22392 Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 

1Throughout this preamble, we refer to ‘carbon 

capture and storage’ or CCS. By this, we mean the 

use of a technology for separating and capturing 

CO2 from the flue gas or syngas stream with 

subsequent compression and transportation to a 

suitable location for long term storage and 

monitoring. Many references refer to CCS as ‘carbon 

capture and sequestration’. In this preamble, 

‘storage’ and ‘sequestration’ mean the same thing 

and the words are used interchangeably. 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2011–0660; FRL–9654–7] 

RIN 2060–AQ91 

Standards of Performance for 

Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The United States EPA is 

proposing new source performance 

standards for emissions of carbon 

dioxide (CO2) for new affected fossil 

fuel-fired electric utility generating 

units (EGUs). The EPA is proposing 

these requirements because CO2 is a 

greenhouse gas (GHG) and fossil fuelfired power plants are the country’s 

largest stationary source emitters of 

GHGs. The EPA in 2009 found that by 

causing or contributing to climate 

change, GHGs endanger both the public 

health and the public welfare of current 

and future generations. The proposed 

requirements, which are strictly limited 

to new sources, would require new 

fossil fuel-fired EGUs greater than 25 

megawatt electric (MWe) to meet an 

output-based standard of 1,000 pounds 

of CO2 per megawatt-hour (lb CO2/ 

MWh), based on the performance of 

widely used natural gas combined cycle 

(NGCC) technology. Because of the 

economics of the energy sector, the EPA 

and others project that NGCC will be the 

predominant choice for new fossil fuelfired generation even absent this rule. In 

its base case analysis, the EPA does not 

project any new coal-fired EGUs 

without CCS to be built in the absence 

of this proposal through 2030. New 

coal-fired or pet coke-fired units could 

meet the standard either by employing 

carbon capture and storage (CCS) 1 of 

approximately 50% of the CO2 in the 

exhaust gas at startup, or through later 

application of more effective CCS to 

meet the standard on average over a 30- 

year period. The 30-year averaging 

option could also provide flexibility for 

owners and operators of coal or pet coke 

units implementing CCS at the outset of 

the unit’s operation that were designed 

and operated to emit at less than 1,000 

lb CO2/MWh to address startup 

concerns or short term interruptions in 

their ability to sequester captured 

carbon dioxide. The EPA is not 

proposing standards of performance for 

existing EGUs whose CO2 emissions 

increase as a result of installation of 

pollution controls for conventional 

pollutants, or for proposed EGUs, which 

are referred to here as transitional 

sources, that have acquired a complete 

preconstruction permit by the time of 

this proposal and that commence 

construction within 12 months of this 

proposal. As a result, those sources 

would not be subject to the standards of 

performance proposed in today’s rule. 

DATES: Comments. Comments must be 

received on or before June 12, 2012. 

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 April 13, 2012, a comment to 

the OMB is best assured of having its 

full effect if the OMB receives it by May 

14, 2012. 

Public Hearing. The EPA will hold 

public hearings on this proposal. The 

dates, times, and locations of the public 

hearings will be announced separately. 

Oral testimony will be limited to 5 

minutes per commenter. The EPA 

encourages commenters to provide 

written versions of their oral testimonies 

either electronically or in paper copy. 

Verbatim transcripts and written 

statements will be included in the 

rulemaking docket. If you would like to 

present oral testimony at one of the 

hearings, please notify Ms. Pamela 

Garrett, Sectors Policies and Programs 

Division (C504–03), U.S. EPA, Research 

Triangle Park, NC 27711, telephone 

number (919) 541–7966; email: 

garrett.pamela@epa.gov. Persons 

wishing to provide testimony should 

notify Ms. Garrett at least 2 days in 

advance of the public hearings. The 

public hearings will provide interested 

parties the opportunity to present data, 

views, or arguments concerning the 

proposed rule. The EPA officials may 

ask clarifying questions during the oral 

presentations, but will not respond to 

the presentations or comments at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearing. For 

updates and additional information on 

the public hearings, please check the 

EPA’s Web site for this rulemaking, 

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

carbonpollutionstandards. 

ADDRESSES: Comments. Submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2011–0660, by one of 

the following methods: 

At the 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–2011–0660. 

Facsimile: Fax your comments to 

(202) 566–9744, Attn: Docket ID No. 

EPA–HQ–OAR–2011–0660. 

Mail: Send your comments to the EPA 

Docket Center, U.S. EPA, Mail Code 

2822T, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460, Attn: Docket ID 

No. EPA–HQ–OAR–2011–0660. Please 

include a total of two copies. In 

addition, please mail a copy of your 

comments on the information collection 

provisions to the Office of Information 

and Regulatory Affairs, OMB, Attn: Desk 

Officer for EPA, 725 17th St. NW., 

Washington, DC 20503. 

Hand Delivery or Courier: Deliver 

your comments to the EPA Docket 

Center, EPA West, Room 3334, 1301 

Constitution Ave., NW., Room 3334, 

Washington, DC, 20460, Attn: Docket ID 

No. EPA–HQ–OAR–2011–0660. Such 

deliveries are accepted only during the 

Docket’s normal hours of operation 

(8:30 a.m. to 4:20 p.m., Monday through 

Friday, excluding legal holidays), and 

special arrangements should be made 

for deliveries of boxed information. 

Instructions: All submissions must 

include agency name and docket ID 

number (EPA–HQ–OAR–2011–0660). 

The EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or 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– 


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Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 22393 

HQ–OAR–2011–0660. Clearly mark the 

part or all of the information that you 

claim to be CBI. For CBI information in 

a disk or CD–ROM that you mail to the 

EPA, mark the outside of the disk or 

CD–ROM as CBI and then identify 

electronically within the disk or CD– 

ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

The EPA requests that a separate copy 

of your comments also be sent to the 

contact person identified below (see FOR

FURTHER INFORMATION CONTACT). If the 

comment includes information you 

consider to be CBI or otherwise 

protected, a copy of the comment that 

does not contain the information 

claimed as CBI or otherwise protected 

should be sent. 

The www.regulations.gov 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, EPA West, 

Room 3334, 1301 Constitution Ave. 

NW., Washington, DC. The Public 

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

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. Visit the EPA Docket Center 

homepage at http://www.epa.gov/ 

epahome/dockets.htm for additional 

information about the EPA’s public 

docket. 

In addition to being available in the 

docket, an electronic copy of this 

proposed rule will also be available on 

the Worldwide Web (WWW) through 

the Technology Transfer Network 

(TTN). Following signature, a copy of 

the proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Christian Fellner, Energy Strategies 

Group, Sector Policies and Programs 

Division (D243–01), U.S. EPA, Research 

Triangle Park, NC 27711; telephone 

number (919) 541–4003, facsimile 

number (919) 541–5450; email address: 

fellner.christian@epa.gov or Dr. Nick 

Hutson, Energy Strategies Group, Sector 

Policies and Programs Division (D243– 

01), U.S. EPA, Research Triangle Park, 

NC 27711; telephone number (919) 541– 

2968, facsimile number (919) 541–5450; 

email address: hutson.nick@epa.gov. 

SUPPLEMENTARY INFORMATION: Acronyms. 

A number of acronyms and chemical 

symbols are used in this preamble. 

While this may not be an exhaustive 

list, to ease the reading of this preamble 

and for reference purposes, the 

following terms and acronyms are 

defined as follows: 

AB Assembly Bill 

AEP American Electric Power 

AEO Annual Energy Outlook 

ANSI American National Standards 

Institute 

ASME American Society of Mechanical 

Engineers 

ASTM American Society for Testing of 

Materials 

BACT Best Available Control Technology 

BDT Best Demonstrated Technology 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per 

Kilowatt Hour 

Btu/lb British Thermal Units per Pound 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or 

Sequestration) 

CDX Central Data Exchange 

CEDRI Compliance and Emissions Data 

Reporting 

CEMS Continuous Emissions Monitoring 

System 

CH4 Methane 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

CSAPR Cross-State Air Pollution Rule 

DOE Department of Energy 

DOT Department of Transportation 

ECMPS Emissions Collection and 

Monitoring Plan System 

EERS Energy Efficiency Resource Standards 

EGU Electric Utility Generating Units 

EIA Energy Information Administration 

EO Executive Order 

EOR Enhanced Oil Recovery 

EPA Environmental Protection Agency 

FR Federal Register 

GHG Greenhouse Gas 

H2 Hydrogen Gas 

HAP Hazardous Air Pollutant 

HFC Hydrofluorocarbon 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined 

Cycle 

IPCC Intergovernmental Panel on Climate 

Change 

IPM Integrated Planning Model 

kg/MWh Kilogram per Megawatt-hour 

kJ/kg Kilojoules per Kilogram 

kWh Kilowatt Hour 

lb CO2/MMBtu Pound of CO2 per Million 

British Thermal Unit 

lb CO2/MWh Pound of CO2 per Megawatthour 

lb CO2/yr Pound of CO2 per Year 

lb/lb-mole Pound per Pound-Mole 

MATS Mercury and Air Toxic Standards 

MW Megawatt 

MWe Megawatt Electric 

MWh Megawatt-hour 

N2O Nitrous Oxide 

NAAQS National Ambient Air Quality 

Standards 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NETL National Energy Technology 

Laboratory 

NGCC Natural Gas Combined Cycle 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

O2 Oxygen Gas 

OMB Office of Management and Budget 

PC Pulverized Coal 

PFC Perfluorocarbon 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSD Prevention of Significant Deterioration 

RCRA Resource Conservation and Recovery 

Act 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

SBA Small Business Administration 

SCC Social Cost of Carbon 

SCR Selective Catalytic Reduction 

SF6 Sulfur Hexafluoride 

SIP State Implementation Plan 

SNCR Selective Non-Catalytic Reduction 


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SO2 Sulfur Dioxide 

SSM Startup, Shutdown, and Malfunction 

Tg Teragram 

Tpy Tons per Year 

TSD Technical Support Document 

TTN Technology Transfer Network 

UIC Underground Injection Control 

UMRA Unfunded Mandates Reform Act of 

1995 

U.S. United States 

USGCRP U.S. Global Climate Research 

Program 

VCS Voluntary Consensus Standard 

WWW Worldwide Web 

Organization of This Document. The 

information presented in this preamble 

is organized as follows: 

I. General Information 

A. Executive Summary 

B. Does this action apply to me? 

II. Background 

A. Statutory Background for This Rule 

B. Overview of Climate Change Impacts 

From GHG Emissions 

C. GHGs From Fossil Fuel-Fired EGUs 

D. Litigation Directly Leading to This Rule 

E. Coordination With Other Rulemakings 

III. Summary of the Proposed Requirements 

for New Sources 

A. What is the affected source? 

B. What emissions limitations must I meet? 

C. What are the startup, shutdown, and 

malfunction requirements? 

D. What are the continuous monitoring 

requirements? 

E. What are the emissions performance 

testing requirements? 

F. What are the continuous compliance 

requirements? 

G. What are the notification, 

recordkeeping, and reporting 

requirements? 

IV. Rationale for the Proposed Standards: 

New Sources 

A. How did the EPA establish the emission 

limits? 

B. How did the EPA determine the other 

requirements for the proposed 

standards? 

V. Implications for PSD and Title V Programs 

A. Overview 

B. Implications for PSD Program 

C. Implications for Title V Program 

VI. Discussion of Modified Sources 

A. CAA Section 111 Requirements 

B. Timing for Promulgation of Standards of 

Performance for Modifications 

VII. Impacts of the Proposed Action 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. How will this proposal contribute to 

climate change protection? 

E. What are the economic and employment 

impacts? 

F. What are the benefits of the proposed 

standards? 

VIII. Request for Comments 

IX. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review, and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act as Amended 

by the Small Business Regulatory 

Enforcement Fairness Act of 1996, 

5 U.S.C. 601 et seq. 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Summary 

1. Executive Summary 

In this rulemaking, the EPA proposes 

to limit GHG emissions from new fossil 

fuel-fired power plants by limiting CO2

emissions. The proposed rule is 

undertaken pursuant to section 111 of 

the Clean Air Act, which establishes a 

several step process for the EPA and the 

States to regulate air pollutants from 

stationary sources. Under section 111, 

the EPA must regulate emissions from 

new sources in the source category by 

issuing a standard of performance, 

which is defined as ‘‘a standard for 

emissions of air pollutants which 

reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account * * * cost [and other factors]) 

* * * has been adequately 

demonstrated.’’ 

In today’s action, the EPA is 

proposing to combine electric utility 

steam generating units (boilers and 

IGCC units, which are currently 

included in the Da category) and 

combined cycle units that generate 

electricity for sale and meet certain size 

criteria (which are currently included in 

the KKKK category), into a new category 

for new sources (the TTTT category) for 

the purposes of GHG emissions. The 

EPA is proposing standards of 

performance that require that all new 

fossil fuel-fired EGUs meet an 

electricity-output-based emission rate of 

1,000 lb CO2/MWh of electricity 

generated on a gross basis. This 

proposed standard is based on the 

demonstrated performance of natural 

gas combined cycle (NGCC) units, 

which are currently in wide use 

throughout the country, and are likely to 

be the predominant fossil fuel-fired 

technology for new generation in the 

future. 

New coal-, coal refuse-, oil- and 

petroleum coke-fired boilers and IGCC 

units should also be able to meet this 

standard by employing carbon capture 

and storage (CCS) technology. While a 

coal unit with CCS may be more 

expensive to construct than NGCC 

generation, for reasons explained below, 

we expect the difference to decrease 

over time as CCS becomes more mature 

and less expensive. 

We include in today’s proposed 

rulemaking a 30-year averaging 

compliance option under which affected 

coal- and pet coke-fired sources could 

comply with the 1,000 lb CO2/MWh 

standard on a 30-year average basis. 

Coal- and pet coke-fired EGUs that use 

this compliance alternative must meet 

an immediate performance standard of 

1,800 lb CO2/MWh (gross) on a 12- 

month annual average basis, which can 

be achieved by a ‘‘supercritical’’ 

efficiency level, during the period 

before installation of CCS. By no later 

than the beginning of the 11th year, the 

facility would be required to meet a 

reduced CO2 emission limit of no more 

than 600 lb CO2/MWh (gross) on a 12- 

month annual average basis for the 

remaining 20 years of the 30-year 

period, such that the weighted average 

CO2 emissions rate from the facility over 

the 30-year time period would be 

equivalent to the proposed standard of 

performance of 1,000 lb CO2/MWh. 

Today’s proposal to require an 

emission rate of 1,000 lb CO2/MWh 

meets the requirements for a ‘‘standard 

of performance,’’ as defined under CAA 

section 111(a)(1). This proposed 

standard is based on the degree of 

emission limitation achievable through 

natural gas combined cycle generation. 

NGCC qualifies as the ‘‘best system of 

emission reduction’’ (BSER) that the 

EPA has determined has been 

adequately demonstrated. New natural 

gas-fired EGUs are less costly than new 

coal-fired EGUs, and as a result, our 

Integrated Planning Model (IPM) model 

projects that for economic reasons, 

natural gas-fired EGUs will be the 

facilities of choice until at least 2020, 

which is the analysis period for this 

rulemaking. 

Indeed, our IPM model does not 

project construction of any new coalfired EGUs during that period. This state 

of affairs has come about primarily 

because technological developments 

and discoveries of abundant natural gas 

reserves have caused natural gas prices 

to decline precipitously in recent years 

and have secured those relatively low 

prices for the near-future. We emphasize 

that, in light of a number of economic 

factors, including the increased 

availability and significantly lower price 


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2Or 32.4% of all anthropogenic GHG emissions; 

from information in Table 2–1 from ‘Inventory of 

U.S. Greenhouse Gas Emissions and Sinks: 1990– 

2009,’ U.S. Environmental Protection Agency, EPA 

430–R–11–005, April 2011. 3The National Academies comprise the National 

Academy of Sciences, National Academy of 

Engineering, Institute of Medicine and National 

Research Council. 4National Research Council (2011) America’s 

Climate Choices, Committee on America’s Climate 

Choices, Board on Atmospheric Sciences and 

Climate, Division on Earth and Life Studies, The 

National Academies Press, Washington, DC. 5EPA, ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases under Section 

202(a) of the Clean Air Act’’ (74 FR 66,496; Dec. 15, 

2009). http://epa.gov/climatechange/ 

endangerment.html. 6Endangerment Finding at 74 FR 66,518, which 

notes that the 2007 conclusion of the 

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

Global Change Research Program. 

7EPA, ‘‘Technical Support Document for 

Endangerment and Cause or Contribute Findings for 

Continued 

of natural gas, energy industry modeling 

forecasts uniformly predict that few, if 

any, new coal-fired power plants will be 

built in the foreseeable future. 

We recognize that some owners/ 

operators may nevertheless seek to 

construct new coal-fired capacity. This 

may be beneficial from the standpoint of 

promoting energy diversity, and today’s 

proposal does not interfere with 

construction of new coal-fired capacity. 

At present, while CCS would add 

considerably to the costs of a new coalfired power plant, there are sources of 

funding available to support the 

deployment of CCS, including a limited 

number of government demonstration 

programs. Even if companies decide to 

construct a few new coal-fired power 

plants under any circumstance, those 

few may well have access to those 

government programs. We expect that 

the costs of CCS will decline in the 

future as CCS matures and is utilized 

more widely. 

For purposes of today’s action, the 

EPA does not have a sufficient base of 

information to develop a proposal for 

the anticipated relatively few affected 

sources that may be expected to take 

actions that would constitute 

‘‘modifications’’ (as defined under the 

EPA’s NSPS regulations) and therefore 

be subject to requirements for new 

sources. As a result, the EPA is not 

proposing requirements for NSPS 

modifications. 

The EPA is aware that approximately 

15 proposed EGUs have received CAA 

permitting authority approval for their 

preconstruction permits, but may not 

have ‘‘commenced construction’’ by the 

date of today’s proposed rulemaking. 

For this proposed rule, these sources 

that, as of the date of this proposal, have 

a PSD permit and are poised to 

commence construction within the very 

near future are referred to as 

‘‘transitional sources.’’ In today’s 

proposed rulemaking, the EPA is not 

proposing a standard of performance for 

transitional sources, which we define as 

sources that have been issued a PSD 

permit by the date of proposal 

(including sources that have approved 

permits that are in the process of being 

amended, if those sources are intending 

to install CCS as evidenced by 

participating in any of the DOE CCS 

funding programs, either loan guarantee 

or grant programs) and that commence 

construction within 12 months of the 

date of publication of this proposal in 

the Federal Register. Upon finalization 

of this rulemaking without a standard of 

performance applicable to these sources, 

they will not be treated as new sources 

subject to the specific limitations set 

forth in the final new source standards. 

Our IPM modeling, using Energy 

Information Administration (EIA) 

reference case assumptions, projects 

that there will be no construction of 

new coal-fired generation without CCS 

by 2030. Under these assumptions, the 

proposed rule will not impose costs by 

2030. We also examined a scenario with 

both increased future natural gas prices 

and increased future electric demand. In 

this sensitivity case, we saw small 

amounts of coal-fired generation being 

built in 2030. Even under this 

sensitivity analysis with small amounts 

of new coal generation under conditions 

of high natural gas prices and 

simultaneously high electricity demand 

in 2030, we do not project that this 

proposed rule will impose notable costs 

upon sources. 

We seek comments on all aspects of 

this proposal and identify a number of 

aspects of the proposal on which 

comments are specifically requested. 

B. Overview and Outline 

1. Overview 

In this rulemaking, the EPA proposes 

to limit GHG emissions from new fossil 

fuel-fired power plants by limiting CO2

emissions. In 2009, the EPA issued a 

finding that GHG air pollution may 

reasonably be anticipated to endanger 

Americans’ public health and welfare, 

now and in the future, by contributing 

to climate change. Fossil fuel-fired 

power plants emit more GHG emissions 

than any other stationary source 

category in the United States, and 

among new GHG emissions sources, the 

largest individual sources are in this 

source category. This rulemaking 

proposes federal standards of 

performance for new fossil fuel-fired 

power plants that can be met with 

existing technology. 

Note that in this preamble, while we 

refer to these sources, interchangeably, 

as power plants, steam generating units, 

affected sources, fossil fuel-fired electric 

generating units, covered EGUs, or, 

simply, EGUs, the proposed standards 

apply to only those sources identified in 

Section III.A. as the affected source 

category. 

2. Why is the EPA proposing this rule? 

This proposed rule reflects the EPA’s 

common-sense approach to reducing 

CO2 and other GHG emissions, which by 

causing climate change, pose a serious 

threat to public health and welfare. The 

EPA is focusing first on reducing 

emissions from the largest emitters 

through measures with reasonable costs. 

The EPA is proposing to control CO2

pollution from fossil fuel-fired power 

plants because they are responsible for 

approximately 40 percent of all U.S. 

anthropogenic CO2 emissions.2

Individual new coal-fired power plants 

are among the largest individual new 

sources of GHGs. Furthermore, design 

and technology choices, such as NGCC, 

exist that can be readily and costeffectively used to reduce GHG 

emissions from new fossil fuel-fired 

power plants. Thus, this proposed rule 

is a rational first step to control GHG 

emissions from the largest-emitting 

stationary sources under CAA section 

111. 

a. The Serious Threat of Climate 

Change to the Public’s Health and 

Welfare. Climate change, including 

global warming, is a significant threat to 

the global environment. The National 

Research Council (NRC) of the National 

Academies 3 stated in a 2011 report, 

‘‘Each additional ton of greenhouse 

gases emitted commits us to further 

change and greater risks. In the 

judgment of the [NRC] Committee on 

America’s Climate Choices, the 

environmental, economic, and 

humanitarian risks of climate change 

indicate a pressing need for substantial 

action to limit the magnitude of climate 

change and to prepare to adapt to its 

impacts.’’ 4

Action to reduce emissions is 

warranted because, as the EPA stated in 

its 2009 Endangerment Finding,5 GHGs 

endanger the public health and public 

welfare of current and future 

generations. The anthropogenic buildup 

of GHGs in the atmosphere is very likely 

(90 to 99 percent probability) the cause 

of most of the observed global warming 

over the last 50 years.6 Based on the 

Endangerment Finding and its 

underlying technical support document 

(TSD),7 reasons to reduce GHG 

emissions include the following: 


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22396 Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 

Greenhouse Gases under Section 202(a) of the Clean 

Air Act, Dec. 9, 2009.’’ Both the Federal Register 

Notice and the TSD for Endangerment and Cause 

or Contribute Findings are found in the public 

docket established for the endangerment 

rulemaking, Docket No. EPA–OAR–2009–0171 and 

at http://epa.gov/climatechange/ 

endangerment.html. 

8Endangerment Finding, 74 FR 66498. 

9Endangerment Finding, 74 66497. 

10Endangerment Finding, 74 FR 66535. 

11Endangerment TSD, p. 136. 

12Endangerment TSD, p. 75–78. The U.S. Climate 

Change Science Program defined ‘‘abrupt change’’ 

as a ‘‘large-scale change in the climate system that 

takes place over a few decades or less, persists (or 

is anticipated to persist) for at least a few decades, 

and causes substantial disruptions in human and 

natural systems.’’ Synthesis and Assessment 

Product (SAP) 3.4: Abrupt Climate Change (2008). 

13Endangerment TSD, p. 75, citing National 

Research Council (2002). 

14Endangerment TSD, pp. 76–78. 

15National Research Council (NRC) (2011). 

Climate Stabilization Targets. Committee on 

Stabilization Targets for Atmospheric Greenhouse 

Gas Concentrations; Board on Atmospheric 

Sciences and Climate, Division of Earth and Life 

Sciences, National Academy Press. Washington, 

DC. 

16Or 32.4% of all anthropogenic GHG emissions; 

from information in Table 2–1 from ‘Inventory of 

U. S. Greenhouse Gas Emissions and Sinks: 1990— 

2009’, U. S. Environmental Protection Agency, EPA 

430–R–11–005, April 2011. 

17 ‘‘Blueprint for a Secure Energy Future’’, March 

30, 2011. 

• The key effects of climate change 

observed to date and projected to occur 

in the future include, but are not limited 

to, more frequent and intense heat 

waves, more severe wildfires, degraded 

air quality, heavier and more frequent 

downpours and flooding, increased 

drought, greater sea level rise and storm 

surge, more intense storms, harm to 

water resources, continued ocean 

acidification, harm to agriculture, and 

harm to wildlife and ecosystems. 

• These effects are anticipated to 

result in premature deaths, illnesses, 

damage to property and infrastructure, 

and other harm to people’s welfare in 

the U.S. 

• Those ‘‘most vulnerable’’ to climate 

related health effects, such as children, 

the elderly and the poor—and future 

generations—face disproportionate 

risks.8

• Human-induced climate change 

impacts have the potential to be farreaching and multidimensional, though 

not all risks and potential impacts can 

be quantified.9

• A supporting consideration is that 

climate change impacts in certain 

regions of the world (potentially 

leading, for example, to food scarcity, 

conflicts or mass migration) may 

exacerbate problems that raise 

humanitarian, trade and national 

security issues for the United States.10

The TSD further notes that some risks, 

such as the extinction of many species, 

would be irreversible.11 Also, the TSD 

points to research on the potential for 

‘‘abrupt changes’’ 12 which have 

uncertain or low probability but high 

potential impact. The NRC has said 

abrupt changes are an important 

consideration because, if triggered, they 

could occur so quickly and 

unexpectedly that human or natural 

systems would have difficulty adapting 

to them.13 Examples include severe 

drought in subtropical areas, release of 

large amounts of GHGs stored in the sea 

floor and frozen Arctic soils, and rapid 

disintegration of Greenland ice sheet or 

collapse of the West Antarctic ice sheet 

leading to many feet of sea level rise.14

The special characteristics of GHGs 

make it important to take initial steps to 

control the largest emissions categories 

without delay. Unlike most traditional 

air pollutants, GHGs persist in the 

atmosphere for time periods ranging 

from decades to millennia, depending 

on the greenhouse gas. Greenhouse 

gases will continue to accumulate in the 

atmosphere at higher and higher 

concentrations each year unless 

substantial reductions in global 

greenhouse gas emissions are achieved. 

The NRC notes that emissions reduction 

choices made today matter in 

determining the level of impacts 

experienced not just over the next few 

decades, but in the coming centuries 

and millennia.15 Also, the longer that 

the U.S. and other countries take to 

reduce emissions, the greater the future 

emissions reductions that will be 

required to limit global temperature 

increase to any given level. 

This proposed rule to limit GHG 

emissions from the largest U.S. 

stationary source category will 

contribute to the emissions reductions 

required to slow or reverse the 

accumulation of GHG concentrations in 

the atmosphere, which is necessary to 

protect against projected climate change 

impacts and risks. Reducing GHG 

emissions reduces the impacts and risks 

articulated in the Endangerment 

Finding and TSD. 

b. The High Level of GHG Emissions 

from Fossil-Fuel-Fired Power Plants and 

the Opportunities to Reduce these 

Emissions. Fossil fuel-fired power 

plants comprise the largest category of 

stationary source GHG emissions in the 

U.S. These sources account for 

approximately 40 percent of total U.S. 

anthropogenic CO2 emissions, based on 

2009 data.16 Among all stationary 

sources of GHG emissions, fossil-fuelfired power plants generally constitute 

the largest individual sources. 

Furthermore, a range of options are 

available to reduce emissions of new 

power plants. For economic reasons, 

most new power plants being built in 

the U.S. today are either natural gasfired or are powered by renewable 

sources of energy, such as wind and 

solar, and therefore generally produce 

significantly fewer CO2 emissions than 

uncontrolled coal-fired power plants. 

Natural gas combustion inherently emits 

less CO2 than coal combustion and the 

technology of choice for generating 

electricity with natural gas, stationary 

combined cycle gas turbines, is also 

more efficient. Almost all the stationary 

combined cycle gas turbines built in the 

U.S. in the last five years can meet the 

proposed standard of 1,000 lb CO2/ 

MWh. New coal-fired power plants can 

install CCS technology and can thereby 

limit their CO2 emissions per MWh 

generated to levels similar to, or even 

lower than, those of natural gas-fired 

combined cycle plants without CCS. 

New coal-fired power plants with CCS 

are being permitted and built today, 

albeit usually with considerable 

financial assistance from the federal 

government. 

c. Alignment with Industry’s Other 

CAA Obligations. Establishing the 

overall regulatory requirements for GHG 

emissions from new fossil fuel-fired 

power plants at this time is efficient 

because the EPA has recently issued 

regulations to limit criteria and 

hazardous air pollutants from these 

sources. Aligning the timing of these 

GHG rules with the rules for criteria and 

air toxics pollutants gives the industry 

more regulatory certainty, will facilitate 

the industry’s investment decisions, and 

will help inform its compliance 

decisions to meet all of its CAA 

obligations. 

d. Promotion of Energy Diversity. This 

proposed rule is consistent with the 

President’s goal to ensure that ‘‘by 2035 

we will generate 80% of our electricity 

from a diverse set of clean energy 

sources—including renewable energy 

sources like wind, solar, biomass and 

hydropower, nuclear power, efficient 

natural gas and clean coal.’’ 17 The 

proposed rule will assist the 

deployment of CCS technology for new 

coal-fired power plants and reinforce 

incentives for the use of efficient natural 

gas-fired generation. Regulatory 

uncertainty may be hindering the 

development and deployment of CCS, as 

evidenced by American Electric Power 

(AEP)’s recent deferral of a large-scale 

CCS retrofit demonstration project on 

one of its coal-fired power plants 

because the State’s utility regulators 

would not approve CCS without a 


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18 In a July 17, 2011, press release, AEP’s 

chairman said, ‘‘We are placing the project on hold 

until economic and policy conditions create a 

viable path forward * * * We are clearly in a 

classic ‘which comes first?’ situation. The 

commercialization of this technology is vital if 

owners of coal-fueled generation are to comply with 

potential future climate regulations without 

prematurely retiring efficient, cost-effective 

generating capacity. But as a regulated utility, it is 

impossible to gain regulatory approval to recover 

our share of the costs for validating and deploying 

the technology without federal requirements to 

reduce greenhouse gas emissions already in place. 

The uncertainty also makes it difficult to attract 

partners to help fund the industry’s share.’’ 

19 549 U.S. 497 (2007). 

20These recent scientific findings are described in 

section II of this notice, titled ‘‘Background.’’ See 

subsection II.B.3., ‘‘Climate Impacts Detailed in 

Recent NRC Assessments.’’ The legal options 

introduced here are presented in detail below in 

section IV.A.2, ‘‘Endangerment and Cause-orContribute-Significantly Finding.’’ 

regulatory requirement to reduce CO2.18

The standard established in this 

proposal would help create the 

regulatory certainty that CCS is the path 

forward for new coal-fired generation. 

3. Legal Proceedings Leading up to This 

Rulemaking 

In April 2007, the U.S. Supreme Court 

ruled, in Massachusetts v. EPA,19 that 

GHGs meet the definition of ‘‘air 

pollutant’’ in the CAA. This decision 

clarified that the authorities and 

requirements of the CAA, including 

section 111, apply to GHG emissions. 

As a result of this decision, the EPA 

obtained a voluntary remand from the 

U.S. Court of Appeals for the District of 

Columbia Circuit (the ‘‘Court’’) to 

reconsider the EPA’s actions in a 2006 

rulemaking for EGUs under CAA section 

111, in which the EPA had promulgated 

standards for criteria air pollutants, but 

had declined to regulate GHG 

emissions. In part in response to 

threatened litigation over the EPA’s 

failure to act on the remand, the EPA 

agreed to propose today’s action to 

regulate GHG emissions from new fossil 

fuel-fired EGUs. 

4. Legal Basis for CAA Standards for 

Fossil-Fired Power Plants 

a. General Legal Requirements. Clean 

Air Act section 111 establishes a several 

step process for the EPA and the States 

to regulate air pollutants from stationary 

sources. First, the EPA must list 

categories of stationary sources that 

cause or contribute significantly to air 

pollution that may reasonably be 

anticipated to endanger public health or 

welfare. Then, the EPA must regulate 

emissions from new sources in the 

source category by issuing a standard of 

performance, which is defined as ‘‘a 

standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account * * * cost [and other factors]) 

* * * has been adequately 

demonstrated.’’ New sources include 

new construction, and, as discussed 

below, modifications to existing sources 

as well as reconstructed sources. 

Standards of performance for new 

sources are often referred to as new 

source performance standards (NSPS). 

b. Cause-or-Contribute-Significantly 

Finding for Fossil Fuel-Fired Power 

Plants and Endangerment Finding for 

GHG Air Pollution. The EPA is 

authorized to regulate GHGs from power 

plants based on earlier actions 

concerning endangerment. Before 

today’s rulemaking, the EPA listed 

different types of fossil fuel-fired EGUs 

as source categories that caused or 

contributed significantly to air pollution 

that may reasonably be anticipated to 

endanger public health or welfare. 

Specifically, the EPA listed electric 

utility steam generating boilers, 

including coal-fired boilers, and 

initially regulated them in subpart D of 

its regulations under CAA section 111. 

Subsequent regulation of utility boilers 

has been under subpart Da. The EPA 

listed stationary combustion turbine 

engines and initially regulated them 

under subpart GG. The stationary 

combustion turbine engine portions of 

combined cycle facilities were also 

regulated under subpart GG. Heat 

recovery steam generators (HRSG) 

associated with combined cycle 

facilities with duct burners were 

regulated under either subpart Da or one 

of the industrial boiler regulations, 

depending on the specific 

characteristics of the HRSG. To 

minimize the compliance burden for 

owners/operators of combined cycle 

facilities some monitoring 

harmonization was done, but the two 

subparts were still applicable. In 2005, 

the EPA proposed subpart KKKK as a 

replacement for subpart GG and 

specifically covered the entire combined 

cycle facility under subpart KKKK such 

that only a single set of requirements 

would apply. In that same year, the EPA 

proposed to include Integrated 

Gasification Combined Cycle (IGCC) 

facilities under the applicability of 

subpart Da. The EPA is authorized to 

promulgate the rulemaking proposed 

today—which would establish 

standards of performance for CO2

emissions from EGUs currently in the 

Da and KKKK source categories— 

because the EPA has already determined 

that both those source categories cause 

or contribute significantly to air 

pollution that may reasonably be 

expected to endanger public health or 

welfare. Clean Air Act section 111 does 

not require the EPA, as a prerequisite to 

regulating any particular air pollutant, 

to issue an endangerment finding or a 

cause-or-contribute-significantly finding 

for that air pollutant from that source 

category. 

As an alternative, the EPA is 

considering whether CAA section 111 

should be interpreted to require that the 

EPA base its regulation of CO2

emissions from EGUs on two findings: 

(i) A finding that GHG air pollution may 

reasonably be anticipated to endanger 

public health or welfare; and (ii) a 

finding that CO2 emissions from EGUs 

cause or contribute significantly to that 

air pollution. If section 111 were so 

interpreted, the EPA believes that (a) the 

2009 Endangerment Finding, along with 

the EPA’s 2010 action denying petitions 

to reconsider that finding (which action 

reviewed scientific developments after 

the Endangerment Finding) would 

fulfill any requirement to make the 

endangerment finding concerning GHG 

air pollution; and (b) the large amount 

of CO2 emissions from EGUs clearly 

exceeds the low applicability threshold 

upon which the EPA would make the 

cause-or-contribute-significantly 

finding. 

As another alternative, the EPA is also 

considering whether CAA section 111 

should be interpreted to require that the 

EPA base its regulation of CO2

emissions from EGUs on a rational basis 

for protection of the public health or 

welfare. If section 111 were so 

interpreted, the EPA believes that (i) its 

2009 Endangerment Finding and 2010 

denial of petitions to reconsider, by 

themselves, and particularly in 

conjunction with the National Academy 

of Sciences’ assessment reports issued 

since then, coupled with (ii) the fact 

that EGUs are the largest stationary 

source emitters of CO2, provide a 

rational basis for regulating CO2

emissions from EGUs. There is no 

reason to revisit the 2009 Endangerment 

Finding given recent scientific findings 

that strengthen the scientific conclusion 

that GHG air pollution endangers public 

health and welfare.20

5. Summary of Today’s Proposed 

Requirements To Reduce GHG 

Emissions From New Fossil Fired Power 

Plants, and Rationale for Those 

Requirements 

a. Summary of Proposed Revisions to 

Categories and Requirements for New 

Sources 

i. Revisions to Categories of EGUs. In 

today’s action, the EPA is proposing to 


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

and KKKK categories for conventional pollutants 

and does not affect the KKKK category for simple 

cycle turbines. 

combine electric utility steam 

generating units (boilers and IGCC units, 

which are currently included in the Da 

category) and combined cycle units that 

generate electricity for sale and meet 

certain size criteria (which are currently 

included in the KKKK category), into a 

new category for new sources (the TTTT 

category) for the purposes of GHG 

emissions. Today’s proposed 

rulemaking would not affect NSPS 

requirements for criteria air pollutants, 

simple cycle turbines or EGUs located 

in non-continental areas.21 It also would 

not affect biomass-fired boilers 

(including those that sell electricity to 

the grid) that co-fire with less than 250 

MMBtu/h of any fossil fuel (biomass 

boilers currently subject to subpart Db, 

the Industrial-Commercial-Institutional 

Steam Generating Unit NSPS). 

ii. Control Requirements for New 

Sources. The EPA is proposing 

standards of performance that require 

that all new fossil fuel-fired EGUs meet 

an electricity-output-based emission 

rate of 1,000 lb CO2/MWh of electricity 

generated on a gross basis. This 

proposed standard is based on the 

demonstrated performance of natural 

gas combined cycle (NGCC) units, 

which are currently in wide use 

throughout the country, and are likely to 

be the predominant fossil fuel-fired 

technology for new generation in the 

future. 

New coal-, coal refuse-, oil- and 

petroleum coke-fired boilers and IGCC 

units should also be able to meet this 

standard by employing CCS technology. 

There are currently a number of coaland pet coke-fired EGU projects under 

development that include CCS. While a 

coal unit with CCS may be more 

expensive to construct than NGCC 

generation, for reasons explained below, 

we expect the difference to decrease 

over time as CCS becomes more mature 

and less expensive. 

We include in today’s proposed 

rulemaking a 30-year averaging 

compliance option under which affected 

coal- and pet coke-fired sources could 

comply with the 1,000 lb CO2/MWh 

standard on a 30-year average basis. 

Coal- and pet coke-fired EGUs that use 

this compliance alternative must meet 

an immediate performance standard of 

1,800 lb CO2/MWh (gross) on a 12- 

month annual average basis, which can 

be achieved by a ‘‘supercritical’’ 

efficiency level, during the period 

before installation of CCS. By no later 

than the beginning of the 11th year, the 

facility would be required to meet a 

reduced CO2 emission limit of no more 

than 600 lb CO2/MWh (gross) on a 12- 

month annual average basis for the 

remaining 20 years of the 30-year 

period, such that the weighted average 

CO2 emissions rate from the facility over 

the 30-year time period would be 

equivalent to the proposed standard of 

performance of 1,000 lb CO2/MWh. 

We seek comment on this compliance 

option and on reasonable variations on 

the framework we propose to establish, 

and in particular on a mechanism for 

establishing practicably enforceable 

short term limits during the 30-year 

period. The potential approaches here 

include (1) requiring the owner/operator 

to identify and obtain approval of, at the 

time of construction, an alternative 30- 

year emission trajectory to the 10- and 

20-year limits described immediately 

above; and (2) specifying the emission 

rate for each year during the 30-year 

period consistent with meeting a 30- 

year average emission rate of 1,000 lb 

CO2/MWh. Such an option would 

provide coal-fired sources that intend to 

use a reduction technology, such as 

CCS, significant flexibility in how that 

reduction technology is implemented. 

They could install the technology as 

part of the original project but use some 

or all of the initial ten year period to 

optimize the system. Such flexibility 

could be particularly useful to early 

adopters (i.e., ‘‘first movers’’) of the 

technology. Alternatively, they could 

delay installation of the technology for 

a period of up to ten years to take 

advantage of advancements in the 

technology that could reduce costs and 

enhance performance. Under CAA 

section 111(b)(1)(B), the EPA is required 

to conduct a review of the new source 

standards in eight years and we intend 

at that time to review the availability 

and cost of CCS. As proposed, this 30- 

year averaging compliance option is 

available only to new coal- and pet 

coke-fired EGUs. We do not believe that 

it is necessary for NGCC units, as they 

should be able to meet the proposed 

performance with no need for add-on 

technology. We also solicit comment on 

the need to extend the applicability for 

the 30-year averaging compliance option 

to other fossil fuels beyond just coal and 

pet coke. 

b. Rationale. Today’s proposal to 

combine the relevant parts of the Da and 

KKKK categories is authorized under 

CAA section 111(b)(1)(A) because that 

provision authorizes the EPA, after 

drawing up the list of affected source 

categories, to ‘‘revise’’ that list from time 

to time. Combining the relevant parts of 

the categories, as the EPA proposes to 

do, is one method to ‘‘revise’’ the list. 

Moreover, the EPA’s action to combine 

the relevant parts of the categories is 

reasonable because with the 

combination, all new fossil fuel-fired 

electricity generating units that meet 

specified minimum criteria will be 

subject to the same requirements, and 

therefore will be treated alike because 

they serve the same function, that is to 

serve baseload or intermediate demand. 

The EPA is not including stationary 

simple cycle turbines in this rule 

because they generally operate 

differently than the other units covered 

by today’s rule. The units covered by 

today’s rule are generally used to serve 

baseload or intermediate demand, while 

simple cycle turbines are generally used 

much less often (and thus have lower 

GHG emissions) and are generally used 

to meet peak demand rather than base 

or intermediate load requirements. 

Today’s proposal does not apply to 

new sources in non-continental areas, 

which include Hawaii and the 

territories. This is because noncontinental areas do not have available 

pipeline quality natural gas and, 

accordingly, a natural-gas-fired plant 

that could comply with the 1,000 lb 

CO2/MWh may not be feasible. At 

present, we do not have information to 

identify what types of new power plants 

may be constructed in those areas. 

Those types of power plants may range 

from liquified natural gas (LNG)-, to 

oil-, to coal-fired to renewables. Our 

lack of more specific information 

precludes us from proposing, at this 

time, a standard for new sources in noncontinental areas. 

Today’s proposal to require an 

emission rate of 1,000 lb CO2/MWh 

meets the requirements for a ‘‘standard 

of performance,’’ as defined under CAA 

section 111(a)(1). This proposed 

standard is based on the degree of 

emission limitation achievable through 

natural gas combined cycle generation. 

NGCC qualifies as the ‘‘best system of 

emission reduction’’ (BSER) that the 

EPA has determined has been 

adequately demonstrated because NGCC 

emits the least amount of CO2 and does 

so at the least cost. We propose that a 

NGCC facility is the best system of 

emission reduction for two main 

reasons. First, natural gas is far less 

polluting than coal. Combustion of 

natural gas emits only about 50 percent 

of the CO2 emissions that the 

combustion of coal does per unit of 

energy generated. Second, new natural 

gas-fired EGUs are less costly than new 

coal-fired EGUs, and as a result, our 

Integrated Planning Model (IPM) model 

projects that for economic reasons, 

natural gas-fired EGUs will be the 

facilities of choice until at least 2020, 


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22A number of the sources that EPA has 

identified as transitional sources have received 

some form of DOE financial assistance to 

demonstrate CCS. In addition, several additional 

projects have received funding but have not yet 

received air permits. Beyond these projects, 

prospects for additional federal funding are 

dependent on the overall budget process. 

23EIA analysis (AEO 2012 early release) shows 

that ‘‘coal remains the dominant energy source for 

electricity generation.’’ 

24Biologically-based material is defined as nonfossilized and biodegradable organic material 

originating from modern or contemporaneously 

grown plants, animals or micro-organisms 

(including products, by-products, residues and 

waste from agriculture, forestry and related 

industries as well as the non-fossilized and 

biodegradable organic fractions of industrial and 

municipal wastes, including gases and liquids 

recovered from the decomposition of non-fossilized 

and biodegradable organic material). 

which is the analysis period for this 

rulemaking. Indeed, our IPM model 

does not project construction of any 

new coal-fired EGUs during that period. 

This state of affairs has come about 

primarily because technological 

developments and discoveries of 

abundant natural gas reserves have 

caused natural gas prices to decline 

precipitously in recent years and have 

secured those relatively low prices for 

the near-future. Importantly, because 

the IPM modeling shows that natural 

gas-fired plants are the facilities of 

choice, the proposed standard of 

performance in today’s rulemaking –– 

which is based on the emission rate of 

a new NGCC unit –– does not add costs. 

In addition, compared to coal-fired 

EGUs, natural gas-fired EGUs have 

fewer nonair quality health and 

environmental impacts. This is true 

under not only a set of base-case 

assumptions, but also under a 

sensitivity considering significantly 

higher gas prices. 

The just-described reasons are 

sufficient as a legal matter to justify 

today’s proposed actions to combine 

source categories and establish the 1,000 

lb CO2/MWh standard. Such a standard 

could also be met today by new coalfired units using CCS. In addition, we 

propose to include the compliance 

alternative of allowing new coal- and 

pet coke-fired power plants to meet the 

1,000 lb CO2/MWh standard over a 30- 

year period so that plant developers can 

take advantage of future advancements 

cost savings in CCS technology that 

could lower its cost. This compliance 

alternative allows owners/operators to 

install CCS when the unit is first 

constructed but also provides the 

operational flexibility that may be 

necessary to optimize the performance 

and to have additional time to address 

any startup challenges related to issues 

such as business arrangements related to 

the sale or storage of the captured CO2. 

We recognize that, in light of a 

number of economic factors, including 

the increased availability and 

significantly lower price of natural gas, 

energy industry modeling forecasts 

uniformly predict that few, if any, new 

coal-fired power plants will be built in 

the foreseeable future. For these 

economic reasons, and independent of 

this proposed standard, the fossil fuelfired electricity generating industry has 

been trending towards increased use of 

natural gas and decreased use of coal for 

new generating capacity. Today’s 

proposed action is consistent with that 

trend; but, at the same time, today’s 

proposal is not intended to affect that 

apparent trend. 

We recognize that some owners/ 

operators may nevertheless seek to 

construct new coal-fired capacity. This 

may be beneficial from the standpoint of 

promoting energy diversity, and today’s 

proposal does not interfere with 

construction of new coal-fired capacity. 

In the first instance, a new coal-fired 

power plant may be able to meet the 

1,000 lb CO2/MWh standard by 

installing CCS at the time of 

construction. At present, while CCS 

would add considerably to the costs of 

a new coal-fired power plant, there are 

sources of funding available to support 

the deployment of CCS, including a 

limited number of government 

demonstration programs.22 Even if 

companies decide to construct a few 

new coal-fired power plants under any 

circumstance, those few may well have 

access to those government programs. 

The proposed 30-year averaging 

compliance option adds additional 

flexibility for new coal- and pet cokefired power plants by allowing them to 

construct and begin operations without 

CCS, and then to install and operate 

CCS at some time in the future, as long 

as they install CCS within ten years and 

operate it in a manner that allows them 

to meet the 1,000 lb CO2/MWh standard, 

on a weighted average basis, over the 

30-year period. 

We expect that the costs of CCS will 

decline in the future as CCS matures 

and is utilized more widely. Today’s 

action, if finalized, would promote 

utilization and further development of 

CCS by making it clear that CCS would 

be necessary for new coal-fired power 

plants to meet the performance 

standard. The prospect of declining CCS 

costs, in conjunction with the 

possibility of continued availability of 

additional funding mechanisms (e.g. 

demonstration funding such as 

Department of Energy (DOE) grants, tax 

credits (for investment and/or EOR), 

State incentives such as clean energy 

standards), and sale of other usable 

products such as CO2, sulfur and 

hydrogen based products, indicates that 

CCS may well be sufficiently accessible 

in the near term to the few coal-fired 

power plants that are expected to 

commence construction. Thus, the 30- 

year averaging compliance option, along 

with the potential opportunities for 

funding to implement CCS immediately, 

helps to alleviate any concerns that 

today’s action could restrict new coalfired construction. 

It should be noted that we are not 

required to justify the 30-year averaging 

compliance option on grounds that it 

qualifies as the ‘‘best system of emission 

reduction’’ adequately demonstrated, 

and we are not stating in this action 

whether that compliance alternative 

does or does not qualify as such. Thus, 

it is not necessary to determine that our 

expectation that costs will go down 

meets the standards for determining that 

CCS is ‘‘adequately demonstrated.’’ 

Rather, to reiterate, the 30-year 

averaging compliance option, along 

with the opportunity to implement CCS 

to meet the 1,000 lb CO2/MWh standard 

immediately upon startup, make CCS an 

available option for the limited number 

of new coal-fired power plants that may 

construct to serve the policy goals of 

promoting energy diversity, as well as 

other policy objectives.23 Indeed, by 

clarifying that, in the future, new coalfired power plants will need to 

implement CCS, this rulemaking 

eliminates uncertainty about the status 

of new coal and may well enhance the 

prospects for new coal-fired generation. 

In addition, there may also be other 

potential compliance options available 

that were not considered in this 

proposal. In the analysis for today’s 

proposal, the EPA did not include 

unique treatment of CO2 emissions from 

biologically-based material, otherwise 

called biogenic CO2 emissions.24

In 2011, the EPA prepared and 

submitted the draft Accounting 

Framework for Biogenic CO2 Emissions 

from Stationary Sources (http://

www.epa.gov/climatechange/emissions/ 

biogenic_emissions/study.html ). The 

draft Framework includes both a 

detailed examination of the scientific 

and technical issues related to 

accounting for biogenic CO2 emissions 

from stationary sources, and a proposed 

method to account for a stationary 

source’s onsite CO2 emissions, taking 

the biological cycling of carbon into 

consideration, in a scientifically and 

technically rigorous manner. The 

independent Science Advisory Board 

(SAB) has convened a Biogenic Carbon 


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25Note that any analysis of the cost and feasibility 

of CCS that EPA has undertaken for purposes of this 

proposal has focused solely on new sources. In 

today’s action, EPA has not undertaken any analysis 

of the cost or feasibility of CCS for existing units 

that undergo modifications. 

26As mentioned elsewhere, the EPA held a series 

of listening sessions and allowed for a period of 

additional comment after announcing it was 

moving forward with development of new source 

performance standards for GHGs emitted from fossil 

fuel-fired EGUs. The term ‘‘commenters’’ here refers 

to those who commented during the listening 

sessions or during the subsequent comment period. 

Emissions Panel (http://yosemite.

epa.gov/sab/sabproduct.nsf/0/

2F9B572C712AC52E8525783100704886

?OpenDocument) to conduct a peer 

review of the draft Framework. The peer 

review report will be finalized later in 

2012. 

The SAB’s peer review of the EPA’s 

discussion on the science related to the 

impacts of biogenic CO2 is not yet 

finalized and the EPA looks forward to 

the SAB’s conclusions later in 2012. 

Given that the SAB’s peer review is 

ongoing, the EPA is not suggesting 

specific methods of accounting or 

otherwise making particular proposals 

for treatment of biogenic CO2 emissions 

in any stationary source program, 

including NSPS. As more information, 

including the SAB peer review, becomes 

available, the EPA will consider its 

options and move forward as warranted. 

c. Requirements and Rationale for 

NSPS Modifications for GHGs. For 

purposes of today’s action, the EPA does 

not have a sufficient base of information 

to develop a proposal for the affected 

sources that may be expected to take 

actions that would constitute 

‘‘modifications’’ (as defined under the 

EPA’s NSPS regulations) for GHGs and 

therefore be subject to requirements for 

new sources. As a result, the EPA is not 

proposing requirements for NSPS 

modifications for GHGs.25

The EPA’s current regulations define 

an NSPS ‘‘modification’’ as a physical or 

operational change that increases the 

source’s maximum achievable hourly 

rate of emissions, but specifically 

exempt from that definition pollution 

control projects, which are projects that 

entail the installation of pollution 

control equipment or systems. Based on 

current information, most of the projects 

that we believe EGUs are most likely to 

undertake in the foreseeable future that 

could increase the maximum achievable 

hourly rate of CO2 emissions would 

constitute pollution control projects. In 

many cases, those projects would 

involve the installation of add-on 

control equipment required to meet 

CAA requirements for criteria and air 

toxics air pollutants. These increases in 

CO2 emissions would generally be small 

and would occur as a chemical 

byproduct of the operation of the 

control equipment. In other cases, those 

projects would involve equipment 

changes to improve efficiency to meet 

the requirements of a future 111(d) 

rulemaking for existing sources and 

would have the effect of increasing a 

source’s maximum achievable hourly 

emission rate (lb CO2/hr), even while 

decreasing its actual output based 

emission rate (lb CO2/MWh). Because 

all of these actions would be treated as 

pollution control projects under the 

EPA’s current NSPS regulations, they 

would be specifically exempted from 

the definition of modification. 

Our base of knowledge concerning 

NSPS modifications has depended 

largely on the enforcement actions 

brought against power plants and on 

self-reporting by power plants. Over the 

lengthy history of the NSPS program, 

those have been too few in number to 

allow us to develop a sufficiently robust 

base of knowledge to propose a standard 

of performance for NSPS modifications 

for GHGs at this time. 

In addition, the sources that took 

these actions vary widely one from 

another, and the types of actions were 

disparate. In light of this, as noted, we 

do not have adequate information as to 

the types of actions that qualify as 

modifications, the amount of increase in 

CO2 emissions they cause, the types of 

control measures, or the costs and 

effectiveness of control measures, on 

which to base a proposed standard of 

performance. Therefore, in today’s 

action, we are not proposing a standard 

of performance for modifications. We 

note that the statute contemplates that 

in circumstances such as these (where 

section 111(d) is implicated), sources 

not subject to the new source standards 

would be treated as existing sources 

subject to section 111(d). 

In today’s action, we solicit comment 

on the types of modifications power 

plants may undertake and the 

appropriate control measures. 

Depending on the information we 

develop, we may issue proposed 

standards of performance in the future. 

d. Requirements for Transitional 

sources. The EPA is aware that 

approximately 15 proposed EGUs have 

received CAA permitting authority 

approval for their preconstruction 

permits, but may not have ‘‘commenced 

construction’’ by the date of today’s 

proposed rulemaking. 

A few of these sources have taken 

additional action preparatory to 

commencing construction. For this 

proposed rule, these sources that, as of 

the date of this proposal, have a PSD 

permit and are poised to commence 

construction within the very near future 

are referred to as ‘‘transitional sources.’’ 

We are aware that approximately six of 

these sources have plans to implement 

CCS to some degree. 

CAA section 111 provides by its terms 

that sources that have not ‘‘commenced 

construction’’ before the date of 

proposed standards for new sources will 

be subject to the NSPS when they do 

commence construction. The EPA’s 

regulations define ‘‘commenced 

construction’’ as, in general, 

undertaking a continuous program of 

construction or entering into a binding 

contract to do so. 40 CFR 60.2. 

Commenters 26 have pointed out that 

absent different treatment, transitional 

sources will be subject to the same 

requirements that apply to new sources 

that did not obtain their permit before 

the date of proposal. These commenters 

have suggested that today’s proposed 

rule should treat transitional sources 

differently, especially in light of the 

substantial redesign that meeting such 

the proposed standard would have and 

the impact that redesign would have on 

the schedule for a project that was 

nearly ready to commence construction. 

The transitional sources at issue are 

coal-fired EGUs that, absent special 

treatment, would be subject to the 

standard of performance proposed in 

this rulemaking. 

In today’s proposed rulemaking, the 

EPA is not proposing a standard of 

performance for transitional sources, 

which we define as sources that have 

been issued a PSD permit by the date of 

proposal (including sources that have 

approved permits that are in the process 

of being amended, if those sources are 

intending to install CCS as evidenced by 

participating in any of the DOE CCS 

funding programs, either loan guarantee 

or grant programs) and that commence 

construction within 12 months of the 

date of publication of this proposal in 

the Federal Register. Upon finalization 

of this rulemaking without a standard of 

performance applicable to these sources, 

they will not be treated as new sources 

subject to the specific limitations set 

forth in the final new source standards. 

These sources would remain obligated, 

by the terms of their permits, to 

construct and operate in accordance 

with their permits. In addition, these 

sources will be treated as existing 

sources and would be subject to any 

requirements that a State promulgates to 

meet its obligations under section 

111(d). Sources that do not commence 

construction within 12 months of the 

date of this proposed action will be 

subject to this standard of performance 

for new sources. 


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27The EPA has made endangerment findings 

under this section for more than 60 stationary 

source categories and subcategories that are now 

subject to NSPS. 

e. Requirements for Reconstructed 

Sources, and Rationale. The EPA’s CAA 

section 111 regulations provide that 

reconstructed sources are to be treated 

as new sources and, therefore, subject to 

new source standards of performance. 

The regulations define reconstructed 

sources as, in general, existing sources 

(i) that replace components to such an 

extent that the capital costs of the new 

components exceed 50 percent of the 

capital costs of an entirely new facility, 

and (ii) for which compliance with 

standards of performance for new 

sources is technologically and 

economically feasible. 40 CFR 60.15. 

As with NSPS modifications, our base 

of knowledge concerning 

reconstructions has depended largely on 

the enforcement actions brought against 

power plants and on self-reporting by 

power plants. Over the lengthy history 

of the NSPS program, those have been 

too few in number to allow us to 

develop a sufficiently robust base of 

knowledge to propose a standard of 

performance for reconstructions for 

GHGs at this time. Thus, we lack 

adequate information about the type of 

source; the type of changes; the extent 

of emissions increases; and the type of 

control measures, including their cost 

and emissions reductions, that we need 

to propose a standard of performance for 

reconstructions. 

As a result, in today’s action, the EPA 

is not including a proposal for 

reconstructed units for GHGs. Instead, 

we solicit comment on how we should 

approach reconstructions and, 

depending on the information we 

receive, we may propose and finalize a 

standard for reconstructions at a later 

time. 

6. Summary of Emissions Impacts, Costs 

and Benefits 

Our IPM modeling, using Energy 

Information Administration (EIA) 

reference case assumptions, projects 

that there will be no construction of 

new coal-fired generation without CCS. 

In addition we examined a case with 

higher future electric demand and 

another case with higher future natural 

gas prices. We did not see any 

additional new construction of coalfired generation through 2030 in either 

of these cases. Under the relevant 

assumptions, we do not project that this 

rule will impose notable costs. 

We also examined a scenario with 

both increased future natural gas prices 

and increased future electric demand. In 

this sensitivity case we saw small 

amounts of coal-fired generation being 

built in 2030. Even under this 

sensitivity analysis with small amounts 

of new coal generation under conditions 

of high natural gas prices and 

simultaneously high electricity demand 

in 2030, we do not project that this 

proposed rule will impose notable costs 

upon sources. (See the RIA for further 

discussion of sensitivities). 

While this proposed rule also will not 

have direct impact on U.S. emissions of 

greenhouse gases under expected 

economic conditions, it provides 

assurance that emission rates from new 

fossil fuel-fired generation will not 

exceed the level of the standard and will 

send a strong signal both domestically 

and internationally. Domestically, this 

proposed rule can further stimulate 

investment in CCS and other clean coal 

technologies, by making it clear that 

such technologies do provide a clear 

path forward for new coal-fired 

generating capacity. Internationally, this 

rule may encourage others to consider 

less GHG-intensive forms of power 

generation. 

B. Does this action apply to me? 

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 regulated 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 Include 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 

A. Statutory Background for This Rule 

Clean Air Act section 111 establishes 

mechanisms for controlling emissions of 

air pollutants from stationary sources. 

As a preliminary step, CAA section 

111(b)(1)(A) requires the EPA to list 

categories of stationary sources that the 

Administrator, in his or her judgment, 

finds ‘‘cause[], or contribute[] 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ 27

Once it has listed a source category, 

the EPA establishes ‘‘standards of 

performance’’ that apply to new sources, 

which are sources that are constructed, 

or that undertake modifications or 

reconstruction, after the EPA proposes 

the standards of performance for the 

relevant source category. CAA section 

111(b)(1)(B). Specific statutory and 

regulatory provisions define what 

constitutes a modification or 

reconstruction of a facility. An existing 

facility undertakes a modification if it 

undergoes ‘‘any physical change * * * 

or change in the method of operation 

* * * which increases the amount of 

any air pollutant emitted by such source 

or which results in the emission of any 

air pollutant not previously emitted.’’ 

CAA section 111(a)(4). The EPA’s NSPS 

regulations provide exemptions for 

several types of changes, including the 

installation of pollution control projects. 

40 CFR 60.2, 60.14(e). An existing 

facility undertakes a reconstruction if it 

replaces components to such an extent 

that the capital costs of the new 

equipment or components exceed 50 

percent of what is believed to be the 

cost of a completely new facility. 40 

CFR 60.15. In promulgating standards of 

performance, the EPA has significant 


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28This level of control has historically been 

referred to as best demonstrated technology (BDT). 

29 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

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

(December 15, 2009). 

30 ‘‘Light-Duty Vehicle Greenhouse Gas Emission 

Standards and Corporate Average Fuel Economy 

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

31 74 FR 66510–66511. 

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

methane (CH4), perflurocarbons (PFCs), 

hydrofluorocarbons (HFCs), and sulfur hexafluoride 

(SF6). 

discretion to create subcategories based 

on source type, class or size. CAA 

section 111(b)(2). 

Clean Air Act section 111(a)(1) 

defines a ‘‘standard of performance’’ 

as— 

a standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any nonair 

quality health and environmental impact and 

energy requirements) the Administrator 

determines has been adequately 

demonstrated. 

We call this level of control the best 

system of emission reduction (BSER).28

The standard that the EPA develops, 

based on the BSER, is commonly a 

numerical emissions limit, expressed as 

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

standard). Generally, the EPA does not 

prescribe a particular technological 

system that must be used to comply 

with a standard of performance. Rather, 

sources remain free to elect whatever 

combination of measures will achieve 

equivalent or greater control of 

emissions. 

B. Overview of Climate Change Impacts 

From GHG Emissions 

In 2009, the EPA Administrator 

issued the 2009 Endangerment 

Finding,29 under CAA section 202(a)(1), 

as part of the process for promulgating 

the Light Duty Vehicle Rule.30 With the 

Endangerment Finding, the 

Administrator found that elevated 

concentrations of GHGs in the 

atmosphere may reasonably be 

anticipated to endanger public health 

and welfare. These adverse effects on 

public health and welfare are 

summarized here, and described in 

more detail in the RIA. As explained in 

the Endangerment Finding, the EPA 

made this determination based 

primarily upon the recent, major 

assessments by the U.S. Global Change 

Research Program (USGCRP), 

Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC).31 In brief, 

these assessments addressed the 

scientific issues that the EPA was 

required to examine, were 

comprehensive in their coverage of the 

GHG and climate change problem, and 

underwent rigorous and exacting peer 

review by the expert community, as 

well as rigorous levels of U.S. 

government review and acceptance. 

Below is a brief, non-comprehensive 

summary of effects noted in the 

Endangerment Finding and the 

assessment reports. 

1. Public Health Impacts Detailed in the 

2009 Endangerment Finding 

Climate change threatens public 

health through a number of impacts 

such as increases in hot weather, ozone 

pollution, and the severity and 

frequency of extreme weather events. 

Children, the elderly, and the poor are 

among the most vulnerable to these 

climate-related health effects. 

By increasing higher average 

temperatures, climate change increases 

the likelihood of heat waves, which are 

associated with increased deaths and 

illnesses. While climate change also 

leads to decreases in cold-related 

mortality, some evidence suggests that 

the net impact on mortality is more 

likely to be adverse. Heat is already the 

leading cause of weather-related deaths 

in the U.S. 

Climate change is expected to 

increase ozone pollution over broad 

areas of the country including large 

population areas with unhealthy surface 

ozone levels. Ozone health studies 

indicate that elevated surface ozone 

increases risks of premature death, acute 

bronchitis, heart attacks, asthma 

aggravation, and other respiratory 

effects. 

Public health threats also stem from 

increases in intensity or frequency of 

extreme weather associated with climate 

change, such as increased hurricane 

intensity, increased frequency of intense 

storms and heavy precipitation. The 

assessment literature indicates that 

there is the potential for hurricanes to 

become more intense, and there is some 

evidence that Atlantic hurricanes have 

already become more intense. 

Hurricanes and floods from humaninduced climate change can cause 

deaths, injuries, waterborne diseases, 

and mental health problems such as 

post-traumatic stress disorders. 

Drownings and other health impacts 

from coastal storms and storm surges are 

expected to increase due to rising sea 

levels. 

2. Public Welfare Impacts Detailed in 

the 2009 Endangerment Finding 

Climate change is expected to have 

numerous effects on public welfare. 

Large areas of the country are at serious 

risk of reduced water supplies, 

increased water pollution, and 

increased occurrence of extreme events 

such as floods and droughts. Coastal 

areas face increased risks from storm 

and flooding damage to property, as 

well as adverse impacts from sea level 

rise such as land loss due to inundation, 

erosion, wetland submergence, and 

habitat loss. 

Climate change is expected to result 

in an increase in peak electricity 

demand, and changes in extreme 

weather threaten energy, transportation, 

and water resource infrastructure. 

Climate changes may exacerbate 

ongoing environmental pressures in 

certain settlements, particularly in 

Alaskan indigenous communities. Over 

the 21st century, climate change will 

fundamentally rearrange U.S. 

ecosystems. 

It is possible that in the next few 

decades, adverse effects in certain parts 

of the agriculture and forestry sectors— 

such as enhanced pest and weed 

growth, increased surface ozone, 

changes in the intensity and frequency 

of droughts and heavy storms, and 

increased wildfires—may be offset by 

benefits resulting from a stimulatory 

carbon dioxide effect and a longer 

growing season. However, the body of 

evidence points towards increasing risks 

of net adverse impacts on U.S. food 

production, agriculture, and forest 

productivity as temperatures continue 

to rise, with the potential for significant 

disruptions and crop failure. 

Human-induced climate change has 

the potential to be far-reaching and 

multidimensional. Given the long 

atmospheric lifetime of the six GHGs,32

which range from roughly a decade to 

centuries, future atmospheric 

greenhouse gas concentrations for the 

remainder of this century and beyond 

will be influenced not only by future 

emissions but indeed by present-day 

emissions. The severity of all the 

described risks and impacts is likely to 

increase over time with accumulating 

GHG concentrations and the associated 

temperature increases and precipitation 

changes. Finally, these impacts are 

global, and may exacerbate problems 

that raise humanitarian, trade, and 

national security issues for the U.S. 

3. Climate Impacts Detailed in Recent 

NRC Assessments 

Since the EPA issued the 2009 

Endangerment Finding, the NAS, which 

is a society established by an Act of 

Congress that is composed of 

distinguished scholars engaged in 

scientific and engineering research, has 


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33NRC (2010). Advancing the Science of Climate 

Change. National Academy Press. Washington, DC. 34NRC (2010). Advancing the Science of Climate 

Change. National Academy Press. Washington, DC. 

Page 3. 

35NRC (2010). Advancing the Science of Climate 

Change. National Academy Press. Washington, DC. 

Page 286. 36 ‘‘Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990–2009’’, Report EPA 430–R–11–005, 

United States Environmental Protection Agency, 

April 15, 2011. 

37From Table 2–3 of the EPA GHG Emissions and 

Sinks Inventory, EPA 430–R–11–005. 

issued assessments with similar 

conclusions to those of the assessments 

upon which the EPA based the 

Endangerment Finding. In May 2010, 

the NRC, which is the operating arm of 

the National Academy of Sciences 

(NAS) that conducts most of the science 

policy and technical work, published its 

comprehensive assessment, ‘‘Advancing 

the Science of Climate Change’’ (the 

2010 NRC Assessment).33 It concluded 

that ‘‘climate change is occurring, is 

caused largely by human activities, and 

poses significant risks for—and in many 

cases is already affecting—a broad range 

of human and natural systems.’’ 34

Furthermore, the NRC stated that this 

conclusion is based on findings that are 

‘‘consistent with the conclusions of 

recent assessments by the U.S. Global 

Change Research Program, the 

Intergovernmental Panel on Climate 

Change’s (IPCC) Fourth Assessment 

Report, and other assessments of the 

state of scientific knowledge on climate 

change.’’ 35 These are the same 

assessments that served as the primary 

scientific references underlying the 

2009 Endangerment Finding. The 2010 

NRC Assessment also warned of risks 

associated with abrupt changes and 

surprises that might occur when certain 

thresholds are crossed, such as the 

release of large quantities of GHGs 

stored in frozen soils in the Arctic or 

irreversible drying and desertification in 

the subtropics; and of potential for 

broad, ‘‘catastrophic’’ impacts on 

marine ecosystems resulting from ocean 

acidification. 

Another NRC assessment, ‘‘Climate 

Stabilization Targets: Emissions, 

Concentrations, and Impacts over 

Decades to Millenia’’, was published in 

2011 (the 2011 NRC Assessment). This 

report found that climate change due to 

CO2 emissions will persist for many 

centuries. The report also estimates a 

number of specific climate change 

impacts, finding that every degree 

Celsius (°C) of warming could lead to 

increases in heavy rainfall and 

decreases in crop yields and Arctic sea 

ice extent, along with other 

precipitation and stream flow changes. 

The assessment also found that with an 

increase of 4 °C, the average summer 

would be as warm as the warmest 

summers of the past century, that for an 

increase of 1 to 2 °C the area burnt by 

wildfires in western North America will 

likely more than double, that coral 

bleaching and erosion will increase due 

both to warming and ocean 

acidification, and that sea level will rise 

1.6 to 3.3 feet by 2100 in a 3 °C scenario. 

The assessment notes that many 

important aspects of climate change are 

difficult to quantify but that the risk of 

adverse impacts is likely to increase 

with increasing temperature, and that 

the risk of surprises can be expected to 

increase with the duration and 

magnitude of the warming. Importantly, 

these recent NRC assessments represent 

another independent and critical 

inquiry of the state of climate change 

science, separate and apart from the 

previous IPCC, NRC, and USGCRP 

assessments. 

C. GHGs From Fossil Fuel-Fired Power 

Plants 

Fossil fuel-fired electric utility 

generating units are by far the largest 

emitters of GHGs, primarily in the form 

of CO2, among stationary sources in the 

U.S. This section describes the amount 

of those emissions and places that 

amount in the context of the national 

inventory of GHGs. 

The EPA prepares the official U.S. 

Inventory of Greenhouse Gas Emissions 

and Sinks 36 (the U.S. GHG Inventory) to 

comply with existing commitments 

under the United Nations Framework 

Convention on Climate Change. This 

inventory, which includes recent trends, 

is presented by industrial sectors. It is 

the source for the information provided 

in Table 2 below concerning total U.S. 

anthropogenic emissions and sinks of 

GHGs and CO2 emissions, by industrial 

sector—including fossil fuel-fired 

EGUs—for the years 1990, 2000, and 

2009. 

TABLE 2—U.S. GHG EMISSIONS AND SINKS BY SECTOR

[Teragram Carbon Dioxide Equivalent (Tg CO2 Eq.)] 37

Sector 1990 2000 2009 

Energy ........................................................................................................................ 5,287 .8 6,168 .0 5,751 .1 

Industrial Processes .................................................................................................. 315 .8 348 .8 282 .9 

Solvent and Other Product Use ................................................................................ 4 .4 4 .9 4 .4 

Agriculture .................................................................................................................. 383 .6 410 .6 419 .3 

Land Use, Land-Use Change and Forestry (Emissions) .......................................... 15 .0 36 .3 25 .0 

Waste ......................................................................................................................... 175 .2 143 .9 150 .5 

Total Emissions .................................................................................................. 6,181 .8 7,112 .7 6,633 .2 

Land Use, Land-Use Change and Forestry (Sinks) .................................................. (861 .5) (576 .6) (1,015 .1) 

Net Emissions (Sources and Sinks) ................................................................... 5,320 .3 6,536 .1 5,618 .2 

Energy-related CO2 emissions are the 

largest contributor to total U.S. GHG 

emissions, representing 86.7 percent of 

total 2009 GHG emissions. In 2009, the 

electric power sector—consisting of 

those entities whose primary business is 

the generation of electricity—accounted 

for 40 percent of all energy-related CO2

emissions. The transportation sector, 

with emissions principally from the 

combustion of gasoline, diesel, and jet 

fuel, was the second-largest source, at 

32 percent of the total. Other energyrelated CO2 emission sources included 

industrial, residential, and commercial 

fossil fuel combustion, natural gas and 

petroleum systems, and incineration of 

waste. 

Direct fuel use in the residential and 

commercial sectors accounted for 26 

percent of total CO2 emissions in 2009. 

Total CO2 emissions from fossil fuelfired EGUs, for years 1990, 2000 and 

2009, are shown below in Table 3. 


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38Copies of the Federal Register notice, the 

settlement agreement, other supporting documents 

and the comments received are available online at 

fdms.gov under docket EPA–HQ–2010–1057. 

39We include this discussion of other 

rulemakings for background purposes. The effort to 

coordinate rulemakings does not provide a defense 

to a violation to the CAA. Sources cannot defer 

compliance with existing requirements because of 

other upcoming regulations. 

40On December 15, 2011, EPA finalized a 

supplemental rule (76 FR 80760, December 27, 

2012) to include five additional states in the CSAPR 

ozone season NOX program. On February 7, 2012, 

EPA issued two sets of minor adjustments to the 

CSAPR (77 FR 10324, February 21, 2012). 

TABLE 3—U.S. GHG EMISSIONS FROM GENERATION OF ELECTRICITY FROM COMBUSTION OF FOSSIL FUELS

[Tg CO2 Eq.] 

GHG Emissions 1990 2000 2009 

Total CO2 from fossil fuel combustion ......................................................................................... 1,820.8 2,296.9 2,154.0 

—from coal ........................................................................................................................... 1,547.6 1,927.4 1,747.6 

—from natural gas ................................................................................................................ 175.3 280.8 373.1 

—from petroleum .................................................................................................................. 97.5 88.4 32.9 

From use of limestone and dolomite ........................................................................................... 2.6 2.5 3.8 

Total CH4—stationary combustion .............................................................................................. 0.6 0.7 0.7

Total N2O—stationary combustion .............................................................................................. 8.1 10.0 9.0 

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. We 

are not proposing separate N2O or CH4

emission limits or an equivalent CO2

emission limit in today’s action because 

of a lack of available data for these 

affected sources. Additional information 

on the quantity and significance of 

emissions and on the availability of 

cost-effective controls would be needed 

before proposing standards for these 

pollutants. The estimated emissions for 

N2O and CH4 from fossil fuel-fired EGUs 

(9.0 and 0.7 Tg of CO2 equivalent, 

respectively) is about 0.4 percent of total 

CO2 equivalent emissions from fossil 

fuel-fired electric power generating 

units. We are requesting comment on 

this approach and on the need to collect 

additional data on N2O and CH4

emissions from these affected sources. 

D. Litigation Directly Leading to This 

Rule 

As discussed below, in section II.E., 

on February 27, 2006, the EPA 

published a final rule that revised the 

standards of performance for criteria 

pollutant emissions of EGUs included in 

the Da category. ’’Standards of 

Performance for Electric Utility Steam 

Generating Units, IndustrialCommercial-Institutional Steam 

Generating Units, and Small IndustrialCommercial-Institutional Steam 

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

2006) (the ‘‘2006 Final Rule’’). The 2006 

Final Rule did not establish standards of 

performance for GHG emissions. Two 

groups of petitioners filed petitions for 

judicial review of this rule in the U.S. 

Court of Appeals for the District of 

Columbia Circuit (the Court), 

contending, among other things, that the 

rule was required to include standards 

of performance for GHG emissions from 

EGUs. The two groups of petitioners 

were (1) the States of New York, 

California, Connecticut, Delaware, 

Maine, New Mexico, Oregon, Rhode 

Island, Vermont, and Washington, the 

Commonwealth of Massachusetts, the 

District of Columbia, and the City of 

New York (collectively ‘‘State 

Petitioners’’); and (2) Natural Resources 

Defense Council (NRDC), Sierra Club, 

and Environmental Defense Fund 

(EDF)(collectively ‘‘Environmental 

Petitioners’’). 

The portions of State and 

Environmental Petitioners’ petitions for 

review of the 2006 Final Rule that 

related to GHG emissions were severed 

from other petitions for review of that 

rule, and were formally pending before 

the Court under the caption State of 

New York, et al. v. EPA, No. 06–1322. 

Following the U.S. Supreme Court’s 

decision in Massachusetts, discussed 

above, the Court, upon motion from the 

EPA, remanded the 2006 Final Rule for 

further consideration of the issues 

related to GHG emissions in light of 

Massachusetts. The EPA did not act on 

that remand. To avoid further litigation, 

the State and Environmental Petitioners 

and the EPA negotiated a proposed 

settlement agreement that set deadlines 

for the EPA to propose and take final 

action on (1) a rule under CAA section 

111(b) that includes standards of 

performance for GHGs for new and 

modified EGUs that are subject to 40 

CFR part 60, subpart Da; and (2) a rule 

under CAA section 111(d) that includes 

emission guidelines for GHGs from 

existing EGUs that would have been 

subject to 40 CFR part 60, subpart Da if 

they were new sources. Pursuant to 

CAA section 113(g), the EPA published 

a notice of the proposed settlement 

agreement in the Federal Register, and 

provided for a public comment period. 

75 FR 82392 (December 30, 2010).38 The 

EPA considered the comments received 

and concluded that they did not 

disclose facts or considerations 

indicating that the proposed settlement 

agreement was inappropriate, improper, 

inadequate or inconsistent with the 

CAA. Therefore, the EPA concluded that 

the proposed settlement agreement 

should be finalized. 

E. Coordination With Other 

Rulemakings 

EGUs are the subject of several CAA 

rulemakings that have been recently 

completed. The EPA recognizes that it is 

important that all of these efforts 

achieve their intended environmental 

objectives in a common sense manner. 

The confluence of these rulemakings 

allows the industry to look across the 

regulatory requirements and design cost 

effective integrated compliance 

strategies.39

On July 6, 2011, the EPA finalized the 

Cross-State Air Pollution Rule 

(CSAPR)40. 76 FR 48208 (August 8, 

2011). Also known as the Transport 

Rule, the CSAPR requires a total of 28 

states and the District of Columbia to 

improve air quality by reducing power 

plant emissions that contribute to ozone 

and fine particle pollution in other 

States. The CSAPR applies to 3,642 

EGUs at 1,081 coal-, gas- and oil-fired 

facilities in the eastern half of the U.S. 

By 2014, combined with other final state 

and EPA actions, the CSAPR will reduce 

power plant SO2 emissions by 73 

percent and NOX emissions by 54 

percent from 2005 levels in the CSAPR 

region. The CSAPR was scheduled to 

begin on January 1, 2012. However, on 

December 30, 2011, the U.S. Court of 

Appeals for the DC Circuit issued a 

ruling to stay the rule pending judicial 

review. This decision is not a ruling on 

the merits of the CSAPR. While this 

decision delays implementation of the 


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CSAPR and the significant health 

benefits associated with the rule, it 

leaves the Clean Air Interstate Rule 

(CAIR), the predecessor regulation to 

CSAPR, in place while the Court 

considers the merits of the challenges to 

the CSAPR. Oral arguments are 

scheduled for April 13, 2012. 

On December 16, 2011, the EPA 

signed the Mercury and Air Toxic 

Standards (MATS) rule to reduce 

emissions of mercury and other HAP 

emissions from coal- and oil-fired power 

plants. This regulation requires 

investments in pollution controls to 

reduce emissions of mercury, other 

metals and acid gases by 2015 or 2016. 

In the same notice, the EPA also revised 

the NSPS for criteria pollutants from 

these sources. Because the control 

technologies and strategies that reduce 

SO2 can also reduce or help to reduce 

HAP emissions, coordinating 

compliance strategies for the CSAPR 

and MATS rules, including the revised 

NSPS for criteria pollutants, will allow 

cost-effective compliance options. 

In April, 2011, the EPA proposed 

standards under the Clean Water Act 

(CWA) to reduce injury and death of 

fish and other aquatic life caused by 

cooling water intake structures existing 

at power plants and factories. 76 FR 

22174 (April 20, 2011). These facilities 

pull in large volumes of cooling water 

from lakes, rivers, estuaries or oceans to 

cool their machinery. The EPA is 

currently considering a wide range of 

comments to this proposal. 

The EPA recognizes that it is 

important that each of these efforts 

achieves its intended environmental 

objectives in a common-sense, cost 

effective manner, that is consistent with 

the underlying statutory requirements 

and that allows the industry to comply 

with all of its obligations under these 

rules as efficiently as possible and to do 

so by making coordinated investment 

decisions and, to the greatest extent 

possible, by adopting integrated 

compliance strategies. In addition, EO 

13563 states that ‘‘[i]n developing 

regulatory actions and identifying 

appropriate approaches, each agency 

shall attempt to promote * * * 

coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve regulatory goals that are 

designed to promote innovation.’’ 

Recent guidance from the Office of 

Information and Regulatory Affairs has 

emphasized the importance of, where 

appropriate and feasible, considering 

cumulative effects and of seeking to 

harmonize rules in terms of both 

content and timing. 

Thus, the EPA recognizes that it needs 

to approach these rulemakings, to the 

extent that its legal obligations permit, 

in ways that allow the industry to make 

practical investment decisions that 

minimize costs in complying with all of 

the final rules, while still achieving the 

fundamentally important environmental 

and public health benefits that the 

rulemakings must achieve. 

F. PSD and Title V Implications 

Commenters have asked whether the 

rulemaking the EPA is proposing today 

has implications for EGUs and other 

stationary sources under the prevention 

of significant deterioration (PSD) and 

Title V programs. We discuss this issue 

in section VI, below, and we include 

relevant background information in that 

discussion. 

G. Stakeholder Input 

The EPA has been engaged in 

extensive interactions with many 

different stakeholders on the subjects of 

climate change, source contributions, 

and potential emission reduction 

opportunities. These stakeholders have 

included industries, environmental 

organizations, and many regional, State, 

and local air quality management 

agencies that have been actively 

engaged in efforts to address GHG 

emissions over a period of several years. 

In addition to these conversations, as 

part of developing this proposed rule, 

the EPA held five listening sessions in 

February and March 2011 to obtain 

additional information and input from 

key stakeholders and the public. Each of 

the five sessions had a particular target 

audience: The electric power industry, 

environmental and environmental 

justice organizations, States and Tribes, 

coalition groups, and the petroleum 

refinery industry. Each session lasted 

two hours and featured a facilitated 

round table discussion among 

stakeholder representatives who were 

identified and selected for their 

expertise in the CAA standard-setting 

process. The EPA had asked key 

stakeholder groups to identify these 

round table participants in advance of 

the listening sessions. The EPA 

accepted comments from the public at 

the end of each session and via the 

electronic docket system. 

From the listening sessions and 

written submissions, the EPA received a 

wide range of comments and ideas for 

this proposed rule. The main topics of 

the comments, which concerned 

requirements for both new and existing 

sources, included the following: 

• Feasibility and availability of 

control technologies 

• Output-based standards 

• Subcategorization factors 

• Fleet-wide averaging 

• Neutrality of fuels 

• Role of efficiency improvements 

• Equivalency of state and regional 

reduction programs 

• Recognition of early action by 

industries and states achieving 

reductions 

• Use of a multi-pollutant, multimedia approach 

• Market-based flexibility 

• Use of a tiered structure, with 

requirements evolving over time 

• Credit for replacement of older, less 

efficient generation units 

• Role of biomass 

• Consideration of compliance issues 

arising from conflicts with other 

regulatory programs 

• Schedule for proposing and 

promulgating this rule 

• Small business impacts 

Comments submitted via the 

electronic docket system concerning 

development of this proposed rule are 

available at www.regulations.gov 

(docket number EPA–HQ–OAR–2011– 

0090). 

III. Proposed Requirements for New 

Sources 

This section describes the proposed 

requirements in this rulemaking for new 

sources. Our rationale for these 

proposed requirements is provided in 

Section IV of this preamble. 

A. What is the affected source? 

Sources affected by today’s proposal 

for new source provisions are sources 

that are considered both covered EGUs 

as defined by this rule and ‘‘new’’ 

sources as defined under the provisions 

of CAA section 111. 

1. Covered EGUs, Generally 

The EPA is proposing to define a 

covered EGU, which is a source that is 

subject to this rule, as any fossil fuelfired combustion unit that supplies 

more than one-third of its potential 

annual electric output and more than 25 

MW net-electrical output (MWe) to any 

utility power distribution system for 

sale, with certain exceptions noted 

below. For this proposed rule, covered 

EGUs include electric utility steam 

generating units (‘‘boilers’’), stationary 

combined cycle combustion turbines 

and their associated HRSG) and duct 

burners; and IGCC units, including their 

combustion turbines and associated 

HRSG. However, for purposes of this 

rule, covered EGUs do not include 

stationary simple cycle combustion 

turbines or EGUs located in Hawaii or 

other non-continental areas. In addition, 

units subject to emission requirements 


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41As discussed below, we are not proposing such 

a limit for modifications, transitional sources, or 

reconstructed sources. 

42As discussed elsewhere, EPA is soliciting 

comment on whether the emissions standard that 

reflects CCS should be somewhat higher or lower 

than 1,000 lb CO2/MWh, and whether the emissions 

standard that reflects supercritical efficiency should 

be somewhat higher or lower than 1,800 lb CO2/ 

MWh. If EPA does promulgate a higher or lower 

standard in either case, then EPA may revise the 

600 lb CO2/MWh amount accordingly. 

under CAA section 129 would not be 

subject to requirements under this 

proposed rule. 

2. CO2 Emissions Only 

This action proposes to regulate 

covered EGU emissions of CO2, and not 

other constituent gases of the air 

pollutant GHG, although we identify the 

pollutant we propose to regulate as 

GHGs. Note that emissions of criteria 

pollutants for covered EGUs remain 

covered under 40 CFR part 60 subparts 

Da and KKKK. 

3. ‘‘New’’ Sources 

CAA section 111(a)(2) defines a ‘‘new 

source’’ as ‘‘any stationary source, the 

construction or modification of which is 

commenced after publication of 

regulations (or, if early, proposed 

regulations) prescribing a standard of 

performance under [CAA section 111] 

which will be applicable to such 

source.’’ In contrast, CAA section 

111(a)(6) defines an ‘‘existing source’’ as 

‘‘any stationary source other than a new 

source.’’ The definition of a ‘‘new 

source’’ applies according to its terms 

for purposes of this rulemaking, except 

that special considerations come into 

play for sources undertaking physical or 

operational changes, transitional 

sources, and sources undertaking 

reconstruction, as discussed below in 

Section V of this preamble. 

B. What emissions limitations must I 

meet? 

In this rulemaking, the EPA is 

proposing a standard of performance 

(NSPS), and we are requesting comment 

on a 30-year averaging compliance 

option, for CO2 emissions from affected 

sources, which are new fossil fired 

EGUs described above in Section III.A. 

1. Standard of Performance 

The standard of performance is a 

gross output-based CO2 emission limit 

expressed in units of emissions mass 

per unit of useful recovered energy 

(specifically, in pounds per megawatthour (lb/MWh)). This emission limit 

would be effective upon the effective 

date of the final action. 

We are not proposing any 

subcategories for new affected sources. 

Instead, we are proposing a single 

output-based CO2 emission limit that 

must be met by all affected sources.41

Specifically, the EPA is proposing a 

standard of 1,000 lb CO2/MWh, but, as 

discussed below, is taking comment on 

a range from 950 lb CO2/MWh to 1,100 

lb CO2/MWh. 

As discussed below, the proposed 

method to calculate compliance is to 

sum the emissions for all operating 

hours and to divide that value by the 

sum of the electrical energy output and 

useful thermal energy output, where 

applicable for combined heat and power 

(CHP) EGUs, over a rolling 12-month 

period. In the alternative, we solicit 

comment on requiring calculation of 

compliance on an annual (calendar 

year) period. 

Under this proposal, no averaging or 

emissions trading among affected 

sources would be allowed. 

We seek comment on all aspects of 

the proposed standard of performance, 

including using net, instead of gross, 

generation-based emissions rate 

measurement. 

2. 30-Year Averaging Compliance 

Option 

We also propose a 30-year averaging 

compliance option that would be 

available only for affected coal- and pet 

coke-fired sources that comply with the 

standard through the use of CCS. This 

approach involves a performance 

standard that includes both a 12-month 

annual average limit and a longer-term 

limit that may be met on an average 

basis by the end of a 30-year period. The 

12-month limit is important because it 

is a practicably enforceable mechanism 

to ensure that the source is on a path to 

comply with the 30-year average limit. 

The annual limit will ensure that the 

source takes timely action to meet a 30- 

year limit. For instance, if meeting the 

30-year limit was predicated on 

installing CCS technology before year 

eleven of operation, the annual 

compliance limits would provide an 

enforceable measure to ensure that CCS 

was installed and operating well before 

a 30-year average could be calculated. 

Note that after the 30th year, the source 

would be required to meet the 12-month 

annual average 1,000 lb CO2/MWh 

emission limit. 

Specifically, for the first ten years of 

operation, the affected source would be 

required to comply with a 12-month 

annual average CO2 emissions limit 

based on the best demonstrated 

performance of a coal-fired facility 

without CCS, which is 1,800 lb CO2/ 

MWh (816 kg CO2/MWh) (gross). This 

proposed emission limit can be met by 

modern coal-fired facilities using 

supercritical steam conditions, IGCC 

facilities, and pressurized CFBs boilers. 

By no later than the 11th year from the 

effective date of the rule, the facility 

would be required to meet a reduced 

emission limit of no more than 600 lb 

CO2/MWh (272 kg CO2/MWh) (gross) on 

a 12-month annual average basis for the 

remaining 20 years of the 30-year 

averaging period, such that the weighted 

average CO2 emissions rate from the 

facility over the 30-year time period 

would be equivalent to the proposed 

standard of performance of 1,000 lb 

CO2/MWh. This reduced emissions 

standard during the remainder of the 30- 

year period would be met with some 

level of CCS.42

For added flexibility, under this 

option, we are taking comment on 

allowing the owner/operator to select a 

different emission trajectory to 

achieving the 30-year average as long as 

the owner/operator obtains EPA 

approval of that rate before beginning 

operations. Such a trajectory would 

have to assure that, assuming similar 

amounts of operation in each year, the 

overall overage emission rate would be 

at or below the required 30-year average 

of 1,000 lb CO2/MWh. For instance, if 

an owner or operator wished to operate 

at a rate of 2,000 lb CO2/MWh for the 

first period, it would have to commit to 

something more stringent than 

achieving a 600 lb CO2/MWh standard 

by the 11th year. Potential compliance 

pathways could include committing to a 

limit of 500 lb CO2/MWh by the 11th 

year or committing to a limit of 600 lb 

CO2/MWh by the 8th year. 

The EPA is also soliciting comment 

on what additional requirements would 

be necessary to implement the 30-year 

averaging requirement. Specifically, if 

the owners or operators did not intend 

to install CCS when the unit 

commenced operation, they could be 

required to submit a plan that includes 

a location to store CO2 and a schedule 

for construction and operation of their 

carbon capture system. The schedule 

would include key milestone dates such 

as soliciting proposals, obtaining 

financing, beginning construction, and 

beginning operation. The EPA requests 

comment on the appropriateness of 

including these, and/or other 

requirements to ensure that the owners 

or operators of the facility have 

adequate plans in place to meet the 30- 

year average emission rate requirement. 

Further, the shorter term emission limits 

for the entire 30-year period must be 

included in the source’s title V permit. 

We solicit comment on the 


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enforceability of the 30-year averaging 

period, how we can ensure that the 

owner/operator will comply with the 

second phase of the standard, and what 

sort of compliance demonstrations are 

appropriate with such a long-term 

standard. We also solicit comment on 

whether this alternative compliance 

mechanism should automatically 

terminate in 2020 such that only 

facilities that commenced construction 

prior to 2020 would be able to use the 

30-year average. 

The EPA suggests that this 30-year 

averaging compliance option may be 

warranted for at least two reasons. First, 

it provides power companies with the 

option of building a coal-fired power 

plant in the near term and installing 

CCS at a later time when costs will 

likely be lower and further experience 

from demonstration projects will have 

been gained. The 30-year averaging 

period is sufficiently long to allow 

sources, before they install CCS, to 

benefit from the experience that will be 

gained from commercial-scale CCS 

demonstration projects operating over 

the next decade from a number of DOEfunded demonstration projects. A new 

coal- or pet coke-fired unit could 

operate for at least a decade before 

installing CCS and still have enough 

years operating at a controlled emission 

rate to reach a 1,000 lb CO2/MWh 

standard on a 30-year basis. A second 

reason that this alternative may be 

practicable is that, even for sources 

installing and operating CCS at the 

beginning of a project, there may be 

startup issues (other than those related 

to the capture technology or the 

arrangements for sequestration). For 

instance, a company’s ability to 

sequester CO2 may be dependent upon 

construction by a third party of a 

pipeline that will be transporting the 

CO2 to a site to be used for enhanced oil 

recovery or permanent sequestration. 

Because the owner or operator does not 

have direct control over this part of the 

project, there may be concerns that it 

will not be completed on time and that 

even after spending all of the money to 

construct a coal-fired unit capable of 

capture, it will have to remain nonoperational for a period of time until the 

pipeline project or sequestration 

destination is completed. The 30-year 

averaging compliance option could 

provide flexibility to operate the unit 

until the pipeline was completed as 

long as the carbon capture system is 

designed to meet a rate sufficiently 

below 1,000 lb CO2/MWh to allow for 

compliance with a 30-year averaging 

period. Such flexibility is likely to be 

most important for the first several CCS 

projects (i.e., ‘‘first movers’’) because of 

the complexity of integration of the 

technologies and the fact that the 

business model is new for the power 

sector. Because the policy purpose of 

this 30-year averaging compliance 

option is to leave open the option of 

building a coal-fired unit in the near 

term and installing CCS after several 

years or to allow for flexibility during 

startup of the system, a long-term 

averaging period is needed to allow time 

for such a unit to achieve the 1,000 lb 

CO2/MWh level. 

We note that under CAA section 

111(b)(1)(B), ‘‘the Administrator shall, at 

least every 8 years, review and, if 

appropriate, revise [the] standards [of 

performance] * * * ’’. This review is 

required to take place in 2020, if not 

sooner. In the event that the EPA adopts 

the 30-year averaging compliance 

option, then at the time of the next 

required review, the EPA will evaluate 

the state of development or 

commercialization of CCS technologies 

and make a determination as to whether 

or not the 30-year averaging approach is 

still warranted for new sources. Because 

we expect CCS technology to advance 

significantly over the next several years, 

we believe that it may not be necessary 

to include this type of compliance 

option for a 30-year average the next 

time we review this NSPS. In light of 

this, we further solicit comment as to 

whether the 30-year averaging 

compliance option should automatically 

terminate in 2020, so that it would be 

available only for facilities that 

commenced construction prior to 2020. 

We recognize that this compliance 

option, by authorizing sources to 

average the CO2 emission level over a 

30-year period, is unique. We recognize 

that the uniqueness of this approach 

may give rise to new issues concerning 

compliance and enforcement. We solicit 

comment on any practical difficulties in 

compliance and enforcement. Along 

these lines, although we propose that 

sources be required to retain records to 

demonstrate compliance with the 

emission limits for at least 30 years 

following the date of initial startup of 

the affected EGU, we solicit comment 

on the merits of extending this period to 

50 years. As with the proposed standard 

of performance, no averaging or 

emissions trading among affected 

sources would be allowed for this 30- 

year averaging compliance option. 

This 30-year averaging compliance 

option is available only to new coal- and 

pet coke-fired EGUs. We do not believe 

that it is necessary for NGCC units, as 

they should be able to meet the 

proposed performance with no need for 

add-on technology. We also solicit 

comment on the need to extend the 

applicability for the 30-year averaging 

compliance option to other fossil fuels 

beyond just coal and pet coke. We seek 

comment on all other aspects of this 30- 

year averaging compliance option. 

C. What are the startup, shutdown, and 

malfunction requirements? 

1. Startups and Shutdowns 

The NSPS that the EPA is proposing 

in this action would apply at all times, 

including during startups and 

shutdowns. In establishing the level of 

the proposed NSPS, the EPA has taken 

into account startup and shutdown 

periods. The EPA is not proposing 

different standards for those periods. 

To establish the proposed NSPS’s 

output-based CO2 standard, we 

accounted for periods of startup and 

shutdown by considering periods of 

part-load operation. As noted above, the 

proposed method to calculate 

compliance is to sum the emissions for 

all operating hours and to divide that 

value by the sum of the electrical energy 

output and useful thermal energy 

output, where applicable for CHP EGUs, 

over a rolling 12-month period. This 

averaging approach gives more weight 

to high-load hours and more accurately 

reflects overall environmental 

performance. In addition, because lowload hours do not factor as heavily into 

the calculated average, the impact of 

including periods of startup and 

shutdown is minimized when 

calculating emission rates. 

We solicit comment on the alternative 

of requiring compliance through an 

annual (calendar year) average. 

We propose that these same 

requirements for startups and 

shutdowns would apply to the 30-year 

averaging compliance option. 

2. Malfunctions 

The NSPS that the EPA is proposing 

in this action would apply at all times, 

including during malfunctions. Periods 

of startup, normal operations, and 

shutdown are all predictable and 

routine aspects of a source’s operations. 

By contrast, malfunction is defined as a 

‘‘sudden, infrequent, and not reasonably 

preventable failure of air pollution 

control and monitoring equipment, 

process equipment or a process to 

operate in a normal or usual manner 

* * * ’’(40 CFR 60.2). The EPA has 

determined that CAA section 111 does 

not require that emissions that occur 

during periods of malfunction be 

factored into development of CAA 

section 111 standards. Further, nothing 

in section 111 or in case law requires 

that the EPA anticipate and account for 


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43Note that the Ninth Circuit recently upheld 

EPA’s decision to apply this affirmative defense 

approach to only actions seeking civil penalties, 

and not also to actions seeking injunctive relief. 

Montana Sulfur & Chemical Co. v. EPA, No. 02– 

71657 (9th Cir. August 31, 2011) (slip op. at 456). 

the innumerable types of potential 

malfunction events in setting emission 

standards. See, Weyerhaeuser v. Costle, 

590 F.2d 1011, 1058 (DC Cir. 1978) (‘‘In 

the nature of things, no general limit, 

individual permit, or even any upset 

provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by regulation.’’) 

Further, it is reasonable to interpret 

CAA section 111 as not requiring the 

EPA to account for malfunctions in 

setting emissions standards. For 

example, we note that section 111 

provides that the EPA set standards of 

performance which reflect the degree of 

emission limitation achievable through 

‘‘the application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated. 

Applying the concept of ‘‘the 

application of the best system of 

emission reduction’’ to periods during 

which a source is malfunctioning 

presents difficulties. The ‘‘application of 

the best system of emission reduction’’ 

is more appropriately understood to 

include operating units in such a way as 

to avoid malfunctions. 

Further, accounting for malfunctions 

would be difficult, if not impossible, 

given the myriad different types of 

malfunctions that can occur across all 

sources in the category and given the 

difficulties associated with predicting or 

accounting for the frequency, degree, 

and duration of various malfunctions 

that might occur. As such, the 

performance of units that are 

malfunctioning is not ‘‘reasonably’’ 

foreseeable. See, e.g., Sierra Club v. 

EPA, 167 F.3d 658, 662 (DC Cir. 1999) 

(The EPA typically has wide latitude in 

determining the extent of data-gathering 

necessary to solve a problem. We 

generally defer to an agency’s decision 

to proceed on the basis of imperfect 

scientific information, rather than to 

‘‘invest the resources to conduct the 

perfect study.’’). In addition, the goal of 

a best controlled or best performing 

source is to operate in such a way as to 

avoid malfunctions of the source and 

accounting for malfunctions could lead 

to standards that are significantly less 

stringent than levels that are achieved 

by a well-performing nonmalfunctioning source. The EPA’s 

approach to malfunctions is consistent 

with section 111 and is a reasonable 

interpretation of the statute. 

In the event that a source fails to 

comply with the applicable CAA section 

111 standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 111 

standard was, in fact, ‘‘sudden, 

infrequent, not reasonably preventable’’ 

and was not instead ‘‘caused in part by 

poor maintenance or careless 

operation.’’ 40 CFR section 60.2 

(definition of malfunction). 

Finally, the EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause an 

exceedance of the relevant emission 

standard. (See, e.g., ‘‘State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown’’ 

(Sept. 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 

15, 1983), which are both included in 

the docket for this rulemaking.) The 

EPA is therefore proposing to add to the 

final rule an affirmative defense to civil 

penalties for exceedances of emission 

limits that are caused by malfunctions. 

See 40 CFR 60.10042 (defining 

‘‘affirmative defense’’ to mean, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding.). We also 

are proposing other regulatory 

provisions to specify the elements that 

are necessary to establish this 

affirmative defense: The source must 

prove by a preponderance of the 

evidence that it has met all of the 

elements set forth in 60.10001. (See 40 

CFR 22.24). The criteria ensure that the 

affirmative defense is available only 

where the event that causes an 

exceedance of the emission limit meets 

the narrow definition of malfunction in 

40 CFR 60.2 (sudden, infrequent, not 

reasonably preventable and not caused 

by poor maintenance and or careless 

operation). For example, to successfully 

assert the affirmative defense, the source 

must prove by a preponderance of the 

evidence that excess emissions ‘‘[w]ere 

caused by a sudden, infrequent, and 

unavoidable failure of air pollution 

control and monitoring equipment, 

process equipment, or a process to 

operate in a normal or usual manner 

* * *.’’ The criteria also are designed to 

ensure that steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with section 60.10001 and 

to prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the evidence that 

‘‘[r]epairs were made as expeditiously as 

possible when the applicable emission 

limitations were being exceeded * * *’’ 

and that ‘‘[a]ll possible steps were taken 

to minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health * * *.’’ 

In any judicial or administrative 

proceeding, the Administrator may 

challenge the assertion of the affirmative 

defense and, if the respondent has not 

met its burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with section 113 of the 

CAA (see also 40 CFR part 22.77). 

The EPA is including an affirmative 

defense in an attempt to balance a 

tension, inherent in many types of air 

regulation, to ensure adequate 

compliance while simultaneously 

recognizing that despite the most 

diligent of efforts, emission limits may 

be exceeded under circumstances 

beyond the control of the source. The 

EPA must establish emission standards 

that ‘‘limit the quantity, rate, or 

concentration of emissions of air 

pollutants on a continuous basis.’’ 42 

U.S.C. 7602(k) (defining ‘‘emission 

limitation and emission standard’’). See 

generally Sierra Club v. EPA, 551 F.3d 

1019, 1021 (DC Cir. 2008) Thus, the EPA 

is required to ensure that section 112 

emissions limitations are continuous. 

The affirmative defense for malfunction 

events meets this requirement by 

ensuring that even where there is a 

malfunction, the emission limitation is 

still enforceable through injunctive 

relief.43 While ‘‘continuous’’ 

limitations, on the one hand, are 

required, there is also case law 

indicating that in many situations it is 

appropriate for the EPA to account for 

the practical realities of technology. For 

example, in Essex Chemical v. 

Ruckelshaus, 486 F.2d 427, 433 (DC Cir. 

1973), the DC Circuit acknowledged that 

in setting standards under CAA section 

111 ‘‘variant provisions’’ such as 

provisions allowing for upsets during 

startup, shutdown and equipment 


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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 (DC Cir. 

1973). Though intervening case law 

such as Sierra Club v. EPA and the CAA 

1977 amendments undermine the 

relevance of these cases today, they 

support the EPA’s view that a system 

that incorporates some level of 

flexibility is reasonable. The affirmative 

defense simply provides for a defense to 

civil penalties for excess emissions that 

are proven to be beyond the control of 

the source. By incorporating an 

affirmative defense, the EPA has 

formalized its approach to upset events. 

In a Clean Water Act setting, the Ninth 

Circuit required this type of formalized 

approach when regulating ‘‘upsets 

beyond the control of the permit 

holder.’’ Marathon Oil Co. v. EPA, 564 

F.2d 1253, 1272–73 (9th Cir. 1977). But 

see, Weyerhaeuser Co. v. Costle, 590 

F.2d 1011, 1057–58 (DC Cir. 1978) 

(holding that an informal approach is 

adequate). The affirmative defense 

provisions give the EPA the flexibility to 

both ensure that its emission limitations 

are ‘‘continuous’’ as required by 42 

U.S.C. 7602(k), and account for 

unplanned upsets and thus support the 

reasonableness of the standard as a 

whole. 

We propose that these same 

requirements for malfunctions would 

apply to the 30-year averaging 

compliance option; however, we take 

comment on whether it is appropriate to 

have an affirmative defense for the 30- 

year averaging portion of that 

compliance option, given that we would 

expect malfunctions to only impact 

shorter emissions limits, and the longer 

the compliance period, the less likely 

malfunction events are to impact a 

source’s ability to meet the standard. 

D. What are the continuous monitoring 

requirements? 

The EPA is proposing that a CO2 mass 

rate CEMS and the associated automatic 

data acquisition and handling system 

must be installed and operated in 

accordance with the requirements 

below. 

1. Prepare a site-specific monitoring 

plan that addresses the monitoring 

system design, data collection, and the 

quality assurance and quality control 

elements consistent with the 

requirements in 40 CFR part 75. 

2. Use all the data collected during all 

other required data collection periods in 

assessing the operation of the control 

device and associated control system. 

3. Report any periods for which the 

monitoring system failed to collect 

required data. 

4. Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required monitoring system quality 

assurance or quality control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments); failure to collect required 

data is a deviation of the monitoring 

requirements. 

We propose that owners/operators 

would install the CEMS and complete 

the CEMS certification in accordance 

with the schedule required in 40 CFR 

part 75, section 75.4(b). 

We also request comment on the 

appropriateness of applying the backup 

monitor requirements in 40 CFR part 

75.10(e), the missing data procedures in 

40 CFR part 75, sections 75.31 through 

75.37, and appendix C for this proposed 

rule. 

We propose that these same 

monitoring requirements would apply 

to the 30-year averaging compliance 

option. 

E. What are the emissions performance 

testing requirements? 

Consistent with the performance 

testing requirements in the CAA section 

111 regulatory general provisions (40 

CFR part 60.8) and CEMS certification 

requirements (40 CFR part 75.4(b)), we 

propose that owners/operators of a new 

unit, conduct an initial performance test 

to demonstrate compliance with the CO2

emissions limits beginning in the 

calendar month following initial 

certification of the CO2 and flow rate 

monitoring CEMS. 

We propose that the initial 

performance test consist of collection of 

hourly CO2 average concentration, mass 

flow rate (standard cubic feet per hour) 

recorded with the certified CO2

concentration and flow rate CEMS and 

the corresponding electrical power 

generation data for all of the hours of 

operation for the first calendar year 

beginning on the first day of the first 

month following completion of the 

CEMS installation and certification. For 

all of the operating hours during each 

monthly period, including startup and 

shutdown, you would calculate 

compliance with the emissions limit by 

dividing the sum of the hourly CO2

mass values by the sum of the hourly 

useful energy output produced over the 

first 12 months of data. 

We propose that these same emissions 

performance testing requirements would 

apply to the 30-year averaging 

compliance option. 

F. What are the continuous compliance 

requirements? 

In this rulemaking, we propose that 

compliance with the applicable average 

CO2 mass emissions rate (lb/MWh) must 

be calculated as a 12-month rolling 

average, updated monthly, using the 

reported hourly CO2 average 

concentration and flow rate values from 

the certified CEMS data collected for the 

previous month’s process operating 

days along with generation data tracked 

by the facility for the unit. We propose 

that compliance with the emissions 

limit must be calculated by dividing the 

sum of the hourly CO2 mass emissions 

values by the sum of the useful energy 

output produced for each calendar 

month period and that the 12-month 

rolling average must be updated as the 

average of the previous 12 months’ 

calculations. Affected sources will 

continue to be subject to the standards 

and maintenance requirements in the 

section 111 regulatory general 

provisions. 40 CFR part 60, subpart A. 

We solicit comment on, in the 

alternative, an annual (calendar year) 

average emission limit, which would be 

calculated through comparable 

methodology as just described. 

We propose that these same 

continuous compliance requirements 

would apply to the 30-year averaging 

compliance option. 

G. What are the notification, 

recordkeeping, and reporting 

requirements? 

In this rulemaking, the EPA is 

proposing that you, as the owner or 

operator of a new unit, must comply 

with the notification and recordkeeping 

requirements in the section 111 

regulatory general provisions, 40 CFR 

part 60, subpart A, and need to report 

results of performance testing and 

excess emissions; as well as record and 

maintain hourly average CO2 emissions 

concentration, hourly average flow rate, 

and hourly useful electrical generation. 

Note that the summary form identified 

as Figure 1 in 40 CFR part 60.7(d) will 

be revised to include CO2 as a pollutant. 

We are also seeking comments on 

whether the EPA should require initial 

notification of compliance status 

reports. In most rules, an initial 

notification of compliance status report, 

where owners and operators of sources 

subject to a particular rule notify the 

EPA and State and Local Air Pollution 

Control Agencies that their source is 

subject to the rule and how they intend 

to comply with the rule, is required. 

Regulators find this information very 

helpful in implementing and enforcing 

particular rules. In this case, most, if not 


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all, of the sources that are potentially 

subject to this rule have already been 

identified because they are subject to 

other New Source Performance 

Standards and Part 75 Acid Rain 

provisions. 

As part of an Agency-wide effort to 

facilitate reporting of environmental 

data and reports, we are requiring 

electronic reporting of selected reports, 

required by this regulation, to the EPA. 

We are proposing that owners and 

operators subject to this regulation must 

electronically submit excess emissions, 

continuous monitoring systems 

performance and-or summary reports 

required under section 60.7(c). Owners 

and operators would need to submit 

these reports to the EPA’s WebFIRE 

database by using the Compliance and 

Emissions Data Reporting Interface 

(CEDRI) that is accessed in the Central 

Data Exchange (CDX). The CDX is the 

EPA’s portal for submitting and 

managing electronic environmental data 

and reports and is accessed at 

www.epa.gov/cdx. The CDX is needed to 

meet the EPA standards for electronic 

reporting set by the Cross-Media 

Electronic Reporting Rule. For more 

information, please see http:// 

www.epa.gov/cromerr/. Owners and 

operators required to submit electronic 

reports would need to register to use the 

CDX and for the CEDRI node at http:// 

cdx.epa.gov/epa_home.asp. Once a user 

has access to CDX and CEDRI, the 

owners and operators would use the 

subpart specific forms in CEDRI to enter 

the information for the 60.7(c) required 

reports. 

In most New Source Performance 

Standards owners and operators are 

required to keep records of their reports 

on site for at least 2 years. Since the 

owner or operator would be submitting 

the data in these reports to be housed in 

CDX and WebFIRE, we are proposing to 

forgo recordkeeping requirements for 

those reports required to be submitted 

in proposed section 60.5555(a)(1). We 

believe that since the WebFIRE database 

is public that the need for recordkeeping 

onsite for certain information will not 

be needed as the information will be 

readily available for all stakeholders to 

access. 

We are aware that owners or operators 

of many existing EGUs are required to 

submit some emissions data through the 

EPA Acid Rain Program’s Emissions 

Collection and Monitoring Plan System 

(ECMPS) for SO2, NOX, CO2, and other 

related data. We propose for affected 

sources to continue to use ECMPS with 

modifications to allow for collecting 

CO2 mass emissions data and the CEMS 

relative accuracy reports proposed in 

this rule. 

We request comment on these and 

other modifications to ECMPS 

appropriate for implementing this rule 

and any other EPA rules that apply to 

EGUs in order to streamline and focus 

all applicable emissions data reporting 

requirements. We request comment on 

modification of the ECMPS system to 

collect, track, and calculate CO2

emissions rates based on hourly useful 

energy output for the unit. We also 

request comment on tracking and 

making use of useful steam data for new 

facilities. 

We are also aware that owners or 

operators of existing units are required 

to submit electrical generation data 

according to procedures required by the 

DOE’s Energy Information 

Administration (EIA) for its reports. We 

request comment on the appropriateness 

of using these electrical generation data 

in this proposed rule. 

The EPA proposes that these same 

notice, recordkeeping, and reporting 

requirements would apply to the 30- 

year averaging compliance option. The 

EPA requests comment on whether any 

alterations or additions are appropriate 

for the notice, recordkeeping, and 

reporting requirements that would 

apply to the 30-year averaging 

compliance option. The EPA also 

requests comment on whether sources 

that utilize the 30-year averaging 

compliance option should include, as 

applicable requirements in their title V 

permits, a specific explanation of their 

compliance plan, including when CCS 

would be deployed, what capture rate(s) 

would be achieved, how the CO2 would 

be sequestered, and whether the 

company anticipates receiving 

government financial assistance or other 

incentives for the CCS. 

IV. Rationale for the Proposed 

Standards for New Sources 

A. How did the EPA establish the 

emission limits? 

1. Rationale for Proposing to Combine 

the Subpart Da Category and a 

Component of the Subpart KKKK 

Category into a New Category for 

Purposes of Regulating GHG Emissions 

The EPA is proposing to create a new 

subpart in 40 CFR part 60 by combining 

the sources in subpart Da (the Da 

category) and a subset of the sources in 

subpart KKKK (the KKKK category)— 

stationary combined cycle units, but not 

stationary simple cycle units—for 

purposes of promulgating standards of 

performance for emissions of GHGs 

from new sources. This new subpart 

will be numbered TTTT. Consistent 

with standard practice and Executive 

Order 13563, and in particular its 

emphasis on ‘‘the open exchange of 

information and perspectives’’ and 

‘‘providing an opportunity for public 

comment on all pertinent parts of the 

rulemaking docket, including relevant 

scientific and technical findings’’ and 

on consideration of alternatives, we 

invite comments on our decision to 

combine the two source categories. 

At this time, the EPA is not proposing 

to subcategorize new sources and is not 

proposing to combine the Da category 

and components of the KKKK category 

for purposes of regulating criteria 

pollutants. 

CAA section 111 provides legal 

authority for combining the categories 

into a new category. Clean Air Act 

section 111(b)(1)(A) provides: 

The Administrator shall, within 90 days 

after December 31, 1970, publish (and from 

time to time thereafter shall revise) a list of 

categories of stationary sources. He shall 

include a category of sources in such a list 

if in his judgment it causes or contributes 

significantly to air pollution which may 

reasonably be anticipated to endanger public 

health or welfare. 

(Emphasis added.) 

As quoted, this provision grants to the 

Administrator the authority to ‘‘revise’’ 

the list of categories. Combining 

categories, in whole or in part, is a form 

of ‘‘revis[ing]’’ the list of categories 

(along with taking other actions, such as 

adding more categories or delisting 

categories), and accordingly is 

authorized. 

For three principal reasons, it is 

appropriate for the EPA to combine the 

Da category and the stationary 

combined cycle component of the 

KKKK category at this time for purposes 

of regulating GHGs. First, all of the 

plants covered by the new combined 

category (including fossil fuel-fired 

boilers, IGCC units and NGCC units) 

perform the same essential function, 

which is to provide generation to serve 

baseload or intermediate load demand. 

It is sensible to treat as part of the same 

category units that generate baseload or 

intermediate load electricity, regardless 

of their design or fossil fuel type. 

Second, all newly constructed sources 

have options in selecting their design 

(although it is true that natural gas-fired 

plants are inherently lower emitting 

with regard to CO2 than coal-fired 

plants. As a result, prospective owners 

and operators of new sources could 

readily comply with the proposed 

emission standards by choosing to 

construct a NGCC unit. These two 

factors provide sufficient legal rationale 

for the EPA to combine the Da category 

and the combined cycle component of 

the KKKK category for purposes of 


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establishing a standard of performance 

for GHG emissions. 

The agency has previously combined 

one type of baseload and intermediate 

load combined cycle unit (IGCC, 

previously covered under Subpart GG) 

with Da units for the purposes of setting 

a standard [40 CFR 60.41Da(b), Feb. 28, 

2005]. This action now similarly 

combines another type of baseload and 

intermediate load combined cycle unit 

(NGCC, previously covered under 

Subpart KKKK) with Subpart Da units 

for the purposes of setting a standard. 

A third factor lends additional 

support. Combining the categories does 

not raise adverse policy concerns. On 

the basis of comments made during the 

listening sessions, we anticipate that 

some commenters may question 

whether combining the categories and 

applying the NGCC standard to all new 

plants within the combined category 

may limit construction of new coal-fired 

power plants, and thereby have a 

disruptive effect on the electric power 

industry, increase electricity prices and/ 

or have adverse implications for energy 

diversity in new generation. We do not 

believe that this action would have 

those effects. As discussed below, and 

importantly, economic models forecast 

no new construction of coal-fired 

generation without CCS through the 

analysis period, which extends until 

2020 (when the standard will be 

revisited). Accordingly, economic 

conditions are expected to be the main 

driver precluding, or at least limiting, 

construction of coal-fired EGUs. 

Because of those economic conditions, 

there is a strong independent movement 

of power plants serving baseload 

generation toward NGCC. In light of that 

movement, it is appropriate for the EPA 

to focus on this technology in 

developing the standard, rather than 

subcategorizing and providing a 

separate standard for new coal units. 

See Portland Cement Ass’n v. EPA, 665 

F.3d 177, 190 (D.C. Cir. 2011) (affirming 

the EPA’s decision not to subcategorize 

in part because of ‘‘the universal 

movement in the portland cement 

industry towards adoption of preheater/ 

precalciner technology’’). 

Notwithstanding these points, we 

recognize the possibility that a limited 

amount of new coal-fired construction 

may nevertheless occur. Today’s action 

would not foreclose construction of new 

coal-fired EGUs. Rather, the new coalfired EGUs that may be expected to be 

built in the foreseeable future (and for 

reasons stated above, this is anticipated 

to be a relatively small number) may 

install CCS control equipment (if not at 

the time of construction, then not long 

thereafter). By doing so, they may 

achieve the same average CO2 emission 

rate (at least over time) as a natural gasfired combined cycle unit. It is 

reasonable to expect that some coalfired power plants may be able to 

implement CCS at the present time, and 

thereby achieve the 1,000 lb CO2/MWh 

standard immediately. As noted 

elsewhere, CCS has been demonstrated 

to be technologically achievable, and, 

even though it is costly, there are some 

State and Federal programs that can 

make CCS more affordable. Several 

power companies have announced 

plans to incorporate CCS at six already 

permitted coal-fired EGU construction 

projects in this country (as we discuss 

below in section V.B., concerning 

transitional sources). Programs exist that 

provide some funding for CCS through 

pilot or other demonstration programs, 

and we expect those to continue. In 

addition, we reasonably expect the costs 

of CCS to decline over time. As 

discussed below, we are not proposing 

that CCS does or does not qualify as the 

‘‘best system of emission reduction’’ 

that ‘‘has been adequately 

demonstrated’’ for new coal-fired power 

plants. Rather, the feasibility of CCS and 

its availability for the limited amount of 

new coal-fired construction that may be 

expected, means that this action to 

combine the categories and establish the 

NSPS at the proposed 1,000 lb CO2/ 

MWh emission limit will not have 

notable adverse effects on new coalfired construction or, therefore, on the 

electric utility industry, electricity 

prices, or energy diversity. We welcome 

public comments on this discussion. 

On the other hand, at this time, we do 

not consider it appropriate to include 

simple cycle facilities as an affected 

source in the new 40 CFR part 60, 

subpart TTTT for GHG emissions from 

new facilities. The reason for this is that 

the function of a new simple cycle 

power plant is different than that of a 

new combined cycle plant or coal-fired 

plant. Combined cycle plants and coalfired plants are typically designed to 

provide baseload or intermediate-load 

power, while simple cycle turbines are 

designed to provide peaking power. 

Because combined cycle power plants 

and coal-fired power plants both serve 

the same purpose and have design 

options to emit CO2 at similar levels, we 

believe it is appropriate to combine 

them. Because peaking turbines operate 

less and because it would be much more 

expensive to lower their emission 

profile to that of a combined cycle 

power plant or a coal-fired plant with 

CCS, the EPA does not believe it is 

appropriate to include them in this 

source category. 

As noted above, some commenters in 

the listening sessions did suggest that 

the EPA not combine the two source 

categories. The EPA has rejected that 

option for all the reasons outlined 

above: (1) Fossil-fuel-fired boilers, 

combined cycle natural gas units, and 

IGCC units all serve the same basic 

function, generating baseload or 

intermediate load power; (2) the 

proposed standards can be met by 

different types of units in the category 

(NGCC units or coal-fired units with 

CCS); and (3) it is consistent with 

industry trends (as further explained 

elsewhere in this notice: Due largely to 

current and projected gas and coal price 

trends, new fossil-fuel-fired builds are 

projected to be natural gas combined 

cycle units or coal-fired units with CCS 

supported by federal funding). There is 

an additional reason for rejecting the 

option of retaining (and establishing 

separate standards for) separate source 

categories. The EPA’s analysis (in 

Section 5.10 of the RIA) suggests that 

over a wide range of market conditions, 

constructing a new unit that meets a 

limit of 1,000 lb CO2/MWh instead of an 

advanced coal-fired unit without CCS 

would likely produce net social 

benefits. For all of these reasons, 

retaining separate source categories 

would be unlikely to generate 

substantial private cost savings, but at 

the same time, would create the risk of 

significantly higher GHG emissions and 

other air pollutants from some new 

units, resulting, in turn, in higher social 

costs. 

By the same token, at this time, we do 

not consider it appropriate to combine 

the Da category and the combined cycle 

component of the KKKK category for 

any pollutants other than GHGs, that is, 

for criteria pollutants. This is because 

although coal-fired EGUs have an array 

of control options for criteria and air 

toxic air pollutants to choose from, 

those controls generally do not reduce 

their criteria and air toxic emissions to 

the level of conventional emissions from 

natural gas-fired EGUs. 

2. Endangerment and Cause-orContribute-Significantly Finding 

a. Overview. In today’s rulemaking, 

we propose or solicit comment on 

alternative interpretations for whether 

section 111 includes prerequisites to 

rulemaking that involve an 

endangerment finding and a cause-orcontribute-significantly finding. By its 

terms, CAA section 111 provides that 

once the EPA lists a source category for 

regulation because the category causes 

or contributes significantly to air 

pollution that may reasonably be 

anticipated to endanger public health or 


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welfare, the EPA then establishes 

requirements for new sources in that 

source category. The EPA proposes to 

interpret these provisions so that it is 

authorized to promulgate the 

rulemaking proposed today because it 

has already determined that both the Da 

and KKKK source categories cause or 

contribute significantly to air pollution 

that may reasonably be anticipated to 

endanger public health or welfare. The 

EPA solicits comment on interpreting 

CAA section 111 in the alternative so as 

to require (i) an endangerment finding 

for air pollution not specifically covered 

by the endangerment finding the EPA 

made when listing the source category, 

but that in this case, the EPA’s 2009 

Endangerment Finding for GHGs under 

Section 202(a) of the CAA (along with 

the EPA’s 2010 denial of petitions to 

reconsider (2010 Reconsideration 

Denial)), fulfills that requirement; and 

(ii) a cause-or-contribute-significantly 

finding for air pollutants not specifically 

covered by the cause-or-contributesignificantly finding the EPA made 

when listing the source category, and 

that in this case, the large amounts of 

CO2 emissions from power plants 

provide a compelling basis allowing the 

EPA to propose that finding. The EPA 

also solicits comment on another 

alternative, which is interpreting CAA 

section 111 so as not to require a 

specific endangerment finding or cause 

or contribute finding, but simply to 

require the EPA to establish a rational 

basis for regulating an air pollutant from 

a source category. In this case, the EPA’s 

2009 Endangerment Finding for GHGs 

and the 2010 denial of petitions to 

reconsider the Endangerment Finding, 

as well as the large amounts of CO2

emissions from power plants, provide 

that rational basis. Finally, as an 

alternative for the basis for a rational 

basis determination, the 2010 and 2011 

Assessment Reports from the National 

Academies confirm the Endangerment 

Finding and the denial of petitions to 

reconsider. 

b. Proposal: Previous Source Category 

Findings Meet Any Endangerment 

Prerequisite to Regulation. In this 

rulemaking, the EPA proposes to 

interpret CAA section 111 so that we are 

not required, as a prerequisite to 

regulating CO2 emissions from EGUs, to 

issue a new finding as to the health or 

welfare impacts of GHG air pollution or 

a finding as to the extent that affected 

sources contribute to that air pollution. 

Clean Air Act section 111(b)(1)(A), by 

its terms, requires that the 

Administrator list a source category for 

regulation if the ‘‘category * * * in [the 

Administrator’s] judgment, * * * 

causes or contributes significantly to air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare.’’ Clean Air Act section 

111(b)(1)(B) goes on to provide that after 

listing the source category, the EPA 

must promulgate regulations 

‘‘establishing federal standards of 

performance for new sources within 

such category.’’ In turn, CAA section 

111(a)(1) defines a ‘‘standard of 

performance’’ as a ‘‘standard for 

emissions of air pollutants which 

reflects the degree of emission reduction 

which (taking into account * * * cost 

* * * and any nonair quality health and 

environmental impact and energy 

requirements) * * * has been 

adequately demonstrated.’’ 

Thus, although CAA section 111 

clearly requires the EPA to list a source 

category if its emissions contribute 

significantly to air pollution that 

endangers public health or welfare, and 

then to promulgate standards of 

performance for particular pollutants, 

section 111 does not by its terms require 

that the EPA make any endangerment 

finding with respect to those particular 

pollutants, or any cause-or-contributesignificantly finding with respect to the 

source category, at the time the EPA 

promulgates the standards of 

performance for those pollutants. The 

lack of any such requirement contrasts 

with (i) the definition of ‘‘standard of 

performance,’’ which specifically 

requires the EPA to consider ‘‘nonair 

quality health and environmental 

impact,’’ CAA section 111(a)(1) 

(emphasis added); and (ii) other CAA 

provisions that do require the EPA to 

make endangerment and cause-orcontribute findings for the particular 

pollutant that the EPA regulates under 

those provisions. E.g., CAA sections 

202(a)(1), 211(c)(1), 231(a)(2)(A). 

Accordingly, under our proposal, 

once the EPA has listed a source 

category, and the EPA proceeds to 

regulate particular pollutants from that 

source category, CAA section 111 does 

not require that the EPA make an 

endangerment finding for the relevant 

air pollution or a cause-or-contributesignificantly finding for the relevant air 

pollutants from that source category. 

The fact that the EPA is, in this 

rulemaking, proposing to partially 

combine the Da and KKKK source 

categories does not alter this outcome. 

As noted above, under CAA section 

111(b)(1)(A), the EPA may add a source 

category to the list of categories only 

after determining that the source 

category ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ The EPA has 

previously determined that each of the 

Da and KKKK categories causes or 

contributes significantly to such air 

pollution. Combining the Da category 

and some of the sources in the KKKK 

category does not necessitate that the 

EPA make a new cause-or-contributesignificantly finding for the expanded 

Da category. This is because the EPA 

has already found that at least one 

component of the new category—the 

former Da sources—by itself causes or 

contributes significantly to such air 

pollution. There is no reason why this 

expansion of the Da category to include 

the pre-existing Da sources plus 

additional sources could be considered 

to contribute to such air pollution to an 

extent that is less than the contribution 

from the pre-existing Da sources alone. 

As a result, the new category must 

necessarily be considered to cause or 

contribute significantly to such air 

pollution. 

In addition to proposing this 

interpretation, we also solicit comment 

on alternative interpretations under 

CAA section 111, including those 

described next. 

c. First Alternative Interpretation: 

Endangerment Finding Prerequisite. We 

solicit comment on an alternative 

interpretation under which the EPA is 

required, as a prerequisite to 

promulgating standards of performance 

under CAA section 111(b), to have 

issued an endangerment finding 

specifically for the relevant air pollution 

and a cause-or-contribute-significantly 

finding specifically for the relevant 

source category and air pollutant. In 

particular, what would be the legal basis 

for such an interpretation? 

Even if CAA section 111 is interpreted 

to require those findings, then, in a case 

in which the EPA did not make those 

findings under CAA section 111, it is 

the EPA’s view that the EPA would 

satisfy the need for a CAA section 111 

endangerment finding through an 

endangerment or comparable finding 

that the EPA made or that Congress 

adopted under any other provision of 

the CAA. For example, the EPA may 

regulate, under CAA section 111, (i) 

NAAQS pollutants because of the 

determinations the EPA made under 

CAA sections 108 and 109 and (ii) HAPs 

that Congress listed under CAA section 

112(b)(1). It is the EPA’s interpretation 

that once an endangerment or 

comparable finding is made with 

respect to the relevant air pollution 

under another CAA provision, 

regulation under CAA section 111 of 

source categories that cause or 

contribute significantly to that same air 

pollution may proceed without any 

need for the EPA to revisit or update 

that endangerment finding as part of the 


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44Levelized Cost of New Generation in the 

Annual Energy Outlook 2011 http://205.254.135.24/ 

oiaf/aeo/electricity_generation.html. 

45http://www.eia.gov/forecasts/aeo/ 

chapter_legs_regs.cfm. 

CAA section 111 regulatory process. 

Instead, any concerns about the 

continued validity of that endangerment 

finding may be resolved through a 

petition to reconsider that finding under 

the applicable CAA provision. 

Applying this alternative 

interpretation of CAA section 111 to this 

rulemaking, the 2009 Endangerment 

Finding for GHG air pollution fulfills 

any requirement under CAA section 111 

that the EPA issue a finding that GHG 

air pollution may reasonably be 

anticipated to endanger public health or 

welfare in order for the EPA to establish 

standards of performance for GHG 

emissions from EGUs. As discussed 

above, the EPA already issued this 

endangerment finding under CAA 

section 202(a)(1), as part of its process 

for promulgating the Light Duty Vehicle 

Rule. 

The EPA recognizes that under this 

alternative interpretation, the EPA could 

be required to issue a cause-orcontribute-significantly finding for CO2

emissions from the fossil fuel-fired 

EGUs, as a prerequisite to regulating 

such emissions under CAA section 111. 

Therefore, under this alternative 

interpretation, in today’s rulemaking, 

the EPA proposes to find that CO2

emissions from fossil fuel-fired EGUs 

cause or contribute significantly to the 

GHG air pollution. The EPA’s basis for 

this proposed finding is, in part, that the 

large amounts of CO2 emitted by fossil 

fuel-fired EGUs clearly exceed the low 

hurdle necessary for the cause-orcontribute-significantly finding. As 

noted above in Tables 2 and 3, 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. 

Indeed, so great is the contribution of 

CO2 air pollutants from EGUs to GHG 

air pollution, that it is simply not 

necessary in this rulemaking to 

determine thresholds for when a 

contribution may be considered to be a 

‘‘significant[]’’ contribution. If it were 

necessary, the EPA proposes that a 

limited amount of contribution would 

meet that standard in light of the fact 

that GHG air pollution is caused by a 

large number of types of sources and 

that no one source category dominates 

the entire inventory. 

d. Second alternative interpretation: 

Rational Basis Prerequisite. As a second 

alternative interpretation, the lack of 

any requirement in CAA section 111 

addressing whether and how the EPA is 

to evaluate emissions of particular 

pollutants from sources in the listed 

source category as a prerequisite for 

regulation may be viewed as a statutory 

gap that requires a Chevron step 2 

interpretation. In this case, the EPA is 

authorized to develop an interpretation 

that reasonably effectuates the purposes 

of CAA section 111. Under this 

alternative interpretation, the EPA must 

demonstrate a rational basis for 

controlling the emissions of the 

particular pollutants. That rational basis 

may consist of some type of factual 

showing that is consistent with the 

purposes of CAA section 111, but may 

be something short of an endangerment 

and a cause-or-contribute-significantly 

finding. 

There are several options for the 

factual showings that comprise a 

rational basis. Under the first option, the 

EPA would be justified in the present 

case in taking action with respect to 

GHG air pollution because of the EPA’s 

2009 Endangerment Finding that GHG 

air pollution may reasonably be 

anticipated to endanger public health 

and welfare. The EPA issued that 

Endangerment Finding quite recently, in 

December, 2009, and by notice dated 

August 13, 2010, the EPA denied ten 

petitions to reconsider that Finding, an 

action that entailed further review of 

scientific information. 

Under the second option, the EPA 

could conclude that the recent 

Endangerment Finding and denial of 

reconsideration, coupled with the even 

more recent assessments from the NAS, 

published in 2010 and 2011, which lend 

further credence to the science 

supporting the Endangerment Finding, 

suffice to provide a rational basis for 

promulgating regulations under CAA 

section 111 designed to address 

contributions to the GHG air pollution. 

Under either of these options, the EPA 

would need to establish a rational basis 

for regulating CO2 emissions from 

affected EGUs. The fact that affected 

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

GHGs and comprise by far the largest 

stationary source category of GHG 

emissions, as discussed above, would 

readily provide such a rational basis. 

3. Rationale for Emission Limits 

a. Few New Coal-fired Power Plants. 

An important part of the basis for the 

EPA’s proposal for new sources in this 

rulemaking is that all indications 

suggest that very few new coal-fired 

power plants will be constructed in the 

foreseeable future. Although a small 

number of new coal-fired power plants 

have been built recently, the industry 

generally is not building these kinds of 

power plants at present and is not 

expected to do so for the foreseeable 

future. The reasons include the current 

economic environment, which has lead 

to lower electricity demand, and 

competitive natural gas prices. Natural 

gas prices have stabilized over the past 

few years as new drilling techniques 

have brought additional supply to the 

marketplace. As a result, natural gas 

prices are expected to be competitive for 

the foreseeable future and utilities are 

likely to rely heavily on natural gas to 

meet new demand for electricity 

generation. On average, the cost of 

generation from a new NGCC power 

plant is expected to be lower than the 

cost of generation from a new coal-fired 

power plant.44

Other drivers that may influence 

decisions to build new power plants are 

State and Federal energy and tax 

policies. Many states have adopted 

renewable portfolio standards (RPS), 

which require that a certain portion of 

electricity come from renewable energy 

sources like solar or wind. The federal 

government has also adopted incentives 

for electric generation from renewable 

energy sources and loan guarantees for 

new nuclear power plants. 

These economic, cost, and policy 

factors create an environment in which 

natural gas-fired power plants, 

renewable energy, and nuclear power 

are the forms of energy generation that 

are most often predicted to be built to 

meet new electricity demand over the 

coming years. 

Various energy sector modeling 

efforts, including projections from both 

the EIA and the EPA, show results that 

are consistent with these findings. The 

Annual Energy Outlook (AEO) for 2011 

shows a very modest amount of new 

coal-fired power coming online beyond 

2012, although there are a number of 

coal-fired power plants that are 

currently under construction and 

expected to begin operation in the next 

year or two. According to the AEO 2011, 

the majority of new generating capacity 

will be either natural gas-fired or 

renewable, with some lesser amounts of 

nuclear power. The AEO 2011 is based 

on existing policy and regulations, such 

as state RPS programs and Federal tax 

credits for renewables.45 The new 

generation that EIA does show coming 

on-line after 2012 fits into one of three 

categories: generation that is currently 

under construction, generation that will 

include CCS or industrial CHP. Units in 

the first group would not be subject to 

this rule because, since they have 

commenced construction, they are 

considered existing sources. Units in the 

second group would include either 

units in the transitional category or new 


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46http://www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html#documentation. 

units. In either case, they could be built 

consistent with this action. Units in the 

third group would not be subject to this 

rule because CHP units that generate 

primarily on-site power are not 

considered EGUs and are thus not 

affected by the rule. 

The EPA modeling using the 

Integrated Planning Model (IPM), a 

detailed power sector model that the 

EPA uses to support power sector 

regulations, is keyed to the AEO in a 

number of respects and shows similar 

patterns of little future construction of 

new coal-fired power plants under the 

base case.46 The EPA’s projections from 

IPM can be found in the RIA. 

As discussed below, the fact that the 

expected number of coal-fired power 

plants is so limited supports both (i) 

basing the standard of performance on 

NGCC, which is expected to be the most 

commonly built new fossil fuel-fired 

generating technology; and (ii) allowing 

30-year averaging as an alternative 

compliance option for coal- and pet 

coke-fired power plants because CCS is 

feasible and sufficiently available for the 

few such plants expected, in light of the 

demonstration programs or other 

incentives available for CCS, coupled 

with the prospects that the costs of CCS 

will decline over time. 

b. Basis for the Proposed Standard of 

Performance. In this section, we 

describe our basis for proposing a 

standard of 1,000 lb/MWh, and for 

taking comment on a range of 950 to 

1,100 lb/MWh (430 to 500 kg/MWh). We 

first describe our method for calculating 

these levels of CO2 emissions, and then 

note that several states are already 

requiring these levels of CO2 emissions. 

(1) Calculation of the Standard. For 

reasons explained below (see ‘‘d. Legal 

Justification for the Standard of 

Performance and 30-year averaging 

compliance option’’), a NGCC facility is 

the best system of emission reduction 

for new baseload and intermediate load 

EGUs. To establish an appropriate, 

natural gas-based standard, we reviewed 

the emissions rate of natural gas-fired 

(non-CHP) combined cycle facilities 

used in the power sector that 

commenced operation between 2006 

and 2010 and that report complete 

generation data to EPA. Based on this 

analysis, nearly 95% of these facilities 

meet the proposed standards on an 

annual basis. These units represent a 

wide range of geographic locations (with 

differing elevations and ambient 

temperatures), operational 

characteristics, and sizes. 

We are requesting comment on a 

range of 950 to 1,100 lb/MWh (430 to 

500 kg/MWh) for the final rule. The 

upper limit would incorporate 

essentially all available new combined 

cycle designs and would have limited 

impact on improving efficiency of 

combined cycle facilities. This upper 

limit would also be consistent with 

standards promulgated by some states, 

as noted elsewhere. The stricter 

standard would in general eliminate 

designs without a steam reheat cycle 

and similar lower efficiency designs for 

use in electric-only generation, and 

could limit presently available options 

for generation below approximately 40 

MW. However, an owner/operator of 

combined cycle facilities with higher 

heat rates could either implement CHP 

or integrated solar thermal for feedwater 

heating to achieve the proposed 

standard. 

(2) States Implementing a Comparable 

Standard. Several states have recently 

established emission performance 

standards or other measures to limit 

emissions of GHGs from new EGUs that 

are comparable to the proposal in this 

rulemaking. For example, in September 

2006, California Governor 

Schwarzenegger signed into law Senate 

Bill 1368. The law limits long-term 

investments in baseload generation by 

the state’s utilities to power plants that 

meet an emissions performance 

standard jointly established by the 

California Energy Commission and the 

California Public Utilities Commission. 

The Energy Commission has designed 

regulations that establish a standard for 

new and existing baseload generation 

owned by, or under long-term contract 

to publicly owned utilities, of 1,100 lb 

CO2/MWh. 

In May 2007, Washington Governor 

Gregoire signed Substitute Senate Bill 

6001, which established statewide GHG 

emissions reduction goals, and imposed 

an emission standard that applies to any 

baseload electric generation that 

commenced operation after June 1, 2008 

and is located in Washington, whether 

or not that generation serves load 

located within the state. Baseload 

generation facilities must initially 

comply with an emission limit of 1,100 

lb CO2/MWh. 

In July 2009, Oregon Governor 

Kulongoski signed Senate Bill 101, 

which mandated that facilities 

generating baseload electricity, whether 

gas- or coal-fired, must have emissions 

equal to or less than 1,100 lb CO2/MWh, 

and prohibited utilities from entering 

into long-term purchase agreements for 

baseload electricity with out-of-state 

facilities that do not meet that standard. 

Natural gas- and petroleum distillatefired facilities that are primarily used to 

serve peak demand or to integrate 

energy from renewable resources are 

specifically exempted from the 

performance standard. 

c. Basis for CCS as a Feasible 

Technology Option. In this section, we 

describe the basis for our position that 

CCS is a feasible technology option for 

new coal-fired power plants because 

CCS is technically feasible and 

sufficiently available in light of the 

limited amount of new coal-fired 

construction expected in the foreseeable 

future. In brief, first, at present, CCS is 

technologically feasible for 

implementation at new coal-fired power 

plants and its core components (CO2

capture, compression, transportation 

and storage) have already been 

implemented at commercial scale. 

Second, although the costs of CCS are 

presently high, we have reason to expect 

that the costs of CCS will decrease over 

time. This action will itself contribute to 

downward pressure on CCS costs by 

shifting the regulatory landscape 

towards CCS, consistent with the recent 

report by the Interagency Task Force on 

Carbon Capture and Storage, established 

by President Obama on February 3, 

2010, which we describe below. Third, 

we expect construction of no more than 

a few new coal-fired power plants by 

2020 and those plants may well be able 

to take advantage of demonstration 

programs or other sources of funding for 

CCS. Fourth, several states have set 

emission standards that will make 

implementation of CCS necessary for 

new coal-fired power plants, some 

projects that implement CCS or 

components of it are proceeding, and 

other CCS projects are in the planning 

stages. 

(1) Technological Feasibility of CCS. 

The current state of affairs concerning 

CCS was described and analyzed by the 

Interagency Task Force on Carbon 

Capture and Storage, established by 

President Obama on February 3, 2010, 

co-chaired by the DOE and the EPA, and 

composed of 14 executive departments 

and federal agencies. The Task Force 

was charged with proposing a plan to 

overcome the barriers to the 

widespread, cost-effective deployment 

of CCS within 10 years, with a goal of 

bringing five to ten commercial 

demonstration projects online by 2016. 

The Task Force found that, although 

early CCS projects face economic 

challenges related to climate policy 

uncertainty, first-of-a-kind technology 

risks, and the current high cost of CCS 

relative to other technologies, there are 

no insurmountable technological, legal, 

institutional, regulatory or other barriers 

that prevent CCS from playing a role in 


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47Report of the Interagency Task Force on Carbon 

Capture and Storage (August 2010). 48 IPCC, 2005; DOE, 2007. 49 JJ Dooley, CL Davidson, RT Dahowski, MA 

Wise, N Gupta, SH Kim, EL Malone (2006), Carbon 

Dioxide Capture and Geologic Storage: A Key 

Component of a Global Energy Technology Strategy 

to Address Climate Change. Joint Global Change 

Research Institute, Battelle Pacific Northwest 

Division. PNWD–3602. College Park, MD. 

50These projects are: Sleipner in the North Sea, 

Sn<hvit in the Barents Sea, In Salah in Algeria, and 

Weyburn in Canada. 

51 Dooley, J. J., et al. (2009). An Assessment of the 

Commercial Availability of Carbon Dioxide Capture 

and Storage Technologies as of June 2009. U.S. 

Department of Energy, Pacific Northwest National 

Laboratory, under Contract DE–AC05–76RL01830. 

52U.S. Department of Energy National Energy 

Technology Laboratory (2010). Carbon 

Sequestration Atlas of the United States and 

Canada, Third Edition. 

53Federal Requirements under the Underground 

Injection Control (UIC) Program for Carbon Dioxide 

(CO2) Geologic Sequestration (GS) Wells, Final 

Rule, 75 FR 77230 (Dec. 10, 2010). 

54Mandatory Reporting of Greenhouse Gases: 

Injection and Geologic Sequestration of Carbon 

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

55Hazardous Waste Management System: 

Identification and Listing of Hazardous Waste: 

Carbon Dioxide (CO2) Streams in Geologic 

Sequestration Activities, Proposed Rule, 76 FR 

48073 (Aug. 8, 2011). 

reducing GHG emissions. The Task 

Force also identified the need for 

comprehensive review of the overall 

environmental impacts of CCS. 

(a) Capture and Compression 

Technologies and Costs. Capture of CO2

from industrial gas streams has occurred 

since the 1930s using a variety of 

approaches to separate CO2 from other 

gases. These processes have been used 

in the natural gas industry and to 

produce food and chemical-grade CO2. 

Although current capture technologies 

are feasible, the costs of CO2 capture 

and compression represent the largest 

stumbling block to widespread 

commercialization of CCS. Currently 

available CO2 capture and compression 

processes are estimated to represent 

seventy to ninety percent of the overall 

CCS costs.47

In general, CO2 capture technologies 

applicable to coal-fired power 

generation can be categorized into three 

approaches: 48

• Pre-combustion systems are 

designed to separate CO2 and H2 in the 

high-pressure syngas produced at IGCC 

power plants. 

• Post-combustion systems are 

designed to separate CO2 from the flue 

gas produced by fossil-fuel combustion 

in air. 

• Oxy-combustion uses high-purity 

O2, rather than air, to combust coal and 

therefore produces a highly 

concentrated CO2 stream. 

Each of these three carbon capture 

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

technologically feasible. However, each 

results in increased capital and 

operating costs and decreased electricity 

output (that is, an energy penalty), with 

a resulting increase in the cost of 

electricity. The energy penalty occurs 

because the CO2 capture process uses 

some of the energy produced from the 

plant. 

(b) Current Availability of 

Transportation and Sequestration. The 

remaining steps for CCS (i.e., pipeline 

transportation and storage), are also well 

established but less expensive than 

capture and compression. 

Carbon dioxide has been transported 

via pipelines in the U.S. for nearly 40 

years. Approximately 50 million metric 

tons of CO2 are transported each year 

through 3,600 miles of pipelines. 

Moreover, a review of the 500 largest 

CO2 point sources in the U.S. shows that 

95 percent are within 50 miles of a 

possible geologic sequestration site,49

which would lower transportation costs. 

For these reasons, the transportation 

component of CCS is not expected to be 

a significant stumbling block to the 

commercial availability of CCS in the 

future. 

With respect to sequestration, 

globally, there are at least four 

commercial integrated CCS facilities 

sequestering captured CO2 into deep 

geologic formations and applying a suite 

of technologies to monitor and verify 

that the CO2 remains sequestered.50

These four sites represent over 25 years 

of cumulative experience on safely and 

effectively storing anthropogenic CO2 in 

appropriate deep geologic formations.51

Estimates based on DOE studies indicate 

that areas of the U.S. with appropriate 

geology have a storage potential of 1,800 

billion to more than 20,000 billion 

metric tons of CO2 in deep saline 

formations, oil and gas reservoirs and 

un-mineable coal seams.52 The U.S. 

experience with large-scale CO2

injection, such as at enhanced oil and 

gas recovery projects, combined with 

ongoing research, development, and 

demonstration programs in the U.S. and 

throughout the world, provide 

confidence that the storage—along with 

capture, compression and transport—of 

large amounts of CO2 can be achieved. 

It should be noted that the EPA 

recently finalized two rules that aim to 

protect drinking water and track the 

amount of CO2 that is sequestered from 

facilities that carry out geologic 

sequestration. The Underground 

Injection Control (UIC) Class VI rule, 

established under authority of the Safe 

Drinking Water Act, sets requirements 

to ensure that geologic sequestration 

wells are appropriately sited, 

constructed, tested, monitored, and 

closed in a manner that ensures 

protection of underground sources of 

drinking water.53 The UIC Class VI 

regulations contain monitoring 

requirements to protect underground 

sources of drinking water, including the 

development of a comprehensive testing 

and monitoring plan. This includes 

testing of the mechanical integrity of the 

injection well, ground water monitoring, 

and tracking of the location of the 

injected CO2 using direct and indirect 

methods. Projects are also required to do 

extended post-injection monitoring and 

site care to track the location of the 

injected CO2 and monitor subsurface 

pressures until it can be demonstrated 

that underground sources of drinking 

water are no longer endangered. Subpart 

RR of the Greenhouse Gas Reporting 

Program, which was established under 

authority of the CAA and builds on UIC 

requirements, provides requirements for 

quantifying the amount of CO2

sequestered by these facilities.54 In 

addition, the EPA recently proposed a 

rule that would conditionally exclude 

CO2 streams from the definition of 

hazardous waste under RCRA, where 

these streams are being injected for 

purposes of geologic sequestration, 

provided that they are managed in 

accordance with certain conditions.55

That proposed rule is based upon the 

EPA’s conclusion that the management 

of CO2 streams, under the proposed 

conditions, does not present a 

substantial risk to human health or the 

environment, and was based upon a 

review of existing regulatory programs 

applicable to the transportation of CO2

streams, and their injection into 

permitted UIC Class VI wells. Together, 

these actions help create a consistent 

national framework to ensure the safe 

and effective deployment of geologic 

sequestration. 

(2) Expected reduction in CCS costs. 

Research is underway to reduce CO2

capture costs and to improve 

performance. The DOE/National Energy 

Technology Laboratory (NETL) sponsors 

an extensive research, development and 

demonstration program that is focused 

on developing advanced technology 

options that will dramatically lower the 

cost of capturing CO2 from fossil-fuel 

energy plants compared to today’s 

available capture technologies. The 

DOE/NETL estimates that using today’s 

commercially available CCS 

technologies would add around 80 

percent to the cost of electricity for a 

new pulverized coal (PC) plant, and 

around 35 percent to the cost of 

electricity for a new advanced 


pmangrum on DSK3VPTVN1PROD with PROPOSALS2
22416 Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 

56 DOE/NETL Carbon Dioxide Capture and 

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

National Energy Technology Laboratory, December 

2010. 

57These studies include John M. Dutton and 

Annie Thomas, ‘‘Treating Progress Functions as a 

Managerial Opportunity,’’ 2, 235–247; Dennis 

Epple, Linda Argote, and Rukmini Devadas, 

‘‘Organizational Learning Curves: A Method for 

Investigating Intra-plant Transfer of Knowledge 

Acquired Through Learning by Doing,’’ 

Organizational Science, Vol. 2, No. 1, February 

1991; International Energy Agency, Experience 

Curves for Energy Technology Policy, 2000; and 

Paul L. Joskow and Nancy L. Rose, ‘‘The Effects of 

Technological Change, Experience, and 

Environmental Regulation on the Construction Cost 

of 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. 

58Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; 

Davison, J.; ‘‘Use of experience curves to estimate 

the future cost of power plants with CO2 capture’’, 

Intl. J. of Greenhouse Gas Control, 1, 188 (2007). 

59 Van den Broek, M.; Hoefnagels, R.; Rubin, E.; 

Turkenburg, W.; Faaij, A.; ‘‘Effects of technological 

learning on future cost and performance of power 

plants with CO2 capture’’, Progress in Energy and 

Combustion Science 35 (2009) 457–480. 

60See Center for Climate and Energy Solutions, 

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

www.c2es.org/sites/default/modules/usmap/ 

pdf.php?file=8380. 

61 Dooley, J.J., et al. (2009). An Assessment of the 

Commercial Availability of Carbon Dioxide Capture 

and Storage Technologies as of June 2009. U.S. 

gasification-based (IGCC) plant. The 

CCS research, development and 

demonstration program is aggressively 

pursuing efforts to reduce these costs to 

a less than 30 percent increase in the 

cost of electricity for PC power plants 

and a less than 10 percent increase in 

the cost of electricity for new 

gasification-based power plants.56 The 

large-scale CO2 capture demonstrations 

that are currently planned and in some 

cases underway, under DOE’s 

initiatives, as well as other domestic 

and international projects, will generate 

operational knowledge and enable 

continued commercialization and 

deployment of these technologies. 

Gas absorption processes using 

chemical solvents, such as amines, to 

separate CO2 from other gases have been 

in use since the 1930s in the natural gas 

industry and to produce food and 

chemical grade CO2. The advancement 

of amine-based solvents is an example 

of technology development that has 

improved the cost and performance of 

CO2 capture. Most single component 

amine systems are not practical in a flue 

gas environment as the amine will 

rapidly degrade in the presence of 

oxygen and other contaminants. The 

Fluor Econamine FG process uses a 

monoethanolamine (MEA) formulation 

specially designed to recover CO2 and 

contains a corrosion inhibitor that 

allows the use of less expensive, 

conventional materials of construction. 

Other commercially available processes 

use sterically hindered amine 

formulations (for example, the 

Mitsubishi Heavy Industries KS–1 

solvent) which are less susceptible to 

degradation and corrosion issues. The 

DOE/NETL and private industry are 

continuing to sponsor research on 

advanced solvents (including new 

classes of amines) to improve the CO2

capture performance and reduce costs. 

Significant reductions in the cost of 

CO2 capture would be consistent with 

overall experience with the cost of 

pollution control technology. A 

significant body of literature suggests 

that the per-unit cost of producing or 

using a given technology declines as 

experience with that technology 

increases over time,57 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, research and 

development investments, and other 

factors have been observed over the 

decades. 

We expect that the costs of capture 

technology will follow this pattern. 

Rubin et al. assessed the historical rates 

of cost reductions achieved by other 

energy and environmental process 

technologies and then, by analogy, 

estimated future cost reductions that 

might be achieved by four types of new 

power plants employing CO2 capture.58

The results of the study suggested that 

total costs of CO2 capture can be 

expected to decline by the following 

percentages: NGCC by 40 percent, PC by 

26 percent, IGCC by 13 percent, and 

Oxyfuel by 13 percent after installation 

of the first 100 GW of capacity. 

In a subsequent study, the model used 

in the initial study was extended with 

learning curves for several key 

performance variables, including overall 

energy loss in power plants, the energy 

required for CO2 capture, the CO2

capture ratio (removal efficiency) and 

the power plant availability. The model 

predicted continued reductions in cost 

with increased implementation.59

In addition, we note that the 

Administration’s CCS Task Force report 

recognized that CCS would not become 

more widely available without the 

advent of a regulatory framework that 

promoted CCS or a strong price signal 

for CO2. Today’s action is an important 

component in developing that 

framework. 

(3) Limited amount of construction of 

new coal-fired power plants; 

opportunities for CCS funding. A third 

factor that supports CCS as a feasible 

technology option is that through the 

IPM model period of up to 2020, we 

expect few, if any, new builds of coalfired EGUs, beyond those that already 

have approved PSD permits. We also 

expect continued opportunities for 

financial support for some CCS projects 

through a variety of potential 

mechanisms such as direct grants, tax 

incentives and/or regulatory programs 

(e.g. Clean Energy Standards or 

guaranteed electricity purchase price 

agreements).60 Accordingly, the few 

new coal-fired generation projects that 

may occur over this timeframe may well 

find that financial support for CCS is 

available. 

(4) State Requirements for CCS; 

Projects and Permits for CCS. Several 

states have recently established 

requirements that new coal-fired EGUs 

must implement CCS, and a number of 

projects with CCS have been approved 

and/or are under construction. 

In May 2007, Montana Governor 

Schweitzer signed House Bill 25, 

adopting a CO2 emissions performance 

standard for electric generating units in 

the state. House Bill 25 prohibits the 

state Public Utility Commission from 

approving new electric generating units 

primarily fueled by coal unless a 

minimum of 50 percent of the CO2

produced by the facility is captured and 

sequestered. 

On January 12, 2009, Illinois 

Governor Blagojevich signed Senate Bill 

1987, the Clean Coal Portfolio Standard 

Law. The legislation establishes 

emission standards for new power 

plants that use coal as their primary 

feedstock. From 2009–2015, new coalfueled power plants must capture and 

store 50 percent of the carbon emissions 

that the facility would otherwise emit; 

from 2016–2017, 70 percent must be 

captured and stored; and after 2017, 90 

percent must be captured and stored. 

The following is a brief summary of 

currently operating or planned CO2

capture or storage systems, including, in 

some cases, components necessary for 

coal-based power plant CCS 

applications. 

AES’s coal-fired Warrior Run 

(Cumberland, MD) and Shady Point 

(Panama, OK) power plants are 

equipped with amine scrubbers 

developed by ABB/Lummus. They were 

designed to process a relatively small 

percentage of each plant’s flue gas. At 

Warrior Run, approximately 110,000 

tonnes of CO2 per year are captured, 

whereas at Shady Point 66,000 tonnes of 

CO2 per year are captured. The CO2

from both plants is subsequently used in 

the food processing industry.61


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DOE, Pacific Northwest National Laboratory, under 

Contract DE–AC05–76RL01830. 

62 IEA (2009a), World Energy Outlook 2009, 

OECD/IEA, Paris. 

At the Searles Valley Minerals soda 

ash plant in Trona, CA, approximately 

270,000 tonnes of CO2 per year are 

captured from the flue gas of a coal 

power plant via amine scrubbing and 

used for the carbonation of brine in the 

process of producing soda ash.62

A pre-combustion Rectisol® system is 

used for CO2 capture at the Dakota 

Gasification Company’s synthetic 

natural gas production plant located in 

North Dakota, which is designed to 

remove approximately 1.6 million 

tonnes of CO2 per year from the 

synthesis gas. The CO2 is purified, 

transported via a 200-mile pipeline, and 

injected into the Weyburn oilfield in 

Saskatchewan, Canada. 

In September 2009, American Electric 

Power Co. (AEP) began a pilot-scale CCS 

demonstration at its Mountaineer Plant 

in New Haven, WV. The Mountaineer 

Plant is a 1,300 MWe coal-fired unit that 

was retrofitted with Alstom’s patented 

chilled ammonia CO2 capture 

technology on a 20 MWe portion, or 

‘‘slipstream’’, of the plant’s exhaust flue 

gas. In May 2011, Alstom Power 

announced the successful operation of 

the chilled-ammonia CCS validation 

project. The AEP–Alstom project, the 

world’s first facility to both capture and 

store CO2 from a coal-fired power plant, 

represents a successful scale-up of ten 

times the size of previous field pilots 

(e.g., at We Energies Pleasant Prairie). 

The demonstration achieved capture 

rates from 75 percent (design value) to 

as high as 90 percent, produced CO2 at 

purity of greater than 99 percent, with 

energy penalties within a few percent of 

predictions. The facility reported robust 

steady-state operation during all modes 

of power plant operation including load 

changes, and saw an availability of the 

CCS system of greater than 90 percent. 

AEP, with assistance from the DOE, 

had planned to expand the slipstream 

demonstration to a commercial scale, 

fully integrated demonstration at the 

Mountaineer facility. The 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 is terminating its 

cooperative agreement with the DOE 

and placing its plans to advance CO2

capture and storage technology to 

commercial scale on hold, citing the 

current uncertain status of U.S. climate 

policy and the continued weak economy 

as contributors to the decision. 

Oxy-combustion of coal is being 

demonstrated in a 10 MWe facility in 

Germany. The Vattenfall plant in 

eastern Germany (Schwarze Pumpe) has 

been operating since September 2008. It 

is designed to capture 70,000 tonnes of 

CO2 per year. 

In June 2011, Mitsubishi Heavy 

Industries, an equipment manufacturer, 

announced the successful launch of 

operations at a 25 MW coal-fired carbon 

capture facility at Southern Company’s 

Alabama Power Plant Barry. The 

demonstration is planned to capture 

approximately 150,000 tons of CO2

annually at a CO2 capture rate of over 

90 percent. The captured CO2 will be 

permanently stored underground in a 

deep saline geologic formation. 

Southern Company has begun 

construction of Mississippi Power Plant 

Ratcliffe (formerly the Kemper County 

IGCC Project). Plant Ratcliffe is a 582 

MW IGCC plant that will utilize local 

Mississippi lignite and include precombustion carbon capture to reduce 

CO2 emissions by 65 percent. Operation 

is expected to begin in 2014. The CO2

captured from Plant Ratcliffe will be 

used for enhanced oil recovery (EOR) in 

the Heidelberg Oil Fields in Jasper 

County, MS. 

The Texas Clean Energy Project, a 400 

MW IGCC facility located near Odessa, 

TX will capture 90 percent of its CO2, 

which is approximately 3 million 

tonnes annually. The captured CO2 will 

be used for EOR in the West Texas 

Permian Basin. (Additionally, the plant 

will produce urea and smaller quantities 

of commercial-grade sulfuric acid, 

argon, and inert slag, all of which will 

also be marketed.) Construction is 

expected to begin in 2012. 

d. Legal Justification for the Standard 

of Performance and 30-year Averaging 

Compliance Option. This section 

describes our legal justification for 

proposing that new affected facilities in 

the TTTT category—which combines 

the Da and part of the KKKK 

categories—(i) must limit their CO2

emissions to 1,000 lb CO2/MWh, which 

an affected facility could achieve by 

constructing a NGCC unit or by 

constructing a coal-fired boiler that 

implements CCS immediately; or (ii) in 

the case of a coal- or pet coke-fired 

power plant, may either meet the 1,000 

lb CO2/MWh standard or implement an 

30-year averaging compliance option 

that allows an affected facility to meet 

an initial CO2 emission limit of 1,800 lb 

CO2/MWh (gross), and then—through 

the implementation of CCS—meet the 

1,000 lb CO2/MWh standard, on a timeaveraged basis, over no longer than a 30- 

year period. 

(1) Legal Justification for the Standard 

of Performance. The EPA proposes that 

the emission limit of 1,000 lb CO2/MWh 

meets the requirements for a ‘‘standard 

of performance’’ applicable to new 

sources under CAA section 111(b)(1)(B). 

The term ‘‘standard of performance’’ is 

defined under CAA section 111(a)(1) as 

follows: 

Definitions. For purposes of this section: 

(1) The term ‘‘standard of performance’’ 

means a standard for emissions of air 

pollutants which reflects the degree of 

emission limitation achievable through the 

application of the best system of emission 

reduction which (taking into account the cost 

of achieving such reduction and any nonair 

quality health and environmental impact and 

energy requirements) the Administrator 

determines has been adequately 

demonstrated. 

We apply this definition, in effect, 

from the bottom up. That is, first, we 

determine the ‘‘best system of emission 

reduction which (taking into account 

* * * cost [and other factors]) the 

Administrator determines has been 

adequately demonstrated.’’ For EGUs, 

that is a NGCC facility, for reasons 

discussed below. Then, we calculate the 

‘‘degree of emission limitation 

achievable through the application of’’ 

such best system; and after that, we 

formulate ‘‘a standard for emissions of 

air pollutants which reflects’’ that 

degree of emission limitation. This 

standard is 1,000 lb of CO2/MWh. These 

analytical steps are also discussed 

further below. 

In determining the ‘‘best system of 

emission reduction’’ for this category of 

boilers and combined cycle units, we 

considered a range of natural gas-fired 

and coal-fired generation technologies, 

with available controls. We considered 

modern supercritical and ultrasupercritical coal-fired boilers. This 

technology is available—it is currently 

deployed in Europe and is now being 

widely deployed in Asia (especially 

China)—and it offers much more 

efficient operation than the subcritical 

boilers that have more often been 

constructed in the U.S. These 

supercritical and ultra-supercritical 

boilers have CO2 emissions of 

approximately 1,800 lb/MWh and 

provide the lowest overall costs for 

conventional coal-based electricity. We 

also considered new IGCC, or ‘‘coal 

gasification’’ facilities, which can have 

CO2 emissions levels very similar to 

those of ultra-supercritical coal-fired 

units—albeit at a higher price. 

We also considered natural gas-fired 

boilers which have CO2 emissions of 

approximately 1,350 lb/MWh, obviously 


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much lower than the advanced coalfired or coal gasification technologies. 

However, it seems unlikely that utilities 

would choose a natural gas-fired boiler 

as the generation technology of choice 

when NGCC is a much more efficient, 

less expensive, and more widely used 

technology. 

We propose that a NGCC facility is the 

best system of emission reduction for 

two main reasons. First, natural gas is 

far less polluting than coal. Combustion 

of natural gas emits only about 50 

percent of the CO2 emissions that 

combustion of coal does per unit of 

energy generated. Second, new natural 

gas-fired EGUs are less costly than new 

coal-fired EGUs, and as a result, our IPM 

model projects that for economic 

reasons, natural gas-fired EGUs will be 

the facilities of choice until at least 

2020, which is the analysis period. 

Indeed, those models do not project 

construction of any new coal-fired EGUs 

during that period that would not 

comply with the proposed standard. 

This state of affairs has come about 

primarily because technological 

development and discoveries of 

abundant reserves have caused natural 

gas prices to decline precipitously in 

recent years and have secured those 

relatively low prices for the near-future. 

Importantly, because the IPM modeling 

shows that natural gas-fired plants are 

the facilities of choice, the proposed 

standard of performance in today’s 

rulemaking—which is based on the 

emission rate of a new NGCC unit—does 

not add costs. In addition, compared to 

coal-fired EGUs, natural gas-fired EGUs 

have fewer nonair quality health and 

environmental impacts. 

Essentially because natural gas 

generation is cleaner and cheaper than 

coal, natural gas-fired EGUs qualify as 

the ‘‘best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any 

nonair quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated.’’ 

We recognize that today’s proposed 

approach of combining the Da category 

and a portion of the KKKK category, and 

applying as the standard of performance 

the rate that natural gas-fired EGUs can 

meet, represents a departure from prior 

agency practice. We consider this 

departure warranted in light of both the 

emissions benefits and the changed 

economic circumstances, notably the 

lowered prices of natural gas due to 

technological development and recent 

discoveries that have boosted 

recoverable reserves. We are aware that 

in theory, those economic 

circumstances could change and if they 

do, then a change in the standard of 

performance may be warranted. In this 

regard, we note that CAA section 

111(b)(1)(B) requires that the EPA 

‘‘shall, at least every 8 years, review 

and, if appropriate, revise [the] 

standards [of performance].’’ This 8-year 

review cycle provides a mechanism for 

the EPA to assure that the standard of 

performance for any particular source 

category continues to reflect the ‘‘best 

system.’’ 

(2) Legal Justification for the 30-year 

Averaging Compliance Option. 

Although the IPM model projects that 

for economic reasons, new coal- or pet 

coke-fired EGUs will not be built in the 

foreseeable future (beyond early CCS 

projects), we recognize that in a few 

instances, owners or operators may in 

fact seek to build coal- or pet coke-fired 

EGUs. As discussed in detail below, 

those owners or operators could avail 

themselves of CCS as a 30-year 

averaging compliance option. In 

addition, today’s proposed rulemaking 

offers flexibility for CCS installation: 

The owners or operators could (i) 

achieve the supercritical efficiency level 

for an initial period (e.g., up to the first 

10 years), and (ii) after that, implement 

CCS so as to achieve a 600 lb CO2/MWh 

rate on a 12-month annual average 

during the latter period (i.e., the back 20 

years) and thereby achieve the 1,000 lb 

CO2/MWh rate on an average annual 

basis over the 30-year period. The 

alternative compliance option could 

also allow them to install and operate 

CCS much earlier and use the 10-year 

period to address any startup challenges 

related to being an early adopter of the 

technology. 

Because CO2 is long-lived in the 

atmosphere, the 30-year averaging 

period, as structured, with shorter term 

compliance requirements, is not 

expected to have a different impact on 

climate compared to meeting the 

standard of performance. 

(a) CCS. The significance of CCS as a 

compliance alternative is several-fold. 

As a practical matter, it offers a vehicle 

for the construction of new coal-fired 

EGUs in those few instances in which 

owners or operators decide to construct 

such EGUs, notwithstanding the 

underlying economics. Also, it offers a 

vehicle for the continued scaling of 

CCS, a process that can be expected to 

lower the costs of CCS in the future. In 

addition, this compliance alternative 

provides further support for the 

reasonableness of the EPA’s proposals 

in this rulemaking to combine the Da 

category and a portion of the KKKK 

category and to determine that a NGCC 

facility is the ‘‘best system of emission 

reduction.’’ This is because this 

compliance alternative, by providing a 

vehicle for new coal-fired power plant 

builds, would minimize any disruptions 

that the EPA’s proposals might, at least 

in theory, otherwise entail to the power 

plant industry. 

CCS as a compliance alternative does 

not achieve these goals by necessarily 

qualifying, under the CAA section 

111(a)(1) definition of ‘‘standard of 

performance,’’ as the ‘‘best system of 

emission reduction which (taking into 

account cost [and other factors]) the 

Administrator determines has been 

adequately demonstrated.’’ Instead, this 

compliance alternative is feasible and 

sufficiently available for the limited 

amount of new coal-fired construction 

that is expected, whether or not it 

would qualify as the ‘‘best system.’’ 

First, it is reasonable to expect that 

some coal-fired power plants may be 

able to implement CCS at the present 

time, and thereby achieve the 1,000 lb 

CO2/MWh standard immediately. As 

noted elsewhere, CCS has been 

demonstrated to be technologically 

achievable, and, even though it is costly, 

there are some state and Federal subsidy 

programs that can make CCS more 

affordable, particularly in tandem with 

use of captured CO2 for enhanced oil 

recovery, and those programs may be 

sufficient for the very few new coalfired plants that are expected to be 

constructed in the foreseeable future. 

Some of these programs are discussed 

above. 

We note that the need for 

governmental subsidies to reduce the 

costs of CCS is hardly unique in the 

electricity generation sector. Each of the 

major types of energy used to generate 

electricity has been or is currently 

supported by some type of government 

subsidy—such as tax benefits, loan 

guarantees, low-cost leases, or direct 

expenditures—for some aspect of 

development and utilization, ranging 

from exploration to control installation. 

This is true of fossil fuel-fired; as well 

as nuclear-, geothermal, wind-, and 

solar-generated electricity. These 

subsidies have been designed to 

overcome cost barriers to the utilization 

of the energy. In this context, the need 

for subsidies for CCS to overcome cost 

barriers does not mean that CCS cannot 

be considered an alternative compliance 

method in this rulemaking. 

Second, it is reasonable to expect that 

some coal-fired power plants may be 

able to implement the supercritical 

efficiency standard for an initial period 

of time (the first 10 years) and then 

implement CCS and achieve lower 12- 

month annual average rates after that, so 

that the source achieves the 1,000 lb 

CO2/MWh standard on average over the 


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63Note that under today’s proposed rulemaking, 

the 30-year averaging proposal is associated only 

with the implementation of CCS at new coal- or pet 

coke-fired EGUs. This proposal does not allow 30- 

year averaging for any other purpose. 

30-year period following construction.63

This is because, again, CCS is feasible 

and can be expected to be sufficiently 

available—in light of continued 

subsidies and lower future costs—in 

light of the limited demand. 

Third, although we do not propose 

that the 30-year averaging compliance 

option meets the definition of the ‘‘best 

system of emission reduction [(BSER)] 

* * * adequately demonstrated,’’ under 

CAA section 111, we note that 

identifying CCS as a compliance option 

based in part on the expectation that 

CCS will cost less in the future is 

consistent with the section 111 

requirements for determining the BSER 

adequately demonstrated. In 

determining what emissions controls 

qualify as the BSER adequately 

demonstrated—which must take costs 

into account—the EPA is authorized 

under CAA section 111 to anticipate 

that technology that is costly at present 

will come down in price in the future. 

It is clear from the legislative history of 

section 111 and relevant case law that 

the EPA may anticipate future 

developments—as long as supported by 

an adequate record—in determining 

whether a particular system of emission 

reduction is the BSER adequately 

demonstrated. The Senate Committee 

Report to the 1970 CAA Amendments, 

which first enacted CAA section 111, 

made clear that the EPA may anticipate 

future developments in determining the 

BSER adequately demonstrated: 

As used in this section, the term ‘‘available 

control technology’’ is intended to mean that 

the Secretary should examine the degree of 

emission control that has been or can be 

achieved through the application of 

technology which is available or normally 

can be made available. This does not mean 

that the technology must be in actual, routine 

use somewhere. It does mean that the 

technology must be available at a cost and at 

a time which the Secretary determines to be 

reasonable. The implicit consideration of 

economic factors in determining whether 

technology is ‘‘available’’ should not affect 

the usefulness of this section. The overriding 

purpose of this section would be to prevent 

new air pollution problems, and toward that 

end, maximum feasible control of new 

sources at the time of their construction is 

seen by the committee as the most effective 

and, in the long run, the least expensive 

approach. 

Sen. Rep. 91–1196 at 16 (emphasis 

added). As quoted, this statement makes 

clear that a standard of performance 

may be based on a technology that is not 

‘‘in actual routine use somewhere,’’ but 

that ‘‘normally can be made available.’’ 

Moreover, the technology need not be 

available until ‘‘a time which the 

Secretary determines to be reasonable.’’ 

Id. 

In addition, the D.C. Circuit has been 

explicit that in setting a CAA section 

111 standard of performance, the EPA 

may make reasonable projections of 

what technology will be available to the 

regulated industry in the future. The 

Court stated, in Portland Cement Ass’n 

v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973): 

We begin by rejecting the suggestion of the 

cement manufacturers that the Act’s 

requirement that emission limitations be 

‘‘adequately demonstrated’’ necessarily 

implies that any cement plant now in 

existence be able to meet the proposed 

standards. Section 111 looks toward what 

may fairly be projected for the regulated 

future, rather than the state of the art at 

present, since it is addressed to standards for 

new plants—old stationary source pollution 

being controlled through other regulatory 

authority. It is the ‘‘achievability’’ of the 

proposed standard that is in issue. * * * 

The * * * standard is analogous to the one 

examined in International Harvester * * *. 

The Administrator may make a projection 

based on existing technology, though that 

projection is subject to the restraints of 

reasonableness and cannot be based on 

‘‘crystal ball’’ inquiry.64

Id. at 391 (emphasis added). Again, 

although these statements in the 

legislative history and case law are in 

the context of establishing the basis for 

a standard of performance, the same 

principle –- that the EPA may 

reasonably project the path of 

technological development –- supports 

treating CCS as a compliance 

alternative. 

Although, for the reasons noted 

above, we do expect the costs of CCS to 

decline, we recognize that the amount of 

the decrease is uncertain. Even so, the 

presence of cost uncertainty by itself 

does not mean that prospective power 

plants cannot be expected to adopt the 

30-year averaging compliance option. 

We note that prospective power plants 

face significant cost uncertainties in any 

event. 

For example we note that recently, 

several owner/operators have 

announced that they do not intend to 

construct coal-fired power plants 

without CCS. They have explained that 

they anticipate more widespread CO2

control requirements in the future, so 

that constructing coal-fired plants at this 

time without CCS could leave them 

subject to liability for high retrofit 

control costs in the future. This 

sentiment indicates that some sources 

may avail themselves of the 30-year 

averaging compliance option. 

The inclusion of a 30-year averaging 

compliance option has precedent in 

EPA rulemaking under the CAA. In the 

past, the EPA has promulgated rules 

that adopt an emission limit based on a 

particular technology (such as, in the 

present rulemaking, NGCC), but has 

supported that action on grounds that 

sources have compliance alternatives, 

even though higher priced. See 

‘‘Finding of Significant Contribution 

and Rulemaking for Certain States in the 

Ozone Transport Assessment Group 

Region for Purposes of Reducing 

Regional Transport of Ozone: Final 

Rule’’ 63 FR 57356, 57378 (Oct. 27, 

1998) (in the rule that became known as 

the ‘‘NOX SIP Call,’’ the EPA based NOX

emission limits that states were required 

to meet on the assumption that states 

could adopt specified control measures 

that were ‘‘highly cost-effective,’’ but 

the EPA identified other control 

measures that, even though not as costeffective, the states could adopt 

instead). 

(b) 30-year Period. We propose a 30- 

year period because (i) we generally 

expect that ten years provides sufficient 

time either for owners/operators who 

are interested in considering cost 

improvements that occur as a result of 

the lessons learned from early adopters, 

or provides early adopters sufficient 

time to address any startup challenges; 

and (ii) as noted above, 30 years 

provides enough time for sources to 

achieve the 1,000 lb CO2/MWh emission 

limit following an elevated level of 

emissions over the first 10-year period. 

(c) Supercritical Efficiency Level. 

According to the Department of Energy 

Cost and Performance Baseline for 

Fossil Energy Plants reports, the use of 

supercritical steam is the most cost 

effective option for new conventional 

coal-fired generation and results in the 

lowest overall costs. In addition, the 

increased efficiency results in reduced 

cooling water requirements and reduced 

environmental impacts associated with 

coal mining, delivery, and handling. 

Therefore, considering the benefits and 

minimal, if any, cost of using 

supercritical steam conditions, as 

opposed to subcritical steam conditions, 

we have concluded that an annual 

standard based on the best performing 

conventional coal-fired generation is 

appropriate. 

There are a dozen bituminous-fired 

and 2 subbituminous-fired EGUs that 

have demonstrated the proposed annual 

standard is achievable on a long term 

basis. Furthermore, we have concluded 

that with coal drying technology, which 

is being used on a number of power 

plants today, the annual standard is 

achievable by a wide range of units 


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firing a variety of coal types, including 

lignites. There are multiple vendors that 

offer processes to upgrade lignites to 

heating values that are equal to or 

greater than those of subbituminous 

coals. The best performing 

subbituminous-fired EGU has 

maintained a 12-month emissions rate 

of 1,730 lb CO2/MWh. A new EGU using 

a similar design would be able to burn 

upgraded lignite and be in compliance 

with the proposed annual standard. 

We solicit comment on all aspects of 

the alternative compliance option, 

including the 30-year averaging period 

we propose in this action. Although we 

are not proposing that CCS, including 

the 30-year averaging compliance 

option, does or does not qualify as the 

BSER adequately demonstrated, we also 

solicit comment on that issue. 

B. How did the EPA determine the other 

requirements for the proposed 

standards? 

1. Compliance Requirements 

The proposed compliance 

requirements, to the extent possible, 

incorporate monitoring already being 

performed as part of existing part 60 and 

part 75 requirements. 

In addition, we intend to recognize 

the environmental benefit of electricity 

generated by CHP facilities to account 

for the increased end use efficiency 

resulting from avoided transmission and 

distribution losses. Actual line losses 

vary from location to location, but we 

intend to assume a benefit of 5 percent 

avoided transmission and distribution 

losses when determining the electric 

output for CHP facilities. This provision 

would be restricted to facilities where 

the useful thermal output is at least 20 

percent of the total output. 

We also propose to base compliance 

requirements on a 12-month rolling 

average basis. The variability in GHG 

emissions rates is such that establishing 

a shorter averaging period would 

necessitate establishing a standard to 

account for the conditions that result in 

the lowest efficiency and therefore the 

highest GHG emissions rate. A 12- 

month rolling average accounts for 

variable operating conditions, allows 

consistent emissions rate averaging, 

allows for a more protective standard 

and decreased compliance burden, and 

simplifies compliance for state 

permitting authorities. Because the 12- 

month rolling average can be calculated 

each month, this form of standard 

makes it possible to assess compliance 

and take any needed corrective action 

on a monthly basis. The EPA proposes 

that it is not necessary to have a shorter 

averaging period for CO2 from these 

sources because the effect of GHGs on 

climate change depends on global 

atmospheric concentrations which are 

dependent on cumulative total 

emissions over time, rather than hourly 

or daily emissions fluctuations or local 

pollutant concentrations. 

Even so, we solicit comment on, in 

the alternative basing compliance 

requirements on an annual (calendar 

year) average basis. 

V. Requirements for Modifications, 

Transitional Sources, Reconstructions 

A. Requirements for Modifications 

1. Overview 

Under CAA section 111, existing 

sources are treated as new sources if 

they undertake ‘‘modification[s],’’ 

which are generally defined as physical 

or operational changes that increase 

emissions. CAA section 111(a)(2) and 

(4). The EPA’s regulations exempt 

certain types of changes from the 

definition of modification. 40 CFR 

60.14(e). Available information does not 

provide an adequate basis for the EPA 

to develop proposed standards of 

performance for modifications. Our base 

of knowledge concerning NSPS 

modifications has depended largely on 

the enforcement actions brought against 

power plants and on self-reporting by 

power plants. Over the lengthy history 

of the NSPS program, those have been 

too few in number to allow us to 

develop a sufficiently robust base of 

knowledge to propose a standard of 

performance for NSPS modifications for 

GHGs at this time. 

We note that the types of projects that 

these EGUs are most likely to undertake 

that could increase GHG emissions are 

projects that put on pollution controls 

required under other CAA provisions 

and that emit CO2 as a byproduct, and 

those types of projects are specifically 

exempted from the definition of 

‘‘modifications’’ under 40 CFR 

60.14(e)(5). In addition, based on past 

experience, we expect that actions that 

do constitute modifications to be from 

different types of sources and to take 

different forms. In light of this, the EPA 

does not have sufficient information to 

develop standards of performance for 

modifications, and therefore the EPA is 

not proposing any standards for 

modifications. As a result, EGUs that 

undertake pollution control projects or 

other physical or operational changes 

would continue to be treated as existing 

sources. 

2. Statutory and Regulatory 

Requirements 

Clean Air Act section 111(b)(1)(B) 

requires the EPA to promulgate 

‘‘standards of performance’’ for ‘‘new 

sources’’ within source categories. For 

certain pollutants, CAA section 

111(d)(1) requires the EPA to prescribe 

regulations for state plans covering 

‘‘existing source[s]’’ in a category 

regulated for that pollutant under 

section 111(b). Clean Air Act section 

111(a)(2) defines a ‘‘new source’’ as 

‘‘any stationary source, the construction 

or modification of which is commenced 

after the publication of regulations (or, 

if earlier, proposed regulations) 

prescribing a standard of performance 

under this section which will be 

applicable to such source.’’ Clean Air 

Act section 111(a)(6) defines an 

‘‘existing source’’ as ‘‘any stationary 

source other than a new source.’’ Clean 

Air Act section 111(a)(4) defines 

‘‘modification’’ as ‘‘any physical change 

in, or change in the method of operation 

of, a stationary source which increases 

the amount of any air pollutant emitted 

by such source or which results in the 

emission of any air pollutant not 

previously emitted.’’ 

The EPA’s regulations provide that 

under CAA section 111(a)(4), for 

purposes of determining whether an 

existing electric utility steam generating 

unit undertakes a modification, a 

physical or operational change is treated 

as increasing emissions only when it 

increases the ‘‘maximum hourly 

emissions’’ above the ‘‘maximum hourly 

emissions achievable’’ at the unit. 40 

CFR 60.14(h). In addition, the EPA’s 

regulations exempt certain physical or 

operational changes from the definition 

of modification. 40 CFR 60.14(e)(5). The 

exemptions include pollution control 

projects: 

(e) The following shall not, by themselves, 

be considered modifications * * *: 

* * * * * 

(5) The addition or use of any system or 

device whose primary function is the 

reduction of air pollutants, except when an 

emission control system is removed or is 

replaced by a system which the 

Administrator determines to be less 

environmentally beneficial. 

40 CFR 60.14(e)(5). Thus, the EPA’s 

current regulations define a 

modification as a physical or 

operational change that increases an 

existing affected EGU’s maximum 

achievable hourly rate of emissions, but 

specifically exempt from that definition 

pollution control projects, which are 

projects that entail the installation of 

pollution control equipment or systems. 

3. The EPA’s Proposed Course of Action 

We expect EGUs to undertake changes 

in the foreseeable future that would 

increase their maximum achievable 

hourly rate of CO2 emissions for 


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65Nothing in this discussion of the unique 

circumstances of transitional sources facing new 

GHG requirements should be interpreted as 

providing a defense to any violation of the CAA by 

sources that, for example, fail to obtain PSD permits 

or comply with NSPS before construction. 

purposes of the NSPS. We expect that 

most of those actions would constitute 

pollution control projects. In many 

cases, those projects would involve the 

installation of add-on control equipment 

required to meet CAA requirements for 

conventional air pollutants. We expect 

that these increases in CO2 emissions 

would occur as a chemical byproduct of 

the operation of the control equipment, 

and would be small. In other cases, 

those projects will involve equipment 

changes to meet the requirements of this 

rulemaking and that may have the effect 

of increasing the sources’ maximum 

hourly achievable emission rate, even 

while decreasing actual emission rate. 

Because such actions would be treated 

as pollution control projects under the 

EPA’s current NSPS regulations, they 

would be specifically exempted from 

the definition of modification. 

Aside from pollution control projects, 

in the past, there have also been, as 

noted, a limited number of instances, on 

an annual basis, in which power plants 

have undertaken actions that should be 

treated as NSPS modifications. The 

sources that took these actions vary 

widely, one from another, depending 

on, among other things, size, fuel type, 

and physical plant configuration. The 

diversity of sources undertaking 

modifications has reflected the diversity 

among power plants as a whole. 

Moreover, the types of modifications 

they have undertaken have also varied 

widely. 

Because of the limited number of 

modifications, their disparate nature, 

and the disparate type of sources, we do 

not at present have an adequate base of 

information to propose standards of 

performance for modifications. For 

example, we do not have adequate 

information as to the types of physical 

or operational changes sources may 

undertake or the amount of increase in 

CO2 emissions from those changes. Nor 

do we have adequate information as to 

the types of control actions sources 

could take to reduce emissions, 

including the types of controls that may 

be available or the cost or effectiveness 

of those controls. The most likely 

candidates for control actions would be 

efficiency measures and we do not have 

adequate information as to the types of 

sources and types of changes at issue 

that could provide the basis for a 

proposal for efficiency measures. If 

there were a more robust set of data on 

facilities of a particular type 

undertaking NSPS modifications of a 

particular kind, the EPA may be able to 

develop a standard of performance for 

that type. But, as noted, that is not the 

case here. 

As a result, in this action, the EPA is 

not proposing standards of performance 

for NSPS modifications for GHGs. The 

EPA is soliciting comment on the types 

of sources that may be expected to 

undertake modifications, the types of 

modifications, the types of control 

measures, and all other aspects of this 

issue. This solicitation of comment is in 

the nature of an advance notice of 

proposed rulemaking. If we receive 

sufficient additional information, we 

may issue a proposal for modifications 

in the future. However, to reiterate, we 

are not proposing any standards of 

performance for these modifications at 

this time. Accordingly, the EPA does 

not expect to promulgate any standards 

of performance for modifications when 

it takes final action on this rulemaking. 

The definitional provisions of CAA 

section 111, quoted above, make clear 

that a stationary source that undertakes 

construction or modification is 

considered a ‘‘new source’’ only if there 

is a proposed or final ‘‘standard of 

performance under this section which 

will be applicable to such source.’’ CAA 

section 111(a)(2). Accordingly, if there 

is no proposed or promulgated standard 

of performance applicable to a 

particular source, then the source 

cannot be considered a ‘‘new source’’ 

and therefore will not be subject to any 

standards of performance we finalize for 

new sources. 

Further, under the definitional 

provisions, any source that is not a 

‘‘new’’ source is an ‘‘existing source.’’ 

CAA section 111(a)(6). Therefore, 

affected EGUs that undertake NSPS 

modifications for GHGs will continue to 

be treated as existing sources. Although 

modified sources would not be subject 

to the 1,000 lb CO2/MWh standard for 

new sources, the EPA anticipates that 

modified sources would become subject 

to the requirements the EPA would 

promulgate at the appropriate time, for 

existing sources under 111(d). It is 

important to note that at the same time 

that the EPA promulgated the pollution 

control provision in the EPA’s 

regulations under CAA section 111, the 

EPA promulgated a similar provision in 

EPA’s NSR regulations. The DC Circuit, 

in New York v. EPA, 413 F.3d 3, 40 (DC 

Cir. 2005), vacated the NSR pollutioncontrol-project exemption. Because of 

the similarities between the NSR and 

the section 111 pollution control project 

regulatory provisions, the Court’s 

vacatur of the NSR regulatory provision 

may call into question the continued 

validity of the section 111 regulatory 

provision. As a result, we are soliciting 

comment on whether this exemption 

from the definition of ‘‘modification’’ 

for pollution control projects, under 40 

CFR 60.14(e)(5), continues to be valid or 

not, and what course of action, if any, 

would be appropriate for the EPA to 

take. 

B. Requirements for Transitional 

Sources 

1. Overview 

In this action, the EPA is not 

proposing a standard of performance for 

transitional sources. We define these 

sources as coal-fired power plants that, 

by the date of this proposal, have 

received approval for their PSD 

preconstruction permits that meet CAA 

PSD requirements (or that have 

approved PSD permits that expired and 

are in the process of being extended, if 

those sources are participating in a 

Department of Energy CCS funding 

program), and that commence 

construction within a year of the date of 

this proposal. For convenience, we refer 

to the new sources for which we are 

proposing a standard of performance as 

non-transitional sources. 

Transitional sources are a distinct set 

of sources with unique circumstances.65

We have identified 15 proposed sources 

that may qualify as transitional sources 

based on the above criteria. These 

proposed sources differ considerably 

one from another. They range in size 

from as small as 80 megawatts (MW) to 

as large as 1320 MWs; they will burn 

different fuels: Conventional coal, waste 

coal, or petcoke; and they will use 

different technologies: Circulating 

fluidized bed (CFB), integrated 

gasification combined cycle (IGCC), 

supercritical pulverized coal, or subcritical pulverized coal. Recent industry 

practice raises the probability that no 

more than a few of these 15 proposed 

sources will in fact be constructed. 

We recognize that by the date of this 

proposal, some of the 15 proposed 

sources may have incurred substantial 

sunk costs and may have progressed in 

their preconstruction planning to the 

point where they are poised to 

commence construction in the very near 

future. Under these circumstances, the 

1,000 lb CO2/MWh standard of 

performance that applies to nontransitional sources would not be 

appropriate for these proposed sources. 

As noted, that standard is based on 

natural gas combined cycle (NGCC) as 

the ‘‘best system of emission reduction 

* * * adequately demonstrated’’ 

because NGCC is the least expensive 


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66Since 2008, some 15 proposed coal-fired power 

plants with approved PSD permits have cancelled 

plans to construct, and since 2009, only one coalfired power plant has constructed (Southern 

Company’s Kemper County Project, which installed 

CCS and received DOE funding). 

67We note that there may be some proposed 

natural gas-fired EGUs that are similarly situated to 

the coal-fired transitional sources because the 

natural-gas fired sources have received PSD permits 

but have not commenced construction by the date 

of this proposal. Because they are new gas-fired 

EGUs, we expect that they will be able to meet the 

requirements of the proposed new source standard 

of performance. 

and lowest emitting design for a fossilfuel fired power plant, and because a 

proposed new source may choose to 

construct as an NGCC facility. However, 

proposed coal-fired power plants that 

have already received a PSD permit and 

that have incurred substantial sunk 

costs and developed plans to commence 

construction in the very near future are 

not in the same position as nontransitional sources. Applying the 1,000 

lb CO2/MWh standard would likely 

result in the loss of their sunk costs and 

would likely cause multi-year delays, or 

even abandonment, of their plans to 

construct. (Nor is the 1,000 lb CO2/MWh 

standard appropriate for CCS sources, as 

discussed below.) This is not within the 

scope of BSER. 

However, we do not have sufficient 

information concerning the 15 proposed 

sources to identify which ones may be 

in this position. Specifically, we do not 

have information as to the extent of 

their sunk costs, their preconstruction 

planning, or their overall business 

plans. 

Accordingly, we propose to include a 

requirement that proposed sources must 

commence construction within 12 

months of today’s rulemaking proposal 

as a mechanism for revealing which of 

these sources qualifies as a transitional 

source. We believe that any of these 15 

proposed sources that commences 

construction within 12 months of 

today’s rulemaking proposal should be 

considered to have incurred substantial 

sunk costs and will have engaged in 

sufficient preconstruction planning so 

that the 1,000 lb CO2/MWh standard 

should not apply. Any of these 15 

proposed sources that do not commence 

construction within this period should 

not be considered to be similarly 

situated. For any of these latter sources 

that ultimately are constructed, the 

1,000 lb CO2/MWh standard would 

apply. 

Having identified which proposed 

sources could qualify as transitional 

sources, we further believe that for 

several reasons, it is not appropriate to 

propose any standard of performance for 

those sources. As noted above, we 

necessarily lack information specifically 

as to which of the 15 proposed sources 

will actually qualify as transitional 

sources, and, given the range of size, 

fuel types, and technologies among 

these proposed sources, that renders it 

problematic to propose standards of 

performance. In addition, for the 

proposed sources that are planning to 

install CCS, we lack important 

information concerning the extent to 

which they are planning to capture CO2

or their costs to do so. We also lack 

information as to whether they have 

made contractual arrangements for the 

sale of the CO2 or carbon credits, which 

may be critical to their financing 

arrangements. In addition, attempting to 

propose a standard of performance 

would give rise to serious practical 

problems that would undermine the 

usefulness of the requirement that 

sources commence construction within 

12 months of today’s rulemaking 

proposal as a mechanism for revealing 

which of these sources qualifies as a 

transitional source. These include 

creating uncertainty as to the level of 

the final standard of performance to 

which the proposed sources would be 

subject, which may have the effect of 

forcing them to delay commencing 

construction until after we finalize the 

standards, at which time they would 

have missed their 12-month window to 

commence construction and as a result, 

would fail to qualify as transitional 

sources. We note that CAA section 111 

does not require that we propose or 

promulgate standards of performance 

for all sources in a source category, and 

on numerous occasions in past 

rulemakings the EPA has taken the 

similar approach of not proposing 

standards of performance for all sources 

in the source category. 

Even without an applicable standard 

of performance, transitional sources will 

remain constrained in their emissions of 

CO2 by the requirements of their PSD 

permits. In addition, although 

transitional sources would not be 

subject to the 1,000 lb CO2/MWh 

standard for new sources, the EPA 

anticipates that transitional sources 

would become subject to the 

requirements the EPA would 

promulgate at the appropriate time, for 

existing sources under 111(d). 

2. Identification of Transitional Sources 

For purposes of this action, we define 

a transitional source as a coal-fired 

power plant that has received approval 

for its complete PSD preconstruction 

permit by the date of this proposal (or 

that has an approved PSD permit that 

expired and for which the source is 

seeking an extension, if the source has 

been issued or awarded a DOE CCS loan 

guarantee or grant) for the project, and 

that commences construction within 12 

months of the date of this proposal. For 

this purpose, the date of this proposal 

is the date of publication in the Federal 

Register of this notice of proposed 

rulemaking. The 12-month period 

would not be extended for any reason, 

including because of any challenges to 

the permit that may be brought in any 

Federal or State court or agency. 

The EPA is aware of approximately 15 

sources that could potentially qualify as 

transitional sources because, except as 

otherwise noted, they have obtained 

PSD permits but have not yet 

commenced construction. These 

proposed sources vary considerably one 

from another. They range in size from as 

small as 80 megawatts (MW) to as large 

as 1320 MWs; they will burn different 

fuels: conventional coal, waste coal, or 

petcoke; and they will use different 

technologies: Circulating fluidized bed 

(CFB), integrated gasification combined 

cycle (IGCC), supercritical pulverized 

coal, or sub-critical pulverized coal. 

Based on recent industry practice, it 

appears that no more than a few of these 

sources will be constructed.66

Of these 15 identified potential 

transitional sources, six have indicated 

that they plan to install CCS (and in 

most if not all cases have been issued or 

awarded a DOE CCS loan guarantee or 

grant). These six projects are: The Texas 

Clean Energy Project in Texas, the 

Trailblazer project in Texas, the 

Taylorville project in Illinois, the Good 

Spring facility in Pennsylvania, the 

Power County Advanced Energy Center 

in Idaho and the Cash Creek Generation 

Plant in Kentucky. The remaining nine 

plants, which are without CCS, are: 

Limestone 3, White Stallion and Coletto 

Creek in Texas, Holcomb 2 in Kansas, 

James De Young and Wolverine in 

Michigan, Washington County in 

Georgia, Bonanza in Utah, and Two Elk 

in Wyoming.67

We request that during the public 

comment period on this rulemaking, 

each of these EGUs confirm to us that 

we have correctly identified the status 

of their PSD permits and, in the case of 

any sources that had approved permits 

that are in the process of being 

extended, and that plan to install CCS, 

that they have been issued or awarded 

a DOE CCS loan guarantee or grant. We 

also request that the sources indicate 

whether their permits are undergoing 

challenges before Federal or state 

authorities or courts. We further request 

that any other EGU not listed above that 

has a complete PSD permit and that 

otherwise meets the parameters for 

transitional sources described in this 


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68http://www.texascleanenergyproject.com/newsroom/. 

69EPA intends that its treatment of transitional 

and non-transitional sources be severable from each 

other and considers that severability is logical 

because of the record-based differences between the 

two types of sources and because there is no 

interdependency in EPA’s treatment of the two 

types of sources. This statement concerning 

severability for these components in this 

rulemaking should not be construed to have 

implications for whether other components in this 

rulemaking are severable. 

70The CAA does not include a definition of the 

term ‘‘commenced’’ for these purposes, but the EPA 

Continued 

section identify itself to us (including 

indicating whether its PSD permit is 

undergoing challenge before Federal or 

state authorities or courts). In our final 

rulemaking, we intend to include a 

confirmed list of sources that would 

qualify as transitional sources if they 

commence construction within the 12- 

month period following publication of 

this proposal in the Federal Register. 

As commenters have noted, among 

these 15 proposed sources, some may 

have incurred substantial sunk costs 

associated with processing their permits 

as well as taking additional 

preconstruction steps (e.g., purchasing 

land) so that they may be able to 

commence construction within the near 

term. As examples of these types of 

steps, several sources, such as the Texas 

Clean Energy Project, have signed 

contracts for the sale of electricity, the 

sale or disposal of CO2 or other enabling 

products, or supporting systems.68

Although the Taylorville project’s PSD 

permit has expired, the source is 

seeking to extend it, and the source has 

entered into CCS funding arrangements 

with DOE. These actions indicate that 

this proposed source, too, has sunk 

costs and may be in a position to 

commence construction within the near 

term, and therefore is similarly situated 

to the other 14 proposed plants 

(assuming that it is able to secure an 

extension of its PSD permit). 

Even so, we face major gaps in our 

information about these sources that 

would inform us at this point as to 

which of these sources have incurred 

costs and material commitments to the 

extent that a 1,000 lb CO2/MWh 

standard would be so costly and 

disruptive as not to be BSER. For 

example, we do not have specific 

information as to those sources’ specific 

sunk costs, specific project development 

actions to date, or overall business plan. 

Accordingly, we are not able to 

determine which ones are in a position 

to commence construction in the near 

term. In addition, for the sources whose 

PSD permit indicates that they will 

install CCS, we do not have specific 

information as to the amount of CO2 that 

they plan to capture; their costs to 

operate CCS; or their possible revenue 

streams associated with CCS, such as 

from the sale or use of CO2 in enhanced 

oil recovery or the possible sale of 

carbon credits in voluntary or other 

carbon markets. 

Instead, the 12-month period, serving 

as a surrogate for the missing 

information, provides a mechanism for 

revealing the qualification of proposed 

sources for treatment as transitional 

sources. In light of the complex of 

requirements, which range from siting 

to financing, needed to commence 

construction of a project as large and 

expensive as a power plant, any 

proposed source that does commence 

construction within the relatively short 

period of 12 months of the date of 

proposal can be said to have incurred 

substantial sunk costs and to have taken 

preconstruction steps by the time of this 

proposal. It is these sources that would 

be most disadvantaged by being 

subjected to the standards of 

performance proposed in today’s 

rulemaking. The one-year period serves 

as a type of surrogate for more precise 

information as to the amount of sunk 

costs sources must incur or steps 

leading to commencement of 

construction that sources must 

undertake in order to qualify as 

transitional sources, as well as which 

sources have incurred those costs or 

taken those steps, which information is 

not available at this time. In addition, 12 

months is long enough to give these 

sources a reasonable period to 

commence construction in accordance 

with the terms of their permit. Any 

proposed source that does not 

commence construction within 12 

months cannot be said to be similarly 

situated. 

3. The EPA’s Treatment of Transitional 

Sources 

In this action, the EPA is treating 

transitional sources as a distinct set of 

sources. We make clear that the 

proposed standard of performance for 

non-transitional sources of 1,000 lb 

CO2/MWh is not applicable to 

transitional sources because that 

standard is not based on the BSER 

adequately demonstrated for transitional 

sources. In addition, in light of the 

unique circumstances of transitional 

sources, including a lack of information 

and other considerations, we do not 

propose any other standard of 

performance for transitional sources.69

Although a transitional source would 

not be subject to new source CO2

emissions controls under CAA section 

111(b), it would be subject to CO2

emissions limits due to any CO2 limits 

in the source’s PSD permit. If the source 

received the permit prior to January 2, 

2011, the permit will not include CO2

limits, but in that case, as a practical 

matter, CO2 emissions would be limited 

by whatever design or operating 

constraints are imposed on the source 

under the PSD permit. 

We also note that the fact that 

transitional sources would not be 

subject to the proposed standard of 

performance, would not relieve them 

from any requirements applicable to 

existing sources under section 111(d) 

and related state plans. 

4. Legal Basis for the EPA’s Treatment 

of Transitional Sources 

In this section, we describe the legal 

basis for our treatment of transitional 

sources. First, we identify the relevant 

CAA section 111 provisions. Second, we 

explain why the standard of 

performance we propose for nontransitional sources does not apply to 

transitional sources, which is because 

that standard does not reflect the best 

system of emission reduction 

adequately demonstrated for transitional 

sources. Third, we explain why we are 

not proposing any other standard of 

performance for transitional sources, 

which is due to lack of information and 

other considerations. In the course of 

these explanations, we discuss the 

relevant CAA section 111 requirements 

and our interpretations of them. 

a. Key CAA Section 111 Provisions 

As the first step in the process of 

promulgating regulations under section 

111, under CAA section 111(b)(1)(A), 

the Administrator must ‘‘publish * * * 

a list of categories of stationary 

sources.’’ Then, the Administrator must 

‘‘[propose] * * * Federal standards of 

performance for new sources within [the 

source] category,’’ and then ‘‘promulgate 

* * * such standards with such 

modifications as he deems appropriate.’’ 

Section 111(b)(1)(B). Section 111(b)(2) 

goes on to provide that ‘‘[t]he 

Administrator may distinguish among 

classes, types, and sizes within 

categories of new sources for the 

purpose of establishing such standards.’’ 

Section 111 includes several key 

definitions. The provision defines a 

‘‘new source’’ as ‘‘any stationary source, 

the construction or modification of 

which is commenced after the 

publication of regulations (or, if earlier, 

proposed regulations) prescribing a 

standard of performance under this 

section which will be applicable to such 

source.’’ CAA section 111(a)(2).70 A 


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framework regulations promulgated under section 

111 define this term as follows: 

Commenced means, with respect to the definition 

of new source in section 111(a)(2) of the Act, that 

an owner or operator has undertaken a continuous 

program of construction or modification or that an 

owner or operator has entered into a contractual 

obligation to undertake and complete, within a 

reasonable time, a continuous program of 

construction or modification. 

40 CFR 60.2. 

71Section 111(b)(2) authorizes the EPA to 

‘‘distinguish among classes, types, and sizes within 

categories of new sources for the purpose of 

establishing such standards.’’ In other words, once 

the EPA selects the set of sources for which to 

propose regulations, the EPA may establish 

subcategories among those new sources and 

promulgate different standards for those 

subcategories. 

‘‘standard of performance’’ is defined as 

a— 

standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the application 

of the best system of emission reduction 

which (taking into account the cost of 

achieving such reduction and any nonair 

quality health and environmental impact and 

energy requirements) the Administrator 

determines has been adequately 

demonstrated. 

CAA section 111(a)(2). 

Once the Administrator promulgates 

standards for new sources under CAA 

section 111(b), the States, consistent 

with EPA regulatory requirements, must 

take action under CAA section 111(d) to 

establish requirements for ‘‘any existing 

source for any air pollutant (i) [that falls 

into specified categories] but (ii) to 

which a standard of performance under 

this section would apply if such existing 

source were a new source. * * *’’ 

Section 111(d)(1). An ‘‘existing source’’ 

is defined as ‘‘any stationary source 

other than a new source.’’ Section 

111(a)(6). 

b. Reasons for Not Applying the 1,000 

lb CO2/MWh Standard of Performance 

to Transitional Sources 

(i) Introduction 

In this action, the EPA is treating 

transitional sources as a distinct set of 

sources, although the EPA is not 

establishing a specific subcategory for 

these sources in the regulatory 

provisions.71 Under CAA section 111, 

the EPA may not apply a standard of 

performance to sources unless it reflects 

the ‘‘best system of emission reduction’’ 

(BSER) adequately demonstrated. 

As noted, the EPA proposes that nontransitional source fossil-fired power 

plants that commence construction after 

the date of proposal are subject to the 

standard of 1,000 lb CO2/MWh, and the 

EPA proposes to base this standard on 

the EPA’s identification of natural gas 

combined cycle (NGCC) as the BSER 

adequately demonstrated. The EPA 

justifies this proposal because owners or 

operators contemplating construction of 

non-transitional power plants to serve 

baseload and intermediate load demand 

have choices: They can choose the type 

of facility and therefore may choose to 

construct a NGCC plant. As a result, for 

these sources, NGCC constitutes the 

BSER, and the 1,000 lb CO2/MWh 

emission limit reflects that BSER and 

therefore is the appropriate standard of 

performance under section 111. 

Moreover, for those that choose to 

construct a coal-fired unit, they may 

choose to construct the plant in a place 

and a manner that allows installation of 

CCS—and thereby meet the 1,000 lb 

CO2/MWh standard—either at the time 

of construction or, in accordance with 

the 30-year averaging proposal, some 

years later. 

(ii) Transitional Sources and NGCC 

In contrast, the circumstances 

surrounding transitional sources are 

quite different. Transitional sources are 

a very small group of sources with a 

distinct profile of costs, preconstruction 

planning, overall business plans, 

technical and design concerns, and 

equitable concerns. Because they are 

such large facilities, their sunk costs and 

planning horizons are substantial. 

Transitional sources have already 

incurred substantial costs in permitting 

and taking other steps preparatory to 

commencing construction as coal-fired 

power plants within 12 months of the 

date of this proposal, which may 

include purchasing land for the new 

facility. Considering these sunk costs, 

converting their plant design to NGCC 

would be significantly more expensive 

than for proposed non-transitional 

sources that have not reached the stage 

of development that transitional sources 

have reached. The EPA is required to 

consider costs in determining the BSER 

adequately demonstrated, and under 

these circumstances, the costs factor 

points away from treating NGCC as 

BSER for transitional sources. 

In addition, because transitional 

sources have obtained a PSD permit and 

have developed their plans to the point 

where they are on the verge of 

commencing construction, the 

converting of their plant design to 

NGCC would be significantly more 

disruptive to their plans than for 

proposed non-transitional sources. It 

may require them to start over the 

process of developing the plant, and 

thereby render futile the planning and 

steps they have taken to date. These 

losses would, at a minimum, lead to 

delays in their commencing 

construction that realistically would be 

measured in years, and in fact may lead 

them to abandon the project. 

Although the potentially significant 

planning impacts at issue here are not 

explicitly identified as part of the 

definition of the ‘‘standard of 

performance,’’ they should nevertheless 

be considered in determining the BSER. 

This is because CAA section 111(a)(2), 

in its definition of ‘‘new source,’’ clearly 

contemplates that sources are expected 

to be able to commence construction 

after the EPA proposes, and before the 

EPA promulgates, a standard of 

performance applicable to them. There 

is nothing in CAA section 111 that 

suggests that Congress expected that the 

EPA may determine the BSER in a way 

that would significantly disrupt the 

plans of the regulated sources that are 

implicated here. Therefore, for this 

reason, too, the 1,000 lb CO2/MWh 

standard cannot be considered to reflect 

the BSER for transitional sources, and 

therefore cannot be the appropriate 

standard of performance. 

Nor can transitional sources 

reasonably be expected to meet the 

1,000 lb CO2/MWh standard through the 

installation of CCS, for the reasons 

discussed below. 

Note that the EPA takes the position 

that in this particular action, both of 

those factors—sunk costs and extent of 

planning to commence construction— 

must be considered in determining 

whether the 1,000 lb CO2/MWh 

standard reflects the BSER adequately 

demonstrated. That is, both are 

necessary conditions, and neither one, 

by itself, is a sufficient condition. We 

believe that these reasons concerning 

costs and planning suffice to justify our 

position that the 1,000 lb CO2/MWh 

standard is not appropriate for 

transitional sources. 

(iii) Coal-Fired Transitional Sources Not 

Designed for CCS 

As noted, while it is generally the 

case that proposed new sources could 

choose to build coal-fired power plants 

with CCS and thereby meet the 1,000 lb 

CO2/MWh standard, that is not the case 

for those transitional sources that are 

not designed for CCS. As a practical 

matter, it would be challenging for such 

a source to proceed with construction 

without substantial re-design of the 

project in order to install CCS and 

thereby be in compliance with the 1,000 

lb CO2/MwH standard. There are several 

reasons for this. First, captured CO2

must be sequestered or used. If this was 

not considered as part of the original 

site selection, the source will likely be 

significantly challenged in its efforts to 

adopt CCS. Second, if CCS was not 

considered in the original project 


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design, space considerations may make 

it difficult to now accommodate it in the 

facility’s design. Third, the requirement 

to use CCS could necessitate a change 

in the very power generation technology 

that a source may choose to use. For 

instance, instead of building a 

pulverized coal boiler, IGCC technology 

may be more appropriate. This is not to 

say that CCS could not be added to a 

project at this stage. Projects like the 

AEP Mountaineer project have shown 

that CCS can be successfully retrofitted 

into an existing plant. However, unlike 

in an existing facility where retrofit 

decisions must take into account 

previously made design decisions, in a 

facility in the pre-design phase, there is 

more opportunity for cost savings from 

re-designing the project, rather than 

having to adapt through retrofit. 

It bears emphasis that the 

requirements created by the new source 

standard in today’s action are 

fundamentally different from postcombustion controls required to meet 

new source standards for conventional 

pollutants in the sense that those 

controls could be much more easily redesigned into an already planned plant 

without changing the plant’s basic 

underlying characteristics (such as type 

of unit or even location). In contrast, 

CCS is more fundamental to both the 

design and siting of a unit, and therefore 

would likely involve fundamental 

changes to the underlying project. This 

is much more difficult in a project that 

has progressed through the permitting 

stage and is very close to commencing 

construction than it would be in other 

types of projects. 

(iv) Coal-Fired Transitional Sources 

Designed for CCS 

Although some of the proposed 

sources that may qualify as transitional 

sources are planning for CCS, that does 

not provide a basis for concluding that 

the 1,000 lb CO2/MWh standard is 

appropriate for them. As noted, the EPA 

is not, in this rulemaking, proposing 

that CCS is the BSER adequately 

demonstrated for coal-fired EGUs. 

Moreover, these proposed sources 

have established their location and 

developed their business plans without 

the expectation that the proposal in this 

rulemaking for CCS would apply to 

them. For example, their plans may 

assume installing CCS in a manner that 

results in emissions at levels higher 

than 1,000 lb CO2/MWh, or it may 

assume the sale of emission reduction 

credits based on an allowable emission 

rate above 1,000 lb CO2/MWh. 

Imposition of an unexpected emission 

rate requirement at such a late date 

could upset carefully crafted financial 

plans, causing delay or even 

cancellation of the project. 

Importantly, we do not have 

information as to key components of 

their proposed project and business 

plan, including, among other things, the 

amount of capture from the planned 

CCS system or possible revenue streams 

associated with CCS. Any proposal for 

what is BSER would depend on those 

costs and other information. 

Accordingly, we are not able to propose 

determinations that are essential to 

proposing the BSER for these proposed 

sources. As a result, we are not able to 

propose a standard of performance for 

these proposed sources. 

(v) Equitable Considerations 

For all transitional sources, the costs 

and delays discussed above give rise to 

equitable considerations that also 

support our treatment of these proposed 

sources. As noted, owners or operators 

of transitional sources have incurred 

significant expenses and undertaken a 

long planning period that has led them 

to being able to commence construction 

in the very near future, and, having 

invested so substantially in their current 

plans, should as an equitable matter be 

allowed to proceed without concern 

about requirements other than those in 

their PSD permits. To reiterate, they are 

in a posture that is fundamentally 

different from non-transitional sources. 

c. Reasons for Not Applying Other 

Standard of Performance 

Although, for the reasons described 

above, the 1,000 lb CO2/MWh standard 

that the EPA proposes for nontransitional sources does not reflect 

BSER for transitional sources, the EPA 

is not proposing any other standard of 

performance for transitional sources. It 

is reasonable to read section 111 not to 

require the EPA to propose a standard 

of performance when faced with the 

specific circumstances presented by 

transitional sources in the context of 

this rulemaking. These circumstances 

include: (1) The EPA’s lack of 

information with regard to these sources 

and the appropriate BSER for these 

sources; (2) the unique challenges with 

regard to adaptation of proposed 

projects to the requirements of this 

standard; (3) the small number of these 

sources and the possibility that 

promulgating a standard of performance 

would not have a beneficial 

environmental impact; and (4) although 

transitional sources would not be 

subject to the 1,000 lb CO2/MWh 

standard for new sources, the EPA 

anticipates that transitional sources 

would become subject to the 

requirements the EPA would 

promulgate at the appropriate time, for 

existing sources under 111(d). 

(i) CAA Requirements for Promulgating 

Standards of Performance for Sources in 

a Source Category 

The EPA interprets the CAA 

provisions described above to authorize 

the EPA not to promulgate a standard of 

performance for transitional sources. 

Under section 111(b)(1)(B), once the 

EPA lists a category of sources, the EPA 

is required to propose and promulgate 

standards of performance for new 

sources in that category. The EPA is not, 

however, required to promulgate 

standards of performance that cover all 

new sources . This is clear from the 

directive in section 111(b)(1)(B), which 

requires that the EPA propose standards 

of performance ‘‘for new sources’’ 

within the category, but does not require 

that the EPA propose such standards for 

all new sources or for any new source. 

The EPA may fulfill that directive by 

proposing standards that cover some, 

but not all, sources that newly 

commence construction or modification. 

Similarly, the term ‘‘new source’’ in 

section 111(a)(2) is defined to 

incorporate the limitation that the EPA 

must propose or promulgate a standard 

applicable to the source for the source 

to be considered ‘‘new.’’ That is, section 

111(a)(2) defines a ‘‘new source’’ as any 

source for which construction or 

modification commences after the EPA 

proposes ‘‘a standard of performance 

* * * which will be applicable to such 

source.’’ By its terms, this provision 

contemplates that the EPA may not 

propose a standard of performance 

applicable to certain sources, and that if 

the EPA does not, those sources would 

not be considered to be ‘‘new source[s]’’ 

and therefore not subject to any new 

source standard of performance. 

Thus, these provisions do not, by 

their terms, mandate that the EPA 

propose standards for each and every 

source in the source category. Under 

Chevron step 1, these provisions do not 

unambiguously require that the EPA 

propose standards of performance for all 

sources in the source category. We read 

these provisions as according the EPA 

some measure of discretion for the EPA 

to determine not to set standards for a 

particular portion of the source 

category, where appropriate, bounded 

by the principle of rationality. If these 

provisions are read to be ambiguous as 

to whether the EPA has discretion to 

propose and promulgate standards of 

performance for all sources in the 

source category, we believe it reasonable 

to read the provisions to provide such 

discretion in appropriate circumstances 

and that such reading is entitled to 


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22426 Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 

72As the U.S. Supreme Court recently stated in 

Massachusetts v. EPA, 549 U.S. 497, 524 (2007): 

‘‘Agencies, like legislatures, do not generally 

resolve massive problems in one fell regulatory 

swoop;’’ and instead they may permissibly 

implement such regulatory programs over time, 

‘‘refining their preferred approach as circumstances 

change and as they develop a more nuanced 

understanding of how best to proceed.’’ See Grand 

Canyon Air Tour Coalition v. F.A.A., 154 F.3d 455 

(DC Cir. 1998), City of Las Vegas v. Lujan, 891 F.2d 

927, 935 (DC Cir. 1989), National Association of 

Broadcasters v. FCC, 740 F.2d 1190, 1209–14 (DC 

Cir. 1984). 

73Note that because the basic rationale for EPA’s 

treatment of transitional sources is that they have 

already incurred substantial sunk costs and have 

positioned themselves to be close to commencing 

construction, and the one-year period for 

commencing construction is a surrogate for that, 

this treatment of transitional sources cannot 

logically be stretched to cover sources that do not 

commence within a substantially longer period. 

There is no reason to believe those latter sources 

would have, by the time of the proposal for the rest 

of the source category, already incurred significant 

costs and moved close to commencing construction. 

deference under Chevron step 2. In 

addition, interpreting these provisions 

to give the EPA the discretion not to 

propose and promulgate standards 

covering all sources in a category under 

appropriate circumstances—such as 

those present here—is consistent with 

the caselaw that authorizes agencies to 

establish a regulatory framework in an 

incremental fashion, that is, a step at a 

time.72

(ii) Precedents in Prior NSPS 

Rulemakings 

In applying section 111 over the past 

several decades, there have been a 

number of rulemakings in which the 

EPA has promulgated new source 

performance standards that do not cover 

all sources within the relevant source 

category that newly commence 

construction or modification. Some 

examples include the following: (i) In an 

early NSPS, involving lime kilns, the 

EPA promulgated an NSPS for certain 

types of kilns, but not for all types of 

sources that remained within the 

relevant source category. The DC 

Circuit, in its opinion reviewing the 

rule, noted this state of affairs, without 

expressing concerns. National Lime 

Ass’n v. EPA, 627 F.2d 416, 426 & n. 28 

(DC Cir. 1980) (noting that ‘‘of the 

various types of kilns that may be used 

in the calcinations of limestone, only 

rotary kilns are regulated by the 

standards,’’ and not ‘‘the vertical kiln; 

the rotary hearth kiln; and the fluidized 

bed kiln’’). (ii) In the EPA’s initial 

promulgation of NSPS regulations for 

petroleum refineries, the EPA did not 

promulgate standards of performance 

for certain units, including fluid coking 

units, delayed coking units, and process 

heaters, instead promulgating standards 

of performance for those units 

subsequently. See 40 CFR 60.100a(a); 

‘‘Standards of Performance for 

Petroleum Refineries: Proposed Rules,’’ 

72 FR 27178 (May 14, 2007). (iii) 

Similarly, in the EPA’s recent revision 

of the NSPS regulations for coal 

preparation and processing plants, the 

EPA ‘‘expand[ed] applicability of the 

existing NSPS by revising the 

definitions of thermal dryers, pneumatic 

coal-cleaning equipment, and coal. It 

also establishe[d] work practice 

standards for open storage piles. The 

final rule amend[ed] the definition of 

thermal dryer for units constructed, 

reconstructed, or modified after May 27, 

2009, to include both direct and indirect 

dryers drying all coal ranks (i.e., 

bituminous, subbituminous, lignite, and 

anthracite coals) and coal refuse.’’ 

‘‘Standards of Performance for Coal 

Preparation and Processing Plants,’’ 74 

FR 51950, 51952 (Oct. 8, 2009). (iv) In 

subpart KKKK of the NSPS regulations, 

the EPA promulgated regulations for the 

source category of stationary 

combustion turbines. The EPA did not 

promulgate regulations for turbines with 

smaller than 10 MMBtu/hr heat input, 

emergency units, or combustion turbine 

test cells. 40 CFR 60.4305(a), 60.4310(a), 

(d). (v) For other source categories, the 

EPA also declined to propose and 

promulgate standards of performance 

for the smaller sources. For example, for 

the source category of metal furniture 

coating operations, the EPA did not 

apply standards of performance to metal 

furniture surface coating operations that 

use less than 3.842 liters of coating (as 

applied) per year. 40 CFR 60.310(b). (vi) 

In proposing standards of performance 

for natural gas processing plants, the 

EPA proposed standards for only two of 

the three emission points in the plants 

(‘‘storage emission sources’’ and 

‘‘equipment leaks’’) and declined to 

propose standards for the third emission 

point (‘‘process emission sources’’) on 

grounds that ‘‘[b]est demonstrated 

control technology has not been 

identified for [the latter] sources.’’ 

‘‘Standards of Performance for New 

Stationary Sources; Onshore Natural 

Gas Processing Plants in the Natural Gas 

Production Industry, Equipment Leaks 

of VOC,’’ 49 FR 2636, 2637 (January 20, 

1984). 

(iii) Lack of Basis for Specifying 

Information 

A major reason why the EPA is not 

proposing a standard of performance for 

transitional sources is that it is relying, 

in part, on the one-year commenceconstruction limit to qualify a source as 

transitional: The EPA does not have 

sufficient information about the 

proposed sources’ sunk costs and 

preconstruction steps to be able to 

identify which of these proposed 

sources may qualify as transitional 

sources. In addition, even if the EPA 

could determine that a particular 

proposed source would in fact become 

a transitional source, the EPA lacks 

information that, under these 

circumstances, may be important for 

determining BSER. For example, the 

EPA lacks information as to the amount 

of the proposed source’s sunk costs, 

which may be relevant in determining 

BSER for these proposed sources. In 

addition, for proposed CCS sources, as 

noted above, the EPA does not have 

information as to key components of 

their proposed project and business 

plan, including, among other things, the 

amount of capture from the planned 

CCS system or possible revenue streams 

associated with CCS. 

Moreover, because transitional 

sources are defined by reference to the 

fact that they will commence 

construction within 12 months of the 

date of this proposal, it would be futile 

for the EPA to attempt to develop that 

information and then issue a proposal. 

By the time the EPA could do this, 

which would likely take at least a year, 

this set of sources will have become a 

null set: They either will have 

commenced construction, such that they 

would no longer be deemed ‘‘new 

sources’’ for purposes of CAA section 

111, or they will not have commenced 

construction, such that they would be 

subject to the new source standard for 

non-transitional sources we are 

proposing today.73

(iv) Practical Problems 

In addition, the EPA’s lack of 

information and other considerations 

give rise to several serious practical 

problems that would arise were the EPA 

to propose a standard of performance for 

transitional sources. Importantly, were 

the EPA to propose a standard of 

performance, all transitional sources 

would face substantial uncertainty as to 

what final standard the EPA would 

promulgate. This uncertainty would 

arise for several reasons. As noted, the 

EPA lacks information concerning 

transitional sources. In addition, 

transitional sources differ one from 

another in terms of design and in other 

respects, which would render the EPA’s 

task more complex. As a result, there is 

risk that the EPA might finalize 

standards of performance different from 

what the EPA proposed. The final 

standards of performance may be more 

difficult for a given transitional source 

to meet. 


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74This type of standard of performance could 

take one of several different forms, such as a 

standard that would not limit the source’s CO2

emissions, or a standard that the transitional source 

itself would identify as equaling the emission limit 

it would achieve through compliance with the 

applicable terms of its permit. 

75CAA section 111 does not explicitly include 

provisions for reconstructed sources. 

Other forms of uncertainty may arise 

as well. For example, a possible 

standard of performance that the EPA 

would consider would be based on 

identifying the BSER for transitional 

sources as the controls to which they 

would be subject under the terms of 

their PSD permits, with no further 

controls under section 111.74 With this 

approach, the EPA would need to 

determine the emission rate for each 

source that would reflect that source’s 

level of CO2 emissions in accord with 

the terms of its PSD permit. This 

emission rate would constitute the ‘‘nofurther-control’’ standard of 

performance. Note that under such an 

approach, each source would receive an 

emission limit unique to that source. 

However, some of the transitional 

sources may have a PSD permit that 

does not regulate CO2 because GHGs 

were not subject to PSD until the 

January 2, 2011 effective date of the first 

regulatory action controlling CO2

emissions under the CAA. Particularly 

for those sources, this approach could 

create uncertainty as to what the EPA 

would promulgate as the emission rate 

in the final standard of performance. 

This is because since these sources’ 

permits do not specify a CO2 limit, the 

EPA would have to develop limits based 

on the design of the unit (including the 

project’s type of technology and fuels). 

The uncertainties that the sources 

could experience as to what the final 

standards of performance would entail 

could well deter those sources from 

commencing construction until the EPA 

promulgated the final standard of 

performance. Such delay would 

undermine the usefulness of the 

requirement that sources commence 

construction within 12 months of 

today’s rulemaking proposal as a 

mechanism for revealing which of these 

sources qualifies as a transitional 

source, and thus defeat the policy 

underlying the EPA’s approach to 

transitional sources, which, for the 

reasons explained above, is to exclude 

from coverage by this new source 

standard only those sources that 

commence construction within 12 

months of proposal. If sources are 

deterred from commencing construction 

until after the final rule, they will have 

lost the benefit of the 12-month 

window. As another practical problem, 

we also note concern with attempting to 

promulgate standards of performance 

for transitional sources at a time when 

it may reasonably be expected that some 

of the 15 sources with PSD permits may 

well not commence construction within 

12 months (or may never do so). As a 

result, the effort to develop a standard 

of performance for those sources would 

have been unnecessary. 

(v) Small Number of Transitional 

Sources, Lack of Environmental Benefit 

As part of our reasoning for not 

proposing a standard of performance for 

transitional sources, we also take into 

consideration the fact that we expect the 

number of transitional sources to be 

small, no more than a few of the 15 

potential sources listed above. Further, 

if we were to propose a ‘‘no further 

control’’ standard of performance, as 

described above, that approach would 

provide little, if any, environmental 

benefit because that standard would not 

likely provide further control beyond 

the limits of the sources’ PSD permits. 

In fact, treating transitional sources as 

existing sources may achieve more 

reductions than a no-further-control 

NSPS standard for those sources by 

including them under the flexible 

existing source standard that the EPA 

expects to promulgate. 

(vi) Other Considerations 

The EPA’s approach of not proposing 

a standard of performance for 

transitional sources does not leave these 

sources uncontrolled. Rather, they 

would remain subject to whatever CO2

emission limits are included in, or 

result from compliance with, their PSD 

permits. And, although transitional 

sources would not be subject to the 

1,000 lb CO2/MWh for new sources, the 

EPA anticipates that transitional sources 

would become subject to the 

requirements the EPA would 

promulgate at the appropriate time for 

existing sources under 111(d). 

In notable contrast, in the previous 

rulemakings cited above in which the 

EPA did not propose coverage of all 

sources within the relevant source 

category, because of the pollutants at 

issue in these actions, the decision not 

to propose coverage of all sources 

within the relevant source category 

operated without the assurance afforded 

by section 111(d) that uncovered 

sources would necessarily be picked up 

as existing sources subject to existing 

source guidelines. Where, as here, that 

assurance mechanism applies, the 

recognition and application of the 

Agency’s discretion to not propose 

coverage of all sources in the source 

category is all the more appropriate. 

We recognize that this approach of 

not proposing a standard of performance 

for transitional sources could raise the 

question of consistency with the 

requirement implicit in the definition of 

‘‘new source’’ under CAA section 

111(a)(2) that a source be subject to a 

standard of performance when it 

commences construction after the date 

of proposal for that standard. We believe 

the approach is consistent with, and 

does not circumvent, that requirement. 

As noted, CAA section 111 does not 

require that all sources that newly 

commence construction be treated as 

new sources, and in past section 111 

rulemakings, the EPA has not applied 

the standards of performance that it 

proposes and promulgates to all sources 

that newly commence construction in a 

source category. In addition to the 

reasons for not promulgating a standard 

for transitional sources provided above, 

where, as here, the pollutants covered 

by the proposed new source standard 

give rise to an obligation to develop 

section 111(d) guidelines for existing 

sources with the source category, 

ultimate coverage of the sources in 

question is inevitable, eliminating any 

prospect of a regulatory gap of any 

material concern. 

C. Requirements for Reconstructions 

1. Overview 

The EPA’s framework regulations 

under CAA section 111 provide that 

reconstructed sources —which, in 

general, are existing sources that 

conduct extensive replacement of 

components—are to be treated as new 

sources and, therefore, subject to new 

source standards of performance. In 

today’s rulemaking, we do not propose 

any standard of performance for 

reconstructed sources, and we take 

comment how to approach 

reconstructions. We note that if we do 

not establish a new standard of 

performance for reconstructions, as a 

practical matter, that would mean that 

reconstructed sources would be treated 

as existing sources. 

2. Background 

a. The EPA Regulations. The EPA’s 

framework regulations, interpreting the 

definition of ‘‘new source’’ in CAA 

section 111(a)(2),75 provide that an 

existing source, ‘‘upon reconstruction,’’ 

becomes subject to the standard of 

performance for new sources. 40 CFR 

60.15(a). The regulations define 

‘‘reconstruction’’ as— 

[T]he replacement of components of an 

existing facility to such an extent that: 


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22428 Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 / Proposed Rules 

76 ‘‘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. 

(1) The fixed capital cost of the new 

components exceeds 50 percent of the fixed 

capital cost that would be required to 

construct a comparable entirely new facility, 

and 

(2) It is technologically and economically 

feasible to meet the applicable standards set 

forth in this part. 

40 CFR 60.15(b). Thus, a reconstruction 

occurs if the existing source replaces 

components to such an extent that the 

capital costs of the new components 

exceed 50 percent of the capital costs of 

an entirely new facility, even if the 

existing source does not increase 

emissions. In addition, the component 

replacement constitutes a reconstruction 

only if it is technologically and 

economically feasible for the source to 

meet the applicable standards. 

The regulations go on to require the 

owner or operator of an existing source 

that proposes to replace components to 

an extent that exceeds the 50 percent 

level, to notify the EPA and to provide 

specified information, including ‘‘a 

discussion of any economic or technical 

limitations the facility may have in 

complying with the applicable 

standards of performance after the 

proposed replacements.’’ In addition, 

the regulations require the EPA to 

determine, within a specified time 

period, whether the proposed 

replacement constitutes a 

reconstruction. 40 CFR 60.15(d)–(e). 

b. Reconstructions. As with 

modifications, our base of knowledge 

concerning reconstructions has 

depended largely on the enforcement 

actions brought against power plants 

and on self-reporting by power plants. 

Over the lengthy history of the NSPS 

program, those have been too few in 

number to allow us to develop a 

sufficiently robust base of knowledge to 

propose a standard of performance for 

reconstructions for GHGs at this time. 

The EPA is not aware that any power 

plants are presently planning any 

project that could meet the requirements 

for a reconstruction. 

2. Options 

In this action, the EPA is not issuing 

a proposal for affected sources that 

undertake reconstructions. Our 

reasoning is much the same as with 

NSPS modifications, which is that the 

lack of adequate information about the 

type of source; the type of changes; the 

extent of emissions increases; and the 

type of control measures, including 

their cost and emissions reductions, 

precludes proposing a standard of 

performance. Instead of issuing a 

proposal, the EPA solicits comment on 

all issues related to reconstructions, 

including the aspects just noted. 

Depending on the information the EPA 

acquires about reconstructions, the EPA 

may, in the future, propose and 

promulgate standards of performance 

for them. 

VI. Implications for PSD and Title V 

Programs 

A. Overview 

The proposal in this rulemaking 

would, for the first time, regulate GHGs 

under CAA section 111. Under the 

EPA’s regulations for the CAA PSD 

preconstruction permit program, and 

the CAA Title V operating permit 

program, regulation of GHGs under CAA 

section 111 triggers the applicability of 

PSD. Even so, today’s proposal should 

not require any additional SIP revisions 

to make clear that the Tailoring Rule 

thresholds—described below—continue 

to apply to the PSD program. 

This issue arises because States with 

approved PSD programs in their state 

implementation plans (SIPs) implement 

PSD, and most of these States have 

recently revised their SIPs to 

incorporate the higher thresholds for 

PSD applicability to GHGs that the EPA 

promulgated under what we call the 

Tailoring Rule.76 Commenters have 

queried whether under the EPA’s PSD 

regulations, promulgation of a section 

111 standard of performance 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) the EPA will 

proceed with a separate rulemaking 

action to narrow its approval of that 

state’s SIP so as to assure that for federal 

purposes, the Tailoring Rule thresholds 

will continue to apply as of the effective 

date of today’s rulemaking. 

In the alternative, if the Tailoring Rule 

thresholds did not continue to apply 

when the EPA promulgates 

requirements under CAA section 111, 

then the EPA would shortly proceed 

with a separate rulemaking action to 

narrow its approval of all of the State’s 

approved SIP PSD programs to assure 

that for federal purposes, the Tailoring 

Rule thresholds will continue to apply 

as of the effective date of today’s 

proposal. 

As discussed below, in the case of 

title V, today’s rulemaking does not 

have implications for the Tailoring Rule 

thresholds established with respect to 

sources subject to title V requirements. 

B. Implications for PSD Program 

Under the PSD program in part C of 

title I of the CAA, in areas that are 

classified as attainment or unclassifiable 

for NAAQS pollutants, a new or 

modified source that emits any air 

pollutant subject to regulation at or 

above specified thresholds, is required 

to obtain a preconstruction permit. This 

permit assures that the source meets 

specified requirements, including 

application of best available control 

technology. States authorized for the 

PSD program may issue PSD permits. If 

a state is not authorized, then the EPA 

issues the PSD permits. 

Regulation of GHG emissions in the 

Light Duty Vehicle Rule (75 FR 25324) 

triggered applicability of stationary 

sources to regulations for GHGs under 

the PSD and title V provisions of the 

CAA. Hence, on June 3, 2010 (75 FR 

31514), the EPA issued the ‘‘Tailoring 

Rule,’’ which establishes thresholds for 

GHG emissions in order to define and 

limit when new and modified industrial 

facilities must have permits under the 

PSD and title V programs. The rule 

addresses emissions of six GHGs: CO2, 

CH4, N2O, HFCs, PFCs and SF6. On 

January 2, 2011, large industrial sources, 

including power plants, became subject 

to permitting requirements for their 

GHG emissions if they were already are 

required to obtain PSD or title V permits 

due to emissions of other (non-GHG) air 

pollutants. 

Commenters have queried whether, 

because of the way that the EPA’s PSD 

regulations are written, promulgating 

the rule we propose today may raise 

questions as to whether the EPA must 

revise its PSD regulations—and, by the 

same token, whether states must revise 

their SIPs—to assure that the Tailoring 

Rule thresholds will continue to apply 

to sources subject to PSD. That is, under 

the EPA’s regulations, PSD applies to a 

‘‘major stationary source’’ that 


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77This position reads the regulations to be 

consistent with the CAA PSD provisions 

themselves. Under those provisions, PSD applies to 

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

mean stationary sources that emit or have the 

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

or 250 tons per year, depending on the source 

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

interpreted these provisions to apply PSD to a 

stationary source that emits the threshold amounts 

of any air pollutant subject to regulation. See 

Tailoring Rule, 75 FR 31579. Under these 

provisions, at present, PSD is already applicable to 

GHGs because GHGs are already subject to 

regulation, and regulating GHGs under CAA section 

111 does not any additional type of PSD trigger. 

undertakes construction, 40 CFR 

51.166(a)(7)(i), and to a ‘‘major 

modification.’’ 40 CFR 51.166(a)(7)(iii). 

A ‘‘major modification’’ is defined as 

‘‘any physical change in or change in 

the method of operation of a major 

stationary source that would result in a 

significant emissions increase * * * 

and a significant net emissions increase. 

* * *’’ Thus, for present purposes, the 

key component of these applicability 

provisions is that PSD applies to a 

‘‘major stationary source.’’ This term is 

the regulatory replacement for the term 

‘‘major emitting facility,’’ which is 

central to the PSD applicability 

requirements established in the CAA 

itself, under sections 165(a)(1) and 

169(1). 

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’’ to include, among other 

things, ‘‘Any pollutant that is subject to 

any standard promulgated under section 

111 of the Act.’’ 40 CFR 

51.166(b)(49)(ii). 

Thus, the PSD regulations contain a 

separate PSD trigger for pollutants 

regulated under the NSPS, 40 CFR 

51.166(b)(49)(ii) (the ‘‘NSPS trigger 

provision’’), so that as soon as the EPA 

promulgates the first NSPS for a 

particular air pollutant, as we are doing 

in this rulemaking with respect to the 

GHG air pollutant, then PSD is triggered 

for that air pollutant. 

The Tailoring Rule, on the face of its 

regulatory provisions, incorporated the 

revised thresholds it promulgated into 

only the fourth prong (‘‘[a]ny pollutant 

that otherwise is subject to regulation 

under the Act’’), and not the second 

prong (‘‘[a]ny pollutant that is subject to 

any standard promulgated under section 

111 of the Act’’). For this reason, a 

question may arise as to whether the 

Tailoring Rule thresholds apply to the 

PSD requirement as triggered by the 

NSPS that the EPA is promulgating in 

this rulemaking. 

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, 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’’).77 To clarify and 

confirm that the Tailoring Rule 

thresholds apply to the section 111 

prong of the definition of regulated NSR 

pollutant, in this proposed rulemaking, 

the EPA is proposing to revise the NSPS 

regulations, although not the PSD 

regulations, to explicitly make clear that 

the NSPS trigger provision in the PSD 

regulations incorporate the Tailoring 

Rule thresholds. 

As a result, the EPA believes that 

states that incorporated the Tailoring 

Rule thresholds into their SIPs may take 

the position that they also incorporated 

the EPA’s interpretation in the preamble 

that the thresholds apply to the 

definition ‘‘major stationary source.’’ 

The EPA requests that all States with 

approved SIP PSD programs that apply 

to GHGs indicate during the comment 

period on this rule whether they can 

interpret their SIPs already to apply the 

Tailoring Rule thresholds to the NSPS 

prong or whether they must revise their 

SIPs. For any State that says it must 

revise its SIP (or that does not respond), 

the EPA expects to propose a rule that 

is comparable to the SIP PSD Narrowing 

Rule shortly after the close of the 

comment period, and expects to finalize 

that rule at the same time that it 

finalizes this NSPS rule. 

C. Implications for Title V Program 

Under the title V program, a source 

that emits any air pollutant subject to 

regulation at or above specified 

thresholds (along with certain other 

sources) is required to obtain an 

operating permit. This permit includes 

all of the CAA requirements applicable 

to the source. These permits are 

generally issued through EPA-approved 

State title V programs. 

As the EPA explained in the Tailoring 

Rule preamble, title V applies to a 

‘‘major source,’’ CAA section 502(a), 

which is defined to include, among 

other things, certain sources, including 

any ‘‘major stationary source,’’ CAA 

section 501(2)(B), which, in turn, is 

defined to include a stationary source of 

‘‘any air pollutant’’ at or above 100 tpy. 

CAA section 302(j). The EPA’s 

regulations under title V define the term 

‘‘major source,’’ and in the Tailoring 

Rule, the EPA revised that definition to 

make clear that the term is limited to 

stationary sources that emit any air 

pollutant ‘‘subject to regulation.’’ The 

EPA incorporated the Tailoring Rule 

threshold within this definition of 

‘‘subject to regulation.’’ The EPA 


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described its action as follows in the 

preamble to the Tailoring Rule: 

Thus, EPA is adding the phrase ‘‘subject to 

regulation’’ to the definition of ‘‘major 

source’’ under 40 CFR 70.2 and 71.2. EPA is 

also adding to these regulations a definition 

of ‘‘subject to regulation.’’ Under the part 70 

and part 71 regulatory changes adopted, the 

term ‘‘subject to regulation,’’ for purposes of 

the definition of ‘‘major source,’’ has two 

components. The first component codifies 

the general approach EPA recently 

articulated in the ‘‘Reconsideration of 

Interpretation of Regulations That Determine 

Pollutants Covered by Clean Air Act 

Permitting.’’ 75 FR 17704. Under this first 

component, a pollutant ‘‘subject to 

regulation’’ is defined to mean a pollutant 

subject to either a provision in the CAA or 

regulation adopted by EPA under the CAA 

that requires actual control of emissions of 

that pollutant and that has taken effect under 

the CAA. See id. at 17022–23; Wegman 

Memorandum at 4–5. To address tailoring for 

GHGs, EPA includes a second component of 

the definition of ‘‘subject to regulation,’’ 

specifying that GHGs are not subject to 

regulation for purposes of defining a major 

source, unless as of July 1, 2011, the 

emissions of GHGs are from a source emitting 

or having the potential to emit 100,000 tpy 

of GHGs on a CO2e basis. 

75 FR at 31,583. 

Unlike the PSD regulations described 

above, the title V definition of ‘‘major 

source’’, as revised by the Tailoring 

Rule, does not on its face distinguish 

among types of regulatory triggers for 

title V. Because title V has already been 

triggered for GHG-emitting sources, the 

promulgation of CAA section 111 

requirements has no further impact on 

title V requirements for major sources of 

GHGs. Accordingly, today’s rulemaking 

has no title V implications with respect 

to the Tailoring Rule threshold. Of 

course, unless exempted by the 

Administrator through regulation under 

CAA section 502(a), sources subject to a 

NSPS are required to apply for, and 

operate pursuant to, a title V permit that 

assures compliance with all applicable 

CAA requirements for the source, 

including any GHG-related 

requirements. We have concluded that 

this rule will not affect non-major 

sources and there is no need to consider 

whether to exempt non-major sources 

VII. Impacts of the Proposed Action 

A. What are the air impacts? 

The EPA believes that electric power 

companies would choose to build new 

EGUs that comply with the regulatory 

requirements of this proposal even in 

the absence of this proposal, because of 

existing and expected market 

conditions. We do not project any new 

coal-fired EGUs without CCS to be built 

in the absence of this proposal. 

Accordingly, the EPA believes that this 

proposed rule is not likely to produce 

changes in emissions of greenhouse 

gases or other pollutants although it 

does encourage the current trend 

towards cleaner generation. 

B. What are the energy impacts? 

This proposed rule is not anticipated 

to have a notable effect on the supply, 

distribution, or use of energy. As 

previously stated, we believe that 

electric power companies would choose 

to build new EGUs that comply with the 

regulatory requirements of this proposal 

even in the absence of the proposal, 

because of existing and expected market 

conditions. In addition, we do not 

project any new coal-fired EGUs 

without CCS to be built in the absence 

of this proposal. 

C. What are the compliance costs? 

The EPA believes this proposed rule 

will have no notable compliance costs 

associated with it, because electric 

power companies would be expected to 

build new EGUs that comply with the 

regulatory requirements of this proposal 

even in the absence of the proposal, due 

to existing and expected market 

conditions. The EPA does not project 

any new coal-fired EGUs without CCS to 

be built in the absence of the proposal. 

D. How will this proposal contribute to 

climate change protection? 

As previously explained, the special 

characteristics of GHGs make it 

important to take initial steps to control 

the largest emissions categories without 

delay. Unlike most traditional air 

pollutants, GHGs persist in the 

atmosphere for time periods ranging 

from decades to millennia, depending 

on the gas. Fossil-fueled power plants 

emit more GHG emissions than any 

other stationary source 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 2020. Essentially the EPA 

believes that owners of newly built 

electric generating units will choose 

technologies that meet these standards 

even in the absence of this proposal due 

to existing economic conditions as 

normal business practice. Likewise, we 

believe this rule will not have any 

impacts on the price of electricity, 

employment or labor markets, or the US 

economy. 

F. What are the benefits of the proposed 

standards? 

As previously stated, the EPA does 

not anticipate that the power industry 

will incur compliance costs as a result 

of this proposal and we do not 

anticipate any notable CO2 emission 

changes resulting from the rule. 

Therefore, there are no direct monetized 

climate benefits in terms of CO2

emission reductions associated with this 

rulemaking. However, by clarifying that 

in the future, new coal-fired power 

plants will be required to install CCS, 

this rulemaking eliminates uncertainty 

about the status of coal and may well 

enhance the prospects for new coal-fired 

generation and the deployment of CCS, 

and thereby promote energy diversity. 

VIII. Request for Comments 

We request comments on all aspects 

of the proposed rulemaking including 

the RIA. All significant comments 

received will be considered in the 

development and selection of the final 

rule. We specifically solicit comments 

on additional issues under 

consideration as described below. 

CEMS. We are considering and 

requesting comment on requiring the 

use of CO2 CEMS including stack gas 

flow rate monitoring for all new affected 

facilities, including those burning 

exclusively natural gas and/or distillate 

oil. In addition, we are requesting 

comment on requiring the use the 

following measurement procedures in 

conducting CEMS relative accuracy 

testing: 

a. EPA Method 2F of 40 CFR part 60 

for flow rate measurement during the 

relative accuracy test audit and 

performance testing. Method 2F 

provides velocity data for three 

dimensions and provides measurements 

more representative of actual gas flow 

rates than EPA Method 2 or 2G of 40 

CFR part 60. 

b. EPA Method 2H of 40 CFR part 60 

or Conditional Test Method (CTM)–041 


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78http://www.physicalgeography.net/ 

fundamentals/7a.html. 

(see: http://www.epa.gov/airmarkets/ 

emissions/docs/square-ducts-walleffects-test-method-ctm-041.pdf) to 

account for wall effects on for stack gas 

flow rate calculations during CEMS 

relative accuracy determinations and for 

performance testing. 

c. EPA Method 4 of 40 CFR part 60 

to determine moisture for flow rate 

during CEMS relative accuracy 

determinations and for performance test 

calculations. 

d. EPA Method 3A of 40 CFR part 60 

for CO2 concentration measurement and 

for molecular weight determination 

during CEMS relative accuracy 

determinations or for performance 

testing. Account for ambient air argon 

concentration of 0.93 percent 78 and a 

molecular weight of 39.9 lb/lb-mol in 

calculating the dry gas molecular 

weight. 

e. Measure the stack diameter at the 

CEMS measurement site and the 

reference method sampling site with a 

laser distance measurement device. 

Determine the mean average of three 

separate diameter measurements for 

circular stack areas or the mean average 

of three depth and width measurements 

for rectangular measurement areas. 

Calculate the effective stack area for all 

flow rate measurements, both CEMS 

system and Reference Method, using 

this measurement data. This would be a 

one-time measurement that would fix 

the effective area of the stack emissions 

point unless a new location is chosen 

for the CEMS or Reference Method 

measurement point. All calculations 

involving pi would use a value of 

3.14159. 

f. Apply a daily calibration drift 

criteria not to exceed 0.3 percent CO2

for CO2 CEMS. 

g. Do not exceed a relative accuracy 

specification of 2.5 percent for both CO2

and flow rate measurement CEMS. 

We also request comment on whether 

Method 3B of 40 CFR part 60 (integrated 

bag sample), in addition to Method 3A, 

should be allowed for CO2

concentration measurement and for 

molecular weight determination during 

CEMS relative accuracy determinations 

or for performance testing. 

Coal refuse. Due to the multiple 

environmental benefits of remediating 

coal refuse piles, we are considering and 

requesting comment on subcategorizing 

EGUs that burn over 75 percent coal 

refuse on an annual basis. As part of the 

GHG listening sessions, one commenter 

mentioned the advantages of utilizing 

coal refuse to create electricity. The 

commenter stated that if net emissions 

caused by using mining waste to 

generate electricity are calculated, then 

mining waste facility would produce no 

net GHG emissions in the long term and 

emissions would be no greater than the 

short term emissions of a combined 

cycle gas plant in. The comment states 

that due to the size of the piles, mining 

waste pile exposure to atmospheric 

oxygen and pressure promotes heatgenerating reactions, primarily 

oxidation of the mining waste itself (i.e., 

the coal refuse piles are slowly burning). 

This process emits CO2 and other air 

pollutants. Remediation would stop 

current and future CO2 emissions 

resulting from the uncontrolled 

combustion of waste piles. 

Coordinates. We realize that 

geographic latitude and longitude 

coordinates of each stack in terms of 

decimal degrees are presently reported 

to the EPA’s Clean Air Markets Division 

in terms of four decimal points to the 

right of the decimal point. We are 

requesting comment on whether we 

should require owners/operators of 

affected facilities to submit to the EPA 

Administrator the geographic latitude 

and longitude coordinates of each stack 

to have at least six values to the right 

of the decimal for each location. By way 

of example, the coordinates for the 

monument next to Zachary Taylor’s 

tomb in Louisville, KY are 38.279401 

latitude and -85.643751 longitude. 

Combined Heat and Power. We are 

also considering and requesting 

comment on if exempting all CHP 

facilities where useful thermal output 

accounts for at least 20 percent of the 

total useful output from this proposed 

rule would recognize the environmental 

benefit of CHP and result in additional 

installations that would otherwise no 

occur. In considering exemption of CHP 

units, the EPA is particularly interested 

in the overall impact this would have on 

the composition of new builds. The 

definition of affected sources under this 

rule already exempts CHP sources that 

primarily generate on-site power. 

Therefore, as explained earlier, today’s 

proposal does not impact any of the 

small amount of projected coal-fired 

CHP in EIA’s AEO 2011. CHPs that 

would be covered by this rule generate 

and sell large quantities of electricity. 

While building such units is more 

energy efficient and results in some 

GHG reductions, building new coalfired units to meet a standard of 1,000 

lb CO2/MWh would likely result in 

greater reductions. If potential 

developers of new coal-fired generation 

opted instead to build coal-fired CHP to 

avoid the CO2 limitations proposed 

under today’s rule, it could result in 

greater emissions of CO2. Furthermore, 

requiring such units to meet a standard 

of 1,000 lb CO2/MWh does not preclude 

new coal-fired units from being CHP 

units. 

Format of the Proposed Standards. 

Although we have proposed gross 

output-based emission standards, the 

EPA believes that the net power 

supplied to the end user is a better 

indicator of environmental performance 

than gross output from the power 

producer. Net output is the combination 

of the gross electrical output of the 

electric generating unit minus the 

parasitic power requirements. A 

parasitic load for an electric generating 

unit is any of the loads or devices 

powered by electricity, steam, hot water, 

or directly by the gross output of the 

electric generating unit that does not 

contribute electrical, mechanical, or 

thermal output. In general, less than 7.5 

percent of coal-fired station power 

output, and about 2.5 percent of a 

combined cycle station power output, is 

used internally by parasitic energy 

demands, but the amount of these 

parasitic loads vary from source to 

source. Reasons for using net output 

include (1) recognizing the efficiency 

gains of selecting EGU designs and 

control equipment that require less 

auxiliary power, (2) selecting fuels that 

require less emissions control 

equipment, and (3) recognizing the 

environmental benefit of higher 

efficiency motors, pumps, and fans. In 

addition, use of a gross output-based 

standard could potentially drive the 

installation of electrically driven feed 

pumps instead of steam driven feed 

pumps, even though from an overall net 

efficiency basis, it may be more efficient 

to use steam-driven feed pumps. 

Further, monitoring net output for new 

and reconstructed facilities can be 

designed into the facility at low costs. 

Thus, we are requesting comment on the 

use of net output-based emission 

standards for owners/operators of new 

facilities. 

Stationary Simple Cycle Turbines. As 

stated in the preamble, the intent of the 

proposed regulations is to cover 

stationary combustion turbines use for 

intermediate and base load electric 

power generation and to exempt 

stationary combustion turbines used for 

peaking operations (i.e., simple cycle 

turbines). We are considering and 

requesting comment on not including a 

definition of simple cycle turbines in 

the final rule. The potential electric 

output requirement in the definition of 

electric generating unit would already 

exclude facilities with permit restricting 

limiting operation to less than 1⁄3 of 

their potential electric output, 

approximately 2,900 hours of full load 


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operation annually. The peaking season 

is generally considered to be less than 

2,500 hours annually, and we are 

requesting comment on if the capacity 

factor exemption is sufficient such that 

specifically exempting simple cycle 

turbine is unnecessary. We are also 

requesting comment on whether the 

exemption would provide a perverse 

incentive to build less efficient simple 

cycle combustion turbines in order to 

avoid applicability with the proposed 

rule. While few existing simple cycle 

turbines presently generate greater than 

1⁄3 of their potential electric output for 

sale, we are requesting comment on 

whether the exemption for simple cycle 

turbines would result in the greater use 

of simple cycle turbines for intermediate 

load applications when more efficient 

combined cycle facilities would have 

otherwise been built. In addition, it is 

our understanding that combined cycle 

facilities are sometimes built in stages 

with the combustion turbine engine 

installation occurring first and the heat 

recovery steam generator being installed 

in later years as electricity demand 

increases. We are requesting comment 

on whether the exemption would 

potentially delay the installation of the 

heat recovery steam generator portion of 

new combined cycle facilities. Finally, 

in the event we use the definition 

approach in the final rule, we are 

requesting comment on whether a CHP 

facility that uses the recovered exhaust 

heat for purposes other than to generate 

steam and recuperated combustion 

turbines should be considered simple or 

combined cycle combustion turbines. 

IX. Statutory and Executive Order 

Reviews 

A. Executive Order 12866, Regulatory 

Planning and Review, and Executive 

Order 13563, Improving Regulation and 

Regulatory Review 

Under Executive Order (EO) 12866 

(58 FR 51,735, October 4, 1993), this 

action is a ‘‘significant regulatory 

action’’ because it ‘‘raises novel legal or 

policy issues arising out of legal 

mandates’’. Accordingly, the EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under Executive Orders 12866 

and 13563 (76 FR 3821, January 21, 

2011) and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. In addition, the EPA 

prepared an analysis of the potential 

costs and benefits associated with this 

action. This analysis is contained in the 

Regulatory Impact Analysis for the 

Standards of Performance for 

Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility 

Generating Units. 

The EPA believes this rule will have 

no notable compliance costs associated 

with it over a range of likely sensitivity 

conditions because electric power 

companies would choose to build new 

EGUs that comply with the regulatory 

requirements of this proposal even in 

the absence of the proposal, because of 

existing and expected market 

conditions. (See the RIA for further 

discussion of sensitivities.) Because our 

modeling shows that natural gas-fired 

plants are the facilities of choice, the 

proposed standard of performance— 

which is based on the emission rate of 

a new NGCC unit—would not add costs. 

The EPA does not project any new coalfired EGUs without CCS to be built in 

the absence of this proposal. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by the EPA has been 

assigned EPA ICR number 2465.01. 

This proposed action would impose 

minimal new information collection 

burden on affected sources beyond what 

those sources would already be subject 

to under the authorities of CAA parts 75 

and 98. OMB has previously approved 

the information collection requirements 

contained in the existing part 75 and 98 

regulations (40 CFR part 75 and 40 CFR 

part 98) under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control numbers 2060–0626 and 2060– 

0629, respectively. Apart from certain 

reporting costs based on requirements in 

the NSPS General Provisions (40 CFR 

part 60, subpart A), which are 

mandatory for all owners/operators 

subject to CAA section 111 national 

emission standards, there are no new 

information collection costs, as the 

information required by this proposed 

rule is already collected and reported by 

other regulatory programs. The 

recordkeeping and reporting 

requirements are specifically authorized 

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

All information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart B. 

The EPA believes that electric power 

companies will choose to build new 

EGUs that comply with the regulatory 

requirements of this proposal because of 

existing and expected market 

conditions. The EPA does not project 

any new coal-fired EGUs that commence 

construction after this proposal to 

commence operation over the 3-year 

period covered by this ICR. We estimate 

that 17 new affected NGCC units would 

commence operation during that time 

period. As a result of this proposal, 

those units would be required to 

prepare a summary report, which 

includes reporting of excess emissions 

and downtime, every 6 months. 

When a malfunction occurs, sources 

must report them according to the 

applicable reporting requirements of 40 

CFR part 60, subpart TTTT. An 

affirmative defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions is available to a 

source if it can demonstrate that certain 

criteria and requirements are satisfied. 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction (sudden, 

infrequent, not reasonable preventable, 

and not caused by poor maintenance 

and or careless operation) and where the 

source took necessary actions to 

minimize emissions. In addition, the 

source must meet certain notification 

and reporting requirements. For 

example, the source must prepare a 

written root cause analysis and submit 

a written report to the Administrator 

documenting that it has met the 

conditions and requirements for 

assertion of the affirmative defense. 

To provide the public with an 

estimate of the relative magnitude of the 

burden associated with an assertion of 

the affirmative defense position adopted 

by a source, the EPA has estimated what 

the notification, recordkeeping, and 

reporting requirements associated with 

the assertion of the affirmative defense 

might entail. The EPA’s estimate for the 

required notification, reports, and 

records, including the root cause 

analysis, associated with a single 

incident totals approximately totals 

$3,141, and is based on the time and 

effort required of a source to review 

relevant data, interview plant 

employees, and document the events 

surrounding a malfunction that has 

caused an exceedance of an emission 

limit. The estimate also includes time to 

produce and retain the record and 

reports for submission to the EPA. The 

EPA provides this illustrative estimate 

of this burden, because these costs are 

only incurred if there has been a 

violation, and a source chooses to take 

advantage of the affirmative defense. 


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The EPA provides this illustrative 

estimate of this burden because these 

costs are only incurred if there has been 

a violation and a source chooses to take 

advantage of the affirmative defense. 

Given the variety of circumstances 

under which malfunctions could occur, 

as well as differences among sources’ 

operation and maintenance practices, 

we cannot reliably predict the severity 

and frequency of malfunction-related 

excess emissions events for a particular 

source. It is important to note that the 

EPA has no basis currently for 

estimating the number of malfunctions 

that would qualify for an affirmative 

defense. Current historical records 

would be an inappropriate basis, as 

source owners or operators previously 

operated their facilities in recognition 

that they were exempt from the 

requirement to comply with emissions 

standards during malfunctions. Of the 

number of excess emissions events 

reported by source operators, only a 

small number would be expected to 

result from a malfunction (based on the 

definition above), and only a subset of 

excess emissions caused by 

malfunctions would result in the source 

choosing to assert the affirmative 

defense. Thus, we believe the number of 

instances in which source operators 

might be expected to avail themselves of 

the affirmative defense will be 

extremely small. In fact, we estimate 

that there will be no such occurrences 

for any new sources subject to 40 CFR 

part 60, subpart TTTT over the 3-year 

period covered by this ICR. We expect 

to gather information on such events in 

the future, and will revise this estimate 

as better information becomes available. 

The annual information collection 

burden for this collection consists only 

of reporting burden as explained above. 

The reporting burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $15,570 and 396 labor 

hours. This estimate includes semiannual summary reports which include 

reporting of excess emissions and 

downtime. All burden estimates are in 

2010 dollars. Average burden hours per 

response are estimated to be 16.5 hours. 

The total number of respondents over 

the 3-year ICR period is estimated to be 

36. Burden is defined at 5 CFR 

1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for 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–2011–0660. 

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 EPA. Since OMB is required 

to make a decision concerning the ICR 

between 30 and 60 days after April 13, 

2012, a comment to OMB is best assured 

of having its full effect if OMB receives 

it by May 14, 2012. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act as 

Amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996, 5 U.S.C. et seq. 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, small 

entity is defined as: 

(1) A small business that is defined by 

the SBA’s regulations at 13 CFR 121.201 

(for the electric power generation 

industry, the small business size 

standard is an ultimate parent entity 

defined as having a total electric output 

of 4 million MWh or less in the previous 

fiscal year. The NAICS codes for the 

affected industry are in Table 4 below); 

(2) A small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and 

(3) A small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

TABLE 4—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Category NAICS Code Examples of potentially regulated 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 Include NAICS categories for source categories that own and operate electric power generating units (includes boilers and stationary combined cycle combustion turbines). b Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

We do not include an analysis of the 

illustrative impacts on small entities 

that may result from implementation of 

this proposed rule because we do not 

anticipate any compliance costs over a 

range of likely sensitivity conditions as 

a result of this proposal. Thus the 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.) Because our 

modeling shows that natural gas-fired 

plants are the facilities of choice, the 

proposed standard of performance— 

which is based on the emission rate of 

a new NGCC unit—would not add costs. 

The EPA does not project any new coalfired EGUs without CCS to be built. 

Accordingly, there are no anticipated 


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economic impacts as a result of this 

proposal. 

Nevertheless, the EPA is aware that 

there is substantial interest in this rule 

among small entities (municipal and 

rural electric cooperatives). In light of 

this interest, the EPA determined to 

seek early input from representatives of 

small entities while formulating the 

provisions of this proposed regulation. 

Such outreach is also consistent with 

the President’s January 18, 2011 

Memorandum on Regulatory Flexibility, 

Small Business, and Job Creation, which 

emphasizes the important role small 

businesses play in the American 

economy. This process has enabled the 

EPA to hear directly from these 

representatives, at a very preliminary 

stage, about how it should approach the 

complex question of how to apply 

Section 111 of the CAA to the regulation 

of GHGs from these source categories. 

The EPA’s outreach regarded planned 

actions for new and existing sources, 

but only new sources would be affected 

by this proposed action. 

The EPA conducted an initial 

outreach meeting with small entity 

representatives on April 6, 2011. The 

purpose of the meeting was to 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. 

Small entities expressed concern 

regarding units making modifications 

being regulated as new sources. As 

explained above, we are not proposing 

a standard of performance for 

modifications. As a result, sources that 

undertake modifications would be 

treated as existing sources and thus 

would not be subject to the 

requirements proposed in this notice. 

As also explained above, the EPA is not 

proposing standards of performance for 

existing proposed EGUs, which are 

referred to as transitional sources, that 

have acquired a complete 

preconstruction permit by the time of 

this proposal and that commence 

construction within 12 months of this 

proposal. As a result, any transitional 

sources owned by small entities would 

not be subject to the standards of 

performance proposed in today’s rule. 

We invite comments on all aspects of 

the proposal and its impacts, including 

potential adverse impacts, on small 

entities. 

D. Unfunded Mandates Reform Act of 

1995 

This proposed rule does not contain 

a Federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or the private sector in 

any one year. The EPA believes this 

proposed rule will have no compliance 

costs associated with it over a range of 

likely sensitivity conditions because 

electric power companies will choose to 

build new EGUs that comply with the 

regulatory requirements of this proposal 

because of existing and expected market 

conditions. (See the RIA for further 

discussion of sensitivities.) As 

previously explained, because our 

modeling shows that natural gas-fired 

plants are the facilities of choice, the 

proposed standard of performance— 

which is based on the emission rate of 

a new NGCC unit—would not add costs. 

The EPA does not project any new coalfired 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. The EPA invited 

the following 10 national organizations 

representing state and local elected 

officials to a meeting held on April 12, 

2011, in Washington DC: (1) National 

Governors Association; (2) National 

Conference of State Legislatures, (3) 

Council of State Governments, (4) 

National League of Cities, (5) U.S. 

Conference of Mayors, (6) National 

Association of Counties, (7) 

International City/County Management 

Association, (8) National Association of 

Towns and Townships, (9) County 

Executives of America, and (10) 

Environmental Council of States. These 

10 organizations representing elected 

state and local officials have been 

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

organizations appropriate to contact for 

purpose of consultation with elected 

officials. The purposes of the 

consultation were to provide general 

background on the proposal, answer 

questions, and solicit input from state/ 

local governments. The EPA’s 

consultation regarded planned actions 

for new and existing sources, but only 

new sources would be affected by this 

proposed action. 

During the meeting, officials asked 

clarifying questions regarding CAA 

section 111 requirements and efficiency 

improvements that would reduce CO2

emissions. In addition, they expressed 

concern with regard to the potential 

burden associated with impacts on state 

and local entities that own/operate 

affected utility boilers, as well as on 

state and local entities with regard to 

implementing the rule. Subsequent to 

the April 12, 2011 meeting, the EPA 

received a letter from the National 

Conference of State Legislatures. In that 

letter, the National Conference of State 

Legislatures urged the EPA to ensure 

that the choice of regulatory options 

maximizes benefit and minimizes 

implementation and compliance costs 

on state and local governments; to pay 

particular attention to options that 

would provide states with as much 

flexibility as possible; and to take into 

consideration the constraints of the state 

legislative calendars and ensure that 

sufficient time is allowed for state 


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actions necessary to come into 

compliance. 

E. Executive Order 13132, Federalism 

This proposed action does not have 

federalism implications. It would not 

have substantial direct effects on the 

States, on the relationship between the 

national government and the States, or 

on the distribution of power and 

responsibilities among the various 

levels of government, as specified in EO 

13132. This proposed action would not 

impose substantial direct compliance 

costs on state or local governments, nor 

would it preempt state law. Thus, 

Executive Order 13132 does not apply 

to this action. The EPA consulted with 

state and local officials in the process of 

developing the proposed rule to permit 

them to have meaningful and timely 

input into its development. The EPA’s 

consultation regarded planned actions 

for new and existing sources, but only 

new sources would be affected by this 

proposed action. The EPA met with 10 

national organizations representing state 

and local elected officials to provide 

general background on the proposal, 

answer questions, and solicit input from 

state/local governments. The UMRA 

discussion in this preamble includes a 

description of the consultation. In the 

spirit of EO 13132, and consistent with 

EPA policy to promote communications 

between the EPA and state and local 

governments, the EPA specifically 

solicits comment on this proposed 

action from state and local officials. 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the EO 13175 (65 FR 67249, 

November 9, 2000) the EPA may not 

issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by tribal governments, or 

the EPA consults with tribal officials 

early in the process of developing the 

proposed regulation and develops a 

tribal summary impact statement. 

The EPA has concluded that this 

proposed action would not have tribal 

implications. It would neither impose 

substantial direct compliance costs on 

tribal governments, nor preempt Tribal 

law. This proposed rule would impose 

requirements on owners and operators 

of new EGUs. The EPA is aware of three 

coal-fired EGUs located in Indian 

Country but is not aware of any EGUs 

owned or operated by tribal entities. 

The EPA notes that this proposal does 

not affect existing sources such as the 

three coal-fired EGUs located in Indian 

Country, but addresses CO2 emissions 

for new EGU sources only. 

Because the EPA is aware of Tribal 

interest in this proposed rule, the EPA 

offered consultation with tribal officials 

early in the process of developing this 

proposed regulation to permit them to 

have meaningful and timely input into 

its development. The EPA’s 

consultation regarded planned actions 

for new and existing sources, but only 

new sources would be affected by this 

proposed action. 

Consultation letters were sent to 584 

tribal leaders. The letters provided 

information regarding the EPA’s 

development of NSPS and emission 

guidelines for EGUs and offered 

consultation. A consultation/outreach 

meeting was held on May 23, 2011, with 

the Forest County Potawatomi 

Community, the Fond du Lac Band of 

Lake Superior Chippewa Reservation, 

and the Leech Lake Band of Ojibwe. 

Other tribes participated in the call for 

information gathering purposes. In this 

meeting, the EPA provided background 

information on the GHG emission 

standards to be developed and a 

summary of issues being explored by 

the Agency. Tribes suggested that the 

EPA consider expanding coverage of the 

GHG standards to include combustion 

turbines, lowering the 250 MMBtu per 

hour heat input threshold so as to 

capture more EGUs, and including 

credit for use of renewables. The tribes 

were also interested in the scope of the 

emissions averaging being considered 

by the Agency (e.g., over what time 

period, across what units). In addition, 

the EPA held a series of listening 

sessions on this proposed action. Tribes 

participated in a session on February 17, 

2011 with the state agencies, as well as 

in a separate session with tribes on 

April 20, 2011. 

The EPA will also hold additional 

meetings with tribal environmental staff 

to inform them of the content of this 

proposal as well as provide additional 

consultation with tribal elected officials 

where it is appropriate. We specifically 

solicit additional comment on this 

proposed rule from tribal officials. 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the Order has the potential to influence 

the regulation. This proposed action is 

not subject to EO 13045 because it is 

based solely on technology 

performance. The proposal is not 

expected to produce notable changes in 

emissions of greenhouse gases or other 

pollutants but does encourage the 

current trend towards cleaner 

generation, helping to protect air quality 

and children’s health. The Agency 

recognizes that children are among the 

groups most vulnerable to climate 

change impacts and the public is invited 

to submit comments or identify peer 

reviewed studies relevant to this 

proposal. 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed action is not a 

‘‘significant energy action’’ as defined in 

EO 13211 (66 FR 28355 (May 22, 2001)) 

because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. This 

proposed action is not anticipated to 

have notable impacts on emissions, 

costs or energy supply decisions for the 

affected electric utility industry. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the NTTAA of 1995 

(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 cites the 

following standards in this proposed 

rule: D5287–08 (Standard Practice for 

Automatic Sampling of Gaseous Fuels), 

D4057–06 (Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products), and D4177–95(2010) 

(Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products). The EPA is proposing use of 

Appendices B, D, F, and G to 40 CFR 

part 75; these Appendices contain 

standards that have already been 

reviewed under the NTTAA. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this action. 


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J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the U.S. 

The EPA has determined that this 

proposed rule would not result in 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations, 

including any minority, low-income 

population or indigenous populations. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: March 27, 2012. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60 of 

the Code of the Federal Regulations is 

proposed to be amended as follows: 

PART 60—[AMENDED] 

1. The authority citation for part 60 

continues to read as follows: 

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

2. Part 60 is amended by adding 

subpart TTTT to read as follows: 

Subpart TTTT Standards of Performance for 

Greenhouse Gas Emissions for Electric 

Utility Generating Units 

Applicability 

Sec. 

60.5508 What is the purpose of this 

subpart? 

60.5509 Am I subject to this subpart? 

60.5510 What is the affected EGU of this 

subpart? 

Emissions Standards 

60.5515 What greenhouse gases are 

regulated by this subpart? 

60.5520 What CO2 emissions standards 

must I meet? 

General Compliance Requirements 

60.5525 What are my general requirements 

for complying with this subpart? 

60.5530 Affirmative Defense for Exceedance 

of Emission Limit During Malfunction 

Monitoring and Compliance Determination 

Procedures 

60.5535 How do I monitor and collect data 

to demonstrate compliance? 

60.5540 How do I demonstrate compliance 

and determine excess emissions with my 

CO2 emissions limit? 

Notifications, Reports, and Records 

60.5550 What notifications must I submit 

and when? 

60.5555 What reports must I submit and 

when? 

60.5560 What records must I keep? 

60.5565 In what form and how long must I 

keep my records? 

Other Requirements and Information 

60.5570 What parts of the General 

Provisions apply to me? 

60.5575 Who implements and enforces this 

subpart? 

60.5580 What definitions apply to this 

subpart? 

Table 1 to Subpart TTTT of Part 60— 

Applicability of Subpart A General 

Provisions to Subpart TTTT 

Applicability 

§ 60.5508 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of greenhouse gas (GHG) 

emissions from electric utility 

generating units that commenced 

construction after April 13, 2012. 

§ 60.5509 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an electric utility 

generating unit that commences 

construction after April 13, 2012 with a 

base load rating of more than 73 

megawatts (MW) (250 million British 

thermal units per hour (MMBtu/h)) heat 

input of fossil fuel except as specified 

under § 60.5510(b). 

§ 60.5510 What is the affected EGU of this 

subpart? 

(a) The affected facility to which this 

subpart applies is each electric utility 

generating unit (EGU) except as 

provided for in paragraph (b) of this 

section. 

(b) An electric utility generating unit 

that meets the conditions specified in 

paragraphs (b)(1) through (b)(3) of this 

section is exempt from this subpart. 

(1) A steam electric generating unit 

that meets the definition of municipal 

waste combustor unit and is subject to 

subpart Eb of this part. 

(2) A steam electric generating unit 

that meets the definition of a 

commercial or industrial solid waste 

incineration unit and is subject to 

subpart CCCC of this part. 

(3) Transitional sources. 

(i) You are not subject to this subpart 

if you own or operate a transitional 

source that commences construction 

within 12 months after April 13, 2012. 

(ii) For purposes of paragraph 

(b)(3)(ii) a ‘‘transitional source’’ is 

defined as an EGU with a base load 

rating of more than 73 megawatts (MW) 

(250 million British thermal units per 

hour (MMBtu/h)) heat input of fossil 

fuel, except as provided for in 

§ 60.5510(b)(1) and (2), and that 

received a complete permit that meets 

the requirements of the Prevention of 

Significant Deterioration Program under 

part C of Title I of the Clean Air Act 

prior to April 13, 2012 (or that had an 

approved PSD permit that has expired 

and is in the process of being extended, 

if the source is participating in a 

Department of Energy CCS funding 

program). 

Emissions Standards 

§ 60.5515 What greenhouse gases are 

regulated by this subpart? 

The greenhouse gas regulated by this 

subpart is carbon dioxide (CO2). 

§ 60.5520 What CO2 emissions standards 

must I meet? 

(a) You must not discharge any gases 

that contain CO2 from any affected EGU 

into the atmosphere in excess of 454 

kilograms (kg) of CO2 per gross output 

in Megawatt-hours (MWh) (454 kg/ 

MWh) (1,000 lb/MWh) on a 12- 

operating month annual average basis, 

except as provided for in paragraphs (b) 

through (d) of this section. 

(b) If the affected EGU utilizes coal or 

petroleum coke for fuel and is designed 

to allow installation and operation of a 

carbon capture and storage (CCS) 

system, you may comply with each 

standard in paragraphs (b)(1) through (3) 

as an alternative to complying with 

paragraph (a) of this section. 

(1) For each year until the 11th year 

of operation, you must not discharge 

any gases that contain CO2 from the 

affected EGU into the atmosphere in 

excess of 816 kg/MWh (1,800 lb/MWh) 

gross output on a 12-operating month 

annual average basis, and 

(2) Beginning with the 11th year of 

operation, the CCS system must be 

operational and you must not discharge 

any gases that contain CO2 from the 

affected EGU into the atmosphere in 

excess of 272 kg/MWh (600 lb/MWh) 

gross output on a 12-operating month 

annual average basis, and 

(3) You must not discharge any gases 

that contain CO2 from the affected EGU 

into the atmosphere in excess of 454 kg/ 

MWh gross output on a 30-year average 

basis. 


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(c) Electric utility generating units 

located in a non-continental area are not 

subject to the requirements of this 

subpart. 

(d) Simple cycle combustion turbines 

are not subject to the requirements of 

this subpart. 

General Compliance Requirements 

§ 60.5525 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emissions limits in this subpart 

applicable to your affected EGU. These 

limits apply at all times. 

(b) At all times you must operate and 

maintain each affected EGU, including 

associated equipment and monitoring 

equipment, in a manner consistent with 

safety and good practices for 

minimizing CO2 emissions. 

Determination of whether such 

operation and maintenance procedures 

are being used will be based on 

information available to the 

Administrator which may include, but 

is not limited to, fuel use records, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, 

review of reports required by this 

subpart, and inspection of the facility. 

(c) For each affected EGU subject to 

the CO2 emissions limits in § 60.5520, 

you must measure or calculate a 12 

month rolling average CO2 emission 

rate, calculated per calendar month, in 

terms of tons/MWh. 

(1) If your EGU is subject to the 

requirements of 40 CFR 75.10(a)(3)(i), 

you must use the CO2 CEMS to measure 

the 12 month rolling average CO2

emissions rate. 

(d) You must conduct an initial 

compliance determination for your 

affected EGU according to the 

requirements in this subpart within 30 

days following the first day of the 13th 

operating month following the date of 

initial operations. Thereafter, you must 

demonstrate continuous compliance 

according to the requirements in this 

subpart each calendar month 

determined to be an operating month. 

§ 60.5530 Affirmative Defense for 

Exceedance of Emission Limit During 

Malfunction. 

In response to an action to enforce the 

standards you may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined at 40 

CFR 60.2. Appropriate penalties may be 

assessed, however, if the respondent 

fails to meet its burden of proving all of 

the requirements in the affirmative 

defense. The affirmative defense shall 

not be available for claims for injunctive 

relief. 

(a) To establish the affirmative 

defense in any action to enforce such a 

limit, the owners or operators of 

facilities must timely meet the 

notification requirements in paragraph 

(b) of this section, and must prove by a 

preponderance of evidence that: 

(1) The excess emissions: 

(i) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner; 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(iii) Did not result from any activity 

or event that could have been foreseen 

and avoided, or planned for; and 

(iv) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; 

(2) Repairs were made as 

expeditiously as practicable when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; 

(3) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; 

(4) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; 

(5) All practicable steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health; 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all practicable, consistent with 

safety and good air pollution control 

practices; 

(7) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; 

(8) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(b) The owner or operator of an 

affected EGU experiencing an 

exceedance of its emission limit(s) 

during a malfunction shall notify the 

Administrator by telephone or facsimile 

(FAX) transmission as soon as 

practicable, but no later than two (2) 

business days after the initial 

occurrence of the malfunction, if it 

wishes to avail itself of an affirmative 

defense to civil penalties for that 

malfunction. The owner or operator 

seeking to assert an affirmative defense 

shall also submit a written report to the 

Administrator within 45 days of the 

initial occurrence of the exceedance of 

the standard to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45-day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedances. 

Monitoring and Compliance 

Determination Procedures 

§ 60.5535 How do I monitor and collect 

data to demonstrate compliance? 

(a) You must prepare a site-specific 

monitoring plan that addresses the 

monitoring system design, data 

collection and the quality assurance and 

quality control elements consistent with 

the applicable requirements in § 60.13, 

40 CFR part 75, and this section. 

(b) Follow the applicable quality 

assurance procedures for CO2 emissions 

in appendices B, D, and G to 40 CFR 

part 75. 

(c) If you determine the your affected 

EGU’s CO2 mass emissions rate by 

monitoring fuel combusted in the 

affected EGU and periodic fuel sampling 

as allowed under § 60.5525(c)(2), you 

must use the procedures specified in 40 

CFR part 75, appendix G. 

(1) Determine a site-specific F factor 

using the ultimate analysis and GCV in 

equation F–7a of 40 CFR part 75, 

Appendix F; and 

(2) Monitor and determine the 

affected EGU’s daily fuel consumption 

for each type of fuel combusted in the 

affected EGU. 

(3) Use ASTM D5287–08 (Standard 

Practice for Automatic Sampling of 

Gaseous Fuels) to collect a 

representative gaseous fuel sample. 


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(4) Use one of the following methods 

to collect a representative liquid oil fuel 

sample: 

(i) ASTM D4057–06 (Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products) or 

(ii) ASTM D4177–95 (2010) (Standard 

Practice for Automatic Sampling of 

Petroleum and Petroleum Products). 

(d) You must monitor and record the 

applicable data needed to determine 

your affected EGU’s gross output for 

each operating month. 

(e) Follow the applicable missing data 

substitution procedures in 40 CFR part 

75 for CO2 concentration, stack gas flow 

rate, fuel flow rate, high heating value, 

and fuel carbon content. 

§ 60.5540 How do I demonstrate 

compliance and determine excess 

emissions with my CO2 emissions limit? 

(a) If you use a CO2 CEMS to 

demonstrate compliance you must use 

the procedure specified in paragraphs 

(a)(1) through (5) of this section to 

determine the 12-operating month 

rolling average CO2 emissions rate for 

your affected EGU. 

(1) Calculate hourly CO2 mass 

emissions for each hour of the operating 

month in terms of kilograms CO2 using 

CFR 40 part 75 appendix G. 

(2) Determine hourly gross output in 

terms of MWh for each hour of the 

operating month. 

(3) Sum the hourly CO2 mass 

emissions for the operating month, and 

sum the hourly gross output for the 

operating month. 

(4) Divide the total CO2 mass 

emissions calculated for the month by 

the total hourly gross output calculated 

for the operating month. 

(5) Add the quotient to the sum of the 

quotients of the previous 11 operating 

months and divide by 12 to determine 

the 12-operating month rolling average. 

(6) If the 12-operating month rolling 

average value does not exceed the 

applicable emissions limit in § 60.5520, 

your affected EGU is determined to be 

in compliance with the emissions limit. 

Otherwise, your affected EGU is 

determined to have excess emissions. 

(b) If you use fuel sampling to 

demonstrate compliance, you must use 

the procedure specified in paragraphs 

(b)(1) through (5) of this section to 

determine the 12-operating month 

rolling average CO2 emissions rate for 

your affected EGU. 

(1) Calculate monthly CO2 mass 

emissions by multiplying the monthly F 

factor by the monthly fuel consumption. 

(2) Sum the hourly gross output in 

terms of MWh for the month. 

(3) Divide the monthly CO2 mass 

emissions by the sum of the hourly 

gross output for the month. 

(4) Add the quotient to the sum of the 

quotients of the previous 11 operating 

months to determine the 12-operating 

month rolling average. 

(5) If the 12-operating month rolling 

average value does not exceed the 

applicable emissions limit in § 60.5520, 

your affected EGU is determined to be 

in compliance with the emissions limit. 

Otherwise, your affected EGU is 

determined to have excess emissions. 

(c) If you elect to comply with 

§ 60.5520(b), the 30-year average CO2

emissions rate for your affected EGU is 

the sum of the monthly CO2 emissions 

for each operating month for the 30-year 

period divided by the sum of the 

monthly gross output in terms of MWh 

for the 30-year period. Use the 

procedure specified in paragraphs (c)(1) 

through (4) of this section to determine 

the 12-month annual average CO2

emissions rate for your affected EGU. 

(1) If you do not use a CO2 CERMS to 

demonstrate compliance with 

§ 60.5520(b), you must calculate hourly 

CO2 mass emissions for each hour of the 

12-month annual period in terms of 

kilograms CO2 using CFR 40 Part 75 

Appendix G. If you use a CO2 CERMS 

to demonstrate compliance with 

§ 60.5520(b) you must calculate hourly 

CO2 mass emissions for each hour of the 

12-month annual period in terms of 

kilograms CO2 using the CERMS hourly 

mass emissions measurements. 

(2) Determine hourly gross output in 

terms of MWh for each hour of the 12- 

month annual period. 

(3) Sum the hourly CO2 mass 

emissions for the 12-month annual 

operating period, and sum the hourly 

gross output for the 12-month annual 

operating period. 

(4) Divide the total CO2 mass 

emissions calculated for the 12-month 

annual operating period by the total 

hourly gross output calculated for the 

12-month annual operating period. 

(5) If the 12-month annual average 

value does not exceed the applicable 

emissions limit in § 60.5520, your 

affected EGU is determined to be in 

compliance with the emissions limit. 

Otherwise, your affected EGU is 

determined to have excess emissions. 

Notification, Reports, and Records 

§ 60.5550 What notifications must I submit 

and when? 

(a) You must prepare and submit 

notifications specified in § 60.7(a) and 

§ 60.19, as applicable to your affected 

EGU. 

(b) You must prepare and submit 

notifications specified in 40 CFR part 

75.61, as applicable to your affected 

EGU. 

§ 60.5555 What reports must I submit and 

when? 

(a) You must prepare and submit 

reports specified in § 60.7(c) through (e) 

and § 60.19, as applicable to your 

affected EGU. All reports required under 

§ 60.7 must be submitted by the 30th 

day following the end of each 6-month 

period. 

(1) The excess emissions and 

continuous monitoring systems 

performance reports and-or summary 

report forms required in § 60.7(c) must 

be submitted to the EPA’s WebFIRE 

database by using the Compliance and 

Emissions Data Reporting Interface 

(CEDRI) that is accessed through the 

EPA’s Central Data Exchange 

(CDX)(www.epa.gov/cdx). In CEDRI, the 

owner or operator shall use the 

appropriate electronic reporting form for 

this subpart or provide an alternate 

electronic file consistent with EPA’s 

form output format. 

(b) You must follow the applicable 

reporting requirements and submit 

reports as required in subpart G of 40 

CFR part 75. You must report CO2 mass 

emissions data, and other related data 

electronically using the Emissions 

Collection and Monitoring Plan System 

(ECMPS). 

§ 60.5560 What records must I maintain? 

(a) You must maintain records of your 

information used to demonstrate 

compliance with this subpart as 

specified in § 60.7 (b) and (f). 

(1) Notwithstanding the requirements 

of this section you do not need to 

maintain records of the reports that have 

been submitted to the EPA’s WebFIRE 

database as required in § 60.5555(a)(1). 

(b) You must follow the applicable 

recordkeeping requirements and 

maintain records as required in subpart 

F of 40 CFR part 75. 

(c) If you determine the CO2 mass 

emissions rate by monitoring fuel 

combusted in an affected EGU and 

periodic fuel sampling according to the 

requirements in this rule then you must 

maintain records of fuel type and 

quantity combusted in the affected EGU 

for each operating month the 

information specified in paragraphs (c) 

(1) and (2) of this section. 

(1) Records of fuel type and quantity 

combusted in the affected EGU for each 

operating month. 

(2) Records of the calculations 

performed to determine the site-specific 

F factor and monthly total CO2 mass 

emissions rates. 

(d) Records of the applicable data 

recorded and calculations performed 

used to determine your affected EGU’s 

gross output for each operating month. 


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§ 60.5565 In what form and how long must 

I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review. 

(b) You must keep each record for 5 

years following the date of each 

occurrence, measurement, maintenance, 

corrective action, report, or record 

except those records required to 

demonstrate compliance with the 

emissions limits in § 60.5520(b). 

Records required to demonstrate 

compliance with the emissions limits in 

§ 60.5520(b) must be kept for at least 40 

years following the date of initial 

startup of the affected EGU. 

(c) You must keep each record on site 

for at least 2 years after the date of each 

occurrence, measurement, maintenance, 

corrective action, report, or record, 

according to § 60.10. You can keep the 

records off site for the remaining years 

as required by this subpart. 

Other Requirements and Information 

§ 60.5570 What parts of the General 

Provisions apply to me? 

Table 1 to this subpart shows which 

parts of the General Provisions in 

§§ 60.1 through 60.19 apply to you. 

§ 60.5575 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by 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 

authorities listed in paragraphs (b)(1) 

through (5) of this section are retained 

by the Administrator and are not 

transferred to the state, local, or tribal 

agency; however, the EPA retains 

oversight of this subpart and can take 

enforcement actions, as appropriate. 

(1) Approval of alternatives to the 

emission standards. 

(2) Approval of major alternatives to 

test methods. 

(3) Approval of major alternatives to 

monitoring. 

(4) Approval of major alternatives to 

recordkeeping and reporting. 

(5) Performance test and data 

reduction waivers under § 60.8(b). 

§ 60.5580 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein will have the meaning 

given them in the Clean Air Act and in 

subpart A (General Provisions of this 

part). 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Base load rating means the maximum 

amount of heat input (fuel) that a steam 

generating unit can combust on a steady 

state basis, as determined by the 

physical design and characteristics of 

the steam generating unit at ISO 

conditions. For a stationary combustion 

turbine base load means 100 percent of 

the design heat input capacity of the 

stationary combustion turbine engine at 

ISO conditions. 

Carbon capture and storage (CCS) 

means a process that includes capture 

and compression of CO2 produced by an 

electric utility generating unit before 

release to the atmosphere; transport of 

the captured CO2 (usually in pipelines); 

and storage of that CO2 in geologic 

formations, such as deep saline 

formations, oil and gas reservoirs, and 

unmineable coal seams. 

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 means a stationary 

turbine combustion system where heat 

from the turbine exhaust gases is 

recovered by a heat recovery steam 

generating unit. 

Combined heat and power, also 

known as ‘‘cogeneration,’’ means a 

steam-generating unit that 

simultaneously produces both electric 

(and mechanical) and useful thermal 

energy from the same primary energy 

source. 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17), diesel fuel oil 

numbers 1 and 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17), kerosene, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

Electric utility generating unit or EGU 

means any steam electric generating 

unit or stationary combustion turbine 

that is constructed for the purpose of 

supplying more than one-third of its 

potential electric output capacity and 

more than 25 MW net-electrical output 

to any utility power distribution system 

for sale. Also, any steam supplied to a 

steam distribution system for the 

purpose of providing steam to a steamelectric generator that would produce 

electrical energy for sale is considered 

in determining the electrical energy 

output capacity of the affected EGU. 

Excess emissions means a specified 

averaging period over which the CO2

emissions rate are higher than the 

applicable emissions standard. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable State implementation 

plan, and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 51.24. 

Fossil fuel means natural gas, 

petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Gaseous fuel means any fuel that is 

present as a gas at standard conditions 

and includes, but is not limited to, 

natural gas, refinery fuel gas, process 

gas, coke-oven gas, synthetic gas, and 

gasified coal. 

Gross output means the gross 

electrical or mechanical output from the 

unit plus 75 percent of the useful 

thermal output measured relative to ISO 

conditions that is not used to generate 

additional electrical or mechanical 

output or to enhance the performance of 


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the unit (i.e., steam delivered to an 

industrial process). 

Integrated gasification combined 

cycle electric utility generating unit 

means an electric utility combined cycle 

gas turbine that is designed to burn fuels 

containing 50 percent (by heat input) or 

more solid-derived fuel not meeting the 

definition of natural gas. The 

Administrator may waive the 50 percent 

solid-derived fuel requirement during 

periods of the gasification system 

construction or repair. No solid fuel is 

directly burned in the unit during 

operation. 

ISO conditions means 288 Kelvin (15° 

C), 60 percent relative humidity and 

101.3 kilopascals pressure. 

Natural gas means a fluid mixture of 

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

propane), composed of at least 70 

percent methane by volume or that has 

a gross calorific value between 35 and 

41 megajoules (MJ) per dry standard 

cubic meter (950 and 1,100 Btu per dry 

standard cubic foot), that maintains a 

gaseous state under ISO conditions. In 

addition, natural gas contains 20.0 

grains or less of total sulfur per 100 

standard cubic feet. Finally, natural gas 

does not include the following gaseous 

fuels: landfill gas, digester gas, refinery 

gas, sour gas, blast furnace gas, 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 the gross 

electric sales to the utility power 

distribution system minus purchased 

power on a calendar year basis. 

Non-continental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Operating month means a calendar 

month during which any fuel is 

combusted in the electric utility 

generating unit at any time. 

Out-of-control period means any 

period beginning with the quadrant 

corresponding to the completion of a 

daily calibration error, linearity check, 

or quality assurance audit that indicates 

that the instrument is not measuring 

and recording within the applicable 

performance specifications and ending 

with the quadrant corresponding to the 

completion of an additional calibration 

error, linearity check, or quality 

assurance audit following corrective 

action that demonstrates that the 

instrument is measuring and recording 

within the applicable performance 

specifications. 

Potential electric output means 33 

percent of the maximum design heat 

input capacity of the steam generating 

unit, divided by 3,413 Btu/KWh, 

divided by 1,000 kWh/MWh, and 

multiplied by 8,760 h/yr (e.g., a steam 

generating unit with a 100 MW (340 

MMBtu/h) fossil-fuel heat input 

capacity would have a 289,080 MWh 12 

month potential electrical output 

capacity). 

Simple cycle combustion turbine 

means a stationary combustion turbine 

that which does not recover heat from 

the combustion turbine exhaust gases 

for purposes other than enhancing the 

performance of the combustion turbine 

itself. 

Solid fuel means any fuel that has a 

definite shape and volume, has no 

tendency to flow or disperse under 

moderate stress, and is not liquid or 

gaseous at ISO conditions. This 

includes, but is not limited to, coal, 

biomass, and pulverized solid fuels. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine, the fuel, air, lubrication 

and exhaust gas systems, control 

systems (except emissions control 

equipment), heat recovery system, fuel 

compressor, heater, and/or pump, postcombustion emission control 

technology, and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any combined 

cycle combustion turbine, and any 

combined heat and power combustion 

turbine based system. Stationary means 

that the combustion turbine is not self 

propelled or intended to be propelled 

while performing its function. It may, 

however, be mounted on a vehicle for 

portability. 

Steam electric generating unit means 

any furnace, boiler, or other device used 

for combusting fuel for the purpose of 

producing steam (including fossil fuelfired steam generators associated with 

combined cycle gas turbines; nuclear 

steam generators are not included) plus 

any integrated device that provides 

electricity or useful thermal output to 

either the boiler or to power auxiliary 

equipment. 

Useful thermal output means the 

thermal energy made available for use in 

any industrial or commercial process, or 

used in any heating or cooling 

application, i.e., total thermal energy 

made available for processes and 

applications other than electrical 

generation or to enhance the 

performance of the stationary 

combustion turbine. Thermal output for 

this subpart means the energy in 

recovered thermal output measured 

against the energy in the thermal output 

at ISO conditions. 

TABLE 1 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A GENERAL PROVISIONS TO SUBPART TTTT 

General provisions citation Subject of citation Applies to 

subpart TTTT Explanation 

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

§ 60.2 ....................................................... Definitions .............................................. Yes ................... Additional terms defined in § 60.5580. 

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

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

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

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

§ 60.7 ....................................................... Notification and Recordkeeping ............. Yes ................... Except for the requirements to submit 

written excess emissions reports 

under § 60.7(c). 

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

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

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

§ 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. 


pmangrum on DSK3VPTVN1PROD with PROPOSALS2
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TABLE 1 TO SUBPART TTTT OF PART 60—APPLICABILITY OF SUBPART A GENERAL PROVISIONS TO SUBPART TTTT— 

Continued 

General provisions citation Subject of citation Applies to 

subpart TTTT Explanation 

§ 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. 

[FR Doc. 2012–7820 Filed 4–12–12; 8:45 am] 

BILLING CODE 6560–50–P 


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