Vol. 79 Wednesday, 

No. 5 January 8, 2014 

Part II 

Environmental Protection Agency 

40 CFR Parts 60, 70, 71, et al. 

Standards of Performance for Greenhouse Gas Emissions From New 

Stationary Sources: Electric Utility Generating Units; Proposed Rule 

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1430 Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60, 70, 71, and 98 

[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 

withdrawing the April 13, 2012, 

proposal, and, in this action, the EPA is 

proposing new standards of 

performance for new affected fossil fuelfired 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 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. This action also 

includes related proposals concerning 

permitting fees under Clean Air Act 

Title V, the Greenhouse Gas Reporting 

Program, and the definition of the 

pollutant covered under the prevention 

of significant deterioration program. 

DATES: Comments. Comments must be 

received on or before March 10, 2014. 

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 January 8, 2014, a comment 

to the OMB is best assured of having its 

full effect if the OMB receives it by 

February 7, 2014. 

Public Hearing. A public hearing will 

be held on January 28, 2014, at the 

William Jefferson Clinton Building East, 

Room 1153 (Map Room), 1201 

Constitution Avenue NW., Washington 

DC 20004. The hearing will convene at 

9:00 a.m. (Eastern Standard Time) and 

end at 8:00 p.m. (Eastern Standard 

Time). Please contact Pamela Garrett at 

(919) (541–7966) or at garrett.pamela@

epa.gov to register to speak at the 

hearing. The last day to pre-register in 

advance to speak at the hearing will be 

2 business days in advance of the public 

hearing. Additionally, requests to speak 

will be taken the day of the hearing at 

the hearing registration desk, although 

preferences on speaking times may not 

be able to be fulfilled. If you require the 

service of a translator or special 

accommodations such as audio 

description, please let us know at the 

time of registration. 

The hearing will provide interested 

parties the opportunity to present data, 

views or arguments concerning the 

proposed action. The EPA will make 

every effort to accommodate all speakers 

who arrive and register. Because this 

hearing is being held at U.S. government 

facilities, individuals planning to attend 

the hearing should be prepared to show 

valid picture identification to the 

security staff in order to gain access to 

the meeting room. In addition, you will 

need to obtain a property pass for any 

personal belongings you bring with you. 

Upon leaving the building, you will be 

required to return this property pass to 

the security desk. No large signs will be 

allowed in the building, cameras may 

only be used outside of the building and 

demonstrations will not be allowed on 

federal property for security reasons. 

The EPA may ask clarifying questions 

during the oral presentations but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral comments 

and supporting information presented at 

the public hearing. Commenters should 

notify Ms. Garrett if they will need 

specific equipment, or if there are other 

special needs related to providing 

comments at the hearing. The EPA will 

provide equipment for commenters to 

show overhead slides or make 

computerized slide presentations if we 

receive special requests in advance. Oral 

testimony will be limited to 5 minutes 

for each commenter. The EPA 

encourages commenters to provide the 

EPA with a copy of their oral testimony 

electronically (via email or CD) or in 

hard copy form. Verbatim transcripts of 

the hearings and written statements will 

be included in the docket for the 

rulemaking. The EPA will make every 

effort to follow the schedule as closely 

as possible on the day of the hearing; 

however, please plan for the hearing to 

run either ahead of schedule or behind 

schedule. Information regarding the 

hearing (including information as to 

whether or not one will be held) will be 

available at: http://www2.epa.gov/

carbon-pollution-standards/. 

ADDRESSES: Comments. Submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2013–0495, by one of 

the following methods: 

At the Web site http://

www.regulations.gov: Follow the 

instructions for submitting comments. 

At the Web site http://www.epa.gov/

oar/docket.html: Follow the instructions 

for submitting comments on the EPA 

Air and Radiation Docket Web site. 

Email: Send your comments by 

electronic mail (email) to a-and-rdocket@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, William Jefferson Clinton 

Building West, Room 3334, 1301 

Constitution Ave. NW., Washington, DC 

20004, Attn: Docket ID No. EPA–HQ– 

OAR–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. 

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://

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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1431 

www.regulations.gov or email. 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 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 Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 

listed in the index, some information is 

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

information whose disclosure is 

restricted by statute). Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the EPA Docket Center, William 

Jefferson Clinton Building West, Room 

3334, 1301 Constitution Ave. NW., 

Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

federal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. Visit 

the EPA Docket Center homepage at 

http://www.epa.gov/epahome/

dockets.htm for additional information 

about the EPA’s public docket. 

In addition to being available in the 

docket, an electronic copy of this 

proposed rule will be available on the 

Worldwide Web (WWW) through the 

Technology Transfer Network (TTN). 

Following signature, a copy of the 

proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http://

www.epa.gov/ttn/oarpg/. 

FOR FURTHER INFORMATION CONTACT: 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 

considered comments submitted in 

response to the original April 13, 2012, 

proposal in developing this new 

proposal. However, we are withdrawing 

the original proposal. If you would like 

comments submitted on the April 13, 

2012 rulemaking to be considered in 

connection with this new proposal, you 

should submit new comments or resubmit your previous comments. 

Commenters who submitted comments 

concerning any aspect of the original 

proposal will need to consider the 

applicability of those comments to this 

current proposal and submit them again, 

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 

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 Megawatthour 

lb CO2/yr Pounds of CO2 per Year 

lb/lb-mole Pounds per Pound-Mole 

LCOE Levelized Cost of Electricity 

MATS Mercury and Air Toxic Standards 

MMBtu/hr Million British Thermal Units 

per Hour 

MW Megawatt 

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1432 Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 

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 nth-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 

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 

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 Section 111 Requirements 

D. Interpretation of CAA Section 111 

Requirements 

E. Rational Basis To Promulgate Standards 

for GHGs From Fossil-Fired 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 

C. Certain Projects Under Development 

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 

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. 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 

X. Impacts of the Proposed Action 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. 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? 

XI. Request for Comments 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

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 

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 gas-fired 

stationary combustion turbines. These 

proposed standards reflect separate 

determinations of the best system of 

emission reduction (BSER) adequately 

demonstrated for utility boilers and 

IGCC units and for natural gas-fired 

stationary combustion turbines. In 

contrast, the April 2012 proposal relied 

on a single standard and a single BSER 

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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1433 

1 In this rulemaking, all references to lb CO2/

MWh are on a gross output basis, unless specifically 

noted otherwise. 

2Conditions 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 (N2O), sulfur hexafluoride (SF6), 

hydrofluorocarbons (HFCs), and perfluorocarbons 

(PFCs). 

4For 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). 

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 a 

document (published separately in 

today’s Federal Register) that 

withdraws 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 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) pollution 3

threatens the American public’s health 

and welfare by contributing to longlasting 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 fuel-fired 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 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 sector,4 the 

EPA is issuing a new proposal to 

establish separate standards for fossil 

fuel-fired 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 document (published 

separately in today’s Federal Register) 

that withdraws the original proposal, 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 gasfired power plants and the nature of 

GHGs, the EPA should regulate CO2

from these power plants through the 

same NSPS regulatory structure that 

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, 

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5While 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. 

6Even 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. 

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. 

primarily undertaken by EIA, indicating 

that, while substantial reliance on coalfired electricity generation would 

continue in the future, few, if any, new 

coal-fired power plants 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 document and 

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 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 company’s W.A. 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 (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 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 fuel-fired 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 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 nonEGUs (turbines primarily used to 

generate steam and/or electricity for onsite 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. 

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 reasonable. 

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 efficient generation 

technology implementing partial CCS is 

the BSER for new affected fossil fuelfired boilers and IGCC units (subpart Da 

sources) and modern, efficient NGCC 

technology is the BSER for new affected 

combustion turbines (subpart KKKK 

sources). The 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 

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8The 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. 

9The 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. 

10The 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. 

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) highly efficient new 

generation with ‘‘full capture’’ CCS and 

(3) highly efficient new generation with 

‘‘partial capture’’ CCS. 

Generation technologies representing 

enhancements in operational efficiency 

(e.g., supercritical or ultra-supercritical 

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 coalfired generation capacity. However, they 

do not provide meaningful reductions in 

CO2 emissions from 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 highefficiency 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 efficiencyenhancing technology alone, as opposed 

to CCS, is the BSER for CO2 emissions 

from new coal-fired 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 nearly 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 projects 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) 

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-fired 

power generation 8 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 nonnatural 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 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 

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11While 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. 

12The Global CCS Institute, http://

www.globalccsinstitute.com/projects/browse. 

13For example, the Hydrogen Energy California 

facility plans to capture approximately 90 percent 

of the CO2 in the emission stream. 

14 ‘‘Operating Flexibility of Power Plants with 

CCS’’, International Energy Agency (IEAGHG) 

report 2012/6, June 2012. 

Plains Synfuels Facility 11 is a coal 

gasification facility that has captured at 

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 gasfired 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 

reasonable. 

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 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 coal-fired 

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 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 fuelfired 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 fuel-fired 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 gasfired 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. 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 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. 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 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 

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 start-ups/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 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 

codify the standards of performance for 

the respective sources within existing 

40 CFR Part 60 subparts. Applicable 

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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1437 

15 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

GHG standards for electric utility steam 

generating units would be included in 

subpart Da and applicable GHG 

standards for stationary combustion 

turbines would be included 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 include 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? 

This action presents the EPA’s 

proposed approach for setting standards 

of performance for new affected fossil 

fuel-fired 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 

fuel-fired utility boilers and IGCC units 

and for natural gas-fired stationary 

combustion turbines, respectively. 

Implications for Prevention of 

Significant Deterioration (PSD) and title 

V programs are described in Section IX, 

and impacts of the proposed action are 

described in Section X. In Section XI, 

the agency specifically requests 

comments on the proposal. A discussion 

of statutory and executive order reviews 

is provided in Section XII, and the 

statutory authority for this action is 

provided in Section XIII. Also published 

today in the Federal Register is the 

document withdrawing 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 ENTITIES a

Category NAICS 

Code Examples of Potentially Affected Entities 

Industry ....................................................... 221112 Fossil fuel electric power generating units. 

Federal Government .................................. b 221112 Fossil fuel electric power generating units owned by the federal government. 

State/Local Government ............................ b 221112 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). bFederal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

This table is not intended to be 

exhaustive, but rather to provide a guide 

for readers regarding entities likely to be 

affected by this proposed action. To 

determine whether your facility, 

company, business, organization, etc., 

would be regulated by this proposed 

action, you should examine the 

applicability criteria in 40 CFR 60.1. If 

you have any questions regarding the 

applicability of this action to a 

particular entity, consult either the air 

permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

II. Background 

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 

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, 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 

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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 FR 49557 (Aug. 13, 

2010) (‘‘Reconsideration Denial’’). 

17Coalition 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). 

18We discuss litigation history involving this 

rulemaking in more detail later in this section. 

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’’). 

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/ 

Endangerment_TSD.pdf (TSD). 

21http://www.epa.gov/climatechange/ 

endangerment/petitions.html. 

22 549 U.S. 497 (2007). 

23CRR, 684 F.3d at 117–27. 

24 Id. at 121. 

impacts. Children, the elderly, and the 

poor are among the most vulnerable to 

these climate-related health effects. 

2. Public Welfare Impacts Detailed in 

the 2009 Endangerment Finding 

Anthropogenic emissions of GHGs 

and consequent climate change also 

threaten public welfare in multiple 

aspects. Climate changes are expected to 

place large areas of the country at 

serious risk of reduced water supplies, 

increased water pollution, and 

increased occurrence of extreme events 

such as floods and droughts. Coastal 

areas are expected to face increased 

risks from storm and flooding damage to 

property, as well as adverse impacts 

from rising sea level, such as land loss 

due to inundation, erosion, wetland 

submergence and habitat loss. Climate 

change is expected to result in an 

increase in peak electricity demand, and 

extreme weather from climate change 

threatens energy, transportation, and 

water resource infrastructure. Climate 

change may exacerbate ongoing 

environmental pressures in certain 

settlements, particularly in Alaskan 

indigenous communities. Climate 

change also is very likely to 

fundamentally rearrange U.S. 

ecosystems over the 21st century. 

Though some benefits may balance 

adverse effects on 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 

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 

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 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 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 

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25 Id. at 125. 

26 Id. at 120. 

27 Id. at 120. 

28SREX, p. 7. 29Climate Stabilization Targets, p. 3. 

30Climate 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). 

31Sea Level Rise, p. 4. 

32National Security Implications, p. 9. 

33 ‘‘Climate and Social Stress: Implications for 

Security Analysis’’ (2012), p.3. 

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 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 reprove 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 

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 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 °C 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 °C will 

lead to a sea level rise of 0.5 to 1 meter 

by 2100. With an increase of 4 °C, 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. (It should be 

noted that in 2007, the IPCC stated that 

including poorly understood ice sheet 

processes could lead to an increase in 

the projections.) 30 While these 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 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 

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1440 Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 

34 ‘‘Understanding Earth’s Deep Past: Lessons for 

Our Climate Future’’ (2011), p.138. 

35 Ibid, p. 1. 

36 ‘‘Ocean Acidification: A National Strategy to 

Meet the Challenges of a Changing Ocean’’ (2010), 

p. 5. 

37 Id. 

38 74 FR 66524. 

39CRR, 684 F.3d at 121. 

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. 

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

Earth history.’’ 34 This assessment finds 

that CO2 concentrations by the end of 

the century, without a reduction in 

emissions, are projected to increase to 

levels that Earth has not experienced for 

more than 30 million years.35 The report 

draws potential parallels with nonlinear 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 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 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 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 emails 

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 

emails 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 emails purport to 

show about the state of climate change 

science is not adequate evidence to 

challenge the voluminous and welldocumented 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 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 

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42Unrelated to the Endangerment Finding and its 

validation by the Court, the EPA has made progress 

towards implementing the recommendations from 

the Inspector General. 

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. 

44Sinks are a physical unit or process that stores 

GHGs, such as forests or underground or deep sea 

reservoirs of carbon dioxide. 

45From Table 2–3 of ‘‘Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990–2011’’, 

April 15, 2013, EPA 430–R–13–001. 46Note 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.’’ 

review processes when referencing 

existing peer reviewed science in the 

EPA actions.42

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 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 FuelFired 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 fuel-fired units, 

coal-fired units are by far the largest 

emitters. This section describes the 

amounts of those emissions and places 

those amounts in the context of the 

national inventory of GHGs. 

The EPA prepares the official U.S. 

Inventory of Greenhouse Gas Emissions 

and Sinks 43 (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

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 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.) 

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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47Even 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 2024 in a case where power companies 

do assume GHGs emission limitations. 

48Levelized Cost of New Generation Resources in 

the Annual Energy Outlook 2011 http:// 

www.eia.gov/forecasts/aeo/ 

electricity_generation.html. 

49http://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-east-1.elb.amazonaws.com/w/ 

images/6/6d/0383%282011%29.pdf. 

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

chapter_legs_regs.cfm. 

51Energy Information Adminstration’s Annual 

Energy Outlook for 2013, Final Release available at 

http://www.eia.gov/forecasts/aeo/index.cfm. 

52EIA’s reference case projections are the result 

of its baseline assumptions for economic growth, 

fuel supply, technology, and other key inputs. 

We are aware that nitrous oxide (N2O) 

and, to a lesser extent, methane (CH4) 

may be emitted from fossil fuel-fired 

EGUs, especially from coal-fired 

circulating fluidized bed (CFB) 

combustors and from units with 

selective catalytic reduction (SCR) and 

selective 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 document 

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 combustion turbines. 

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 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, 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 percent 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 coalfired 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. 

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 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 2013,51 (i) shows that a 

modest amount of coal-fired power 

plants that are currently under 

construction are expected to begin 

operation in the next several years 

(referred to as ‘‘planned’’); and (ii) 

projects in the reference case,52 that a 

very small amount of new 

(‘‘unplanned’’) conventional coal-fired 

capacity, with CCS, will come online 

after 2012, and through 2034 in 

response to Federal and State 

incentives. According to the AEO 2013, 

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53Annual Energy Outlook 2010, 2011, 2012, and 

2013. 

54http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. 

55CAA section 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. 56CAA section 111(b)(1)(B). 57CAA section 111(a)(2). 58CAA section 111(a)(4). 59 40 CFR 60.2, 60.14(e). 60 40 CFR 60.15. 61CAA section 111(b)(2). 62As noted, we generally refer to this system of 

control as the best system of emission reduction, or 

Continued 

the vast majority of new generating 

capacity during this period will be 

either natural gas-fired or renewable. 

Similarly, 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 

2020.53

Specifically, the AEO 2013 projects 

the need for 25.9 GW of additional base 

load or intermediate load generation 

capacity through 2020 (this includes 

projects that are under development— 

i.e., being constructed or in advance 

planning—and model-projected 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 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 during the period from 2020 

through 2034, where new modelprojected (unplanned) intermediate and 

base load capacity is expected to be 

compliant with the proposed standard 

without incurring further control costs 

(i.e., an additional 45.1 GW of NGCC 

and no additional coal, for a total, from 

2013 through 2030, of 48.2 GW of NGCC 

and 0.3 GW of coal with CCS). 

It should be noted that under the EIA 

projections, existing coal-fired 

generation will remain an important 

part of the mix 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 approximately 40 

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.54 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, 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 demandside 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 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 coalfired 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 program, establishes mechanisms 

for regulating emissions of air pollutants 

from stationary sources that are key in 

this rulemaking.55 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.56 A ‘‘new source’’ is ‘‘any 

stationary source, the construction or 

modification of which is commenced 

after,’’ in general, the date of the 

proposal.57 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.’’ 58

The EPA, through regulations, has 

determined that certain types of changes 

are exempt from consideration as a 

modification.59 The EPA’s regulations 

also provide that an existing facility is 

also 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.60 In 

establishing standards of performance, 

the EPA has significant discretion to 

create subcategories based on source 

type, class or size.61

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).62

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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). 

63 ‘‘Standards of Performance for Fossil-FuelFired Steam Generators for Which Construction Is 

Commenced After August 17, 1971,’’ 36 FR 24875 

(Dec. 23, 1971) codified at 40 CFR 60.40–46; 36 FR 

5931 (Mar. 31, 1971). 

64 ‘‘Standards of Performance for Electric Utility 

Steam Generating Units for Which Construction is 

Commenced After September 18, 1978,’’ 44 FR 

33580 (June 11, 1979) 

65 ’’Standards of Performance for Electric Utility 

Steam Generating Units, Industrial-CommercialInstitutional Steam Generating Units, and Small 

Industrial-Commercial-Institutional Steam 

Generating Units, Final Rule.’’ 71 FR 9866 (Feb. 27, 

2006). 

66State 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’’). 

67CRR, 684 F.3d at 102. 

68 ‘‘Light-Duty Vehicle Greenhouse Gas Emission 

Standards and Corporate Average Fuel Economy 

Standards; Final Rule.’’ 75 FR 25324 (May 7, 2010). 69 ‘‘Interpretation of Regulations that Determine 

Pollutants Covered by Clean Air Act Permitting 

Programs.’’ 75 FR 17004 (April 2, 2010). 

70 ‘‘Prevention of Significant Deterioration and 

Title V Greenhouse Gas Tailoring Rule; Final Rule.’’ 

75 FR 31514 (June 3, 2010). 

71 Las Brisas Energy Center, LLC v. Environmental 

Protection Agency, No. 12–1248, 2012 U.S. App. 

LEXIS 25535 (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 

Industrial-Commercial-Institutional Steam 

Generating Units, Final Rulemaking, ’’ 78 FR 24073 

(April 24, 2013). 

73We 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. 

The standard that the EPA develops, 

based on the BSER, is commonly a 

numerical emissions limit, expressed as 

a performance level (e.g., a rate-based 

standard). Generally, the EPA does not 

prescribe a particular technological 

system that must be used to comply 

with a standard of performance. Rather, 

sources 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 IX of this preamble. 

E. Regulatory and Litigation Background 

The EPA initially included fossil fuelfired 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.63 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. None of these 

rulemakings or codifications, however, 

have constituted a new listing under 

CAA section 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.64 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 industrial-commercialinstitutional cogeneration units that sell 

more than 25 MW and more than onethird 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).65 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 D.C. Circuit.66

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 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.67 The Court also upheld 

standards for motor vehicles that 

limited GHG emissions.68 In addition, 

the Court affirmed the EPA’s view that 

the CAA PSD and title V permitting 

requirements became applicable to 

GHG-emitting 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,69

which established the January 2, 2011 

date when the PSD and title V 

permitting requirements applied to 

GHG-emitting stationary sources; and 

the Tailoring Rule,70 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. 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 

performance under CAA section 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. 

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74Other pending EPA regulatory actions in the 

power sector are discussed in more detail in 

Chapter 4 of the RIA. 

75 78 FR 24073. 

76Comments related to the listening sessions 

submitted via the electronic docket system are 

available at www.regulations.gov (docket number 

EPA–HQ–OAR–2011–0090). 

77Those comments are available at 

www.regulations.gov (docket number EPA–HQ– 

OAR–2011–0660). 

78E.g., 40 CFR 60.40Da(a)(1). 79 40 CFR 60.41Da (definition of (‘‘Electric utility 

steam-generating unit’’). 

80 Id. 

Therefore, few interactions are likely 

between other power sector rules and 

this rule, which focuses only on new 

sources.74

We note that the EPA recently 

finalized revisions to the MATS rule as 

related to new sources.75 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 commonsense, cost-effective manner consistent 

with the underlying statutory 

requirements and assures a reliable 

power system. Executive Order (EO) 

13563 states that ‘‘[i]n developing 

regulatory actions and identifying 

appropriate approaches, each agency 

shall attempt to promote . . . 

coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve 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 the 

harmonization 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 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.76

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, DC 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.77 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 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 our 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—in Sections V–VIII 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 fossil fuel,78 (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’’ 79 (that is, to the grid), 

and (3) ‘‘constructed for the purpose of 

supplying . . . more than 25 MW netelectric output’’ to the grid.80 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 add additional criteria to 

be met in addition to the ‘‘constructed 

for the purpose of supplying more than 

one-third of its potential electric output 

capacity’’ to the grid. One new criterion 

would be that a unit actually ‘‘supplies 

more than one-third of its potential 

electric output’’ to the grid. Both criteria 

would also be used in subparts KKKK 

and TTTT. Combined with the three 

year rolling average methodology to 

determine if the one-third criteria is met 

(as explained further below), this 

approach makes it clear that a unit that 

was not originally constructed to supply 

more than one-third of its potential 

electric output to the grid, but does so 

for one year does not automatically 

become affected. The EPA believes that 

coal-fired utility boilers, IGCCs and 

large NGCC units are constructed with 

the purpose of supplying more than 

one-third of their potential electric 

output to the grid, and, except in rare 

cases (such as very extended outages), 

usually do. Small NGCC units and 

simple cycle combustion turbines that 

are generally designed for operation 

during peak demand will usually 

supply less than one-third of their 

potential electric output to the grid. 

Even though these projects are not 

generally designed to supply more than 

one-third of their potential electric 

output to the grid, there can be rare 

instances when they do. For instance, 

when a large base load unit in a 

transmission-constrained area 

experiences a long, unexpected outage, 

it may be necessary to operate simple 

cycle combustion turbines significantly 

more than anticipated. The EPA 

believes the combination of the actual 

sales criteria and the three year rolling 

average to determine if the sales criteria 

are met will address this concern. 

Second, we are proposing to revise the 

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81The EPA’s draft accounting framework is 

available at http://www.epa.gov/climatechange/ 

ghgemissions/biogenic-emissions.html. 

82The text of the SAB Peer Review Advisory is 

available at http://yosemite.epa.gov/sab/

sabproduct.nsf/0/2f9b572c712ac52e8525783100704

886!OpenDocument&TableRow=2.3#2. 

83Oil-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). 

84CAA section 111(a)(2), (6). 

85This 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. 

third criteria to be met if the EGU is 

constructed for the purpose of 

supplying ‘‘more than 219,000 MWh,’’ 

as opposed to ‘‘25 MW,’’ net-electrical 

output to the grid. This proposed 

change 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 threeyear rolling average for stationary 

combustion turbines. In addition, we are 

proposing to add a new applicability 

criterion that is not currently in subpart 

Da: EGUs, for which 10 percent or less 

of the heat input over a three-year 

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, the 

proposed definition of potential electric 

output includes ‘‘or the design net 

electric output efficiency’’ as an 

alternative to the default one-third 

efficiency value for determining the 

value of the potential electric output. 

Next, we are proposing to add ‘‘of the 

thermal host facility or facilities’’ to the 

definition of net-electric output for 

determining electric sales with respect 

to the NSPS. 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 definition of a steam 

generating unit to include ‘‘plus any 

integrated equipment that provides 

electricity or useful thermal output to 

either the affected facility or auxiliary 

equipment’’ instead of the existing 

language ‘‘plus any integrated 

combustion turbines and fuel cells’’. 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 different 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).81 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 delivered its Peer 

Review Advisory to the EPA on 

September 28, 2012.82 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 gasfired stationary combustion turbines; 83

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 

section 111(a) definitions of ‘‘new 

source’’ and ‘‘existing source,’’ 84 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. 

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; 85 (2) natural gas-fired 

stationary combustion turbines with a 

heat input rating that is less than or 

equal to 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 

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86 40 CFR 60.41Da. 87 International Standards Organization Metric 

(ISO) Conditions are 288 Kelvin (15 °C), 60 percent 

relative humidity, and 101.325 kilopascals (kPa) 

pressure. 

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 

addition, we solicit comment on an 

emission limitation for new fossil fuelfired boilers and IGCC units in the range 

of 1,000–1,200 lb CO2/MWh. 

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 useful energy 

output over a rolling 12-operatingmonth period. In the alternative, we 

solicit comment on requiring 

calculation of compliance on an annual 

(calendar year) period. 

b. Gross Output 

Subpart Da currently defines ‘‘gross 

energy 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’’ 86 87 (referred 

to in today’s document 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 9304). In 

that rulemaking, we 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. 

Consequently, 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 the definition of gross 

energy output for criteria pollutant 

emission standards (i.e., adjusted gross 

output), both IGCC and traditional coalfired EGUs that have the same gross 

energy output-based emissions rate 

would have a similar net output-based 

emissions rate. If we did not include the 

parasitic load from the primary gas 

compressors when determining the 

gross emissions rate 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 ISO conditions that 

is not used to generate additional 

electrical or mechanical output or to 

enhance the performance of the unit 

(i.e., steam delivered to an industrial 

process).’’ 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 production at IGCC 

facilities could be more challenging to 

implement. 

Therefore, we are proposing to define 

the gross energy output for traditional 

steam generating units to include the 

electricity measured at the generator 

terminals minus electric power used to 

run the feedwater pumps, and to define 

the gross electric output for IGCC and 

subpart KKKK affected facilities to 

include the electricity measured at the 

generator terminals. We are considering 

and requesting comment on (1) whether 

the definition of ‘‘gross energy output’’ 

in subpart Da for GHGs should be 

consistent with the current definition in 

subpart Da for criteria pollutants, (2) 

whether we should adopt the proposed 

definition of ‘‘gross energy output’’, and 

(3) whether the definition should be the 

same for both traditional and IGCC 

facilities. We seek comment on how to 

account for energy consumption 

associated with products other than 

electricity and useful thermal output 

created at a poly-generation facility and 

the impact of that energy use on the 

numerical emissions standard, all of 

which is relevant to possible adoption 

of an adjusted gross output definition. 

We are also considering and 

requesting comment on using net-output 

based standards either as a compliance 

alternative for, or in lieu of, gross-output 

based standards, including whether we 

should have a different approach for 

different subcategories. In the 

compliance alternative approach, 

owners/operators would elect to comply 

with either a gross-output 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 coalfired station power output, 

approximately 15 percent of non-CCS 

IGCC-based coal-fired station power 

output and about 2.5 percent of nonCCS combined cycle station power 

output is used internally by parasitic 

energy demands, but the amount of 

these parasitic loads vary from source to 

source. Reasons for using net output 

include (1) recognizing the efficiency 

gains of selecting EGU designs and 

control equipment that require less 

auxiliary power, (2) selecting fuels that 

require less emissions control 

equipment, and (3) recognizing the 

environmental benefit of higher 

efficiency motors, pumps, and fans. 

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88Rounding to two significant figures results in 

the same standard in units of lb/MWh in some 

cases. 89 551 F.3d 1019 (D.C. Cir. 2008). 

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 noted, switching from gross 

output to net or adjusted gross output 

would have little or no impact on the 

required rates for gas-fired NGCC plants, 

which are likely to be the dominant 

fossil fuel-fired technology for new 

intermediate or base load power 

generation. Since the change would 

have little impact on these units in 

terms of environmental performance, 

the EPA has proposed to use a standard 

consistent with current reporting 

protocols. However, as is noted in Table 

4, the use of net instead of gross output 

could have a much larger impact on 

coal-fired power plants. 

TABLE 4—SUBPART DA EMISSION RATES 88

Gross output based standard Approximate equivalent adjusted gross 

output based standard 

Approximate 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). 

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 

Approximate 

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 technology options available 

to comply with the standard for coalfired 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. 84-Operating-Month Rolling Average 

Compliance Option 

We also propose an 84-operatingmonth rolling average compliance 

option that would be available for 

affected subpart Da boilers and IGCC 

facilities. The EPA suggests that this 84- 

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 1,000 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-operatingmonth standard. We also request 

comment on whether owners/operators 

electing to comply with the 84- 

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 what the standard should 

be. This shorter term standard would 

facilitate enforceability 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 84-operatingmonth 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 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,89

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

standard, we accounted for periods of 

startup and shutdown by incorporating 

them as periods of partial load 

operation. As noted above, the proposed 

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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. 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 partial load is 

believed to have a negligible effect on 

the performance of the source with 

respect to long-term efficiency. 

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 84-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 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 data-gathering 

necessary to solve a problem. We 

generally defer to an agency’s decision 

to proceed on the basis of imperfect 

scientific information, rather than to 

‘‘invest the resources to conduct the 

perfect study.’’). See also, Weyerhaeuser 

v. Costle, 590 F.2d 1011, 1058 (D.C. 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 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 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 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 § 60.5530 and to 

prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the evidence that 

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‘‘[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 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 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 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). Although due to intervening case 

law such as Sierra Club v. EPA and the 

CAA 1977 amendments (which added 

the ‘‘continuous’’ requirement of 42 

U.S.C. 7602(k)) these cases are no longer 

good law on whether EPA can exempt 

malfunctions from liability, their core 

principle remains valid: regulatory 

accommodation is appropriate where a 

standard cannot be achieved 100 

percent of the time due to circumstances 

out of the control of the owner/operator 

of the source, and 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 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-operatingmonth standard and the 84-operatingmonth rolling average compliance 

option; however, we will take comment 

on whether it is appropriate to have an 

affirmative defense for the 84-operatingmonth rolling average portion of that 

compliance option, given that we would 

expect malfunctions 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 

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 Appendix A to part 75 

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 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 

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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 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 sitespecific 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. 

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 

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 qualityassured 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-operatingmonths of data, starting with the month 

in which emissions are first required to 

be reported. The initial 12-operatingmonth 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 84- 

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, quality-assured data from the 

certified Part 75 monitoring systems 

would 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 84-operating-month 

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 84- 

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 requirements in subpart 

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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 carbon-based 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 84- 

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 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 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 84-operatingmonth 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 for the quarter that 

includes the final (60th) operating 

month of the initial 84-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. 

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 subparts Da, 

KKKK, and TTTT 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 FossilFired EGUs 

A. Overview 

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 section 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 section 

111(b)(1)(A). 

We have reconsidered that proposal 

in light of the numerous comments we 

received. In today’s document, we 

propose that under section 111, the EPA 

is required to have a rational basis for 

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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1453 

90 It should be noted that CAA section 111 clearly 

applies to GHGs. The U.S. Supreme Court has made 

this clear because (i) section 111 applies to ‘‘any air 

pollutant,’’ CAA section 111(a)(3), see section 

111(d)(1)(A) (exempting, for purposes of section 

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 section 302(g), includes GHGs; and (ii) in 

American Electric Power Company v. Connecticut, 

131 S.Ct. 2527 (2011), the Supreme Court 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 section 111 ‘‘provides a means to seek limits 

on emissions of carbon dioxide from domestic 

power plants * * *.’’ Id. at 2538. 

91 467 U.S. 837 (1984). 

92 Id. at 842–43. 

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 has 

concluded that even if section 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 steam-generating 

units and turbines) that the EPA already 

listed under CAA section 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 section 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, 2012.90

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 fuelfired 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 Section 111 Requirements 

To review the key CAA section 111 

requirements: CAA section 111(b)(1)(A), 

by its terms, requires that the 

Administrator publish (and from time to 

time thereafter shall revise) a list of 

categories of stationary sources. He shall 

include a category of sources in such 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 section 111(b)(1)(B) goes on to 

provide that after listing the source 

category, the EPA must promulgate 

regulations ‘‘establishing federal 

standards of performance for new 

sources within such category.’’ In turn, 

CAA section 111(a)(1) defines a 

‘‘standard of performance’’ as a 

‘‘standard for emissions of air pollutants 

which reflects the degree of emission 

reduction which (taking into account 

* * * cost * * * and any nonair quality 

health and environmental impact and 

energy requirements) . . . has been 

adequately demonstrated.’’ CAA section 

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 Section 111 

Requirements 

CAA section 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 section 111(b)(1)(A), the EPA may 

make these determinations on the basis 

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 section 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 section 

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 section 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). 

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, 91 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.92 In this 

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1454 Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 

93 ‘‘Air Pollution Prevention and Control: List of 

Categories of Stationary Sources,’’ 36 FR 5931 

(March 31, 1971). 

94 ‘‘Standards of Performance for Fossil-FuelFired Steam Generators for Which Construction Is 

Commenced After August 17, 1971,’’ 36 FR 24875 

(Dec. 23, 1971) codified at 40 CFR 60.40–46; 36 FR 

5931 (Mar. 31, 1971). 

95 42 FR 53657 (Oct. 3, 1977). 

96 ‘‘Standards of Performance for Electric Utility 

Steam Generating Units for Which Construction is 

Commenced After September 18, 1978,’’ 44 FR 

33580 (June 11, 1979). 

97 44 FR 33580 (June 11, 1979). 

98 71 FR 38497 (July 6, 2006), as amended at 74 

FR 11861 (Mar. 20, 2009). 

99 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 FR 22410/2–22411/3. 

100Under 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. 

case, the EPA is authorized to develop 

a reasonable interpretation. 

Our interpretation is that in order to 

promulgate a section 111 standard of 

performance for a particular pollutant, 

we do not need to make a pollutantspecific 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 

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 section 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 pollutantby-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, 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) 93 and the EPA 

promulgated the first set of standards of 

performance for this source category in 

1971, which the EPA codified in subpart 

D.94 Subsequently, the EPA included 

fossil fuel-fired combustion turbines in 

a category that the EPA listed under 

section 111(b)(1)(A),95 and the EPA 

promulgated standards of performance 

for this source category in 1979, which 

the EPA codified in subpart GG.96

The EPA has revised those 

regulations, and in some instances, has 

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 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.97 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.98 None of these rulemakings, 

including the revised codifications, 

however, constituted a new listing 

under CAA section 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., steamgenerating boilers and turbines. 

Moreover, we are establishing different 

requirements for different sets of 

sources, including steam-generating 

boilers as well as smaller and larger 

combustion turbines, in accordance 

with CAA section 111(b)(2). That 

provision authorizes the EPA to 

‘‘distinguish among classes, types, and 

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.99 Our 

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 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.100 This category, 

created by combining two existing 

categories, cannot be considered a new 

source category that EPA is placing on 

the list of categories for regulation under 

CAA section 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 coproposal to combine the categories and 

codify the GHG standards for all new 

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 

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101 627 F.2d 416 (D.C. Cir. 1980). 

102 Id. at 431–32 n.48. 

103 539 F.2d 775 (D.C. Cir. 1976). 

104 Id. at 784. 

105 74 FR 66496, 66519 (Dec. 15, 2009). 

106 75 FR 25324, 25396–97 (May 7, 2010). 

107Commenters on the original proposal stated 

that new solid-fuel fired power plants made no 

contribution to air pollution because EPA’s 

modeling projected no new construction of those 

types of plants. However, CAA section 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. 

108 627 F.2d at 432, n. 48. 

109 539 F.2d at 784–85. 

fired steam generating units and 

combustion turbines. 

E. Rational Basis To Promulgate 

Standards for GHGs From Fossil-Fired 

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 section 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 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 

section 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,101 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 section 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.102

Similarly, in National Asphalt 

Pavement Ass’n v. Train,103 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.104

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 

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 

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.’’ 105 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.106

Further, the fact that affected EGUs 

emit almost one-third of all U.S. GHGs 

and comprise by far the largest 

stationary source category of GHG 

emissions, 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.107 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 twentyfifth 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.’’).108

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.’’ 109

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 

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110 Indeed, it is literally true that if fossil-fuel 

fired EGUs cannot be found to contribute 

significantly to GHG air 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 section 111. 

111 ‘‘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 FR 49556, 58 (Aug. 13, 2010). 

112 Massachusetts v. EPA, 549 U.S. 497. 

113CRR, 684 F.3d at 102. 

114 Id at 121. 

115 Id at 120. 

116 Id at 125. 

basis, as described, should be 

considered to constitute those findings. 

As noted above, the EPA’s rational 

basis for regulating under section 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. 

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-contributesignificantly finding for CO2 emissions 

from the fossil fuel-fired EGUs, as a 

prerequisite to regulating such 

emissions under CAA section 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 one-third 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.110

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) 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 

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, 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 not of ‘‘central relevance’’ to the 

Finding.111 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,112 and were 

adequately supported by the 

administrative record.113 The Court 

found that the EPA had based its 

decision on ‘‘substantial scientific 

evidence,’’ 114 and noted that the EPA’s 

reliance on assessments was consistent 

with the methods decision-makers often 

use to make a science-based 

judgment.115 The Court also found that 

the Petitioners had ‘‘not provided 

substantial support for their argument 

that the Endangerment Finding should 

be revised.’’ 116 Moreover, the Court 

assessed the EPA’s reliance on the major 

scientific assessment reports that were 

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117 Id at 120. 

118 Id at 120. 

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.117

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 reprove the existence of the atom every time it 

approaches a scientific question.118

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 peerreviewed 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 

assessment also concludes that, 

combined with increasing vulnerability 

and exposure of populations and assets, 

changes in extreme weather and climate 

events have consequences for disaster 

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 °C 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 °C will 

lead to a sea level rise of 0.5 to 1.0 

meters by 2100; and with an increase of 

4 °C, 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 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 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 

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119 74 FR 66524. 

120CRR, 684 F.3d at 121. 

121 74 FR 66512 (emphasis added). 122 984 F.3d at 117. 

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 PaleoEocene 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.’’ 

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. 

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’’,119 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.’’ 120 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 peerreviewed 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 has determined that they are outside 

the scope of the endangerment analysis.121

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.122

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 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 

emails 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. Local observed changes 

can be of great concern to individuals 

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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 fuel-fired 

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 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 standards of performance apply to 

a facility if the facility supplies more 

than one-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 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 onethird 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 

allowing 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 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., sales of less than twofifths 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 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 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 twofifths 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. 

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123 (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. 

124 (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. 

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 MMBtu/h.123 The 33 

percent efficient facility would become 

subject to the NSPS requirements when 

it sells more than one-third 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.124 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. 

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. This 

is because these types of units more 

closely resemble the non-fossil fuelfired 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 fuelfired 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 threeyear 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 propose 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 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 adjacent 

facility using the thermal output from 

the CHP facility (i.e., the thermal host) 

can subtract out power purchased by the 

adjacent 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 host(s) are not under 

common ownership. We are therefore 

proposing to add ‘‘of the thermal host 

facility or facilities’’ to the definition of 

net-electric output for qualifying CHP 

facilities (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-partyowned 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 

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. 

We solicit comment on various issues 

concerning, and different approaches to, 

the applicability requirements for steam 

generating units and combustion 

turbines. In particular, we recognize that 

several of the requirements proposed 

today are based on the source’s 

operations. These include, for both 

steam generating units and combustion 

turbines, the requirement that the 

source supply more than one-third of its 

potential electric output and more than 

219,000 MWh net-electric output to the 

grid for sale on an annual or tri-annual 

basis (the one-third and 219,000 MWh 

sales requirement), as well as the 

requirement that the source burn fossil 

fuel for more than 10 percent of the heat 

input during three years; and for 

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125The NSPS regulations include definitions of 

‘‘commenced’’ and ‘‘construction’’. See 40 CFR 

60.2. 

126The 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/news-views-articles/as-coalplant-teeters-groups-mount-legal-attack.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. 

127 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 construction commencement 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 that 

determination. The purpose of this automatic 

withdrawal is to ensure that the project is placed 

on the same footing as the Wolverine project as 

Continued 

combustion turbines, the additional 

requirement that the source combust 

over 90 percent natural gas on a heat 

input basis over three years. 

We solicit comment on whether these 

requirements raise implementation 

issues because they are based on source 

operation after construction has 

occurred. We also solicit comment on 

whether, to avoid any such 

implementation issues, these 

requirements should be recast to be 

based on the source’s purpose at the 

time of construction. For example, 

should we recast the 10% percent 

requirement so that it would be met if 

the source was constructed for the 

purpose of burning fossil fuel for more 

than 10 percent of its heat input over 

any three-year period? 

In addition, we solicit comment on 

whether we should include these 

requirements not as applicability 

requirements for whether the source is 

subject to the standard of performance, 

but rather as criteria for which part of 

the standard of performance the source 

is subject to. Under this approach, at 

least for combustion turbines, the EPA 

would promulgate applicability 

requirements or a definition of utility 

unit designed to assure that combustion 

turbine utility units—but not 

combustion turbine industrial units or 

other types of non-utility units—would 

be subject to the standard of 

performance. For example, under this 

approach, all combustion turbine units 

that meet such applicability 

requirements or definition of utility 

units and that have a design heat input 

to the turbine engine greater than 250 

MMBtu/h, would be subject to the 

standard of performance for CO2

emissions. That standard would be: (i) 

during periods when certain conditions 

(noted below) are met, 1,000 or 1,100 lb 

CO2/MWh (depending on whether the 

unit has a design heat input to the 

turbine engine of greater than 850 

MMBtu/h); and (ii) during periods when 

one or more of those conditions is not 

met, no emission limit (that is, the unit 

could emit at an uncontrolled level). In 

the latter case, although the unit would 

not be subject to an emission limit, it 

would remain subject to the standard of 

performance, and therefore would be 

subject to any monitoring, reporting, 

and recordkeeping requirements. The 

conditions could include, during any 3- 

year period on a rolling average basis, 

combusting over 10% fossil fuel on a 

heat input basis, combusting over 90% 

natural gas on a heat input basis, and 

selling more than one-third of potential 

electric output and more than 219,000 

MWh net-electric output to the grid. 

Under this approach, as noted, in 

order to be consistent with today’s 

proposal to apply the standard of 

performance for CO2 emissions to only 

utility units—and not to industrial or 

other non-utility units—we would need 

to include other applicability 

requirements or definitional provisions 

that would explicitly limit the standard 

to utility units. 

We solicit comment on all aspects of 

this approach, including the extent to 

which it would achieve the policy 

objectives of assuring that a simple 

cycle turbine and a combined cycle 

turbine are subject to the same standard 

if they sell more than one-third of their 

capacity and more than 219,000 KWh 

net electric output to the grid, and are 

subject to the same standard if they sell 

less than those amounts to the grid. We 

also solicit comment on how to 

implement the three-year requirements 

described above during the period 

within three years after an affected EGU 

begins operations. For example, under 

the approach where operational criteria 

that entail a three-year compliance 

period are used to determine to which 

standard of performance the facility is 

subject, the owner or operator and 

permitting authority would not know 

for certain what standard applies to the 

facility until three years after initial 

startup. For this scenario, we request 

comment on how to implement the 

three year operational requirements and 

what documentation should be 

collected and reported to the EPA 

during the period up to the end of the 

third year after a source begins 

operation. 

C. 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 125 in the very near future and, 

as currently designed, could not meet 

the 1,100 lb CO2/MWh standard 

proposed for other new fossil fuel-fired 

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.126 At the time of finalization 

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 

should be situated similarly to the 

Wolverine project. Accordingly, if it is 

determined in the future that either of 

these projects has not commenced 

construction as of the date of this 

proposal, then that project will be 

addressed in the same manner as the 

Wolverine project.127 Further discussion 

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soon as possible. It is worth noting that nothing in 

this proposal binds the EPA to the position that the 

projects have ‘‘commenced construction’’ for NSPS 

purposes. 

128 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). 

129The 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. 

130Portland 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). 

131 In the 1970 CAAA, Congress defined 

‘‘standard of performance,’’ under section 111(a)(1), 

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) 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 

is provided in the technical support 

document in the docket referenced 

above.128

We invite comment on all aspects of 

this approach for addressing the 

Wolverine project (and the Washington 

County and Holcomb projects, if 

applicable).129

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 

section 111 that we propose in this 

rulemaking, which is that the standards 

must consist of emission limits that are 

based on the ‘‘best system of emission 

reduction . . . adequately 

demonstrated,’’ taking into account cost 

and other factors (BSER). In this 

manner, CAA section 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 

section 111 is designed to 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 section 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.’’ section 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. section 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.’’ section 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.’’ section 111(a)(1). 

2. Court Interpretation 

For present purposes, the key section 

111 provisions are the definition of 

‘‘standard of performance,’’ under CAA 

section 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 section 111 

on numerous occasions during the past 

40 years, handing down decisions dated 

from 1973 to 2011,130 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 section 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.131

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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 section 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. 

132See Sierra Club v. Costle, 657 F.2d 298, 326 

(D.C. Cir. 1981). 

133See Sierra Club v. Costle, 657 F.2d at 347. 

134See Sierra Club v. Costle, 657 F.2d at 330. 

135See Lignite Energy Council v. EPA, 198 F.3d 

930, 933 (D.C. Cir. 1999). 

136Sierra Club v. Costle, 657 F.2d at 325 & n.83 

(quoting 44 FR 33580, 33581/3–33582/1). 

137See, e.g., International Harvester Co. v. EPA, 

478 F.2d 615, 640 (D.C. Cir. 1973). 

138 486 F.2d at 390. 

139Portland Cement Ass’n v. Ruckelshaus, 486 

F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 

140See, 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). 

141Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d at 437 & n. 27. 

142Sierra 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.’’ 

3. Overview of Interpretation 

By its terms, the definition of 

‘‘standard of performance’’ under CAA 

section 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 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’’ 132 and ‘‘technological 

innovation.’’133

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.134 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.’’ 135

Moreover, the Court has stated that in 

considering the various factors and 

determining the ‘‘best system,’’ the EPA 

must be mindful of the purposes of 

section 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.’’136 Finally, based 

on cases the D.C. Circuit has handed 

down under related provisions of the 

CAA and the EPA’s regulatory 

precedent under section 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.137

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 

section 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 

industry met the requirement to be 

‘‘achievable,’’ which, in turn, depended 

on whether the technology on which 

EPA based the standard was 

‘‘adequately demonstrated.’’ 138 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.139

In subsequent cases, the D.C. Circuit has 

consistently reiterated this formulation 

of ‘‘achievable.’’ 140

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 percent above the 

standard on a total of 19 occasions.141

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 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’’).142 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 

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143Essex 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)). 

144The 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. 

145Portland Cement Association v. Ruckelshaus, 

486 F.2d at 387–88. 

146Sierra Club v. Costle, 657 F.2d at 313 (citations 

omitted) (emphasis added). 

147Similarly, 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 FR 62624, 62628–29; 62923– 

27; 62942–46 (October 15, 2012) (rulemaking setting 

GHG emissions standards for Light-Duty Vehicles 

for Model Years 2017–2025). 

controlled to the ‘maximum practicable 

degree.’ ’’ 143

2. Costs 

In several cases, the D.C. Circuit has 

elaborated on the cost factor that the 

EPA is required to consider under CAA 

section 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 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 the industry 

could bear and survive.’’ 144

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 convenience, in this rulemaking, we 

will use reasonableness as the standard, 

so that a control technology may be 

considered the ‘‘best system of emission 

reduction . . . adequately 

demonstrated’’ if its costs are 

reasonable, but cannot be considered 

the best system if its costs are 

unreasonable. 

(ii) Examples 

In the case law under CAA section 

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 

‘‘economic costs to the industry.’’ 145

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.146

b. Revenue Enhancements 

In determining the costs of pollution 

control technology, it is reasonable to 

take into account any revenues 

generated by 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 byproducts 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).147

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148Sierra Club v. Costle, 657 F.2d at 347. 

149S. Rep. 91–1196 at 16 (1970). The technologyforcing nature of section 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). 

150S. 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 

section 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’’). 

151See 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’’). 

152See 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’’). 

153See Sierra Club v. Costle, 657 F.2d at 351 

(upholding a standard of performance designed to 

promote the use of an emerging technology). 

154Sierra Club v. Costle, 657 F.2d at 351. 

155Sierra Club v. Costle, 657 F.2d at 330. 

156Sierra 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.’’ 

157Sierra 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. 

158Sierra Club v. Costle, 657 F.2d at 331 (citations 

omitted) (citing legislative history). 

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 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.148

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.149

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 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.150

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) 151; (ii) the expanded use of the 

best demonstrated technology; 152 and 

(iii) the development of emerging 

technology.153

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.154 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.155

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 

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.156

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 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 long-term effects.157

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 111.158

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159Sierra Club v. Costle, 657 F.2d at 337–39. 

160Sierra Club v. Costle, 657 F.2d at 327–28 

(quoting 44 FR 33583/3–33584/1). 

161Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 

842–43 (1984). 

162Sierra Club v. Costle, 657 F.2d at 319. 163Sierra Club v. Costle, 657 F.2d at 321. 164 Lignite Energy Council v. EPA, 198 F.3d 930, 

933 (D.C. Cir. 1999) (paragraphing revised for 

convenience). 

165S. Rep. 91–1116 at 16 (1970). See 116 Cong. 

Rec. 42,384 (statement of Sen. Muskie) 

(summarizing the House-Senate Conference 

agreement).) 

166See S. Rep. 91–1196 at 16 (1970). 

The Court then examined the EPA’s 

justification for the variable standard, 

and held that the justification was 

reasonable.159 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: 

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.160

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 section 111(a)(1), among other 

things, to authorize the EPA to balance 

economic, environmental, or energy 

factors through a 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.161

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 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 section 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,’’ 162 and emphasized that ‘‘[t]he 

text gives the EPA broad discretion to 

weigh different factors in setting the 

standard.’’ 163 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 111.164

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 Sources 

Under CAA section 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 section 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 section 111. 

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 operations 

* * *.165

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.166

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 

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167 1970 Senate Commitee Report at 2. 

168 116 Cong. Rec. 32,917 (1970) (statement of 

Sen. Muskie). 

169See 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). 

170 International Harvester Co. v. EPA, 478_F.2d 

at 640. 

171NRDC v. EPA, 489 F.3d at 1376. 

172Standards of Performance for New Stationary 

Sources, Primary Copper, Zinc, and Lead Smelters, 

41 FR 2331, 2333 (Jan. 15, 1976). 

173 41 FR 2333. 

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.’’ 167 Senator Muskie added: 

Land use planning and control should be 

used by State, local, and regional agencies as 

a method of minimizing 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.168

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.169

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 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 

U.S.C. 1857f–1(b)(5)(D) (1970 CAAA)), 

to grant automakers a one-year 

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 

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.170

Similarly, in a 2007 decision under 

CAA section 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.’’ 171

Thus, these decisions supported 

EPA’s emissions 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 coalfired 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 

‘‘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.172

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....173

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 for new 

fossil fuel-fired boiler and IGCC EGUs, 

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174This is on a gross output basis. All emission 

rates in this section are on a gross output basis 

unless specifically noted otherwise. 

175 It should be noted that the standard of 

performance that we propose in this rulemaking for 

new fossil-fired utility steam-generating units of 

1,100 lb CO2/MWh applies to new liquid 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 liquid oil- and natural gas-fired units. That is 

because no new utility steam-generating units 

designed to be fired primarily with liquid 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. 

176Subcritical 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. 

177Sierra Club, F.2d at 327 & n. 83 (quoting 44 

FR 33581/3—33582/1). 

178Exhibit 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). 

179 ‘‘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/NETL–2010/

1397 (November 2010). 

180The 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. 

181The only exception that we are aware of is the 

Virginia City subcritical CFB unit. 

182Ultra-supercritical (USC) and advanced ultrasupercritical (A–USC) are terms often used to 

designate a coal-fired power plant design with 

steam conditions well above the critical point. 

183Sierra Club, F.2d at 327 & n. 83 (quoting 44 

FR 33581/3—33582/1). 

which are based on our proposal that 

efficient generating technology 

implementing partial CCS is the BSER 

adequately demonstrated for those 

sources. 

As noted, CAA section 111 and 

subsequent court decisions establish a 

set of factors for the EPA to consider in 

a BSER determination, including criteria 

listed in CAA section 111 or identified 

in the court decisions and the 

underlying purposes of section 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) highly efficient new 

generation technology with ‘‘full 

capture’’ CCS (that is, CCS with capture 

of at least 90 percent CO2 emissions) 

and (3) highly efficient new generation 

technology with ‘‘partial capture’’ CCS 

(that is, CCS with capture of a lower 

level of CO2 emissions). 

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 84- 

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.174

We then explain our rationale for the 

requirements for geologic 

sequestration.175

B. Identification of the Best System of 

Emission Reduction 

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 

supercritical 176 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 section 111 of providing ‘‘as much 

[emission reduction] as practicable.’’ 177

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 

approximately 1,800 lb CO2/MWh,178 a 

new SCPC unit using bituminous coal 

would emit nearly 1,700 lb CO2/MWh, 

and a new IGCC unit 179 would emit 

about 1,450 lb CO2/MWh.180

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-fired EGUs that have 

broken ground have been high 

performing versions of SCPC or IGCC 

projects.181 Among those plants are: (1) 

AEP’s John W. Turk, Jr. Power Plant, a 

600 MW ultra-supercritical 182 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. These 

facilities all use advanced generation 

technology: Turk, as noted, is an ultrasupercritical 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 section 111 to achieve ‘‘as much 

[emission reduction] as practicable.’’ 183

As we discuss below, identifying CCSpartial capture as the BSER would 

provide for significantly greater 

emissions reductions. 

b. Lack of Incentive for Technological 

Innovation 

Identifying highly efficient generation 

technology as the BSER would not 

achieve another purpose of CAA section 

111, to encourage the development and 

implementation of control technology. 

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184http://www.aep.com/newsroom/newsreleases/

?id=1704. 

185 ‘‘Cost and Performance of PC and IGCC Plants 

for a Range of Carbon Dioxide Capture’’, DOE/

NETL–2011/1498, May 27, 2011. 

186The 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/gasifipedia/4-gasifiers/4-3_syngastable2.html). 

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 coalfired generation does not advance the 

development and implementation of 

control technologies that reduce CO2

emissions. In 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 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.184

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. 

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 section 

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.185 The study identified 

technical configurations that were 

tailored to achieve a specific level of 

carbon capture. 

a. SCPC 

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 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 CO2.186 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. 

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, two-stage 

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). 

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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 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 twostage WGS with bypass and the twostage 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: 

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, 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 postcombustion CO2 scrubbers that have 

been designed and sized to treat only a 

portion of the flue gas stream. 

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 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 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. 

With a standard of 1,000 lb CO2/MWh, 

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 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 


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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1471 

187Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010), page 7. 

188 ‘‘An Assessment of the Commercial 

Availability of Carbon Dioxide Capture and Storage 

Technologies as of June 2009’’, PNNL–18520, 

Pacific Northwest National Laboratory, Richland, 

WA, June 2009. Available at: http://www.pnl.gov/ 

main/publications/external/technical_reports/ 

PNNL-18520.pdf. 

189The ‘‘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. 

190 ‘‘Cost and Performance of PC and IGCC Plants 

for a Range of Carbon Dioxide Capture’’, DOE/ 

NETL–2011/1498, May 27, 2011. 

191Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010). 

192 Id at 29. 

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, 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, a new 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/MWh without the use of 

CCS. An emissions rate of 1,400 lb CO2/ 

MWh would provide even less 

technology development and emissions 

reductions. At an emissions rate of 

1,400 lb CO2/MWh, an IGCC facility 

could comply with no WGS reactor and 

by (i) capturing less than 5 percent 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 addition, at an emissions rate of 

1,400 lb CO2/MWh 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 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 

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 fuel-fired industrial plants 

currently in commercial operation and 

pilot-scale fossil fuel-fired EGUs 

currently in operation, the progress 

towards completion of construction of 

fossil fuel-fired 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 

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-a-kind 

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.187

The Pacific Northwest National 

Laboratory (PNNL) recently prepared a 

study that evaluated the development 

status of various CCS technologies for 

the DOE.188 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 particular their ‘‘Cost 

and Performance Baseline’’ reports,189

including one on partial capture 190— 

that further support our proposed 

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. 

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.191

In general, CO2 capture technologies 

applicable to coal-fired power 

generation can be categorized into three 

approaches: 192

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1472 Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 

193 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. 

194Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010). 

195McCollum, D., Ogden, J., 2006. TechnoEconomic Models for Carbon Dioxide Compression, 

Transport, and Storage & Correlations for Estimating 

Carbon Dioxide Density and Viscosity. Institute of 

Transportation Studies, University of California, 

Davis, Davis, CA. 

196McCoy, 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. 

197 DOE/NETL. (2013). Carbon Dioxide Transport 

and Storage Costs in NETL Studies, Quality 

Guidelines for energy system studies. March 2013. 

DOE/NETL–2013/1614. 

198Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010). 

199 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. 

200Benson, Sally M. and David R. Cole. (2008). 

CO2 Sequestration in Deep Sedimentary 

Formations. Elements, Vol. 4, pp. 325–331. 

201Sleipner in the North Sea, Sn<hvit in the 

Barents Sea, In Salah in Algeria, and Weyburn in 

Canada. 

202Report of the Interagency Task Force on 

Carbon Capture and Storage (August 2010). 

203Han, 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. 

204Sewell, 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.global

ccsinstitute.com/sites/default/files/publications/

39961/ccsinwareport-opt.pdf. 

• 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 highpurity O2, rather than air, to combust 

coal and thereby produce a highly 

concentrated CO2 stream. 

Each of these three carbon capture 

approaches (pre-combustion, postcombustion, and oxy-combustion) is 

technologically feasible. However, each 

results in increased capital and 

operating costs and decreased electricity 

output (that is, an energy penalty), with 

a resulting increase in the cost of 

electricity. The energy penalty occurs 

because the CO2 capture process uses 

some of the energy (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,193

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 the $1 to $4 dollar per 

ton of CO2 range.194 195 196 197 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 

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: Research, 

development, and demonstration of CCS 

technologies and the assessment of the 

country’s geologic capacity to store 

carbon dioxide, are particularly 

important.198 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 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).199 200

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 countries,201 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.202 For 

example, CO2 has been injected in the 

SACROC Unit in the Permian basin 

since 1972 for enhanced oil recovery 

purposes. A study evaluated this 

project, and estimated that about 93 

million metric tons of CO2 were injected 

and about 38 million metric tons were 

produced from 1972 to 2005, resulting 

in a geologic CO2 accumulation of 55 

million metric tons of CO2.203 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 Collie-South West CO2

Geosequestration Hub project in 

Australia have both demonstrated 

geologic CO2 trapping mechanisms.204

Numerous other field studies, for 

example those conducted by the DOE/ 

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205 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. 

206The United States 2012 Carbon Utilization and 

Storage Atlas, Fourth Edition, U.S. Department of 

Energy, Office of Fossil Energy, National Energy 

Technology Laboratory (NETL). 

207U.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/. 

208U.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/. 

209 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 sitespecific 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/code

xdownloadpdf.php?ID=190. 

210 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.). 

211Hovorka, 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 http:// 

www.sciencedirect.com/science/article/pii/ 

S1876610211004711. 

NETL Regional Carbon Sequestration 

Partnerships, have been completed that 

demonstrate CO2 trapping mechanisms 

working in geologic formations in 

smaller scale projects. Examples of these 

DOE/NETL studies include: 205

• 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 EORscale 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 billion metric tons of CO2

in deep saline formations, oil and gas 

reservoirs and un-mineable coal 

seams.206 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.207 The 

USGS assessment estimates a mean of 

3,000 billion metric tons of subsurface 

CO2 storage potential across the United 

States. For comparison, this amount is 

500 times the 2011 annual U.S. energyrelated CO2 emissions of 5.5 Gigatons 

(Gt).208

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 reinjected into the oil or 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 

detected.209

• 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.210

• 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.211 The Cranfield 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

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212 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/ 

BPM-MVA-2012.pdf. 

213U.S. Department of Energy National Energy 

Technology Laboratory (2012). United States 

Carbon Utilization and Storage Atlas, Fourth 

Edition. 

214See ‘‘Documentation for the Summary of 

Carbon Dioxide Industrial Capture to Enhanced Oil 

Recovery Projects’’ (Docket EPA–HQ–OAR–2013– 

0495). 

215 ‘‘Opportunities for Utilizing Anthropogenic 

CO2 for Enhanced Oil Recovery and CO2 Storage’’, 

Michael L. Godec, Advanced Resources 

International, June 11, 2013 presentation at the 

Introduction to CO2 EOR Workshop, http:// 

na2050.org/introduction-to-carbon-dioxideenhanced-oil-recovery-co2-eor. 

216 ‘‘Improving Domestic Energy Security and 

Lowering CO2 Emissions with ‘‘Next Generation’’ 

CO2-Enhanced Oil Recovery (CO2-EOR)’’, DOE/ 

NETL–2011/1504 (June 20, 2011). 

217 Ibid. 

218Tracking Clean Energy Progress 2013, 

International Energy Agency (IEA), Input to the 

Clean Energy Ministerial, OECD/IEA 2013. 

219 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. 

220 IEA (2009), World Energy Outlook 2009, 

OECD/IEA, Paris. 

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.212

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 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.213

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 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.214 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 2012.215 A recent study by 

DOE found that the 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.216

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.217 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. 

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 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.218

d. 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.219

At the Searles Valley Minerals soda 

ash plant in Trona, CA, approximately 

270,000 metric tons of CO2 per year are 

captured 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.220

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 pilotscale 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 chilledmstockstill on DSK4VPTVN1PROD with PROPOSALS2

Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1475 

221 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 

approximately more than 90 percent of the plant’s 

carbon emissions. http:// 

www.futuregenalliance.org/. 

222Available 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. 

223 In addition, the EPA may consider costs 

through a national lens, as discussed below. 

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 

steady-state operation during all modes 

of power plant operation including load 

changes, and saw an availability of the 

CCS system of greater than 90 percent. 

AEP, with assistance from the DOE, 

had planned to expand the slip stream 

demonstration to a commercial scale, 

fully integrated demonstration at the 

Mountaineer facility. The commercialscale 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.221

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 

pre-combustion 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, 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 percent of its CO2 emissions. 

The facility 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.222 The 

database includes active, proposed, 

canceled, and terminated CCUS projects 

worldwide. 

F. Costs 

As noted, according to the D.C. 

Circuit case law, control costs are 

considered acceptable as long as they 

are reasonable, meaning that they can be 

accommodated by the industry.223 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 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 

fossil fueled power generation options. 

These options are shown in Table 6 

below. The costs in Table 6 are 

projected for new fossil generation with 

and without various carbon capture 

options. The costs for new NGCC 

technology are provided at two different 

natural gas prices: at $6.11/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 projected 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). 

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224These costs are derived from the following 

DOE/NETL studies: (1) Cost and Performance 

Baseline for Fossil Energy Plants Volume 1: 

Bituminous Coal and Natural Gas to Electricity, Rev 

2, DOE/NETL–2010/1397 (Nov 2010); (2) Updated 

Costs (June 2011 Basis) for Selected Bituminous 

Baseline Cases’’ DOE/NETL–341/082312 (Aug 

2012); (3) Cost and Performance of PC and IGCC 

Plants for a Range of Carbon Dioxide Capture, DOE/ 

NETL–2011/1498 (May 2011). Capacity factor are 

assumed at 85 percent. 

225These costs do not include the impact of 

subsidies that may potentially be available to 

developers of new projects that include CCS. 

226SCPC LCOE includes a 3 percent increase to 

the weighted average cost of capital to reflect EIA’s 

climate uncertainty adder (CUA). 

227Engineering, Procurement, and Construction 

Management. 

228Elsewhere 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’’). 

229http://ghgnews.com/index.cfm/summit-evenwithout-uk-demo-funding-project-will-moveforward/?mobileFormat=true. 

TABLE 6—LEVELIZED COST OF ELECTRICITY FOR FOSSIL FUEL ELECTRIC

GENERATING TECHNOLOGIES, EXCLUDING TRANSMISSION

COSTS 224 225

Technology 

Levelized cost 

of electricity 

($2011/MWh) 

NGCC @ $6.11/MMBtu 59 

NGCC @ $10.0/MMBtu 86 

SCPC w/o CCS226 ....... 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 

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 

The DOE/NETL reports cite an 

accuracy range of ¥15% to +30% for 

the central point estimates shown in 

Table 6, which are based on a number 

of assumptions, including: an EPCM 227

contracting methodology, ISO ambient 

conditions, Midwest merit-shop labor 

costs, and a level greenfield site in the 

United States Midwest with no unusual 

characteristics (e.g., flood plain, seismic 

zones, environmental remediation). For 

specific sites that differ from this 

generic description, plant costs could 

differ from the quoted range. We have 

presented that central estimate above. 

Also note that the 2010 DOE/NETL 

capital and operating costs and coal 

price were updated to 2011 dollars 

using the values from the 2012 DOE/ 

NETL report. The value of the DOE/

NETL 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-akind’’ (FOAK) plant or an ‘‘nth-of-akind’’ (NOAK) plant, the latter of which 

has lower costs due to the ‘‘learning by 

doing’’ and risk reduction benefits that 

result from serial deployments as well 

as from continuing research, 

development and demonstration 

projects.228 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 and/or which have not yet been 

serially deployed in a commercial 

context, such as IGCC or any plant that 

includes CO2 capture, the cost estimates 

in Table 6 represent a plant that is 

somewhere between FOAK and NOAK, 

sometimes referred to as ‘‘next-of-akind’’, or ‘‘next commercial offering’’. 

These cost estimates for next 

commercial offerings do not include the 

unique cost premiums associated with 

FOAK plants that must demonstrate 

emerging technologies and iteratively 

improve upon initial plant designs. 

However, these costs do utilize 

currently available cost bases for 

emerging technologies with associated 

process contingencies applied at the 

appropriate subsystem levels. It should 

also be noted that successful RD&D can 

lead to improved performance and 

lower costs. 

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 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 poly-generation 

project in Texas.229 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-akind project—or perhaps even a next-ofa-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, but 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. 

The EPA has also examined costs of 

new non-fossil fueled power generation 

options. These options are shown in 

Table 7 below. 

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230 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 in Table 6, the EIA estimates 

provided in this table do not include transmission 

investment. 

231The LCOE estimates in Table 7 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 nondispatchable technologies are as follows: Wind—30 

to 39 percent, Wind Offshore—33 to 42 percent, 

Solar PV—22 to 32 percent, and Solar Thermal— 

11 to 26 percent. Capacity factors for dispatchable 

non-fossil fueled technologies are as follows: 

Nuclear—90 percent, Biomass—83 percent, and 

Geothermal—92 percent. There is no capacity credit 

provided to dispatchable resources. 

232Costs are expressed in terms of net AC power 

available to the grid for the installed capacity. 

233See Technical Support Document: ‘‘Review of 

Electric Utility Integrated Resource Plans’’ (Docket 

EPA–HQ–OAR–2013–0495). 

234Although geothermal energy is also generally 

considered for base load power, it is limited in 

availability. The other low-GHG emitting generation 

listed in Table 4—solar and wind—are not used for 

base load. 

235Regulatory 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). 

TABLE 7—RANGE OF LEVELIZED COST

OF ELECTRICITY FOR NON-FOSSIL

FUEL ELECTRIC GENERATING TECHNOLOGIES, EXCLUDING TRANSMISSION COSTS 230 231

Technology 

Levelized cost of 

electricity 

($2011/MWh) 

Nuclear ..................... 103–114 

Biomass .................... 97–130 

Geothermal ............... 80–99 

Combustion Turbine 87–116 

Onshore Wind ........... 70–97 

Offshore Wind ........... 177–289 

Solar PV232 .............. 109–220 

Solar Thermal ........... 184–412 

Nuclear ..................... 103–114 

Biomass .................... 97–130 

Geothermal ............... 80–99 

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 GHGintensive 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 IRPs,233 they must fall 

into one of two classes. The first, which 

is the 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 Tables 6 and 7 above show, while 

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 the 

principal other option often considered 

for providing new base load power. It is 

also competitive with biomass-fired 

generation, which is another generation 

technology often considered for base 

load power.234 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 

As noted in Table 6, above, and 

discussed in the RIA 235 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 coalfired 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 

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 

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236Portland Cement Ass’n v. EPA, 513 F.2d 506, 

508 (D.C. Cir. 1975). 

237 77 FR 22418/3. 

238See Duke Power Co. v. Carolina 

Environmental Study Group, 438 U.S. 59 (1978). 

239See Internal Revenue Code section 263. 

240See ‘‘General Explanations of the 

Administration’s Fiscal Year 2013 Revenue 

Proposals,’’ pp. 120–24. http://www.treasury.gov/

resource-center/tax-policy/Documents/GeneralExplanations-FY2013.pdf. 

241See Internal Revenue Code section 45. 

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 6, 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 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 needed 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. 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.236

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,237

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 liability claims 

arising from nuclear incidents,238 and 

domestic oil and gas production,239 coal 

exploration and development,240 and 

renewable energy generation 241 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 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 coal-fired 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 large. The costs 

provided in Table 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 CCS should 

be BSER. When considered in 

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242Task Force Report on CCS, p. 76 

243Task Force Report on CCS, p. 76 

244See Center for Climate and Energy Solutions, 

‘‘Financial Incentives for CCS’’—available at http:// 

www.c2es.org/. 

245 77 FR 22418/3. 

246Portland 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). 

247 Lignite Energy Council v. EPA, 198 F.3d 930, 

934 (D.C. 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. 

248 DOE/NETL Carbon Dioxide Capture and 

Storage RD&D Roadmap, U.S. Department of Energy 

National Energy Technology Laboratory, December 

2010. 

conjunction with other factors, such as 

the cost of full CCS where EOR is not 

available and the fact that more projects 

using partial CCS than full CCS are 

underway, the EPA believes that partial 

CCS should be considered 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 

partial-capture 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.242

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 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.’’ 243

In addition, regulatory programs may 

serve to defray the costs of CCS, 

including, for example, Clean Energy 

Standards or guaranteed electricity 

purchase price agreements.244

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 fuelfired; as well as nuclear-, geothermal-, 

wind-, and solar-generated 

electricity.245

c. Expected Reductions in the Costs of 

CCS 

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. . . .’’ 246 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.247

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 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 

significantly to the cost of electricity for 

a new pulverized coal plant, and 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 

less for the partial capture standard 

being proposed in today’s document.) 

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.248 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 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 

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249These studies include: John M. Dutton and 

Annie Thomas, ‘‘Treating Progress Functions as a 

Managerial Opportunity,’’ Academy of Management 

review, 1984, vol. 9, No. 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 Coal-Burning Generating Units,’’ RAND Journal 

of Economics, Vol. 16, Issue 1, 1–27 (1985). See 

discussion in ‘‘The Benefits and Costs of the Clean 

Air Act from 1990 to 2020,’’ U.S. EPA, Office of Air 

and Radiation (April 2011). 250Sierra Club v. Costle, 657 F.2d at 330. 

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 declines as 

experience with that technology 

increases over time,249 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-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 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.250

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 fuel-fired 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 fuel-fired 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 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 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 coalfired EGUs through 2020. Based on 

these IPM analyses, the RIA for this 

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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 fuel-fired 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 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 coalfired capacity. Currently, any new coalfired 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 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 coalfired plant 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 section 111 that may have 

the effect of precluding construction of 

sources in certain geographic 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 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 coalfired 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 section 

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 standard would remain valid 

under CAA section 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 than 90 

percent. In this situation, the 

performance of the specific pollution 

control device impacts the emissions 

rate much more than the EGU 

efficiency. 

EGU efficiency can vary 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-operatingmonth rolling average explicitly 

accounts for variable operating 

conditions, 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 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 

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251http://water.epa.gov/type/groundwater/uic/

wells_sequestration.cfm. 

252http://www.epa.gov/ghgreporting/reporters/

subpart/d.html. 

253http://www.epa.gov/ghgreporting/reporters/

subpart/pp.html. 

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. 84-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 84-operatingmonth rolling basis. 

The EPA has previously offered 

sources optional, longer-term emission 

standards that are stricter than the 

primary emissions standard in 

combination with a longer averaging 

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 84- 

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 84-operating-month 

standard would have to comply with. 

This standard would be numerically 

between the alternate 12-operatingmonth 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 84-operating-month period offers 

increased operational flexibility and 

will tend to compensate for short-term 

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 long-term geologic sequestration at 

sites where enhanced oil recovery 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 III, 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 another 

type of CO2 storage technology 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 

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.251 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 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 

facilities that contain electricitygenerating units must report emissions 

from electricity-generating units and all 

other source categories located at the 

facility for which methods are defined 

in part 98.252 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.253 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 facilities with 

production process unit(s) that capture 

a CO2 stream for purposes of supplying 

CO2 for commercial applications or that 

capture and maintain custody of a CO2

stream in order to sequester or 

otherwise inject it underground and 

which meet certain applicability 

requirements to report the mass of CO2

captured. CO2 suppliers are required to 

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254 76 FR 48073 (Aug. 8, 2011). 

report the annual quantity of CO2

transferred offsite and for what end use, 

including geologic sequestration. 

Subpart RR requires 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 EPAapproved 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. 

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 framework to 

verify geologic sequestration when 

determining eligibility of taxpayers 

claiming 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.254

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 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 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 its 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 its 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, and (2) the eGGRT 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. 

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. 

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255We note that the PSD program regulates CO2

as part of the ‘‘Greenhouse Gas’’ pollutant, which 

includes the aggregate group of the following gases: 

CO2, CH4, N20, SF6, HFCs, and PFCs. 

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 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 part 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 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 

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. 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.255

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 EPAapproved 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 renewable 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 case-specific PSD evaluation of the 

source under review. However, the 

permits for similar sources should 

generally contain the same basic 

information. 

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 

stationary source (‘‘EGU facility’’) that 

does not exceed the NSPS emission 

limit standard using the 12-operatingmonth rolling average or the NSPS 

alternative compliance method. 

• 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. 

• 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 

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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 two types of 

efficient generation without any CCS, 

including (ii) 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 

technical feasibility and because of 

adverse impact on electricity prices 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 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 affected sources as 

natural gas-fired combustion turbines, 

and not as NGCC sources. 

1. Full and Partial CCS 

To determine the BSER for naturalgas-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. There are 

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 CCS projects have operated 

in a cycling mode. Similarly, none of 

the larger CCS 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). 

Therefore, the overall amount of CO2

that can be captured in a CCS project is 

likely lower. Finally, unlike subpart Da 

affected facilities, where there are fullscale 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. 

Additional factors that make CCS 

more challenging for a natural gas 

combustion turbine compared to coalfired EGUs include the time it would 

take to complete the CCS project and the 

water use requirements. Requiring CCS 

at a natural gas combustion turbine 

facility would potentially delay the 

project more than at a coal-fired EGU. 

Natural gas combustion turbine facilities 

can be constructed in about half the 

time required to construct a coal-fired 

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 a natural gas 

combustion turbine than a coal-fired 

EGU. Natural gas combustion turbines 

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 a natural gas 

combustion turbine 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 fuelfired power is projected to use NGCC 

technology, requiring CCS would 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 

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 lowGHG-emitting fuel and NGCC to be a 

low-emitting 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. 

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 stateof-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, advanced 

simple cycle combustion turbines have 

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 gasfired (non-CHP) combined cycle facilities 

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256 77 FR 22414/1. 257 Gas Turbine World—2012 GTW Handbook. 

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.256

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 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 (nonCHP) 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, 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 on 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 

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 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 

comparing the efficiency values 

reported in Gas Turbine World of small 

and large combined cycle designs.257

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 

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258 ‘‘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. 

remaining 293 are above 850 MMBtu/

MWh. Two of the small combined cycle 

facilities had a maximum 12-operatingmonth rolling average emissions rate 

equal to or greater than 1,000 lb CO2/

MWh and one had a 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 eight recently 

permitted NGCC facilities. Of these 

facilities, seven are larger than 850 

MMBtu/h, and one is smaller. The seven 

larger facilities all have emission rates 

below 1,000 lb/MWh, and as low as 880 

lb/MWh. The single smaller facility, 

which is 400 MMBtu/h, has a permitted 

emissions rate of 1,100 lb CO2/MWh. 

The GHG BACT permit limits are higher 

than the base load rating emissions rates 

because they take into account actual 

operating conditions. 

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 1,200 

lb CO2/MWh (450 to 540 kg CO2/MWh) 

for the small turbine subcategory. 

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 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.258

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 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 of 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 

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 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 

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259This position reads the regulations to be 

consistent with the CAA PSD provisions 

themselves. Under those provisions, PSD applies to 

any ‘‘major emitting facility,’’ which is defined to 

mean stationary sources that emit or have the 

potential to emit ‘‘any air pollutant’’ at either 100 

or 250 tons per year, depending on the source 

category. CAA section 165(a), 169(1). EPA has long 

interpreted these provisions to apply PSD to a 

stationary source that emits the threshold amounts 

of any air pollutant subject to regulation. See 

Tailoring Rule, 75 FR 31579. Under these 

provisions, at present, PSD is already applicable to 

GHGs because GHGs are already subject to 

regulation, and regulating GHGs under CAA section 

111 does not create any additional type of PSD 

trigger. 

260The Tailoring Rule thresholds themselves are 

not at issue in this rulemaking. 

261 ‘‘Limitation of Approval of Prevention of 

Significant Deterioration Provisions Concerning 

Greenhouse Gas Emitting-Sources in State 

Implementation Plans; Final Rule,’’ 75 FR 82536 

(December 30, 2010). 

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’’ 40 CFR 51.166(b)(49) to 

include any pollutant that is subject to 

any standard promulgated under section 

111 of the Act. 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. 

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 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’’).259

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.260 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 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, 2010.261 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 operation of the new 

equipment on emissions. The emission 

thresholds that define PSD applicability 

can be found in 40 CFR parts 51 and 52 

and are discussed briefly in the above 

section. 

As mentioned above, sources that are 

subject to PSD must obtain a 

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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 section 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 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, once an NSPS is finalized, 

then the standard applies to any new 

source or 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 case-by-case 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 sources 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 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 the 

extent to 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), 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. The 

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 FR 31583. 

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 

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262Also, 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. 

263 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. 

264The current corresponding part 70 fee rate, 

adjusted for inflation, is approximately $47 per ton. 

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 GHG-related 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 CFR parts 70 and 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.262

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. 

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 

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 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 

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 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 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 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).263 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 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 inflation.264 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 

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265The definition includes any pollutant that is 

subject to any standard promulgated under section 

111 of the Act. 266 40 CFR 70.2 defines regulated pollutant (for 

presumptive fee calculation) to include any 

regulated air pollutant except carbon monoxide, 

any pollutant that is a regulated air pollutant solely 

because it is a Class I or II substance subject to a 

standard promulgated under or established by title 

VI of the Act and 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. 

267 40 CFR 71.2 defines regulated pollutant (for 

fee calculation) the same as reegulated pollutant 

(for presumptive fee calculation) in 40 CFR 70.2. 

268Note 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. 

269For 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. 

pollutant’’265 (at 40 CFR 70.2 and 71.2) 

that tracks the Act 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) 266’’ in 40 

CFR 70.2 and ‘‘regulated pollutant (for 

fee calculation) 267’’ 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 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 emissions-based fee 

schedule that uses the definition of 

‘‘regulated 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 emissionsbased 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 

ton,268 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 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,269 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 25234, May 7, 

2010), and the Tailoring Rule 

established emissions thresholds for 

purposes of PSD and title 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. The 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 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 

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270See 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. 

271Consistent 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). 

272Note 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. 

273The 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. 

274We 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. 

275The fee provisions are set forth in CAA section 

502(b)(3) and in our regulations at 40 CFR 70.9 and 

71.9. 

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 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 fuel.270 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 year 271 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).’’ 272

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,273 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 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.274 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 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 than 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 

administer [title V] programs.’’ 275 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 

FR 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 

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276Conversely, 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). 

277The 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. 278Regulatory Impact Analysis for the Final 

Prevention of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule, Final Report, May 

2010. 279The ICR change request form for the Tailoring 

Rule was based on the assumptions made in the 

RIA for the Tailoring Rule. 

the same policies for the purposes of the 

recent Step 3 rule (77 FR 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 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.276 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 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. 

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 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 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 70 277 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 Rule 278 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 Rule279. 

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 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 

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280A 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 

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. 

281The 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. 

282At 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). 

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 

GHG-related 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 GHGrelated 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 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.280 The GHG 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. 

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,281 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).282 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 

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 

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 

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283See 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. 

284At 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). 

285Note that EPA does not project any difference 

in the impacts between the alternative to regulate 

sources under subparts Da and KKKK versus 

regulating them under new subpart TTTT. 

286Conditions in the analysis year of 2022 are 

represented by a model year of 2020. 

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 adequacy; however, nonpresumptive 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 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.) 

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 70.283 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 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 pollutant 

(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 71 fee in effect to calculate 

the revise fee rate.284 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). 

X. Impacts of the Proposed Action 285

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 that this proposed rule 

will result in negligible CO2 emission 

changes, quantified benefits, and costs 

by 2022.286

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287http://www.physicalgeography.net/

fundamentals/7a.html. 

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 

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. 

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 fuelfired generating units. The proposed 

rule will also serve as a necessary 

predicate for the regulation of existing 

sources within this source category 

under CAA section 111(d). In these 

ways, the proposed rule will contribute 

to the actions required to slow or 

reverse the accumulation of GHG 

concentrations in the atmosphere, 

which is necessary to protect against 

projected climate change impacts and 

risks. 

E. What are the economic and 

employment impacts? 

The EPA does not anticipate that this 

proposed rule will result in notable CO2

emission changes, energy impacts, 

monetized benefits, costs, or economic 

impacts by 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. 

XI. Request for Comments 

We request comments on all aspects 

of the proposed rulemaking including 

the RIA. All significant comments 

received will be considered in the 

development and selection of the final 

rule. We specifically solicit comments 

on additional issues under 

consideration as described below. 

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. 

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 287 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. In the original proposal, 

we requested comment on 

subcategorizing EGUs that burn over 75 

percent coal refuse on an annual basis. 

Multiple commenters supported the 

exemption, citing numerous 

environmental benefits of remediating 

coal refuse piles. Other commenters 

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 that a new 

coal refuse-fired EGU would 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). One commenter on the 

original proposal stated that existing 

coal refuse piles are naturally 

combusting at a rate of 0.3 percent 

annually. We are requesting comment 

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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. 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 would potentially have to comply 

with one of the proposed emissions 

standards. However, based on 

anticipated capacity factors for new 

CAES facilities, it is our understanding 

that the proposed one-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, if so, whether the EPA should 

exempt stationary combustion turbines 

at CAES facilities from the proposed 

CO2 emission standards. We have 

concluded this could be appropriate 

since we expect only a limited number 

of new CAES facilities, and the use of 

stored energy complicates the 

determination of compliance with the 

proposed emission standards. 

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 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, we are requesting 

comment on whether it is appropriate to 

adjust the measured 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). 

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 

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 one-third of their 

potential electric output to continue to 

generate electricity during a grid 

emergency without such generation 

counting towards the one-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 grid 

supply power to the grid. Provisions 

were added to 40 CFR part 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.’’ 

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-operating-month 

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 include the 

traditional generating unit ‘‘plus any 

integrated equipment that provides 

electricity or useful thermal output.’’ 

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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-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 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. The 

definition would include the additional 

language ‘‘or co-located 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 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 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 generated from 

the combustion of fossil fuels), this 

approach would expand options for 

more intermittent intermediate load 

generators to efficiently integrate nonemitting energy generation into their 

design. 

Other GHGs. Today’s proposed rule 

would require continuous measurement 

of CO2 from fossil fuel-fired EGUs. 

Other GHGs, such as CH4 and 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 84- 

operating month period, the source’s 

emission rate exceeds the standard, the 

number of daily violations in the 12- or 

84-operating-month averaging period 

would be the number of operating days 

in that period. However, if a violation 

occurs directly following the previous 

12-operating-month or 84-operatingmonth 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 84-operatingmonth standard. 

XII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

Under Executive Order (EO) 12866 

(58 FR 51735, 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 of this proposal. However, 

because some companies may choose to 

construct coal or other fossil fuel-fired 

units, the RIA also analyzes projectlevel 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 2465.02. 

This proposed action would impose 

minimal new information collection 

burden on affected sources beyond what 

those sources would already be subject 

to under the authorities of CAA parts 75 

and 98. OMB has previously approved 

the information collection requirements 

contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR 

part 98) under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control numbers 2060–0626 and 2060– 

0629, respectively. Apart from certain 

reporting costs based on requirements in 

the NSPS General Provisions (40 CFR 

part 60, subpart A), which are 

mandatory for all owners/operators 

subject to CAA section 111 national 

emission standards, there are no new 

information collection costs, as the 

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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 3-year 

period covered by this ICR. We estimate 

that 17 new affected NGCC units would 

commence operation during that time 

period. As a result of this proposal, 

those units would be required to 

prepare a summary report, which 

includes reporting of emissions and 

downtime, every 3 months. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 40 

CFR part 60, subparts Da and KKKK or 

subpart TTTT 60.5530. An affirmative 

defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

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 

$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 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 and subpart KKKK 

or subpart TTTT over the 3-year period 

covered by this ICR. We expect to gather 

information on such events in the 

future, and will revise this estimate as 

better information becomes available. 

The annual information collection 

burden for this collection consists only 

of reporting burden as explained above. 

The reporting burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $15,570 and 396 labor 

hours. This estimate includes quarterly 

summary reports which include 

reporting of emissions and downtime. 

All burden estimates are in 2010 dollars. 

Average burden hours per response are 

estimated to be 8 hours. The total 

number of respondents over the 3-year 

ICR period is estimated to be 36. Burden 

is defined at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public 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 

January 8, 2014, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by February 7, 2014. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, small 

entity is defined as: 

(1) A small business that is defined by 

the SBA’s regulations at 13 CFR 121.201 

(for the electric power generation 

industry, the small business size 

standard is an ultimate parent 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 8 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. 

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TABLE 8—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Category NAICS Code Examples of potentially regulated entities 

Industry ................................................................... 221112 Fossil fuel electric power generating units. 

State/Local Government ......................................... b 221112 Fossil fuel electric power generating units owned by municipalities. 

a Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines). bState 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 costto-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 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 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 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 

This proposed rule does not contain 

a federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or the private sector in 

any one year. The EPA believes this 

proposed rule will have no compliance 

costs associated with it over a range of 

likely sensitivity conditions because 

electric power companies will choose to 

build new EGUs that comply with the 

regulatory requirements of this proposal 

because of existing and expected market 

conditions. (See the RIA for further 

discussion of sensitivities). 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 

identified by the EPA as the ‘‘Big 10’’ 

organizations appropriate to contact for 

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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 

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 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 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It would neither impose 

substantial direct compliance costs on 

tribal governments, nor preempt Tribal 

law. This proposed rule would impose 

requirements on owners and operators 

of new EGUs. The EPA is aware of three 

coal-fired EGUs located in Indian 

Country but is not aware of any EGUs 

owned or operated by tribal entities. 

The EPA notes that this proposal does 

not affect existing sources such as the 

three coal-fired EGUs located in Indian 

Country, but addresses CO2 emissions 

for new EGU sources only. Thus, 

Executive Order 13175 does not apply 

to this action. 

Although Executive Order 13175 does 

not apply to this action, EPA consulted 

with tribal officials in developing this 

action. Because the EPA is aware of 

Tribal interest in this proposed rule, 

prior to the April 13, 2012 proposal (77 

FR 22392), 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 

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 

The EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the Order has the potential to influence 

the regulation. This action is not subject 

to EO 13045 because it is based solely 

on technology performance. 

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. 

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I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the NTTAA of 1995 

(Pub. L. 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 proposes 

to use the following standards in this 

proposed rule: D5287–08 (Standard 

Practice for Automatic Sampling of 

Gaseous Fuels), D4057–06 (Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products), and 

D4177–95(2010) (Standard Practice for 

Automatic Sampling of Petroleum and 

Petroleum Products). The EPA is 

proposing use of Appendices B, D, F, 

and G to 40 CFR part 75; these 

Appendices contain standards that have 

already been reviewed under the 

NTTAA. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this action. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

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, lowincome, 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 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)). 

List of Subjects 

40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

40 CFR Part 70 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

40 CFR Part 71 

Environmental Protection, 

Administrative practice and procedure, 

Air pollution control, Reporting and 

recordkeeping requirements. 

40 CFR Part 98 

Environmental protection, 

Greenhouse gases and monitoring, 

Reporting and recordkeeping 

requirements. 

Dated: September 20, 2013. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60, 70, 

71, and 98 of the Code of the Federal 

Regulations is proposed to be amended 

as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart Da—Standards of 

Performance for Electric Utility Steam 

Generating Units 

■ 2. Section 60.46Da is added to read as 

follows: 

§ 60.46Da Standards for carbon dioxide 

(CO2). 

(a) Your affected facility is subject to 

this section if construction commenced 

after [DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], and the affected 

facility meets the conditions specified 

in paragraphs (a)(1) and (a)(2) of this 

section, except as specified in paragraph 

(b) of this section. 

(1) The affected facility combusts 

fossil fuel for more than 10.0 percent of 

the heat input during any 3 consecutive 

calendar years. 

(2) The affected facility supplies more 

than one-third of its potential electric 

output and more than 219,000 MWh 

net-electric output to a utility power 

distribution system for sale on an 

annual basis. 

(b) The following EGUs are not 

subject to this section: 

(1) The proposed Wolverine EGU 

project described in Permit to Install No. 

317–07 issued by the Michigan 

Department of Environmental Quality, 

Air Quality Division, effective June 29, 

2011 (as revised July 12, 2011). 

(2) The proposed Washington County 

EGU project described in Air Quality 

Permit No. 4911–303–0051–P–01–0 

issued by the Georgia Department of 

Natural Resources, Environmental 

Protection Division, Air Protection 

Branch, effective April 8, 2010, 

provided that construction had not 

commenced for NSPS purposes as of 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

(3) The proposed Holcomb EGU 

project described in Air Emission 

Source Construction Permit 0550023 

issued by the Kansas Department of 

Health and Environment, Division of 

Environment, effective December 16, 

2010, provided that construction had 

not commenced for NSPS purposes as of 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

(c) As owner or operator of an affected 

facility subject to this section, you shall 

not cause to be discharged into the 

atmosphere from the affected facility 

any gases that contain CO2 in excess of 

the emissions limitation specified in 

either paragraphs (c)(1) or (c)(2) of this 

section. 

(1) 500 kilograms (kg) of CO2 per 

megawatt-hour (MWh) of gross energy 

output (1,100 lb CO2/MWh) on a 12- 

operating month rolling average basis; 

or 

(2) 480 kg of CO2 per MWh of gross 

energy output (1,050 lb CO2/MWh) on 

an 84-operating month rolling average 

basis. 

(d) You must make compliance 

determinations at the end of each 

operating month, as provided in 

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paragraphs (d)(1) and (d)(2) of this 

section. For the purpose of this section, 

operating month means a calendar 

month during which any fossil fuel is 

combusted in the affected facility. 

(1) If you elect to comply with the 

CO2 emissions limitation in paragraph 

(c)(1) of this section, you must 

determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected facility at the end 

of each 12-operating month period that 

includes, as the last month, the month 

for which you are determining 

compliance. 

(2) If you elect to comply with the 

CO2 emissions limitation in paragraph 

(c)(2) of this section, you must 

determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected facility at the end 

of each 84-operating month period that 

includes, as the last month, the month 

for which you are determining 

compliance. 

(e) You must conduct an initial 

compliance determination with the CO2

emissions limitation for your affected 

facility within 30 days after 

accumulating the required number of 

operating months for the compliance 

period with which you have elected to 

comply (i.e., 12-operating months or 84- 

operating months). The first operating 

month included in this compliance 

period is the month in which emissions 

reporting is required to begin under 

§ 75.64(a) of this chapter. 

(f) You must monitor and collect data 

to demonstrate compliance with the CO2

emissions limitation according to the 

requirements in paragraphs (f)(1) 

through (4) of this section. 

(1) You must prepare a monitoring 

plan in accordance with the applicable 

provisions in § 75.53(g) and (h) of this 

chapter. 

(2) You must measure the hourly CO2

mass emissions from each affected 

facility using the procedures in 

paragraphs (f)(2)(i) through (vii) of this 

section, except as provided in paragraph 

(f)(3) of this section. 

(i) You must install, certify, operate, 

maintain, and calibrate a CO2

continuous emission monitoring system 

(CEMS) to directly measure and record 

CO2 concentrations in your affected 

facility’s exhaust gases that are emitted 

to the atmosphere and an exhaust gas 

flow rate monitoring system according 

to § 75.10(a)(3)(i) of this chapter. If you 

measure CO2 concentration on a dry 

basis, you must also install, certify, 

operate, maintain, and calibrate a 

continuous moisture monitoring system, 

according to § 75.11(b) of this chapter. 

(ii) For each monitoring system used 

to determine the CO2 mass emissions, 

you must meet the applicable 

certification and quality assurance 

procedures in § 75.20 of this chapter 

and Appendices B and D to part 75 of 

this chapter. 

(iii) You must use a laser device to 

measure the dimensions of each exhaust 

gas stack or duct at the flow monitor 

and the reference method sampling 

locations prior to the initial setup 

(characterization) of the flow monitor. 

For circular stacks, you must make 

measurements of the diameter at three 

or more distinct locations and average 

the results. For rectangular stacks or 

ducts, you must make measurements of 

each dimension (i.e., depth and width) 

at three or more distinct locations and 

average the results. If the flow rate 

monitor or reference method sampling 

site is relocated, you must repeat these 

measurements at the new location. 

(iv) You can only use unadjusted 

exhaust gas volumetric flow rates to 

determine the hourly CO2 mass 

emissions from the affected facility; you 

must not apply the bias adjustment 

factors described in section 7.6.5 of 

Appendix A to part 75 of this chapter 

to the exhaust gas flow rate data. 

(v) If you choose to use Method 2 in 

Appendix A–1 to this part to perform 

the required relative accuracy test audits 

(RATAs) of the part 75 flow rate 

monitoring system, you must use a 

calibrated Type-S pitot tube or pitot 

tube assembly. You must not use the 

default Type-S pitot tube coefficient. 

(vi) If two or more affected facilities 

share a common exhaust gas stack and 

are subject to the same CO2 emissions 

limitation in paragraph (c) of this 

section, you may monitor the hourly 

CO2 mass emissions at the common 

exhaust gas stack rather than monitoring 

each affected facility separately. 

(vii) If the exhaust gases from the 

affected facilities are emitted to the 

atmosphere through multiple stacks (or 

if the exhaust gases are routed to a 

common stack through multiple ducts 

and you choose to monitor in the ducts), 

you must monitor the hourly CO2 mass 

emissions and the ‘‘stack operating 

time’’ (as defined in § 72.2 of this 

chapter) at each stack or duct separately. 

(3) As an alternative to complying 

with paragraph (f)(2) of this section, for 

affected facilities that do not combust 

any solid fuel, you may determine the 

hourly CO2 mass emissions by using 

Equation G–4 in Appendix G to part 75 

of this chapter according to the 

requirements specified in paragraphs 

(f)(3)(i) and (f)(3)(ii) of this section. 

(i) You must implement the 

applicable procedures in Appendix D to 

part 75 of this chapter to determine 

hourly unit heat input rates (MMBtu/h), 

based on hourly measurements of fuel 

flow rate and periodic determinations of 

the gross calorific value (GCV) of each 

fuel combusted. 

(ii) You may determine site-specific 

carbon-based F-factors (Fc) using 

Equation F–7b in section 3.3.6 of 

Appendix F to part 75 of this chapter, 

and you may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(4) You must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record the gross electric 

output from the affected facility, and 

you must meet the requirements 

specified in paragraphs (f)(4)(i) and (ii) 

of this section, as applicable. 

(i) If your affected facility is a 

combined heat and power unit as 

defined in § 60.42Da, you must also 

install, calibrate, maintain, and operate 

meters to continuously determine and 

record the total useful recovered 

thermal energy. For process steam 

applications, you must install, calibrate, 

maintain, and operate meters to 

continuously determine and record 

steam flow rate, temperature, and 

pressure. If your affected facility has a 

direct mechanical drive application, you 

must submit a plan to the Administrator 

or delegated authority for approval of 

how gross energy output will be 

determined. Your plan shall ensure that 

you install, calibrate, maintain, and 

operate meters to continuously 

determine and record each component 

of the determination. 

(ii) If two or more affected facilities 

have steam generating units that serve a 

common electric generator, you must 

apportion the combined hourly gross 

electric output to each individual 

affected facility using a plan approved 

by the Administrator (e.g., using steam 

load or heat input to each affected 

facility). Your plan shall ensure that you 

install, calibrate, maintain, and operate 

meters to continuously determine and 

record each component of the 

determination. 

(g) You must demonstrate compliance 

with the CO2 emissions limitation using 

the procedures specified in paragraphs 

(g)(1) and (2) of this section. 

(1) You must calculate the CO2 mass 

emissions rate for your affected facility 

using the calculation procedures in 

paragraphs (g)(1)(i) through (v) of this 

section with the hourly CO2 mass 

emissions and gross energy output data 

determined and recorded according to 

the procedures in paragraph (f) of this 

section for each operating hour in the 

applicable compliance period (i.e., 12- 

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operating months or 84-operating 

months). 

(i) You must only use operating hours 

in the compliance period for which you 

have valid data for all the parameters 

you use to determine the hourly CO2

mass emissions and gross output data. 

You must not use operating hours 

which use the substitute data provisions 

of part 75 of this chapter for any of the 

parameters in the calculation. For the 

compliance determination calculation, 

you must obtain valid hourly values for 

a minimum of 95 percent of the 

operating hours in the applicable 

compliance period. 

(ii) You must calculate the total CO2

mass emissions by summing all of the 

valid hourly CO2 mass emissions values 

for the applicable compliance period. If 

exhaust gases from the affected facility 

are emitted to the atmosphere through 

multiple stacks or ducts, you must 

calculate the total CO2 mass emissions 

for the affected facility by summing the 

total CO2 mass emissions from each of 

the individual stacks or ducts. 

(iii) For each operating hour of the 

compliance period used in paragraph 

(g)(1)(ii) of this section to calculate the 

total CO2 mass emissions, you must 

determine the affected facility’s 

corresponding hourly gross energy 

output using the appropriate definitions 

in § 60.42Da and paragraph (k) of this 

section and using the procedure 

specified in paragraphs (g)(3)(iii)(A) 

through (D) of this section. 

(A) Calculate Pgross for your affected 

facility using the following equation: 

Where: a 

Pgross = Gross energy output of your affected 

facility in megawatt-hours in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected facility’s integrated 

equipment that provides electricity or 

mechanical energy to the affected facility 

or auxiliary equipment in MWh. 

(Pe)FW = Electric energy used to power boiler 

feedwater pumps at steam generating 

units in MWh. This term is not 

applicable to IGCC facilities. 

(Pt)PS = Useful thermal energy output of 

steam measured relative to ISO 

conditions that is used for applications 

that do not generate additional 

electricity, produce mechanical energy 

output, or enhance the performance of 

the affected facility. This term is 

calculated using the equation specified 

in paragraph (g)(3)(iii)(B) of this section 

in MWh. 

(Pt)HR = Hourly useful thermal energy output 

measured relative to ISO conditions from 

heat recovery that is used for 

applications other than steam generation 

or performance enhancement of the 

affected facility in MWh. 

(Pt)IE = Useful thermal energy output relative 

to ISO conditions from any integrated 

equipment that provides thermal energy 

to the affected facility or auxiliary 

equipment in MWh. 

T = Electric Transmission and Distribution 

Factor. 

T = 0.95 for a combined heat and power 

affected facility where at least on an 

annual basis 20.0 percent of the total 

gross energy output consists of electric or 

direct mechanical output and 20.0 

percent of the total gross energy output 

consists of useful thermal energy output 

on a rolling 3 year basis. 

T = 1.0 for all other affected facilities. 

(B) If applicable to your affected 

facility, calculate (Pt)PS using the 

following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure relative to ISO 

conditions in Joules per kilogram (J/kg) 

(or Btu/lb). 

3.6 × 109 = Conversion factor (J/MWh) (or 

3.413 × 106 Btu/MWh). 

(C) For an operating hour in which 

there is no gross electric load, but there 

is mechanical or useful thermal output, 

you must still determine the gross 

energy output for that hour. In addition, 

for an operating hour in which there is 

no useful output, you must still 

determine the hourly gross CO2

emissions for that hour. 

(D) If hourly CO2 mass emissions are 

determined for a common stack, you 

must determine the hourly gross energy 

output (electric, thermal, and/or 

mechanical, as applicable) by summing 

the hourly loads for the individual 

affected facility and you must express 

the operating time as ‘‘stack operating 

hours’’ (as defined in § 72.2 of this 

chapter). 

(iv) You must calculate the total gross 

energy output by summing the hourly 

gross energy output values for the 

affected facility determined from 

paragraph (g)(1)(iii) of this section for all 

of the operating hours in the applicable 

compliance period. 

(v) You must calculate the CO2 mass 

emissions rate for the applicable 

compliance period interval by dividing 

the total CO2 mass emissions value from 

paragraph (g)(1)(ii) of this section by the 

total gross energy output value from 

paragraph (g)(1)(iv) of this section. 

(2) You must determine compliance 

with the CO2 emissions limitation in 

paragraph (c) of this section is 

determined as specified in paragraphs 

(g)(2)(i) and (ii) of this section using the 

CO2 mass emissions rate for your 

affected facility that you determined in 

paragraph (g)(1) of this section. 

(i) If the CO2 mass emissions rate for 

your affected facility is less than or 

equal to the CO2 emissions limitation 

applicable to your affected facility, then 

your affected facility is in compliance 

with the CO2 emissions limitation. If 

you attain compliance with the CO2

emissions limitation at a common stack 

for two or more affected facilities 

subject to the same CO2 emissions 

limitation, each affected facility sharing 

the stack is in compliance with the CO2

emissions limitation. 

(ii) If the CO2 mass emissions rate for 

the affected facility is greater than the 

CO2 emissions limitation in paragraph 

(c) of this section applicable to the 

affected facility, then the affected 

facility has excess CO2 emissions. 

(h) You must prepare and submit 

notifications and reports according to 

paragraphs (h)(1) through (4) of this 

section. 

(1) You must prepare and submit the 

notifications in §§ 60.7(a)(1) and (a)(3) 

and 60.19, as applicable to your affected 

facility. 

(2) You must prepare and submit 

notifications in § 75.61 of this chapter, 

as applicable to your affected facility. 

(3) You must submit electronic 

quarterly reports according to the 

requirements specified in paragraphs 

(h)(3)(i) through (iii) of this section. 

(i) Initially, after you have 

accumulated the required number of 

operating months for the CO2 emission 

limitation compliance period that you 

have chosen to comply with (i.e., 12- 

operating months or 84-operating 

months), you must submit a report for 


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the calendar quarter that includes the 

final (12th- or 84th) operating month no 

later than 30 days after the end of that 

quarter. Thereafter, you must submit a 

report for each subsequent calendar 

quarter no later than 30 days after the 

end of the quarter. 

(ii) In each quarterly report you must 

include the information in paragraphs 

(h)(3)(ii)(A) through (E) of this section. 

(A) The CO2 emission limitation 

compliance period with which you have 

chosen to comply. 

(B) Any months in the calendar 

quarter that you are not counting as 

operating months. 

(C) For each operating month in the 

calendar quarter, the corresponding 

average CO2 mass emissions rate for the 

applicable compliance period interval 

that you determined according to 

paragraph (g) of this section. 

(D) The percentage of valid CO2 mass 

emission rates in each compliance 

period (i.e., the total number of valid 

CO2 mass emission rates in that period 

divided by the total number of operating 

hours in that period, multiplied by 100 

percent). 

(E) Any operating months in the 

calendar quarter with excess CO2

emissions. 

(iii) In the final quarterly report of 

each calendar year you must include the 

following: 

(A) Net electric output sold to an 

electric grid over the calendar year; and 

(B) The potential electric output of the 

facility. 

(iv) You must submit each electronic 

report using the Emissions Collection 

and Monitoring Plan System (ECMPS) 

Client Tool provided by the Clean Air 

Markets Division in the EPA Office of 

Atmospheric Programs. 

(4) You must meet all applicable 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter. 

(5) If your affected unit uses geologic 

sequestration to meet the applicable 

emissions limit, you must report in 

accordance with the requirements of 40 

CFR Part 98, subpart PP and either: 

(i) if injection occurs onsite, report in 

accordance with the requirements of 40 

CFR Part 98, subpart RR, or 

(ii) if injection occurs offsite, transfer 

the captured CO2 to a facility or 

facilities that reports in accordance with 

the requirements of 40 CFR Part 98, 

subpart RR. 

(i) For each affected electric utility 

stream generating unit, you must 

maintain records according to 

paragraphs (i)(1) through (i)(8) of this 

section. 

(1) You must comply with the 

applicable recordkeeping requirements 

and maintain records as required under 

subpart F of part 75 of this chapter. 

(2) You must maintain records of the 

calculations you performed to 

determine the total CO2 mass emissions 

for each operating month, and the 

averages for each compliance period 

interval (i.e., 12-operating months or 84- 

operating months, as applicable to the 

CO2 emissions limitations). 

(3) You must maintain records of the 

applicable data recorded and 

calculations performed that you used to 

determine the gross energy output for 

each operating month. 

(4) You must maintain records of the 

calculations you performed to 

determine the percentage of valid CO2

mass emission rates in each compliance 

period. 

(5) You must maintain records of the 

calculations you performed to assess 

compliance with each applicable CO2

emissions limitation in paragraph (c) of 

this section. 

(6) Your records must be in a form 

suitable and readily available for 

expeditious review. 

(7) You must maintain each record for 

5 years after the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record except those 

records required to demonstrate 

compliance with an 84-operating month 

compliance period. You must maintain 

records required to demonstrate 

compliance with an 84-operating month 

compliance period for at least 10 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(8) You must maintain each record on 

site for at least 2 years after the date of 

each occurrence, measurement, 

maintenance, corrective action, report, 

or record, according to § 60.7. You may 

maintain the records off site and 

electronically for the remaining year(s) 

as required by this subpart. 

(j) PSD and Title V Thresholds for 

Greenhouse Gases. 

(1) For purposes of 40 CFR 

51.166(b)(49)(ii), with respect to GHG 

emissions from new affected facilities, 

the ‘‘pollutant that is subject to the 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

40 CFR 51.166(b)(48) and in any SIP 

approved by the EPA that is interpreted 

to incorporate, or specifically 

incorporates, 40 CFR 51.166(b)(48). 

(2) For purposes of 40 CFR 

52.21(b)(50)(ii), with respect to GHG 

emissions from new affected facilities, 

the ‘‘pollutant that is subject to the 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

40 CFR 52.21(b)(49). 

(3) For purposes of 40 CFR 70.2, with 

respect to greenhouse gas emissions 

from new affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 70.2. 

(4) For purposes of 40 CFR 71.2, with 

respect to greenhouse gas emissions 

from new affected facilities, the 

‘‘pollutant that is subject to any 

standard promulgated under section 111 

of the Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 71.2. 

(k) For purposes of this section, the 

following definitions apply: 

Gross energy output means: 

(i) Except as provided under 

paragraph (ii) of this definition, for 

electric utility steam generating units, 

the gross electric or mechanical output 

from the affected facility (including, but 

not limited to, output from steam 

turbine(s), combustion turbine(s), and 

gas expanders) minus any electricity 

used to power the feedwater pumps 

plus 75 percent of the useful thermal 

output measured relative to ISO 

conditions that is not used to generate 

additional electric or mechanical output 

or to enhance the performance of the 

unit (e.g., steam delivered to an 

industrial process for a heating 

application); 

(ii) For electric utility steam 

generating unit combined heat and 

power facilities where at least 20.0 

percent of the total gross energy output 

consists of electric or direct mechanical 

output and at least 20.0 percent of the 

total gross energy output consists of 

thermal output on a rolling 3 year basis, 

the gross electric or mechanical output 

from the affected facility (including, but 

not limited to, output from steam 

turbine(s), combustion turbine(s), and 

gas expanders) minus any electricity 

used to power the feedwater pumps, 

that difference divided by 0.95, plus 75 

percent of the useful thermal output 

measured relative to ISO conditions that 

is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the unit 

(e.g., steam delivered to an industrial 

process for a heating application); 

(iii) Except as provided under 

paragraph (ii) of this definition, for a 

IGCC electric utility generating unit, the 

gross electric or mechanical output from 

the affected facility (including, but not 

limited to, output from steam turbine(s), 

combustion turbine(s), and gas 

expanders) plus 75 percent of the useful 

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thermal output measured relative to ISO 

conditions that is not used to generate 

additional electric or mechanical output 

or to enhance the performance of the 

unit (e.g., steam delivered to an 

industrial process for a heating 

application); 

(iv) For IGCC electric utility 

generating unit combined heat and 

power facilities where at least 20.0 

percent of the total gross energy output 

consists of electric or direct mechanical 

output and at least 20.0 percent of the 

total gross energy output consists of 

thermal output on a rolling 3 year basis, 

the gross electric or mechanical output 

from the affected facility (including, but 

not limited to, output from steam 

turbine(s), combustion turbine(s), and 

gas expanders) divided by 0.95, plus 75 

percent of the useful thermal output 

measured relative to ISO conditions that 

is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the unit 

(e.g., steam delivered to an industrial 

process for a heating application); 

IGCC facility is an integrated 

gasification combined cycle electric 

utility steam generating unit, which 

means an electric utility combined cycle 

facility that is designed to burn fuels 

containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the 

definition of natural gas plus any 

integrated equipment that provides 

electricity or useful thermal output to 

either the affected facility or auxiliary 

equipment. The Administrator may 

waive the 50 percent solid-derived fuel 

requirement during periods of the 

gasification system construction, startup 

and commissioning, shutdown, or 

repair. No solid fuel is directly burned 

in the facility during operation. 

Net-electric output means: 

(i) Except as provided under 

paragraph (ii) of this definition, the 

gross electric sales to the utility power 

distribution system minus purchased 

power on a calendar year basis, or 

(ii) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total gross 

energy output consists of thermal 

output, 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. 

Potential electric output means: 

(i) Either 33 percent or the design net 

electric output efficiency, at the election 

of the owner/operator of the affected 

facility, 

(ii) Multiplied by the maximum 

design heat input capacity of the steam 

generating unit, 

(iii) Divided by 3,413 Btu/KWh, 

(iv) Divided by 1,000 kWh/MWh, and 

(v) Multiplied by 8,760 h/yr. 

(vi) For example, 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 electric output 

capacity. 

Steam generating unit means 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 boiler or auxiliary equipment. 

Subpart KKKK—Standards of 

Performance for Stationary 

Combustion Turbines 

■ 3. Section 60.4305 is amended by 

adding paragraph (c) to read as follows: 

§ 60.4305 Does this subpart apply to my 

stationary combustion turbine? 

* * * * * 

(c) For purposes of regulation of 

greenhouse gases, the applicable 

provisions of this subpart affect your 

stationary combustion turbine if it meets 

the applicability conditions in 

paragraphs (c)(1) through (c)(5) of this 

section. 

(1) Commenced construction after 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]; 

(2) Has a design heat input to the 

turbine engine greater than 73 MW (250 

MMBtu/h); 

(3) Combusts fossil fuel for more than 

10.0 percent of the heat input during 

any 3 consecutive calendar years. 

(4) Combusts over 90% natural gas on 

a heat input basis on a 3 year rolling 

average basis; and 

(5) Was constructed for the purpose of 

supplying, and supplies, one-third or 

more of its potential electric output and 

more than 219,000 MWh net-electrical 

output to a utility distribution system 

on a 3 year rolling average basis. 

■ 4. Section 60.4315 is revised to read 

as follows: 

§ 60.4315 What pollutants are regulated by 

this subpart? 

(a) The pollutants regulated by this 

subpart are nitrogen oxides (NOX), 

sulfur dioxide (SO2), and greenhouse 

gases. 

(b)(1) The greenhouse gases regulated 

by this subpart consist of carbon dioxide 

(CO2). 

(2) PSD and Title V Thresholds for 

Greenhouse Gases. 

(i) For purposes of 40 CFR 

51.166(b)(49)(ii), with respect to GHG 

emissions from affected stationary 

combustion turbine, the ‘‘pollutant that 

is subject to the standard promulgated 

under section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in 40 CFR 

51.166(b)(48) and in any SIP approved 

by the EPA that is interpreted to 

incorporate, or specifically incorporates, 

40 CFR 51.166(b)(48). 

(ii) For purposes of 40 CFR 

52.21(b)(50)(ii), with respect to GHG 

emissions from affected stationary 

combustion turbines, the ‘‘pollutant that 

is subject to the standard promulgated 

under section 111 of the Act’’ shall be 

considered to be the pollutant that 

otherwise is subject to regulation under 

the Act as defined in 40 CFR 

52.21(b)(49). 

(iii) For purposes of 40 CFR 70.2, with 

respect to greenhouse gas emissions 

from affected stationary combustion 

turbines, the ‘‘pollutant that is subject to 

any standard promulgated under section 

111 of the Act’’ shall be considered to 

be the pollutant that otherwise is 

‘‘subject to regulation’’ as defined in 40 

CFR 70.2. 

(iv) For purposes of 40 CFR 71.2, with 

respect to greenhouse gas emissions 

from affected stationary combustion 

turbines, the ‘‘pollutant that is subject to 

any standard promulgated under section 

111 of the Act’’ shall be considered to 

be the pollutant that otherwise is 

‘‘subject to regulation’’ as defined in 40 

CFR 71.2. 

■ 5. Section 60.4326 is added to read as 

follows: 

§ 60.4326 What CO2 emissions standard 

must I meet? 

You must not discharge from your 

affected stationary combustion turbine 

into the atmosphere any gases that 

contain CO2 in excess of the applicable 

CO2 emissions standard specified in 

Table 2 of this subpart. 

■ 6. Section 60.4333 is amended by 

adding paragraph (c) to read as follows: 

§ 60.4333 What are my general 

requirements for complying with this 

subpart? 

* * * * * 

(c) If you own or operate an affected 

stationary combustion turbine subject to 

a CO2 emissions standard in § 60.4326, 

you must make compliance 

determinations on a 12-operating month 

rolling average basis, and you must 

determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected stationary 

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combustion turbine at the end of each 

12-operating month period. 

■ 7. Section 60.4373 is added under 

undesignated center heading 

‘‘Monitoring’’ to read as follows: 

§ 60.4373 How do I monitor and collect 

data to demonstrate compliance with my 

CO2 emissions standard using a CO2

CEMS? 

(a) You must prepare a monitoring 

plan in accordance with the applicable 

provisions in § 75.53(g) and (h) of this 

chapter. 

(b) You must measure the hourly CO2

mass emissions from each affected 

stationary combustion turbine using the 

procedures in paragraphs (b)(1) through 

(5) of this section, except as provided in 

paragraph (c) of this section. 

(1) You must install, certify, operate, 

maintain, and calibrate a CO2

continuous emission monitoring system 

(CEMS) to directly measure and record 

CO2 concentrations in the stationary 

combustion turbine exhaust gases 

emitted to the atmosphere and an 

exhaust gas flow rate monitoring system 

according to § 75.10(a)(3)(i) of this 

chapter. If you measure CO2

concentration on a dry basis, you must 

also install, certify, operate, maintain, 

and calibrate a continuous moisture 

monitoring system, according to 

§ 75.11(b) of this chapter. 

(2) For each monitoring system that 

you use to determine the CO2 mass 

emissions, you must meet the applicable 

certification and quality assurance 

procedures in § 75.20 of this chapter 

and Appendices B and D to part 75 of 

this chapter. 

(3) You must use a laser device to 

measure the dimensions of each exhaust 

gas stack or duct at the flow monitor 

and the reference method sampling 

locations prior to the initial setup 

(characterization) of the flow monitor. 

For circular stacks, you must make 

measure of the diameter at three or more 

distinct locations and average the 

results. For rectangular stacks or ducts, 

you must measure each dimension (i.e., 

depth and width) at three or more 

distinct locations and average the 

results. If the flow rate monitor or 

reference method sampling site is 

relocated, you must repeat these 

measurements at the new location. 

(4) You must use unadjusted exhaust 

gas volumetric flow rates only to 

determine the hourly CO2 mass 

emissions from the affected stationary 

combustion turbine; you must not apply 

the bias adjustment factors described in 

section 7.6.5 of Appendix A to part 75 

of this chapter to the exhaust gas flow 

rate data. 

(5) If you chose to use Method 2 in 

Appendix A–1 to this part to perform 

the required relative accuracy test audits 

(RATAs) of the part 75 flow rate 

monitoring system, you must use a 

calibrated Type-S pitot tube or pitot 

tube assembly. You must not use the 

default Type-S pitot tube coefficient. 

(c) As an alternative to complying 

with paragraph (b) of this section, you 

may determine the hourly CO2 mass 

emissions by using Equation G–4 in 

Appendix G to part 75 of this chapter 

according to the requirements specified 

in paragraphs (c)(1) and (2) of this 

section. 

(1) You must implement the 

applicable procedures in appendix D to 

part 75 of this chapter to determine 

hourly unit heat input rates (MMBtu/h), 

based on hourly measurements of fuel 

flow rate and periodic determinations of 

the gross calorific value (GCV) of each 

fuel combusted. 

(2) You may determine site-specific 

carbon-based F-factors (Fc) using 

Equation F–7b in section 3.3.6 of 

Appendix F to part 75 of this chapter, 

and you may use these Fc values in the 

emissions calculations instead of using 

the default Fc values in the Equation G– 

4 nomenclature. 

(d) You must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record the gross electric 

output from the affected stationary 

combustion turbine. If the affected 

stationary combustion turbine is a CHP 

stationary combustion turbine, you must 

also install, calibrate, maintain, and 

operate meters to continuously 

determine and record the total useful 

recovered thermal energy. For process 

steam applications, you will need to 

install, calibrate, maintain, and operate 

meters to continuously determine and 

record steam flow rate, temperature, and 

pressure. If the affected stationary 

combustion turbine has a direct 

mechanical drive application, you must 

submit a plan to the Administrator or 

delegated authority for approval of how 

gross energy output will be determined. 

Your plan shall ensure that you install, 

calibrate, maintain, and operate meters 

to continuously determine and record 

each component of the determination. 

(e) If two or more affected stationary 

combustion turbines serve a common 

electric generator, you must apportion 

the combined hourly gross output to the 

individual stationary combustion 

turbines using a plan approved by the 

Administrator (e.g., using steam load or 

heat input to each affected stationary 

combustion turbine). Your plan shall 

ensure that you install, calibrate, 

maintain, and operate meters to 

continuously determine and record each 

component of the determination. 

(f) In accordance with § 60.13(g), if 

two or more stationary combustion 

turbines that implement the continuous 

emission monitoring provisions in 

paragraph (b) of this section share a 

common exhaust gas stack and are 

subject to the same emissions standard 

under § 60.4326, you may monitor the 

hourly CO2 mass emissions at the 

common stack in lieu of monitoring 

each stationary combustion turbine 

separately. If you choose this option, the 

hourly gross load (electric, thermal, 

and/or mechanical, as applicable) must 

be the sum of the hourly loads for the 

individual stationary combustion 

turbines and you must express the 

operating time as ‘‘stack operating 

hours’’ (as defined in § 72.2 of this 

chapter). If you attain compliance with 

the applicable emissions standard in 

§ 60.4326 at the common stack, each 

stationary combustion turbine sharing 

the stack is in compliance. 

(g) In accordance with § 60.13(g), if 

the exhaust gases from a stationary 

combustion turbine that implements the 

continuous emission monitoring 

provisions in paragraph (b) of this 

section are emitted to the atmosphere 

through multiple stacks (or if the 

exhaust gases are routed to a common 

stack through multiple ducts and you 

chose to monitor in the ducts), you must 

monitor the hourly CO2 mass emissions 

and the ‘‘stack operating time’’ (as 

defined in § 72.2 of this chapter) at each 

stack or duct separately. In this case, 

you determine compliance with the 

applicable emissions standard in 

§ 60.4326 by summing the CO2 mass 

emissions measured at the individual 

stacks or ducts and dividing by the total 

gross output for the unit. 

■ 8. Section 60.4374 is added under 

undesignated center heading 

‘‘Monitoring’’ to read as follows: 

§ 60.4374 How do I demonstrate 

compliance with my CO2 emissions 

standard and determine excess emissions? 

(a) You must calculate the CO2 mass 

emissions rate for your affected 

stationary combustion turbine by using 

the hourly CO2 mass emissions and total 

gross output data determined and 

recorded according to the procedures in 

§ 60.4373 for the compliance period for 

the CO2 emissions standard applicable 

to the affected stationary combustion 

turbine, and the calculation procedures 

in paragraphs (a)(1) through (a)(5) of this 

section. 

(1) You must only use operating hours 

in the compliance period for the 

compliance determination calculation 

for which you obtained valid data for all 

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parameters you used to determine the 

hourly CO2 mass emissions and gross 

output data, are used for the compliance 

determination calculation. You must not 

include operating hours in which you 

used the substitute data provisions of 

part 75 of this chapter for any of the 

parameters in the calculation. For the 

compliance determination calculation, 

you must obtain valid hourly CO2 mass 

emission values for a minimum of 95 

percent of the operating hours in the 

compliance period. 

(2) You must calculate the total CO2

mass emissions by summing the hourly 

CO2 mass emissions values for the 

affected stationary combustion turbine 

determined to be valid according to the 

conditions specified in paragraph (a)(1) 

of this section for all of the operating 

hours in the applicable compliance 

period. 

(3) For each operating hour of the 

compliance period used in paragraph 

(a)(2) of this section to calculate the 

total CO2 mass emissions, you must 

determine the affected stationary 

combustion turbine’s corresponding 

hourly gross output (Pgross) by applying 

the appropriate definitions in 

§§ 60.4420 and 60.4421 of this subpart 

and according to the procedures 

specified in paragraphs (a)(3)(i) and (iv) 

of this section. 

(i) Calculate Pgross for your affected 

stationary combustion turbine using the 

following equation: 

Where: 

Pgross = Gross energy output of your affected 

stationary combustion turbine in 

megawatt-hours in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbines in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected stationary combustion 

turbine’s integrated equipment that 

provides electricity to the affected 

facility or auxiliary equipment in MWh. 

(Pt)PS = Useful thermal energy output of 

steam relative to ISO conditions that is 

used for applications that do not 

generate additional electricity, produce 

mechanical energy output, enhance the 

performance of the affected facility. 

Calculated using the equation specified 

in paragraph (a)(3)(ii) of this section in 

MWh. 

(Pt)HR = Useful thermal energy output 

relative to ISO conditions from heat 

recovery that is used for applications 

other than steam generation or 

performance enhancement of the affected 

facility in MWh. 

(Pt)IE = Useful thermal energy output relative 

to ISO conditions from any integrated 

equipment that provides input to the 

affected facility or auxiliary equipment 

in MWh. 

T = Electric Transmission and Distribution 

Factor. 

T = 0.95 for a CHP stationary combustion 

turbine where at least on an annual basis 

20.0 percent of the total gross energy 

output consists of electric or direct 

mechanical output and 20.0 percent of 

the total gross energy output consists of 

useful thermal energy output on a rolling 

3 year basis. 

T = 1.0 for all other affected stationary 

combustion turbines. 

(ii) If applicable to your affected 

stationary combustion turbine, calculate 

(Pt)PS using the following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure relative to ISO 

conditions in Joules per kilogram (J/kg) 

(or Btu/lb). 

3.6 × 109 = Conversion factor (J/MWh) (or 

3.413 × 106 Btu/MWh). 

(iii) You must determine the hourly 

gross energy output for each operating 

hour in which there is no electric 

output, but there is mechanical output 

or useful thermal output. In addition 

you must determine the hourly gross 

CO2 emissions for each operating hour 

in which there is no useful output. 

(iv) In the case for which compliance 

is demonstrated according to 

§ 60.4373(f) for affected stationary 

combustion turbines that vent to a 

common stack, then you must calculate 

the hourly gross energy output (electric, 

mechanical, and/or thermal, as 

applicable) by summing the hourly 

gross energy output you determined for 

each of your individual affected 

stationary combustion turbines that vent 

to the common stack; and you must 

express the operating time as ‘‘stack 

operating hours’’ (as defined in § 72.2 of 

this chapter). 

(4) You must calculate the total gross 

output for the affected stationary 

combustion turbine’s compliance period 

by summing the hourly gross output 

values for the affected stationary 

combustion turbine determined from 

paragraph (a)(2) of this section for all of 

the operating hours in the applicable 

compliance period. 

(5) You must calculate the CO2 mass 

emissions rate for the affected stationary 

combustion turbine by dividing the total 

CO2 mass emissions value as calculated 

according to the requirements of 

paragraph (a)(2) of this section by the 

total gross output value as calculated 

according to the requirements of 

paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions rate for 

the affected stationary combustion 

turbine determined according to the 

procedures specified in paragraph (a) of 

this section is less than or equal to the 

CO2 emissions standard in Table 2 of 

this subpart applicable to the affected 

stationary combustion turbine, then 

your affected stationary combustion 

turbine is in compliance with the 

emissions standard. If the average CO2

mass emissions rate is greater than the 

CO2 emissions standard in Table 2 of 

this subpart applicable to the affected 

stationary combustion turbine, then 

your affected stationary combustion 

turbine has excess CO2 emissions. 

■ 9. Section 60.4375 is amended by 

revising the section heading to read as 

follows: 

§ 60.4375 What reports must I submit to 

comply with my NOX and SO2 emissions 

limits? 

* * * * * 

■ 10. Section 60.4376 is added to read 

as follows: 

§ 60.4376 What notifications and reports 

must I submit to comply with my CO2

emissions standard? 

(a)(1) You must prepare and submit 

the notifications specified in 

§§ 60.7(a)(1) and (a)(3) and 60.19, as 

applicable to your affected stationary 

combustion turbine. 

(2) You must prepare and submit 

notifications specified in § 75.61 of this 

chapter, as applicable to your affected 

stationary combustion turbine. 

(b) You must prepare and submit 

reports according to paragraphs (b)(1) 

through (d) of this section, as 

applicable. 

(1) For stationary combustion turbines 

that are required, by § 60.4333(c), to 

conduct initial and on-going compliance 

determinations on a 12-operating month 

rolling average basis for the standard in 

§ 60.4326, you must submit electronic 

quarterly reports as follows. After you 


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have accumulated the first 12-operating 

months for the affected stationary 

combustion turbine, you must submit a 

report for the calendar quarter that 

includes the 12th-operating month no 

later than 30 days after the end of that 

quarter. Thereafter, you must submit a 

report for each subsequent calendar 

quarter, no later than 30 days after the 

end of the quarter. 

(2) In each quarterly report, you must 

include the following information, as 

applicable: 

(i) Each rolling average CO2 mass 

emissions rate for which the last (12th) 

operating month in a 12-operating 

month compliance period falls within 

the calendar quarter. You must calculate 

each average CO2 mass emissions rate 

according to the requirements of 

§ 60.4374. You must report the dates 

(month and year) of the 1st and 12thoperating months in each compliance 

period for which you performed a CO2

mass emissions rate calculation. If there 

are no compliance periods that end in 

the quarter, you must include a 

statement to that effect; 

(ii) If one or more compliance periods 

end in the quarter, you must identify 

each operating month in the calendar 

quarter with excess CO2 emissions; 

(iii) The percentage of valid CO2 mass 

emission rates (as defined in § 60.4374) 

in each 12-operating month compliance 

period described in paragraph (b)(2)(i) 

of this section (i.e., the total number of 

valid CO2 mass emission rates in that 

period divided by the total number of 

operating hours in that period, 

multiplied by 100 percent); and 

(iv) The CO2 emissions standard (as 

identified in Table 2 of this subpart) 

with which your affected stationary 

combustion turbine is complying. 

(3) The final quarterly report of each 

calendar year must contain the 

following: 

(i) Net electric output sold to an 

electric grid over the 4 quarters of the 

calendar year; and 

(ii) The potential electric output of the 

stationary combustion turbine. 

(c) You must submit all electronic 

reports required under paragraph (b) of 

this section using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office 

of Atmospheric Programs of the EPA. 

(d) You must meet all applicable 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter. 

■ 11. Section 60.4391 is added to read 

as follows: 

§ 60.4391 What records must I maintain to 

comply with my CO2 emissions limits? 

(a) You must maintain records of the 

information you used to demonstrate 

compliance with this subpart as 

specified in § 60.7(b) and (f). 

(b) You must follow the applicable 

recordkeeping requirements and 

maintain records as required under 

subpart F of part 75 of this chapter. 

(c) You must keep records of the 

calculations you performed to 

determine the total CO2 mass emissions 

for: 

(1) Each operating month (for all 

affected units); 

(2) Each compliance period, 

including, as applicable, each 12- 

operating month compliance period. 

(d) You must keep records of the 

applicable data recorded and 

calculations performed that you used to 

determine your affected stationary 

combustion turbine’s gross output for 

each operating month. 

(e) You must keep records of the 

calculations you performed to 

determine the percentage of valid CO2

mass emission rates in each compliance 

period. 

(f) You must keep records of the 

calculations you performed to assess 

compliance with each applicable CO2

mass emissions standard in § 60.4326. 

(g) You must keep records of the 

calculations you performed to 

determine any site-specific carbonbased F-factors you used in the 

emissions calculations (if applicable). 

(h)(1) Your records must be in a form 

suitable and readily available for 

expeditious review. 

(2) You must keep each record for 5 

years after the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record to demonstrate 

compliance with a 12-operating month 

emissions standard. 

(3) You must keep each record on site 

for at least 2 years after the date of each 

occurrence, measurement, maintenance, 

corrective action, report, or record, 

according to § 60.7. You may keep the 

records off site and electronically for the 

remaining year(s) as required by this 

subpart. 

■ 12. Section 60.4395 is revised to read 

as follows: 

§ 60.4395 When must I submit my reports? 

All of your reports required under 

§ 60.7(c) must be postmarked by the 

30th day after the end of each 6-month 

period, except as specified in § 60.4376 

■ 13. Section 60.4421 is added to read 

as follows: 

§ 60.4421 What definitions with respect to 

CO2 emissions apply to this subpart? 

As used in this subpart: 

Base load rating means 100 percent of 

the manufacturer’s design heat input 

capacity of the combustion turbine 

engine at ISO conditions using the 

higher heating value of the fuel (heat 

input from duct burners is not 

included). 

Excess emissions means a specified 

averaging period over which either: 

(1) The CO2 emissions rate of your 

affected stationary combustion turbine 

exceeds the applicable emissions 

standard in Table 2 of this subpart or 

§ 60.4330; or 

(2) The recorded value of a particular 

monitored parameter is outside the 

acceptable range specified in the 

parameter monitoring plan for the 

affected unit. 

Gross energy output means: 

(1) The gross electric or direct 

mechanical output from both the 

combustion turbine engine and any 

associated steam turbine(s) or integrated 

equipment plus any useful thermal 

output measured relative to ISO 

conditions (except for GHG calculations 

in § 60.4374 as only 75 percent credit is 

given) that is not used to generate 

additional electric or mechanical output 

or to enhance the performance of the 

unit (e.g., steam delivered to an 

industrial process for a heating 

application). 

(2) For a CHP stationary combustion 

turbine where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total gross 

energy output consists of useful thermal 

output on a rolling 3-year basis, the sum 

of the gross electric or direct mechanical 

output from both the combustion 

turbine engine and any associated steam 

turbine(s) divided by 0.95 plus any 

useful thermal output measured relative 

to ISO conditions (except for GHG 

calculations in § 60.4374 as only 75 

percent credit is given) that is not used 

to generate additional electric or 

mechanical output or to enhance the 

performance of the unit (e.g., steam 

delivered to an industrial process for a 

heating application). 

Net-electric output means: 

(1) The gross electric sales to the 

utility power distribution system minus 

purchased power on a 3 calendar year 

rolling average basis; or 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total gross 

energy output consists of useful thermal 

output on a 3 calendar year rolling 

average basis, the gross electric sales to 

the utility power distribution system 

minus purchased power of the thermal 

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host facility or facilities on a three 

calendar year rolling average basis. 

Operating month means a calendar 

month during which any fuel is 

combusted in the affected stationary 

combustion turbine. 

Potential electric output means 33 

percent or the design electric output 

efficiency on a net output basis (at the 

election of the owner/operator of the 

affected facility) multiplied by the base 

load rating (expressed in MMBtu/h) of 

the stationary combustion turbine, 

multiplied by 106 Btu/MMBtu, 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 

stationary combustion turbine with a 

100 MW (341 MMBtu/h) fossil-fuel heat 

input capacity would have a 310,000 

MWh 12-month potential electric output 

capacity). 

Stationary combustion turbine means 

all equipment, including but not limited 

to the combustion turbine engine, the 

fuel, air, lubrication and exhaust gas 

systems, control systems, heat recovery 

system, steam turbine, fuel compressor, 

heater, and/or pump, post-combustion 

emission control technology, and any 

ancillary components and subcomponents plus any integrated 

equipment that provides electricity or 

useful thermal output to the combustion 

turbine engine, heat recovery system or 

auxiliary equipment. Stationary means 

that the combustion turbine is not self 

propelled or intended to be propelled 

while performing its function. It may, 

however, be mounted on a vehicle for 

portability. 

■ 14. Table 2 to Subpart KKKK of Part 

60 is added to read as follows: 

TABLE 2 TO SUBPART KKKK OF PART 60—CARBON DIOXIDE EMISSION LIMITS FOR STATIONARY COMBUSTION TURBINES

[Note: all numerical values have a minimum of 2 significant figures] 

Affected stationary combustion turbine CO2 Emission standard 

Stationary combustion turbine that has a design heat input to the turbine engine of greater than 250 MW (850MMBtu/h).450 kilograms (kg) of CO2 per megawatt-hour (MWh) of gross output 

(1,000 lb/MWh) on a 12-operating month rolling average. 

Stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less 

than 250 MW (850MMBtu/h).

500 kg of CO2 per MWh of gross output (1,100 lb CO2/MWh) on a 12- 

operating month rolling average. 

■ 15. Table 3 to Subpart KKKK of Part 

60 is added to read as follows: 

TABLE 3 TO SUBPART KKKK OF PART 60—APPLICABILITY OF SUBPART A GENERAL PROVISIONS TO STATIONARY

COMBUSTION TURBINE CO2 EMISSIONS STANDARDS IN SUBPART KKKK 

General provisions citation Subject of citation 

Applies to 

subpart 

KKKK 

Explanation 

§ 60.1 .......................................... Applicability ...................................................................................... Yes. 

§ 60.2 .......................................... Definitions ........................................................................................ Yes. 

§ 60.3 .......................................... Units and Abbreviations .................................................................. Yes. 

§ 60.4 .......................................... Address ........................................................................................... Yes. 

§ 60.5 .......................................... Determination of construction or modification ................................. Yes. 

§ 60.6 .......................................... Review of plans ............................................................................... Yes. 

§ 60.7 .......................................... Notification and Recordkeeping ...................................................... Yes Only the requirements to 

submit the notification in 

§ 60.7(a)(1) and (a)(3). 

§ 60.8 .......................................... Performance tests ........................................................................... No. 

§ 60.9 .......................................... Availability of Information ................................................................ Yes. 

§ 60.10 ........................................ State authority ................................................................................. Yes. 

§ 60.11 ........................................ Compliance with standards and maintenance requirements .......... No. 

§ 60.12 ........................................ Circumvention .................................................................................. Yes. 

§ 60.13 ........................................ Monitoring requirements .................................................................. Yes. 

§ 60.14 ........................................ Modification ..................................................................................... No. 

§ 60.15 ........................................ Reconstruction ................................................................................. No. 

§ 60.16 ........................................ Priority list ........................................................................................ No. 

§ 60.17 ........................................ Incorporations by reference ............................................................ Yes. 

§ 60.18 ........................................ General control device requirements .............................................. No. 

§ 60.19 ........................................ General notification and reporting requirements ............................. Yes. 

■ 16. Part 60 is amended by adding 

subpart TTTT to read as follows: 

Subpart TTTT—Standards of 

Performance for Greenhouse Gas 

Emissions for Electric Utility 

Generating Units 

Sec. 

Applicability 

60.5508 What is the purpose of this 

subpart? 

60.5509 Am I subject to this subpart? 

Emission Standards 

60.5515 What greenhouse gases are 

regulated by this subpart? 

60.5520 What CO2 emissions standard must 

I meet? 

General Compliance Requirements 

60.5525 What are my general requirements 

for complying with this subpart? 

60.5530 Affirmative defense for violation of 

emission standards during malfunction 

Monitoring and Compliance Determination 

Procedures 

60.5535 How do I monitor and collect data 

to demonstrate compliance? 

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60.5540 How do I demonstrate compliance 

with my CO2 emissions standard and 

determine excess emissions? 

Notifications, Reports, and Records 

60.5550 What notifications must I submit 

and when? 

60.5555 What reports must I submit and 

when? 

60.5560 What records must I maintain? 

60.5565 In what form and how long must I 

keep my records? 

Other Requirements and Information 

60.5570 What parts of the General 

Provisions apply to my affected facility? 

60.5575 Who implements and enforces this 

subpart? 

60.5580 What definitions apply to this 

subpart? 

Applicability 

§ 60.5508 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of greenhouse gas (GHG) 

emissions from a steam generating unit, 

IGCC, or a stationary combustion 

turbine that commences construction 

after [DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

§ 60.5509 Am I subject to this subpart? 

(a) Except as provided for in 

paragraph (b) of this section, the subpart 

applies to any steam generating unit, 

IGCC, or stationary combustion turbine 

that commences construction after 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER] that meets the 

relevant applicability conditions in 

paragraphs (a)(1) and (a)(2) of this 

section. 

(1) A steam generating unit or IGCC 

that has a design heat input greater than 

73 MW (250MMBtu/h) heat input of 

fossil fuel (either alone or in 

combination with any other fuel), 

combusts fossil fuel for more than 10.0 

percent of the average annual heat input 

during a 3 year rolling average basis, 

and was constructed for the purpose of 

supplying, and supplies, one-third or 

more of its potential electric output and 

more than 219,000 MWh net-electric 

output to a utility distribution system 

on an annual basis. 

(2) A stationary combustion turbine 

that has a design heat input to the 

turbine engine greater than 73 MW (250 

MMBtu/h), combusts fossil fuel for more 

than 10.0 percent of the average annual 

heat input during a 3 year rolling 

average basis, combusts over 90% 

natural gas on a heat input basis on a 

3 year rolling average basis, and was 

constructed for the purpose of 

supplying, and supplies, one-third or 

more of its potential electric output and 

more than 219,000 MWh net-electrical 

output to a utility distribution system 

on a 3 year rolling average basis. 

(b) You are not subject to the 

requirements of this subpart if your 

affected facility meets any one of the 

conditions specified in paragraphs (b)(1) 

through (b)(5) of this section. 

(1) The proposed Wolverine EGU 

project described in Permit to Install No. 

317–07 issued by the Michigan 

Department of Environmental Quality, 

Air Quality Division, effective June 29, 

2011 (as revised July 12, 2011). 

(2) The proposed Washington County 

EGU project described in Air Quality 

Permit No. 4911–303–0051–P–01–0 

issued by the Georgia Department of 

Natural Resources, Environmental 

Protection Division, Air Protection 

Branch, effective April 8, 2010, 

provided that construction had not 

commenced for NSPS purposes as of 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

(3) The proposed Holcomb EGU 

project described in Air Emission 

Source Construction Permit 0550023 

issued by the Kansas Department of 

Health and Environment, Division of 

Environment, effective December 16, 

2010, provided that construction had 

not commenced for NSPS purposes as of 

[DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 

(4) Your affected facility is a 

municipal waste combustor unit that is 

subject to subpart Eb of this part. 

(5) Your affected facility is a 

commercial or industrial solid waste 

incineration unit that is subject to 

subpart CCCC of this part. 

Emission Standards 

§ 60.5515 What greenhouse gases are 

regulated by this subpart? 

(a) The greenhouse gas regulated by 

this subpart is carbon dioxide (CO2). 

(b) PSD and Title V Thresholds for 

Greenhouse Gases. 

(1) For purposes of 40 CFR 

51.166(b)(49)(ii), with respect to GHG 

emissions from affected facilities, the 

‘‘pollutant that is subject to the standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

40 CFR 51.166(b)(48) and in any SIP 

approved by the EPA that is interpreted 

to incorporate, or specifically 

incorporates, 40 CFR 51.166(b)(48). 

(2) For purposes of 40 CFR 

52.21(b)(50)(ii), with respect to GHG 

emissions from affected facilities, the 

‘‘pollutant that is subject to the standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is subject to 

regulation under the Act as defined in 

40 CFR 52.21(b)(49). 

(3) For purposes of 40 CFR 70.2, with 

respect to greenhouse gas emissions 

from affected facilities, the ‘‘pollutant 

that is subject to any standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 70.2. 

(4) For purposes of 40 CFR 71.2, with 

respect to greenhouse gas emissions 

from affected facilities, the ‘‘pollutant 

that is subject to any standard 

promulgated under section 111 of the 

Act’’ shall be considered to be the 

pollutant that otherwise is ‘‘subject to 

regulation’’ as defined in 40 CFR 71.2. 

§ 60.5520 What CO2 emissions standard 

must I meet? 

For each affected facility subject to 

this subpart, you must not discharge 

from the affected facility stack into the 

atmosphere any gases that contain CO2

in excess of the applicable CO2

emissions standard specified in Table 1 

of this subpart. 

General Compliance Requirements 

§ 60.5525 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission standards in this subpart 

that apply to your affected facility at all 

times. However, you must make a 

compliance determination only at the 

end of the applicable operating month, 

as provided in paragraphs (a)(1) and (2) 

of this section. 

(1) For each affected facility subject to 

a CO2 emissions standard based on a 12- 

operating month rolling average, you 

must determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected facility at the end 

of each 12-operating month period. 

(2) For each affected facility subject to 

a CO2 emissions standard based on an 

84-operating month rolling average, you 

must determine compliance monthly by 

calculating the average CO2 emissions 

rate for the affected facility at the end 

of each 84-operating month period. 

(b) At all times you must operate and 

maintain each affected facility, 

including associated equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practice. The 

Administrator will determine if you are 

using consistent operation and 

maintenance procedures based on 

information available to the 

Administrator that may include, but is 

not limited to, fuel use records, 

monitoring results, review of operation 

and maintenance procedures and 

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records, review of reports required by 

this subpart, and inspection of the 

facility. 

(c) You must conduct an initial 

compliance determination for your 

affected facility for the applicable 

emissions standard in § 60.5520, 

according to the requirements in this 

subpart, within 30 days after the end of 

the initial compliance period for the 

CO2 emissions standards applicable to 

your affected facility (i.e., 12-operating 

months or 84-operating months). The 

first operating month included in this 

compliance period is the month in 

which emissions reporting is required to 

begin under § 75.64(a) of this chapter. 

§ 60.5530 Affirmative defense for violation 

of emission standards during malfunction. 

In response to an action to enforce the 

standards set forth in § 60.5520, you 

may assert an affirmative defense to a 

claim for civil penalties for violations of 

such standards that are caused by 

malfunction, as defined at 40 CFR 60.2. 

Appropriate penalties may be assessed 

if you fail to meet your burden of 

proving all of the requirements in the 

affirmative defense. The affirmative 

defense shall not be available for claims 

for injunctive relief. 

(a) Assertion of affirmative defense. 

To establish the affirmative defense in 

any action to enforce such a standard, 

you must timely meet the reporting 

requirements in paragraph (b) of this 

section, and must prove by a 

preponderance of evidence that: 

(1) The violation: 

(i) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner; and 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; 

(iv) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; 

(2) Repairs were made as 

expeditiously as possible when the 

violation occurred; 

(3) The frequency, amount and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; 

(4) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; 

(5) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

(7) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; 

(8) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(b) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. This 

affirmative defense report is due after 

the initial occurrence of the exceedance 

of the standard in § 60.5520, and on the 

same quarterly reporting schedule as in 

§ 60.5555 (which may be the end of any 

applicable averaging period). If such 

quarterly report is due less than 45 days 

after the initial occurrence of the 

violation, the affirmative defense report 

may be included in the following 

quarterly report required in § 60.5555(a). 

Monitoring and Compliance 

Determination Procedures 

§ 60.5535 How do I monitor and collect 

data to demonstrate compliance? 

(a) You must prepare a monitoring 

plan in accordance with the applicable 

provisions in § 75.53(g) and (h) of this 

chapter. 

(b) You must measure the hourly CO2

mass emissions from each affected 

facility using the procedures in 

paragraphs (b)(1) through (5) of this 

section, except as provided in paragraph 

(c) of this section. 

(1) You must install, certify, operate, 

maintain, and calibrate a CO2

continuous emission monitoring system 

(CEMS) to directly measure and record 

CO2 concentrations in the affected 

facility exhaust gases emitted to the 

atmosphere and an exhaust gas flow rate 

monitoring system according to 

§ 75.10(a)(3)(i) of this chapter. If you 

measure CO2 concentration on a dry 

basis, you must also install, certify, 

operate, maintain, and calibrate a 

continuous moisture monitoring system, 

according to § 75.11(b) of this chapter. 

(2) For each monitoring system you 

use to determine the CO2 mass 

emissions, you must meet the applicable 

certification and quality assurance 

procedures in § 75.20 of this chapter 

and Appendices B and D to part 75 of 

this chapter. 

(3) You must use a laser device to 

measure the dimensions of each exhaust 

gas stack or duct at the flow monitor 

and the reference method sampling 

locations prior to the initial setup 

(characterization) of the flow monitor. 

For circular stacks, you must measure 

the diameter at three or more distinct 

locations and average the results. For 

rectangular stacks or ducts, you must 

measure each dimension (i.e., depth and 

width) at three or more distinct 

locations and average the results. If the 

flow rate monitor or reference method 

sampling site is relocated, you must 

repeat these measurements at the new 

location. 

(4) You must use only unadjusted 

exhaust gas volumetric flow rates to 

determine the hourly CO2 mass 

emissions from the affected facility; you 

must not apply the bias adjustment 

factors described in section 7.6.5 of 

Appendix A to part 75 of this chapter 

to the exhaust gas flow rate data. 

(5) If you choose to use Method 2 in 

Appendix A–1 to this part to perform 

the required relative accuracy test audits 

(RATAs) of the part 75 flow rate 

monitoring system, you must use a 

calibrated Type-S pitot tube or pitot 

tube assembly. You must not use the 

default Type-S pitot tube coefficient. 

(c) If your affected facility exclusively 

combusts liquid fuel and/or gaseous fuel 

as an alternative to complying with 

paragraph (b) of this section, you may 

determine the hourly CO2 mass 

emissions by using Equation G–4 in 

Appendix G to part 75 of this chapter 

according to the requirements in 

paragraphs (c)(1) and (2) of this section. 

(1) You must implement the 

applicable procedures in appendix D to 

part 75 of this chapter to determine 

hourly unit heat input rates (MMBtu/h), 

based on hourly measurements of fuel 

flow rate and periodic determinations of 

the gross calorific value (GCV) of each 

fuel combusted. 

(2) You may determine site-specific 

carbon-based F-factors (Fc) using 

Equation F–7b in section 3.3.6 of 

appendix F to part 75 of this chapter, 

and you may 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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(d) You must install, calibrate, 

maintain, and operate a sufficient 

number of watt meters to continuously 

measure and record the gross electric 

output from the affected facility. If the 

affected facility is a CHP facility, you 

must also install, calibrate, maintain, 

and operate meters to continuously 

determine and record the total useful 

recovered thermal energy. For process 

steam applications, you will need to 

install, calibrate, maintain, and operate 

meters to continuously determine and 

record steam flow rate, temperature, and 

pressure. If the affected facility has a 

direct mechanical drive application, you 

must submit a plan to the Administrator 

or delegated authority for approval of 

how gross energy output will be 

determined. Your plan shall ensure that 

you install, calibrate, maintain, and 

operate meters to continuously 

determine and record each component 

of the determination. 

(e) If two or more affected facilities 

serve a common electric generator, you 

must apportion the combined hourly 

gross output to the individual affected 

facilities using a plan approved by the 

Administrator (e.g., using steam load or 

heat input to each affected EGU). Your 

plan shall ensure that you install, 

calibrate, maintain, and operate meters 

to continuously determine and record 

each component of the determination. 

(f) In accordance with § 60.13(g), if 

two or more affected facilities that 

implement the continuous emission 

monitoring provisions in paragraph (b) 

of this section share a common exhaust 

gas stack and are subject to the same 

emissions standard under § 60.5520, 

you may monitor the hourly CO2 mass 

emissions at the common stack in lieu 

of monitoring each EGU separately. If 

you choose this option, the hourly gross 

load (electric, thermal, and/or 

mechanical, as applicable) must be the 

sum of the hourly loads for the 

individual affected facility and you 

must express the operating time as 

‘‘stack operating hours’’ (as defined in 

§ 72.2 of this chapter). If you attain 

compliance with the applicable 

emissions standard in § 60.5520 at the 

common stack, each affected facility 

sharing the stack is in compliance. 

(g) In accordance with § 60.13(g), if 

the exhaust gases from an affected 

facility that implements the continuous 

emission monitoring provisions in 

paragraph (b) of this section are emitted 

to the atmosphere through multiple 

stacks (or if the exhaust gases are routed 

to a common stack through multiple 

ducts and you elect to monitor in the 

ducts), you must monitor the hourly 

CO2 mass emissions and the ‘‘stack 

operating time’’ (as defined in § 72.2 of 

this chapter) at each stack or duct 

separately. In this case, you must 

determine compliance with the 

applicable emissions standard in 

§ 60.5520 by summing the CO2 mass 

emissions measured at the individual 

stacks or ducts and dividing by the total 

gross output for the affected facility. 

§ 60.5540 How do I demonstrate 

compliance with my CO2 emissions 

standard and determine excess emissions? 

(a) You must calculate the CO2 mass 

emissions rate for your affected facility 

by using the hourly CO2 mass emissions 

and total gross output data determined 

and recorded according to the 

procedures in § 60.5535 for each 

operating hour in the compliance period 

for the CO2 emissions standard 

applicable to the affected facility (i.e., 

12- or 84-operating month rolling 

average period), and the calculation 

procedures in paragraphs (a)(1) through 

(a)(5) of this section. 

(1) You can only use operating hours 

in the compliance period for the 

compliance determination calculation if 

valid data are obtained for all 

parameters you used to determine the 

hourly CO2 mass emissions and the 

gross output data are used for the 

compliance determination calculation. 

You must not include operating hours 

in which you used the substitute data 

provisions of part 75 of this chapter for 

any of those parameters in the 

calculation. For the compliance 

determination calculation, you must 

obtain valid hourly CO2 mass emission 

values for a minimum of 95 percent of 

the operating hours in the compliance 

period for the CO2 emissions standard 

applicable to the affected facility. 

(2) You must calculate the total CO2

mass emissions by summing the valid 

hourly CO2 mass emissions values for 

all of the operating hours in the 

applicable compliance period. 

(3) For each operating hour of the 

compliance period that you used in 

paragraph (a)(2) of this section to 

calculate the total CO2 mass emissions, 

you must determine the affected 

facility’s corresponding hourly gross 

output according to the procedures in 

paragraphs (a)(3)(i) and (ii) of this 

section, as appropriate for the type of 

affected facility. For an operating hour 

in which there is no gross electric load, 

but there is mechanical or useful 

thermal output, you must still 

determine the gross output for that hour. 

In addition, for operating hours in 

which there is no useful output, you 

still need to determine the CO2

emissions for that hour. 

(i) Calculate Pgross for your affected 

facility using the following equation: 

Where: a 

Pgross = Gross energy output of your affected 

facility in megawatt-hours in MWh. 

(Pe)ST = Electric energy output plus 

mechanical energy output (if any) of 

steam turbines in MWh. 

(Pe)CT = Electric energy output plus 

mechanical energy output (if any) of 

stationary combustion turbine(s) in 

MWh. 

(Pe)IE = Electric energy output plus 

mechanical energy output (if any) of 

your affected facility’s integrated 

equipment that provides electricity or 

mechanical energy to the affected facility 

or auxiliary equipment in MWh. 

(Pe)FW = Electric energy used to power boiler 

feedwater pumps at steam generating 

units in MWh. Not applicable to 

stationary combustion turbines or IGCC 

facilities. 

(Pt)PS = Useful thermal energy output of 

steam measured relative to ISO 

conditions that is used for applications 

that do not generate additional 

electricity, produce mechanical energy 

output, or enhance the performance of 

the affected facility. Calculated using the 

equation specified in paragraph 

(g)(3)(iii)(B) of this section in MWh. 

(Pt)HR = Hourly useful thermal energy output 

measured relative to ISO conditions from 

heat recovery that is used for 

applications other than steam generation 

or performance enhancement of the 

affected facility in MWh. 

(Pt)IE = Useful thermal energy output relative 

to ISO conditions from any integrated 

equipment that provides thermal energy 

to the affected facility or auxiliary 

equipment in MWh. 

T = Electric Transmission and Distribution 

Factor. 

T = 0.95 for a combined heat and power 

affected facility where at least on an 

annual basis 20.0 percent of the total 

gross energy output consists of electric or 

direct mechanical output and 20.0 

percent of the total gross energy output 

consists of useful thermal energy output 

on a rolling 3 year basis. 

T = 1.0 for all other affected facilities. 


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(ii) If applicable to your affected 

facility, you must calculate (Pt)PS using 

the following equation: 

Where: 

Qm = Measured steam flow in kilograms (kg) 

(or pounds (lb)) for the operating hour. 

H = Enthalpy of the steam at measured 

temperature and pressure relative to ISO 

conditions in Joules per kilogram (J/kg) 

(or Btu/lb). 

3.6 × 109 = Conversion factor (J/MWh) (or 

3.413 × 106 Btu/MWh). 

(4) You must calculate the total gross 

output for the affected facility’s 

compliance period by summing the 

hourly gross output values for the 

affected facility that you determined 

from paragraph (a)(2) of this section for 

all of the operating hours in the 

applicable compliance period. 

(5) You must calculate the CO2 mass 

emissions rate for the affected facility by 

dividing the total CO2 mass emissions 

value calculated according to the 

procedures in paragraph (a)(2) of this 

section by the total gross output value 

calculated according to the procedures 

in paragraph (a)(4) of this section. 

(b) If the CO2 mass emissions rate for 

your affected facility that you 

determined according to the procedures 

specified in paragraph (a) of this section 

is less than or equal to the CO2

emissions standard in Table 1 of this 

subpart applicable to the affected 

facility, then your affected facility is in 

compliance with the emissions 

standard. If the average CO2 mass 

emissions rate is greater than the CO2

emissions standard in Table 1 of this 

subpart applicable to the affected 

facility, then your affected facility has 

excess CO2 emissions. 

Notification, Reports, and Records 

§ 60.5550 What notifications must I submit 

and when? 

(a) You must prepare and submit the 

notifications specified in §§ 60.7(a)(1) 

and (a)(3) and 60.19, as applicable to 

your affected facility. 

(b) You must prepare and submit 

notifications specified in § 75.61 of this 

chapter, as applicable to your affected 

facility. 

§ 60.5555 What reports must I submit and 

when? 

(a) You must prepare and submit 

reports according to paragraphs (a) 

through (d) of this section, as 

applicable. 

(1) For affected facilities that are 

required by § 60.5525 to conduct initial 

and on-going compliance 

determinations on a 12- or 84-operating 

month rolling average basis for the 

standard in § 60.5520 you must submit 

electronic quarterly reports as follows. 

After you have accumulated the first 12- 

operating months for the affected 

facility (or, the first 84-operating months 

for an affected facility electing to 

comply with the 84-operating month 

standard), you must submit a report for 

the calendar quarter that includes the 

twelfth (or eighty-fourth) operating 

month no later than 30 days after the 

end of that quarter. Thereafter, you must 

submit a report for each subsequent 

calendar quarter, no later than 30 days 

after the end of the quarter. 

(2) In each quarterly report you must 

include the following information, as 

applicable: 

(i) Each rolling average CO2 mass 

emissions rate for which the last (12th 

or eighty-fourth) operating month in a 

12- or 84-operating month compliance 

period falls within the calendar quarter. 

You must calculate each average CO2

mass emissions rate according to the 

procedures in § 60.5540. You must 

report the dates (month and year) of the 

first and twelfth (or eighty-fourth) 

operating months in each compliance 

period for which you performed a CO2

mass emissions rate calculation. If there 

are no compliance periods that end in 

the quarter, you must include a 

statement to that effect; 

(ii) If one or more compliance periods 

end in the quarter you must identify 

each operating month in the calendar 

quarter with excess CO2 emissions; 

(iii) The percentage of valid CO2 mass 

emission rates (as defined in § 60.5540) 

in each 12- or 84-operating month 

compliance period described in 

paragraph (a)(1)(i) of this section (i.e., 

the total number of valid CO2 mass 

emission rates in that period divided by 

the total number of operating hours in 

that period, multiplied by 100 percent); 

and 

(iv) The CO2 emissions standard (as 

identified in Table 1 of this subpart) 

with which your affected facility is 

complying. 

(3) In the final quarterly report of each 

calendar year, you must include the 

following: 

(i) Gross electric output sold to an 

electric grid over the 4 quarters of the 

calendar year; and 

(ii) The potential electric output of the 

facility. 

(b) You must submit all electronic 

reports required under paragraph (a) of 

this section using the Emissions 

Collection and Monitoring Plan System 

(ECMPS) Client Tool provided by the 

Clean Air Markets Division in the Office 

of Atmospheric Programs of EPA. 

(c) You must meet all applicable 

reporting requirements and submit 

reports as required under subpart G of 

part 75 of this chapter. 

(d) If your affected unit employs 

geologic sequestration to meet the 

applicable emission limit, you must 

report in accordance with the 

requirements of 40 CFR part 98, subpart 

PP and either: 

(1) if injection occurs onsite, report in 

accordance with the requirements of 40 

CFR part 98, subpart RR, or 

(2) if injection occurs offsite, transfer 

the captured CO2 to a facility or 

facilities that reports in accordance with 

the requirements of 40 CFR part 98, 

subpart RR. 

§ 60.5560 What records must I maintain? 

(a) You must maintain records of the 

information you used to demonstrate 

compliance with this subpart as 

specified in § 60.7(b) and (f). 

(b) You must follow the applicable 

recordkeeping requirements and 

maintain records as required under 

subpart F of part 75 of this chapter. 

(c) You must keep records of the 

calculations you performed to 

determine the total CO2 mass emissions 

for: 

(1) Each operating month (for all 

affected units); 

(2) Each compliance period, 

including, as applicable, each 12- 

operating month compliance period and 

the 84-operating month compliance 

period. 

(d) You must keep records of the 

applicable data recorded and 

calculations performed that you used to 

determine your affected facility’s gross 

output for each operating month. 

(e) You must keep records of the 

calculations you performed to 

determine the percentage of valid CO2

mass emission rates in each compliance 

period. 

(f) You must keep records of the 

calculations you performed to assess 

compliance with each applicable CO2

mass emissions standard in § 60.5520. 

(g) You must keep records of the 

calculations you performed to 

determine any site-specific carbonbased F-factors you used in the 

emissions calculations (if applicable). 

§ 60.5565 In what form and how long must 

I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review. 

(b) You must maintain each record for 

5 years after the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record except those 

records required to demonstrate 


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compliance with an 84-operating month 

compliance period. You must maintain 

records required to demonstrate 

compliance with an 84-operating month 

compliance period for at least 10 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(c) You must maintain each record on 

site for at least 2 years after the date of 

each occurrence, measurement, 

maintenance, corrective action, report, 

or record, according to § 60.7. You may 

maintain the records off site and 

electronically for the remaining year(s) 

as required by this subpart. 

Other Requirements and Information 

§ 60.5570 What parts of the General 

Provisions apply to my affected facility? 

Notwithstanding any other provision 

of this chapter, certain parts of the 

General Provisions in §§ 60.1 through 

60.19, listed in Table 2 of this subpart, 

do not apply to your affected facility. 

§ 60.5575 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by the EPA, or a delegated 

authority such as your state, local, or 

tribal agency. If the Administrator has 

delegated authority to your state, local, 

or tribal agency, then that agency (as 

well as the EPA) has the authority to 

implement and enforce this subpart. 

You should contact your EPA Regional 

Office to find out if this subpart is 

delegated to your state, local, or tribal 

agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency, the 

Administrator retains the authorities 

listed in paragraphs (b)(1) through (5) of 

this section and does not transfer them 

to the state, local, or tribal agency. In 

addition, the EPA retains oversight of 

this subpart and can take enforcement 

actions, as appropriate. 

(1) Approval of alternatives to the 

emission standards. 

(2) Approval of major alternatives to 

test methods. 

(3) Approval of major alternatives to 

monitoring. 

(4) Approval of major alternatives to 

recordkeeping and reporting. 

(5) Performance test and data 

reduction waivers under § 60.8(b). 

§ 60.5580 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subpart A (General Provisions of this 

part). 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Base load rating means the maximum 

amount of heat input (fuel) that a steam 

generating unit can combust on a steady 

state basis, as determined by the 

physical design and characteristics of 

the steam generating unit at ISO 

conditions. For a stationary combustion 

turbine, baseload means 100 percent of 

the design heat input capacity of the 

simple cycle portion of the stationary 

combustion turbine at ISO conditions 

(heat input from duct burners is not 

included). 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17), 

coal refuse, and petroleum coke. 

Synthetic fuels derived from coal for the 

purpose of creating useful heat, 

including but not limited to solventrefined coal, gasified coal (not meeting 

the definition of natural gas), coal-oil 

mixtures, and coal-water mixtures are 

included in this definition for the 

purposes of this subpart. 

Coal refuse means waste products of 

coal mining, physical coal cleaning, and 

coal preparation operations (e.g. culm, 

gob, etc.) containing coal, matrix 

material, clay, and other organic and 

inorganic material. 

Combined cycle facility means an 

electric generating unit that uses a 

stationary combustion turbine from 

which the heat from the turbine exhaust 

gases is recovered by a heat recovery 

steam generating unit to generate 

additional electricity. 

Combined heat and power facility or 

CHP facility, (also known as 

‘‘cogeneration’’) means an electric 

generating unit that that use a steamgenerating unit or stationary combustion 

turbine to simultaneously produce both 

electric (or mechanical) and useful 

thermal energy from the same primary 

energy source. 

Distillate oil means fuel oils that 

contain no more than 0.05 weight 

percent nitrogen and comply with the 

specifications for fuel oil numbers 1 and 

2, as defined by the American Society 

of Testing and Materials in ASTM D396 

(incorporated by reference, see § 60.17); 

diesel fuel oil numbers 1 and 2, as 

defined by the American Society for 

Testing and Materials in ASTM D975 

(incorporated by reference, see § 60.17); 

kerosene, as defined by the American 

Society of Testing and Materials in 

ASTM D3699 (incorporated by 

reference, see § 60.17); biodiesel as 

defined by the American Society of 

Testing and Materials in ASTM D6751 

(incorporated by reference, see § 60.17); 

or biodiesel blends as defined by the 

American Society of Testing and 

Materials in ASTM D7467 (incorporated 

by reference, see § 60.17). 

Excess emissions means a specified 

averaging period over which the CO2

emissions rate is higher than the 

applicable emissions standard located 

in Table 1 of this subpart. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Gaseous fuel means any fuel that is 

present as a gas at ISO conditions and 

includes, but is not limited to, natural 

gas, refinery fuel gas, process gas, cokeoven gas, synthetic gas, and gasified 

coal. 

Gross energy output means: 

(1) For stationary combustion turbines 

and IGCC facilities, the gross electric or 

direct mechanical output from both the 

unit (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)) plus 75 percent of the 

useful thermal output measured relative 

to ISO conditions that is not used to 

generate additional electric or 

mechanical output or to enhance the 

performance of the unit (e.g., steam 

delivered to an industrial process for a 

heating application). 

(2) For electric utility steam 

generating units, the gross electric or 

mechanical output from the affected 

facility (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)) minus any electricity used 

to power the feedwater pumps plus 75 

percent of the useful thermal output 

measured relative to ISO conditions that 

is not used to generate additional 

electric or mechanical output or to 

enhance the performance of the unit 

(e.g., steam delivered to an industrial 

process for a heating application); 

(3) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

20.0 percent of the total gross energy 

output consists of thermal output on a 

rolling 3 year basis, the gross electric or 

mechanical output from the affected 

facility (including, but not limited to, 

output from steam turbine(s), 

combustion turbine(s), and gas 

expander(s)) minus any electricity used 

to power the feedwater pumps (the 

electric auxiliary load of boiler 

feedwater pumps is not applicable to 

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IGCC facilities), that difference divided 

by 0.95, plus 75 percent of the useful 

thermal output measured relative to ISO 

conditions that is not used to generate 

additional electric or mechanical output 

or to enhance the performance of the 

unit (e.g., steam delivered to an 

industrial process for a heating 

application). 

Heat recovery steam generating unit 

(HRSG) means a unit in which hot 

exhaust gases from the combustion 

turbine engine are routed in order to 

extract heat from the gases and generate 

useful output. Heat recovery steam 

generating units can be used with or 

without duct burners. 

Integrated gasification combined 

cycle facility or IGCC facility means a 

combined cycle stationary combustion 

turbine that is designed to burn fuels 

containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the 

definition of natural gas. The 

Administrator may waive the 50 percent 

solid-derived fuel requirement during 

periods of the gasification system 

construction, startup and 

commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit 

during operation. 

ISO conditions means 288 Kelvin (15° 

C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Liquid fuel means any fuel that is 

present as a liquid at ISO conditions 

and includes, but is not limited to, 

distillate oil and residual oil. 

Mechanical output means the useful 

mechanical energy that is not used to 

operate the affected facility, generate 

electricity and/or thermal energy, or to 

enhance the performance of the affected 

facility. Mechanical energy measured in 

horsepower hour should be converted 

into MWh by multiplying it by 745.7 

then dividing by 1,000,000. 

Natural gas means a fluid mixture of 

hydrocarbons (e.g., methane, ethane, or 

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a 

process which might result in highly 

variable sulfur content or heating value. 

Net-electric output means: 

(1) The gross electric sales to the 

utility power distribution system minus 

purchased power on a three calendar 

year rolling average basis; or 

(2) For combined heat and power 

facilities where at least 20.0 percent of 

the total gross energy output consists of 

electric or direct mechanical output and 

at least 20.0 percent of the total gross 

energy output consists of useful thermal 

output on a 3 calendar year rolling 

average basis, the gross electric sales to 

the utility power distribution system 

minus purchased power of the thermal 

host facility or facilities on a three 

calendar year rolling average basis. 

Oil means crude oil or petroleum or 

a fuel derived from crude oil or 

petroleum, including distillate and 

residual oil, and gases derived from 

solid oil-derived fuels (not meeting the 

definition of natural gas). 

Operating month means a calendar 

month during which any fuel is 

combusted in the affected facility at any 

time. 

Potential electric output means 33 

percent or the design electric output 

efficiency on a net output basis 

multiplied by the maximum design heat 

input capacity (expressed in MMBtu/h) 

of the steam generating unit, multiplied 

by 106 Btu/MMBtu, 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 affected facility with a 

100 MW (341 MMBtu/h) fossil-fuel heat 

input capacity would have a 310,000 

MWh 12 month potential electric output 

capacity). 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine engine, the fuel, air, 

lubrication and exhaust gas systems, 

control systems (except emissions 

control equipment), heat recovery 

system, fuel compressor, heater, and/or 

pump, post-combustion emission 

control technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system plus any 

integrated equipment that provides 

electricity or useful thermal output to 

the combustion turbine engine, heat 

recovery system or auxiliary equipment. 

Stationary means that the combustion 

turbine is not self propelled or intended 

to be propelled while performing its 

function. It may, however, be mounted 

on a vehicle for portability. If a 

stationary combustion turbine burns any 

solid fuel directly it is considered a 

steam generating unit. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel and producing steam 

(nuclear steam generators are not 

included) plus any integrated 

equipment that provides electricity or 

useful thermal output to the affected 

facility or auxiliary equipment. 

Useful thermal output means the 

thermal energy made available for use in 

any industrial or commercial process, or 

used in any heating or cooling 

application, i.e., total thermal energy 

made available for processes and 

applications other than electric 

generation, mechanical output at the 

affected facility, or to enhance the 

performance of the affected facility. 

Thermal output for this subpart means 

the energy in recovered thermal output 

measured against the energy in the 

thermal output at ISO conditions. 

TABLE 1 TO SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS

[NOTE: all numerical values have a minimum of 2 significant figures] 

Affected facility CO2 Emission standard 

Stationary combustion turbine that has a base load rating heat input to 

the turbine engine of greater than 250 MW (850MMBtu/h).

450 kilograms (kg) of CO2 per megawatt-hour (MWh) of gross output 

(1,000 lb/MWh) on a 12-operating month rolling average. 

Stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less 

than 250 MW (850MMBtu/h).

500 kg of CO2 per MWh of gross output (1,100 lb CO2/MWh) on a 12- 

operating month rolling average. 

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TABLE 1 TO SUBPART TTTT OF PART 60—CO2 EMISSION STANDARDS—Continued 

[NOTE: all numerical values have a minimum of 2 significant figures] 

Affected facility CO2 Emission standard 

Steam generating unit .............................................................................. 500 kg of CO2 per MWh of gross energy output (1,100 lb CO2/MWh) 

on a 12-operating month rolling average basis; 

or 

480 kg of CO2 per MWh of gross energy output (1,050 lb CO2/MWh) 

on an 84-operating month rolling average basis. 

Integrated gasification combined cycle (IGCC) facility ............................ 500 kg of CO2 per MWh of gross energy output (1,100 lb CO2/MWh) 

on a 12-operating month rolling average basis; 

or 

480 kg of CO2 per MWh of gross energy output (1,050 lb CO2/MWh) 

on an 84-operating month rolling average basis. 

TABLE 2 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A GENERAL PROVISIONS TO SUBPART TTTT 

General provisions citation Subject of citation 

Applies to 

subpart 

TTTT 

Explanation 

§ 60.1 .......................................... Applicability ...................................................................................... Yes.

§ 60.2 .......................................... Definitions ........................................................................................ Yes .......... Additional terms defined in 

§ 60.5580. 

§ 60.3 .......................................... Units and Abbreviations .................................................................. Yes.

§ 60.4 .......................................... Address ........................................................................................... Yes.

§ 60.5 .......................................... Determination of construction or modification ................................. Yes.

§ 60.6 .......................................... Review of plans ............................................................................... Yes.

§ 60.7 .......................................... Notification and Recordkeeping ...................................................... Yes .......... Only the requirements to 

submit the notification in 

§ 60.7(a)(1) and (a)(3). 

§ 60.8 .......................................... Performance tests ........................................................................... No.

§ 60.9 .......................................... Availability of Information ................................................................ Yes.

§ 60.10 ........................................ State authority ................................................................................. Yes.

§ 60.11 ........................................ Compliance with standards and maintenance requirements .......... No.

§ 60.12 ........................................ Circumvention .................................................................................. Yes.

§ 60.13 ........................................ Monitoring requirements .................................................................. Yes.

§ 60.14 ........................................ Modification ..................................................................................... No.

§ 60.15 ........................................ Reconstruction ................................................................................. No.

§ 60.16 ........................................ Priority list ........................................................................................ No.

§ 60.17 ........................................ Incorporations by reference ............................................................ Yes.

§ 60.18 ........................................ General control device requirements .............................................. No.

§ 60.19 ........................................ General notification and reporting requirements ............................. Yes.

PART 70—STATE OPERATING PERMIT 

PROGRAMS 

■ 17. The authority citation for part 70 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

■ 18. Section 70.2 is amended: 

■ a. By adding in alphabetical order the 

definition of ‘‘Greenhouse gases,’’ 

■ b. By revising the introductory text, 

removing ‘‘or’’ from the end of 

paragraph (2), adding ‘‘or’’ to the end of 

paragraph (3), and adding paragraph (4) 

to the definition of ‘‘Regulated pollutant 

(for presumptive fee calculation),’’ and 

■ c. By revising paragraph (1) to the 

definition of ‘‘Subject to regulation.’’ 

The revision and additions read as 

follows: 

§ 70.2 Definitions. 

* * * * * 

Greenhouse gases (GHGs) means the 

air pollutant defined in § 86.1818–12(a) 

of this chapter as the aggregate group of 

six greenhouse gases: carbon dioxide, 

nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, 

and sulfur hexafluoride. 

* * * * * 

Regulated pollutant (for presumptive 

fee calculation), which is used only for 

purposes of § 70.9(b)(2), means any 

regulated air pollutant except the 

following: 

* * * * * 

(4) Greenhouse gases. 

* * * * * 

Subject to regulation * * * 

(1) Greenhouse gases shall not be 

subject to regulation unless, as of July 1, 

2011, the GHG emissions are at a 

stationary source emitting or having the 

potential to emit 100,000 tpy CO2

equivalent emissions. 

* * * * * 

■ 19. Section 70.9 is amended by 

revising paragraph (b)(2)(i), and by 

adding paragraph (b)(2)(v) to read as 

follows: 

§ 70.9 Fee determination and certification. 

* * * * * 

(b) * * * 

(2)(i) The Administrator will presume 

that the fee schedule meets the 

requirements of paragraph (b)(1) of this 

section if it would result in the 

collection and retention of an amount 

not less than $25 per year [as adjusted 

pursuant to the criteria set forth in 

paragraph (b)(2)(iv) of this section] 

times the total tons of the actual 

emissions of each regulated pollutant 

(for presumptive fee calculation) 

emitted from part 70 sources and any 

GHG cost adjustment required under 

paragraph (b)(2)(v) of this section. 

* * * * * 

(v) GHG cost adjustment. The amount 

calculated in paragraph (b)(2)(i) of this 

section shall be increased by the GHG 

cost adjustment determined as follows: 

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For each activity identified in the 

following table, multiply the number of 

activities performed by the permitting 

authority by the burden hours per 

activity, and then calculate a total 

number of burden hours for all 

activities. Next, multiply the burden 

hours by the average cost of staff time, 

including wages, employee benefits and 

overhead. 

Activity 

Burden 

hours per 

activity 

GHG completeness determination (for initial permit or updated application) .................... 43 

GHG evaluation for a modification or related permit action .... 7 

GHG evaluation at permit renewal ....................................... 10 

* * * * * 

PART 71—FEDERAL OPERATING 

PERMIT PROGRAMS 

■ 20. The authority citation for part 71 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

■ 21. Section 71.2 is amended: 

■ a. By adding in alphabetical order the 

definition of ‘‘Greenhouse gases,’’ 

■ b. By removing ‘‘or’’ from the end of 

paragraph (2), adding ‘‘or’’ to the end of 

paragraph (3), and adding paragraph (4) 

to the definition of ‘‘Regulated pollutant 

(for fee calculation),’’ and 

■ c. By revising paragraph (1) of the 

definition of ‘‘Subject to regulation.’’ 

The revisions and additions read as 

follows: 

§ 71.2 Definitions. 

* * * * * 

Greenhouse gases (GHGs) means the 

air pollutant defined in § 86.1818–12(a) 

of this chapter as the aggregate group of 

six greenhouse gases: carbon dioxide, 

nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, 

and sulfur hexafluoride. 

* * * * * 

Regulated pollutant (for fee 

calculation), which is used only for 

purposes of § 71.9(c), means any 

‘‘regulated air pollutant’’ except the 

following: 

* * * * * 

(4) Greenhouse gases. 

* * * * * 

Subject to regulation * * * 

(1) Greenhouse gases shall not be 

subject to regulation unless, as of July 1, 

2011, the GHG emissions are at a 

stationary source emitting or having the 

potential to emit 100,000 tpy CO2

equivalent emissions. 

* * * * * 

■ 22. Section 71.9 is amended by: 

■ a. Revising paragraphs (c)(1), (c)(2)(i), 

(c)(3), and (c)(4), and 

■ b. Adding paragraph (c)(8). 

The revisions and additions read as 

follows: 

§ 71.9 Permit fees. 

* * * * * 

(c) * * * 

(1) For part 71 programs that are 

administered by EPA, each part 71 

source shall pay an annual fee which is 

the sum of: 

(i) $32 per ton (as adjusted pursuant 

to the criteria set forth in paragraph 

(n)(1) of this section) times the total tons 

of the actual emissions of each regulated 

pollutant (for fee calculation) emitted 

from the source, including fugitive 

emissions; and 

(ii) Any GHG fee adjustment required 

under paragraph (c)(8) of this section. 

(2) * * * 

(i) Where the EPA has not suspended 

its part 71 fee collection pursuant to 

paragraph (c)(2)(ii) of this section, the 

annual fee for each part 71 source shall 

be the sum of: 

(A) $24 per ton (as adjusted pursuant 

to the criteria set forth in paragraph 

(n)(1) of this section) times the total tons 

of the actual emissions of each regulated 

pollutant (for fee calculation) emitted 

from the source, including fugitive 

emissions; and 

(B) Any GHG fee adjustment required 

under paragraph (c)(8) of this section. 

* * * * * 

(3) For part 71 programs that are 

administered by EPA with contractor 

assistance, the per ton fee shall vary 

depending on the extent of contractor 

involvement and the cost to EPA of 

contractor assistance. The EPA shall 

establish a per ton fee that is based on 

the contractor costs for the specific part 

71 program that is being administered, 

using the following formula: Cost per 

ton = (E × 32) + [(1¥ E) × $ C] 

Where E represents EPA’s proportion 

of total effort (expressed as a percentage 

of total effort) needed to administer the 

part 71 program, 1¥ E represents the 

contractor’s effort, and C represents the 

contractor assistance cost on a per ton 

basis. C shall be computed by using the 

following formula: C = [ B + T + N] 

divided by 12,300,000 

Where B represents the base cost 

(contractor costs), where T represents 

travel costs, and where N represents 

nonpersonnel data management and 

tracking costs. In addition, each part 71 

source shall pay a GHG fee adjustment 

for each activity as required under 

paragraph (c)(8) of this section. 

(4) For programs that are delegated in 

part, the fee shall be computed using the 

following formula: Cost per ton = (E × 

32) + (D × 24) + [(1¥ E ¥ D) × $ C] 

Where E and D represent, 

respectively, the EPA and delegate 

agency proportions of total effort 

(expressed as a percentage of total effort) 

needed to administer the part 71 

program, 1¥ E ¥ D represents the 

contractor’s effort, and C represents the 

contractor assistance cost on a per ton 

basis. C shall be computed using the 

formula for contractor assistance cost 

found in paragraph (c)(3) of this section 

and shall be zero if contractor assistance 

is not utilized. In addition, each part 71 

source shall pay a GHG fee adjustment 

for each activity as required under 

paragraph (c)(8) of this section. 

* * * * * 

(8) GHG fee adjustment. The annual 

fee shall be increased by a GHG fee 

adjustment for any source that has 

initiated an activity listed in the 

following table since the fee was last 

paid. The GHG fee adjustment shall be 

equal to the set fee provided in the table 

for each activity that has been initiated 

since the fee was last paid: 

Activity Set fee 

GHG completeness determination 

(for initial permit or updated application) ...................................... $2,236 

GHG evaluation for a permit modification or related permit action .. 364 

GHG evaluation at permit renewal 520 

* * * * * 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

■ 23. The authority citation for part 98 

is revised to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart PP—Suppliers of Carbon 

Dioxide 

■ 24. Section 98.426 is amended by 

adding paragraph (h) to read as follows: 

§ 98.426 Data reporting requirements. 

* * * * * 

(h) If you capture a CO2 stream from 

an electricity generating unit that is 

subject to subpart D of this part and 

transfer CO2 to any facilities that are 

subject to subpart RR of this part, you 

must: 

(1) Report the facility identification 

number associated with the annual GHG 

report for the facility that is subject to 

subpart D of this part, 

(2) Report each facility identification 

number associated with the annual GHG 

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Federal Register / Vol. 79, No. 5 / Wednesday, January 8, 2014 / Proposed Rules 1519 

reports for each facility that is subject to 

subpart RR of this part to which CO2 is 

transferred, and 

(3) Report the annual quantity of CO2

in metric tons that is transferred to each 

facility that is subject to subpart RR of 

this part. 

■ 25. Section 98.427 is amended by 

adding paragraph (d) to read as follows: 

§ 98.427 Records that must be retained. 

* * * * * 

(d) Facilities subject to § 98.426(h) 

must retain records of CO2 in metric 

tons that is transferred to each facility 

that is subject to subpart RR of this part. 

[FR Doc. 2013–28668 Filed 12–27–13; 8:45 am] 

BILLING CODE 6560–50–P 

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