the first category would by definition already 

include at least partial CCS and, as a result, would be affected 

by this rule to only a limited extent. Projects in the second 

category would be more affected, but developers of these 

projects would nevertheless have several options. They could 

pursue coal with CCS and possibly rely on cost savings from EOR 

or on their customers’ willingness to pay a higher premium. 

Alternatively, they could choose a different generation 

technology (most likely natural gas). Even if they chose a 

different generation technology, the small number of these 
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sources and the fact that the basic demand for electricity would 

still be met would limit the impact of this rule on the power 

sector.

2. Impacts on nationwide electricity prices.

Identifying partial CCS as the BSER for fossil fuel-fired 

utility boilers and IGCC units will not have significant impacts 

on nationwide electricity prices. The reason is that the 

additional costs of partial CCS will, on a nationwide basis, be 

small because no more than a few new coal-fired projects are 

expected, and because, as noted, at least some of these can be 

expected to incorporate CCS technology in any event. It should 

be noted that the computerized model the EPA relies on to assess 

energy sector and nationwide impacts – the Integrated Planing 

Model (IPM) – does not forecast any new coal-fired EGUs through 

2020. Based on these IPM analyses, the RIA for this rulemaking 

concludes that the proposed standard of 1,100 lb of CO2/MWh for 

new fossil fuel-fired EGUs, which is based on partial CCS as the 

best demonstrated system, does not create any costs. 

3. Energy considerations

Identifying partial CCS as the BSER for new fossil fuelfired utility boilers and IGCC units is consistent with 

nationwide energy considerations because it will not have 

adverse effects on the structure of the power sector, will 

Comment [A44]: EPA may want to consider 

pointing out in this section that the availability of 

natural gas-fired plants to meet electricity generation 

needs at a reasonable cost also serves as a backstop 

against any large economic/energy impacts.

EPA: Since we’ve already said that we expect the

fuel of choice to be natural gas and that not much

coal will be built, it is not clear how this point would

fit in?
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promote fuel diversity over the long term, and will not have 

adverse effects on the supply of electricity.

Identifying partial CCS as the BSER will not have adverse 

impacts on the structure of the power sector because, as noted, 

for reasons related to the cost differential between natural 

gas-fired and coal-fired electricity, very little, if any, new 

coal-fired EGUs are projected to be built, and at least some of 

those that may be built would be expected to include CCS 

technology in any event.

In addition, identifying partial CCS as the BSER for coal 

will be beneficial to coal-fired electric generation, and 

therefore fuel diversity, over the long term. This is because 

identifying partial CCS as BSER eliminates uncertainty as to 

future control obligations for coal-fired capacity. Currently, 

any new coal-fired source that constructs without CCS faces the 

risk that future state or federal controls may require carbon 

capture, which would require the source to retrofit to CCS, 

which, in turn, is a more expensive proposition. This risk is 

heightened because power plants have expected lives of 30 to 40 

years and the likelihood of future carbon limitations can be 

expected to remain throughout that period. Any new coal-fired 

source that constructs with partial-capture CCS will achieve 

some level of CO2 emissions reductions, which lowers the risk of 
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future liability, and may provide competitive advantages over 

higher emitting sources. Because at present, new electric 

generating construction is primarily natural gas-fired, 

benefiting new coal-fired capacity, at least over the long term, 

protects fuel diversity. 

Moreover, even if requiring CCS adds sufficient costs to 

prevent a new coal-fired plants from constructing in a 

particular part of the country due to lack of available EOR to 

defray the costs, or, in fact, from constructing at all, a new 

NGCC plant can be built to serve the electricity demand that the 

coal-fired plant would otherwise serve. Thus, the present 

rulemaking does not prevent basic electricity demand from being 

met, and thus does not have an adverse effect on the supply of 

electricity. As noted above, the EPA is authorized to promulgate 

standards of performance under CAA § 111 that may have the 

effect of precluding construction of sources in certain 

geographic locations or in certain locations. 

4. Environmental considerations

Identifying partial CCS as the BSER for coal-fired power 

plants protects the environment by preventing large amounts of 

CO2 emissions from new fossil fuel-fired utility boilers and IGCC 

units. As noted, CCS is the only technology available at present 

or within the foreseeable future that provides meaningful 
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reductions in the amount of CO2 emissions in this sector.

I. Deference

As noted above, the D.C. Circuit has held that it will 

grant a high degree of deference to the EPA in determining the 

appropriate standard of performance. Because determining the 

BSER for coal-fired power plants requires balancing several 

factors, including on a nationwide basis and over time, the 

EPA’s determination that partial CCS is the BSER should be 

granted a high degree of deference.

J. CCS and BSER in locations where costs are too high to 

implement CCS

As noted above, under CAA § 111, an emissions standard may 

meet the requirements of a “standard of performance” even if it 

cannot be met by every new source in the source category that 

would have constructed in the absence of that standard. As also 

noted above, the EPA’s analysis for this proposal indicates that 

coal-fired power plants that would otherwise construct in the 

absence of the standards in this proposal may still do so.

However, we recognize that there may be some geographic 

locations where EOR is not practicably available, so that in 

those locations, the higher costs of CCS may tilt the economics 

against new coal-fired construction. Even in this case, the 
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standard would remain valid under CAA § 111, particularly 

because the basic demand for electricity could still be served 

by NGCC, which this rulemaking determines to be the “best 

system” for natural gas-fired power plants.

K. Compliance period

1. 12-operating-month period

Under today’s proposal, sources must meet the 1,100 lb 

CO2/MWh limit on a 12-operating-month rolling basis. This 12-

operating-month period is important due the inherent variability 

in power plant GHG emissions rates. 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. 

EGU efficiency has a significant impact on the source’s GHG 

emission rate. By comparison, efficiency has a smaller impact on 

the emissions rate for criteria or hazardous air pollutants 

(HAPs). This is because control of criteria pollutants and HAPs 

often involves the use of a pollution control device that 

results in significant reductions, often greater 90 percent. In 

this situation, the performance of the specific pollution 

control device impacts the emissions rate much more than the EGU 

efficiency.
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EGU efficiency can vary significantly from month to month 

throughout the year. For example, high ambient temperature can 

negatively impact the efficiency of combustion turbine engines 

and steam generating units. As a result, an averaging period 

shorter than 12 operating-months would require us to set a 

standard that could be achieved under these conditions. This 

standard could potentially be high enough that it would not be a 

meaningful constraint during other parts of the year. In 

addition, operation at low load conditions can also negatively 

impact efficiency. It is likely that for some short period of 

time an EGU will operate at an unusually low load. A short 

averaging period that accounts for this operation would again 

not produce a meaningful constraint for typical loads. 

On the other hand, a 12-operating-month rolling average 

explicitly accounts for variable operating conditions, allows 

consistent emissions rate averaging, allows for a more 

protective standard and decreased compliance burden, allows EGUs 

to have and use a consistent basis for calculating compliance 

(i.e., ensuring that 12 operating months of data would be used 

to calculate compliance irrespective of the number of long-term 

outages), and simplifies compliance for state permitting 

authorities. Because the 12-operating-month rolling average can 

be calculated each month, this form of the standard makes it 
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possible to assess compliance and take any needed corrective 

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

necessary to have a shorter averaging period for CO2 from these 

sources because the effect of GHGs on climate change depends on 

global atmospheric concentrations which are dependent on 

cumulative total emissions over time, rather than hourly or 

daily emissions fluctuations or local pollutant concentrations. 

Unlike for emissions of criteria and hazardous air pollutants, 

we do not believe that there are measureable implications to 

health or environmental impacts from short-term higher CO2

emission rates as long as the 12-month average emissions rate is 

maintained.

We solicit comment on, in the alternative, basing 

compliance requirements on an annual (calendar year) average 

basis.

2. 60-operating84-operating-month compliance period

Under today’s proposal, new fossil fuel-fired boilers and 

IGCC units will have the option to alternatively meet an 

emission standard on an 60-operating84-operating-month rolling 

basis. 

The EPA has previously offered sources optional, longerterm emission standards that are stricter than the primary 

emissions standard in combination with a longer averaging 
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period. We are proposing that this alternative emission limit 

should be between 1,000 – 1,050 lb CO2/MWh and we are requesting 

comment on what the final numerical standard should be (within 

that range) such that the 60-operating84-operating-month 

standard would be as stringent as or more stringent than the 12-

operating-month standard. 

We are also requesting comment on an appropriate 12-

operating-month standard that owners/operators electing to 

comply with the 60-operating84-operating-month standard would 

have to comply with. This standard would be numerically between

the alternate 12-operating-month standard and an emissions rate 

of a coal-fired EGU without CCS (e.g., 1,800 lb CO2/MWh). This 

shorter term standard would be more easily enforced and assure 

adequate emission reductions. 

This 60-operating84-operating-month period offers increased 

operational flexibility and will tend to compensate for shortterm emission excursions, which may especially occur at the 

initial startup of the facility and the CCS system.

L. Geologic sequestration

1. Overview

We expect that for the immediate future, virtually all of 

the CO2 captured at EGUs will be injected underground for longterm geologic sequestration at sites where enhanced oil recovery 
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is also occurring. There is an existing regulatory framework for 

geologic sequestration and enhanced oil recovery activities. We 

intend to rely upon this existing framework to verify that the 

CO2 captured from an affected unit is injected underground for 

long-term containment. More specifically, as discussed in 

section 3, the EPA is proposing to build from the existing GHG

Reporting Program 40 CFR Part 98 to track that the captured CO2

is geologically sequestered.

In addition, we recognize that types of CO2 storage 

technologies other than geologic sequestration are under 

development (e.g. precipitated calcium carbonate, etc). EGUs may 

use other types of CO2 storage technologies to meet the standard, 

once the EPA has approved its use, including methods for 

reporting, monitoring, and verifying long-term CO2 storage. We 

welcome comments on an appropriate mechanism for making this 

determination.

2. Existing regulatory framework for CCS

As noted, the EPA expects that for the immediate future, 

captured CO2 from affected units will be injected underground for 

geologic sequestration at sites where EOR is occurring. 

Underground injection is currently the only technology available 

that can accommodate the large quantities of CO2 captured at 

EGUs, and EOR provides an associated economic incentive and 
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benefit. Three solid-fuel fired EGU projects incorporating CCS–

Kemper, TCEP, and HECA – all include utilization of captured CO2

for EOR.

The EPA has promulgated, or recently proposed, several 

rules to protect underground sources of drinking water and track 

the total amount of CO2 that is supplied to the economy and 

injected underground for geologic sequestration. First, the 

EPA’s 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.254 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 and 

the associated area of elevated pressure using both direct and 

indirect methods, as appropriate. Projects are also required to 

conduct extended post-injection monitoring and site care to 

 

254

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cf

m
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track the location of the injected CO2 and monitor subsurface 

pressures until it can be demonstrated that there is no longer a 

risk of endangerment to underground sources of drinking water.

UIC Class II wells inject fluids associated with oil and 

natural gas production and the storage of liquid hydrocarbons. 

Most of the injected fluid is salt water, which is brought to 

the surface in the process of producing (extracting) oil and gas 

and subsequently re-injected. In addition, other fluids, 

including CO2, are injected to enhance oil and gas production. 

Class II regulations include site characterization, well 

construction, operating, monitoring, testing, reporting, 

financial responsibility, and closure requirements to prevent 

endangerment of underground sources of drinking water. Wells 

that inject CO2 underground for enhanced oil or gas recovery may 

be permitted as UIC Class II or Class VI wells. However, the 

designation of the appropriate well class depends, principally, 

on the risks posed or changes in the risks posed to underground 

sources of drinking water by a specific injection operation.

Second, the GHG Reporting Program covers sources that 

generate electricity (40 CFR Part 98 subpart D), sources that 

supply CO2 to the economy (40 CFR Part 98, subpart PP) and 

sources that inject CO2 underground for geologic sequestration 

(40 CFR Part 98, subpart RR). Subpart D owners or operators of 
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facilities that contain electricity-generating units must report 

emissions from electricity-generating units and all other source 

categories located at the facility for which methods are defined 

in Part 98.255 Owners or operators are required to collect 

emission data; calculate GHG emissions; and follow the specified 

procedures for quality assurance, missing data, recordkeeping, 

and reporting.

Subpart PP provides requirements for quantifying CO2

supplied to the economy.256 Affected units that capture CO2 to 

inject underground or supply offsite, are subject to all of the 

requirements under Subpart PP of the GHG Reporting Program, 

which relates to suppliers of CO2. Specifically, Subpart PP 

requires suppliers of CO2 that meet certain applicability 

requirements to report the mass of CO2 captured from production 

process unit(s) for the purposes of supplying CO2 for commercial 

applications or that capture and maintain custody of a CO2 stream 

in order to sequester or otherwise inject underground. CO2

suppliers are required to report the annual quantity of CO2

transferred offsite and for what end use, including geologic 

sequestration.

 

255 http://www.epa.gov/ghgreporting/reporters/subpart/d.html

256 http://www.epa.gov/ghgreporting/reporters/subpart/pp.html
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Subpart RR requires that facilities meeting the source 

category definition (40 CFR 98.440) for any well or group of 

wells to report basic information on the amount of CO2 received 

for injection; develop and implement an EPA-approved monitoring, 

reporting, and verification (MRV) plan; and report the amount of 

CO2 sequestered using a mass balance approach and annual 

monitoring activities. The MRV plan must be submitted and 

approved by the EPA and revised if necessary over time according 

to 40 CFR 98.448(d). The subpart RR MRV plan must include five 

major components: 

A delineation of the maximum monitoring area (MMA) and the 

active monitoring area (AMA).

An identification and evaluation of the potential surface 

leakage pathways and an assessment of the likelihood, 

magnitude, and timing, of surface leakage of CO2 through 

these pathways in the MMA.

A strategy for detecting and quantifying any surface 

leakage of CO2 in the event leakage occurs.

An approach for establishing the expected baselines for 

monitoring CO2 surface leakage.

A summary of considerations made to calculate site-specific 

variables for the mass balance equation.
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More information on the MRV plan is available in the 

Technical Support Document for the subpart RR final rule (75 FR 

75065). 

If an enhanced oil and gas recovery project holds a UIC 

Class VI permit, it is required to report under subpart RR. If 

the project holds a UIC Class II permit and is injecting a CO2

stream underground, it is not subject to subpart RR, but the 

owner or operator may choose to opt-in to subpart RR. Sources 

reporting under subpart RR, whether they are UIC Class VI or 

Class II well(s), must follow the same set of requirements. 

As stated in the preamble to the final subpart RR rule:

“while requirements under the UIC program are focused 

on demonstrating that USDWs are not endangered as a 

result of CO2 injection into the subsurface, 

requirements under the GHG Reporting Program through 

40 CFR part 98, subpart RR will enable EPA to verify 

the quantity of CO2 that is geologically sequestered 

and to assess the efficacy of GS as a mitigation 

strategy. Subpart RR achieves this by requiring 

facilities conducting GS to develop and implement a 

MRV plan to detect and quantify leakage of injected CO2

to the surface in the event leakage occurs and to 

report the amount of CO2 geologically sequestered using 

a mass balance approach, regardless of the class of 

UIC permit that a facility holds.” (75 FR 75060) 

The Internal Revenue Service relies on the existing 

regulatory frameworksubpart RR compliance to verify 

geologic sequestration when determining eligibility of 
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taxpayers claimingfor the 45Q tax credit. As stated in the 

preamble to the final subpart RR rule:

“EPA notes that the Internal Revenue Service 

(IRS) published IRS Notice 2009–83 7 to provide 

guidance regarding eligibility for the Internal 

Revenue Code section 45Q credit for CO2 sequestration, 

computation of the section 45Q tax credit, reporting 

requirements for taxpayers claiming the section 45Q 

tax credit, and rules regarding adequate security 

measures for secure GS. As clarified in the IRS 

guidance, taxpayers claiming the section 45Q tax 

credit must follow the appropriate UIC requirements. 

The guidance also clarifies that taxpayers claiming 

section 45Q tax credit must follow the MRV procedures 

that are being finalized under 40 CFR part 98, subpart 

RR in this final rule.” (75 FR 75060) 

Third, the EPA 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, into a UIC Class VI well and meet other 

conditions.257 The rationale for the rule was that any CO2 stream 

that would otherwise be defined as hazardous waste, need not be 

managed as hazardous waste, provided it is managed under other 

regulatory programs that address the potential risks to human 

health and the environment that these materials may pose. 

3. Proposal

a. Geologic Sequestration

To provide certainty and verify that CO2 captured at an 

 

257 76 Fed. Reg. 48073 (Aug. 8, 2011)
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affected unit is geologically sequestered, today’s action relies 

upon the existing regulatory framework the EPA already has in 

place under the GHG Reporting Program 40 CFR Part 98. As 

discussed in the previous section, there are key subparts (i.e., 

subpart D, PP and RR) under 40 CFR Part 98 that provide a 

transparent reporting and verification mechanism for EPA and the 

public. The EPA requires electric generating units to report CO2

emissions under subpart D. Facilities that capture CO2 are 

required to report quantities of CO2 captured and injected on 

site or transferred off-site under subpart PP. Facilities that 

inject CO2 underground for geologic sequestration report under 

subpart RR.

First, the EPA is proposing that any affected unit that 

employs CCS technology which captures enough CO2 to meet the 

1,100 lb/MWh standard must report, under 40 CFR Part 98 subpart

RR, if the captured CO2 is injected onsite. If the captured CO2

is sent offsite, then the facility injecting the CO2 underground 

must report under 40 CFR Part 98 subpart RR. As noted above, 

owners and operators of projects that inject CO2 underground and 

that are permitted under a UIC Class VI permit are required to 

comply with subpart RR. The practical impact of our proposal 

would be that owners and operators of projects injecting CO2

underground that are permitted under UIC Class II and that 
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receive CO2 captured from EGUs to meet the proposed performance 

standard will also be required to submit and receive approval of 

a subpart RR MRV plan and report under subpart RR. This proposal 

does not change any of the requirements to obtain or comply with 

a UIC permit for facilities that are subject to EPA’s UIC 

program under the Safe Drinking Water Act.

In order to use the GHG Reporting Program to ensure that 

the affected unit is sending their captured CO2 to a site 

reporting under subpart RR, the EPA proposes minor modifications 

to subpart PP, CO2 supply. We propose that a facility capturing 

CO2 from an affected unit, and therefore subject to 40 CFR Part 

98 subpart PP, must provide additional information in their 

subpart PP annual report including 1) the electronic GHG

Reporting Tool identification (e-GGRT ID) of the facility with 

the electric generating unit from which CO2 was captured, 2) the 

e-GGRT ID(s) for, and mass of CO2 transferred to, each geologic 

sequestration site reporting under subpart RR. This proposed 

amendment to the GHG Reporting Program provides a transparent 

and consistent method to track CO2 capture and sequestration 

without significantly increasing burden on the affected sources. 

If the affected unit does not report under 40 CFR Part 98 

subpart PP and comply with these proposed requirements, it will 

be considered in noncompliance with today’s proposal.
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The EPA notes that compliance with the standard of 1,100 lb 

CO2/MWh is determined exclusively by the tons of CO2 captured by 

the emitting EGU. The tons of CO2 sequestered by the geologic 

sequestration site are not part of that calculation. However, to 

verify that the CO2 captured at the emitting EGU is sent to a 

geologic sequestration site, we are building on existing 

regulatory requirements under the GHG Reporting program.

The EPA acknowledges that there can be downstream losses of 

CO2 after capture, for example during transportation, injection 

or storage. Though a well selected and operated site is expected 

to contain CO2 for the long-term, there is the potential for 

unanticipated leakage. The EPA expects these losses to be modest 

with incentives due to the market use of CO2 as a purchased 

product. There remains an issue of whether the standard itself 

should be adjusted to reflect these downstream losses. The EPA 

is not proposing to do so. Moreover, the EPA wishes to encourage 

rather than discourage EOR using captured CO2 since the practice 

makes CCS itself more economic and thus promotes use of the 

technology on which the proposed standard is based. See Sierra

Club v. Costle, 657 F. 2d at 347 (one purpose of section 111 

standards is to promote expanded use and development of 

technology).

We also emphasize that today’s proposal does not involve 
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regulation of any downstream recipients of captured CO2. That is, 

the regulatory standard applies exclusively to the emitting EGU, 

not to any downstream user or recipient of the captured CO2

(whether the captured CO2 is sold for EOR or otherwise 

sequestered underground). The requirement that the emitting EGU 

assure that captured CO2 is managed at an entity subject to the 

GHG reporting rules is thus exclusively an element of 

enforcement of the EGU standard. Similarly, the existing 

regulatory requirements applicable to geologic sequestration are 

not part of the proposed NSPS. The standard is a numeric value, 

applicable exclusively to the emitting EGU. 

The approach proposed today relies on the existing GHG

Reporting framework to ensure that CO2 captured at an affected 

unit is transferred to a facility reporting geologic 

sequestration, and it does not impose any additional 

requirements for an affected unit to demonstrate how the 

captured CO2 is transferred to a facility that is compliant with 

40 CFR 98 subpart RR. We seek comment on whether there should 

be such requirements and suggestions for what those might 

include. 

b. Alternatives to geologic sequestration

In the development of this proposal, the EPA has identified 

some potential alternatives to geologic sequestration, including 
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but not limited to CO2 stored in precipitated calcium carbonate 

and certain types of cement. The EPA solicits comment on whether 

these and other alternatives to geologic sequestration 

permanently store CO2 (so that the stack standard is assured of 

achieving its object—to capture CO2 and prevent its atmospheric 

release) and if they are technically available for EGUs to meet 

the performance standard. Consideration of how these 

alternatives could meet the performance standard involves 

understanding the ultimate fate of the captured CO2 and the 

degree to which the method permanently isolates the CO2 from the 

atmosphere, as well as existing methodologies to verify this 

permanent storage. The EPA proposes that alternatives to 

geologic sequestration could not be used until the EPA finalizes 

a mechanism to demonstrate that a non-CCS technology would 

result in permanent storage of CO2. The EPA believes that the 

number of cases where an EGU would seek to comply with the 

performance standard through an alternative to CCS will be very 

few. However, the EPA wishes to encourage development of 

alternatives to geologic sequestration that could help offset 

the cost of CO2 capture.

c. Drafting PSD permits for affected sources using geologic 

sequestration

Comment [A45]: Has EPA demonstrated that GS 

meets this standard?

EPA: Text added to VII.E.2.c.1 to support technical 

basis that GS can meet the standard.
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In most cases, sources that are subject to this NSPS will 

also be a major source or major modification under PSD and 

required to obtain a PSD permit prior to commencing 

construction. A permit is the legal tool used to establish all 

the source limitations deemed necessary by the reviewing agency 

during review of the permit application, and is the primary 

basis for enforcement of PSD requirements. A well written 

permit reflects the outcome of the permit review process 

and clearly defines what is expected of the source. The permit 

must be a "stand-alone" document that: (1) identifies the 

emissions units to be regulated; (2) establishes emissions 

standards or other operational limits to be met; (3) specifies 

methods for determining compliance and/or excess emissions, 

including reporting and recordkeeping requirements; and

(4) outlines the procedures necessary to maintain continuous 

compliance with the emission limits.

One of the criteria that must be met to obtain a PSD permit 

is that the owner or operator of the facility must demonstrate 

that emissions from construction or operation of the facility 

will not cause or contribute to air pollution in excess of “any 

other applicable emissions standard or standard of performance 

under this chapter.” 42 U.S.C. 7475(a)(3)(C); see also 42 U.S.C. 

Comment [A46]: I think this needs something 

more to show how this relates to PSD requirements 

and how you can justify putting such requirements in 

a PSD permit. 

EPA: The language has been edited.
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7410(j). Accordingly, PSD permits for EGU sources that are 

subject to this NSPS will need to reflect that, at a minimum, 

the source will meet the requirements of this NSPS. Compliance 

with the NSPS emissions standard is determined exclusively by 

evaluating emissions of CO2 at the EGU.

258

As noted in the "Implications for PSD and Title V programs" 

section of this preamble, some states have authority to issue 

PSD permits. In other cases, the EPA issues the permit. States 

with EPA-approved permitting programs have some discretion in 

making permit decisions and including the necessary conditions 

in the permit to ensure the enforceability of the 

requirements. Additionally, some states may have additional 

state-specific requirements (e.g., a renewal portfolio standard 

adopted by a state) that may affect the stringency of the 

emission limits for the permits issued in their states. Thus, 

permits for similar source types may vary from state to state 

depending on the permitting program of the state, and the casespecific PSD evaluation of the source under review. However, the 

permits for similar sources should generally contain the same 

basic information.

 

258 We note that the PSD program regulates CO2 as part of the 

“Greenhouse Gas” pollutant, which includes the aggregate group 

of the following gases: CO2, methane (CH4), nitrous oxide (N20), 

sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), and 

perfluorocarbons (PFCs).

Comment [dj47]: Per OMB:

Odd that the list of GHGs is placed in FN. Consider 

stating earlier.

EPA: As suggested, a FN as been added earlier in the 

document.
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Thus, while EPA recognizes that permit conditions may 

vary from state to state, the EPA believes it is important to 

clarify the key components that should be included in a PSD 

permit for sources subject to the NSPS, as proposed here, and 

that intend to comply with the standard using geologic storage. 

We believe the following general condition areas of a PSD permit 

would adequately show that the source will not cause or 

contribute to air pollution in excess of this NSPS: 

A BACT emissions limit that applies to the EGU (or EGUs) at 

the facility stationary source (“EGU facility” that does 

not exceed either the primary NSPS emission standard (i.e., 

as proposed, 1,100 lb CO2/MWh on a using the 12-operatingmonth rolling average) or the NSPS alternative compliance 

methodoption (i.e., as proposed, between 950 and 1,050 lb 

CO2/MWh on a 60-operating-month rolling average).

Procedures for how the EGU will demonstrate compliance with 

the permitted emissions limit, which, at a minimum, meet

the monitoring and recordkeeping requirements defined in §

60.5355.

A requirement that CO2 produced by the EGU (or EGUs) is 

reported under Subpart PP by the permittee.
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A requirement that all CO2 that is geologically sequestered 

at the site of the EGU facility is reported under subpart 

RR by the permittee.

A requirement that the captured CO2 that the permittee sends

offsite of the EGU facility is transferred to an entity 

that is subject to the requirements of Subpart RR.

We specifically request comment on this basic framework for 

PSD permits that are issued for affected EGU sources that use 

geologic sequestration.

VIII. Rationale for Emission Standards for Natural Gas-fired 

Stationary Combustion Turbines

A. Best system of emission reduction

The EPA evaluated several different control technology 

configurations as potentially representing the “best system of 

emissions reductions ... adequately demonstrated” (BSER) for new 

natural gas-fired stationary combustion turbines: (i) the use of 

full or partial capture CCS and several types of efficient 

generation without any CCS, (ii) including high efficiency 

simple cycle aeroderivative turbines and (iii) natural gas 

combined cycle (NGCC) technology. We do not consider full or 

partial capture CCS to be BSER because of insufficient 

information to determine uncertainties about technical 

feasibility and because of adverse impact on electricity prices 
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and the structure of the electric power sector. In addition, we 

do not consider simple cycle turbines to be BSER because they 

have a higher emission rate and a higher cost than NGCC 

technology. We do find NGCC technology to be the BSER because it 

is technically feasible and relatively inexpensive, its emission 

profile is acceptably low, and it would not adversely affect the 

structure of the electric power sector.

We note at the outset that currently, virtually all new 

sources in this category are using natural gas combined cycle 

(NGCC) technology. That technology is considered to be the state 

of the art for this source category. Because, in this 

rulemaking, we are considering, and selecting, NGCC as the BSER 

for this category, as a matter of terminology, to avoid 

confusion, we generally refer to the sources as natural gasfired combustion turbines, and not as NGCC sources.

1. Full and partial CCS

To determine the BSER for natural-gas-fired stationary 

source combustion turbines, we evaluated full and partial CCS 

against the criteria. We propose to reject CCS technology as the 

BSER because we cannot conclude that it meets several of the key 

criteria.

First, it is not clear that full or partial capture CCS is 

technically feasible for this source category. Unlike subpart Da 
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affected facilities, where there are full-scale plants with CCS 

that are currently under construction or in advanced stages of 

development, the EPA is aware of only one demonstration project, 

which is an approximately 40 MW slip stream installation on a 

320 MW NGCC unit. Importantly, there are some significant 

differences between natural gas-fired combustion turbines and 

solid fossil fuel-fired EGUs that lead us to this conclusion. 

First, while some of these turbines are used to serve base load

power demand, many cycle their operation much more frequently 

than coal-fired power plants. It is unclear how part-load 

operation and frequent startup and shutdown events would impact 

the efficiency and reliability of CCS. We are not aware that any 

of the pilot-scale projects have operated in that mode. None of 

the larger projects being constructed, or under development, are 

designed to operate in a cycling mode. Furthermore, the CO2

concentration in the flue gas of a natural gas combustion 

turbine is much lower (usually approximately 4 volume percent) 

than the CO2 concentration in the flue gas stream of a typical 

coal-fired plant (which is approximately 16 volume percent for a 

SCPC or CFB unit) or the syngas of an IGCC unit (in which CO2 can 

be as high as 60 volume percent), so the overall amount that can

be captured for each project is likely lower. Comment [A48]: Need a conclusion here.

EPA: We believe this is OK as written.
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Additional factors that make CCS more challenging for NGCC 

compared to coal-fired EGUs include the time it would take to 

complete the CCS project and the water use requirements. 

Requiring CCS at a NGCC facility would potentially delay the 

project more than at a coal-fired EGU. NGCC facilities can be 

constructed in about half the time required to construct a coalfired EGU. Therefore, the time necessary to construct the carbon 

capture equipment and any associated pipelines to transport the 

CO2 would have a relatively larger impact on an NGCC than a coalfired EGU. NGCC have relatively low cooling requirements for the 

steam condensing cooling cycle compared to coal-fired EGUs and 

often use dry cooling technology. The imposition of CCS would 

have a larger impact on water requirements for an NGCC facility 

compared to a coal-fired EGU.

Moreover, identifying partial or full CCS as the BSER for 

new stationary combustion turbines would have significant 

adverse effects on national electricity prices, electricity 

supply, and the structure of the power sector. Because virtually 

all new fossil fuel-fired power is projected to use NGCC 

technology, requiring CCS would add significant costs to 

electricity generation across the nation have more of an impact

on the price of electricity than the few projected coal plants

with CCS and the number of projects would make it difficult to 

Comment [A49]: Cites? Referencces? 

EPA: We are still considering this comment

Per OMB (again): Please address comment

EPA: Have editted
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implement in the short term. In addition, requiring CCS could 

lead some operators and developers to forego retiring older 

coal-fired plants and replacing them with new NGCC projects, and 

instead keep the older plants on line longer which could have

adverse emission impacts. Identifying CCS and BSER for 

combustion turbines would likely result in higher nationwide 

electricity prices and could adversely affect the supply of 

electricity, since virtually all new fossil fuel-fired power is 

projected to use NGCC technology.

We recognize that identifying full or partial CCS as the 

BSER for this source category would result in significant 

emissions reductions, but at present, we already consider 

natural gas to be a low-GHG-emitting fuel and NGCC to be a lowemitting technology. Although identifying CCS as the BSER would 

promote the development and implementation of emission control 

technology, for the reasons described, the EPA does not believe 

that CCS represents BSER for natural gas combustion turbines at 

this time.

2. Energy efficient generation technology

To determine the BSER, the EPA also evaluated the use of 

energy efficient generation technology, including high 

efficiency simple cycle aeroderivative turbines. 

Comment [A50]: And this would have 

environmental impacts, also. 
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The use of high efficiency simple cycle aeroderivative

turbines does not provide emission reductions from the current 

state-of-the-art technology, is more expensive than the current 

state-of-the-art technology, and does not develop emission 

control technology. For these reasons, we do not consider it 

BSER. According to the AEO 2013 emissions rate information, this 

type of sourceadvanced simple cycle combustion turbines haves a 

base load rating CO2 emissions rate of 1,150 lb CO2/MWh, which is 

higher than the base load rating emission rates of 830 and 760 

lb CO2/MWh for the conventional and advanced NGCC model 

facilities, respectively. 

In the April 2012 proposal, we identified NGCC as the BSER 

for this source category, and proposed a standard of 1,000 

lb/MWh. We stated:

[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 reviewed the emissions rate of natural 

gas-fired (non-CHP) combined cycle facilities used in 

the power sector that commenced operation between 2006 

and 2010 and that report complete generation data to 

EPA. Based on this analysis, nearly 95% of these 

facilities meet the proposed standards on an annual 

basis. These units represent a wide range of 

geographic locations (with different elevations and 

ambient temperatures), operational characteristics, 

and sizes.259

 

259 77 Fed. Reg. at 22,414/1.
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The same information supports our current proposal. As 

described above, NGCC has a lower cost of electricity than 

simple cycle turbines at intermediate and high capacity factors. 

In addition, NGCC has an emissions rate that is approximately 25 

percent lower than the most efficient simple cycle facilities. 

Therefore, the use of a heat recovery steam generator in 

combination with a steam turbine to generate additional 

electricity is a cost effective control for intermediate and 

high capacity factor stationary combustion turbines. Therefore, 

BSER for intermediate and high capacity factor stationary 

combustion turbines is the use of modern high efficiency NGCC 

technology.

B. Determination of the standards of performance 

Multiple commenters on the April 2012 proposal stated the 

proposed standard of 1,000 lb CO2/MWh for combined cycle 

facilities in the April 2012 proposal was too stringent and 

should be increased to a minimum of 1,100 lb CO2/MWh. Commenters 

explained that the increased use of renewable energy for 

electricity generation will require combined cycle facilities to 

startup, shutdown, cycle, and operate at part-load more 

frequently than they currently do, and that this more cyclical 

operation necessarily entails a higher emission rate. The 

commenters stated that the recent historical emissions data that 
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the EPA relied on for the original proposal does not account for 

these likely operational changes. Additional reasons given 

justifying a higher standard include the deterioration of 

efficiencies over time, the need for flexibility to use 

distillate oil as a backup fuel, the operation of combined cycle 

facilities in simple cycle mode, the fact that combined cycle 

facilities located at high elevations and/or in locations with 

high ambient temperatures are less efficient, and the fact that 

smaller combined cycle facilities are inherently less efficient 

than larger facilities. On the other hand, other commenters

stated that the final standard should be lower than proposed on 

grounds that the best performing facilities are operating below 

the original proposed standard. Multiple commenters also stated 

that the EPA should evaluate additional CEMS data to determine 

the appropriate standard.

In light of these comments, we have reviewed the CO2

emissions data from 2007 to 2011 for natural gas-fired (non-CHP) 

combined cycle units that commenced operation on or after 

January 1, 2000 and that reported complete electric generation 

data, including output from the steam turbine, to the EPA. A 

more detailed description of this emissions data analysis is 

included in a technical support document in the docket for this 

rulemaking. These 307 NGCC units are diverse in location, age, 
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capacity, and operating profile. Based on these data, we propose 

to subcategorize the turbines into the same two size-related 

subcategories currently in subpart KKKK for standards of 

performance for the combustion turbine criteria pollutants. 

These subcategories are based whether the design heat input rate 

to the turbine engine is either less than or equal to 850 

MMBtu/h or greater than 850 MMBtu/h. We further propose to 

establish different standards of performance for these two 

subcategories.

This subcategorization has a basis in differences in 

several types of equipment used in the differently sized units, 

which affect the efficiency of the units. Large-size combustion 

turbines use industrial frame type combustion turbines and may 

use multiple pressure or steam reheat turbines in the heat 

recovery steam generator (HRSG) portion of a combined cycle 

facility. Multiple pressure HRSGs employ two or three steam 

drums that produce steam at multiple pressures. The availability 

of multiple pressure steam allows the use of a more efficient 

multiple pressure steam turbine, compared to a single pressure 

steam turbine. A steam reheat turbine is used to improve the 

overall efficiency of the generation of electricity. In a steam 

reheat turbine, steam is withdrawn after the high pressure 

section of the turbine and returned to the boiler for additional 
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heating. The superheated steam is then returned to the 

intermediate section of the turbine, where it is further 

expanded to create electricity. Although HRSGs with steam reheat 

turbines are more expensive and complex than HRSGs without them, 

steam reheat turbines offer significant reductions in CO2

emission rates. In contrast, small-size combustion turbines 

frequently use aeroderivative turbine engines instead of 

industrial frame design turbines. While there is not a strict 

definition for an aeroderivative turbine, at least parts of 

aeroderivative turbines are derived from aircraft engines. 

Aeroderivative and frame turbines use different combustor 

designs, lubrication oil systems, and bearing designs. While 

aeroderivative turbines are typically more expensive than 

industrial frame turbines, they are generally more compact, 

lighter, are able to start up and shut down more quickly, and 

handle rapid load changes more easily than industrial frame 

turbines. Due to their higher simple cycle efficiencies, they 

have traditionally been used more for peak and intermittent 

purposes rather than base power generation. However, combined 

cycle facilities based on aeroderivative combustion turbines are 

available. Due to the higher efficiency of the simple cycle 

portion of an aeroderivative turbine based combined cycle

facility, the HRSG portion would contribute relatively less to 
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the overall efficiency than a HRSG in a frame turbine based 

combined cycle facility. Therefore, adding a multiple steam 

pressure and/or a reheat steam turbine to the HRSG would be 

relatively more expensive to an aeroderivative turbine based 

combined cycle facility compared to a frame based combined cycle

facility. Consequently, multiple pressure steam and reheat steam 

turbine HRSG are not widely available for aeroderivative turbine 

based combined cycle facilities. In addition, since 

aeroderivative turbine engines have faster start times and 

change load more quickly than frame turbines, aeroderivative

turbine based combined cycle facilities are more likely to run 

at part load conditions and to potentially bypass the HRSG and 

run in simple cycle mode for short periods of time than 

industrial frame turbine based combined cycle facilities.

Because of these differences in equipment and inherent 

efficiencies of scale, the smaller capacity NGCC units (850 

MMBtu/h and smaller) available on the market today are less 

efficient than the larger units (larger than 850 MMBtu/h). 

According to the data in the EPA’s Clean Air Markets Division 

database, which contains information on 307 NGCC facilities, 

there is a 7 percent difference in average CO2 emission rate 

between the small- and large-size units. This relative 

difference is consistent with what would be predicted when 
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comparing the efficiency values reported in Gas Turbine World of 

small and large combined cycle designs. Fourteen of the study 

NGCC facilities evaluated using the Clean Air Markets data have 

heat input rates of less than or equal to 850 MMBtu/h, and the 

remaining 293 are above 850 MMBtu/MWh. Two of the small combined 

cycle facilities had a maximum 12-operating-month rolling 

average emissions rate equal to or greater than 1,000 lb CO2/MWh 

and one had an maximum 12-operating-month rolling average 

emissions rate equal to or greater than 1,100 lb CO2/MWh. Twenty 

three of the large turbines had at least one occurrence of a 12-

operating-month rolling average emissions rate greater than or 

equal to 1,000 lb CO2/MWh and forty four had at least one 

occurrence of a 12-operating-month rolling average emissions 

rate greater than or equal to 950 lb CO2/MWh. Therefore, because 

over 90 percent of small and large existing NGCC facilities are 

currently operating below the emission rates of 1,100 lb CO2/MWh 

and 1,000 lb CO2/MWh, respectively, these rates are considered 

BSER for new NGCC facilities in those respective subcategories. 

These values represent the emission rates that a modern high 

efficiency NGCC facility located in the U.S. would be able to 

maintain over its life. 

To further evaluate the impact of the proposed rule we 

reviewed the GHG BACT permits for 8 recently permitted NGCC 

Comment [A51]: Add citation.

Will add
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facilities. Of these facilities, 7 are larger than 850 MMBtu/h, 

and 1 is smaller. The 7 larger ones all have emission rates 

below 1,000 lb/MWh, and as low as 880 lb/MWh. The single smaller 

unit, which is 400 MMBtu/h, has a permitted emissions rate of 

1,100 lb CO2/MWh. 

We are requesting comment on a range of 950 to 1,100 lb 

CO2/MWh (430 to 500 kg CO2/MWh) for the large turbine subcategory 

and 1,000 to 1,1501,200 lb CO2/MWh (450 to 520 545 kg CO2/MWh) 

for the small turbine subcategory. 

IX. Rationale for 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. 

We propose to recognize the environmental benefit of 

electricity generated by combined heat and power (CHP) 

facilities to account for the increased end use efficiency 

resulting from avoided transmission and distribution losses. To 

do so, we propose to allow CHP facilities, in calculating their 

emission rate in lb CO2/MWh, to deem their MWh to be 5 percent

higher than their actual MWh, which would result in them being 

deemed to have a lower emission rate for purposes of compliance 

with this rule. 

Actual transmission and distribution losses vary from Comment [M52]: Moved up.
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location to location, but we propose that this 5 percent of 

actual MWh represents a reasonable average amount for the 

avoided transmission and distribution losses for CHP facilities. 

Note that we propose to limit this 5 percent adjustment to 

facilities for which the useful thermal output is at least 20 

percent of the total output.

IX. 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. Commenters have raised 

questions regarding whether this rule will have implications for 

regulations and permits written under the CAA PSD 

preconstruction permit program and the CAA Title V operating 

permit program.

Today’s proposal should not require any additional SIP 

revisions to make clear that the Tailoring Rule thresholds –

described below - continue to apply to the PSD program.

Likewise, today’s rulemaking does not have implications for the 

Tailoring Rule thresholds established with respect to sources 

subject to title V requirements. Furthermore, this proposal does 

not have any direct applicability on the determination of Best 

Available Control Technology (BACT) for existing EGUs that 

require PSD permits to authorize a major modification of the 
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EGU. Finally, this proposal does have some implications for 

Title V fees, but EPA is proposing action to address those 

implications as discussed below.

B. Applicability of Tailoring Rule thresholds under the PSD 

Program

States with approved PSD programs in their state 

implementation plans (SIPs) implement PSD, and most of these 

States have recently revised their SIPs to incorporate the 

higher thresholds for PSD applicability to GHGs that the EPA 

promulgated under what we call the Tailoring Rule.260 Commenters 

have queried whether under the EPA’s PSD regulations, 

promulgation of a section 111 standard of performance for GHGs 

would require these states to revise their SIPs again to 

incorporate the Tailoring Rule thresholds again. The EPA 

included an interpretation in the Tailoring Rule preamble, which 

makes clear that the Tailoring Rule thresholds continue to apply 

if and when the EPA promulgates requirements under CAA section 

111. Even so, in today’s proposal, the EPA is including a 

provision in the CAA section 111 regulations that confirms this 

 

260 “Prevention of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule; Final Rule,” 75 FR 31514 (June 3, 

2010). In the Tailoring Rule, EPA established a process for 

phasing in PSD and Title V applicability to sources based on the 

amount of their GHG emissions, instead of immediately applying 

PSD and title V at the 100 or 250 ton per year or thresholds 

included under the PSD and title V applicability provisions.
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interpretation. 

However, if a state with an approved PSD SIP program that 

applies to GHGs believes that were the EPA to finalize the 

rulemaking proposed today, the state would be required to revise 

its SIP to make clear that the Tailoring Rule thresholds 

continue to apply, then (i) the EPA encourages the state to do 

so as soon as possible, and (ii) if the State cannot do so 

promptly, the EPA will assess whether to proceed with a separate 

rulemaking action to narrow its approval of that state’s SIP so 

as to assure that for federal purposes, the Tailoring Rule 

thresholds will continue to apply as of the effective date of 

the final rule that the EPA is proposing today.

In the alternative, if the Tailoring Rule thresholds would

not continue to apply when the EPA promulgates requirements 

under CAA section 111, then the EPA would assess whether to 

proceed with a separate rulemaking action to narrow its approval 

of all of the State’s approved SIP PSD programs to assure that 

for federal purposes, the Tailoring Rule thresholds will 

continue to apply as of the effective date the final rule that 

EPA is proposing today.

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 

Comment [A53]: Consider moving this text out 

of the Overview section and into the Implications 

Section. It is more informative to provide this after 

the background information.

EPA: We believe the text is OK as is.
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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 BACT. States that are authorized by the EPA to 

administer the PSD program may issue PSD permits. If a state is 

not authorized, then the EPA issues the PSD permits. 

Regulation of GHG emissions in the Light Duty Vehicle Rule 

(75 FR 25324) triggered applicability of stationary sources to 

regulations for GHGs under the PSD and title V provisions of the 

CAA. Hence, on June 3, 2010 (75 FR 31514), the EPA issued the 

“Tailoring Rule,” which establishes thresholds for GHG emissions 

in order to define and limit when new and modified industrial 

facilities must have permits under the PSD and title V programs. 

The rule addresses emissions of six GHGs: CO2, CH4, N2O, HFCs, 

PFCs and SF6. On January 2, 2011, large industrial sources, 

including power plants, became subject to permitting 

requirements for their GHG emissions if they were already 

required to obtain PSD or title V permits due to emissions of 

other (non-GHG) air pollutants.

Commenters have queried whether, because of the way that 

the EPA’s PSD regulations are written, promulgating the rule we 

propose today may raise questions as to whether the EPA must 

revise its PSD regulations –- and, by the same token, whether 
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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 and to a 

“major modification.” 40 CFR 51.166(a)(7)(i) and (iii). A “major 

modification” is defined as “any physical change in or change in 

the method of operation of a major stationary source that would 

result in a significant emissions increase . . . and a 

significant net emissions increase . . . .” Thus, for present 

purposes, the key component of these applicability provisions is 

that PSD applies to a “major stationary source.” 

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.... 
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(ii) Any pollutant that is subject to any 

standard promulgated under section 111 of the 

Act;

(iii) Any Class I or II substance subject to a 

standard promulgated under or established by 

title VI of the Act;

(iv) Any pollutant that otherwise is subject to 

regulation under the Act as defined in paragraph 

(b)(48) of this section....

40 CFR 51.166(b)(49). Thus, the PSD regulations contain a 

separate PSD trigger for pollutants regulated under the NSPS, 40

CFR 51.166(b)(49)(ii) (the “NSPS trigger provision”), so that as 

soon as the EPA promulgates the first NSPS for a particular air 

pollutant, as we are doing in this rulemaking with respect to 

the GHG air pollutant, then PSD is triggered for that air 

pollutant. 

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 NSPS trigger provision 

in 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.
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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, “major emitting facility” -- and 

“major modification,” which embodies the statutory 

term, “modification,” and it is those statutory and 
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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 open-ended 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 of the final Tailoring 

Rule, 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”).261

 

261 This position reads the regulations to be consistent with the 

CAA PSD provisions themselves. Under those provisions, PSD 

applies to any “major emitting facility,” which is defined to 

mean stationary sources that emit or have the potential to emit 

“any air pollutant” at either 100 or 250 tons per year, 

depending on the source category. CAA section 165(a), 169(1). 

EPA has long interpreted these provisions to apply PSD to a 

stationary source that emits the threshold amounts of any air 

pollutant subject to regulation. See Tailoring Rule, 75 FR 

31579. Under these provisions, at present, PSD is already 
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As a result, the EPA believes that states that incorporated 

the Tailoring Rule thresholds into their SIPs may take the 

position that they also incorporated the EPA’s interpretation in 

the preamble that the thresholds apply to the definition “major 

stationary source.”

Even so, 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 add new provisions to the NSPS regulations, 

although not the PSD regulations, to make explicit that the NSPS 

trigger provision in the PSD regulations incorporates the 

Tailoring Rule thresholds.262 Under these new provisions, to the 

extent that promulgation of section 111 requirements for GHGs 

triggers PSD requirements for GHGs, it does so only for GHGs 

emitted at or above the Tailoring Rule thresholds.

The EPA requests that all States with approved SIP PSD 

programs that apply to GHGs indicate during the comment period 

on this rule whether, (i) in light of EPA’s interpretation that 

the Tailoring Rule thresholds continue to apply even when the 

EPA promulgates the first NSPS for GHGs, and (ii) assuming that 

 

applicable to GHGs because GHGs are already subject to 

regulation, and regulating GHGs under CAA section 111 does not 

create any additional type of PSD trigger.

262 The Tailoring Rule thresholds themselves are not at issue in 

this rulemaking.
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EPA finalizes the added provisions to the section 111 

regulations proposed today, 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 will 

assess whether to propose a rule shortly after the close of the 

comment period, to narrow its approval of that state’s SIP so as 

to assure that for federal purposes, the Tailoring Rule 

thresholds will continue to apply as of the effective date of 

the final rule that the EPA is proposing today. Such a rule 

would be comparable to what we call the SIP PSD Narrowing Rule 

that EPA promulgated in December, 2010.263 The EPA may finalize 

such a narrowing rule at the same time that it finalizes this 

NSPS rule.

C. Implications for BACT determinations under PSD

New major stationary sources and major modifications at 

existing major stationary sources are required by the CAA to, 

among other things, obtain a permit under the PSD program before 

commencing construction. A source is subject to PSD by way of 

its proposed construction and the effect of the construction and 

 

263 “Limitation of Approval of Prevention of Significant 

Deterioration Provisions Concerning Greenhouse Gas EmittingSources in State Implementation Plans; Final Rule,” 75 Fed. Reg. 

82,536 (December 30, 2010). 
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operation of the new equipment on emissions. The emission 

thresholds that define PSD applicability can be found in 40 CFR 

51 and 52 and are discussed briefly in the above section. 

As mentioned above, sources that are subject to PSD must 

obtain a preconstruction permit that contains emission 

limitations based on application of Best Available Control 

Technology for each regulated NSR pollutant. The BACT 

requirement is set forth in section 165(a)(4) of the CAA, and in 

EPA regulations under 40 CFR Parts 51 and 52. These provisions 

require that BACT determinations be made on a case-by-case basis 

after consideration of the record in each case. CAA § 169(3) 

defines BACT as:

an emissions limitation (including a visible emission 

standard) based on the maximum degree of reduction for each 

pollutant subject to regulation under the Clean Air Act 

which would be emitted from any proposed major stationary 

source or major modification which the Administrator, on a 

case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, 

determines is achievable for such facility through 

application of production processes and available methods, 

systems, and techniques, including fuel cleaning, clean 

fuels, or treatment or innovative fuel combustion 

techniques for control of each such pollutant....

Furthermore, this definition in the CAA specifies that 

“[i]n no event shall application of [BACT] result in emissions 

of any pollutants which will exceed the emissions allowed by any 

applicable standard established pursuant to section 111 or 112 
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of the Act.” This has historically been interpreted to mean that 

BACT cannot be less stringent than any applicable standard of 

performance under the NSPS. See e.g. EPA, PSD and Title V 

Permitting Guidance for Greenhouse Gases, p. 20-21 (March 2011). 

Thus, upon completion of an NSPS, EPA reads the CAA to mean that 

the NSPS establishes a “BACT Floor” for PSD permits issued to 

affected facilities covered by an NSPS. It is important to note 

that a proposed NSPS does not establish the BACT Floor for 

affected facilities seeking a PSD permit. This is explained on 

page 25 of EPA’s PSD and Title V Permitting Guidance for 

Greenhouse Gases (March 2011):

In cases where a NSPS is proposed, the NSPS will not be 

controlling for BACT purposes since it is not a final 

action and the proposed standard may change, but the record 

of the proposed standard (including any significant public 

comments on EPA’s evaluation) should be weighed when 

considering available control strategies and achievable 

emission levels for BACT determinations made that are 

completed before a final standard is set by EPA. However, 

even though a proposed NSPS is not a controlling floor for 

BACT, the NSPS is an independent requirement that will 

apply to an NSPS source that commences construction after 

an NSPS is proposed and carries with it a strong 

presumption as to what level of control is achievable. This 

is not intended to limit available options to only those 

considered in the development of the NSPS. (p.25)

However, as noted in the “transitional sources under the 

current proposal” section of this notice, once an NSPS is 

finalized, then the standard applies to any new source or 
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modification that meets the applicability of the NSPS and has 

not commenced construction as of the date of the proposed NSPS. 

It is also important to keep in mind that BACT is a caseby-base review that considers a number of factors, and the fact 

that a minimum control requirement is established by EPA through 

an NSPS does not mean that a more stringent control cannot be 

chosen by the permitting agency. The EPA’s PSD and Title V 

Permitting Guidance for Greenhouse Gases (March 2011) discusses 

considerations (e.g., technical feasibility, economic impacts 

and other costs, and environmental and energy impacts) when 

evaluating BACT for CO2, as well as other greenhouse gases.

Under this proposed NSPS, an affected facility is a new 

EGU. In this rule we are not proposing standards for modified or 

reconstructed sources. However, since both a new and existing 

power plant can add new EGUs to increase generating capacity, 

this NSPS will apply to both a new, greenfield EGU facility or 

an existing facility that adds EGU capacity by adding a new EGU 

that is an affected facility under this NSPS. While this latter 

scenario can be considered the modification of existing source 

under PSD, this proposed NSPS will not apply to modified or 

reconstructed sources as those terms are defined under Part 60. 

Thus, this NSPS would not establish a BACT floor for sources 

that are modifying an existing EGU, for example, by adding new 
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steam tubes in an existing boiler or replacing blades in their 

existing combustion turbine with a more efficient design.

Furthermore, our analysis for this proposed NSPS considers 

only to extent which particular pollution control techniques are 

BSER for new units, and does not evaluate whether such 

techniques also qualify as BSER for modified or reconstructed 

sources under Part 60 or are otherwise achievable methods for 

reducing GHG emission from such sources considering economic, 

environmental, and energy impacts. Therefore, we do not believe 

that the content of this rule has any direct applicability on 

the determination of BACT for any Part 60 modified or 

reconstructed sources obtaining a PSD permit.

D. Implications for title V program

Under the title V program, a source that emits any air 

pollutant subject to regulation at or above specified thresholds 

(along with certain other sources) is required to obtain an 

operating permit. This permit includes all of the CAA 

requirements applicable to the source. These permits are 

generally issued through EPA-approved State title V programs.

As the EPA explained in the Tailoring Rule preamble, title 

V applies to a “major source,” CAA section 502(a), which is 

defined to include, among other things, certain sources, 

including any “major stationary source,” CAA section 501(2)(B), 
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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 the definition 

of “subject to regulation.” The EPA described its action as 

follows in the preamble to the Tailoring Rule:

Thus, EPA is adding the phrase “subject to 

regulation” to the definition of “major source” under 

40 CFR 70.2 and 71.2. EPA is also adding to these 

regulations a definition of “subject to regulation.” 

Under the part 70 and part 71 regulatory changes 

adopted, the term “subject to regulation,” for 

purposes of the definition of “major source,” has two 

components. The first component codifies the general 

approach EPA recently articulated in the 

“Reconsideration of Interpretation of Regulations That 

Determine Pollutants Covered by Clean Air Act 

Permitting.” 75 FR 17704. Under this first component, 

a pollutant “subject to regulation” is defined to mean 

a pollutant subject to either a provision in the CAA 

or regulation adopted by EPA under the CAA that 

requires actual control of emissions of that pollutant 

and that has taken effect under the CAA. See id. at 

17022-23; Wegman Memorandum at 4-5. To address 

tailoring for GHGs, EPA includes a second component of 

the definition of “subject to regulation,” specifying 

that GHGs are not subject to regulation for purposes 

of defining a major source, unless as of July 1, 2011, 

the emissions of GHGs are from a source emitting or 

having the potential to emit 100,000 tpy of GHGs on a 

CO2e basis.

75 Fed. Reg. at 31,583. 
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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 applicability 

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 GHGrelated applicable requirements. We have concluded that this 

rule will not affect non-major sources and there is no need to 

consider whether to exempt non-major sources.

Note that we propose to move the definition of “Greenhouse 

gases” currently within the definitions of “Subject to 

regulation” in 40 CFR 70.2 and 71.2 to a definition within 70.2 

and 71.2 to promote clarity in the regulations. 

E. Implications for title V fee requirements for GHGs

The issuance of the final EGU GHG NSPS will trigger certain 

requirements related to title V fees for GHG emissions under 40 
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CFR part 70 and part 71. States (and approved local and tribal 

permitting authorities) will be required to include GHG 

emissions in determining whether they collect adequate fees, if 

the state relies on the “presumptive minimum” approach to 

demonstrating fee adequacy. In addition, sources subject to 

federal permitting under part 71 will be required to include GHG 

emissions in calculating their annual permit fee.264 The EPA is 

proposing changes to the title V rules to limit the impact of 

the requirements that would otherwise occur under the existing 

rules, provide flexibility to the states to ensure sufficient 

funding for their programs, and to ensure that the requirements 

are consistent with the Clean Air Act.

These requirements would be triggered because the 

regulation of GHGs under section 111 for the first time through 

the issuance of the EGU GHG NSPS would make GHGs a “regulated 

air pollutant,” as defined under 40 CFR parts 70 and 71, a 

“regulated pollutant (for presumptive fee calculation)” as 

defined under part 70 and a “regulated pollutant (for fee 

calculation)” as defined under part 71. 

 

264 Also, we understand several states may have fee requirements 

that are structured with similar definitions that would result 

in GHGs being added to the list of air pollutants that are 

subject to title V fees.
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Under the current part 70, regulation of GHGs under section 

111 through the issuance of any NSPS would result in GHGs being 

added to the list of air pollutants used in “presumptive 

minimum” fee calculations. Also, in EPA’s part 71 permit 

program, and possibly in certain state part 70 programs, 

issuance of a NSPS standard would result in GHGs being added to 

the list of air pollutants that are subject to fee payment by 

sources. This effect of adding GHGs to certain title V fee 

requirements was not discussed in the previous original proposal 

for the EGU GHG NSPS; however, several public comments were 

raised on this issue, and a number of related issues, during the 

public comment period on the previous original proposal for the 

EGU GHG NSPS.

In this re-proposal of the EGU GHG NSPS, we discuss this 

issue for GHGs related to title V fees and propose rule 

amendments that will enable permitting authorities to collect 

fees as needed to support their programs, and to avoid excessive 

and unnecessary fees. We also respond to and clarify some 

related issues raised by commenters on the previous original

proposal. 

In summary, we are proposing to exempt GHGs from the 

presumptive fee calculation, yet account for the costs of GHG 

permitting program costs through a cost adjustment to ensure 
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that fees will be collected that are sufficient to cover the 

program costs. We are also proposing that permitting agencies 

that do not use the presumptive fee approach can continue to 

demonstrate that their fee structures are adequate to implement 

their title V programs.

Prior to explaining our proposal in more detail, the 

following discussion provides background on the fee requirements 

of the title V rules, what those fees cover in terms of 

agencies’ program implementation, what additional activities 

agencies might be expected to have to undertake as a result of 

GHGs becoming “regulated pollutants” under the NSPS, what the 

GHG Tailoring Rule said about title V fees, background on title 

V fees in the context of the previous original proposal for the 

EGU GHG NSPS, and existing limitations on the collection of GHG 

fees. 

1. Background

a. The title V rules

Title V is implemented through 40 CFR parts 70 and 71. 

Part 70 defines the minimum requirements for state, local and 

tribal (state) agencies to develop, implement and enforce a 

title V operating permit program; these programs are developed 

by the state and the state submits a program to EPA for a review 

of consistency with part 70. There are about 112 approved part 
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70 programs in effect, with about 15,000 part 70 permits 

currently in effect. (See Appendix A of 40 CFR part 70 for the 

approval status of each state program). Part 71 is a federal 

permit program run by the EPA, primarily where there is no part 

70 program in effect (e.g., in Indian country, the federal Outer 

Continental Shelf and for offshore Liquified Natural Gas

terminals).265 There are about 100 part 71 permits currently in 

effect (most are in Indian country). 

b. The fee requirements of title V

Section 502(b)(3)(A) of the Act requires owners or 

operators of all sources subject to permitting to “pay an annual 

fee, or the equivalent over some other period, sufficient to 

cover all reasonable (direct and indirect) costs required to 

develop and administer the permit program.” Section 502(b)(3)(B) 

of the Act generally sets forth the methods for determining 

whether a permitting authority is collecting sufficient fees in 

total to cover the costs of the program. First, under the 

“presumptive minimum” approach set forth in section 

502(b)(3)(B)(i), a state can satisfy the requirement by showing 

 

265 In some circumstances, EPA may delegate authority for part 71 

permitting to another permitting agency, such as a tribal agency

or a state. The EPA has entered into delegation agreements for 

certain part 71 permitting activities with at least one tribal 

agency. There are currently no states that do not have an 

approved part 70 program; thus, there is no need for EPA to 

delegate part 71 permitting authority to any state at this time.
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that “the program will result in the collection, in the 

aggregate, from all sources subject to [the program] of an 

amount not less than $25 per ton of each regulated pollutant, or 

such other amount as the Administrator may determine adequately 

reflects the reasonable costs of the permit program.” The 

statute further provides that emissions in excess of 4,000 tpy 

for any one pollutant need not be included in the calculation, 

and that the initial fee rate ($25 per ton) shall be adjusted 

for inflation266. See section 502(b)(3)(B)(iii)-(v). Also, 

section 502(b)(3)(B)(ii) of the Act sets forth a definition of 

“regulated pollutant” for purposes of the presumptive fee 

calculation that includes, in part, each pollutant regulated 

under section 111 of the Act, such as any pollutants regulated 

under any NSPS, which would make GHG a “regulated pollutant” 

based on our proposal for the EGU GHG NSPS. Each of the title V 

rules that implement title V contains a definition of “regulated 

air pollutant”267 (at 40 CFR 70.2 and 71.2) that tracks the Act 

 

266 The current corresponding part 70 fee rate, adjusted for 

inflation, is approximately $47 per ton.

267 The definition reads in relevant part: “Regulated air 

pollutant means the following: (1) Nitrogen oxides or any 

volatile organic compounds; (2) Any pollutant for which a 

national ambient air quality standard has been promulgated; (3) 

Any pollutant that is subject to any standard promulgated under 

section 111 of the Act; (4) Any Class I or II substance subject 

to a standard promulgated under or established by title VI of 

the Act; or (5) Any pollutant subject to a standard promulgated 
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definition of “regulated pollutant.” The “regulated air 

pollutant" definition is used in the regulatory text for 

application and other purposes and it is relevant for fee 

purposes because it is cross-referenced as the starting point 

for two fee-related definitions: “regulated pollutant (for 

presumptive fee calculation)268” in 40 CFR 70.2 and “regulated 

pollutant (for fee calculation)269” in 40 CFR 71.2.

Alternatively, if a state does not wish to show it collects 

an amount of fees at least equal to the presumptive minimum 

amount, section 502(b)(3)(B)(iv) provides that a program may be 

approved if the state demonstrates that it collects sufficient 

fees to cover the costs of the program, even if that amount is 

below the presumptive minimum.

The presumptive fee approach of the statute is reflected in 

the part 70 regulations for those states that wish to use it for 

 

under section 112 or other requirements established under 

section 112 of the Act, including sections 112(g), (j), and (r) 

of the Act . . .” 

268 40 CFR 70.2 defines regulated pollutant (for presumptive fee 

calculation) to mean: “any ‘regulated air pollutant’ except the 

following: (1) Carbon monoxide; (2) Any pollutant that is a 

regulated air pollutant solely because it is a Class I or II 

substance to a standard promulgated under or established by 

title VI of the Act; or (3) Any pollutant that is a regulated 

air pollutant solely because it is subject to a standard or 

regulation under section 112(r) of the Act.”

269 40 CFR 71.2 defines regulated pollutant (for fee calculation) 

the same as regulated pollutant (for presumptive fee calculation 

in 40 CFR 70.2.
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fee adequacy purposes. In addition, for the federal part 71 

permitting program, which the EPA implements directly, the EPA 

has adopted rules to ensure that it collects adequate fees, 

consistent with the statute. These statutory requirements for 

fees are reflected in 40 CFR 70.9 and 71.9, respectively.

Although the Clean Air Act and part 70 require that a title 

V permit program must collect sufficient fees to cover the costs 

of the program, neither the Act nor part 70 specifies the 

details of how those fees must be charged to particular sources 

in their fee schedules. The part 70 regulations specifically 

provide, at 40 CFR 70.9(b)(3), that a “state program’s fee 

schedule may include emission fees, application fees, service 

fees or other types of fees, or any combination thereof.” Many 

states use emission fees and other types of fees in combination 

in their fee schedules and we understand that some state fee 

schedules are structured such that they would result in GHG fees 

being required when GHGs are regulated under any NSPS. For 

example, states may have chosen for convenience sake to use the 

“regulated pollutant (for presumptive fee calculation)” 

definition of part 70, or a similar state definition, to 

identify the pollutants subject to fees as part of their fee 

schedule. For part 71, the EPA chose to promulgate an emissionsbased fee schedule that uses the definition of “regulated 
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pollutants (for fee calculation)” to identify the pollutants 

subject to fees, and thus, part 71 is structured such that GHG 

fees would be required when GHGs are regulated under any NSPS.

State fee schedules charge emissions-based fees that range 

from about $15 to $100 or more per ton for each air pollutant 

for which they charge a fee, while part 71 charges about $48 per 

ton270, effective for calendar year 2013, for each of the 

“regulated pollutants (for fee calculation).” See 40 CFR 

71.9(c)(1). Most part 70 and part 71 programs require sources to 

pay the fees on an annual basis, initially with the submittal of 

its permit application, and thereafter, on the anniversary of 

application submittal. See 40 CFR 70.9(a), 71.9(e). 

Section 502(b)(3)(A) of the CAA broadly requires permit 

fees “sufficient to cover all reasonable (direct and indirect) 

costs required to develop and administer the permit program” 

including the reasonable costs of: “(i) reviewing and acting 

upon any application for such a permit, (ii) implementing and 

enforcing the terms and conditions of any such permit (not 

including any court costs or other costs associated with any 

 

270 Note that the part 71 fee rate and the part 70 presumptive 

fee rate are slightly different because the part 71 rate was set 

based on an analysis that showed that the EPA needed slightly 

more than the presumptive minimum to collect sufficient revenue 

to fund the program.
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enforcement action), (iii) emissions and ambient monitoring, 

(iv) preparing generally applicable regulations, or guidance, 

(v) modeling, analyses, and demonstrations, and (vi) preparing 

inventories and tracking emissions.” These statutory 

requirements were incorporated into the regulations at 40 CFR 

70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on 

EPA’s interpretation of this list of activities in several 

memoranda,271 and these activities have been considered in the 

context of the ICR development and renewal process for part 70 

and 71. 

c. How EPA Addressed Title V Fees in the Tailoring Rule 

The GHG Tailoring Rule concerned when sources are required 

to obtain permits under prevention of significant deterioration 

(PSD) and title V due to emissions of GHGs. (See Prevention of 

Significant Deterioration and Title V Greenhouse Tailoring Rule; 

Final Rule [the Tailoring Rule]; 75 FR 31514, June 3, 2010.) 

GHGs became subject to regulation as a result of the Light Duty 

Vehicle Rule (75 FR 25,234, May 7, 2010), and the Tailoring Rule 

established emissions thresholds for purposes of PSD and title 

 

271 For example, see “Reissuance of Guidance on Agency Review of 

State Fee Schedules for Operating Permits Programs Under Title 

V”; from John S. Seitz, Director, Office of Air Quality Planning 

and standards, to Air Division Directors, Regions I-X; August 4, 

1993; available at 

http://www.epa.gov/region07/air/title5/t5memos/fees.pdf.
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V. Neither the Light Duty Vehicle Rule nor the Tailoring Rule 

made any changes that would cause GHGs to meet the definition of 

“regulated air pollutant,” or related fee definitions in the 

title V regulations. EPA has promulgated no other standards that 

would trigger fee requirements for GHGs in title V programs.

The GHG Tailoring Rule addressed the possible need for 

states and the EPA to charge fees for GHG emissions based on the 

burdens imposed under the Tailoring Rule for states to 

incorporate GHGs into permits or to issue permits to sources 

based on GHG emissions. We did not revise the part 70 rules to 

require fees for GHGs, although we did clarify that states have 

the option of charging fees to recover the costs of permitting 

related to GHGs. Also, we did not revise part 71 to require GHG 

fees, and we stated that we would review the need for additional 

fees to cover program costs for GHGs over time. (See 75 FR 31526 

and 31584.) We retained this approach in last year’s Step 3 

Tailoring Rule. (See Prevention of Significant Deterioration and 

Title V Greenhouse Tailoring Rule Step 3, GHG Plantwide 

Applicability Limitations and GHG Synthetic Minor Limitations, 

(Step 3 of the Tailoring Rule), 77 FR 41051, July 12, 2012).

d. Title V fees in the previous EGU GHG NSPS proposal

The previous EGU GHG NSPS proposal did not discuss any 

title V fee issues related to regulating GHGs under a section 
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111 standard; however, several public commenters (two state 

agencies and one industry group) raised several concerns or 

asked for clarification on a number of issues related to title V 

fees during the public comment period. Two of these commenters 

requested clarification as to whether the issuance of the EGU 

GHG NSPS would make either GHGs or CO2 subject to regulation such 

that title V fee requirements would be triggered for either of 

these pollutants. One commenter requested clarification on 

whether fees are required for “regulated NSR pollutants,” such 

as GHG. One commenter questioned whether the rationale of the 

Tailoring Rule for deferring fees for GHGs would also apply to 

the EGU GHG NSPS. Finally, one commenter asked us to clarify if 

a state could refrain from charging a fee for CO2 (based on the 

issuance of the EGU GHG NSPS) if the state otherwise generates a 

fee sufficient to meet the “program support requirements” of 

title V. Note that we address the substance of several of these 

comments related to title V fees in section B of this portion of 

the proposal. 

e. Unique Characteristics of GHGs relative to Fees

There are a number of provisions in part 70 and part 71 and 

characteristics of GHGs that are relevant to any discussion 

related to charging fees for GHGs. First, it should be noted 

that GHG are emitted in extremely high quantities relative to 
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other air pollutants, such as the criteria pollutants, which are 

typically emitted by combustion sources that also emit GHGs. A 

review of emission factors in EPA’s AP-42 shows that GHGs are 

typically emitted in quantities as much as one thousand or more 

times higher than CO or NOX and many other pollutants as a 

product of combustion for a given mass of fuel272. Thus, we 

expect that charging fees for GHGs at the same rate (in dollars 

per ton) as other regulated air pollutants would lead to fee 

revenue that would be excessive, far beyond the reasonable costs 

of the program. Even though most part 70 and 71 programs cap 

total fees at 4,000 tons per air pollutant per year273 we note 

that the total GHG fee for a particular source under the current 

part 71 rule could still be significant, up to about $194,000 

per year for GHGs alone, if GHGs are charged at the same rate as 

for other “regulated pollutants (for fee calculation).”274

 

272 See AP-42, Compilation of Air Pollution Emission Factors, 

Volume I, Stationary and Area Sources, Fifth Edition. For 

example, for external combustion of bituminous and subbituminous 

coals, see table 1.1-3 for NOx and CO emission factors and table 

1.1-20 for CO2 emissions factors.

273 Consistent with the option afforded states at 40 CFR 

70.9(b)(2)(ii)(B) and the EPA’s fee schedule at 40 CFR 

71.9(c)(5).

274 Note that most sources that emit GHGs, particularly major 

sources of GHG, also emit other regulated air pollutants subject 

to fees; thus, they would pay significant title V fees even if a 

fee for GHGs is not charged.
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Second, unlike other pollutants, GHGs can be estimated in two 

ways: by mass or by CO2 equivalent (CO2e). While the title V 

permitting threshold for the Tailoring Rule was established at 

100,000 CO2e and 100 tpy mass, the fee provisions of part 70 and 

71, and we believe the fee provisions of the majority, if not 

all, state programs, charge fees on a mass (per ton), rather 

than on a CO2e

275, basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR 

71.9(c)(1).

2. Response to comments on fees from the previous EGU GHG NSPS 

proposal

In response to concerns raised by commenters, and because 

response to certain of these issues will help to provide a 

better proposal, we respond to several of these comments at this 

time. In response to the question as to whether CO2 or GHGs would 

be regulated by the EGU GHG NSPS, we clarify that GHG would be 

regulated under section 111 of the Act and that this does not 

affect the applicability thresholds previously established for 

PSD and title V in the Tailoring Rule. First, the EPA considers 

 

275 The term “tpy CO2 equivalent emissions” (or “CO2e”) is defined 

within the definition of “subject to regulation” in 40 CFR 70.2 

and 71.2. The definitions read, in relevant part, “[CO2e] shall 

represent an amount of GHGs emitted, and shall be computed by 

multiplying the mass amount of emissions (tpy), for each of the 

six greenhouse gases in the pollutant GHGs, by the gas's 

associated global warming potential published at Table A-1 to 

subpart A of part 98 of this chapter—Global Warming Potentials, 

and summing the resultant value for each to compute a tpy CO2e. 
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the pollutant being regulated by the NSPS for the purposes of 

PSD and title V to be GHG, rather than CO2. Thus, under this 

interpretation, this NSPS has not caused CO2 to be treated as a 

“regulated air pollutant” under the third prong of the 

definition of “regulated air pollutant” contained in 40 CFR 70.2 

and 71.2, which includes “[a]ny pollutant that is subject to any 

standard promulgated under section 111 of the Act,” because it 

causes GHG, rather than CO2, to be the “regulated air pollutant.” 

Second, although EPA’s PSD regulations provide that regulation 

of GHGs under CAA section 111 triggers PSD applicability, the 

Tailoring Rule thresholds for GHG continue to apply for major 

source applicability for both the PSD and Title V permitting 

programs.276 In addition, we are proposing regulatory text in 

section 60.46Da(f) and section 60.4315(b) to make clear that for 

purposes of PSD and title V, greenhouse gases (not carbon 

dioxide) is the pollutant subject to a standard promulgated 

under section 111.

In response to the comment inquiring whether the rationale 

of the Tailoring Rule remains relevant for deferring action on 

fees, we are proposing several revisions to the part 70 and part 

 

276 We have clarified these points further in a memorandum added 

to the docket for this rulemaking (“PSD Threshold Memorandum,” 

dated May 8, 2012). See document number EPA-HQ-OAR-2011-0660-

7602.

Comment [A54]: Note: identical reg text on this 

point appears in 2 places in the regs. I am not sure 

why and was thinking perhaps one could be deleted 

so I only cited one place here.
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71 regulations in response to the proposed regulation of GHGs 

under section 111, while retaining the general approach that we 

described in the Tailoring Rule. At the time of the promulgation 

of the Tailoring Rule, there were no section 111 standards (or 

other standards) that had been promulgated that would have 

resulted in title V fee requirements being triggered for GHGs. 

Thus the rationale we use now is necessarily different that the 

rationale we used for the Tailoring Rule fee discussion. If the 

commenter is referring to the requests of certain state agencies 

in their comments on the Tailoring Rule for the EPA to set a 

presumptive fee of GHGs, we are responding to that request in 

this proposal by proposing to set a presumptive fee cost 

adjustment. If the commenter is referring to the fee flexibility 

afforded by 40 CFR 70.9(b)(3), we respond that we are not 

proposing to revise that regulatory provision. A state commenter 

generally asked us if it could refrain from requiring a fee for 

CO2 (or GHG) if it could show that it can otherwise generate a 

fee sufficient to meet the “program support requirements” of 

title V. The response to this comment is yes, based on the 

following analysis. Title V requires permitting authorities to 

collect fees from sources that are ‘‘sufficient to cover all 

reasonable (direct and indirect) costs required to develop and 
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administer [title V] programs.”277 States have adopted various 

fee schedules to meet this requirement. 40 CFR 70.9(b)(3) allows 

a State program's fee schedule to include emissions fees, 

application fees, service-based fees or other types of fees, or 

any combination thereof, to meet the requirements of the 

collection and retention of revenues sufficient to cover the 

permit program costs. Further, states are not required to 

calculate fees on any particular basis or in the same manner for 

all part 70 sources or for all regulated air pollutants, 

provided that they collect a total amount of fees sufficient to 

meet the program support requirements. This flexibility is also 

true for states that use the presumptive minimum approach to 

demonstrate they would collect sufficient fees to fund the 

program. In the final Tailoring Rule (75 Fed. Reg. 31584, June 

3, 2010), we did not change our fee regulations to require title 

V fees for GHGs or require new fee demonstrations from states 

related to permitting GHGs, and we have retained the same 

policies for the purposes of the recent Step 3 rule (77 Fed. 

Reg. 41051, July 12, 2012). In the final Tailoring Rule, we 

recommended that each state, local or tribal program review its 

resource needs for GHGs and determine if the existing fee 

 

277 The fee provisions are set forth in CAA section 502(b)(3) and 

in our regulations at 40 CFR 70.9 and 71.9.
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approaches would be adequate. If those approaches were not 

adequate, we suggested that they should be proactive in raising 

fees to cover the direct and indirect costs of the program or 

develop other alternative approaches to meet the shortfall. 

Therefore, we agree with the commenter that consistent with 40 

CFR 70.9(b)(3), if a state generates fees “sufficient to meet 

the program support requirements,” without charging fees based 

on GHG emissions, then a fee does not have to be charged 

specifically for GHGs.278 Thus, this proposal does not seek to 

revise fee schedule flexibility for states and instead focuses 

on revising the presumptive minimum fee provisions under part 70 

to more appropriately account for GHG program costs. This notice 

does not propose any new requirements for states that do not use 

the presumptive approach to establish adequacy of fees.

3. Today’s proposal to address GHGs in title V fees

In this part of the preamble we explain and solicit comment 

on options to address the title V fee issues raised by the 

proposed regulation of GHGs under this NSPS. In sum, we propose 

to exempt GHGs from the presumptive fee calculation, yet account 

for the costs of GHG permitting through a cost adjustment to 

 

278 Conversely, where a state cannot show that sufficient fees 

are being collected, the state would need to modify its fee 

schedule (which could, but need not, involve charging fees for 

GHG emissions).
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ensure that fees will be collected that are sufficient to cover 

the program costs. We request comment on these proposals, 

particularly from state, local, and tribal permitting agencies, 

and particularly with respect to which approach would be most 

appropriate, feasible, and workable and result in fees that 

would be adequate to cover the direct and indirect costs of 

permitting GHGs. We also invite comments on ways to improve this 

proposal and/or address this issue in other ways consistent with 

the same principles, concerns, and statutory authority that we 

have described for this proposal.

a. Exemption of GHGs from presumptive fee calculation

For the reasons discussed earlier in this proposal, we 

propose to exempt GHGs from the definition of “regulated 

pollutant (for presumptive fee calculation)” in 40 CFR 70.2 in 

order to exclude GHGs from being subject to the statutory fee 

rate set for the presumptive minimum fee calculation of 40 CFR 

70.9(b)(2)(i). Pursuant to the authority of section 

502(b)(3)(B)(i), we are proposing to determine that utilizing 

the statutory fee rate for GHGs would be inappropriate because 

it would result in excessive fees, far above the reasonable 

costs of a program. We are proposing a significantly smaller 

cost adjustment for GHGs to reflect the program costs related to 

GHGs. 
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We have estimated the cost of permitting GHGs associated 

with the Tailoring Rule thresholds in an economic analysis 

performed for the Tailoring Rule and in several documents 

related to Information Collection Request (ICR) requirements for 

part 70 and 71, and we believe these analyses provide a basis 

for estimating the costs related to GHG permitting for the 

typical permitting authority. Thus, we propose to revise 40 CFR 

70.9(b)(2)(i) to add a GHG cost adjustment to account for the 

GHG permitting program costs. 

b. Addition of a GHG cost adjustment to the presumptive minimum 

fee calculation 

We propose to revise the presumptive minimum fee provisions 

of part 70 to add a GHG cost adjustment to account for the 

typical GHG permitting program costs that may not already be 

covered by the existing presumptive minimum fee provisions of 

parts 70 and 71. The current presumptive minimum fee provisions 

of the title V rules implements the statutory mandate to collect 

fees that are sufficient to cover the direct and indirect GHG 

program costs. Since we are not proposing to charge fees for 

GHGs at the statutory rate ($25 per ton, adjusted for inflation) 

due to concerns raised by permitting authorities and others 

about this resulting in excessive fees, we may need an 

alternative presumptive minimum fee to recover any costs related 
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to GHGs that would not otherwise be covered by the presumptive 

minimum fee that is calculated based on emissions of regulated 

air pollutants, excluding GHGs. We estimated certain incremental 

GHG program costs that would not be covered under the context of 

the Tailoring Rule, but we did not revise our permit rule to 

reflect those costs at that time. We are aware that the EGU NSPS 

may further increase permitting authority costs above the levels 

that would be covered by presumptive minimum fee provisions that 

exclude GHGs, but we are also concerned that accounting for GHGs 

using the statutory rate would result in excessive calculation 

of costs. Thus, to address these concerns, we are proposing two 

alternative options to adjust the presumptive minimum fee 

provisions of the regulations, including a modest additional 

cost for each GHG-related activity of certain types that a 

permitting authority would process over the period covered by 

the presumptive minimum fee calculation, and a modest additional 

increase in the per ton rate used in the presumptive minimum 

calculation. We are also soliciting comment on an option that 

would calculate no additional costs for GHGs.

When we promulgate step 4 of the Tailoring Rule, and 

depending on EPA’s proposal(s) and final action(s) there, we may 

revisit the GHG cost adjustment and potentially revise it, 

taking into account any changes in permitting authority costs 
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for GHGs related to the obligations for permitting authorities 

under that rulemaking.

In addition, as a general matter, the presumptive minimum 

adjustments for part 70 we propose for GHGs are based, in part, 

on information concerning permitting authority burden (in hours) 

and cost (in dollars) contained in the Information Collection 

Request (ICR) renewal for part 70279 approved by the Office of 

Management and Budget on October 3, 2012 for the 36 month period 

of October 31, 2012 through September 30, 2015. Also, this 

information is consistent with, and updates, burden and cost 

information in the Regulatory Impact Assessment (RIA) for the 

Tailoring Rule280 and an ICR change request for the GHG Tailoring 

Rule (EPA ICR Number 1587.11), which was approved by OMB at the 

time of the promulgation of the Tailoring Rule281. These 

assumptions are relevant at least through step 3 of the 

implementation of the Tailoring Rule. The supporting statement 

for the ICR renewal for part 70 sets forth our estimate of the 

three-year and annual incremental burden related to certain 

 

279 The most recent part 70 ICR renewal is identified as EPA ICR 

number 1587.12 and the ICR for part 70 has been assigned OMB 

control number 2060-0243.

280 Regulatory Impact Analysis for the Final Prevention of 

Significant Deterioration and Title V Greenhouse Gas Tailoring 

Rule, Final Report, May 2010.

281 The ICR change request form for the Tailoring Rule was based 

on the assumptions made in the RIA for the Tailoring Rule.
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activities performed by permitting authorities under the 

Tailoring Rule. (See Supporting Statement for the Part 70 state 

Operating Permits Program, document number EPA-HQ-OAR-2004-0016-

0023). The information in the supporting statement is designed 

to be a directionally correct assessment of costs, and thus, may 

serve as a starting point for considerations of the possible 

range of costs to consider when proposing adjustments to the 

presumptive minimum fee provisions of part 70 to appropriately 

account for GHG permitting program costs.

First, we are proposing to adjust the presumptive minimum 

fee to account for GHG costs by adding a cost for each GHGrelated activity of certain types that a permitting authority 

may perform over the period covered by a presumptive minimum fee 

calculation. Additional information supporting this approach may 

be found in part in Table 12 of the supporting statement (in the 

ICR) summarizing the permitting authority burden for particular 

GHG-related permitting activities. Table 12 in the ICR shows 

certain incremental burden assumptions for certain activities 

related to GHG permitting program costs in the form of an hourly 

burden for each activity that a permitting authority may 

process. Based on observations regarding permitting activities 

since the Tailoring Rule, we have adapted these assumptions for 

the purposes of this option and included certain activities with 
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a somewhat different description than we used in the table in 

the ICR in an attempt to more accurately reflect the types of 

permitting activities that have occurred in the GHG permit 

program. In addition, by making these clarifying changes, we are 

trying to more closely track the language in the CAA and parts 

70 and 71 regarding the specific of the permit process. We are 

proposing to include three general activities in this proposed 

option: 1) “GHG completeness determination (for initial permits 

or for updated applications)” at 43 hours, 2) “GHG evaluation 

for a modification or related permit action” at 7 hours, and 3) 

“GHG evaluation at permit renewal” at 10 burden hours.282 The GHG 

 

282 A completeness determination is the first step performed by 

the permitting authority once a permit application is received. 

This step is generally more time consuming for an initial permit 

application compared to other permit applications because this 

is the initial evaluation leading to the drafting and issuance 

of the permit for the first time. Because GHG permitting is in 

the early stages of implementation and EPA is in the early 

stages of issuing new applicable requirements for GHGs, we 

believe permitting authorities will experience additional 

burdens related to GHGs as part of this initial completeness 

determination. Thus, the first item, “GHG completeness 

determination (for initial permit or update application)” 

reflects these additional burdens for completeness 

determinations related to GHGs. This item would also cover 

subsequent application updates related to an initial 

application. See, e.g., 40 CFR 70.5(a)(2). The second item, “GHG 

evaluation for a permit modification or related permitting

action” applies where a permitting authority undertakes an 

evaluation of whether a permit modification involves any GHGrelated requirements. This might also occur, for example, where 

a synthetic or true minor application is submitted and the 

permitting authority needs to undertake a GHG related analysis
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cost adjustment for the presumptive fee would be calculated 

under this approach by multiplying the burden hours for each 

activity by the cost of staff time (in $ per hour), including 

wages, benefits, and overhead, as determined by the state for 

the particular activities undertaken. We also solicit comment on 

the specific burden hours we propose for these GHG-related 

activities. The proposed burden hours for the three activities 

above were not directly discussed in the ICR or directly subject 

to public comment in that context. We believe this proposal 

would benefit from state input on the burden hour assumptions 

for the activities identified and we solicit comment the burden 

hour assumptions and on additional GHG-related permitting 

activities that should be added to the list.

We are also co-proposing an alternative option under which 

we would increase the fee rate used in the presumptive minimum 

calculation for each regulated air pollutant, excluding GHGs. 

This option would rely primarily on data concerning the state 

burdens of permitting GHGs through step 3 of the tailoring rule 

found in the Information Collection Request (ICR) for part 70. 

 

to determine if it affects the existing title V permit. The 

third item, “GHG evaluation at permit renewal” applies where the 

permitting authority receives a renewal application that is not 

coupled with any facility modifications. The EPA suggests this 

language because it is more closely tied to the specific work to 

be performed by permitting authorities consistent with statutory 

and regulatory obligations.
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This suggests that when looking at Tailoring Rule burden in 

isolation, that GHG permitting increases permitting authority 

burden by about 7 percent above the baseline burden 283, which 

would be multiplied by the presumptive minimum fee rate in 

effect to calculate the revise presumptive fee rate to account 

for GHG. Under this approach, the new presumptive minimum fee 

effective for the current period would be $50.00 per ton for 

each regulated pollutant (for presumptive fee calculation)284. 

Several states suggested an approach similar to this in comments 

on the Tailoring Rule, however, their comments assumed we would 

not be exempting GHGs from the definition of regulated 

pollutants (for presumptive fee calculation), as we are 

proposing today. We solicit comment on the appropriateness of 

the 7 percent fee increase for the presumptive minimum fee we 

propose to account for the GHG permitting costs for permitting 

 

283 The baseline costs in the supporting statement for the ICR were 

the costs of permitting looking at all activities except for 

those related to the GHG tailoring rule and certain other recent 

rule changes. Table 14 of the supporting statement shows a 

permitting authority burden of 102,122 hours for implementing 

the GHG tailoring rule and 1,414,293 hours of baseline 

permitting authority burden, and Table 15 shows a permitting 

authority cost of $5.5 million for implementing the GHG 

tailoring rule and $76.4 million for the baseline permitting 

program.

284 At the current rate for part 70 of $46.73, this would result 

in a GHG fee adjustment of about $3.27, or a new rate of $50.00 

per ton for each regulated pollutant (for presumptive fee 

calculation).
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authorities under this alternative option. We are particularly 

interested in state input on whether this level should be higher 

or lower than we propose.

The two options we co-propose for adjusting the presumptive 

minimum fee to account for the costs of GHG permitting are 

similar in that we believe they would both result in about the 

same amount of additional fee revenue being collected. For the 

first option, we took the assumptions approved into the ICR and 

adapted them somewhat so that they more accurately reflect the 

actual implementation experience of permitting authorities 

related to GHGs. On the second, alternative option, we used the 

ICR estimate to determine the relative contribution of GHG 

tailoring rule costs to the total costs of title V permitting 

and we assume these relative costs will hold true in any 

particular state that uses the presumptive minimum fee approach 

to demonstrating fee adequacy. The two options differ in that 

the first option calculates the GHG adjustment to the 

presumptive fee minimum by determining the number of actual GHGrelated activities they have performed for a period, while the 

second option calculates the GHG adjustment by increasing the 

presumptive fee rate for non–GHG pollutants by a set ratio to 

reflect average expected costs. The first approach requires a 

state to track the number of activities of these types it is 
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performing and is thus more burdensome to calculate, although it 

may more accurately reflect the actual costs. The second 

approach is simpler to calculate and predictable but is less 

directly tied to actual implementation experience in a 

particular state.

We also solicit comment on whether we need to revise the 

presumptive minimum calculation provisions to account for GHGs 

costs if we exempt GHGs from the calculation of the presumptive 

minimum fee. The basis for this option would be that because 

most GHG sources that would be subject to title V permitting, 

whether due to GHGs or due for other reasons under the proposed 

NSPS and applicability provisions of the permitting rules (see 

40 CFR 70.3 and 71.3) would have actual emissions of other 

regulated air pollutants subject to fees, and thus the cost of 

permitting these sources may be adequately accounted for without 

charging any additional fees specifically based on emissions of 

GHGs. We also note that support for this approach can be found 

in the current OMB-approved ICR for part 70, tables 14, 15 and 

18, where the cost of permitting for permitting authorities is 

summarized, considering the effects of several recent EPA 

rulemakings that were conducted since the last ICR update. 

This proposal does not directly affect those states that do 

not rely on the presumptive minimum fee approach to show fee 
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adequacy; however, non-presumptive fee states are still required 

to charge sufficient fees to recover all reasonable direct and 

indirect program costs. Part 70 allows the EPA to review state 

fee programs at any time to determine if they are collecting 

fees sufficient to cover their costs, whether or not states rely 

on the presumptively minimum fee approach. We are not requiring 

any additional detailed fee submittals from states at this time 

based on these proposed changes.

Some states may conclude that they wish to revise their 

part 70 programs in response to this proposal either to revise 

their state fee schedules to prevent any possible collection of 

excessive fees (e.g., if they require any regulated pollutant 

subject to a section 111 standard to pay a fee) or to charge 

additional fees to sources because their presumptive minimum fee 

target has increased. We solicit comment on the most expeditious 

means for EPA to approve title V program revisions across the 

states once this proposal is finalized.

There may be other viable options consistent with statutory 

and regulatory authority, principles, and concerns, in addition 

to those we have described in this proposal. For example, states 

have previously commented on establishing a separate, lower 

presumptive fee per ton of GHG emissions). The EPA invites 

states, local, and/or Tribal authorities to provide more refined 
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data and/or information surrounding the unique costs associated 

with permitting GHG sources under this proposed rule, and other 

fee options such data supports. Notably, the regulatory text 

included today represents only one option on which comments are 

solicited. The EPA is providing full regulatory text only for 

this option because it represents the most novel approach. The 

EPA is also soliciting comment on other viable approaches

described herein, but considers the discussion provided herein 

to provide an adequate basis for public comment. The EPA notes 

that the final rule may be based on any of the approaches 

described in the preamble.

c. Revisions to the part 71 fee schedule

As part of the promulgation of the final part 71 rule, the 

EPA performed a detailed analysis of the costs of developing and 

implementing the program and reviewed the inventory of emissions 

of regulated pollutants (for fee calculation) to determine the 

appropriate emission fee that would be sufficient to recover all 

direct and indirect programs costs – we set the fee at $32 per 

ton, adjusted for inflation, times the emissions of regulated 

pollutant (for fee calculation). (See Federal Operating Programs 

Fees, Revised Cost Analysis, February 1996; legacy docket A-93-

51, document number II-A-3.)
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For part 71, we also propose to exempt GHGs from the 

definition of regulated pollutant (for fee calculation), which 

is similar to the definition of regulated pollutants (for 

presumptive fee calculation) used in part 70, for the same 

reasons we have explained for part 70. In addition, for the same 

reasons we explained for part 70, we are proposing two options 

for revising the fee schedule of 40 CFR 71.9(c) to ensure that 

we continue to recover sufficient fees to fully fund the part 71 

GHG permitting program. The bases for the options were described 

in more detail earlier in this proposal with respect to part 70 

proposals and those also apply here to part 71.

First, the EPA (or delegate agency) burden hour assumptions 

we propose for each GHG-related permitting activity under part 

71 are the same as we are proposing for states under the 

presumptive minimum fee provisions of part 70.285 This option 

would rely on the following information. The labor rate 

assumption we propose for the EPA (or delegate agency) staff 

time under part 71 is the average hourly rate we assumed in the 

 

285 See the supporting statement for the ICR renewal for part 71 

approved by the Office of Management and Budget on June 13, 2012 

for the 36 month period of June 30, 2012 through May 31, 2015. 

The ICR renewal for part 71 is identified as EPA ICR number 

1713.10 and the ICR for part 71 has been assigned OMB control 

number 2060-0336. The assumptions of this part 71 ICR renewal 

for GHG burden are identical to those used for the part 70 ICR. 

See Table 12 of the part 71 supporting statement.
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supporting statement for the recent part 71 ICR renewal of $52 

per hour in 2011 dollars, including wages, benefits and overhead 

costs. We propose to determine the GHG fee adjustment for each 

GHG permitting program activity by multiplying the burden hour 

assumption we propose by the EPA (or delegate agency) labor rate 

we propose. Thus, for example, we propose a set fee to be paid 

by sources for each “completeness determination (for new permit 

or updated application” of $364 (7 hours times $52 per hour for 

the current period). Also, we propose to charge, for simplicity 

sake, the same set fees for GHG activities, whether performed by 

the EPA, a delegate agency, or by the EPA with contractor 

assistance. The appropriate set fees for all GHG permitting 

program activities performed for the source would be added to 

the traditional fee that is determined based on emissions of 

each regulated pollutants (for fee calculation) to determine the 

total fee for the source. 

The second option we propose for part 71 is to increase the 

emission fee by a modest amount for each regulated air 

pollutant, excluding GHGs. For simplicity sake, we propose to 

charge the same adjustment under this option that we propose for 

part 70, or 7 percent, which would be multiplied by annual part 
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71 fee in effect to calculate the revise fee rate286. The 

rationale for this approach is described in more detail earlier 

in this preamble during the part 70 discussion.

We also solicit comment on whether we could exclude GHG 

emissions from the calculation of the annual part 71 fee for 

reasons similar to those we explained for part 70 (e.g., because 

permitting costs can be covered by the existing part 71 permit 

fee). 

XI. Impacts of the Proposed Action287

A. What are the air impacts?

As explained in the Regulatory Impact Analysis (RIA) for 

this proposed rule, available data indicate that, even in the 

absence of this rule, existing and anticipated economic 

conditions will lead electricity generators to choose new 

generation technologies that would meet the proposed standard 

without installation of additional controls. Therefore, based on 

the analysis presented in Chapter 5 of the RIA, the EPA projects 

 

286 At the current rate for part 71 of $48.33, this would result in 

a GHG fee adjustment of $3.38, or a new rate of $51.71 per ton 

for each regulated pollutant (for fee calculation).

287 Note that EPA does not project any difference in the impacts between the alternative to regulate sources under

Subparts Da and KKKK vs regulating them under New Subpart TTTT

Comment [dj55]: Per OMB:

Suggest adding a discussion here of the potential 

impacts of the alternative co-proposal , and 

comparing that with the separate standards proposal. 

Given that the co-proposal is unlikely to alter the 

estimated impacts, costs, and benefits, it may be 

sufficient to add a paragraph of discussion in the 

beginning of the Section.

EPA: Added footnote
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that this proposed rule will result in negligible CO2 emission 

changes, quantified benefits, and costs by 2022.288

B. What are the energy impacts?

This proposed rule is not anticipated to have a notable 

effect on the supply, distribution, or use of energy. As 

previously stated, the EPA believes that electric power 

companies would choose to build new EGUs that comply with the 

regulatory requirements of this proposal even in its absence, 

because of existing and expected market conditions. In addition, 

the EPA does not project any new coal-fired EGUs without CCS to 

be built in the absence of this proposal.

C. What are the compliance costs?

The EPA believes this proposed rule will have no notable 

compliance costs associated with it, because electric power 

companies would be expected to build new EGUs that comply with 

the regulatory requirements of this proposal even in the absence 

of the proposal, due to existing and expected market conditions. 

The EPA does not project any new coal-fired EGUs without CCS to 

be built in the absence of the proposal. However, because some 

companies may choose to construct coal or other fossil fuelfired units, the RIA also analyzes project-level costs of a unit 

 

288 Conditions in the analysis year of 2022 are represented by a 

model year of 2020.
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with and without CCS, to quantify the potential cost for a 

fossil fuel-fired unit with CCS.

D. How will this proposal contribute to climate change 

protection?

As previously explained, the special characteristics of 

GHGs make it important to take initial steps to control the 

largest emissions categories without delay. Unlike most 

traditional air pollutants, GHGs persist in the atmosphere for 

time periods ranging from decades to millennia, depending on the 

gas. Fossil-fueled power plants emit more GHG emissions than any 

other stationary source category in the United States, and among 

new GHG emissions sources, the largest individual sources are in 

this source category. 

This proposed rule will limit GHG emissions from new 

sources in this source category to levels consistent with 

current projections for new fossil-fuel-firedfossil fuel-fired

generating units. The proposed rule will also serve as a 

necessary predicate for the regulation of existing sources 

within this source category under CAA section 111(d). In these 

ways, the proposed rule will contribute to the actions required 

to slow or reverse the accumulation of GHG concentrations in the 

atmosphere, which is necessary to protect against projected 

climate change impacts and risks.
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E. What are the economic and employment impacts?

The EPA does not anticipate that this proposed rule will 

result in notable CO2 emission changes, energy impacts, monetized 

benefits, costs, or economic impacts by 2022. The owners of 

newly built electric generating units will likely choose 

technologies that meet these standards even in the absence of 

this proposal due to existing economic conditions as normal 

business practice. Likewise, the EPA believes this rule will not 

have any impacts on the price of electricity, employment or 

labor markets, or the U.S. economy.

F. What are the benefits of the proposed standards?

As previously stated, the EPA does not anticipate that the 

power industry will incur compliance costs as a result of this 

proposal and we do not anticipate any notable CO2 emission 

changes resulting from the rule. Therefore, there are no direct 

monetized climate benefits in terms of CO2 emission reductions 

associated with this rulemaking. However, by clarifying that in 

the future, new coal-fired power plants will be required to meet 

a particular performance standard, this rulemaking reduces 

uncertainty and may enhance the prospects for new coal-fired 

generation and the deployment of CCS, and thereby promote energy 

diversity. 

XII. Request for Comments
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We request comments on all aspects of the proposed 

rulemaking including the RIA. All significant comments received 

will be considered in the development and selection of the final 

rule. We specifically solicit comments on additional issues 

under consideration as described below. 

Measurement. We are requesting comment on requiring the use 

the following procedures that increase the precision of GHG 

measurements:

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-ducts-walleffects-test-method-ctm-041.pdf) to account for wall effects 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.
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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.

e. An ambient air argon concentration of 0.93 percent[1] and 

a molecular weight of 39.9 lb/lb-mol in calculating the dry gas 

molecular weight.

f. A value for pi of 3.14159 when calculating the effective 

area for circular stacks.

g. A daily calibration drift cap no greater than 0.3 

percent CO2 for CO2 CEMS.

h. A maximum relative accuracy specification of 2.5 percent 

for both CO2 and flow rate measurement CEMS.

i. Method 3B of 40 CFR part 60 in addition to Method 3A, 

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 pilesIn the original proposal, we 

requested comment in the previous proposal on subcategorizing 

EGUs that burn over 75 percent coal refuse on an annual basis. 

Multiple commenters on the previous proposal supported the 

exemption citing the numerous environmental benefits of 

 

[1] http://www.physicalgeography.net/fundamentals/7a.html.
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remediating coal refuse piles. Other commenters on the previous 

original proposal disagreed with any exemption, specifically 

citing the N2O emissions from fluidized bed boilers (coal refusefired EGUs typically use fluidized bed technology). Due to the 

environmental benefits of remediating coal refuse piles cited by 

commenters, the limited amount of coal refuse, and the fact that 

a new coal refuse-fired EGU would have to be located in close 

proximity to the coal refuse pile, we are continuing to consider 

establishing a subcategory for coal refuse-fired EGUs and are 

requesting additional comments. Specifically, we are requesting 

additional information on the net environmental benefits of coal 

refuse-fired EGUs, and in the event we do establish a coal 

refuse-fired subcategory, what the emissions standard for that 

subcategory should be (i.e., should it be based on a lower 

amount of partial CCS or on highly efficient generation alone 

without the use of CCS and an appropriate emissions rate). One 

commenter on the previous original proposal stated that existing 

coal refuse piles are naturally combusting at a rate of 0.3 

percent annually. We are requesting comment on assuming this 

rate of natural combustion and the proper approach to accounting 

for naturally occurring emissions from coal refuse piles.

Compressed Air Energy Storage (CAES) Facilities. The EPA is 

considering and requesting comment on exempting stationary 
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combustion turbines at compressed air energy storage facilities 

from the CO2 emissions standard. CAES technology is an energy 

storage technology that involves two steps. Air is compressed by 

electric motor driven compressors during off-peak electricity 

demand hours and stored in a storage media (e.g., an underground 

cavern). Electricity is then generated during peak electricity 

demand periods by releasing the high‐pressure air, heating the 

air with natural gas, and expanding it through sequential 

turbines (expanders), which drive an electrical generator. Since 

natural gas is combusted in the stationary combustion turbine, a 

new CAES facility meeting the general applicability requirements 

would potentially have to comply with one of the proposed an 

emissions standard. However, based on anticipated capacity 

factors for new CAES facilities, it is our understanding that 

the proposed 1/3one-third electric sales of potential electric 

output applicability criteria would exempt new CAES facilities 

from the proposed emission standards. The EPA is requesting 

comment on whether this assumption is accurate. In the event 

that this is not the case, the EPA is considering and requesting 

comment on if new source review is the appropriate mechanism to 

establish site specific GHG requirements for CAES facilities and 

exempt stationary combustion turbines at CAES facilities from 

the proposed CO2 emission standards. We have concluded this could 
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be appropriate the use of stored energy complicates determining 

compliance with the proposed emission standards. sSince we only 

expect a limited number of new CAES facilities, and the use of 

stored energy complicates the determination of compliance with 

the proposed emission standards.we have concluded that the new 

source review program is the appropriate mechanism to establish 

site specific GHG requirements for such sources.

District Energy. District energy systems produce steam, hot 

water or chilled water at a central facility. The steam, hot 

water or chilled water is then distributed through pipes to 

individual consumers for space heating, domestic hot water 

heating and air conditioning. As a result, individual consumers

served by a district energy system do not need their own 

heating, water heating or air conditioning systems. Even though 

with the proposed definition of net-electric output it is 

unlikely that a district energy system would be subject to an 

emissions standard, we are considering and requesting comment on 

an appropriate method to recognize the environmental benefit of 

district energy systems. The steam or hot water distribution 

system of a district energy system located in urban areas, 

college and university campuses, hospitals, airports, and 

military installations eliminates the need for multiple, smaller 

boilers at individual buildings. A central facility typically 
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has superior emission controls and consists of a few larger 

boilers facilitating more efficient operation than numerous 

separate smaller individual boilers. However, when the hot water 

or steam is distributed, approximately two to three percent of 

the thermal energy in the water and six to nine percent of the 

thermal energy in the steam is lost, reducing the net efficiency 

advantage. To recognize the net environmental benefit of 

district energy systems compared to multiple smaller heating and 

cooling systems, Wwe are requesting comment on whether it is 

appropriate to adjust the measureddivide the thermal output from 

district energy systems when calculating the emissions rate used 

for compliance purposes. For example, if thermal energy from 

central district energy systems is approximately 5 percent more 

efficient than thermal energy supplied by multiple smaller 

heating and cooling systems the measured thermal output would be 

divided by 0.95 (e.g., 100 MMBtu/h of measured steam would be 

105 MMBtu/h when determining the emissions rate)by a factor 

(i.e., 0.95 or 0.90) that would account for the net efficiency 

benefits of district energy systems. This approach would be 

similar to the proposed approach to how the electric output for 

CHP is considered when determining regulatory compliance and is 

consistent with the approach in the proposed amendments to the 

combustion turbine NSPS (77 FR 52554). We request that comments 
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include technical analysis of the net benefits in support of any 

conclusions on an appropriate adjustment factor.

Emergency conditions. We are requesting comment on 

excluding electricity generated as a result of a grid emergency 

declared by the Regional Transmission Organizations (RTO), 

Independent System Operators (ISO) or control area Administrator 

from counting as net sales when determining applicability as an 

EGU. For example, under this approach, if grid voltage drops 

below acceptable levels and the affected facility is the only 

facility with available capacity, then electricity generated 

during this period would not count for applicability purposes. 

While the proposed 3 year average electric sales applicability 

provides significant flexibility for simple cycle turbines, we 

are considering including the emergency conditions exemption to 

allow facilities designed with the intent to sell less than 

1/3one-third of their potential electric output to continue to 

generate electricity during a grid emergency without such 

generation counting towards the 1/3one-third sales applicability 

criterion. In the original 1979 electric utility NSPS rulemaking

(44 FR 33580), the EPA recognized that emergency periods do 

occur from unplanned EGU outages, transmission outages or 

surging customer demand loads. Such occurrences may require that 

all available operable EGUs interconnected to the electrical 
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grid supply power to the grid. Provisions were added to 40 CFR 

60 subpart Da to address emergency conditions when continued 

operation of an EGU with a malfunctioning flue gas 

desulfurization (FGD) system is acceptable and not considered a 

violation of the SO2 emissions standard. These conditions require 

that all available capacity from the power company’s other EGUs 

is being used and all available purchase power from 

interconnected power companies is being obtained. In this case, 

the EPA concluded that the broader benefits of operating the 

power plant with the malfunctioning FGD system to generate 

electrical power during emergency conditions in order to ensure 

uninterrupted electricity supply to the public outweigh any 

adverse impacts from a short-term increase in SO2 emission to the 

atmosphere from the power plant. The definition for a system

emergency we are considering is “any abnormal system condition 

that the Regional Transmission Organizations (RTO), Independent 

System Operators (ISO) or control area Administrator determines 

requires immediate automatic or manual action to prevent or 

limit loss of transmission facilities or generators that could 

adversely affect the reliability of the power system and 

therefore call for maximum generation resources to operate in 

the affected area, or for the specific affected facility to 

operate to avert loss of load.”
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Initial Design Efficiency Test. We are considering and 

requesting comment on requiring an initial performance test for 

stationary combustion turbines in addition to the 12-operatingmonth rolling average standard. Requiring an initial compliance 

test that is numerically more stringent than the annual standard 

for new combined cycle facilities would insure that the most 

efficient stationary combustion turbines are installed. The less 

stringent 12-month rolling average standard would be set at a

level that would take into account actual operating conditions.

Integrated Equipment. The proposed affected facility 

definitions includes the stationary combustion 

turbine/steamtraditional generating unit “plus any integrated 

equipment that provides electricity or useful thermal output.” 

For example, the definition of a steam generating unit for GHG 

purposes, “means any furnace, boiler, or other device used for 

combusting fuel for the purpose of producing steam (including 

fossil-fuel-firedfossil fuel-fired steam generators associated 

with combined cycle gas turbines; nuclear steam generators are 

not included) plus any integrated equipment that provides 

electricity or useful thermal output to either the boiler or to 

power auxiliary equipment” (emphasis added). We are considering 

and requesting comment on also including in the definition of 

the affected facility co-located non-emitting energy generation 
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equipment that is not integrated into the operation of the 

affected facility. This approach would provide additional 

flexibility, lower compliance costs, and recognize the 

environmental benefit of non-emitting sources of electricity and 

not limit options to integrated solar thermal feedwater heating. 

The definition would include the additional language “or colocated non-emitting energy generation included in the facility 

operating permit.” For example, the definition of a steam 

generating unit for GHG purposes would be expanded to read, “any 

furnace, boiler, or other device used for combusting fuel for 

the purpose of producing steam (including fossil-fuelfiredfossil fuel-fired steam generators associated with combined 

cycle gas turbines; nuclear steam generators are not included) 

plus any integrated equipment that provides electricity or 

useful thermal output to either the boiler or to power auxiliary 

equipment or co-located non-emitting energy generation included 

in the facility operating permit” (emphasis added). This would 

permit the use of co-located photovoltaic solar power, wind 

turbines, and other non-emitting energy generation as means for 

achieving compliance with the emission standards. Since 

integrated solar thermal feedwater heating is primarily a

feasible option only for facilities that operate daily (e.g., 

thermal energy from the solar thermal is used in the steam cycle 
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generated from the combustion of fossil fuels), this approach 

would expand options for more intermittent intermediate load 

generators to efficiently integrate non-emitting energy 

generation into their design.

Net-output-based standards. We are considering and 

requesting comment on requiring the use or adding an optional

net-output based standard for each subcategory. As described in 

the original proposal for this rulemaking, net output is the 

combination of the gross electrical output of the electric 

generating unit minus the parasitic (i.e., auxiliary) 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 non-IGCC 

and non-CCS coal-fired station power output, approximately 15 

percent of non-CCS IGCC-based coal-fired station power output

and about 2.5 percent of non-CCS 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 
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require less emissions control equipment, and (3) recognizing 

the environmental benefit of higher efficiency motors, pumps, 

and fans. While the EPA has concluded that the net power 

supplied to the end user is a better indicator of environmental 

performance than gross output from the power producer, we only 

have CEMS emissions data reported on a gross output basis. In 

addition, for facilities that coproduce chemicals and other 

useful byproducts, accurate accounting of the parasitic loads 

could be problematic.

The optional net-output based standard would have the most 

impact for non-IGCC-based coal-fired EGUs. While the net output 

based emissions rate for all non-CCS coal-fired generation is 

similar, IGCC facilities have substantially larger parasitic 

loads and correspondingly lower gross emissions rates. Using a 

strictly gross-output based standard requires that a coal-fired 

PC or CFB EGU capture approximately 60 percent more CO2 than a 

coal-fired IGCC EGU. A 1,400 lb CO2/MWh-net standard would 

require similar amount of CCS for both IGCC and SCPC EGUs, 25 

and 28 percent respectively.The net-output based CO2 emissions 

rate for steam generating units and IGCC facilities 

corresponding to an emissions rate of 1,100 lb CO2/MWh on a gross 

basis would be 1,400 lb CO2/MWh. A 1,400 lb CO2/MWh-net standard 

would require similar amount of CCS for both IGCC and SCPC EGUs, 

Comment [A56]: It would be helpful if EPA 

could explain why it only has CEMS emission data 

reported on a gross output basis and why the agency 

is not able to move to a more optimal parasitic 

accounting approach.

EPA: addressed earlier
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25 and 28 percent respectively. The range of net-output based 

emission rates being considered that corresponds to the gross 

output-based limits is 1,100 to 1,500 lb CO2/MWh-net, rounded to 

2 significant digits. Requiring or including an optional netoutput based standard would provide more operational flexibility 

and expand the technologies options available to comply with the 

standard for coal-fired PC and CFB EGUs which could impact our 

determination of BSER. For example, at an emissions limit of 

1,500 lb CO2/MWh-net a PC or CFB could use integrated natural 

gas-fired combustion turbines or fuel cells for boiler feedwater 

heating, supplemental steam production, or for preheated air for 

the boiler to reduce the level of CCS required or as an 

alternative to CCS. We request that commenters who support the 

use of net output-based standards address potential concerns 

about proving adequate technology development to be considered 

BSER.

The net-output based rate for stationary combustion 

turbines corresponding to the proposed 1,100 lb CO2/MWh-gross and 

1,100 lb CO2/MWh-gross would be 1,030 lb CO2/MWh-net and 1,130 lb 

CO2/MWh-net for the large and small subcategories respectively.

The corresponding range of net-output based emission rates being 

considered is 970 to 1,130 lb CO2/MWh-net and 1,030 to 1,180 lb 

CO2/MWh-net for the large and small combustion turbine 
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subcategory respectively. However, the actual numerical limits 

would not change in all circumstances using the convention of 2 

significant digits.

Other GHGs. Today’s proposed rule would require continuous 

measurement of CO2 from fossil fuel-fired EGUs. Other GHGs, such 

as methane (CH4) and nitrous oxide (N2O) are not included in the 

proposed emission standards and are also not required to be 

measured and reported by affected EGUs as part of today’s 

proposal, even though their 100-year global warming potential is 

21 to 310 times greater than that of CO2, because their emissions 

from EGUs are believed to be negligible when compared to CO2

emissions. We request comment on the appropriateness, technique, 

and frequency (one-time or periodic, but not continuous) of 

measurement and reporting of CH4 and N2O emissions from fossil 

fuel-fired EGUs as part of the proposed emissions standard. 

Receipt of this data would enhance understanding of total GHG 

emissions from EGUs and could aid future policy decisions 

regarding whether these GHGs should be included in a revised 

emission standard, as part of 8-year NSPS review and potential 

revision cycle.

Violations. We are proposing that the calculation of the 

number of daily violations within an averaging period be 

determined using the following methodology. If, for any 12- or 
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60-operating84-operating month period, the source’s emission 

rate exceeds the standard, the number of daily violations in the

12- or 60-operating84-operating-month averaging period would be 

the number of operating days in that period. However, if a 

violation occurs directly following the previous 12-operatingmonth or 60-operating84-operating-month averaging period, daily 

violations would not double count operating days that were 

determined as violations under the previous averaging period. 

For example, assume that a facility operates 10 days out of each 

month for 12 months from January 1, Year 1 to December 31, Year 

1, and exceeds the emissions standard during that 12-month 

period. The violation for this January-December Year 1 period 

would constitute 120 daily violations. If the facility operated 

20 days the following month, which would be January, Year 2, and 

was still in excess of the emissions standard over the period 

from February, Year 1 to January, Year 2, then 20 additional 

daily violations would result, for a total of 140 daily 

violations. We are requesting comment on this determination of 

daily violations for owners/operators that exceeds either a 12-

operating-month or 60-operating84-operating-month standard.

XIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and 

Executive Order 13563, Improving Regulation and Regulatory 
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Review

Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 

1993), this action is a “significant regulatory action” because 

it “raises novel legal or policy issues arising out of legal 

mandates”. Accordingly, the EPA submitted this action to the 

Office of Management and Budget (OMB) for review under Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any 

changes made in response to OMB recommendations have been 

documented in the docket for this action. In addition, the EPA 

prepared an analysis of the potential costs and benefits 

associated with this action. This analysis is contained in the 

Regulatory Impact Analysis for the Standards of Performance for 

Greenhouse Gas Emissions for New Fossil Fuel-Fired Electric 

Utility Steam Generating Units and Stationary Combustion 

Turbines. 

 The EPA believes this rule will have no notable compliance 

costs associated with it over a range of likely sensitivity 

conditions because electric power companies would choose to 

build new EGUs that comply with the regulatory requirements of 

this proposal even in the absence of the proposal, because of 

existing and expected market conditions. (See the RIA for 

further discussion of sensitivities). The EPA does not project 

any new coal-fired EGUs without CCS to be built in the absence 
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of this proposal. However, because some companies may choose to 

construct coal or other fossil fuel-fired units, the RIA also 

analyzes project-level costs of a unit with and without CCS, to 

quantify the potential cost for a fossil fuel-fired unit with 

CCS.

B. Paperwork Reduction Act

The information collection requirements in this proposed 

rule have been submitted for approval to the Office of 

Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) 

document prepared by the EPA has been assigned the EPA ICR 

number 2465.01.

This proposed action would impose minimal new information 

collection burden on affected sources beyond what those sources 

would already be subject to under the authorities of CAA parts 

75 and 98. OMB has previously approved the information 

collection requirements contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR part 98) under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. and has assigned OMB control numbers 2060-0626 and 2060-

0629, respectively. Apart from certain reporting costs based on 

requirements in the NSPS General Provisions (40 CFR part 60, 

subpart A), which are mandatory for all owners/operators subject 
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to CAA section 111 national emission standards, there are no new 

information collection costs, as the information required by 

this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to Agency 

policies set forth in 40 CFR part 2, subpart B.

The EPA believes that electric power companies will choose 

to build new EGUs that comply with the regulatory requirements 

of this proposal because of existing and expected market 

conditions. The EPA does not project any new coal-fired EGUs 

that commence construction after this proposal to commence 

operation over the three-year period covered by this ICR. We 

estimate that 17 new affected NGCC units would commence 

operation during that time period. As a result of this proposal, 

those units would be required to prepare a summary report, which 

includes reporting of excess emissions and downtime, every six 

months.

When a malfunction occurs, sources must report them 

according to the applicable reporting requirements of 40 CFR 

part 60, subpart TTTT 60.5530subpart Da or subpart KKKK. An 
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affirmative defense to civil penalties for exceedances of 

emission limits that are caused by malfunctions is available to 

a source if it can demonstrate that certain criteria and 

requirements are satisfied. The criteria ensure that the 

affirmative defense is available only where the event that 

causes an exceedance of the emission limit meets the narrow 

definition of malfunction (sudden, infrequent, not reasonably 

preventable, and not caused by poor maintenance or careless 

operation) and where the source took necessary actions to 

minimize emissions. In addition, the source must meet certain 

notification and reporting requirements. For example, the source 

must prepare a written root cause analysis and submit a written 

report to the Administrator documenting that it has met the 

conditions and requirements for assertion of the affirmative 

defense. 

To provide the public with an estimate of the relative 

magnitude of the burden associated with an assertion of 

affirmative defense, the EPA has estimated what the 

notification, recordkeeping, and reporting requirements 

associated with the assertion of the affirmative defense might 

entail. The EPA’s estimate for the required notification, 

reports, and records, including the root cause analysis, 

associated with a single incident totals approximately totals 
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$3,141, and is based on the time and effort required of a source 

to review relevant data, interview plant employees, and document 

the events surrounding a malfunction that has caused an 

exceedance of an emission limit. The estimate also includes time 

to produce and retain the record and reports for submission to 

the EPA. The EPA provides this illustrative estimate of this 

burden, because these costs are only incurred if there has been 

a violation, and a source chooses to take advantage of the 

affirmative defense.

Given the variety of circumstances under which malfunctions 

could occur, as well as differences among sources' operation and 

maintenance practices, we cannot reliably predict the severity 

and frequency of malfunction-related excess emissions events for 

a particular source. It is important to note that the EPA has no 

basis currently for estimating the number of malfunctions that 

would qualify for an affirmative defense. Current historical 

records would be an inappropriate basis, as this rule applies 

only to sources built in the future. Of the number of excess 

emissions events that may be reported by source operators, only 

a small number would be expected to result from a malfunction, 

and only a subset of excess emissions caused by malfunctions 

would result in the source choosing to assert an affirmative 

defense. Thus, we believe the number of instances in which 
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source operators might be expected to avail themselves of the 

affirmative defense will be extremely small. In fact, we 

estimate that there will be no such occurrences for any new 

sources subject to 40 CFR part 60, subpart Da or subpart KKKK 

over the three-year period covered by this ICR. We expect to 

gather information on such events in the future, and will revise 

this estimate as better information becomes available.

The annual information collection burden for this 

collection consists only of reporting burden as explained above. 

The reporting burden for this collection (averaged over the 

first three years after the effective date of the standards) is 

estimated to be $15,570 and 396 labor hours. This estimate 

includes semi-annual summary reports which include reporting of 

excess emissions and downtime. All burden estimates are in 2010 

dollars. Average burden hours per response are estimated to be 

16.5 hours. The total number of respondents over the three-year 

ICR period is estimated to be 36. Burden is defined at 5 CFR 

1320.3(b).

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9.
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To comment on the Agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID number EPA-HQ-OAR-2013-0495. Submit any 

comments related to the ICR to the EPA and OMB. See ADDRESSES

section at the beginning of this notice for where to submit 

comments to the EPA. Send comments to OMB at the Office of 

Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Officer for the EPA. Since OMB is required to make a 

decision concerning the ICR between 30 and 60 days after [INSERT 

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

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

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

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

information collection requirements contained in this proposal.

C. Regulatory Flexibility Act 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 
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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 fiscal year. The NAICS codes for the 

affected industry are in Table 75 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 57. Potentially Regulated Categories and Entitiesa

Category NAICS 

Code

Examples of Potentially Regulated 

Entities

Industry 221112 Fossil fuel electric power generating 

units.
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Federal 

Government

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government

221112b Fossil fuel electric power generating 

units owned by municipalities.

Tribal 

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

a Include NAICS categories for source categories that own and 

operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines).

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

establishments are classified according to the activity in which 

they are engaged.

After considering the economic impacts of this proposed 

rule on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities.

We do not include an analysis of the illustrative impacts 

on small entities that may result from implementation of this 

proposed rule because we do not anticipate any compliance costs 

over a range of likely sensitivity conditions as a result of 

this proposal. Thus the cost-to-sales ratios for any affected 

small entity would be zero costs as compared to annual sales 

revenue for the entity. The EPA believes that electric power 

companies will choose to build new EGUs that comply with the 

regulatory requirements of this proposal because of existing and 

expected market conditions. (See the RIA for further discussion 
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of sensitivities). The EPA does not project any new coal-fired 

EGUs without CCS to be built. Accordingly, there are no 

anticipated economic impacts as a result of this proposal. 

Nevertheless, the EPA is aware that there is substantial 

interest in this rule among small entities (municipal and rural 

electric cooperatives). In light of this interest, prior to the 

April 13, 2012 proposal (77 FR 22392), the EPA determined to 

seek early input from representatives of small entities while 

formulating the provisions of the proposed regulation. Such 

outreach is also consistent with the President’s January 18, 

2011 Memorandum on Regulatory Flexibility, Small Business, and 

Job Creation, which emphasizes the important role small 

businesses play in the American economy. This process has 

enabled the EPA to hear directly from these representatives, at 

a very preliminary stage, about how it should approach the 

complex question of how to apply Section 111 of the CAA to the 

regulation of GHGs from these source categories. The EPA’s 

outreach regarded planned actions for new and existing sources, 

but only new sources would be affected by this proposed action.

The EPA conducted an initial outreach meeting with small 

entity representatives on April 6, 2011. The purpose of the 

meeting was to provide an overview of recent EPA proposals 

impacting the power sector. Specifically, overviews of the 
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Transport Rule, the Mercury and Air Toxics Standards, and the 

Clean Water Act 316(b) Rule proposals were presented.

The EPA conducted outreach with representatives from 20 

various small entities that potentially would be affected by 

this rule. The representatives included small entity 

municipalities, cooperatives, and private investors. We 

distributed outreach materials to the small entity 

representatives; these materials included background, an 

overview of affected sources and GHG emissions from the power 

sector, an overview of CAA section 111, an assessment of CO2

emissions control technologies, potential impacts on small 

entities, and a summary of the listening sessions. We met with 

eight of the small entity representatives, as well as three 

participants from organizations representing power producers, on 

June 17, 2011, to discuss the outreach materials, potential 

requirements of the rule, and regulatory areas where the EPA has 

discretion and could potentially provide flexibility.

A second outreach meeting was conducted on July 13, 2011. 

We met with nine of the small entity representatives, as well as 

three participants from organizations representing power 

producers. During the second outreach meeting, various small 

entity representatives and participants from organizations 

representing power producers presented information regarding 
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issues of concern with respect to development of standards for 

GHG emissions. Specifically, topics suggested by the small 

entity representatives and discussed included: boilers with 

limited opportunities for efficiency improvements due to NSR 

complications for conventional pollutants; variances per 

kilowatt-hour and in heat rates over monthly and annual 

operations; significance of plant age; legal issues; importance 

of future determination of carbon neutrality of biomass; and 

differences between municipal government electric utilities and 

other utilities.

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392). We invite comments on all aspects of the 

proposal and its impacts, including potential adverse impacts, 

on small entities.

D. Unfunded Mandates Reform Act of 1995

This proposed rule does not contain a federal mandate that 

may result in expenditures of $100 million or more for State, 

local, and tribal governments, in the aggregate, or the private 

sector in any one year. The EPA believes this proposed rule will 

have no compliance costs associated with it over a range of likely 

sensitivity conditions because electric power companies will 
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choose to build new EGUs that comply with the regulatory 

requirements of this proposal because of existing and expected 

market conditions. (See the RIA for further discussion of 

sensitivities). The EPA does not project any new coal-fired EGUs 

without CCS to be built. Thus, this proposed rule is not subject 

to the requirements of sections 202 or 205 of UMRA.

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments.

In light of the interest in this rule among governmental 

entities, the EPA initiated consultations with governmental 

entities prior to the April 13, 2012 proposal (77 FR 22392). The 

EPA invited the following 10 national organizations representing 

state and local elected officials to a meeting held on April 12, 

2011, in Washington DC: 1) National Governors Association; 2) 

National Conference of State Legislatures, 3) Council of State 

Governments, 4) National League of Cities, 5) U.S. Conference of 

Mayors, 6) National Association of Counties, 7) International 

City/County Management Association, 8) National Association of 

Towns and Townships, 9) County Executives of America, and 10) 

Environmental Council of States. These 10 organizations 

representing elected state and local officials have been 
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identified by the EPA as the “Big 10” organizations appropriate 

to contact for purpose of consultation with elected officials. 

The purposes of the consultation were to provide general 

background on the proposal, answer questions, and solicit input 

from state/local governments. The EPA’s consultation regarded 

planned actions for new and existing sources, but only new 

sources would be affected by this proposed action.

During the meeting, officials asked clarifying questions 

regarding CAA section 111 requirements and efficiency 

improvements that would reduce CO2 emissions. In addition, they 

expressed concern with regard to the potential burden associated 

with impacts on state and local entities that own/operate 

affected utility boilers, as well as on state and local entities 

with regard to implementing the rule. Subsequent to the April 

12, 2011 meeting, the EPA received a letter from the National 

Conference of State Legislatures. In that letter, the National 

Conference of State Legislatures urged the EPA to ensure that 

the choice of regulatory options maximizes benefit and minimizes 

implementation and compliance costs on state and local 

governments; to pay particular attention to options that would 

provide states with as much flexibility as possible; and to take 

into consideration the constraints of the state legislative 

calendars and ensure that sufficient time is allowed for state 
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actions necessary to come into compliance.

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392).

E. Executive Order 13132, Federalism

This proposed action does not have federalism implications. 

It would not have substantial direct effects on the States, on 

the relationship between the national government and the States, 

or on the distribution of power and responsibilities among the 

various levels of government, as specified in EO 13132. This 

proposed action would not impose substantial direct compliance 

costs on state or local governments, nor would it preempt state 

law. Thus, Executive Order 13132 does not apply to this action. 

Prior to the April 13, 2012 proposal (77 FR 22392), 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’s consultation 

regarded planned actions for new and existing sources, but only 

new sources would be affected by this proposed action. The EPA 

met with 10 national organizations representing state and local 

elected officials to provide general background on the proposal, 

answer questions, and solicit input from state/local 
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governments. The UMRA discussion in this preamble includes a 

description of the consultation. While formulating the 

provisions of this proposed regulation, the EPA also considered 

the input provided in the over 2.5 million public comments on 

the April 13, 2012 proposed rule (77 FR 22392). In the spirit of 

EO 13132, and consistent with the EPA policy to promote 

communications between the EPA and state and local governments, 

the EPA specifically solicits comment on this proposed action 

from state and local officials.

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

Subject to the EO 13175 (65 FR 67249, November 9, 2000) the 

EPA may not issue a regulation that has tribal implications, 

that imposes substantial direct compliance costs, and that is 

not required by statute, unless the federal government provides 

the funds necessary to pay the direct compliance costs incurred 

by tribal governments, or the EPA consults with tribal officials 

early in the process of developing the proposed regulation and 

develops a tribal summary impact statement. 

The EPA has concluded that this proposed action would not 

have tribal implications. It would neither impose substantial 

direct compliance costs on tribal governments, nor preempt 

Tribal law. This proposed rule would impose requirements on 
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owners and operators of new EGUs. The EPA is aware of three 

coal-fired EGUs located in Indian Country but is not aware of 

any EGUs owned or operated by tribal entities. The EPA notes 

that this proposal does not affect existing sources such as the 

three coal-fired EGUs located in Indian Country, but addresses 

CO2 emissions for new EGU sources only.

Because the EPA is aware of Tribal interest in this 

proposed rule, prior to the April 13, 2012 proposal (77 FR 

22392), the EPA offered consultation with tribal officials early 

in the process of developing the proposed regulation to permit 

them to have meaningful and timely input into its development. 

The EPA’s consultation regarded planned actions for new and 

existing sources, but only new sources would be affected by this 

proposed action.

Consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA’s development of 

NSPS and emission guidelines for EGUs and offered consultation. 

A consultation/outreach meeting was held on May 23, 2011, with 

the Forest County Potawatomi Community, the Fond du Lac Band of 

Lake Superior Chippewa Reservation, and the Leech Lake Band of 

Ojibwe. Other tribes participated in the call for information 

gathering purposes. In this meeting, the EPA provided background 

information on the GHG emission standards to be developed and a 
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summary of issues being explored by the Agency. Tribes suggested 

that the EPA consider expanding coverage of the GHG standards to 

include combustion turbines, lowering the 250 MMBtu per hour 

heat input threshold so as to capture more EGUs, and including 

credit for use of renewables. The tribes were also interested in 

the scope of the emissions averaging being considered by the 

Agency (e.g., over what time period, across what units). In 

addition, the EPA held a series of listening sessions on this 

proposed action. Tribes participated in a session on February 

17, 2011 with the state agencies, as well as in a separate 

session with tribes on April 20, 2011.

While formulating the provisions of this proposed 

regulation, the EPA also considered the input provided in the 

over 2.5 million public comments on the April 13, 2012 proposed 

rule (77 FR 22392).

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
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The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) 

as applying to those regulatory actions that concern health or 

safety risks, such that the analysis required under section 5-

501 of the Order has the potential to influence the regulation. 

This proposed action is not subject to EO 13045 because it is 

based solely on technology performance. The proposal is not 

expected to produce notable changes in emissions of greenhouse 

gases or other pollutants but does encourage the current trend 

towards cleaner generation, helping to protect air quality and 

children's health. The Agency recognizes that children are among 

the groups most vulnerable to climate change impacts and the 

public is invited to submit comments or identify peer reviewed 

studies relevant to this proposal.

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This proposed action is not a “significant energy action” 

as defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. This proposed action is 

not anticipated to have notable impacts on emissions, costs or 

energy supply decisions for the affected electric utility 

industry.

I. National Technology Transfer and Advancement Act 
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Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 

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

Standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. The NTTAA directs the 

EPA to provide Congress, through annual reports to the OMB, with 

explanations when an agency does not use available and 

applicable VCS.

This proposed rulemaking involves technical standards. The 

EPA cites the following standards in this proposed rule: D5287-

08 (Standard Practice for Automatic Sampling of Gaseous Fuels), 

D4057-06 (Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products), and D4177-95(2010) (Standard Practice for 

Automatic Sampling of Petroleum and Petroleum Products). The EPA 

is proposing use of Appendices B, D, F, and G to 40 CFR part 75; 

these Appendices contain standards that have already been 

reviewed under the NTTAA.

The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 
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potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

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

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the U.S.

This proposed rule limits GHG emissions from new fossil 

fuel-fired EGUs by establishing national emission standards for 

CO2. The EPA has determined that this proposed rule would not 

result in disproportionately high and adverse human health or 

environmental effects on minority, low-income, and indigenous 

populations because it increases the level of environmental 

protection for all affected populations without having any 

disproportionately high and adverse human health or 
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environmental effects on any population, including any minority, 

low-income or indigenous populations.

XIII. Statutory Authority

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
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List of Subjects in 40 CFR Part 60

Environmental protection, Administrative practice and

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements.

___________________

Dated:[add signature date]

____________________

Gina McCarthy

Administrator