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

Sent: Friday, May 23, 2014 3:57 PM 

To: Higgins, Cortney 

Cc: Wayland, Robertj 

Subject: Mods/Recon preamble 

Importance: High 

Per Bob’s earlier e-mail, here is the mods preamble language. Per our brief discussion, we plan to 

send some additional language Tuesday addressing some things we have heard about the new 

source proposal that are relevant here. 

<< EO12866_GHG EGU ModifiedSources 2060-AR88 Proposal__20140523 to OMB.docx >> 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

6560-50-P 

EO12866_GHG EGU ModifiedSources 2060-AR88 Proposal_20140418 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[EPA-HQ-OAR-2013-0603; FRL 9910-00-OAR ] 

RIN 2060-AR88 

Carbon Pollution Standards for Modified and Reconstructed Power 

Plants: Standards of Performance for Greenhouse Gas Emissions 

from Modified and Reconstructed Stationary Sources: Electric 

Utility Generating Units

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: In this action, tThe Environmental Protection Agency 

(EPA) is proposing standards of performance for emissions of 

greenhouse gases from affected modified and reconstructed fossil 

fuel-fired electric utility steam generating units and natural 

gas-fired stationary combustion turbines. that supply more than 

one-third of their potential electric output to the grid. 

Natural gas-fired combustion turbines that operate as Peaking 

peaking units, - those that which operate at supply one-third 

or less of their maximum capacitypotential to the grid, are not 

covered by today’s proposal. With respect toFor affected 

modified fossil fuel-fired electric utility steam generating 

units (utility boilers and integrated gasification combined 

cycle units), the EPA is co-proposing two alternatives related 

Comment [A1]: General Comment: Reviewers 

would appreciate further explanations of potential 

interactions between this rule and the 111(d) rules, 

particularly with regards to quantification of 

emissions and generation for the purposes of state 

compliance. 

EPA Response: EPA would like additional 

feedback on where what type of further 

explanation would be helpful. The EPA feels that 

there is sufficient explanation of interaction 

between the two programs.

Comment [A2]: General Question: At what point 

would the replacement of an existing EGU be 

considered “new” for 111(b) purposes? Would the 

full replacement of the EGU at the same site be 

considered a “reconstructed” or a “new” 

unit? Would the EGU have to be in a different 

geographic position (an entirely new site) to be 

considered “new” rather than “reconstructed”? EPA 

may want to make this distinction more clear when 

defining “reconstruction” in the preamble. 

EPA Response: New language explaining the 

distinction between a reconstructed source and a 

newly constructed source has been added along 

with a solicitation of comment on additional 

distinction.
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to standards of performance. for Under the first alternative, 

all modified units would be subject to a single standard of 

performance. In the second co-proposed alternative, the EPA is 

proposing that the specific form of the standard will depend on 

whether the source makes the modification before or after 

becoming subject to a CAA section 111(d) plan. This alternative 

recognizes that actions taken to comply with a Clean Air Act 

(CAA) section 111(d) plan may result in improved performance at 

the source. In all cases the level of the proposed standards is 

based on a combination of best operating practices and equipment 

upgrades. 

For affected modified natural gas-fired stationary 

combustion turbines, the agency is proposing standards of 

performance set at a level based on efficient Natural Gas 

Combined Cycle (NGCC) technology. These standards would be 

applicable whether or not a unit is subject to a section 111(d) 

plan. 

For affected reconstructed fossil fuel-fired electric 

utility steam generating units (utility boilers and integrated 

gasification combined cycle units), and for affected 

reconstructed natural gas-fired stationary combustion turbines, 

the EPA is proposing standards of performance based on the most 

efficient generating technology that is applicable to each 

Comment [A3]: Something missing here. 

EPA Response: Fixed
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category of units. This standard would not be affected by the 

submittal of a CAA section 111(d) plan. 

DATES: Comments on the proposed standards. Comments on the 

proposed standards must be received on or before [INSERT DATE 60 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

Comments on the information collection request. Under the 

Paperwork Reduction Act (PRA), since the Office of Management 

and Budget (OMB) is required to make a decision concerning the 

information collection request between 30 and 60 days after 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment 

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

receives it by [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. 

Public Hearing. In a separate action in the Federal 

Register, the EPA is proposing Clean Air Act (CAA) section 

111(d) emission guidelines for existing fossil fuel-fired 

electric utility generating units (EGUs) and is announcing 

public hearings associated with that action. Because of the 

interconnected nature of this proposed rulemaking with the 

proposed Emission Guidelines for Existing Sources, we will hold 

joint hearings on both proposed rulemakings. Please consult the 

Federal Register notice proposing Emission Guidelines for 

Existing Sources for information on public hearings for both 

actionsthe proposed emission guidelines and for this action. 

Comment [A4]: ... proposing Emission 

Guidelines for Existing Sources? 

EPA Response: Fixed
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Additionally, information for the joint public hearings will be 

posted on the following website: http://www2.epa.gov/carbonpollution-standards/. If any dates, times or locations of 

announced public hearings are changed for the proposed emission 

guidelines, then the public hearing dates, times and locations 

for this action will also change accordingly. If you would like 

to speak at the public hearing(s), please register by following 

instructions provided in the notice for the emission guidelines 

proposed in the Federal Register. Please note that written 

statements and supporting information submitted during the 

comment period will be considered with the same weight as oral 

comments and supporting information presented at the public 

hearing. 

ADDRESSES: Comments. Submit your comments, identified by Docket 

ID No. EPA-HQ-OAR-2013-0603, by one of the following methods: 

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

instructions for submitting comments. 

At the website http://www.epa.gov/oar/docket.html: Follow 

the instructions for submitting comments on the EPA Air and 

Radiation Docket website.

Email: Send your comments by electronic mail (email) to aand-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0603. 

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

ID No. EPA-HQ-OAR-2013-0603. 
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Mail: Send your comments to the EPA Docket Center, U.S. 

EPA, Mail Code 28221T, 1200 Pennsylvania Ave., NW, Washington, 

DC 20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0603. In addition, 

please mail a copy of your cComments on the information 

collection provisions should be mailed to the Office of 

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

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

Hand Delivery or Courier: Deliver your comments to the EPA 

Docket Center, William Jefferson Clinton Building West, Room 

3334, 1301 Constitution Ave., NW, Washington, DC 20004, Attn: 

Docket ID No. EPA-HQ-OAR-2013-0603. Such deliveries are accepted 

only during the Docket Center’s normal hours of operation (8:30 

a.m. to 4:30 p.m., Monday through Friday, excluding Ffederal 

holidays), and special arrangements should be made for 

deliveries of boxed information. 

 Instructions: All submissions must include the agency name 

and docket ID number (EPA-HQ-OAR-2013-0603). The EPA’s policy is 

to include all comments received without change, including any 

personal information provided, in the public docket, available 

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

includes information claimed to be confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 
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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-HQ-OAR2013-0603. Clearly mark the part or all of the information that 

you claim to be CBI. For CBI information on a disk or CD-ROM 

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

as CBI and then identify electronically within the disk or CDROM the specific information you claim as CBI. In addition to 

one complete version of the comment that includes information 

claimed as CBI, you must submit a copy of the comment that does 

not contain the information claimed as CBI for inclusion in the 

public docket. Information so marked will not be disclosed 

except in accordance with procedures set forth in 40 CFR part 2. 

 The EPA requests that you also submit a separate copy of 

your comments to the contact person identified below (see FOR 

FURTHER INFORMATION CONTACT). If the comment includes 

information you consider to be CBI or otherwise protected, you 

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

information claimed as CBI or otherwise protected. 

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

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

contact information unless you provide it in the body of your 
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Page 7 of 181

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

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

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

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

the EPA recommends that you include your name and other contact 

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

technical difficulties and cannot contact you for clarification, 

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

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

encryption and be free of any defects or viruses. 

 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 at 

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

Center, William Jefferson Clinton Building West, Room 3334, 1301 

Constitution Ave., NW, Washington, DC. The Public Reading Room 

is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 

excluding federal holidays. The telephone number for the Public 
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Reading Room is (202)566-1744, and the telephone number for the 

Air Docket is (202)566-1742. Visit the EPA Docket Center 

homepage at http://www.epa.gov/epahome/dockets.htm for 

additional information about the EPA’s public docket. 

 In addition to being available in the docket, an electronic 

copy of this proposed rule will be available on the World Wide 

Web (WWW) through the technology transfer network (TTN). 

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

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

promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. 

FOR FURTHER INFORMATION CONTACT: 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 
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defined as follows: 

AEO Annual Energy Outlook 

APPA American Public Power Association 

BSER Best System of Emission Reduction 

CAA Clean Air Act 

CAP Climate Action Plan 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CFB Circulating Fluidized Bed 

CH4 Methane 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DCE Direct Contact Evaporator 

DOE Department of Energy 

EGU Electric Utility Generating Unit 

EO Executive Order 

EPA Environmental Protection Agency 

FB Fluidized Bed 

FR Federal Register 

GHG Greenhouse Gas 

HFC Hydrofluorocarbon 

HRSG Heat Recovery Steam Generator 

ICR Information Collection Request 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

lb CO2/MWh-net Pounds of CO2 per megawatt-hour on a net output 

basis 

LCOE Levelized Cost of Electricity 

MMBtu/h Million British Thermal Units per Hour 

MPa Megapascal 

MW Megawatt 

MWe Megawatt Electrical 

MWh Megawatt-hour 

N2 Nitrogen Gas 

N2O Nitrous Oxide 

NOx Nitrogen Oxide 

NAICS North American Industry Classification System 

NDCE Non-Direct Contact Evaporator 

NETL National Energy Technology Laboratory 

NGCC Natural Gas Combined Cycle 

NGR Natural Gas Reburning 

NRC National Research Council 

NRECA National Rural Electric Cooperative Association 

NSPS New Source Performance Standards 

NTTAA National Technology Transfer and Advancement Act 
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OFR Overfire Air 

OMB Office of Management and Budget 

PC Pulverized Coal 

PFC Perfluorocarbons 

PRA Paperwork Reduction Act 

psi Pounds per square inch 

RFA Regulatory Flexibility Act 

RIA Regulatory Impact Analysis 

SBA Small Business Administration 

SCPC Supercritical pulverized coal 

SF6 Sulfur Hexafluoride 

Tg Teragram (one trillion (1012) grams) 

TRS Total Reduced Sulfur 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

U.S. United States 

USGCRP U.S. Global Change 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. Overview 

C. Does this action apply to me? 

II. Background 

A. Climate Change Impacts from GHG Emissions 

B. GHG Emissions from Fossil Fuel-fired EGUs 

C. The Utility Power Sector 

D. Statutory Background 

E. Regulatory Background 

F. Stakeholder Outreach 

G. Modifications and Reconstructions 

III. Proposed Requirements for Modified and Reconstructed 

Sources 

A. Applicability Requirements 

B. Emission Standards 

C. Startup, Shutdown and Malfunction Requirements 

D. Continuous Monitoring Requirements 

E. Emissions Performance Testing Requirements 

F. Continuous Compliance Requirements 

G. Notification, Recordkeeping and Reporting Requirements 
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IV. Rationale for Reliance on Rational Basis to Regulate GHG 

from Fossil Fuel-fired EGUs 

A. Rational Basis and Endangerment Finding 

B. Source Categories 

V. Rationale for Applicability Requirements 

VI. Rationale for Emission Standards for Reconstructed Fossil 

Fuel-Fired Utility Boilers and IGCC Units 

A. Overview 

B. Identification of Best System of Emissions Reduction 

C. Determination of the Level of the Standard 

D. Compliance Period 

VII. Rationale for Emission Standards for Modified Fossil Fuelfired Utility Boilers and IGCC Units 

A. Introduction 

B. Identification of the Best System of Emission Reduction 

C. Determination of the Level of the Standard 

D. Compliance Period 

VIII. Rationale for Emission Standards for Reconstructed Natural 

Gas-fired Stationary Combustion Turbines 

A. Identification of the Best System of Emission Reduction 

B. Determination of the Standards of Performance 

IX. Rationale for Emission Standards for Modified Natural Gasfired Stationary Combustion Turbines 

A. Identification of the Best System of Emission Reduction 

B. Determination of the Level of the Standards of Performance

X. Impacts of the Proposed Action 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. How will this proposal contribute to climate change 

protection? 

E. What are the economic and employment impacts? 

F. What are the benefits of the proposed standards? 

XI. Statutory and Executive Order Reviews 

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

Executive Order 13563, Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132, Federalism 

F. Executive Order 13175, Consultation and Coordination With 

Indian Tribal Governments 

G. Executive Order 13045, Protection of Children From 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 
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I. National Technology Transfer and Advancement Act 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

XII. Statutory Authority 

I. General Information 

A. Executive Summary

1. Purpose of the Regulatory Action 

On June 25, 2013, in conjunction with announcement of his 

Climate Action Plan (CAP), President Obama issued a Presidential 

Memorandum directing the EPA to issue a new proposal to address 

carbon pollution from new power plants by September 30, 2013 and 

to issue “standards, regulations, or guidelines, as appropriate, 

which address carbon pollution from modified, reconstructed and 

existing power plants.” Consistent with the Presidential 

Memorandum, on September 20, 2013, the Administrator signed 

proposed carbon pollution standards for newly constructed fossil 

fuel-fired power plants (79 FR 1430, January 8, 2014) (January 

2014 proposal). Specifically, under the authority of Clean Air 

Act (CAA) section 111(b), the EPA proposed new source 

performance standards (NSPS) to limit emissions of carbon 

dioxide (CO2) from newly constructed fossil fuel-fired electric 

utility steam generating units (utility boilers and integrated 

gasification combined cycle (IGCC) units) and newly constructed

natural gas-fired stationary combustion turbines. 
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In this action, under the authority of CAA section 111(b), 

the EPA is proposing standards of performance to limit emissions 

of CO2 from modified and reconstructed fossil fuel-fired electric 

utility steam generating units and natural gas-fired stationary 

combustion turbines, as well as from reconstructed fossil fuelfired electric utility steam generating units and natural gasfired stationary combustion turbines. Specifically, the EPA is 

proposing standards of performance for: (1) modified fossil 

fuel-fired utility boilers and IGCC units, (2) modified natural 

gas-fired stationary combustion turbines, (3) reconstructed 

fossil fuel-fired utility boilers and IGCC units, and (4) 

reconstructed natural gas-fired stationary combustion turbines. 

Consistent with the requirements of CAA section 111(b), these 

proposed standards reflect the degree of emission limitation 

achievable through the application of the best system of 

emission reduction (BSER) that the EPA has determined has been 

adequately demonstrated for each type of unit. 

In a separate action, under CAA section 111(d), the EPA is 

proposing emission guidelines for states to use in developing 

plans to limit CO2 emissions from existing fossil fuel-fired 

EGUs. States must then submit plans to the EPA under timing set 

by that action. 

2. Summary of the Major Provisions 

The proposed standards for the affected modified and 
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reconstructed sources are summarized below in Table 1. 

Table 1. Summary of BSER and Proposed Standards for Affected 

Sources

Affected 

Source 

BSER Standard

Modified 

Utility 

Boilers and 

IGCC Units 

Most 

efficient 

generation 

at the 

affected 

source

achievable 

through a 

combination 

of best 

operating 

practices 

and 

equipment 

upgrades 

Co-proposed Alternative #1

1. Source would be required to meet 

a unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission 

rate (from 2002 to the date of 

the modification) plus an 

additional two percent emission 

reduction; the emission limit 

will be no lower than:

a. 1,900 lb CO2/MWh-net for 

sources with heat input > 

2,000 MMBtu/h.

OR 

b. 2,100 lb CO2/MWh-net for 

sources with heat input ≤

2,000 MMBtu/h.

Modified 

Utility 

Boilers and 

IGCC Units 

Most 

efficient 

generation 

at the 

affected 

source

achievable 

through a 

combination 

of best 

operating 

practices 

and 

equipment 

upgrades

Co-proposed Alternative #2 

Source would be required to meet a 

unit-specific emission limit 

dependent upon when the 

modification occurs. 

1. Sources that modify prior to

becoming subject to a CAA 111(d) 

plan would be required to meet a 

unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission 

rate (from 2002 to date of the 

modification) plus an additional 

two percent emission reduction; 

the emission limit will be no 

lower than:

a. 1,900 lb CO2/MWh-net for 

sources with heat input > 

2,000 MMBtu/h.

OR 

b. 2,100 lb CO2/MWh-net for 

sources with heat input ≤
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2,000 MMBtu/h. 

2. Sources that modify after

becoming subject to a CAA 111(d) 

plan would be required to meet a 

unit-specific emission limit 

determined by the 111(b) 

permitting implementing 

authority from the results of an 

energy efficiency improvement 

audit. 

Modified 

Natural GasFired 

Stationary 

Combustion 

Turbines 

Efficient 

NGCC 

technology 

1. Sources with heat input > 850 

MMBtu/h would be required to meet 

an emission limit of 1,000 lb 

CO2/MWh-gross. 

2. Sources with heat input ≤ 850 

MMBtu/h would be required to meet 

an emission limit of 1,100 lb 

CO2/MWh-gross. 

Reconstructed 

Utility 

Boilers and 

IGCC Units 

Most 

efficient 

generating 

technology 

at the 

affected 

source 

1. Sources with heat input > 2,000 

MMBtu/h would be required to 

meet an emission limit of 1,900 

lb CO2/MWh-net. 

2. Sources with heat input ≤ 2,000 

MMBtu/h would be required to 

meet an emission limit of 2,100 

lb CO2/MWh-net. 

Reconstructed 

Natural GasFired 

Stationary 

Combustion 

Turbines 

 Efficient 

NGCC 

technology 

1. Sources with heat input > 850 

MMBtu/h would be required to 

meet an emission limit of 1,000 

lb CO2/MWh-gross. 

2. Sources with heat input ≤ 850 

MMBtu/h would be required to 

meet an emission limit of 1,100 

lb CO2/MWh-gross. 

Note: For the reasons discussed in the “Legal Memorandum1” 

 

1

 The “Legal Memorandum” supporting document is available in the 

rulemaking docket for the proposed emission guidelines for 

existing source power plants, “Carbon Pollution Guidelines for 

Existing Power Plants: Emission Guidelines for Greenhouse Gas 

Comment [A5]: If this is a footnote to the table, 

please format appropriately. 

EPA: The text was converted to body text rather 

than a note or footnote. 
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supporting document in the docket for the rulemaking for CO2

emissions from existing EGUs under section 111(d).2

, all existing 

sources that become modified or reconstructed sources and which 

are subject to a CAA section 111(d) plan at the time of the 

modification or reconstruction, will remain in the CAA section 

111(d) plan and remain subject to any applicable regulatory 

requirements in the plan, in addition to being subject to 

regulatory requirements under CAA section 111(b). 

It should be noted that the EPA intends each standard of 

performance proposed in this rulemaking to be severable from 

each other standard of performance, such that if one or more of 

the standards of performance were to be remanded or vacated in a 

court challenge, the EPA intends for the other standards to 

remain in effect. The EPA also intends each BSER determination 

or alternative determination, as applicable, for modified 

utility boilers and IGCC units, and for modified natural gasfired stationary combustion turbines, to be severable from each 

other BSER determination. In all of these cases, the EPA 

believes that the standards of performance and associated best 

systems of emission reduction operate independently of each 

 

Emissions from Existing Stationary Sources: Electric Utility 

Generating Units, Docket ID: EPA-HQ-OAR-2013-0602.”

Comment [A6]: For clarity, EPA may want to 

explain here if “subject to a CAA section 111(d) 

plan” refers to inclusion in a submitted 111d plan or 

an approved 111d plan. (Based on an explanation 

later in the preamble, EPA seems to be referring to a 

submitted plan.) 

EPA Response: We solicit comment later in the 

document on if this should be when the state plan 

is submitted. 

Comment [A7]: General comment for this 

paragraph: This may not be the best place for it, 

given that the interaction between 111(b) and 111(d) 

hasn’t yet been introduced. 

EPA Response: We believe that the language is 

acceptable in the current location. 

EPA’s use of the word “severable” in meant to 

identify standards or parts of the rule that EPA 

intends to operate even in the absence of the other 

standards or parts of the rule, such that if a standard 

or provision in the final rule were to be remanded or 

vacated as the result of a court challenge, EPA 

intends for the other standards or provisions to 

remain in effect.

Comment [A8]: Same question as above. 

EPA: See response above
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other.3 The EPA also intends that the standards applicable to the 

units that modify after a the unit is subject to a 111(d) plan 

are severable and that if thosethe standards were over-turned, 

the standards applicable to requirements for units that modify 

when they are not subject to a 111(d) plan would apply to all 

modified sources, regardless of the timing of their 

modification. 

The EPA is proposing that the form of the standards for 

modified and reconstructed natural gas-fired stationary 

combustion turbines be consistent with the standards for newly 

constructed natural gas-fired stationary combustion turbines 

proposed on January 8, 2014 (79 FR 1430). In that proposal, the 

EPA proposed standards for turbines on a gross output basis, but 

also took comment on standards on a net output basis. The EPA is 

similarly proposing standards on a gross output basis, while 

soliciting comment on net output based standards, in today’s 

proposal for modified and reconstructed natural gas-fired 

stationary combustion turbines. To the extent that the EPA 

finalizes modified and reconstructed standards for stationary 

combustion turbines that are consistent with the standards for 

 

3

 See K Mart Corp. v. Cartier, Inc., 486 U.S. 281, 294 (1988) 

(holding that a regulation was severable because the “[t]he 

severance and invalidation of [the subsection at issue would] 

not impair the function of the statute as a whole, and there 

[was] no indication that the regulation would not have been 

passed but for its inclusion.”). 

Comment [A9]: Why is EPA including this 

statement? I don’t recall seeing language like this in 

prior rules where EPA is establishing standards for 

different source types within a rule. 

EPA: See response above 

Comment [A10]: Also if the approval of a state 

plan is over-turned? EPA may want to clarify. 

EPA: Text has been edited to clarify 
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newly constructed stationary combustion turbines, the EPA 

intends to take the same approach with regards to the use of net 

or gross output in both final actions. 

3. Costs and Benefits 

As explained in the regulatory impact analysis (RIA)4

 for 

this proposed rule and further below, the EPA expects few, if 

any, units would trigger either the modification or the 

reconstruction provisions that we are proposing today. Because 

there have been a limited number of units that have notified the 

EPA of NSPS modifications in the past, we have conducted an 

illustrative analysis of the costs and benefits for a 

representative modified unit. Based on the analysis, which is 

presented in Chapter 9 of the RIA, the EPA projects that this 

proposed rule will result in potential CO2 emission changes, 

quantified benefits, and costs for a unit that is subject to the 

modification provision. In this illustrative example based on a 

hypothetical 500 MW coal-fired unit, we estimate costs, net of 

fuel savings, of $0.78 million to $4.5 million (2011$) and CO2

reductions of 133,000 to 266,000 tons in 2025. The climate 

benefits from reductions in CO2, combined with the health cobenefits from reductions in SO2, NOx, and PM2.5, total $18 to $33 

 

4

 The RIA for this proposal is presented as Chapter 9 of the RIA 

for the companion rulemaking for proposed Emission Guidelines 

for Greenhouse Gas Emissions from Existing Stationary Sources: 

Electric Utility Generating Units.
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million (2011$) at a 3 percent discount rate for emission 

reductions in 2025 for the lowest emission reduction scenario, 

and $35 to $65 million ($2011) at a 3 percent discount rate for 

emission reductions in 2025 for the highest emission reduction 

scenario.5

B. Overview 

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

CO2 emissions?

The U.S. Supreme Court ruled, in Massachusetts v. EPA, that 

greenhouse gases (GHGs)6

 meets the definition of “air pollutant” 

in the CAA,7

 and premised its decision in AEP v. Connecticut8

that the CAA displaced any federal common law right to compel 

reductions in CO2 emissions from fossil fuel-fired power plants 

on its view that CAA section 111 applies to GHG emissions. 

 

5

 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average social cost of 

carbon (SCC) at a 3% percent discount rate. We emphasize the 

importance and value of considering the full range of SCC 

values, however, which include the model average at 2.5% and 5

%, percent, and the 95th percentile at 3%. percent. Similarly, 

we summarize the health co-benefits in this summary at a 3% 

percent discount rate. We provide estimates based on additional 

discount rates in the RIA. 

6

 Greenhouse gas pollution is the aggregate group of the 

following gases: CO2, methane (CH4), nitrous oxide (N2O), sulfur 

hexafluoride (SF6), hydrofluorocarbons (HFCs), and 

perfluorocarbons (PFCs).

7

 549 U.S. 497, 520 (2007). 

8

 131 S.Ct. 2527, 2537-38 (2011).
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Congress established requirements under section 111 of the 

1970 CAA to control air pollution from new stationary sources 

through NSPS. Specifically, as explained in greater detail in 

section II below, section 111(b) authorizes the EPA to set 

“standards of performance” for newly constructednew and 

(including modified) stationary sources from listed source 

categories to minimize limit emissions of air pollutants to the 

environment, and the EPA’s implementing regulations provide that 

define newly constructednew sources to include reconstructed 

sources9. Under section 111(a)(1), the EPA must set these 

standards at the level of emission reduction that reflects the 

“best system of emission reduction ... adequately demonstrated”, 

taking into account technical feasibility, costs, and other 

factors. 

For more than four decades, the EPA has used its authority 

under CAA section 111 to set cost-effective emission standards 

that ensure newly constructed, reconstructed and modified 

stationary sources use the best performing technologies to limit 

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

is following the same well-established interpretation and 

application of the law under CAA section 111 to address GHG 

emissions from modified and reconstructed fossil fuel-fired 

 

9

 40 CFR part 60 subpart A

Comment [A11]: Is the verb "minimize" correct 

in this context? Would "limit" or "reduce" be more 

accurate? What’s the statutory language? 

EPA: Agree – the text has been edited to use 

“limit” to more accurately reflect statutory 

language. 

Comment [A12]: Please include a citation for the 

implementing regulations. 

EPA: A citation has been added.
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electric steam generating units and natural gas-fired stationary 

combustion turbines. 

2. What sources would be regulated by the proposed standards? 

The proposed standards of performance would regulate GHG 

emissions from modified and reconstructed (1)fossil fuel-fired 

electric steam generating units – utility boilers and IGCC units 

– whose non-GHG emissions are regulated under 40 CFR part 60, 

subpart Da, and (2) natural gas-fired stationary combustion 

turbines, whose non-GHG emissions are regulated under 40 CFR 

part 60, subpart KKKK. Today’s proposal only applies to 

unitsNatural gas-fired stationary combustion turbines that 

supply more less than one-third of their potential electric 

output to the grid; therefore, peaking units are not covered 

subject to standards in by today’s proposal. 

The CAA and the EPA’s implementing regulations define a 

“modification,” for purposes of NSPS applicability, as a 

physical or operational change that increases the source’s 

maximum achievable hourly rate of emissions, with certain 

exceptions.10

Under the EPA’s 1975 framework regulations covering CAA 

section 111 standards of performance, “reconstruction” means the 

replacement of components of an existing facility to an extent 

 

10 CAA Section 111(a)(4); 40 CFR 60.2, 60.14.

Comment [A13]: This sentence is ambiguous as 

to whether it refers to all units that supply more than 

1/3 (i.e. #1 and #2 in this paragraph); or just gasfired CTs (#2). Please clarify. 

EPA: Language has been edited for clarification. 
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that (1) the fixed capital cost of the new components exceeds 50 

percent of the fixed capital cost that would be required to 

construct a comparable entirely new facility, and (2) it is 

technologically and economically feasible to meet the applicable 

standards.11

3. Why is the EPA issuing this proposed rule? 

GHG pollution threatens the American public's health and 

welfare by contributing to long-lasting changes in our climate 

system that can have a range of negative effects on human health 

and the environment. The impacts could include: longer, more 

intense and more frequent heat waves; more intense precipitation 

events and storm surges; less precipitation and more prolonged 

droughts in the West and Southwest; increased frequency and 

severity of short-term droughts in some other U.S. regions; more 

fires and insect pest outbreaks in American forests, especially 

in the West; and increased ground level ozone pollution, 

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

premature death. Health risks from climate change are especially 

serious for children, the elderly and those with heart and 

respiratory problems. 

Unlike most other air pollutants, GHGs may persist in the 

atmosphere from decades to millennia, depending on the specific 

 

11 40 CFR 60.15(b).

Comment [A14]: EPA may want to provide more 

clarity about the line between a “reconstruction” and 

a “new” unit. Would the full replacement of the 

EGU at the same site be considered a 

“reconstructed” or a “new” unit? Would the EGU 

have to be in a different geographic position (an 

entirely new site) to be considered “new” rather than 

“reconstructed”? 

EPA: See response to previous comment on page 

1. 
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GHG. This special characteristic makes it crucial to act now to 

limit GHG emissions from fossil fuel-fired power plants, 

specifically emissions of CO2, since they are the nation’s 

largest sources of carbon pollution. 

As previously noted, on June 25, 2013, President Obama 

issued a Presidential Memorandum directing the EPA to address 

carbon pollution from the power sector. As an initial step to 

limit carbon pollution from power plants, on January 8, 2014, 

the EPA published a proposed rule to limit GHG emissions from 

new fossil fuel-fired electric steam generating units (utility 

boilers and IGCC units) and new natural gas-fired stationary 

combustion turbines. The EPA is now taking another step to limit 

carbon pollution in this country by issuing a proposed rule to 

limit GHG emissions from modified and reconstructed fossil fuelfired electric steam generating units and modified and 

reconstructed natural gas-fired stationary combustion turbines.

Although we expect that the modification and reconstruction 

standards of performance in this rulemaking will apply to few, 

if any, sources, - since there have been a limited number in the 

past - these standards serve another important purpose that may 

affect a larger number of sources: providing an incentive, and 

the information needed, for existing sources to structure their 

actions to achieve their operating and business goals without 

triggering the modification or reconstruction standards. For 
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example, the modification standard encourages existing sources 

that undertake physical or operational changes to do so in a 

manner that does not increase their emission rate. 

4. What is the EPA’s approach to setting standards for modified 

and reconstructed EGUs under CAA section 111(b)? 

CAA section 111(b) requires the EPA to establish standards 

of performance that reflect the degree of emission limitation 

that is 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 EPA determines 

has been adequately demonstrated. The text and legislative 

history of CAA section 111, as well as relevant court decisions 

identify the factors for the EPA to consider in making a BSER 

determination. They include, among others, whether the system of 

emission reduction is technically feasible, whether the costs of 

the system are reasonable, the amount of emissions reductions 

that the system would generate, and whether the standard would 

effectively promote further deployment or development of 

advanced technologies. The case law addressing section 111 makes 

it clear that the EPA has discretion in weighing these factors, 

and that as a result, the EPA may weigh them differently for 

different types of sources or air pollutants. See further 

discussion of this case law in section VI below. 
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For each of the standards being proposed in today’s action, 

the EPA considered a number of alternatives and evaluated them 

against the factors. 

The BSER that we are proposing for each category of 

affected sources and the proposed standards of performance based 

on these BSER – as described immediately below –are based on 

that evaluation, as discussed in sections VI-IX below. 

5. What are the BSER and the standard of performance for 

modified fossil fuel-fired utility boilers and IGCC units? 

The EPA proposes that the BSER for modified fossil fuelfired boilers and IGCC units is each unit’s own best potential 

performance based on a combination of best operating practices 

and equipment upgrades. Specifically, the EPA is proposing unitspecific emission standards consistent with this BSER 

determination and is co-proposing two alternative standards for 

modified utility steam generating units. In the first coproposed alternative, modified utility boilers and IGCC units 

would be subject to a single emission standard. Specifically, 

under the first co-proposed alternative, a modified source would 

be required to meet a unit-specific emission limit determined by 

the affected source’s best demonstrated historical performance 

(in the years from 2002 to the time of the modification) with an 

additional two percent emission reduction. The EPA has 

determined that this standard can be met through a combination 
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of best operating practices and equipment upgrades. To account 

for facilities that have already implemented best practices and 

equipment upgrades, the proposal also specifies that modified 

facilities would not have to meet an emission standard more 

stringent than the corresponding standard for reconstructed 

EGUs. The EPA also solicits comment on whether, for units that 

have become subject to a CAA 111(d) plan, the period of best 

historical performance should be the years from 2002 to the time 

when the unit becomes subject to the CAA 111(d) plan, rather 

than to the time of the modification. This could address the 

concern that sources that make improvements to their CO2 emission 

rate as a result of a 111(d) plan would have lower baseline 

emissions from which to calculate their required rate. 

It is our interpretation, as we discuss in detail in the 

Legal Memorandum12, that an existing source would continue to be 

subject to 111(d) requirements after it becomes a modified 

source, remains an existing source for the purposes of 111(d),

whether the modification occurs before or after the promulgation 

of a 111(d) plan. Therefore EPA is co-proposing that modified 

sources would be required to meet unit-specific emission 

standards that would depend on the timing of the modification. 

 

12 “Legal Memorandum for Proposed Carbon Pollution Guidelines for 

Existing Power Plants” Technical Support Document available in 

rulemaking docket ID: EPA-HQ-OAR-2013-0602.-Add cite to legal 

memo

Comment [A15]: Is this a mistake? On p. 15, 

EPA makes this distinction: “all existing sources that 

become modified or reconstructed sources and which 

are subject to a CAA section 111(d) plan at the time 

of the modification or reconstruction”. At the very 

least, this is confusing. 

EPA Response: Edit has been made 
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Sources that modify prior to becoming subject to a CAA section 

111(d) plan would be required to meet the same standard 

described in the first co-proposal – that is, the modified 

source would be required to meet a unit-specific emission limit 

determined by the affected source’s best demonstrated historical 

performance (in the years from 2002 to the time of the 

modification) with an additional two percent emission reduction 

(based on equipment upgrades). Sources that modify after 

becoming subject to a CAA section 111(d) plan would be required 

to meet a unit-specific emission limit that would be determined 

by the 111(d) implementing authority and would be based on the 

source’s expected performance after implementation of identified 

unit-specific energy efficiency improvement opportunities. The 

BSER and standards of performance for modified fossil-fired 

electric utility steam generating units are discussed further in 

section VII. 

6. What is the BSER and standard of performance for modified 

natural gas-fired stationary combustion turbines? 

For modified natural gas-fired stationary combustion 

turbines, the EPA is proposing standards of performance based on 

efficient NGCC technology as the BSER. The emission limits 

proposed for these sources are 1,000 lb CO2/MWh-gross for 

facilities with heat input ratings greater than 850 MMBtu/h, and 

1,100 lb CO2/MWh-gross for facilities with heat input ratings of 

Comment [A16]: EPA may want to provide 

further explanation of its legal rationale for allow the 

emission limit under 111(b) to be determined by 

states. If this might be interpreted as EPA delegating 

its 111(b) NSPS-setting authority, EPA may want to 

ask for comment on its legal rationale. 

EPA Response: We do not think that a detailed 

legal rationale on this point is needed; however, 

we are soliciting comment on the proposal that 

the 111(d) implementing authority does this even 

where that is the state, as opposed to EPA.
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850 MMBtu/h or less. For sources that are subject to a CAA 

section 111(d) plan, the EPA is also soliciting comment on 

whether the sources should be allowed to elect, as an 

alternative to the otherwise applicable numeric standard, to 

instead meet a unit-specific emission standard that is 

determined by the 111(d) implementing authority based on 

implementation of identified energy efficiency improvement 

opportunities applicable to the source. This is discussed 

further in section IX. 

7. What are BSER and the standard of performance for 

reconstructed fossil fuel-fired utility boilers and IGCC units? 

For reconstructed utility boilers and IGCC units, the EPA 

is proposing a standard of performance with BSER based on the 

most efficient generating technology for these types of units 

(i.e., reconstructing the boiler to use higher steam, 

temperature and pressure, even if the boiler was not originally 

designed to do so13). The proposed emission limit for these 

sources is 1,900 lb CO2/MWh-net for sources with a heat input 

rating of greater than 2,000 MMBtu/h or 2,100 lb CO2/MWh-net for 

sources with a heat input rating of 2,000 MMBtu/h or less. The 

difference in the proposed standards for larger and smaller 

 

13 Steam with higher temperature and pressure has more thermal 

energy which can be more efficiently converted to electrical 

energy.
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units is based on greater availability of higher 

pressure/temperature steam turbines (e.g. supercritical steam 

turbines) for larger units. The standards could also be met 

through other technology options such as natural gas co-firing 

or capture of a small quantity of CO2 via partial CCS. This is 

discussed further in section VI below. 

As discussed in the Legal Memorandum14, a reconstruction 

would have no effect on the applicability of an approved CAA 

section 111(d) plan; thus, a source that is subject to 

requirements in a CAA section 111(d) plan would remain subject 

to those requirements. 

8. What are BSER and the standard of performance for 

reconstructed natural gas-fired stationary combustion turbines? 

The EPA is proposing to find efficient NGCC technology to 

be the BSER for reconstructed stationary combustion turbines. 

Therefore, the EPA is proposing that larger units be required to 

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

be required to meet a standard of 1,100 lb CO2/MWh-gross. This is 

discussed further in section VIII below. 

A reconstruction would have no effect on the applicability 

of an approved CAA section 111(d) plan on the existing source; 

thus, a source that is subject to requirements in a CAA section 

 

14 Add cite to legal memo 
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111(d) plan would remain subject to those requirements, even 

after reconstruction. 

9. How is EPA proposing to codify the requirements? 

In the January 8, 2014 proposal of carbon pollution 

standards for new power plants (79 FR 1430), the EPA co-proposed 

two options for codifying applicable requirements for covered 

sources. Under the first option the EPA proposed to codify the 

standards of performance for the respective sources within 

existing 40 CFR part 60 subparts so that applicable GHG 

standards for electric utility steam generating units would be 

included in subpart Da and applicable GHG standards for 

stationary combustion turbines would be included in subpart 

KKKK. Under the second option, the EPA co-proposed to create a 

new subpart TTTT and to include all GHG standards of performance 

for covered sources in that newly created subpart. 

In this action for modified and reconstructed sources, the 

EPA co-proposes the same two options for codifying the 

applicable standards. For consistency, the EPA intends – when it 

takes final action on this proposal and on the January 2014 

proposal for new sources, respectively – to codify the standards 

in the same way for the sources addressed under the two 

proposals. 

10. What is the organization and approach for this proposal? 
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 Section II of this preamble provides a brief summary of 

background information on climate change impacts of GHG 

emissions, GHG emissions from fossil-fuel fired EGUs, the 

utility power sector, the statutory and regulatory background 

relevant to this rulemaking, and the EPA’s stakeholder outreach 

activities. Section II also contains additional information on 

the regulatory and litigation history of CAA section 111. 

The specific proposed requirements for modified and 

reconstructed sources are described in detail in section III. 

The rationale for reliance on a rational basis to regulate GHG 

emissions from fossil fuel-fired EGUs and the rationale for the 

applicability requirements in today's proposal are presented in 

sections IV and V, respectively. Sections VI through IX describe 

the rationale for each of the proposed emission standards, 

including an explanation of the determination of the BSER for 

reconstructed fossil fuel-fired utility boilers and IGCC units 

and modified fossil fuel-fired utility boilers and IGCC units, 

as well as for reconstructed natural gas-fired stationary 

combustion turbines and modified natural gas-fired stationary 

combustion turbines. Impacts of the proposed action are 

described in section X. A discussion of statutory and executive 

order reviews is provided in section XI, and the statutory 

authority for this action is provided in section XII. 
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It should be noted that this rulemaking overlaps in certain 

respects with two other related rulemakings: the January 2014 

proposed rulemaking for CO2 emissions from new affected EGUs, and 

the rulemaking for existing EGUs that the EPA is proposing at 

the same time as the present rulemaking. In a number of places 

in this preamble, the EPA cross-references parts of those two 

rulemakings. However, each of these three rulemakings is 

independent of the other two, and each has its own rulemaking 

docket. Accordingly, anyone who wishes to comment on any aspect 

of this rulemaking, including anything described by a crossreference to one of the other two related rulemakings, should 

make those comments on this rulemaking. 

C. Does this action apply to me? 

The entities potentially affected by the proposed standards 

are shown in Table 2 below. 

Table 2. Potentially Affected Entitiesa

Category NAICS 

Code 

Examples of Potentially Affected 

Entities 

Industry 221112 Fossil fuel electric power generating 

units. 

Federal 

Government 

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government 

221112b Fossil fuel electric power generating 

units owned by municipalities. 

Tribal 

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

 Includes North American Industry Classification (NAICS) 

categories for source categories that own and operate electric 

power generating units (including boilers and stationary 

combined cycle combustion turbines). 

b

 Federal, state or local government-owned and operated 

establishments are classified according to the activity in which 

they are engaged. 

This table is not intended to be exhaustive, but rather to 

provide a guide for readers regarding entities likely to be 

affected by this proposed action. To determine whether your 

facility, company, business, organization etc., would be 

regulated by this proposed action, you should examine the 

applicability criteria in 40 CFR 60.1. If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permitting authority for the 

entity or your EPA regional representative as listed in 40 CFR 

60.4 (General Provisions). 

II. Background 

In this section15, we discuss climate change impacts from 

GHG emissions, both on public health and public welfare, present 

information about GHG emissions from fossil-fuel fired EGUs, 

describe the utility power sector and summarize the statutory 

and regulatory background relevant to this rulemaking. We close 

 

15 This background section is intended to provide the same or 

very similar background information as provided in the companion 

proposals for new sources (79 FR 1430) and existing sources (the 

111(d) proposal in today’s Federal Register). Any minor 

differences in phrasing between this proposal and the companion 

proposals are not intended to state a substantive difference. 

Comment [A17]: Will this section track with any 

changes made to the existing source’s comparable 

section? 

EPA Response: Yes, sections A and B track with 

changes made to the comparable sections in the 

111(d) proposal.
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this section by describing stakeholder outreach and a brief 

history of modifications and reconstructions in the power 

sector. 

A. Climate Change Impacts from GHG Emissions 

In 2009, the EPA Administrator issued the document we refer 

toknown as the GHG Endangerment Finding under CAA section 

202(a)(1).16 In the Endangerment Finding, which focused on public 

health and public welfare impacts within the U.S., the 

Administrator found that elevated concentrations of GHGs in the 

atmosphere may reasonably be anticipated to endanger the public 

health and welfare of current and future generations. We 

summarize these adverse effects of GHGs on public health and 

welfare briefly here.17

 

16 “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) (“Endangerment Finding”).

17 The January 8, 2014, preamble to the proposed GHG standards 

for new EGUs (79 FR 1430) and the RIA supporting that proposal 

include a more detailed summary of the public health and welfare 

impacts detailed in the 2009 Endangerment Finding, as well as a

discussion of the science supporting the EPA’s conclusions 

regarding the question of whether GHG endanger public health and 

welfare including: 1) the process by which the Administrator 

reached the Endangerment Finding in 2009; 2) the EPA’s response 

in 2010 to ten administrative petitions for reconsideration of 

the Endangerment Finding (the Reconsideration Denial); and 3) 

the decision by the United States Court of Appeals for the 

District of Columbia Circuit in 2012 to uphold the Endangerment 

Finding and the Reconsideration Denial.
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1. Public Health Impacts Detailed in the 2009 Endangerment 

Finding18

Anthropogenic emissions of GHGs and consequent cClimate 

change caused by human emissions of GHGs threatens public health 

in multiple aspectsways. By raising average temperatures, 

climate change increases the likelihood of heat waves, which are 

associated with increased deaths and illnesses. While climate 

change also leads toincreases the likelihood of reductions in 

cold-related mortality, evidence indicates that the increases in 

heat mortality will be larger than the decreases in cold 

mortality in the U.S. Compared to a future without climate 

change, Cclimate change is expected to increase ozone pollution 

over broad areas of the countryU.S., including large population 

areas with already unhealthy surface ozone levels in the largest 

metropolitan areas with the worst ozone problems, and thereby 

increase the risk of morbidity and mortality. Other public 

health threats also stem from projected increases in intensity 

or frequency of extreme weather associated with climate change, 

such as increased hurricane intensity, increased frequency of 

intense storms and heavy precipitation. Increased coastal storms 

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

 

18 “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) (“Endangerment Finding”).
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increased drownings and other health impacts. Children, the 

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

climate-related health effects. 

2. Public Welfare Impacts Detailed in the 2009 Endangerment 

Finding19

Anthropogenic emissions of GHGs and consequent cClimate 

change caused by human emissions of GHGs also threatens public 

welfare in multiple aspectsways. Climate changes are expected to 

place large areas of the country at serious risk of reduced 

water supplies, increased water pollution, and increased 

occurrence of extreme events such as floods and droughts. 

Coastal areas are expected to face increased risks from storm 

and flooding damage to property, as well as adverse impacts from 

rising sea level, such as land loss due to inundation, erosion, 

wetland submergence, and habitat loss. Climate change is 

expected to result in an increase in peak electricity demand, 

and extreme weather from climate change threatens energy, 

transportation and water resource infrastructure. Climate change 

may exacerbate ongoing environmental pressures in certain 

settlements, particularly in Alaskan indigenous communities. 

Climate change also is very likely to fundamentally rearrange 

 

19 “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) (“Endangerment Finding”).
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U.S. ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S. 

3. New Scientific Assessments 

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

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

scientific information to inform the Administrator’s judgment 

regarding the question of whether GHGs endanger public health 

and welfare was to rely primarily upon the recent, major 

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

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

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

assessments addressed the scientific issues that the EPA was 

required to examine, were comprehensive in their coverage of the 

GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. Since the 

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 
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additionalsuch assessments have been released. These assessments 

include the IPCC’s 2012 “Special Report on Managing the Risks of 

Extreme Events and Disasters to Advance Climate Change 

Adaptation” (SREX) and the Working Group I contribution to the 

2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 

“Climate Change Impacts in the United States” (Climate Change 

Impacts), and the NRC’s 2010 “Ocean Acidification: A National 

Strategy to Meet the Challenges of a Changing Ocean” (Ocean 

Acidification), 2011 “Report on Climate Stabilization Targets: 

Emissions, Concentrations, and Impacts over Decades to 

Millennia” (Climate Stabilization Targets), 2011 “National 

Security Implications for U.S. Naval Forces” (National Security 

Implications), 2011 “Understanding Earth’s Deep Past: Lessons 

for Our Climate Future” (Understanding Earth’s Deep Past), 2012 

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

Washington: Past, Present, and Future”, 2012 “Climate and Social 

Stress: Implications for Security Analysis” (Climate and Social 

Stress), and 2013 “Abrupt Impacts of Climate Change” (Abrupt 

Impacts) assessments. 

The EPA has reviewed these new assessments and finds that 

the improved understanding of the climate system they present 

strengthens the case that GHGs are endangering public health and 

welfare. 
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In addition, these assessments highlight the urgency of the 

situation as the concentration of CO2 in the atmosphere continues 

to rise. Absent a reduction in emissions, a recent NRC of the 

National Academies assessment by the NRC projected that 

concentrations by the end of the century would increase to 

levels that the eEarth has not experienced for millions of 

years.20 In fact, that assessment stated that “the magnitude and 

rate of the present greenhouse gas increase place the climate 

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

radiative forcing of the global climate system in Earth 

history.”21

What this means, as stated in another NRC assessment, is 

that: 

Emissions of carbon dioxide from the burning of 

fossil fuels have ushered in a new epoch where human 

activities will largely determine the evolution of 

Earth’s climate. Because carbon dioxide in the 

atmosphere is long lived, it can effectively lock 

Earth and future generations into a range of impacts, 

some of which could become very severe. Therefore, 

emission reductions choices made today matter in 

determining impacts experienced not just over the next 

few decades, but in the coming centuries and 

millennia.22 

 

20 National Research Council, Understanding Earth’s Deep Past, p. 

1. 

21 Ibid, p.138. 22 National Research Council, Climate Stabilization Targets, 

p. 3. 
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Moreover, due to the time-lags inherent in the eEarth’s 

climate, the NRCClimate Stabilization Targets assessment notes 

that the full warming from any given concentration of CO2 reached 

will not be realized for several centuries. 

The recently released USGCRP “Climate Change Impacts” 

assessment23 emphasizes that climate change is already happening 

now and it is happening in the U.S. The assessment documents the 

increases in some extreme weather and climate events in recent 

decades, the damage and disruption to infrastructure and 

agriculture, and projects continued increase and more severe 

changes across a wide range of peoples, sectors, and ecosystems. 

These assessments underscore the urgency of reducing 

emissions now.: Thesetoday’s emissions will otherwise lead to 

raised atmospheric concentrations for thousands of years, and 

raised eEarth system temperatures for even longer. Emission 

reductions today will benefit the public health and public 

welfare of current and future generations. 

Finally, it should be noted that the concentration of CO2 in 

the atmosphere continues to rise dramatically. At the time of 

theIn 2009, the year of the Endangerment Finding, the average 

concentration of CO2 as measured on top of Mauna Loa was 387 

 

23 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment. 

Available at http://nca2014.globalchange.gov/. 
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Page 41 of 181

parts per million (ppm).24 The average concentration in 2013 was 

396 ppm. And the monthly concentration inBy MarchApril 2014 was 

401 ppm, the first time a monthly average has exceeded (will 

update with most current data as of date of signature), the 

level had increased to 400 ppm since record keeping began, and 

for at least the past 800,000 years according to ice core 

records.25

B. GHG Emissions from Fossil Fuel-fired EGUs 

Among stationary sources in the U.S., fFossil fuel-fired 

EGUs are by far the largest emitters of GHGs, primarily in the 

form of CO2, among stationary sources in the U.S., and. Aamong 

fossil fuel-fired EGUsunits, coal-fired units are by far the 

largest emitters. This section describes the amounts of those 

emissions and places those amounts in the context of the 

national inventory of GHGs.

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

Gas Emissions and Sinks26 (the U.S. GHG Inventory) to comply with 

commitments under the United Nations Framework Convention on 

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

 

24 ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt. 25 http://www.esrl.noaa.gov/gmd/ccgg/trends/. 26 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2012”, Report EPA 430-R-14-003, United States Environmental 

Protection Agency, April 15, 2014.“Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990 – 2012”, Draft Report, United 

States Environmental Protection Agency, February 2014. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

Comment [A18]: EPA could consider adding 

pre-industrial concentration for reference. 

EPA: A link to historical concentrations has been 

provided for readers.
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trends, is organized by industrial sectors. It provides the 

information in Table 3 below, which presents total U.S. 

anthropogenic emissions and sinks27 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2012.

Table 3. U.S. GHG Emissions and Sinks by Sector (teragram carbon 

dioxide equivalent (Tg CO2 Eq.))28

SECTOR 1990 2005 2012 

Energy 

5,256.55,260.

1

6,239.46,243.

5

5,489.65,498.

9

Industrial Processes 316.1 330.2334.9 319.6334.4

Solvent and Other 

Product Use 4.4 4.4 4.4 

Agriculture 473.9 512.2 526.3 

Land Use, Land-Use 

Change and Forestry 13.7 25.5 37.8 

Waste 165.0 133.2 124.0 

Total Emissions 

6,229.66,233.

2

7,244.97,253.

8

6,501.56,525.

6

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.43) 

 

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

forests or underground or deep sea reservoirs of carbon dioxide.

28 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014.“Inventory of 

U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2012, Draft 

Report, United States Environmental Protection Agency, February 

2014. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html
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Net Emissions 

(Sources and Sinks) 

5,398.55,402.

1

6,214.26,223.

1

5,522.15,546.

3

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.97 percent of total 

2012 GHG emissions.29 In 2012, fossil fuel combustion by the 

electric power sector – entities that burn fossil fuel and whose 

primary business is the generation of electricity – accounted 

for 38.7 percent of all energy-related CO2 emissions.30 Table 4 

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

for years 1990, 2005 and 2012. 

Table 4. U.S. GHGCO2 Emissions from Generation of Electricity 

from Combustion of Fossil Fuels (Tg CO2 Eq.)31

 

29 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014.

30 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014.

31 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2012”, Report EPA 430-R-14-003, United States 

Environmental Protection Agency, April 15, 2014.

GHG EMISSIONS 1990 2005 2012 

Total CO2 emissions from 

fossil fuel combustion 

EGUs 1,820.8 2,402.1 

2,023.62,022.

7

 - from coal 1,547.6 1,983.8

1,512.21,511.

2

 - from natural gas 175.3 318.8 492.2 

 - from petroleum 
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C. The Utility Power Sector 

Electricity in the U.S. is generated by a range of sources 

- from power plants that use fossil fuels such as coal, oil and 

natural gas, to non-fossil sources, such as nuclear, solar, wind 

and hydroelectric power. Currently, the majority of power in the 

U.S. is generated from the combustion of coal, natural gas and 

other fossil fuels. 

Natural gas-fired EGUs typically use one of two 

technologies: NGCC or simple cycle combustion turbines. NGCC 

units first generate power from a combustion turbine (the 

combustion cycle). The unused heat from the combustion turbine 

is then routed to a heat recovery steam generator (HRSG) that 

generates steam which is used to produce power using a steam 

turbine (the steam cycle). Combining these generation cycles 

increases the overall efficiency of the system. Simple cycle 

combustion turbines use a single combustion turbine to produce 

electricity (i.e., there is no heat recovery). The power output 

from these simple cycle combustion turbines can be easily ramped 

up and down making them ideal for “peaking” operations. 

Coal-fired utility boilers are primarily either PC boilers 

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

crushed (pulverized) into a powder in order to increase its 

97.5 99.2 18.8 
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surface area. The coal powder is then blown into a boiler and 

burned. In a coal-fired boiler using FB combustion, the coal is 

burned in a layer of heated particles suspended in flowing air. 

Power can also be generated using gasification technology. 

An IGCC unit gasifies coal or petroleum coke to form a syngas 

composed of carbon monoxide and hydrogen, which can be combusted 

in a combined cycle system to generate power. 

D. Statutory Background

CAA section 111 authorizes the EPA to prescribe new source 

performance standards (NSPS) applicable to certain new 

stationary sources (including modified and reconstructed 

sources).32 As a preliminary step to regulation, the EPA must 

list categories of stationary sources that the Administrator, in 

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

significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare.” The EPA has 

listed and regulated more than 60 stationary source categories 

under section 111.33 

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

and then promulgates “standards of performance” for “new 

sources” in the category.34 A “new source” is “any stationary 

 

32 CAA section 111(b)(1)(A). 33 See generally 40 CFR subparts D-MMMM. 34 CAA section 111(b)(1)(B).
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source, the construction or modification of which is commenced 

after,” in general, the date of the proposal.35 A modification is 

“any physical change ... or change in the method of operation 

... which increases the amount of any air pollutant emitted by 

such source or which results in the emission of any air 

pollutant not previously emitted.”36 The EPA, through 

regulations, has determined that certain types of changes are 

exempt from consideration as a modification.37

The EPA’s 1975 framework regulations also provide that an 

existing source is considered a new source if it undertakes a 

“reconstruction,” which is the replacement of components of an 

existing facility to an extent that (1) the fixed capital cost 

of the new components exceeds 50 percent of the fixed capital 

cost that would be required to construct a comparable entirely 

new facility, and (2) it is technologically and economically 

feasible to meet the applicable standards.38 

CAA 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 

 

35 CAA section 111(a)(2). 36 CAA section 111(a)(4). 37 40 CFR 60.2, 60.14(e). 38 40 CFR 60.15.
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(taking into account the cost of achieving such reduction and 

any nonair quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated.” This definition makes clear that the standard of 

performance must be based on “the best system of emission 

reduction ... adequately demonstrated” (BSER). The standard that 

the EPA develops, based on the BSER, is commonly a numeric 

emission limit, expressed as a performance level (e.g., a ratebased standard). Generally, the EPA does not prescribe a 

particular technological system that must be used to comply with 

a standard of performance. Rather, sources generally may select 

any measure or combination of measures that will achieve the 

emissions level of the standard.39 In establishing standards of 

performance, the EPA has significant discretion to create 

subcategories based on source type, class or size.40 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to establish requirements for existing 

sources in that source category for any air pollutant that, in 

general, is not regulated under the CAA section 109 requirements 

for the National Ambient Air Quality Standards or regulated 

under the CAA section 112 requirements for hazardous air 

 

39 CAA section 111(b)(5) 40 CAA section 111(b)(2) 
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pollutants. Unlike CAA section 111(b), which gives EPA direct 

authority to set national standards, CAA section 111(d) requires 

the EPA to promulgate emission guidelines directing states to 

develop and submit, for EPA approval, state plans that include 

standards of performance for the existing sources. 

E. Regulatory Background 

In 1971, the EPA initially included fossil fuel-fired 

(which includes natural gas, petroleum and coal) EGUs that use 

steam-generating boilers in a category that it listed under CAA 

section 111(b)(1)(A),41 and the EPA promulgated the first set of 

standards of performance for sources in that category, which it 

codified in subpart D.42 In 1977, the EPA initially included 

fossil fuel-fired combustion turbines in a category that the EPA 

listed under CAA section 111(b)(1)(A),43 and the EPA promulgated 

standards of performance for that source category in 1979, which 

the EPA codified in subpart GG.44 

The EPA has revised those regulations, and in some 

instances, has revised the codifications (that is, the 40 CFR 

 

41 36 FR 5931 (March 31, 1971) 42 “Standards of Performance for Fossil-Fuel-Fired Steam 

Generators for Which Construction Is Commenced After August 17, 

1971,” 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40-

46;. 

43 42 FR 53,657 (October 3, 1977). 44 “Standards of Performance for Electric Utility Steam 

Generating Units for Which Construction is Commenced After 

September 18, 1978,” 44 FR 33580 (June 11, 1979).
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part 60 subparts), several times over the ensuing decades. In 

1979, the EPA divided subpart D into 3 subparts – Da (“Standards 

of Performance for Electric Utility Steam Generating Units for 

Which Construction is Commenced After September 18, 1978”), Db 

(“Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units”) and Dc (“Standards of 

Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units”) – in order to codify separate requirements 

that it established for these subcategories.45 In 2006, the EPA 

created subpart KKKK, ”Standards of Performance for Stationary 

Combustion Turbines,” which applied to certain sources 

previously regulated in subparts Da and GG.46 None of these 

subsequent rulemakings, including the revised codifications, 

however, constituted a new listing under CAA section 

111(b)(1)(A). 

The EPA promulgated amendments to subpart Da in 2006, which 

included new standards of performance for criteria pollutants 

for EGUs, but no standards of performance for GHG emissions.47

Petitioners sought judicial review of the rule by the D.C. 

 

45 44 FR 33,580 (June 11, 1979) 46 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (March 

20, 2009).

47 ”Standards of Performance for Electric Utility Steam 

Generating Units, Industrial-Commercial-Institutional Steam 

Generating Units, and Small Industrial-Commercial-Institutional 

Steam Generating Units, Final Rule.” 71 FR 9866 (February 27, 

2006).
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Circuit, contending, among other issues, that the rule was 

required to include standards of performance for GHG emissions 

from EGUs.48 The January 8, 2014 preamble to the proposed CO2

standards for new EGUs49 includes a discussion of the GHG-related 

litigation of the 2006 Final Rule as well as other GHGassociated litigation. 

F. Stakeholder Outreach 

The EPA has engaged extensively with a broad range of 

stakeholders and the general public regarding climate change, 

carbon pollution from power plants, and carbon pollution 

reduction opportunities. These stakeholders included industry 

and electric utility representatives, state and local officials, 

tribal officials, labor unions and non-governmental 

organizations. 

In February and March 2011, early in the process of 

developing carbon pollution standards for new power plants, the 

EPA held five listening sessions to obtain 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. 

 

48State of New York, et al. v. EPA, No. 06–1322. 49 79 FR 1430
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The EPA has conducted subsequent outreach sessions: the 

vast majority of which occurred between September 2013 and 

November 2013. The agency held 11 public listening sessions; one 

national listening session in Washington, DC and 10 listening 

sessions in locations across the country. In addition to the 11 

public listening sessions, the EPA has held hundreds of meetings 

with individual stakeholder groups, and meetings that brought 

together a variety of stakeholders to discuss a wide range of 

issues related to the electricity sector and regulation of GHGs 

under the CAA. The agency provided and encouraged multiple 

opportunities to engage with each one of the 50 states. The 

agency met with electric utility associations and electricity 

grid operators. Agency officials have engaged with labor unions 

and with leaders representing large and small industries. 

Because of the focus of the standard on the electricity sector, 

many of the EPA’s meetings with industry have been with 

utilities and industry representatives directly related to the 

electricity sector. The agency has also met with energy 

industries such as coal and natural gas interests. In addition, 

the agency has met with companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

represent renewable energy and energy efficiency interests. The 

EPA has also met with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries, 
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to help understand the issues related to large industrial 

purchasers of electricity. Agency officials engaged with 

representatives of environmental justice organizations, 

environmental groups, and religious organizations. 

Although this stakeholder outreach was primarily framed 

around the GHG emission guidelines for existing EGUs, the 

outreach encompassed issues relevant to this proposed rulemaking 

for modified and reconstructed EGUs. For example, existing EGUs 

would be subject to standards for modified and reconstructed 

EGUs should they undertake modification or reconstruction 

actions, and, thus it is important that we understand previous 

state and stakeholder experience with reducing CO2 emissions in 

the power sector. 

A detailed discussion of this stakeholder outreach is 

included in the preamble to the GHG emission guidelines for 

existing affected EGUs being proposed in a separate action 

today. 

G. Modifications and Reconstructions

1. Modifications 

The EPA’s current regulations50 define an NSPS 

“modification” as a physical or operational change that 

 

50 The discussion of the EPA’s regulations in this rulemaking is 

for background purposes only. The EPA is not re-opening, and 

thus is not soliciting comment on, any provision in its existing 

regulations. 
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increases the source’s maximum achievable hourly rate of 

emissions, with certain exemptions.51 

Based on current information, the EPA believes that 

projects may involve equipment changes to improve efficiency 

that could have the effect of increasing a source’s maximum 

achievable hourly emission rate (lb CO2/h), even while decreasing 

its actual output based emission rate (lb CO2/MWh). However, 

based on current information, the most likely projects that 

could increase the maximum achievable hourly rate of CO2

emissions would involve the installation of add-on control 

equipment required to meet CAA requirements for criteria and 

hazardous air pollutants. These increases in CO2 emissions would 

generally be small and would occur as a chemical by-product of 

the operation of the control equipment. All of these actions, 

however, would be exempted from the definition of modification.52 

There are, however, some actions that could potentially 

trigger the modification provisions of 111(b). For example, in 

some cases, generation from a fossil fuel-fired electric utility 

steam generating unit is limited not by the size of the boiler, 

but by other factors, such as the size of the steam turbine or 

limitations in the particulate control equipment that, in turn, 

limit the amount of coal that can be combusted. If the steam 

 

51 40 CFR 60.2, 60.14. 52 40 CFR 60.14.

Comment [A19]: Would also be helpful to 

include here the additional clarification included in 

the RIA: “In other cases, those projects would 

involve equipment changes to improve fuel 

efficiency to meet state requirements for 

implementation of the future CAA section 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 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.” 

EPA: We prefer the language as it is currently 

presented and feel that the level of detail in the 

preamble is sufficient.

Comment [A20]: Suggest explaining why this is 

the case. 

EPA: We prefer the language as it is currently 

presented and feel that the level of detail in the 

preamble is sufficient.
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turbine or particulate control device is upgraded, more coal can 

be combusted in the boiler, increasing hourly emissions. 

Our base of knowledge concerning the types of NSPS 

modifications has depended largely on self-reporting by power 

plants and on the enforcement actions brought against power 

plants. Over the lengthy history of the NSPS program, the number 

of modifications that we arehave become aware of is limited. 

2. Comments on the April 2012 Proposal for New Sources Related 

to Modifications 

In the April 13, 2012 proposed Standards of Performance for 

Greenhouse Gas Emissions for New Stationary Sources: Electric 

Utility Generating Units (77 FR 22392)53, the EPA did not propose 

standards of performance for modified sources; however, it did 

specifically request comment on the types of modifications that 

may be expected and on the appropriate control measures that may 

be applied. The agency received a number of comments addressing 

standards for modified and reconstructed EGUs.54 The EPA 

subsequently withdrew that proposed rulemaking.55 While many of 

those comments informed today’s proposal, the EPA is not 

responding to those comments in this rulemaking, and if members 

 

53 The proposal was subsequently withdrawn with the publication 

of the January 8, 2014 proposal.

54 The comments are available in the rulemaking docket. Docket 

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

55 79 FR 1352 
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of the public wish to express views on this rulemaking they must 

do so in comments on this rulemaking. 

Many of those comments emphasized that a standard of 

performance that is based on CCS (or partial CCS) is not 

appropriate for modified EGUs. Some commenters suggested that a 

well-designed CAA section 111(d) program could obviate the need 

to set separate standards of performance for modified sources. 

Several commenters disagreed with EPA’s assertion that it lacked 

adequate information to propose standards for modified sources 

(at that time), stating that proposed standards should be based 

on energy efficiency measures. 

3. Reconstructions 

The EPA’s framework regulations, interpreting the 

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

that an existing source, “upon reconstruction,” becomes subject 

to the standard of performance for new sources.56 The regulations 

define reconstruction as the replacement of components of an 

existing facility to such an extent that (1) the fixed capital 

cost of the new components exceeds 50 percent of the fixed 

capital cost that would be required to construct a comparable 

entirely new facility, and (2) it is technologically and 

economically feasible to meet the applicable standards set forth 

 

56 40 CFR 60.15(a) 
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in this part. 

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 its 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 purpose of the reconstruction provision is to 

discourage the perpetuation of a facility, instead of replacing 

it at the end of its useful life with a newly constructed 

affected facility.

The regulations 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 provide 

specified information. This information must include: the name 

and address of the owner or operator; the location of the 

existing facility; a brief description of the existing facility 

and the components which are to be replaced; a description of 

existing and proposed air pollution control equipment; an 

estimate of the fixed capital cost of the replacements and of 

constructing a comparable entirely new facility; the estimated 

life of the existing facility after the replacements; and, 

including “a discussion of any economic or technical limitations 
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the facility may have in complying with the applicable standards 

of performance after the proposed replacements.” In addition, 

tThe regulations require the EPA to determine, within a 

specified time period, whether the proposed replacement 

constitutes a reconstruction.57 The determination shall be based 

on: the fixed capital cost in comparison to the cost to 

construct a comparable entirely new facility; the estimated life 

of the facility after the replacements compared to the life of a 

comparable entirely new facility; the extent to which the 

components being replaced cause or contribute to emissions from 

the facility; and any economic or technical limitations on 

compliance with applicable standards of performance which are 

inherent in the proposed replacements.

Historically, few EGUs have undertaken reconstructions. 

Because of the relative prices of coal and natural gas, and the 

relative costs of reconstructing an existing coal-fired EGU and 

newly constructing an entirely new NGCC unit, the EPA expects 

that few, if any, existing coal-fired EGUs will undertake 

projects that will qualify the unit to be a reconstructed source 

during the analysis period of this rulemaking (i.e., through 

2025). The EPA also does not expect existing NGCC units to 

undertake reconstructions during the analysis period (i.e., 

 

57 40 CFR 60.15(d)–(e) 
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through 2025) because most of them are relatively young (over 80 

percent of the NGCC fleet came on-line after 2000).

While there are specific provisions in the EPA’s 

implementing regulations at 40 CFR 60.15 on what constitutes a 

reconstructed source (as just described), there is not such 

guidance on when an existing source replaces components to such 

a degree that it goes beyond a reconstruction and becomes 

essentially a newly constructed source. Historically there has 

been little need to distinguish between reconstructed sources 

and newly constructed sources as the standards of performance 

are typically the same for either. However, the standards 

proposed in today’s action are different – for reasons we 

explain later – and, therefore, there is a need to clearly 

delineate between a reconstructed source and a newly constructed 

source. For example, it is clear that an entirely new greenfield 

facility would constitute a newly constructed source. It is 

EPA’s view that, a new unit that is built on property contiguous 

with an existing source – but not in the same footprint as the 

existing source – would also constitute a newly constructed 

source. And, it is EPA’s view that a unit that entirely, or for 

all practical purposes, completely replaces an existing sources 

by being constructed on the replaced source’s existing footprint 

would also constitute a newly constructed source. The EPA 

solicits comment on the delineation between a reconstructed 

Comment [A21]: While this may deal with the 

immediate future, is there a need to consider any 

modifications or reconstructions for these units as 

they age? Or can EPA mention the statutory 

requirement to revisit new and modified standards 

every 8 years? 

EPA: The text has been edited to specify “the 

analysis period of this rulemaking (through 2025).
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source, which would be subject to standards proposed in today’s 

action, and a newly constructed source, which would be subject 

to standards proposed in the January 2014 proposal (FR 79 1430), 

for those situations where significant equipment is being 

replaced (enough to exceed the reconstruction threshold) but the 

entire unit is not being rebuilt. 

In addition, the EPA requests comment on having an upper 

capital cost threshold for reconstruction, such that facilities 

that exceed that threshold would be subject to the standard of 

performance for newly constructed sources. With respect to this 

concept, the EPA requests comment on both: (1) the idea of 

having an upper threshold and (2) the appropriate upper 

threshold. With respect to the appropriate upper threshold, EPA 

specifically requests comment on an upper threshold within the 

range of 75 to 100 percent of the cost of an entirely new and 

comparable facility. Finally, the EPA requests comment on 

whether this upper threshold should be coupled with a provision 

comparable to 40 CFR 60.15(b)(2) and 60.15(f)(4), such that a 

facility that exceeded the upper threshold would not be subject 

to the new construction standard if it was technologically and 

economically infeasible for that facility to meet the new 

construction standard.

4. Comments on the April 2012 Proposal for New Sources Related 

to Reconstructions 
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In the April 13, 2012 proposed Standards of Performance for 

Greenhouse Gas Emissions for New Stationary Sources: Electric 

Utility Generating Units (77 FR 22392), the EPA did not propose 

standards of performance for reconstructed sources; however, it 

did specifically request comment on the types of reconstructions 

that may be expected and on the appropriate control measures 

that may be applied. The agency received a number of comments 

addressing standards for reconstructed EGUs.58 As noted above, 

the agency subsequently withdrew that proposal and is not 

responding to those comments in this rulemaking, so that if 

members of the public wish to express views on this rulemaking 

they must do so in comments on this rulemaking. 

Many of the comments on the April 13, 2012 proposal 

supported a delay in proposing standards for reconstructed 

sources. Others did not favor the delay and suggested, instead, 

that reconstructed sources be subject to the same standard as 

newly constructed sources. One commenter expressed concern that 

an existing source that elected to retrofit with CCS technology 

(perhaps in reliance on enhanced oil recovery (EOR) markets) 

might trigger the requirements for a reconstruction due to the 

high cost of CCS technology. The commenter suggested that the 

EPA exclude the cost of retrofitting CCS technology in order to 

 

58 The comments are available in the rulemaking docket. Docket 

ID: EPA-HQ-OAR-2011-0660.
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eliminate barriers to voluntary use of that technology. Several 

commenters expressed concern that a reconstruction could be 

essentially a new plant built on a few remaining parts of an old 

plant. The commenters expressed concern that such reconstructed 

sources would face a standard that is much less stringent than a 

newly constructed greenfield source. 

III. Proposed Requirements for Modified and Reconstructed 

Sources

A. Applicability Requirements 

We generally refer to fossil fuel-fired electric generating 

units that would be subject to an emission standard in this 

rulemaking as “affected” or “covered” sources, units, facilities 

or simply as EGUs. These sources meet both the definition of 

“affected” and “covered” EGUs subject to an emission standard as 

provided by this proposed rule, and the criteria for being 

considered “modified” and “reconstructed” sources as defined 

under the provisions of CAA section 111 and the EPA’s 

regulations. 

The EPA is proposing generally the samesimilar

applicability requirements, for purposes of this rule, that the 
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EPA proposed in the January 2014 proposal.59,60 This section 

describes those requirements. 

To be considered an EGU under Subpart Da currently defines 

an EGU as athe boiler or IGCC must bethat is: (1) “capable of 

combusting” more than 250 MMBtu/h heat input of fossil fuel,61

(2) “constructed for the purpose of supplying more than onethird of its potential net- electric output capacity ... to any 

utility power distribution system for sale”62 (that is, to the 

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

than 25 MW net-electric output” to the grid.63 In the January 

2014 proposal, we proposed to revise the third criterion to read 

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

 

59 See 79 FR at 1,445/2 –and 1,446/3. Note that the statements 

in the January 2014 Proposal that “existing sources undertaking 

modifications or reconstructions; or certain projects under 

development, including the proposed Wolverine EGU project in 

Rogers City, Michigan (and, perhaps, up to two others)” are not 

subject to that rulemaking, 79 FR at 1,446/3, are not relevant 

for purposes of the present rulemaking concerning modifications 

and reconstructions. 

60 In the January 2014 proposal, the EPA solicited comment on 

whether certain applicability requirements were appropriate in 

light of the fact that they assumed that the source had an 

operating history. In this rulemaking, the affected sources that 

would be undertaking modifications or reconstructions do have an 

operating history. As a result, to the extent the solicitation 

of comment in the January 2014 just described may be read to 

identify concerns about those applicability requirements, those 

concerns do not apply to this rulemaking. 

61 E.g., 40 CFR 60.40Da(a)(1). 62 40 CFR 60.41Da (definition of (“Electric utility steamgenerating unit”). 

63 Id. 
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output to the grid. This proposed change to 219,000 MWh net 

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

definition, and we have concluded that it is functionally 

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

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

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

MWh. In the January 2014 proposal we proposed to include two 

additional applicability criteria specific to applicability with 

the GHG standards: (1) that a facility actually sells more than 

1/3 of their potential electric output and more than 219,000 MWh 

to the grid on an annual basis for boilers and IGCC facilities 

and on a 3 year average for combustion turbines (2) that the GHG 

standards are not applicable to facilities that combust 10 

percent or less fossil fuel on a 3 year average. In this 

proposal we are not proposing that any of these additional 

applicability criteria apply for modified or reconstructed 

boilers or IGCC facilities. Therefore, any modified or 

reconstructed boiler or IGCC facility that meets the general 

applicability of subpart Da would also be subject to the GHG 

requirements. For stationary combustion turbines we are 

proposing to maintain all of these criteria, along with the 

additional criteria specific to stationary combustion turbines, 

included in the January 2014 proposal, that only stationary 
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combustion turbines that combust over 90 percent on a 3 year 

rolling average basis are subject to a numerical GHG standard.

Because a modified or reconstructed source will have an 

operating history, unlike a new source, we are proposing to 

define an EGU slightly differently for purposes of this rule. We 

are proposing to include criteria that must be met in addition 

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

criterion. 

First, because the source will have an operating history 

reflecting its additional sales to the grid, we are adding a new 

criterion that a unit actually “supplies more than one-third of 

its potential electric output” to the grid. Combined with the 

three-year rolling average methodology to determine if the onethird criteria is met (as explained further below), this 

approach makes it clear that a unit that was not originally 

constructed to supply more than one-third of its potential 

electric output to the grid but does so for one year does not 

automatically become affected. Both criteria would also be used 

in subparts KKKK and TTTT. 

Second, we are proposing to revise the third criterion to 

read “constructed for the purpose of supplying “more than 

219,000 MWh,” as opposed to “constructed for the purpose of 

supplying 25 MW,” net-electrical output to the grid. This 

Comment [A22]: The exclusion of all 

combustion turbines selling less than 1/3 of their 

potential generation will essentially exclude all 

peakers. (See pp. 57-58 as well as comment on p. 

61.) What if, however, a CT in that category decides 

to upgrade and then, after modification, begins to 

sell, say 50 or 60% to the grid, i.e. operate as 

intermediate load? Would that unit be regulated as a 

new source? 

EPA: The applicability discussion has been edited. 

We are requesting comment on if “constructed for 

the purposes” should be based on allowable hours 

under the applicable permit and the ability to sell to 

the grid. Under this interpretation, a simple cycle CT 

would become subject to an emission standard once 

it sold 1/3 of its potential electric output and 219,000 

MWh on a 3 year average 
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proposed change to 219,000 MWh net sales is consistent with the 

EPA Acid Rain Program (ARP) definition and in the January 8, 

2014 proposal, and we have concluded that it is functionally 

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

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

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

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

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

average for stationary combustion turbines. 

Finally, we are proposing to add a new applicability 

criterion that is not currently in subpart Da: EGUs, for which 

10 percent or less of the heat input over a three-year period is 

derived from a fossil fuel, are not subject to any of the 

proposed CO2 standards. 

Consistent with the January 2014 proposal, Wwe are 

proposing several additional adjustments to the way 

applicability is currently determined under subpart Da for 

purposes of modifications and reconstructions. First, we are 

proposing that the definition of “potential electric output” be 

revised to include “or the design net electric output 

efficiency” as an alternative to the default one-third 

efficiency value (i.e., the proposed definition is “33 percent 

or the design net electric output efficiency times the maximum 

design heat input capacity of the steam generating unit, divided 

Comment [A23]: Is EPA soliciting comment on 

this same applicability definition for new 111(b) 

units? 

EPA: : The revised text clarifies that this was 

included in the January 2014 proposal. 

Comment [A24]: Is EPA soliciting comment on 

this same applicability definition for new 111(b) 

units? 

What type of units is EPA trying to exclude? 

EPA: The revised text clarifies that this was 

included in the January 2014 proposal. The intent is 

to exempt facilities from an CO2 emission standard 

that are “capable” of burning fossil fuel but that burn 

non-fossil fuels. Examples include wood-fired EGUs 

with natural gas burners and combustion turbines 

burning non-fossil fuels but that use natural gas as a 

backup fuel. 
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by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 

8,760 h/yr (e.g., a 35 percent efficient steam generating unit 

with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity 

would have a 310,000 MWh 12 month potential electrical output 

capacity”)” (emphasis added)). Next, we are proposing to add “of 

the thermal host facility or facilities” to the definition of 

“net-electric output” (i.e., the proposed definition would read 

“... the gross electric sales to the utility power distribution 

system minus purchased power of the thermal host facility or 

facilities on a calendar year basis” (emphasis added). 

Finally, consistent with the January 2014 proposal, to 

avoid circumvention of the intent of the emission standards 

(e.g., by having auxiliary equipment provide steam to the EGU to 

increase the output of the EGU and not including the CO2

emissions in determining the emission rate) and to provide 

additional flexibility to the regulated community by 

providingthrough additional compliance options, we are proposing 

to amend the definition of a steam generating unit to include 

“plus any integrated equipment that provides electricity or 

useful thermal output to either the affected facility or 

auxiliary equipment” instead in place of the existing language 

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

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

device used for combusting fuel for the purpose of producing 

Comment [A25]: Would this apply for new units 

under 111(b) too? EPA should clarify. 

EPA: The revised text clarifies that this was 

included in the January 2014 proposal. 
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steam (nuclear steam generators are not included) plus any 

integrated equipment that provides electricity or useful thermal 

output to either the affected facility or auxiliary equipment” 

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

language to the definition of IGCC in subpart Da (or subpart 

TTTT) and stationary combustion turbine in subpart KKKK (or 

subpart TTTT). 

Although we identify the pollutant we propose to regulate 

as GHG, tThis action proposes to regulate set standards only for 

emissions of CO2. The pollutant we propose to regulate could also 

be identified as a broader suite of GHGs. However,and we are not 

proposing to regulate set standards for any other GHGs, (such as 

methane (CH4) or nitrous oxide (N2O)), because they represent 

less than 1 percent of total estimated GHG emissions from fossil 

fuel-fired electric power generating units. This is consistent 

with the approach that was taken in the proposed standards for 

newly constructed EGUs (79 FR 1430, January 8, 2014). 

We are also not proposing standards for certain types of 

sources. These include modified and reconstructed utility 

boilers and IGCC units that were constructed for the purpose of 

selling one-third or less of their potential output and 219,000 

MWh or less to the grid. These units are not covered under 

Subpart Da for any other pollutants but are rather covered as 

industrial units boilers under Subpart Db or stationary 

Comment [A26]: May want to reword to make 

this less confusing. How can the action propose to 

regulate only CO2 but also “identify the pollutant we 

propose to regulate” as a broader suite of GHGs? 

EPA: The text has been edited to make less 

confusing. 

Comment [A27]: These two sentences together 

imply that modified and reconstructed utility boilers 

and IGCC units are exempt if they sell less than 1/3 

of their potential output to the grid. It appears from 

the “Amended Regulatory Text” TSD, page 43, that 

this is not in fact the intention of this rule. Please 

clarify what the intent is, both here and in any other 

applicable portions of this text. 

EPA: The text has been clarified. The amended 

regulatory text TSD is intended to show the broadest 

applicability the EPA soliciting comment on. The 

TSD will be edits to clarify what the EPA is actually 

proposing and soliciting comment on.
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combustion turbines under subpart KKKK. We are also not 

proposing standards for two types of units that are currently 

covered under Subpart KKKK for other pollutants at this time. 

The first is stationary combustion turbines that were 

constructed for the purpose of selling or are sellingsell onethird or less of their potential output or 219,000 MWh or less 

to the grid. These units only account for a small amount of the 

CO2 emissions from fossil-fuel-fired EGUs. The second is modified 

or reconstructed non-natural gas-fired stationary combustion 

turbines.64 Under the proposed approach, applicability with the 

NSPS for stationary combustion turbines could change on an 

annual basis depending on electric sales and for facilities 

burning fuels other than natural gas (e.g., burning backup oil).

B. Emission Standards 

In this rulemaking, the EPA is proposing standards of 

performance for CO2 emissions from modified and reconstructed 

EGUs within two categories and several subcategories of affected 

fossil fuel-fired EGUs. 

The proposed standards of performance for the utility 

boiler and IGCC category are in the form of net energy output-

 

64 Oil-fired stationary combustion turbines, including both 

simple and combined cycle units, are not subject to these 

proposed standards. These units are typically used only in areas 

that do not have reliable access to pipeline natural gas (for 

example, in non-continental areas). 

Comment [A28]: Please clarify applicability of 

1/3 utilization exemption to boilers and IGCC units. 

From the preamble, it is unclear whether modified 

and reconstructed utility boilers/IGCCs are exempt if 

they sell less than 1/3 of their potential output to the 

grid (see comments on p. 20 and p. 61). The 

preamble text on p. 61 implies that the 1/3 utilization 

exemption applies to boilers/IGCC units, whereas 

the “Amended Regulatory Text” memorandum (p. 

43) shows that this is not the case. Please reconcile. 

EPA: The preamble and reg text TSD both base 

applicability for boilers/IGCC on “constructed for 

the purpose” and not on actual sales.= 

Comment [A29]: Suggest clarification with 

regard to treatment of dual fuel units (e.g. in the 

northeast) which typically run on natural gas, unless 

supply/economics cause them to switch to oil. 

EPA: Additional text has been added.
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based CO2 emission limits expressed in units of mass of CO2 per 

unit of net energy output (e.g., net electrical output plus 75 

percent of the useful thermal output), specifically, in lb 

CO2/MWh-net. This emission limit would apply to affected sources 

upon the effective date of the final action. In this 

noticedocument, we sometimes refer to “net energy output” as 

“net output.” 

As explained earlier, the proposed standards of performance 

for natural gas-fired stationary combustion turbines are in the 

form of a gross output-based emission limit expressed in units 

of mass of CO2 per unit of gross energy output, specifically, in 

lb CO2/MWh-gross. We also solicit comment on whether we should 

use a net output-based approach. 

The proposed method to calculate compliance is the same as 

was proposed in the January 8, 2014 proposal. Compliance would 

be calculated as the sum of the emissions for all operating 

hours divided by the sum of the useful energy output over a 

rolling 12-operating-month period. As in the January 2014 

proposal, in the alternative, we solicit comment on requiring 

calculation of compliance on an annual (calendar year) period. 

See 79 FR at 1,477/1. 

1. Emission Standards for Modified Utility Boilers and IGCC 

Units 

The EPA is proposing that affected modified utility boilers 
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and IGCC units must meet a standard of performance based on the 

source’s best potential performance, achieved through a 

combination of best operating practices and equipment upgrades, 

as the BSER. The EPA is co-proposing two alternative standards 

of performance. In the first co-proposed alternative, modified 

sources would be required to meet a unit-specific numeric 

emission standard that is two percent lower than the unit’s best 

demonstrated annual performance during the years from 2002 to 

the year the modification occurs. 

Based on analysis of existing data, the EPA has determined 

that this standard can be met through a combination of best 

operating practices and equipment upgrades. In an analysis to 

determine opportunities for heat rate improvement in the U.S. 

coal-fired utility power fleet, the EPA found that a total of 6 

percent improvement, on average, can be achieved through two 

types of measures: through best operating practices that have 

the potential to improve heat rate, on average, by 4 percent, 

and equipment upgrades that have the potential to improve heat 

rate, on average, by an additional 2 percent.65 The EPA also 

proposes that the unit-specific emission rates that would apply 

to affected modified utility boilers and IGCC units would be no 

 

65 Additional detail can be found in the Technical Support 

Document: “GHG Abatement Measures” (Chapter 2: Heat Rate 

Improvement at Existing Coal-fired EGUs), available in the 

rulemaking docket. 
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more stringent (i.e., no lower) than 1,900 lb CO2/MWh-net for 

units with a heat input rating greater than 2,000 MMBtu/h, and 

no more stringent (i.e., no lower) than 2,100 lb CO2/MWh-net for 

units with a heat input rating of 2,000 MMBtu/h or less. These 

proposed constraints on the stringency of unit-specific emission 

rate standards are consistent with the emission rate standards 

proposed in today’s action for reconstructed utility boilers and 

IGCC units – based on the EPA’s review and analysis of the 

emissions from the best available generating technology. The EPA 

is soliciting comment on whether the most stringent standard for 

modified steam generating units should take into account the 

current steam cycle of the facility. For example, should large 

subcritical steam generating units have a most stringent 

standard that is less stringent (i.e., greater than) 1,900 lb 

CO2/MWh-net, which is based on the use of a supercritical steam 

cycle. 

As we discuss in the Legal Memorandum66, existing sources 

that are subject to requirements under an approved CAA section 

111(d) plan would remain subject to those requirements after 

undertaking a modification or reconstruction. Therefore, we are 

co-proposing a second alternative - that modified sources would 

be required to meet a unit-specific numeric emission standard 

 

66 Add cite to legal memoLegal Memorandum available in rulemaking 

docket ID: EPA-HQ-OAR-2013-0602.
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that would be dependent on the timing of the modification 

relative to the adoption of a 111(d) plan that covers the 

source. Specifically, the EPA proposes that sources that modify 

prior to becoming subject to a CAA section 111(d) plan would be 

required to meet the same standard described in the first coproposed alternative – that is, the modified source would be 

required to meet a unit-specific emission limit determined by 

the affected source’s best demonstrated historical performance 

(in the years from 2002 to the time of the modification) with an 

additional two percent emission reduction. Sources that modify 

after becoming subject to a CAA section 111(d) plan would be 

required to meet a unit-specific emission limit that would be 

determined by the 111(b) permitting implementing authority and 

would be based on the source’s expected performance after 

implementation of identified unit-specific energy efficiency 

improvement opportunities. We seek comment on this proposal that 

the 111(b) implementing authority would determine the unitspecific emission limit, even when the implementing authority is 

a state, as opposed to the EPA.

In addition, we solicit comment on alternative ways to 

determine the best potential performance at affected modified 

utility boilers and IGCC units. Specifically, we are requesting 

comment on whether the unit-specific numerical emission standard 

should be based on the single best annual emission rate (for the 
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years 2002 to the year when the modification occurs) or the best 

three consecutive year average emission rate. We also solicit 

comment on whether there are circumstances where it would not be 

appropriate to require that the best historical emission rate be 

made two percent more stringent, or where some other increment 

of additional stringency should be required. 

The EPA also seeks comment on including an additional 

compliance option for modified utility boilers and IGCC units. 

Specifically, we seek comment on including uniform emission 

standards that are similar to the standards proposed for 

reconstructed utility boilers and IGCC units. Specifically, we 

seek comment on a standard of 1,900 lb CO2/MWh-net for modified 

supercritical sources with a heat input rating of greater than 

2,000 MMBtu/h and a standard of 2,100 lb CO2/MWh-net for all 

modified subcritical sources and for modified supercritical 

sources with a heat input rating of 2,000 MMBtu/h or less. The 

EPA further seeks comment on whether this option should be 

available only to sources that modify before becoming subject to 

an approved CAA 111(d) plan or to all modified boilers and IGCC 

units, regardless of the timing of the modification. 

The EPA further solicits comment on whether, in the case of 

modified utility boilers and IGCC units subject to a CAA section 

111(d) plan, there are any circumstances in which the emission 

limit should be calculated by not including the 2 percent 
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additional emission reduction based on equipment upgrades. This 

may, for example, be appropriate in cases where the state plan 

requires heat rate improvements which improve on the source’s 

historical performance, or where the source has recently 

implemented aggressive measures to improve its operating 

efficiency, and as a result, the additional two percent 

improvement may be unnecessary or not reasonable. 

The EPA also solicits comment on requiring modified utility 

boilers and IGCC units subject to a CAA section 111(d) plan to 

take, as their unit-specific emission rate, the lower of (1) the 

emission rate they are subject to under the section 111(d) plan, 

or (2) the emission rate that is two percent less than the 

unit’s best demonstrated annual performance during the years 

from 2002 to the year the modification occurs. The EPA further 

seeks comment on whether the time period of the unit’s best 

demonstrated performance should be limited to the years from 

2002 to the time that the unit becomes subject to a CAA 111(d) 

plan – rather than to the date that the modification occurs. The 

EPA also seeks comment on whether the time period for best 

historic performance should be from 2002 to the date of 

modification – unless the source can provide evidence of 

significant heat rate improvements that have already been 

implemented in which case the time period would be from the year 

of the first heat rate improvement to the modification. 
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The EPA also seeks comment on whether, and under what 

circumstances, a modified utility boiler or IGCC unit that 

modifies prior to becoming subject to a CAA section 111(d) plan 

should also be allowed to meet a emission limit that is 

determined from the results of an energy assessment or audit. 

The EPA also requests comment on whether this approach should be 

limited to sources that may have voluntarily, or for any other 

reason, implemented energy efficiency measures in the time 

period between 2002 and the date of the modification and whether 

those sources should be required to provide evidence of those 

energy efficiency improvements. 

The EPA also solicits comment on whether we should – as we 

have proposed in this action - have different standards of 

performance for modified utility boilers and IGCC units 

depending on whether a CAA section 111(d) state plan has been 

submitted (or a federal plan promulgated) or not. On the one 

hand, a section 111(d) plan may not necessarily impose 

obligations on a particular unit. On the other hand, such a plan 

may impose significant obligations on a particular source, and 

if that source modifies, it may not be as well positioned to 

implement additional controls. Even so, a state, in developing a 

111(d) plan, may choose to confer with its sources to determine 

whether any expect to modify, and, if any do, take that into 

account in developing the state plan. 
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2. Emission Standards for Modified Natural Gas-fired Stationary 

Combustion Turbines 

For affected modified natural gas-fired stationary 

combustion turbines, this action proposes standards of 

performance that are based on efficient NGCC technology as the 

best system of emission reduction (BSER). The emission limits 

proposed for these sources are 1,000 lb CO2/MWh-gross for 

facilities with heat input ratings greater than 850 MMBtu/h, and 

1,100 lb CO2/MWh-gross for facilities with heat input ratings of 

850 MMBtu/h or less.67 

In the companion rulemaking proposing emission guidelines 

under CAA section 111(d) for CO2 emissions from existing affected 

EGUs, the EPA is proposing that an existing source that becomes 

subject to requirements under section 111(d) will continue to be 

subject to those requirements even after it undertakes a 

modification or reconstruction. This is also discussed in 

greater detail in the ‘Legal Memorandum68’. Under this 

interpretation, a modified or reconstructed source would be 

subject to both (1) the section 111(d) requirements that it had 

previously been subject to and (2) the modified source or 

 

67 This subcategorization of stationary combustion turbines is 

consistent with the subcategories used in the combustion turbine 

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

MMBtu/h corresponds to approximately 100 MWe.

68 Add cite to legal memo 
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reconstructed source standard under 111(b) proposed in this 

rulemaking. 

The EPA also solicits comment on an optional alternative 

method for calculating the emission limit that would be 

applicable to an affected modified natural gas-fired stationary 

combustion turbine after that unit becomes subject to a CAA 

section 111(d) plan. The EPA specifically seeks comment on the 

option of allowing the affected source to meet a unit-specific 

emission limit that is determined by the 111(b) permitting 

implementing authority from an assessment to identify energy 

efficiency improvement opportunities for the affected source. 

3. Emission Standard for Reconstructed EGUs 

Reconstructed fossil fuel-fired boilers and IGCC units with 

a heat input rating that is greater than 2,000 MMBtu/h would be 

required to meet a standard of 1,900 lb CO2/MWh-net. 

Reconstructed fossil fuel-fired utility boilers and IGCC units 

with a heat input rating that is 2,000 MMBtu/h or less would be 

required to meet a standard of 2,100 lb CO2/MWh-net. 

Reconstructed natural gas-fired stationary combustion 

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

be required to meet a standard of 1,000 lb CO2/MWh-gross. 

Reconstructed combustion turbines with a heat input rating or 

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

1,100 lb CO2/MWh-gross. 
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While the EPA is proposing these standards of performance, 

we are also taking comment on a range of potential emission 

limits. Specifically, we solicit comment on the following 

emission limit ranges: 

(1) for reconstructed fossil fuel-fired boilers and IGCC 

units with a heat input rating that is greater than 

2,000 MMBtu/h, a range of 1,700 – 2,100 lb CO2/MWh-net; 

(2) for reconstructed fossil fuel-fired boilers and IGCC 

units with a heat input rating of 2,000 MMBtu/h or less, 

a range of 1,900 – 2,300 lb CO2/MWh-net; 

(3) for reconstructed stationary combustion turbines with a 

heat input rating greater than 850 MMBtu/h, a range of 

950 – 1,100 lb CO2/MWh-gross; and 

(4) for reconstructed stationary combustion turbines with a 

heat input rating of 850 MMBtu/h or less, a range of 

1,000 – 1,200 lb CO2/MWh-gross; 

We also solicit comment on whether: (1) the standards for 

utility boilers and IGCC units should be subcategorized by 

primary fuel type, (2) the small utility boiler and IGCC unit 

subcategory should be limited to utility boilers so that all 

IGCC units would be in the large subcategory regardless of size, 

or if there are sufficient alternate compliance technologies 

(e.g., co-firing natural gas) that the small unit subcategory is 

unnecessary and should be eliminated so that those sources would 
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be required to meet the same emission standard as large utility 

boilers and IGCC units, and (3) an annual short term 

performance test should be required for stationary combustion 

turbines in addition to the 12-operating-month rolling average 

standard. Requiring an initial and annual short term compliance 

test that is numerically more stringent than the 12-operating 

month standard for modified and reconstructed stationary 

combustion turbines would insure that efficient stationary 

combustion turbines are installed and properly maintained. The 

less stringent 12-month rolling average standard would be set at 

a level that would account for operating conditions where the 

emission rate is higher than design conditions. 

3. Net Output 

We are proposing standards for modified and reconstructed 

units as net output emission rates. We are also requesting 

comment on using either gross output standards or adjusted gross 

output based standards in the final rule. See the TSD for more 

details.69 

C. Startup, Shutdown and Malfunction Requirements 

 

69 In the January 8, 2014 proposal for new sources, we proposed 

standards as gross output emission rates, See 79 FR 1,447/1 -and

1,448/3. In the rulemaking for existing sources that we are 

proposing concurrently with this rulemaking, we are proposing 

emission guidelines that call for state standards as net output 

emission rates (but seek comment on gross output-based emission 

rates).
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Consistent with the January 8, 2014, proposal, wWe are 

proposing the standards in this rule apply at all times, 

including during periods of startup and shutdown. We are also 

proposing malfunction and affirmative defense provisions 

consistent with the January 8, 2014, proposal. This section 

provides a summary of the requirements. For additional detail, 

see 79 FR 1430 (January 8, 2014) at 1,448/3 – 1,450/2 and the 

TSD.

1. Startups and shutdowns 

Consistent with Sierra Club v. EPA,70 the EPA is proposing 

standards in this rule that apply at all times, including during 

startups and shutdowns. In proposing the standards in this rule, 

the EPA has taken into account startup and shutdown periods. In 

the compliance calculation, periods of startup and shutdown are 

included as periods of partial load. The proposed method to 

calculate compliance is to sum the emissions for all operating 

hours and to divide that value by the sum of the electrical 

energy output and useful thermal energy output, where applicable 

for CHP EGUs, over a rolling 12-operating-month period. The EPA 

is proposing that sources incorporate in their compliance 

determinations emissions from all periods, including startup or 

shutdown, that fuel is combusted and emissions monitors are not 

 

70 551 F.3d 1019 (D.C. Cir. 2008). 

Comment [A30]: Given the recent court decision 

that struck down affirmative defense, what does EPA 

plan to do here? 

EPA Response: Text has been edited. 
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out-of-control, as well as all power produced over the periods 

of emissions measurements. Given that the duration of startup or 

shutdown periods are expected to be small relative to the 

duration of periods of normal operation and that the fraction of 

power generated during periods of startup or shutdown is 

expected to be very small during startup or shutdown periods, 

the impact of these periods on the total average is expected to 

be minimal. 

2. Malfunctions 

Note: A court decision this morning related to the Portland 

Cement MACT may impact the way the agency addresses affirmative 

defense. Once we have determined how the ruling impacts our 

general affirmative defense policy, we will modify the preamble 

accordingly.

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as “any sudden, 

infrequent, and not reasonably preventable failure of air 

pollution control equipment, process equipment, or a process to 

operate in a normal or usual manner. Failures that are caused in 

part by poor maintenance or careless operation are not 

malfunctions.” (40 CFR 60.2). The EPA has determined that 

section 111 does not require that emissions that occur during 

periods of malfunction be factored into development of CAA 

section 111 standards. Nothing in CAA section 111 or in case law 
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requires that the EPA anticipate and account for the innumerable 

types of potential malfunction events in setting emission 

standards. CAA section 111 provides that the EPA set standards 

of performance which reflect the degree of emission limitation 

achievable through “the application of the best system of 

emission reduction” that the EPA determines is adequately 

demonstrated. A malfunction is a failure of the source to 

perform in a “normal or usual manner” and no statutory language 

compels EPA to consider such events in setting standards based 

on the “best system of emission reduction.” 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 in setting emission 

standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category and given the difficulties associated 

with predicting or accounting for the frequency, degree, and 

duration of various malfunctions that might occur. As such, the 

performance of units that are malfunctioning is not “reasonably” 

foreseeable. See, e.g., Sierra Club v. EPA, 167 F.3d 658, 662 

(D.C. Cir. 1999) (“The EPA typically has wide latitude in 

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency's decision to proceed 
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on the basis of imperfect scientific information, rather than to 

'invest the resources to conduct the perfect study.'") See also, 

Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“ 

In the nature of things, no general limit, individual permit, or 

even any upset provision can anticipate all upset situations. 

After a certain point, the transgression of regulatory limits 

caused by ‘uncontrollable acts of third parties,’ such as 

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement discretion, 

not for specification in advance by regulation.”). In addition, 

emissions during a malfunction event can be significantly higher 

than emissions at any other time of source operation and thus 

accounting for malfunctions could lead to standards that are 

significantly less stringent than levels that are achieved by a 

well-performing non-malfunctioning source. It is reasonable to 

interpret section 111 to avoid such a result. 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, 
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including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. The 

EPA would also consider whether the source's failure to comply 

with the CAA section 111 standard was, in fact, “sudden, 

infrequent, not reasonably preventable” and was not instead 

“caused in part by poor maintenance or careless operation.” 40 

CFR § 60.2 (definition of malfunction). 

Further, to the extent the EPA files an enforcement action 

against a source for violation of an emission standard, the 

source can raise any and all defenses in that enforcement action 

and the federal district court will determine what, if any, 

relief is appropriate. The same is true for citizen enforcement 

actions. Similarly, the presiding officer in an administrative 

proceeding can consider any defense raised and determine whether 

administrative penalties are appropriate. 

In several prior rules, the EPA had included an affirmative 

defense to civil penalties for violations caused by malfunctions 

in an effort to create a system that incorporates some 

flexibility, recognizing that there is a tension, inherent in 

many types of air regulation, to ensure adequate compliance 

while simultaneously recognizing that despite the most diligent 

of efforts, emission standards may be violated under 

circumstances entirely beyond the control of the source. 

Although the EPA recognized that its case-by-case enforcement 
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discretion provides sufficient flexibility in these 

circumstances, it included the affirmative defense to provide a 

more formalized approach and more regulatory clarity. See 

Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 

1978) (holding that an informal case-by-case enforcement 

discretion approach is adequate); but see Marathon Oil Co. v. 

EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more 

formalized approach to consideration of “upsets beyond the 

control of the permit holder.”). Under the EPA’s regulatory 

affirmative defense provisions, if a source could demonstrate in 

a judicial or administrative proceeding that it had met the 

requirements of the affirmative defense in the regulation, civil 

penalties would not be assessed. Recently, the United States 

Court of Appeals for the District of Columbia Circuit vacated 

such an affirmative defense in one of the EPA’s Section 112(d) 

regulations. NRDC v. EPA, No. 10-1371 (D.C. Cir. April 18, 2014) 

2014 U.S. App. LEXIS 7281 (vacating affirmative defense 

provisions in Section 112(d) rule establishing emission 

standards for Portland cement kilns). The court found that the 

EPA lacked authority to establish an affirmative defense for 

private civil suits and held that under the CAA, the authority 

to determine civil penalty amounts lies exclusively with the 

courts, not the EPA. Specifically, the Court found: “As the 

language of the statute makes clear, the courts determine, on a 
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case-by-case basis, whether civil penalties are ‘appropriate.’” 

See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (“[U]nder this 

statute, deciding whether penalties are ‘appropriate’ in a given 

private civil suit is a job for the courts, not EPA.”).71 In 

light of NRDC, the EPA is not including a regulatory affirmative 

defense provision in this rulemaking. As explained above, if a 

source is unable to comply with emissions standards as a result 

of a malfunction, the EPA may use its case-by-case enforcement 

discretion to provide flexibility, as appropriate. Further, as 

the D.C. Circuit recognized, in an EPA or citizen enforcement 

action, the court has the discretion to consider any defense 

raised and determine whether penalties are appropriate. Cf. 

NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments that 

violation were caused by unavoidable technology failure can be 

made to the courts in future civil cases when the issue arises). 

The same logic applies to EPA administrative enforcement 

actions. 

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as “any sudden, 

 

71 The court’s reasoning in NRDC focuses on civil judicial 

actions. The Court noted that “EPA's ability to determine 

whether penalties should be assessed for Clean Air Act 

violations extends only to administrative penalties, not to 

civil penalties imposed by a court.” Id.
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infrequent, and not reasonably preventable failure of air 

pollution control equipment, process equipment, or a process to 

operate in a normal or usual manner. Failures that are caused in 

part by poor maintenance or careless operation are not 

malfunctions.” (40 CFR 60.2). The EPA has determined that 

section 111 does not require that emissions that occur during 

periods of malfunction be factored into development of CAA 

section 111 standards. Nothing in CAA section 111 or in case law 

requires that the EPA anticipate and account for the innumerable 

types of potential malfunction events in setting emission 

standards. CAA section 111 provides that the EPA set standards 

of performance which reflect the degree of emission limitation 

achievable through “the application of the best system of 

emission reduction” that the EPA determines is adequately 

demonstrated. Applying the concept of “the application of the 

best system of emission reduction” to periods during which a 

source is malfunctioning presents difficulties. The “application 

of the best system of emission reduction” is more appropriately 

understood to include operating units in such a way as to avoid 

malfunctions. 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 
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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 a violation of an emission 

standard. The EPA is therefore proposing to add an affirmative 

defense to civil penalties for violations of emission standards 

in this rule 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 proposed criteria are designed in part to ensure 
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that the affirmative defense is available only where the event 

that causes a violation of the emission standard meets the 

narrow definition of malfunction in 40 CFR 60.2. The proposed 

criteria also are designed to ensure that steps are taken to 

correct the malfunction, to minimize emissions and to prevent 

future malfunctions. In any judicial or administrative 

proceeding, the Administrator may challenge the assertion of the 

affirmative defense and, if the respondent has not met its 

burden of proving all of the requirements in the affirmative 

defense, appropriate penalties may be assessed in accordance 

with section 113 of the CAA (see also 40 CFR 22.27).

D. Continuous Monitoring Requirements 

We are proposing the same monitoring requirements for 

modified and reconstructed sources as were proposed for new 

sources in the January 8, 2014, proposal. This section provides 

a summary of the requirements. For additional detail, see 79 FR 

at 1,450/2 and– 1,451/2 and the TSD. 

Today’s proposed rule would require owners or operators of 

EGUs that combust solid fuel to install, certify, maintain, and 

operate continuous emission monitoring systems (CEMS) to measure 

CO2 concentration, stack gas flow rate, and (if needed) stack gas 

moisture content in accordance with 40 CFR pPart 75, in order to 

determine hourly CO2 mass emissions rates (tons/h). 
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The proposed rule would allow owners or operators of EGUs 

that burn exclusively gaseous or liquid fuels to install fuel 

flow meters as an alternative to CEMS and to calculate the 

hourly CO2 mass emissions rates using Equation G-4 in Appendix G 

of Part 75. To implement this option, hourly measurements of 

fuel flow rate and periodic determinations of the gross 

calorific value (GCV) of the fuel are also required, in 

accordance with Appendix D of Part 75. 

In addition to requiring monitoring of the CO2 mass emission 

rate, the proposed rule would require EGU owners or operators to 

monitor the hourly unit operating time and “gross output”, 

expressed in megawatt hours (MWh). The gross output includes 

electrical output plus any mechanical output, plus 75 percent of 

any useful thermal output. 

The proposed rule would require EGU owners or operators to 

prepare and submit a monitoring plan that includes both 

electronic and hard copy components, in accordance with 40 CFR 

parts §§ 75.53(g) and (h). Further, all monitoring systems used 

to determine the CO2 mass emission rates would have to be 

certified according to § 75.20 and section 6 of Part 75, 

Appendix A within the 180-day window of time allotted under § 

75.4(b), and would be required to meet the applicable on-going 

quality assurance procedures in Appendices B and D of Part 75. 
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The proposed rule would require only those operating hours 

in which valid data are collected and recorded for all of the 

parameters in the CO2 mass emission rate equation to be used for 

compliance purposes. Additionally for EGUs using CO2 CEMS, only 

unadjusted stack gas flow rate values would be used in the 

emissions calculations. In this proposal, Part 75 bias 

adjustment factors (BAFs) would not be applied to the flow rate 

data. These restrictions on the use of Part 75 data for Part 60 

compliance are consistent with previous NSPS regulations and 

revisions. 

 Certain variations from and additions to the basic Part 75 

monitoring would be required and are detailed in the January 8, 

2014, proposal (see 79 FR at 1,451/1). 

Special compliance provisions for units with common stack 

or multiple stack configurations, consistent with § 60.13(g), 

would be required and are detailed in the January 8, 2014,

proposal (see 79 FR at 1,451/1 - 1,451/2). 

The proposed rule would require 95 percent of the operating 

hours in each compliance period (including the compliance 

periods for the intermediate emission limits) to be valid hours, 

i.e., operating hours in which quality-assured data are 

collected and recorded for all of the parameters used to 

calculate CO2 mass emissions. EGU owners or operators would have 

the option to use backup monitoring systems, as provided in §§ 
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75.10(e) and 75.20(d), to help meet this proposed data capture 

requirement. 

E. Emissions Performance Testing Requirements 

We are proposing the same emissions performance testing 

requirements for modified and reconstructed sources as were 

proposed for new sources in the January 8, 2014, proposal. This 

section provides a summary of the requirements. For additional 

detail, see 79 FR at 1,451/2 – 1,451/3 and the TSD. 

In accordance with § 75.64(a), the proposed rule would 

require an EGU owner or operator to begin reporting emissions 

data when monitoring system certification is completed or when 

the 180-day window in § 75.4(b) allotted for initial 

certification of the monitoring systems expires (whichever date 

is earlier). The initial performance test would consist of the 

first 12-operating-months of data, starting with the month in 

which emissions are first required to be reported. The initial 

12-operating-month compliance period would begin with the first 

month of the first calendar year of EGU operation in which the 

facility exceeds the capacity factor applicability threshold. 

The traditional 3-run performance tests (i.e., stack tests) 

described in § 60.8 would not be required for this rule. 

Following the initial compliance determination, the emission 

standard would be met on a 12-operating-month rolling average 

basis. 
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F. Continuous Compliance Requirements 

We are proposing the same continuous compliance 

requirements for modified and reconstructed sources as were 

proposed for new sources in the January 8, 2014, proposal. This 

section provides a summary of the requirements. For additional 

detail, see 79 FR at 1,451/3 and the TSD. 

Today’s proposed rule specifies that compliance with the 

mass emissions rate limits would be determined on a 12-

operating-month rolling average basis, updated after each new 

operating month. For each 12-operating-month compliance period, 

quality-assured data from the certified Part 75 monitoring 

systems would be used together with the gross output over that 

period of time to calculate the average CO2 mass emissions rate. 

The proposed rule specifies that the first operating month 

included in the initial 12-operating-month compliance period 

would be the month in which reporting of emissions data is 

required to begin under § 75.64(a), i.e., either the month in 

which monitoring system certification is completed or the month 

in which the 180-day window allotted to finish certification 

testing expires (whichever month is earlier). 

We are proposing that initial compliance with the 

applicable emissions limit in kg/MWh be calculated by dividing 

the sum of the hourly CO2 mass emissions values by the total 

gross output for the 12-operating-month period. Affected EGUs 
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would continue to be subject to the standards and maintenance 

requirements in the section 111 regulatory general provisions 

contained in 40 CFR part 60, subpart A. 

G. Notification, Recordkeeping and Reporting Requirements 

We are proposing the same notification, recordkeeping and 

reporting requirements for modified and reconstructed sources as 

that were proposed for new sources in the January 8, 2014,

proposal. This section provides a summary of the requirements. 

For additional detail, see 79 FR at 1,451/3 –and 1,452/3 and the 

TSD. 

Today’s proposed rule would require an EGU owner or 

operator to comply with the applicable notification requirements 

in § 75.61, §§ 60.7(a)(1) and (a)(3), and § 60.19 and § 75.61. 

The proposed rule would also require the applicable 

recordkeeping requirements in subpart F of Part 75 to be met. 

For EGUs using CEMS, the data elements that would be recorded 

include, among others, hourly CO2 concentration, stack gas flow 

rate, stack gas moisture content (if needed), unit operating 

time, and gross electric generation. For EGUs that exclusively 

combust liquid and/or gaseous fuel(s) and elect to determine CO2

emissions using Equation G-4 in Appendix G of Part 75, the key 

data elements in subpart F that would be recorded include hourly 

fuel flow rates, fuel usage times, fuel GCV, gross electric 

generation. 
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The proposed rule would require EGU owners or operators to 

keep records of the calculations performed to determine the 

total CO2 mass emissions and gross output for each operating 

month. Records would be kept of the calculations performed to 

determine the average CO2 mass emission rate (kg/MWh) and the 

percentage of valid CO2 mass emission rates in each compliance 

period. The proposed rule would also require records to be kept 

of calculations performed to determine site-specific carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G 

(if applicable). 

The proposed rule would require all affected EGU 

owners/operators to submit quarterly electronic emissions 

reports in accordance with subpart G of Part 75. The proposed 

rule would require these reports to be submitted using the ECMPS 

Client Tool. Except for a few EGUs that may be exempt from the 

Acid Rain Program (e.g., oil-fired units), this is not a new 

reporting requirement. Sources subject to the Acid Rain Program 

are already required to report the hourly CO2 mass emission rates 

that are needed to assess compliance with today’s rule. 

Additionally, in the proposed rule and as part of an 

Agency-wide effort to streamline and facilitate the reporting of 

environmental data, the rule would require that quarterly 

electronic “excess emissions” reports be submitted using ECMPS, 

within 30 days after the end of each quarter. Reporting the 
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percentage of valid CO2 mass emission rates is necessary to 

demonstrate compliance with the requirement to obtain valid data 

for 95 percent of the operating hours in each compliance period. 

Any excess emissions that occur during the quarter would be 

identified.

For EGU owners or operators that would assert an 

affirmative defense for a failure to meet a standard due to 

malfunction, the owner or operator must follow the reporting 

requirements for affirmative defense. The report to the 

Administrator, with all necessary supporting documentation, must 

be submitted on the same schedule as the next quarterly report 

required after the initial occurrence of the violation of the 

relevant standard (which may be the end of any applicable 

averaging period).

IV. Rationale for Reliance on Rational Basis to Regulate GHG 

from Fossil fFuel-fired EGUs 

A. Rational Basis and Endangerment Finding 

In the January 2014 proposal, the EPA proposed that, in 

order to regulate GHG from new fossil fuel-fired EGUs, the EPA 

needed a rational basis, but that CAA section 111 did not 

require an endangerment finding. The EPA further proposed that 

even if section 111 did require such a finding, the EPA’s 

rational basis would qualify as one. The EPA expects to finalize 

the January 2014 proposal by the time that it finalizes this 
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proposed rulemaking for affected modified and reconstructed 

fossil fuel-fired EGUs, and in that event, the EPA would not be 

required to further address the rational basis or endangerment 

finding in this rulemaking. 

However, because this rulemaking is a separate action from 

the January 2014 proposal, the EPA is making the same proposal – 

that the EPA has a rational basis for this rulemaking, and that 

no endangerment finding is required, but that if one is, the 

EPA’s rational basis would qualify as one – which it made in the 

January 2014 proposal. See 79 FR at 1,452/3 –through 1,456/1; 

see the TSD for more detail. 

B. Source Categories 

This proposal addresses the same two source categories – 

fossil fuel-fired steam generating units (utility boilers and 

IGCC units) and natural gas-fired stationary combustion turbines 

– that were addressed by the January 2014 proposal. In the 

January 2014 proposal, the EPA included a proposal and coproposal for the treatment of the two affected source 

categories, and for how the regulatory requirements applicable 

to these source categories would be codified in 40 CFR part 60. 

Specifically, the EPA proposed to create subcategories within 

each category, and to codify the regulatory requirements for 

each subcategory in 40 CFR part 60, subparts Da and KKKK, 

respectively. In addition, the EPA co-proposed to combine the 
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two categories for purposes of regulating the CO2 emissions, and 

to codify all the CO2 regulatory requirements in a new subpart, 

TTTT. 

As noted, the EPA expects to finalize the January 2014 

proposal by the time that it finalizes this proposed rulemaking 

for modified and reconstructed fossil fuel-fired EGUs. It is the 

EPA’s intent that the approach for categorization and 

codification will be the same in the final action for this 

proposal as is finalized for the January 2014 proposal. However, 

because this rulemaking is a separate action from the January 

2014 proposal, the EPA is making the same proposal and coproposal with regard to categories and codification for modified 

and reconstructed sources that it made with regard to new 

construction sources in the January 2014 proposal. That is, the 

EPA proposes to create subcategories within each category and to 

codify the regulatory requirements in 40 CFR part 60, subparts 

Da and KKKK, respectively; and in addition, the EPA co-proposes 

to combine the two categories for purposes of regulating CO2

emissions, and to codify all the CO2 regulatory requirements in a 

new subpart, TTTT. See 79 FR at 1,452/3 –through 1,454/1; See 

the TSD for more details. 

V. Rationale for Applicability Requirements 

The rationale for several of the proposed applicability 

requirements for modified and reconstructed sources is the same 
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as that in the January 2014 proposal. This section provides a 

summary of the rationale for these requirements along with 

rationale for differences with the applicability included in the 

January 2014 proposal. In addition, we are soliciting comment on 

multiple alternative approaches to the applicability criteria.In 

the January 2014 proposal, we also solicit comment on various 

issues concerning, and different approaches to, the 

applicability requirements for steam generating units and 

combustion turbines.72 For additional detail, see 79 FR at 1,459/1 

– 1,461/2 and the TSD. 

In today’s rulemaking, we propose that standards of 

performance apply to a facility if the facility supplies more 

than one-third of its potential electric output and more than 

219,000 MWh net electric output to the grid per year. (We refer 

to a facility’s sale of more than one-third of its potential 

electric output as the one-third sales criterion, and we refer 

to the amount of potential electric output supplied to a utility 

power distribution system, expressed in MWh, as the capacity 

factor.) This proposed definition does not explicitly exclude 

 

72 Requests for comment in the January 2014 proposal regarding 

the appropriateness of certain applicability requirements that 

are based on a source’s operations do not apply to this proposed 

rulemaking. Whereas newly constructed sources would not have a 

history of operating, in this rulemaking, the affected sources 

that would be undertaking modifications or reconstructions do 

have an operating history. 
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simple cycle combustion turbines, but as a practical matter, it 

would exclude most of them because the vast majority of simple 

cycle turbines sell less than one-third of their potential 

electric output. The few simple-cycle combustion turbines that 

sell more than one-third of their potential electric output to 

the grid would be subject to the proposed standards of 

performance. 

The following four proposed applicability criteria are 

consistent with the January 2014 proposal. First, Tthis proposal 

includes within the definition of a utility boiler, IGCC unit, 

and stationary combustion turbine that is subject to the 

proposed requirements, any integrated device that provides 

electricity or useful thermal output to the boiler, the 

stationary combustion turbine or to power auxiliary equipment. 

The rationale behind including integrated equipment recognizes 

that the integrated equipment may be a type of combustion unit 

that emits GHGs, and that it is important to assure that those 

GHG emissions are included as part of the overall GHG emissions 

from the affected source.

Second, Wwe are also proposing a different definition of 

potential electric output from the current definition that 

determines the potential electric output (in MWh on an annual 

basis) considering only the design heat input capacity of the 

facility and does not account for efficiency. It assumes a 33 
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percent net electric efficiency, regardless of the actual 

efficiency of the facility. Therefore, we are proposing a 

definition of potential electric output that allows the source 

the option of calculating its potential electric output on the 

basis of its actual design electric output efficiency on a net 

output basis, as an alternative to the default one-third value.

Third, Wwe are proposing to apply the one-third sales 

criterion on a rolling three year basis instead of an annual 

basis for stationary combustion turbines for multiple reasons. 

First, extending the period to three years would ensure that the 

CO2 standards apply only to intermediate and base load EGUs by 

allowing facilities intended to generally operate at low 

capacity factors (e.g. simple cycle turbines that generally sell 

less than one-third of their potential electric output) to avoid 

applicability. Second, only 0.2 percent of existing simple cycle 

turbines had a three-year average capacity factor of greater 

than one-third between 2000 and 2012. 

In today’s actionFinally, we propose that if CHP facilities 

meet the general applicability criteria they should be subject 

to the same requirements as electric-only generators. However, 

one potential issue that we have identified is inequitable 

applicability to third-party CHP developers compared to CHP 

facilities owned by the facility using the thermal output from 

the CHP facility. We are therefore proposing to add “of the 
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thermal host facility or facilities” to the definition of netelectric output for qualifying CHP facilities (i.e., the clause 

would read, “the gross electric sales to the utility power 

distribution system minus purchased power of the thermal host 

facility or facilities on a calendar year basis” (emphasis 

added)). This would make applicability consistent for both 

facility-owned CHP and third-party-owned CHP.

The rationale for following applicability criteria are 

different than the January 2014 proposal. To clarify that 

existing boiler and IGCC facilities would continue to be 

included in 111(d) state programs regardless of their actual 

electric sales or fossil fuel use, we are deleting the criteria 

that to be considered and EGU the facility must (1) actually 

sell 1/3 of their potential electric output and 219,000 MWh on 

an annual basis and (2) the applicability exemption for 

facilities than burn fossil fuel for 10 percent or less of the 

total heat input during a 3 year rolling average period. The 

sales criteria exemption was intended to exempt low capacity 

factor facilities since they would have additional difficulties 

meeting the standards proposed in the January 2014 proposal. 

However, the proposed standards for boilers and IGCC facilities 

in the rulemaking are less stringent and are achievable by low 

capacity factor facilities so the applicability exemption would 

not be applicable. The low fossil use exemption was designed to 
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exempt facilities that are capable of combusting fossil fuel, 

but burn primarily non fossil fuels. These facilities (e.g., 

wood-fired EGUs) typically are inherently less efficient than 

fossil fuel-fired EGUs, and we are soliciting comment on if we 

should subcategorize boilers and IGCC facilities that fossil 

fuel consists of 10 percent or less of the heat input during. In 

the event we establish a subcategory, should the heat input be 

determined on an annual or 3 year rolling period and should the 

standard be an alternate numerical limit or “no emission 

standard”. 

In the January 2014 proposal, we also solicit comment on 

various issues concerning, and different approaches to, the 

applicability requirements for steam generating units and 

combustion turbines.73 For additional detail, see 79 FR 1,459 

through 1,461. We are soliciting comment on additional 

approaches to address potential unintended negative 

environmental impacts and to address issues concerning how the 

general applicability of the 111(b) NSPS potentially impacts the 

111(d) rulemaking since only EGUs that would be included under 

 

73 Requests for comment in the January 2014 proposal regarding 

the appropriateness of certain applicability requirements that 

are based on a source’s operations do not apply to this proposed 

rulemaking. Whereas newly constructed sources would not have a 

history of operating, in this rulemaking, the affected sources 

that would be undertaking modifications or reconstructions do 

have an operating history. 
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the 111(b) applicability if they were new, modified or 

reconstructed are included in the state 111(d) goals. 

We are also proposing a different definition of potential 

electric output from the current definition that determines the 

potential electric output (in MWh on an annual basis) 

considering only the design heat input capacity of the facility 

and does not account for efficiency. It assumes a 33 percent net 

electric efficiency, regardless of the actual efficiency of the 

facility. Therefore, we are proposing a definition of potential 

electric output that allows the source the option of calculating 

its potential electric output on the basis of its actual design 

electric output efficiency on a net output basis, as an 

alternative to the default one-third value.

In addition, we are proposing to limit the applicability of 

the standards to facilities where the heat input is comprised of 

more than 10.0 percent fossil fuel on a three-year rolling 

average basis. Facilities that fall below this 10.0 percent 

threshold more closely resemble the non-fossil fuel-fired 

boilers and stationary combustion turbines that are not covered 

by today’s proposed rule, than they do the fossil fuel-fired 

boilers and stationary combustion turbines that are covered by 

this rule. We, therefore, have concluded that it is not 

appropriate to subject facilities that primarily burn non-fossil 

Comment [FC31]: Will be adding a discussion 

on how the electric sales criteria potentially 

influencing the choice for potential new generation 

and potential “leakage” in the 111(d) guidelines. 
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fuels, but also co-fire a limited amount of fossil fuel, to the 

standards in today’s proposal. 

In today’s action, we propose that if CHP facilities meet 

the general applicability criteria they should be subject to the 

same requirements as electric-only generators. However, one 

potential issue that we have identified is inequitable 

applicability to third-party CHP developers compared to CHP 

facilities owned by the facility using the thermal output from 

the CHP facility. We are therefore proposing to add “of the 

thermal host facility or facilities” to the definition of netelectric output for qualifying CHP facilities (i.e., the clause 

would read, “the gross electric sales to the utility power 

distribution system minus purchased power of the thermal host 

facility or facilities on a calendar year basis” (emphasis 

added)). This would make applicability consistent for both 

facility-owned CHP and third-party-owned CHP.

This proposal includes within the definition of a utility 

boiler, IGCC unit, and stationary combustion turbine that is 

subject to the proposed requirements, any integrated device that 

provides electricity or useful thermal output to the boiler, the 

stationary combustion turbine or to power auxiliary equipment. 

The rationale behind including integrated equipment recognizes 

that the integrated equipment may be a type of combustion unit 

that emits GHGs, and that it is important to assure that those 
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GHG emissions are included as part of the overall GHG emissions 

from the affected source.

VI. Rationale for Emission Standards for Reconstructed Fossil 

Fuel-Fired Utility Boilers and IGCC Units. 

A. Overview 

In this section, we explain our rationale for emission 

standards for reconstructed fossil fuel-fired utility boiler and 

IGCC units, which are based on our proposal that the most 

efficient generating technology is the BSER for these types of 

units. 

CAA section 111(b)(1)(B) authorizes the EPA to promulgate 

“standards of performance” for new sources, including modified 

and reconstructed sources. The CAA directs that standards of 

performance must consist of emission limits that are based on 

the “best system of emission reduction ... adequately 

demonstrated,” taking into account cost and other factors. In 

this manner, CAA section 111 provides that the EPA’s central 

task is to identify the BSER. 

Over a 40-year period, the U.S. Court of Appeals for the 

District of Columbia Circuit (D.C. Circuit or Court) has issued 

a number of decisions interpreting this CAA provision, including 
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its component elements.74 Consistent with this case law, the EPA 

determines the best demonstrated system based on the following 

key considerations, among others: 

 The system of emission reduction must be technically 

feasible. 

 The EPA must consider the amount of emissions reductions 

that the system would generate. 

 The costs of the system must be reasonable. The EPA may 

consider the costs on the source level, the industry-wide 

level, and, at least in the case of the power sector, on 

the national level in terms of the overall costs of 

electricity and the impact on the national economy over 

time.75 

 

74 Portland Cement Association’n v. Ruckelshaus, 486 F.2d 375 

(D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 

427, (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. 

Cir. 1981); Portland Cement Association’n v. EPA, 665 F.3d 177 

(D.C. Cir. 2011). 

75 As discussed in the January 2014 Proposal, the D.C. Circuit’s 

case law formulates the cost consideration in various ways: the 

costs must not be “exorbitant[]”, Essex Chemical Corp. v. 

Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), see Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999); 

“greater than the industry could bear and survive,” Portland 

Cement Ass’n Association v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975); or “excessive” or “unreasonable.” Sierra Club v. Costle, 

657 F.2d 298, 343 (D.C. Cir. 1981). In the January 2014 

Proposal, EPA stated that “these various formulations of the 

cost standard ... are synonymous,” and, for convenience, EPA 

used “reasonableness” as the formulation. EPA takes the same 

approach in this proposal. 
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 The EPA must also consider that CAA section 111 is designed 

to promote the deployment, development and implementation 

of technology.7677

Other considerations are also important, including that the 

EPA must also consider energy impacts, and, as with costs, may 

consider them on the source level and on the nationwide 

structure of the power sector over time. Importantly, the EPA 

has discretion to weigh these various considerations, may 

determine that some merit greater weight than others, and may 

vary the weighting depending on the source category. 

The EPA discussed the CAA requirements and Court interpretations 

of the BSER at length in the January 2104 proposal, 79 FR at 

1,462/1 –through 1,467/3, and incorporates by reference that 

discussion in this rulemaking. 

 

76 See discussion of case law and legislative history in the 

January 2014 proposal. 79 Fed. Reg. 1430, 1465 (cols. 1-2) 

(January 8, 2014).

77 It should be noted that in one of the earliest cases, Essex 

Chemical Corp. v. Ruckelshaus, in 1973, the Court stated that 

because the standard must be “achievable,” the emission limits 

must be technically feasible, and added that “[a]n adequately 

demonstrated system is one which has been shown to be reasonably 

reliable, reasonably efficient, and which can reasonably be 

expected to serve the interests of pollution control without 

becoming exorbitantly costly in an economic or environmental 

way.” Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 427. 

This case law may be read to treat technical feasibility as the 

measure for whether the standard of performance is “achievable,” 

not as a criteria for whether the system of emission reduction 

is the “best system of emission reduction ... adequately 

demonstrated.” However, for convenience, we may refer to 

technical feasibility as another of the criteria for the BSER. 

Comment [A32]: Did EPA intend to cite the case 

law reinforcing this point? On p. 107, the preamble 

says, “As noted above, the case law makes clear that 

the EPA is to consider the effect of its selection of 

BSER on technological innovation or 

development...” Footnote 65 doesn’t seem to lay 

out the case law to make this point as clearly as it 

could. 

EPA Response: We have added a footnote, which 

refers to and cites the discussion of the case law 

and legislative history on this point in the 

January proposal. In addition, I added the same 

citation to the “As noted above, the case law 

makes clear...” phrase that appears below (on or 

about p. 108). 
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It should be noted at the outset that the EPA determined 

that reconstructions are a type of construction, and therefore 

subject to section 111(b), as part of the 1975 framework 

regulations, and the EPA is not re-opening that determination.78 

The EPA also defined reconstructions in those regulations, and 

the EPA is not reopening that definition in this rulemaking. 

These provisions have two main specifications: (1) that 

reconstruction occurs upon replacement of components if the 

fixed capital cost of the new components exceeds 50 percent of 

the fixed capital cost that would be required to construct an 

entirely new comparable facility, and, (2) that it is 

technologically and economically feasible for the facility to 

comply with the applicable standards of performance after the 

replacements. 40 CFR part 60.15. These reconstruction provisions 

have not been amended since originally promulgated in 1975, and 

have been implemented for numerous source categories. 

B. Identification of Best System of Emissions Reduction 

The EPA evaluated seven different control technology 

configurations as potentially representing the BSER for 

reconstructed fossil fuel-fired boiler and IGCC EGUs: (1) the 

use of partial carbon capture and storage (CCS), (2) conversion 

to (or co-firing with) natural gas, (3) the use of combined heat 

 

7840 FR 58417-58418, December 16, 1975 (final NSPS modification, 

notification, and reconstruction provisions).
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and power (CHP), (4) hybrid power plants (5) reductions in 

generation associated with dispatch changes, renewable 

generation, and demand side energy efficiency,(6) efficiency 

improvements achieved through the use of the most efficient 

generation technology, and (7) efficiency improvements achieved 

through a combination of best operating practices and equipment 

upgrades.79

We discuss each of these alternatives below, and explain 

why we propose that for reconstructed fossil fuel-fired boiler 

and IGCC EGUs the most efficient generating technology qualifies 

as the BSER. 

1. Partial CCS 

We considered the implementation of partial CCS as the BSER 

at affected reconstructed utility boilers and IGCC units. In the 

January 8, 2014, proposal (79 FR 1430), the EPA found that, for 

new units, partial CCS has been adequately demonstrated and is 

technically feasible; it can be implemented at costs that are 

not unreasonable; it provides meaningful emission reductions; 

its implementation will serve to promote further development and 

deployment of the technology; and it would not have a 

significant impact on nationwide energy prices. The EPA also 

 

79 Note that we also evaluated these seven different technology 

configuations as potentially representing BSER for modified 

utility boilers and IGCC units. The subsequent discussion of 

each of these is also applicable for that evaluation as well.
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noted in the January 2014 proposal that most of the relatively 

few new projects that are in the development phase are already 

planning to implement CCS, so that partial CCS was consistent 

with current industry trends. 

Partial CCS has been demonstrated at some existing EGUs. It 

has been demonstrated at a large pilot scale (e.g., 20 MW or 

greater) at two facilities: at Southern Company’s Plant Barry 

and at AEP’s Mountaineer Power Plant. A full scale, 110 MW 

project is currently being retrofitted at SaskPower’s Boundary 

Dam coal-fired EGU in Canada and is scheduled expected to begin 

operation in summer 2014. Another large scale retrofit project 

(240 MW) is in advanced stages of project development at NRG 

Energy’s WA Parish facility. There are also a number of smaller 

examples of CCS retrofits on coal-fired power plants.80

However, the EPA does not, at present, have sufficient 

information about costs to propose that partial CCS is the BSER 

for reconstructed utility boilers and IGCC units. Utility 

boilers are numerous and diverse in size and configuration, and 

the EPA does not have sufficient information about the range of 

specific configurations that would be necessary to estimate the 

cost of partial CCS, on either a source-specific basis or an 

 

80 Technical Support Document, “Impact of EPACT 2005 on BSER” 

January 8, 2014 

http://www2.epa.gov/sites/production/files/2014-

01/documents/2013_proposed_cps_for_new_power_plants_tsd.pdf

Comment [A33]: This may be later – please 

confirm. 

EPA: Public statements still seem to support start 

up in 2014. However, the text was edited from 

‘summer 2014’ to ‘2014’.
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industry-wide basis. In particular, retrofitting a plant with 

partial CCS would entail integrating the carbon capture 

equipment with the affected unit’s steam cycle (or with an 

external source of steam or heat) in order to release the 

captured CO2 and regenerate the solvent or sorbent. The cost of a 

retrofit would depend on many site-specific details, including 

the space available for the capture equipment, and the EPA lacks 

information on such details for a significant portion of the 

industry. 

Therefore, the EPA does not propose to find that partial 

CCS is the BSER for CO2 emissions from reconstructed fossil fuelfired utility boilers and IGCC units. 

2. Conversion to or co-firing with natural gas 

While conversion to or co-firing with natural gas in a 

utility boiler is a technically feasible option to reduce CO2

emission rates, it is an inefficient way to generate electricity 

compared to use of an NGCC and the resultant CO2 reductions are 

relatively expensive. The EPA found costs for natural gas cofiring to range from approximately $83/ton to $150/ton of CO2

avoided.81 Even for cases where the natural gas could be co-fired 

without any capital investment or impact on the performance of 

the affected facility (e.g., an existing IGCC facility that 

 

81 Chapter 2, GHG Abatement Measures TSD
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already has a sufficient natural gas supply), the costs of CO2

reduction would still be approximately $75/ton of CO2 avoided. 

Therefore, we are not proposing natural gas co-firing as part of 

the BSER for modified or reconstructed steam generating units. 

However, we specifically solicit comment on whether natural 

gas reburning (NGR) and/or similar technologies82 should be 

included as part of the BSER for reconstructed utility boilers 

and IGCC units. NGR is a combustion technology in which a 

portion of the main fuel heat input is diverted to locations 

above the burners, creating a secondary combustion zone called 

the reburn zone. In NGR, the secondary (or reburn) fuel, natural 

gas, is injected to produce a slightly fuel rich reburn zone. 

Overfire air (OFA) is added above the reburn zone to complete 

burnout. As flue gas passes through the reburn zone, part of the 

nitrogen oxides (NOX) formed in the main combustion zone is 

reduced by hydrocarbon fragments (free radicals) and converted 

to molecular nitrogen (N2). With NGR at 15 and 20 percent of the 

heat input to a coal-fired boiler, the CO2 emission rate would be 

 

82 Fuel lean gas reburning (FLGRTM), also known as controlled gas 

injection, similar to NGR. In FLGRTM, natural gas is injected 

above the main combustion zone at a lower temperature zone than 

in NGR and avoids creating a fuel-rich zone and maintains 

overall fuel-lean conditions. The FLGRTM technology is reported 

to achieve NOX control comparable to NGR using less than 10% 

natural gas heat input without the requirement for OFA. At a 10 

percent heat input reburn rate, the CO2 emission rate of a coalfired EGU would be reduced by 4 percent. 

Comment [A34]: Is EPA similarly taking 

comment on whether NGR should be considered for 

BSER in the 111(d) proposal? 

EPA: Yes, we are requesting comment on natural 

gas co-firing in the 111(d) proposal and NGR is a 

type of co-firing. 
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reduced by 6 percent and 8 percent, respectively. In addition to 

reducing CO2 emissions, a potential financial benefit of NGR 

compared to natural gas co-firing is the generation of 

additional NOX reductions. These reductions could reduce costs a 

source is currently paying for compliance with NOX requirements, 

including operations and maintenance costs associated with 

existing controls such as selective catalytic reduction systems 

and/or the cost of emission allowances under certain pollution 

control programs. NGR is a combustion technology in which a 

portion of the main fuel heat input is diverted to locations 

above the burners, creating a secondary combustion zone called 

the reburn zone. In NGR, the secondary (or reburn) fuel, natural 

gas, is injected to produce a slightly fuel rich reburn zone. 

Overfire air (OFA) is added above the reburn zone to complete 

burnout. As flue gas passes through the reburn zone, part of the 

nitrogen oxides (NOX) formed in the main combustion zone is 

reduced by hydrocarbon fragments (free radicals) and converted 

to molecular nitrogen (N2). With NGR at 15 and 20 percent of the 

heat input to a coal-fired boiler, the CO2 emission rate would be 

reduced by 6 percent and 8 percent, respectively. 

The EPA also takes comment on whether there are other 

factors or technologies related to co-firing that reduce its 

cost, and whether for these or other reasons, co-firing should 

Comment [A35]: It may be helpful to move this 

description of NGR up in the paragraph to explain 

what NGR is immediately. 

EPA Response: Text has been moved.
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be considered as BSER for reconstructed fossil fuel-fired 

electric utility steam generating units. 

3. Combined Heat and Power 

CHP, also known as cogeneration, is the simultaneous 

production of electricity and/or mechanical energy and useful 

thermal output from a single fuel. CHP requires less fuel to 

produce a given energy output, and because less fuel is burned 

to produce each unit of energy output, CHP reduces air pollution 

and greenhouse gas emissions. CHP has lower emission rates and 

can be more economic than separate electric and thermal 

generation. However, not all potentially modified and 

reconstructed utility boilers and IGCC units are located close 

enough to thermal hosts to economically or efficiently use the 

recovered thermal energy. Therefore, we are not proposing to 

find that CHP is the BSER for reconstructed utility boilers and 

IGCC units or stationary combustion turbines. 

4. Hybrid power plant 

Hybrid power plants combine two or more forms of energy 

input into a single facility with an integrated mix of 

complementary generation methods. While there are multiple types 

of hybrid power plants, the most relevant type for this proposal 

is the integration of solar energy (e.g., concentrating solar 

thermal with or without photovoltaic generation) with a fossil 

fuel-fired EGU. Both coal-fired and NGCC EGUs have demonstrated 
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the technical feasibility of integrating concentrating solar 

thermal energy for use in boiler feed water heating, preheating 

makeup water, and/or producing steam for use in the steam 

turbine or to power the boiler feed pumps. While hybrid power 

plants can reduce the CO2 emission rate by several percent 

compared to similar non-hybrid power plants, not all modified 

and reconstructed EGUs may have the space or meteorological 

conditions to generate enough solar thermal energy to 

successfully convert to a hybrid power plant. Solar thermal 

facilities require abundant sunshine and significant land area 

and the EPA does not have sufficient information about the range 

of specific configurations that would be necessary to estimate 

the cost of implementation, on either a source-specific basis or 

an industry-wide basis. We solicit comment on whether hybrid 

power plant technology is broadly applicable to modified and 

reconstructed EGUs and on the costs of integrating non-emitting 

generation. 

Our understanding is that one of the benefits of hybrid 

fossil EGUs is decreased incremental cost of the non-emitting 

(e.g., solar thermal) generated electricity due to the ability 

to use equipment (e.g., HRSG, steam turbine, condenser, etc.) 

already included at the fossil fuel-fired EGU, as well as 

improvement of the electrical generation efficiency of the nonemitting generation. For example, solar thermal often produces 
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steam at relatively low temperatures and pressures and the 

conversion efficiency of the thermal energy in the steam to 

electricity is relatively low. In a hybrid power plant, the 

lower quality steam is heated to higher temperatures and 

pressures in the boiler (or HSRSG) prior to expansion in the 

steam turbine, where it produces electricity. Upgrading the 

relatively low grade steam produced by the solar thermal 

facility improves the relative conversion efficiencies of the 

solar thermal to electricity process. The primary incremental 

costs of the non-emitting solar thermal generation in a hybrid 

power plant is the costs of the mirrors, additional piping, and 

a steam turbine that is 10 to 20 percent larger than a 

comparable fossil only EGU to accommodate the additional steam 

load during sunny hours. 

We specifically solicit comment on an alternate, but 

similar, approach for modified and reconstructed fossil fuelfired EGUs to integrate lower emitting generation. The recovered 

thermal energy from natural gas-fired combustion turbines, fuel 

cells, or other combustion technology could be used to reheat or 

preheat boiler feed water (minimizing the steam that is 

otherwise extracted from the steam turbine), preheat makeup 

water and combustion air, produce steam for use in the steam 

turbine or to power the boiler feed pumps, or use the exhaust 

directly in the boiler to generate steam. In theory, this could 

Comment [A36]: Should be HRSG 

EPA Response: Text has been corrected.
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lower generation costs as well the GHG emissions rate for a 

coal-fired EGU. However, at this time we do not have sufficient 

information on the costs or technical feasibility of this 

approach to include it as the BSER for reconstructed fossil 

fuel-fired utility boilers. 

5. Reductions in Generation Associated with Dispatch Changes, 

Renewable Generation, and Demand Side Energy Efficiency 

In the companion proposal in today’s Federal Register, 

which proposes emission guidelines for existing fossil fuelfired EGUs, the EPA considered numerous measures that can and 

are being implemented to improve emission rates and to limit 

overall CO2 emissions from fossil fuel-fired EGUs. The EPA 

grouped those measures into four main categories, or “building 

blocks.” The EPA proposed that each of the building blocks 

represents a method of CO2 emission reduction at existing fossil 

fuel-fired EGUs that, when combined with the other building 

blocks, represent the “best system of emission reduction... 

adequately demonstrated” for existing fossil-fuel-fired EGUs 

under a 111(d) program. The building blocks are: 

1. Lowering the carbon intensity of generation at individual 

affected EGUs (e.g., through heat rate improvements); 

2. Reducing emissions of the most carbon-intensive affected 

EGUs to the extent that this can be accomplished costeffectively by shifting generation to less carbon-intensive 
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existing NGCC units, including NGCC units that are under 

construction; 

3. Reducing emissions of carbon-emitting EGUs to the extent 

that this can be accomplished cost-effectively by expanding 

the amount of new, lower (or no) carbon-intensity 

generation; and, 

4. Reducing emissions of carbon-emitting EGUs to the extent 

that this can be accomplished cost-effectively by 

increasing demand-side energy efficiency. 

In this rulemaking, we are, in effect, utilizing building 

block one – lowering the carbon intensity of generation at 

individual affected EGUs through heat rate improvements – as 

part of the BSER determination for modified units, but we are 

not proposing that building blocks two, three, or four are 

components of the BSER determination. We solicit comment on 

whether building blocks two, three and four would be appropriate 

in light of the fact that, unlike the CAA section 111(d) 

emission guidelines proposal, which will result in state plans 

that cover all existing sources, this proposal will result in a 

federal rule that covers only those sources that modify or 

reconstruct. We note that it is not possible in advance to 

determine which sourcesones will do so. We solicit comment on 

any additional considerations that the EPA should take into 
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account in the applicability of building blocks two, three and 

four in the BSER determination. 

6. Efficiency Improvements Achieved through the use of the most 

Efficient Generation Technology 

We also considered whether the proposed emission limit for 

reconstructed fossil fuel-fired utility boilers and IGCC units 

should be based on the performance of the most efficient 

generation technology available, which we believe is a SCPC or 

supercritical CFB boiler for large sources, and subcritical for 

small sources. We propose to find that these technologies meet 

the criteria for the BSER.83

a. Technical Feasibility 

The use of supercritical steam conditions has been 

demonstrated by many facilities since the 1960s for both large 

and small EGUs. In fact, the world’s first commercial 

supercritical pressure EGU was the 125 MW Philo Unit 6 that 

commenced operation in 1957. Currently commercially available 

materials capable of tolerating steam conditions of 30 

megapascal (MPa) (4,350 pounds per square inch (psi)) and 605 o

C 

(1,120 o

F) have been demonstrated at coal-fired EGUs. In 

addition, even though the majority of recently constructed coal-

 

83 Note that the discussion of efficiency improvements in this 

section is limited to reconstructed utility boilers and IGCC 

units. We discussed efficiency improvements for modifications 

below.
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fired EGUs use a single steam reheat cycle, the use of a dual 

steam reheat cycle has been demonstrated by multiple facilities 

as technically feasible. For a facility to be considered 

reconstructed for NSPS purposes, the boiler itself would have to 

be substantially refurbished. As part of a reconstruction, an 

owner/operator would be able to replace the steam tubing and 

other necessary equipment to allow the use of the best 

demonstrated steam cycle. Therefore, this option is technically 

feasible. 

It should be noted that this approach identifies as the 

BSER changes in production technology that would result in fewer 

emissions, and not add-on technology that would control 

emissions. The kraft pulp mill NSPS (40 CFR 60, subpart BB) is 

an example in which different equipment design (rather than addon control) is the BSER for a modification or reconstruction. 

b. CO2 Reductions 

The U.S. Department of Energy National Energy Technology 

Laboratory (DOE/NETL) has estimated that a new SCPC boiler using 

subbituminous coal would emit seven percent less CO2 per MWh than 

a comparable subcritical boiler. Therefore, we estimate that 

this standard will result in reduction in emissions of at least 

seven percent when compared to the expected emissions of a 

reconstructed EGU using subcritical steam conditions. Smaller 

EGUs often use relatively low steam parameters and increasing 

Comment [A37]: Isn’t this NETL estimate based 

on a comparison of the costs of new builds? EPA 

may want to provide further explanation of its 

consideration of any potential differences in cost for 

a reconstruction/retrofit in order to strengthen its 

basis for relying on this cost estimate. 

EPA: In this case, we used the estimated 

emissions from a new supercritical boiler as 

compared to a new subcritical boiler to estimate 

differences in CO2 emissions. We assume that 

the relationship between the two would be the 

same for newly constructed or reconstructed 

units. 
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the steam parameters to the maximum subcritical steam parameters 

reduces the CO2 emissions rate. The average steam pressure and 

temperature for small EGUs that were reported to the information 

collection request associated with the Mercury and Air Toxics 

Standards rulemaking is 11 MPa (1,630 psig) and 527 o

C (980 oF) 

and 40 percent have no steam reheat. Increasing the steam 

pressure to 20 MPa (2,900 psig) and 568 o

C (1,054 oF) would 

reduce the CO2 emission rate by 6 percent. In addition, the use 

of a single steam reheat cycle reduces the CO2 emission rate by 

10 percent compared to an equivalent EGU without a steam reheat 

cycle. 

While the percent reduction in CO2 emissions rate using 

efficiency improvements achieved through the use of the most 

efficient generation technology is less than could be achieved 

by a number of the other alternatives for the BSER that the EPA 

considered, as noted above, those other alternatives do not meet 

other criteria for the BSER. Efficiency improvements achieved 

through the use of the most efficient generation technology do 

achieve the greatest emission reductions of any of the remaining 

alternatives that the EPA is considering. 

c. Costs, Structure of the Energy Sector 

U.S. Department of Energy National Energy Technology 

Laboratory (DOE/NETL) has estimated, based on the levelized cost 

of electricity (LCOE), that the capital costs of a SCPC EGU are 
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approximately 3 percent more than a comparable subcritical EGU. 

In fact, the reduced fuel costs are significant enough that the 

overall cost to generate electricity is actually lower for a 

SCPC EGU compared to a subcritical EGU. Therefore, the emission 

reductions are considered cost effective for larger EGUs. 

For smaller boilers, less than approximately 200 MW, it is 

the understanding of the EPA that manufacturers of steam 

turbines do not currently offer turbines that have been 

thermodynamically optimized to use supercritical steam 

conditions. Instead, for smaller applications, they would 

typically adapt their larger turbines for the application. The 

resulting designs have a higher cost premium than larger 

supercritical steam turbines and do not take full advantage of 

the potential efficiency improvements and the benefits of using 

a supercritical steam cycle are reduced. Therefore, for smaller 

reconstructed EGUs the EPA has determined that the BSER is the 

use of highest available subcritical steam conditions. The 

maximum viable subcritical steam parameters are 21 MPa (3,000 

psi) and 570 o

C (1,060 oF). The EPA specifically solicits comment 

on the efficiency benefits and the costs of using supercritical 

steam conditions for smaller EGU designs. 

While we do not have data for the incremental costs of 

increasing steam parameters within subcritical conditions, 

modern materials are widely available that can tolerate the 
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maximum subcritical steam parameters. Therefore, we anticipate 

this cost is low. We solicit comment on these costs. 

Designating the most efficient generation technology as the 

BSER for reconstructed fossil fuel-fired utility boilers and 

IGCC units will not have significant impacts on nationwide 

electricity prices. The reason is that the additional costs of 

the use of efficient generation will, on a nationwide basis, be 

small because few reconstructed coal-fired projects are expected 

and because at least some of these reconstructions can be 

expected to incorporate the most efficient generation technology 

even in the absence of a standard. 

For the same reason, designation of the most efficient 

generation technology as the BSER for reconstructed fossil fuelfired utility boilers and IGCC units will not have adverse 

effects on the structure of the power sector, will not impact 

fuel diversity, and will not have adverse effects on the supply 

of electricity. 

d. Incentive for Technological Innovation 

As noted above, the case law makes clear that the EPA is to 

consider the effect of its selection of BSER on technological 

innovation or development, but that the EPA also has the 

authority to weigh this factor along with the other ones. When 

it comes to the selection of the BSER, the EPA recognizes that 

reconstructed sources face inherent constraints that newly 
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constructed greenfield sources do not; as a result, 

reconstructed sources present different, and in some ways more 

limited, opportunities for technological innovation or 

development. In this case, identifying the most efficient 

generation technology as the BSER promotes the further extension 

of that technology throughout the industry. 

While some of the other options that the EPA considered in 

determining the BSER for reconstructed utility boilers and IGCC 

units would have led to greater opportunities for technology 

advancement, for the reasons discussed above, those other 

options did not meet other criteria. While the proposed standard 

is based on the use of the best available steam cycle, other 

energy efficiency measures will likely be developed and used 

(improved economizers, etc.) and these technologies will be 

transferrable to other EGUs. 

7. Efficiency Improvements Achieved through a Combination of 

Best Operating Practices and Equipment Upgrades 

The EPA also considered whether a combination of best 

operating practices and equipment upgrades would qualify as the 

BSER for a reconstruction. These measures are discussed in 

greater detail in Section VII. A reconstruction, because it 

occurs only when an owner/operator spends more than 50% of the 

cost of a replacement unit, generally entails fundamental 

decisions about what type of unit to rebuild. For example, one 
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reconstruction occurred following an explosion at the boiler and 

resulted in a rebuild of the entire unit including both the 

boiler and the accompanying steam turbine. 

Because a reconstruction generally entails rebuilding the 

unit, operating practices and equipment upgrades are not 

applicable as BSER. Those entail smaller scale changes to the 

unit that may be expected to be rebuilt anyway. In addition, the 

emission reductions that could be achieved through best 

operating practices and equipment upgrades are smaller than the 

most efficient generation technology.

C. Determination of the Level of the Standard 

Once the EPA has determined that a particular system or 

technology represents BSER, the EPA must establish an emission 

standard based on that system or technology. To determine an 

achievable emission standard we reviewed the emission rate 

information submitted by owners/operators of coal-fired EGUs to 

the EPA’s Clean Air Markets Division. For reconstructed fossil 

fuel-fired boiler and IGCC EGUs, the EPA proposes to find that 

the best available steam cycle – which qualify as the BSER - 

support a standard of 1,900 lb CO2/MWh-net for large EGUs (i.e., 

those with heat input greater than 2,000 MMBtu/h), and 2,100 lb 

CO2/MWh-net for small EGUs (i.e., those with a heat input 2,000 

MMBtu/h or less). The U.S. Department of Energy National Energy 

Technology Laboratory (DOE/NETL) estimates that an IGCC unit 
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emission rate is comparable to those achieved by a supercritical 

coal-fired EGU. Therefore, for both technologies, these levels 

of the standard are based on the emission performance that can 

be achieved by a large pulverized or CFB coal unit using 

supercritical steam conditions and a small unit using 

subcritical steam conditions. 

We are also soliciting comment on whether the emission 

limit may be more appropriately set at a different level. Based 

on the rationale included in the TSD, we are soliciting comment 

on a range of 1,700 to 2,100 lb CO2/MWh-net for large units and 

1,900 to 2,300 lb CO2/MWh-net for small units. An emission rate 

of 1,700 lb CO2/MWh-net could potentially be met by an EGU using 

advanced ultra-supercritical steam conditions.84

We are not currently considering a standard more stringent than 

1,700 lb CO2/MWh-net for large units. Available information 

indicates that an EGU facility could not meet a standard of 

1,600 lb CO2/MWh-net based on the use of an advanced ultrasupercritical steam cycle, and instead would be required to 

implement partial CCS, co-fire approximately 40 percent natural 

gas directly in the boiler, or integrate non emitting or lower 

emitting technology in the facility's design (i.e., a hybrid 

power plant). We are not currently considering a standard more 

 

84 Advanced ultra-supercritical steam conditions are 700 – 760 o

C 

(1,290 – 1,400 o

F) and 36 MPa (5,000 psi) 
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stringent than 1,900 lb CO2/MWh-net for small units because 

available information indicates that a small EGU facility could 

only meet a standard of 1,800 lb CO2/MWh-net burning bituminous 

coal and using the best available subcritical steam cycle. 

Modified facilities burning other coal types would be required 

to implement partial CCS, co-fire approximately 10 percent 

natural gas directly in the boiler, or integrate non emitting or 

lower emitting technology in the facility's design (i.e., a 

hybrid power plant). 

We are not currently considering a standard less stringent 

than 2,100 lb CO2/MWh-net for large units because at that level, 

the NSPS would not necessarily promote the use of the best 

available steam cycle. At an emissions rate of 2,200 lb CO2/MWh, 

large EGUs would not be required to use efficient generation 

technologies (e.g., they could use subcritical steam 

conditions). We are not currently considering a standard less 

stringent than 2,300 lb CO2/MWh-net for small units because at 

that level, the NSPS would not necessarily promote the use of 

the best available steam conditions because many smaller 

subcritical units are operating well below 2,300 lb CO2/MWh-net. 

D. Compliance Period 

The EPA is proposing that sources would be required to meet 

the proposed standards on a 12 operating-month rolling basis. 

The proposed compliance period requirements and rationale are 
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the same as in the January 2014 proposal. This section provides 

a summary of the rationale. For additional detail, see 79 FR at 

1,481/2 –and 1,482/1. 

The 12-operating-month averaging period being proposed is 

important because of the inherent variability in power plant GHG 

emissions rates. Establishing a shorter averaging period would 

necessitate establishing a standard to account for the 

conditions that result in the lowest efficiency and therefore 

the highest GHG emissions rate. 

EGU efficiency has a significant impact on the source’s GHG 

emission rate. EGU efficiency can vary from month to month 

throughout the year. For example, high ambient temperature can 

negatively impact the efficiency of combustion turbine engines 

and steam generating units. As a result, an averaging period 

shorter than 12 operating-months would require us to set a 

standard that could be achieved under these conditions. This 

standard could potentially be high enough that it would not be a 

meaningful constraint during other parts of the year. In 

addition, operation at low load conditions can also negatively 

impact efficiency. It is likely that for some short period of 

time an EGU will operate at an unusually low load. A short 

averaging period that accounts for this operation would again 

not produce a meaningful constraint for typical loads. 
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On the other hand, a 12-operating-month rolling average 

explicitly accounts for variable operating conditions, allows 

for a more protective standard and decreased compliance burden, 

allows EGUs to have and use a consistent basis for calculating 

compliance (i.e., ensuring that 12 operating months of data 

would be used to calculate compliance irrespective of the number 

of long-term outages), and simplifies compliance for state 

permitting authorities. The EPA proposes that it is not 

necessary to have a shorter averaging period for CO2 from these 

sources because the effect of GHGs on climate change depends on 

global atmospheric concentrations which are dependent on 

cumulative total emissions over time, rather than hourly or 

daily emissions fluctuations or local pollutant concentrations. 

Unlike for emissions of criteria and hazardous air pollutants, 

we do not believe that there are measureable implications to 

health or environmental impacts from short-term higher CO2

emission rates as long as the 12-month average emissions rate is 

maintained. 

VII. Rationale for Emission Standards for Modified Fossil Fuelfired Utility Boilers and IGCC Units 

A. Introduction 

In this section we explain our rationale for proposing, as 

the “best system of emission reduction ... adequately 

demonstrated” for modified fossil fuel-fired utility boiler and 
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IGCC EGUs, a combination of best operating practices and 

equipment upgrades. 

We include in this discussion (1) our rationale for 

rejecting other alternatives as BSER, (2) a description of 

efficiency improvements achieved through a combination of best 

operating practices and equipment upgrades and our rationale for 

selecting it as BSER and (3) our rationale for co-proposed 

alternative standards of performance based on this BSER 

(including varying the standard depending upon whether the 

affected source would be subject to a CAA section 111(d) state 

plan (or promulgated federal plan) for CO2. 

B. Identification of the Best System of Emission Reduction for 

Modified Fossil Fuel-fired Utility Boilers and IGCC Units

1. Options considered 

For the same reasons explained above for reconstructed 

fossil fuel-fired boiler and IGCC EGUs, the EPA is not proposing 

the following options to be BSER for modified fossil fuel-fired 

utility boiler and IGCC units: (1) the use of partial carbon 

capture and storage (CCS), (2) conversion to (or co-firing with) 

natural gas, (3) the use of combined heat and power (CHP), (4) 

Hybrid Power Plants, and (5) reductions in generation associated 

with dispatch changes, renewable generation, and demand side 

energy efficiency. 
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In this section, we evaluate two other options for BSER: 

(1) efficiency improvements achieved through the use of the most 

efficient generation technology, and (2) efficiency improvements 

achieved through a combination of best operating practices and 

equipment upgrades. 

2. Use of the most efficient generation technology 

We considered whether the BSER for modified fossil fuelfired utility boilers and IGCC units should be based on the 

performance of the most efficient generation technology 

available, which we believe is a supercritical85 unit (i.e., a 

supercritical pulverized coal (SCPC) or supercritical 

circulating fluidized bed (CFB) boiler) for large sources, and a 

subcritical unit for small sources. However, as was previously 

noted, the existing fleet of fossil fuel-fired steam-generating 

boilers is numerous and diverse in size and configuration 

(including steam parameters), and the EPA does not have 

sufficient information about the range of configurations that 

would be necessary to estimate the cost of upgrading the steam 

cycle (switching to higher grade of materials in the furnace, 

 

85 Subcritical coal-fired boilers are designed and operated with 

a steam cycle below the critical point of water. Supercritical 

coal-fired boilers are designed and operated with a steam cycle 

above the critical point of water. Increasing the steam pressure 

and temperature improves the efficiency of a steam turbine 

converting thermal energy to electricity, which in turn leads to 

increased efficiency and a lower emission rate.
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replacement of the steam drum and conversion to a once through 

design, etc.) and auxiliary equipment to the most efficient 

generating technology. For a given boiler design, steam 

pressures and temperatures are limited by the properties of the 

materials (boiler tubes, etc.) and cannot be increased without 

replacing those components. We do not have sufficient 

information on the number of components that would need to be 

replaced or on the costs of replacing individual components. 

Furthermore, we recognize that, in at least some cases, 

requiring a unit to meet levels achievable by a supercritical 

unit, when it was not originally designed to do so, could 

require significant modifications to both the boiler and turbine 

that could start to approach the replacement cost for the unit. 

Unlike in the case of reconstruction explained above, it is 

the understanding of the EPA that modifications do not typically 

involve the type of boiler rebuilding that would make this an 

option with reasonable cost. Consequently, the EPA does not 

propose to find that the use of the most efficient generation 

technology meets the criteria for the BSER for a uniform 

nationwide standard of performance. 

3. Best Operating Practices and Equipment Upgrades 

The second option that EPA considered for modified fossil 

fuel-fired utility boilers and IGCC units is a combination of 

best operating practices and equipment upgrades. Best operating 
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practices includes both operating the unit in the most efficient 

manner for a given operating condition and replacing worn 

components in a timely manner. Equipment upgrades involve 

replacing existing components with upgraded ones or a more 

extensive overhaul of major equipment (turbine or boiler). We 

propose to find that this option meets the criteria for BSER for 

these EGUs. 

In addition, we are co-proposing two alternative standards 

of performance reflective of this BSER. In the first co-proposed 

alternative, all modified utility boilers and IGCC units will be 

required to meet a unit-specific emission standard. In the 

second co-proposed alternative, modified sources will be 

required to meet unit-specific emission limits that will depend 

on whether the affected unit undertakes the modification before 

it becomes subject to a section 111(d) state plan (or 

promulgated federal plan), or after it becomes subject to such a 

plan. Each variation of the BSER meets the criteria, which we 

discuss next. We describe the variations in more detail in the 

section concerning the standards of performance, which follows 

the discussion of the criteria. 

a. Technical Feasibility 

A wide range of studies have been performed evaluating the 
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opportunity to improve the heat rate (or efficiency)86 of an 

existing power plant without upgrading to the most efficient 

generation technology available. These studies are summarized in 

Chapter 2 of the TSD, “GHG Abatement Measures”87 which explains 

that, while the studies are different in the level of detail and 

assumptions, the results of the studies overall suggest that the 

U.S. coal-fired EGU existing fleet is theoretically capable of 

achieving heat rate improvements ranging from 9 to 15 percent. 

Many of the detailed engineering studies describe a wide 

range of opportunities to improve heat rate including 

improvements to the: (1) materials handling equipment at the 

plant, (2) economizer, (3) boiler control systems, (4) soot 

blowers, (5) air heaters, (6) steam turbine, (7) feedwater 

heaters, (8) condenser, (9) boiler feed pumps, (10) induced 

draft (ID) fans, (11) emission controls, and (12) water 

treatment systems. 

As the studies show, these types of upgrades have been made 

 

86 The heat rate is a common way to measure EGU efficiency. As 

the efficiency of a fossil fuel-fired EGU is increased, less 

fuel is burned per kilowatt-hour (kWh) generated by the EGU. 

This results in a corresponding decrease in CO2 and other air 

pollutant emissions. Heat rate is expressed as the number of 

British thermal units (Btu) or kilojoules (kJ) that are required 

to generate one kilowatt-hour (kWh) of electricity. Lower heat 

rates are associated with more efficient fossil fuel-fired EGUs.

87 Chapter 2: Heat Rate Improvement at Existing Coal-fired EGUs, 

Available in the rulemaking docket. Docket ID: EPA-HQ-OAR-2013-

0603.
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at a wide range of power plants, demonstrating their technical 

feasibility. 

b. CO2 Reductions 

This approach would achieve reasonable reductions in CO2

emissions from the affected modified units as those units will 

be required to meet an emission standard that is consistent with 

more efficient operation. In light of the limited opportunities 

for emission reductions from retrofits, these reductions are 

adequate. 

c. Costs 

The EPA reviewed the engineering studies available in the 

literature and selected the Sargent & Lundy 2009 study88 as the 

basis for its assessment of heat rate improvement potentials 

from equipment and system upgrades. We focused on thirteen heat 

rate improvement methods discussed by Sargent & Lundy and listed 

in Table 2-13 of the “GHG Abatement Measures” TSD. We used the 

average of the estimated costs (in $/kW) for each method to 

develop the cost-ranked list of heat rate improvement methods 

(listed by costs from lowest to highest in the table). The first 

nine items in Table 2-13 contribute about 15 percent of the 

total average $/kW cost for all items. We believe it is 

 

88 Coal-fired Power Plant Heat Rate Reductions, SL-009597 Final 

Report, January 2009. Available in the rulemaking docket and at 

http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.

Comment [A38]: Please make sure this section is 

consistent with the discussion in the 111(b) preamble 

and incorporates any changes resulting from the 

interagency process. 

EPA: Agreed, prior to signature we will ensure 

that the relevant sections are consistent between 

the two preambles. 
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reasonable to consider those nine no-cost and low-cost heat rate 

improvement methods as belonging in the category of what has 

been described above as best practices. The remaining four 

methods are higher cost heat rate improvement opportunities that 

we believe properly fall into the category discussed here as 

equipment or system upgrades. Using an average of the ranges of 

potential Btu improvements estimated by Sargent & Lundy for the 

four upgrade methods, equipment or system upgrades could provide 

a 4 percent heat rate improvement if all were applied on an EGU 

that has not already made those upgrades. 

The 2009 Sargent & Lundy study included an estimated range 

of heat rate improvement, and the associated range of capital 

cost for each heat rate improvement method, for units ranging in 

size from 200 MW to 900 MW. If the methods and unit sizes are 

combined, as though they were all applied on a single EGU, the 

range of Sargent & Lundy estimated Btu reductions (412 to 1205 

Btu) resulted in associated combined capital costs in the range 

of $40-150/kW. The wide ranges of estimated Btu reductions and 

capital costs are indicative of the wide range of real 

differences in the many details of site specific EGU designs, 

fuel types, age, size, ambient conditions, current physical 

condition, etc. The EPA’s analysis, therefore, assumed $100/kW 

as a representative combined heat rate improvement capital cost 

to achieve whatever Btu reduction is possible at an average 
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site. 

The EPA heat rate improvement analysis resulted in the 

following summary conclusions: 

 Some degree of heat rate improvement is already economic 

for high heat rate – high coal cost EGUs. 

 If a fleet-wide average 6 percent heat rate is technically 

feasible, it would also be economic on the basis of fuel 

savings alone, before consideration of the value of the 

associated CO2 emission reductions, on a fleet-wide basis at 

today’s coal prices if the associated average capital cost 

is about $75/kW or less. 

 Even at a capital cost of $100/kW and an IPM projected 2020 

coal price of $2.62/MMBtu, the fleet-wide cost of CO2

reduction via 6 percent heat rate improvement would be a 

relatively low $7.7/tonne of CO2 avoided. 

Based on this assessment, the EPA determines that the unitspecific emission limit based on historical best performance 

(which captures the good operating practice at the unit) coupled 

with an additional two percent reduction (which captures minimum 

opportunities for additional heat rate improvements from 

equipment and system upgrades) can be achieved at reasonable 

cost. 

The EPA’s modeling tools do not allow projection of any 

Comment [A39]: In describing the basis for 

requiring 2% efficiency improvement beyond a 

unit’s best historical performance, EPA may want to 

provide additional information about why 2% is a 

technically achievable improvement at a unit level 

and not just at a fleet-wide level. For example, what 

if a facility recently completed efficiency upgrades 

that are already included in their best historical 

annual performance? 

EPA Response: We are proposing that the 

emission standard for reconstructed facilities be 

no lower than the proposed standard for 

reconstructed facilities to account for facilities 

that have already undertaken efficiency 

upgrades. 
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specific number of utility boilers and IGCC units that are 

expected to trigger the NSPS modification provision. As 

discussed below, however, the EPA believes there are likely to 

be few, if any. HenceIn this case, a unit-specific standard of 

performance will not have significant impacts on nationwide 

electricity prices or on the structure of the nation’s energy 

sector. 

d. Incentive for Technological Development 

As noted previously, the case law makes clear that the EPA 

is to consider the effect of its selection of the BSER on 

technological innovation or development, but that the EPA also 

has the authority to weigh this factor, along with the various 

other factors. With the selection of emissions controls, 

modified sources face inherent constraints that newly 

constructed greenfield and even reconstructed sources do not; as 

a result, modified sources present different, and in some ways 

more limited, opportunities for technological innovation or 

development. In this case, the proposed standards promote 

technological development by promoting further development and 

market penetration of equipment upgrades and process changes 

that improve plant efficiency. 

C. Determination of the Level of the Standard 
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Once the EPA has determined that a particular system or 

technology represents BSER, the EPA must establish an emission 

standard based on that technology. 

Because the existing fossil fuel-fired steam-generating 

boilers are numerous and diverse in size and configuration – and 

because the EPA has no way to predict which of those sources may 

modify - developing a single standard for all modified utility 

boilers or IGCC units is challenging. The EPA considered a subcategorization approach, but, as is detailed in Chapter 2 of the 

TSD, “GHG Abatement Measures”, analysis of available data did 

not support a number of potential sub-categorization options - 

such as unit size, type or age - that intuitively seemed 

logical. 

In this action, the EPA is co-proposing two alternative 

standards of performance for modified utility boilers and IGCC 

units. In the first co-proposed alternative, all modified 

sources would meet a unit-specific emission limit. In the second 

co-proposed alternative, the modified source would be required 

to meet a unit-specific emission limit that will depend on the 

timing of the modification. 

For utility boilers or IGCC units undertaking 

modifications, the EPA is proposing that the BSER has two 

components: (1) that the source operates consistently with its 

own best demonstrated historical performance; and (2) that the 
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source implements other available heat rate improvement measures 

including upgrading of some components of the unit. 

Specifically, for the first co-proposed alternative, a modified 

utility boiler or IGCC unit would be required to maintain an 

emission rate that equals the unit’s best demonstrated annual 

performance during the years from 2002 to the year the 

modification occurs, multiplied by 98 percent (i.e., a two 

percent further reduction), but not to be more stringent than 

the emission limit that would be applicable to the source if it 

were a reconstructed source. Consistent with the heat rate 

improvement analysis in the 111(d) proposal, we selected 2002 to 

assure we captured the impacts of maintenance cycles and year to 

year natural variability in CO2 emission rate performance to 

capture the best historical performance. We solicit comment on 

whether we should select a year prior to or subsequent to 2002 

for purposes of determining the best historical emission rate. 

As mentioned, the EPA is also co-proposing standards of 

performance that are dependent on the timing of the 

modification. Specifically, a source that modifies prior to 

becoming subject to a CAA 111(d) plan would be required to meet 

an emission limit that is determined using the same methodology 

described in the first co-proposed alternative. The modified 

utility boiler or IGCC unit would be required to maintain an 

emission rate that equals the unit’s best demonstrated annual 
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performance during the years from 2002 to the year the 

modification occurs, multiplied by 98 percent (i.e., a two 

percent further reduction based on equipment upgrades), but not 

to be more stringent than the emission limit applicable to a 

corresponding reconstructed source. The EPA is proposing that 

units undertaking modifications after they become subject to a 

CAA section 111(d) plan would be required to meet a unitspecific emission limit that is determined by the 111(d) 

permitting implementing authority from an assessment to identify 

energy efficiency improvement opportunities for the affected 

source. This standard is informed by the fact that, as we 

discuss in the Legal Memorandum89, these sources would remain 

subject to the requirements of the CAA section 111(d) plan even 

after modifying. 

The EPA also solicits comment on whether the period of best 

historical performance should be the years from 2002 to the time 

when the unit becomes subject to the CAA 111(d) plan, rather 

than to the time of the modification. 

We are considering different standards applicable before 

and after a source becomes subject to a state 111(d) plan 

because we are concerned that, as a result of implementation of 

state plans, the additional two percent efficiency improvement 

 

89 Add citeLegal Memorandum available in rulemaking docket ID: 

EPA-HQ-OAR-20913-0602.
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(based on efficiency improvements) may be unachievable for a 

substantial number of sources that make efficiency improvements 

as part of a state 111(d) plan. Specifically, we are concerned 

that where a state imposes efficiency improvements on a source, 

or where a source undertakes efficiency improvements to comply 

with the state plan, it will have already attained the maximum 

level of efficiency improvement that is achievable for that 

unit. As a result, the source would be unable to undertake 

additional improvements to meet the highest level of efficiency 

plus the additional two percent reduction (based on equipment 

upgrades) that we are considering. We recognize that in some 

states, 111(d) plans may require no or limited efficiency 

improvements on a specific unit. In such cases, we expect such a 

unit to be able to achieve the standard we are considering for 

sources that modify prior to becoming subject to a state 111(d) 

plan. Accordingly, for such sources, we anticipate that the 

audit process that we are considering will result in an emission 

rate consistent with the highest level of efficiency plus two 

percent (based on equipment upgrades) that we are considering 

for sources that modify prior to becoming subject to a state 

plan. 

For this co-proposal, the EPA is proposing that the date 

for determining whether a unit is subject to a CAA section 

111(d) plan is the date that the plan is initially submitted to 

Comment [A40]: Why wouldn’t this be true for 

other units that recently made efficiency upgrades 

for other reasons (other state requirements or for 

business reasons)? EPA may want to clarify this 

distinction further. 

EPA Response: We are proposing that the 

emission standard for reconstructed facilities be 

no lower than the proposed standard for 

reconstructed facilities to account for facilities 

that have already undertaken efficiency 

upgrades. 
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the EPA. Although a state’s plan is still subject to the EPA’s 

approval, Wwe believe this represents a reasonable point to 

determine that a source is subject to a 111(d) plan, because at 

that point the operator would know what requirements the source 

would have to meet, and would have confirmation of the state’s 

intention to submit that plan to meet the requirements of 

111(d). We are also taking comment on a range of other dates 

including: June 30, 2016 (the original state plan submission 

deadline), the date that the state promulgates its rule, the 

date the EPA approves the rule, and January 1, 2020 (the 

proposed initial compliance date for state plans). 

For a source modifying after a CAA section 111(d) plan 

becomes applicable, a unit-specific emission standard will be 

determined by the 111(d) implementing authority from the results 

of an energy efficiency audit to identify technically feasible 

heat rate improvement opportunities at the affected source. 

An energy efficiency audit, or assessment, is an in-depth 

energy study identifying all energy conservation measures 

appropriate for a facility given its operating parameters. 

An energy audit is a process that involves a thorough 

examination of potential savings from energy efficiency 

improvements, pollution prevention, and productivity 

improvement. It leads to the reduction of emissions of 

pollutants through process changes and other efficiency 

Comment [A41]: Please clarify whether this 

refers to the initial submission or the potential 

second submissions 1-2 years later for states need 

more time or using a multi-state approach. 

EPA Response: Text has been edited.

Comment [A42]: It should be noted that this is 

still subject to EPA’s approval of a state’s plan. 

EPA Response: Text has been edited. 
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modifications. Besides reducing operating and maintenance costs, 

improving energy efficiency results in decreased fuel use which 

results in a corresponding decrease in emissions. Such an energy 

assessment requirement is included in the National Emission 

Standards for Hazardous Air Pollutants for Major Sources: 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters (40 CFR part 63, subpart DDDDD). 

We propose that the energy assessment would include, at a 

minimum, the following elements: 

1. A visual inspection of the facility to identify steam leaks 

or other sources of reduced efficiency; 

2. A review of available engineering plans and facility 

operation and maintenance procedures and logs; and 

3. A comprehensive report detailing the ways to improve 

efficiency, the cost of specific improvements, benefits, 

and the time frame for recouping those investments. 

We propose that the energy assessment be conducted by 

energy professionals or engineers that have expertise in 

evaluating energy systems. We specifically request comment on: 

(1) whether energy assessor certification should be required; 

(2) if certification were required, what should the basis of the 

certification be; and (3) whether there are organizations that 

provide certification of specialists in evaluating energy 

systems. We propose that the 111(d) implementing authority will 
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determine a unit-specific emission limit based on the results of 

the energy efficiency audit and we also request comment on: (1) 

whether the rule should require implementation of identified 

energy efficiency improvements; and (2) if implementation were 

required, what the determining factor(s) for requiring 

thewhether the required improvements should be identified as 

reasonable. Finally, we request comment on: (1) whether an 

energy efficiency audit recently completed (e.g., within 3 years 

of the modification) that meets or is amended to meet the rule’s 

energy audit requirements can be used to satisfy the energy 

efficiency audit requirement and, in such instances, whether 

energy assessor approval and qualification requirements should 

be waived; and (2) whether facilities that operate under an 

energy management program compatible to ISO 5000190 that includes 

the affected units can be used to satisfy the energy efficiency 

audit requirement.

The EPA also seeks comment on whether, and under what 

circumstances, the energy audit methodology – i.e., determining 

the emission limit from the results of the energy audit – should 

 

90 ISO 50001 is a specification created by the International 

Organization for Standardization (ISO) for an energy management 

system. The standard specifies the requirements for 

establishing, implementing, maintaining and improving an energy 

management system, whose purpose is to enable an organization to 

follow a systematic approach in achieving continual improvement 

of energy performance, including energy efficiency, energy 

security, energy use and consumption. 

Comment [A43]: Identified as reasonable by 

whom? 

EPA Response: Text has been edited.
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be an option for sources that modify before becoming subject to 

a CAA section 111(d) plan. In particular, the EPA seeks comment 

on whether the audit methodology should be an option for all 

units that modify, prior to becoming subject to a CAA section 

111(d) plan, or if it should be an option for sources that 

provide evidence that significant energy efficiency improvements 

were implemented after 2002 but before the modification. 

D. Compliance Period 

The EPA is proposing that sources would be required to meet 

the proposed standards on a 12 operating-month rolling basis. 

The compliance period requirements and rationale being proposed 

for modified boilers and IGCC units are the same as the 

requirements and rationale being proposed for reconstructed 

utility boilers and IGCC units (see section VII.D. of this 

preamble), as well as the compliance period requirements and 

rationale in the January 2014 proposal. For additional detail, 

see 79 FR at 1,481/2 –and 1,482/1 and the TSD. 

VIII. Rationale for Emission Standards for Reconstructed Natural 

Gas-fired Stationary Combustion Turbines 

A. Identification of the Best System of Emission Reduction 

The EPA evaluated three different control technology 

configurations as potentially representing the “best system of 

emissions reductions ... adequately demonstrated” for 

reconstructed natural gas-fired stationary combustion turbines: 
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(1) NGCC technology with CCS, (2) NGCC technology by itself, and 

(3) high efficiency simple cycle aeroderivative turbines. 

1. NGCC technology with CCS 

 We are not proposing to find that CCS technology is the 

BSER for reconstructed natural gas-fired stationary combustion 

turbines for the same reasons why we are not proposing to find 

that CCS technology is the BSER for steam-generating units: An 

owner/operator of an existing source that is undertaking 

reconstruction has challenges not faced when building a new NGCC 

unit because the existing unit may be located at a site with 

space constraints that would make installation of CCS 

problematic. We do not have sufficient information about the 

universe of existing sources to be able to determine the costs 

of CCS, in light of these space constraints. .

2. NGCC technology 

For the reasons explained below, we find NGCC technology to 

be BSER for reconstructed natural gas-fired stationary 

combustion turbines. 

a. Technical Feasibility 

NGCC technology is widely used in the power sector today. 

There are hundreds of NGCCs in the U.S. and in other countries. 

b. Emission Reductions 

NGCC technology is the most efficient technology for 

natural-gas fired stationary combustion turbines. It has an 
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emission rate that is approximately 25 percent lower than the 

most effective main alternative technology, which is the simple 

cycle combustion turbine. 

c. Cost 

NGCC technology is one of the lowest cost forms of baseload 

and intermediate load electricity generation. Even in the case 

of a simple cycle turbines that operates at a capacity factor of 

greater than one-third, the cost of replacement with a NGCC unit 

is likely to be cost effective based on consideration of fuel 

savings alone. In the new source proposal (79 FR 1459), we 

explained that at capacity factors of greater than 20 percent, 

the LCOE of a combined cycle unit would be less than the LCOE of 

a simple cycle turbine. Because the cost of adding a HRSG to a 

simple cycle turbine is less than the cost of building a full 

combined cycle unit, the same holds true with a comparison of 

replacing a simple cycle turbine and upgrading it to a combined 

cycle turbine. Furthermore, if the owner/operator of a simple 

cycle turbine wishes to make a modification, they could do so - 

without having to comply with the requirements of this proposal 

- by maintaining an average annual capacity factor of less than 

one-third. As we explained in the proposal, few simple cycle 

turbines operate at an annual capacity factor of greater than 

one-third. (79 FR 1459) 

d. Incentive for technology innovation 
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We recognize that because NGCC technology is already the 

state of the art technology, and is widely used, for natural gas 

stationary combustion turbines, identifying this technology as 

the BSER may not provide significant incentive for technology 

innovation. However, we are according less weight to this factor 

in this case because we consider this technology to be highly 

efficient and because the only more stringent alternative – CCS 

– is one that we are not proposing to identify as BSER, for 

reasons discussed above. 

3. High efficiency simple cycle aeroderivative turbines 

The use of high efficiency simple cycle aeroderivative 

turbines does not provide emission reductions when compared to 

the NGCC technology. According to the Annual Energy Outlook 

(AEO) 2013 emissions rate information, advanced simple cycle 

combustion turbines have a base load rating CO2 emissions rate of 

1,150 lb CO2/MWh-gross, which is higher than the base load rating 

emission rates of 830 and 760 lb CO2/MWh-gross for the 

conventional and advanced NGCC model facilities, respectively. 

In addition, simple cycle technology is more expensive than NGCC 

technology; and it does not further develop or promote use of 

the most advanced emission control technology. For these 

reasons, we do not find it to be the BSER for reconstructed 

natural gas-fired stationary combustion turbines. 

B. Determination of the Standards of Performance 
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The proposed standards of performance for reconstructed 

natural gas-fired stationary combustion turbines, which are 

based on BSER being efficient NGCC technology, are consistent 

with those that were proposed for new natural gas-fired 

stationary combustion turbine sources, as described in the 

January 8, 2014 proposal (79 FR 1430). In that proposal, the EPA 

indicated that it had reviewed the CO2 emissions data from 2007 

to 2011 for natural gas-fired (non-CHP) combined cycle units 

that commenced operation on or after January 1, 2000, and that 

reported complete electric generation data, including output 

from the steam turbine, to the EPA. A more detailed description 

of the emissions data analysis is included in a TSD in the 

docket for that rulemaking91 and is also included in the docket 

for this proposal. 

Consistent with the January 8, 2014, proposal, the EPA 

proposes to subcategorize the turbines into the same two sizerelated subcategories currently in subpart KKKK for standards of 

performance for the combustion turbine criteria pollutants. 

These subcategories are based on whether the design heat input 

rate to the turbine engine is either 850 MMBtu/h or less, or 

greater than 850 MMBtu/h. We further propose to establish 

different standards of performance for these two subcategories. 

 

91 Docket ID: EPA-HQ-OAR-2013-0495.
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This subcategorization has a basis in differences in 

several types of equipment used in the differently sized units, 

which affect the efficiency of the units. Because of these 

differences in equipment and inherent efficiencies of scale, the 

smaller capacity NGCC units (850 MMBtu/h and smaller) are less 

efficient than the larger units (larger than 850 MMBtu/h). 

We are proposing standards of performance of 1,000 lb CO2/MWhgross for the large units and 1,100 lb CO2/MWh-gross for the 

small units; and we are requesting comment on a range of 950 to 

1,100 lb CO2/MWh-gross for the large turbine subcategory and 

1,000 to 1,200 lb CO2/MWh-gross for the small turbine 

subcategory. 

IX. Rationale for Emission Standards for Modified Natural Gasfired Stationary Combustion Turbines

A. Identification of the Best System of Emission Reduction 

We believe that the analysis above with regards to 

reconstructed natural gas-fired stationary combustion turbines 

is also applicable to modified natural gas-fired stationary 

combustion turbines.92 The only potential difference that the EPA 

has identified is consideration of cost because the actions that 

could trigger modification are less extensive changes at the 

 

92 Technical Support Document “Standard of Performance for 

Natural Gas-Fired Combustion Turbines” available in the 

rulemaking docket. Docket ID: EPA-HQ-OAR-2013-0603. 
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facility. We have considered four different scenarios that could 

trigger the modification provisions: (1) modification of an 

older (e.g., pre 2000) combined cycle unit, (2) modification of 

a newer (e.g., a built in 2000 or later) combined cycle unit, 

(3) upgrading of a simple cycle turbine to a combined cycle 

unit, and, (4) modification to a simple cycle turbine other than 

upgrading to a combined cycle unit. As described below, in each 

of these cases, we believe that NGCC is cost-effective. 

1. Modifications to an older (e.g., pre-2000) combined cycle 

unit 

Because the performance of combined cycle technology has 

improved so significantly since 2000, we believe that upgrading 

to current technology is likely to be cost effective when one 

considers a combination of fuel savings, and performance 

benefits (the ability to start up the unit more quickly and 

operate more efficiently over a wider range of loads). 

2. Modifications to a newer combined cycle unit 

These modifications are likely to be made to return the 

unit to close to its original operating performance, and would 

be consistent with the requirements of today’s proposal, and are 

not likely to significantly increase the cost of the project. 

3. Upgrading a simple cycle turbine to a combined cycle unit 

These modifications would be made to upgrade the efficiency 

of the unit, and are consistent with the requirements of today’s 
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proposal, and are not likely to significantly increase the cost 

of the project. 

4. Modifications to a simple cycle turbine other than upgrading 

to combined cycle 

As was noted above - and in the new source proposal - when 

operating at higher capacity factors, the use of combined cycle 

technology instead of simple cycle technology pays for itself in 

fuel savings alone. 

For these reasons, we find the use of NGCC technology to be 

BSER for modified natural gas-fired combustion turbines. 

B. Determination of the Standards of Performance for Modified 

Natural Gas-fired Stationary Combustion Turbines

We propose that the same standards of performance described 

above for reconstructed natural gas-fired stationary combustion 

turbines are also appropriate for modified natural gas-fired 

stationary combustion turbines. 

We are requesting comment on a range of 950 to 1,100 lb 

CO2/MWh-gross (430 to 500 kg CO2/MWh) for the large turbine 

subcategory and 1,000 to 1,200 lb CO2/MWh-gross (450 to 540 kg 

CO2/MWh) for the small turbine subcategory. 

For sources that are subject to a CAA section 111(d) plan, 

the EPA is also soliciting comment on whether the sources should 

be allowed to elect, as an alternative to the otherwise 

applicable numeric standard, to meet a unit-specific emission 
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standard, determined by the 111(d) permitting implementing 

authority, based on implementation of identified energy 

efficiency improvement opportunities applicable to the source. 

X. Impacts of the Proposed Action93

As explained in the RIA for this proposed rule, the EPA 

expects few, if any, sources will trigger either the NSPS 

modification or reconstruction provisions that we are proposing 

today. Because the EPA is aware of a limited number of units 

that have notified the EPA of NSPS modifications in the past, we 

have conducted an illustrative analysis of the costs and 

benefits for a representative unit. Based on the analysis, which 

is presented in Chapter 9 of the RIA, the EPA expects that this 

proposed rule will result in potential CO2 emission changes, 

quantified benefits, and costs for a unit that was subject to 

the modification provision. In this illustrative example based 

on a hypothetical 500 MW coal-fired unit, we estimate costs, net 

of fuel savings, of $0.78 million to $4.5 million (2011$) and CO2

reductions of 133,000 to 266,000 tons in 2025. The combined 

climate benefits from reductions in CO2 and health co-benefits 

from reductions in SO2, NOx, and PM2.5 total $18 to $33 million 

(2011$) at a 3 percent discount rate for emission reductions in 

 

93 Note that the EPA does not project any difference in the 

impacts between the alternative to regulate sources under 

subparts Da and KKKK versus regulating them under new subpart 

TTTT
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2025 for the lowest emission reductions scenario and $35 to $65 

million (2011$) at a 3 percent discount rate for emission 

reductions in 2025 for the highest emission reduction scenario.94

A. What are the air impacts? 

As explained immediately above, the EPA expects few, if 

any, modified or reconstructed EGUs in the period of analysis. 

Because there have been a limited number of units that have 

notified the EPA of NSPS modifications in the past, we have 

conducted an illustrative analysis of the impacts for a 

hypothetical unit that triggered the modification provision. For 

this illustrative example, we estimate CO2 reductions of 133,000 

to 266,000 tons in 2025. Additionally, we estimate co-reductions 

of SO2, NOx, and PM2.5. 

B. What are the energy impacts? 

This proposed rule is not anticipated to have significant 

impacts on the supply, distribution, or use of energy. As 

previously stated, the EPA expects few, if any, reconstructed or 

modified EGUs in the period of analysis and the nationwide cost 

impacts to be minimal as a result. 

 

94 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average social cost of 

carbon (SCC) at a 3% discount rate. We emphasize the importance 

and value of considering the full range of SCC values, however, 

which include the model average at 2.5% and 5%, and the 95th

percentile at 3%. Similarly, we summarize the health co-benefits 

in this synopsis at a 3% discount rate. We provide estimates 

based on additional discount rates in the RIA. 
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C. What are the compliance costs? 

The EPA believes this proposed rule will have minimal 

compliance costs associated with it, because, as previously 

stated, the EPA expects, few, if any, modified or reconstructed 

EGUs in the period of analysis. Because the EPA is aware of a 

limited number of units that have notified the EPA of NSPS 

modifications in the past, we have conducted an illustrative 

analysis of the costs and benefits for a representative unit. 

Based on the analysis, which is presented in Chapter 9 of the 

RIA, the EPA estimates compliance costs, net of fuel savings, of 

$0.78 to $4.5 million (2011$) in 2025 for a hypothetical unit 

that triggered the modification provisions. 

D. How will this proposal contribute to climate change 

protection? 

As previously explained, the special characteristics of GHG 

make it important to take action to control the largest 

emissions categories without delay. Unlike most traditional air 

pollutants, GHG persist in the atmosphere for time periods 

ranging from decades to millennia, depending on the gas. Fossil 

fuel-fired power plants emit more GHG emissions than any other 

stationary source category in the U.S. 

This proposed rule would limit GHG emissions from modified 

fossil fuel-fired electric utility steam generating units 

(utility boilers and IGCC units) to levels consistent with the 
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unit’s best potential performance. GHG emissions from 

reconstructed utility boilers and IGCC units would be limited to 

levels consistent with modern, efficient generating technology 

(e.g., supercritical steam cycles). While the EPA expects few, 

if any, units to trigger the modification or reconstruction 

provisions, this proposed rule would limit GHG emissions from 

any modified and reconstructed stationary combustion turbines to 

levels consistent with modern, efficient natural gas combined 

cycle technology. As a result, this 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?

As previously stated, the EPA anticipates few, if any, 

units will trigger the proposed modification or reconstruction 

provisions. For this reason, the proposed standards will result 

in minimal emission reductions, costs, or quantified benefits by 

2025. There are no macroeconomic or employment impacts expected 

as a result of these proposed standards.As previously stated, 

the EPA anticipates few, if any, units will trigger the proposed 

modification or reconstruction provisions. Because there have 

been a limited number of units that have notified the EPA of 

NSPS modifications in the past, we have conducted an 
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illustrative analysis of the costs and benefits for a 

representative unit. Based on the analysis, which is presented 

in Chapter 9 of the RIA, the combined climate benefits from 

reductions in CO2 and health co-benefits from reductions in SO2, 

NOx, and PM2.5 total $18 to $33 million (2011$) at a 3 percent 

discount rate for emission reductions in 2025 for the lowest 

emission reductions scenario and $35 to $65 million (2011$) at a 

3 percent discount rate for emission reductions in 2025 for the 

highest emission reduction scenario.95

F. What are the benefits of the proposed standards? 

As previously stated, the EPA anticipates few, if any, 

units will trigger the proposed modification or reconstruction 

provisions. Because there have been a limited number of units 

that have notified the EPA of NSPS modifications in the past, we 

have conducted an illustrative analysis of the costs and 

benefits for a representative unit. Based on the analysis, which 

is presented in Chapter 9 of the RIA, the combined climate 

benefits from reductions in CO2 and health co-benefits from 

reductions in SO2, NOx, and PM2.5 total $18 to $33 million (2011$) 

 

95 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average social cost of 

carbon (SCC) at a 3% discount rate. We emphasize the importance 

and value of considering the full range of SCC values, however, 

which include the model average at 2.5% and 5%, and the 95th

percentile at 3%. Similarly, we summarize the health co-benefits 

in this synopsis at a 3% discount rate. We provide estimates 

based on additional discount rates in the RIA.
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at a 3 percent discount rate for emission reductions in 2025 for 

the lowest emission reductions scenario and $35 to $65 million 

(2011$) at a 3 percent discount rate for emission reductions in 

2025 for the highest emission reduction scenario.96As previously 

stated, the EPA anticipates minimal CO2 emission changes 

resulting from the rule in the period of analysis. Therefore, 

there are no direct monetized climate or human health benefits 

associated with this rulemaking. 

XI. 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 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 OMB 

for review under Executive Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011) and any changes made in response to the OMB 

recommendations have been documented in the docket for this 

 

96 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average social cost of 

carbon (SCC) at a 3% discount rate. We emphasize the importance 

and value of considering the full range of SCC values, however, 

which include the model average at 2.5% and 5%, and the 95th

percentile at 3%. Similarly, we summarize the health co-benefits 

in this synopsis at a 3% discount rate. We provide estimates 

based on additional discount rates in the RIA.
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action. In addition, the EPA prepared an analysis of the 

potential costs and benefits associated with this action. This 

analysis is contained in Chapter 9 of the Regulatory Impact 

Analysis for Emission Guidelines for Greenhouse Gas Emissions 

from Existing Stationary Sources: Electric Utility Generating 

Units. 

As explained in the RIA for this proposed rule, in the 

period of analysis (through 2025) the EPA anticipates few, if 

any, sources will trigger either the modification or the 

reconstruction provisions proposed. Because there have been a 

few units that have notified the EPA of NSPS modifications in 

the past, we have conducted an illustrative analysis of the 

costs and benefits for a representative unit that is included in 

Chapter 9 of the RIA. 

B. Paperwork Reduction Act

This proposed action doesis not expected to impose an 

information collection burden under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is 

defined at 5 CFR 1320.3(b). As previously stated, the EPA 

expects, few, if any, modified or reconstructed EGUs in the 

period of analysis. Specifically, the EPA believes it unlikely 

that fossil fuel-fired electric utility steam generating units 

(utility boilers and IGCC units) or stationary combustion 

turbines will take actions that would constitute modifications 
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or reconstructions as defined under the EPA’s NSPS regulations. 

Accordingly, this proposed action is not anticipated to impose 

any information collection burden over the 3-year period covered 

by this ICR. We have estimated, however, the information 

collection burden that would be imposed on an affected EGU if it 

was modified or reconstructed. The information collection 

requirements in this proposed rule have been submitted for 

approval to the Office of Management and Budget (OMB) under the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document prepared by the EPA has been 

assigned the EPA ICR number 2465.03.

 The EPA intends to codify the standards of performance in 

the same way for both this proposed action and the January 2014 

proposal for new sources and is proposing the same recordkeeping 

and reporting requirements that were included in the January 

2014 proposal.97 See 79 FR at 1,498/3 –and 1,499/3. Although not 

anticipated, if an EGU were to modify or reconstruct, this 

proposed action would impose minimal information collection 

burden on affected sources beyond what those sources would 

already be subject to under the authorities of CAA parts 75 and 

 

97 The information collection requirements in the January 2014 

proposal have been submitted for approval to the OMB under the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR document 

prepared by the EPA for the January 2014 proposal has been 

assigned the EPA ICR number 2465.02.
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98. The 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 potential energy metering 

modifications to comply with net energy output based emission 

limits proposed in this action and certain reporting costs, 

which are mandatory for all owners/operators subject to CAA 

section 111 national emission standards, there would be 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. 

Although, as stated above, the EPA expects few, if any, 

sources will trigger either the NSPS modification or 

reconstruction provisions that we are proposing, if an EGU were 

to modify or reconstruct during the 3-year period covered by 

this ICR, it is likely that an EGU’s energy metering equipment 

would need to be modified to comply with proposed net energy 
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output based CO2 emission limits. Specifically, the EPA estimates 

that it would take approximately 3 working months for a 

technician to retrofit existing energy metering equipment to 

meet the proposed net energy output requirements. In addition, 

after modifications are made that enable a facility to measure 

net energy output, each EGU’s Data Acquisition System (DAS) 

would need to be upgraded to accommodate reporting of net energy 

output rate based emissions. A modified or reconstructed EGU 

would be required to prepare a quarterly summary report, which 

includes reporting of emissions and downtime, every 3 months. 

The reporting burden for such a unit (averaged over the first 3 

years after the effective date of the standards) is estimated to 

be $17,217 and 205 labor hours. Estimated cost burden is based 

on 2013 Bureau of Labor Statistics (BLS) labor cost data. 

Average burden hours per response are estimated to be 47.3 hours 

and the average number of annual responses over the 3-year ICR 

period is 4.33 per year. Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. 
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To comment on the Agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID number EPA-HQ-OAR-2013-0603. Submit any 

comments related to the ICR to the EPA and OMB. See ADDRESSES

section at the beginning of this notice for where to submit 

comments to the EPA. Send comments to OMB at the Office of 

Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Officer for the EPA. Since OMB is required to make a 

decision concerning the ICR between 30 and 60 days after [INSERT 

DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB 

is best assured of having its full effect if OMB receives it by 

[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 

The final rule will respond to any OMB or public comments on the 

information collection requirements contained in this proposal.

The information collection requirements in the January 2014 

proposal have been submitted for approval to the OMB under the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR document 

prepared by the EPA for the January 2014 proposal has been 

assigned the EPA ICR number 2465.02. 

C. Regulatory Flexibility Act
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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 with less than 750 employees. The NAICS codes for the 

affected industry are in Table 4 below); 

(2) A small governmental jurisdiction that is a government 

of a city, county, town, school district or special district 

with a population of less than 50,000; and 

(3) A small organization that is any not-for-profit 

enterprise which is independently owned and operated and is not 

dominant in its field.

Table 4. Potentially Regulated Categories and Entitiesa

Comment [A44]: Should this include “tribal 

governments” as Table 2 (pg. 31) does? 

EPA Response: For purposes of the RFA, states 

and tribal governments are not considered small 

governments. 

We have removed the table because small entity 

(including small governmental jurisdiction) is 

defined immediately above and, as pointed out, 

Table 2 lists potentially regulated entities, in 

general.
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Category NAICS 

Code 

Examples of Potentially Regulated 

Entities 

Industry 

 

221112 

 

Fossil fuel electric power generating 

units. 

State/Local 

Government 

 

221112b

 

Fossil fuel electric power generating 

units owned by municipalities. 

a

 Include NAICS categories for source categories that own and 

operate electric power generating units (includes boilers and 

stationary combined cycle combustion turbines). 

b

 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. 

The EPA expects few, if any, modified utility boilers, IGCC 

units, or stationary combustion turbines in the period of 

analysis. An NSPS modification is defined as a physical or 

operational change that increases the source’s maximum 

achievable hourly rate of emissions. The EPA does not believe 

that there are likely to be EGUs that will take actions that 

would constitute modifications as defined under the EPA’s NSPS 

regulations. 

Because there have been a limited number of units that have 

notified the EPA of NSPS modifications in the past, the RIA for 
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this proposed rule includes an illustrative analysis of the 

costs and benefits for a representative unit. 

Based on the analysis, the EPA estimates that this proposed 

rule could result in CO2 emission changes, quantified benefits, 

or costs for a hypothetical unit that triggered the modification 

provision. However, we do not anticipate this proposed rule 

would impose significant costs on those sources, including any 

that are owned by small entities. 

In addition, the EPA expects few, if any, reconstructed 

fossil fuel-fired electric utility steam generating units 

(utility boilers and IGCC units) or stationary combustion 

turbines in the period of analysis. Reconstruction occurs when a 

single project replaces components or equipment in an existing 

facility and exceeds 50 percent of the fixed capital cost that 

would be required to construct a comparable entirely new 

facility. Due to the limited data available on reconstructions, 

it is not possible to conduct a representative illustrative 

analysis of what costs and benefits might result from this 

proposal in the unlikely case that a unit were to reconstruct. 

However, based on the low number of previous reconstructions and 

the BSER determination based on the most efficient available 

generating technology, we would expect this proposal to result 

in no significant CO2 emission changes, quantified benefits, or 

costs for NSPS reconstructions. Accordingly, there are no 
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anticipated economic impacts as a result of the proposed 

standards for reconstructed EGUs. 

Nevertheless, the EPA is aware that there is substantial 

interest in the proposed rule among small entities (municipal 

and rural electric cooperatives). As summarized in section II.G. 

of this preamble, the EPA has conducted an unprecedented amount 

of stakeholder outreach. As part of that outreach, agency 

officials participated in many meetings with individual 

utilities as well as meetings with electric utility 

associations. Specifically, the EPA Administrator, Gina 

McCarthy, participated in separate meetings with both the 

National Rural Electric Cooperative Association (NRECA) and the 

American Public Power Association (APPA). The meetings brought 

together leaders of the rural cooperatives and public power 

utilities from across the country. The Administrator discussed 

and exchanged information on the unique challenges, in 

particular the financial structure, of NRECA and APPA member 

utilities. A detailed discussion of the stakeholder outreach is 

included in the preamble to the emission guidelines for existing 

affected electric utility generating units being proposed in a 

separate action. 

In addition, as described in the RFA section of the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1499 and- 1500, January 8, 2014), 

Comment [A45]: Extensive? 

EPA Response: This text is consistent with the 

111(d) proposal preamble discussion regarding 

stakeholder outreach, and, thus, we believe it 

should be retained in this preamble as well.
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the EPA conducted outreach to representatives of small entities 

while formulating the provisions of the proposed standards. 

Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new, 

reconstructed, modified and existing sources. 

While formulating the provisions of this proposed rule, the 

EPA considered the input provided over the course of the 

stakeholder outreach. We invite comments on all aspects of this 

proposal and its impacts, including potential impacts on small 

entities. 

D. Unfunded Mandates Reform Act

This proposed rule does not contain a federal mandate that 

may result in expenditures of $100 million or more for state, 

local and tribal governments, in the aggregate, or the private 

sector in any 1 year. As previously stated, the EPA expects few, 

if any, modified or reconstructed fossil fuel-fired electric 

utility steam generating units (utility boilers and IGCC units) 

or stationary combustion turbines in the period of analysis. 

Accordingly, 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. 
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In light of the interest among governmental entities, the 

EPA initiated consultations with governmental entities while 

formulating the provisions of the proposed standards for newly 

constructed EGUs. This outreach regarded planned actions for 

new, reconstructed, modified and existing sources. As described 

in the UMRA discussion in the preamble to the proposed standards 

of performance for GHG emissions from new EGUs (79 FR 1500 and1501, January 8, 2014), the EPA consulted with the following 10 

national organizations representing state and local elected 

officials: (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. On February 

26, 2014, the EPA re-engaged with those governmental entities to 

provide a pre-proposal update on the emission guidelines for 

existing EGUs and emission standards for modified and 

reconstructed EGUs. 

While formulating the provisions of these proposed 

standards, the EPA also considered the input provided over the 

course of the extensive stakeholder outreach conducted by the 

EPA (see section II.G. of this preamble). 
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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 Executive Order 

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. 

However, as described in the Federalism discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501, January 8, 2014), the EPA 

consulted with state and local officials in the process of 

developing the proposed standards for newly constructed EGUs. 

This outreach regarded planned actions for new, reconstructed, 

modified and existing sources. The EPA engaged 10 national 

organizations representing state and local elected officials. 

The UMRA discussion in the preamble to the proposed standards of 

performance for GHG emissions from new EGUs (79 FR 1500 and1501, January 8, 2014) includes a description of the 

consultation. In addition, on February 26, 2014, the EPA reengaged with those governmental entities to provide a preproposal update on the emission guidelines for existing EGUs and 
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emission standards for modified and reconstructed EGUs. While 

formulating the provisions of these proposed standards, the EPA 

also considered the input provided over the course of the 

extensive stakeholder outreach conducted by the EPA (see section 

II.G. of this preamble). In the spirit of Executive Order 13132 

and consistent with the EPA policy to promote communications 

between the EPA and state and local governments, the EPA 

specifically solicits comment on this proposed action from state 

and local officials. 

F. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments 

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

would neither impose substantial direct compliance costs on 

tribal governments, nor preempt Tribal law. This proposed rule 

would impose requirements on owners and operators of 

reconstructed and modified EGUs. The EPA is aware of three coalfired EGUs located in Indian Country but is not aware of any 

EGUs owned or operated by tribal entities. The EPA notes that 

this proposal would only affect existing sources such as the 

three coal-fired EGUs located in Indian Country, if those EGUs 

were to take actions constituting modifications or 

reconstructions as defined under the EPA’s NSPS regulations. 

However, as previously stated the EPA expects few, if any, 
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modified or reconstructed EGUs in the period of analysis. Thus, 

Executive Order 13175 does not apply to this action. 

Although Executive Order 13175 does not apply to this 

action, the EPA conducted outreach to tribal environmental staff 

and offered consultation with tribal officials in developing 

this action. Because the EPA is aware of tribal interest in 

carbon pollution standards for the power sector, prior to 

proposal of GHG standards for new power plants, the EPA offered 

consultation with tribal officials early in the process of 

developing the proposed regulation to permit them to have 

meaningful and timely input into its development. The EPA’s 

consultation regarded planned actions for new, reconstructed, 

modified, and existing sources. The Consultation and 

Coordination with Indian Tribal Governments discussion in the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1501, January 8, 2014) includes a 

description of that consultation. 

During development of this proposed regulation, 

consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA’s development of 

both the NSPS for modified and reconstructed EGUs and emission 

guidelines for existing EGUs and offered consultation. None have 

requested consultation. Tribes were invited to participate in 

the national informational webinar held August 27, 2013, and to 
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which tribes were invited. In addition, a consultation/outreach 

meeting was held on September 9, 2013, with tribal 

representatives from some of the 584 tribes. The EPA also met 

with tribal environmental staff with the National Tribal Air 

Association, by teleconference, on July 25, 2013, and December 

19, 2013. In those teleconferences, the EPA provided background 

information on the GHG emission guidelines to be developed and a 

summary of issues being explored by the agency. Additional 

detail regarding this stakeholder outreach is included in the 

preamble to the emission guidelines for existing affected 

electric utility generating units being proposed in a separate 

action today. The EPA also held a series of listening sessions 

prior to proposal of GHG standards for new power plants. 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 during the public comment period, to inform 

them of the content of this proposal, as well as offer further 

consultation with tribal elected officials where it is 

appropriate. We specifically solicit additional comment from 

tribal officials on this proposed rule. 

G. Executive Order 13045, Protection of Children From 

Environmental Health Risks and Safety Risks 
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The EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying to those regulatory actions that 

concern health or safety risks, such that the analysis required 

under section 5-501 of the Order has the potential to influence 

the regulation. This action is not subject to Executive Order 

13045 because it is based solely on technology performance.

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

This proposed action is not a “significant energy action” 

as defined in Executive Order 13211 (66 FR 28355, May 22, 2001) 

because it is not likely to have a significant adverse effect on 

the supply, distribution, or use of energy. As previously 

stated, the EPA expects few, if any, reconstructed or modified 

EGUs in the period of analysis andThis proposed action is not 

anticipated to have impacts on emissions, costs or energy supply 

decisions for the affected electric utility industry to be 

minimal as a result. 

I. National Technology Transfer and Advancement Act 

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

15 U.S.C. 272 note) directs the EPA to use VCS in their 

regulatory and procurement activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. VCS 

are technical standards (e.g., materials specifications, test 

methods, sampling procedures, business practices) developed or 

Comment [A46]: This should reference the 

explanation for this statement 

EPA Response: Text has been added. 

Comment [A47]: Should ANSI Standard C12-20 

be mentioned here (see, e.g., proposed section 

60.46Da(f)(4))? 

EPA response: Section has been updated. 
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adopted by one or more voluntary consensus bodies. The NTTAA 

directs the EPA to provide Congress, through annual reports to 

the OMB, with explanations when an agency does not use available 

and applicable VCS. 

This proposed rulemaking involves technical standards. The 

EPA proposes to use the following standards in this proposed 

rule: ASTM D5287388-12-08 (Standard Classification of Coals by 

RankStandard Practice for Automatic Sampling of Gaseous Fuels), 

ASTM D396-13c4057-06 (Standard Specification for Fuel 

OilsStandard Practice for Manual Sampling of Petroleum and 

Petroleum Products), and ASTM D4177-95(2010)975-14 (Standard 

Specification for Diesel Fuel OilsStandard Practice for 

Automatic Sampling of Petroleum and Petroleum Products), D3699-

13b (Standard Specification for Kerosene), D6751-12 (Standard 

Specification for Biodiesel Fuel Blend Stock (B100) for Middle 

Distillate Fuels), ASTM D7467-13 (Standard Specification for 

Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and ANSI C12.20 

(American National Standard for Electricity Meters - 0.2 and 0.5 

Accuracy Classes). The EPA is proposing use of Appendices A, B, 

D, F and G to 40 CFR part 75; these Appendices contain standards 

that have already been reviewed under the NTTAA. 

The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 
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potentially-applicable VCS and to explain why such standards 

should be used in this action. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

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

establishes federal executive policy on environmental justice. 

Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies and activities 

on minority populations and low-income populations in the U.S. 

 This proposed rule limits GHG emissions from modified and 

reconstructed fossil fuel-fired electric utility steam 

generating units (utility boilers and IGCC units) and stationary 

combustion turbines by establishing national emission standards 

for CO2. The EPA has determined that this proposed rule would not 

result in disproportionately high and adverse human health or 

environmental effects on minority, low-income and indigenous 

populations because it does not affect the level of protection 

provided to human health or the environment. As previously 

stated, the EPA expects few, if any, modified or reconstructed 

fossil fuel-fired electric utility steam generating units 
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(utility boilers and IGCC units) or stationary combustion 

turbines in the period of analysis. 

XII. Statutory Authority 

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
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Carbon Pollution Standards for Modified and Reconstructed Power 

Plants: Standards of Performance for Greenhouse Gas Emissions 

from Modified and Reconstructed Stationary Sources: Electric 

Utility Generating Units

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List of Subjects 

40 CFR Part 60 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements. 

___________________ 

Dated: MONTH XX, 2014. 

____________________ 

Gina McCarthy, 

Administrator.
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Proposed Rule Amendment with ChangesAmended Regulatory Text

The Environmental Protection Agency proposed rule amending 

40 CFR parts 60, 70, 71, which was published atOn January 8, 

2014, (79 FR 1430), January 8, 2014, the EPA proposed amendments 

to the regulatory text of subparts Da and KKKK and, as an 

alternative to amending subparts Da and KKKK, to create a new 

subpart (subpart TTTT) to include GHG standards for new EGUs. To 

facilitate understanding the amendments being proposed in this 

proposal, we are providing a Technical Support DocumentTSD in 

the docket for this rulemaking in track changes that shows the 

proposed amendments considering the amendments proposed in 

previous the January 8, 2014, proposalFederal register 

publication. 

Comment [A48]: General Comment: General 

Tribal implications should be clarified in the 

regulatory text where appropriate. For example, the 

text currently only notes that tribal agencies can 

implement/enforce in § 60.5575, pg. 35). 

EPA: We will clarify the regulatory text as 

appropriate.