1

Fellner, Christian

From: Wayland, Robertj

Sent: Wednesday, May 28, 2014 7:04 PM

To: Higgins, Cortney

Cc: Culligan, Kevin; Hutson, Nick; Fellner, Christian; Johnson, Mary

Subject: Revised 111(b) Preamble

Attachments: EO12866_GHG EGU ModifiedSources 2060-AR88 Proposal__20140528_RLSO.docx

Cortney ‐ 

  

Attached is the revised mods/recon package.  Please let Kevin/Nick know if there are any questions/concerns.

  

bob

Robert J. Wayland, Ph.D.

Leader, Energy Strategies Group

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Mail Code D243‐01

Research Triangle Park, North Carolina 27709

 

Office:  (919) 541‐1045

Cell:     (919) 306‐2290

Fax:     (919) 541‐5450

 

Email:  wayland.robertj@epa.gov

 

**************************************

DRAFT/Deliberative Document ‐ FOIA EXEMPT

**************************************
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 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 

Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection Agency (EPA) is proposing 

standards of performance for emissions of greenhouse gases from 

affected modified and reconstructed fossil fuel-fired electric 

generating units. Specifically, the EPA is proposing standards 

to limit emissions of carbon dioxide from modified and 

reconstructed utility steam generating units and from natural 

gas-fired stationary combustion turbines. This rule, as 

proposed, would continue progress already underway to reduce 

carbon dioxide emissions from the electric power sector in the 

United States. 

Natural gas-fired combustion turbines that operateThis rule, as 

peaking units - those that supply one-third or less of their 

potential to the grid, are not covered by today’s proposal. For 

affected modified fossil fuel-fired proposed, would continue 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 2 of 181

progress already underway to reduce carbon dioxide emissions 

from the electric utility steam generating units (utility 

boilers and integrated gasification combined cycle units), the 

EPA is co-proposing two alternative standards of performance. 

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 

resultpower sector 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, 
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Page 3 of 181

the EPA is proposing standards of performance based on the most 

efficient generating technology that is applicable to each 

category of units. This standard would not be affected by the 

submittal of a CAA section 111(d) planthe United States.

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 
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Page 4 of 181

Existing Sources for information on public hearings for both 

actions. Additionally, information for the joint public hearings 

will be posted on the following website: 

http://www2.epa.gov/carbon-pollution-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. 

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. 

Mail: Send your comments to the EPA Docket Center, U.S. 
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Page 5 of 181

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

DC 20460, Attn: Docket ID No. EPA-HQ-OAR-2013-0603. Comments 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 Federal 

holidays), and special arrangements should be made for 

deliveries of boxed information. 

 Instructions: All submissions must include the agency name 

and docket ID number (EPA-HQ-OAR-2013-0603). 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 

http://www.regulations.gov or email. Send or deliver information 

identified as CBI only to the following address: Roberto 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 6 of 181

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 

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

without going through http://www.regulations.gov, your email 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 7 of 181

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 

Reading Room is (202)566-1744, and the telephone number for the 

Air Docket is (202)566-1742. Visit the EPA Docket Center 
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Page 8 of 181

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 

defined as follows: 

AEO Annual Energy Outlook 
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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 

OFR Overfire Air 

OMB Office of Management and Budget 

PC Pulverized Coal 
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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 

IV. Rationale for Reliance on Rational Basis to Regulate GHG 

from Fossil Fuel-fired EGUs 

A. Rational Basis and Endangerment Finding 

B. Source Categories 
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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 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 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 
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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. 

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 
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utility steam generating units and natural gas-fired 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 fuelfired 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 

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 

Most 

efficient 

Co-proposed Alternative #1 
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Boilers and 

IGCC Units 

generation 

at the 

affected 

source 

achievable 

through a 

combination 

of best 

operating 

practices 

and 

equipment 

upgrades 

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 ≤

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) 

implementing authority from the 

results of an energy efficiency 

improvement audit. 
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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. 

For the reasons discussed in the “Legal Memorandum1” 

supporting document in the docket for the rulemaking for CO2

emissions from existing EGUs under section 111(d), 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 

 

1 The “Legal Memorandum” supporting document is available in the 

rulemaking docket for the proposed emission guidelines for 

existing source power plants, Docket ID: EPA-HQ-OAR-2013-0602.”
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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 

other.2 The EPA also intends that the standards applicable to the 

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

severable and that if those standards were over-turned, the 

standards applicable to 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. 

 

2 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.”). 
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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 

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)3 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 

 

3 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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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 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 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 

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.4

B. Overview 

 

4 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 3percent 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. 
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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)5 meets the definition of “air pollutant” 

in the CAA,6 and premised its decision in AEP v. Connecticut7

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. 

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 new (including modified) 

stationary sources from listed source categories to limit 

emissions of air pollutants to the environment, and the EPA’s 

implementing regulations provide that new sources include 

reconstructed sources8. 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 

 

5 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).

6 549 U.S. 497, 520 (2007). 

7 131 S.Ct. 2527, 2537-38 (2011).

8 40 CFR part 60 subpart A
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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 

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. Natural gas-fired stationary combustion 

turbines that supply less than one-third of their potential 

electric output to the grid are not subject to standards in 

today’s proposal. 
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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.9

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 

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.10

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 

 

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

10 40 CFR 60.15(b).
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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 

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.
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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 

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 
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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. 

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 co-
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proposed 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 

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

Legal Memorandum11, that an existing source would continue to be 

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

source, 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. 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 

 

11 “Legal Memorandum for Proposed Carbon Pollution Guidelines for 

Existing Power Plants” Technical Support Document available in 

rulemaking docket ID: EPA-HQ-OAR-2013-0602.-
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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 

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

temperature and pressure, even if the boiler was not originally 

designed to do so12). 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 

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 Memorandum13, 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? 

 

12 Steam with higher temperature and pressure has more thermal 

energy which can be more efficiently converted to electrical 

energy.

13 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-2013-0602.Add cite to legal memo
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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 

111(d) plan would remain subject to those requirements, even 

after reconstruction. 

9. How is EPA proposing to codify the requirements? 

In the January 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. 
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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? 

 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 
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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. 

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
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Category NAICS 

Code 

Examples of Potentially Affected 

Entities 

Industry 221112 Fossil fuel electric power generating 

units. 

Federal 

Government 

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government 

221112b Fossil fuel electric power generating 

units owned by municipalities. 

Tribal 

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

a Includes 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 
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In this section14, 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 

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 known as 

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

Endangerment Finding, which focused on public health and public 

welfare impacts within the U.S.,United States, the Administrator 

found that elevated concentrations of GHGs in the atmosphere may 

reasonably be anticipated to endanger public health and welfare 

of current and future generations. We summarize these adverse 

effects of GHGs on public health and welfare briefly here.16

 

14 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. 

15 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases underUnder Section 202(a) of the Clean Air Act,” 74 FRFed. 

Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”). 16 The January 8, 2014, preamble to the proposed GHG standards 

for new EGUs (79 FR 1430) and the RIA supporting that proposal 
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1. Public Health Impacts Detailed in the 2009 Endangerment 

Finding17

Climate change caused by human emissions of GHGs threatens 

public health in multiple ways. By raising average temperatures, 

climate change increases the likelihood of heat waves, which are 

associated with increased deaths and illnesses. While climate 

change also increases the likelihood of reductions in coldrelated mortality, evidence indicates that the increases in heat 

mortality will be larger than the decreases in cold mortality in 

the U.S.United States. Compared to a future without climate 

change, climate change is expected to increase ozone pollution 

over broad areas of the U.S., including 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 

 

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.

17 “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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or frequency of extreme weather associated with climate change, 

such as increased hurricane intensity, increased frequency of 

intense storms, and heavy precipitation. Increased coastal 

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

cause increased drownings and other health impacts. Children, 

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

climate-related health effects. 

2. Public Welfare Impacts Detailed in the 2009 Endangerment 

Finding18

Climate change caused by human emissions of GHGs also 

threatens public welfare in multiple ways. 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 

 

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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change may exacerbate ongoing environmental pressures in certain 

settlements, particularly in Alaskan indigenous communities. 

Climate change also is very likely to fundamentally rearrange 

U.S. ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

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

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

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

security issues for the U.S.

3. 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 
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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 

such 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 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 
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strengthens the case that GHGs endanger public health and 

welfare.

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 NRCNational 

Research Council of the National Academies assessment projected 

that concentrations by the end of the century would increase to 

levels that the Earth has not experienced for millions of 

years.19 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.”20

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, 

 

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

1.

20 Id., p.138.
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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.21 

Moreover, due to the time-lags inherent in the Earth’s 

climate, the Climate 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 

ImpactsNational Climate Assessment” assessment22 emphasizes that 

climate change is already happening now and it is happening in 

the U.S.United States. 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 changesincreases in 

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

These assessments underscore the urgency of reducing 

emissions now: today’s emissions will otherwise lead to raised 

 

21 National Research Council, Climate Stabilization Targets, 

p. 3. 

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

the United States: The Third National Climate Assessment, May 

2014 Available at http://nca2014.globalchange.gov/. 

http://nca2014.globalchange.gov/.
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atmospheric concentrations for thousands of years, and raised 

Earth 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 

CO2carbon dioxide in the atmosphere continues to rise 

dramatically. In 2009, the year of the Endangerment Finding, the 

average concentration of CO2carbon dioxide as measured on top of 

Mauna Loa was 387 parts per million (ppm)..23 The average 

concentration in 2013 was 396 ppm.parts per million. And the 

monthly concentration inAprilin April of 2014 was 401 ppmparts 

per million, the first time a monthly average has exceeded 400 

ppmparts per million since record keeping began at Mauna Loa in 

1958, and for at least the past 800,000 years according to ice 

core records.24

B. GHG Emissions from Fossil Fuel-fired EGUs 

Fossil fuel-fired EGUselectric utility generating units 

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

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

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

emitters. This section describes the amounts of those emissions 

 

23 

ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt

24 http://www.esrl.noaa.gov/gmd/ccgg/trends/
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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 Sinks25 (the U.S. GHG Inventory) to comply with 

commitments under the United Nations Framework Convention on 

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

trends, is organized by industrial sectors. It provides the 

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

anthropogenic emissions and sinks26 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.))27

SECTOR 1990 2005 2012 

Energy 5,260.1 6,243.5 5,498.9

Industrial Processes 316.1 334.9 334.4

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 

 

25 “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. 

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

forests or underground or deep sea reservoirs of carbon dioxide.

27 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. 
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Waste 165.0 133.2 124.0 

Total Emissions 6,233.2 7,253.8 6,525.6 

Land Use, Land-Use 

Change and Forestry 

(Sinks) (831.3) (1,030.7) (979.3)

Net Emissions (Sources 

and Sinks) 5,402.1 6,223.1 5,546.3 

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.7 percent of total 

2012 GHG emissions.28 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.29

Table 4 below presents total CO2 emissions from fossil fuel-fired 

EGUs, for years 1990, 2005 and 2012. 

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

Combustion of Fossil Fuels (Tg CO2)30

 

28 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. 

29 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. 

30 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 

1,820.8 2,402.1 2,022.7 
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C. The Utility Power Sector 

Electricity in the U.S.United States is generated by a 

range of sources - from power plants that use fossil fuels such 

aslike coal, oil, and natural gas, to non-fossil sources, such 

as nuclear, solar, wind and hydroelectric power. Currently, the 

majorityIn 2013, over 67 percent of power in the U.S. iswas

generated from the combustion of coal, natural gas, and other 

fossil fuels., over 40 percent from coal and over 26 percent 

from natural gas.31 In recent years, though, the proportion of 

new renewable generation coming on line has increased 

dramatically. For instance, over 38 percent of new generating 

capacity (over 5 GW out of 13.5 GW) built in 2013 used renewable 

power generation technologies.32 

 

31 U.S. Energy Information Administration (EIA), “Table 7.2b 

Electricity Net Generation: Electric Power Sector Electric Power 

Sector,” data from April 2014 Monthly Energy Review, release 

date April 25, 2014. Available at: 

http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&

freq=m 

32 Based on Table 6.3 (New Utility Scale Generating Units by 

Operating Company, Plant, Month, and Year) of the U.S. Energy 

Total CO2 emissions from 

fossil fuel combustion 

EGUs 

 - from coal 1,547.6 1,983.8 1,511.2

 - from natural gas 175.3 318.8 492.2 

 - from petroleum 97.5 99.2 18.8 
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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 

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. 

 

Information Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable energy sources: 

solar, wind, hydro, geothermal, landfill gas, and biomass. 

Available at: 

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e

pmt_6_03 
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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).33 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 111.34 

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

and then promulgates “standards of performance” for “new 

sources” in the category.35 A “new source” is “any stationary 

source, the construction or modification of which is commenced 

after,” in general, the date of the proposal.36 A modification is 

 

33 CAA section 111(b)(1)(A). 

34 See generally 40 CFR subparts D-MMMM.

35 CAA section 111(b)(1)(B).

36 CAA section 111(a)(2).
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“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.”37 The EPA, through 

regulations, has determined that certain types of changes are 

exempt from consideration as a modification.38

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.39 

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 (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. 

 

37 CAA section 111(a)(4).

38 40 CFR 60.2, 60.14(e).

39 40 CFR 60.15.
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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 rate-based 

standard). Generally, the EPA does not prescribe a particular 

technological system that must be used to comply with a standard 

of performance. Rather, sources generally may select any measure 

or combination of measures that will achieve the emissions level 

of the standard.40 In establishing standards of performance, the 

EPA has significant discretion to create subcategories based on 

source type, class or size.41 

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 

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 

 

40 CAA section 111(b)(5) 

41 CAA section 111(b)(2) 
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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),42 and the EPA promulgated the first set of 

standards of performance for sources in that category, which it 

codified in subpart D.43 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),44 and the EPA promulgated 

standards of performance for that source category in 1979, which 

the EPA codified in subpart GG.45 

The EPA has revised those regulations, and in some 

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

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 

 

42 36 FR 5931 (March 31, 1971) 

43 “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;. 

44 42 FR 53,657 (October 3, 1977). 

45 “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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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.46 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.47 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.48

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

Circuit, contending, among other issues, that the rule was 

required to include standards of performance for GHG emissions 

 

46 44 FR 33,580 (June 11, 1979)

47 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (March 

20, 2009).

48 ”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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from EGUs.49 The January 8, 2014 preamble to the proposed CO2

standards for new EGUs50 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. 

The EPA has conducted subsequent outreach sessions: the 

vast majority of which occurred between September 2013 and 

 

49State of New York, et al. v. EPA, No. 06–1322. 50 79 FR 1430
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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, 

to help understand the issues related to large industrial 

purchasers of electricity. Agency officials engaged with 
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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 regulations51 define an NSPS 

“modification” as a physical or operational change that 

increases the source’s maximum achievable hourly rate of 

 

51 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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emissions, with certain exemptions.52 

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. 

under the current NSPS regulations.53 

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 

 

52 40 CFR 60.2, 60.14. 

53 40 CFR 60.14.
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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 are 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)54, 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.55 The EPA 

subsequently withdrew that proposed rulemaking.56 While many of 

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

responding to those comments in this rulemaking, and if members 

 

54 The proposal was subsequently withdrawn with the publication 

of the January 8, 2014 proposal.

55 The comments are available in the rulemaking docket. Docket 

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

56 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.57 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 

 

57 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 

discourageavoid creating any regulatory incentive to perpetuate

the perpetuationoperation 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, a 
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discussion of any economic or technical limitations the facility 

may have in complying with the applicable standards of 

performance after the proposed replacements. The regulations 

require the EPA to determine, within a specified time period, 

whether the proposed replacement constitutes a reconstruction.58

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 

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 

 

58 40 CFR 60.15(d)–(e) 
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reconstructions during the analysis period (i.e., 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 
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solicits comment on the delineation between a reconstructed 

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 (79 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 
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to Reconstructions 

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.59 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 

 

59 The comments are available in the rulemaking docket. Docket 

ID: EPA-HQ-OAR-2011-0660.
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EPA exclude the cost of retrofitting CCS technology in order to 

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 similar applicability 

requirements, for purposes of this rule, that the EPA proposed 
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in the January 2014 proposal.60,61 This section describes those 

requirements. 

To be considered an EGU under Subpart Da the boiler or IGCC 

must be: (1) capable of combusting more than 250 MMBtu/h heat 

input of fossil fuel,62 (2) constructed for the purpose of 

supplying more than one-third of its potential net- electric 

output capacity to any utility power distribution system for 

sale63 (that is, to the grid), and (3) constructed for the 

purpose of supplying more than 25 MW net-electric output to the 

grid.64 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 output to the grid. This proposed change 

 

60 See 79 FR 1,445 and 1,446. 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 1,446, are not relevant for 

purposes of the present rulemaking concerning modifications and 

reconstructions. 

61 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. 

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

63 40 CFR 60.41Da (definition of (“Electric utility steamgenerating unit”). 

64 Id. 
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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 

combustion turbines that combust over 90 percent on a 3 year 

rolling average basis are subject to a numerical GHG standard. 
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We are proposing and soliciting comment on an additional

amendment, not included in the January 2014 proposal, to clarify 

that net-electric sales, for applicability purposes, includes 

electricity supplied to other facilities that produce 

electricity to offset auxiliary loads. Without this amendment, 

smaller EGUs that are co-located with larger EGUs could claim

that they do not meet the rule applicability criteria because

their generated power is used to offset the parasitic loads of 

the larger facility. 

Consistent with the January 2014 proposal, we 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 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 
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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 through 

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” 

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 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 
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definition of IGCC in subpart Da (or subpart TTTT) and 

stationary combustion turbine in subpart KKKK (or subpart TTTT). 

This action proposes to set standards only for emissions of 

CO2. The pollutant we propose to regulate could also be 

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

proposing to 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 boilers and 

IGCC units that were constructed for the purpose of selling onethird 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 

boilers under Subpart Db or stationary 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 

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

MWh or less to the grid. These units only account for a small 
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amount of the CO2 emissions from fossil-fuel-fired EGUs. The 

second is modified or reconstructed non-natural gas-fired 

stationary combustion turbines.65 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 outputbased 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 document, 

we sometimes refer to “net energy output” as “net output.” 

 

65 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). 
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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 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 1,477. 

We are proposing additional amendments to the definition of 

useful thermal output. The current definition excludes energy 

used to enhance the performance of the affected facility from 

being considered as useful thermal output. The intent of this 

restriction is to clarify that thermal energy that is directly 

used by the affected facility to create additional output (e.g., 

the economizer) are not counted as useful thermal output. 

Without this restriction, the energy could be doubled counted – 

once as useful thermal output and again as electric output. This 

could also be interpreted to exclude thermal energy used to 

reduce fuel moisture (e.g., coal drying) as being useful thermal 
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output because it enhances the performance of the affected 

facility. However, coal-drying could be done at a separate 

offsite facility by an industrial boiler prior to delivery at 

the power plant. In that scenario, the CO2 emissions from the 

industrial boiler would not be included when the coal-fired 

boiler determined compliance with the proposed standards even 

though the overall emissions to the atmosphere could be greater 

than for an integrated system where the thermal energy for the 

drying is supplied by the power plant. Therefore, we are 

proposing that thermal energy used for reducing fuel moisture 

(e.g., coal drying) be counted as useful thermal output. This 

approach would avoid potential disincentives for integrating 

coal drying at power plants. We are also proposing that default 

useful thermal output be measured relative to standard ambient 

temperature and pressure (25 oC and 14.5 psi) instead of ISO 

conditions (15 oC and 14.7 psi). In other words, at SATP 

conditions, the amount of useful thermal energy (commonly called 

“enthalpy”) is considered to be zero. The rationale behind 

providing a relative measurement of thermal output is so that 

measurements are made relative to the energy content in the 

makeup water. We have concluded that standard ambient conditions 

are more representative than ISO conditions of the energy 

content in the makeup water. In addition, we are proposing the 

CHP facilities with high energy condensate return would measure 
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the energy in the condensate when determining the useful thermal 

output. In addition, we are soliciting comment on providing 

credit for useful thermal output in the range of 75 to 100 

percent. 

1. Emission Standards for Modified Utility Boilers and IGCC 

Units 

The EPA is proposing that affected modified utility boilers 

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, 
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and equipment upgrades that have the potential to improve heat 

rate, on average, by an additional 2 percent.66 The EPA also 

proposes that the unit-specific emission rates that would apply 

to affected modified utility boilers and IGCC units would be no 

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. 

 

66 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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As we discuss in the Legal Memorandum67, 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 

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) 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 all aspects of this co-

 

67 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-2013-0602.
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proposal that, including whether the 111(b) implementing 

authority would determine the unit-specific 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 

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 
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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 

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. Similarly, the 

EPA solicits comment on whether modified utility boilers and 
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IGCC units subject to a Section 111(d) plan could be evaluated 

on a case-by-case basis to determine whether, as their section 

111(b) standard, they should be required to continue to be 

subject to the 111(d) requirements to which they are subject. 

One method of doing this might be through a delegation of the 

EPA's 111(b) authority over that source to the state 

administering the applicable 111(d) plan. 

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. 

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 
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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. 

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 
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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.68 

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 Memorandum69’. 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 

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 

 

68 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.

69 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-2013-0602.Add cite to legal memo
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option of allowing the affected source to meet a unit-specific 

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

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; 
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(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 

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 
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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.70 

C. Startup, Shutdown and Malfunction Requirements 

We are proposing the standards in this rule apply at all 

times, including during periods of startup and shutdown. This 

section provides a summary of the requirements. 

1. Startups and shutdowns 

Consistent with Sierra Club v. EPA,71 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, 

 

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

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

1,448. 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).

71 551 F.3d 1019 (D.C. Cir. 2008). 
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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 

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, the impact of these periods on the 

total average is expected to be minimal. 

2. Malfunctions 

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as “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 
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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. 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 
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performance of units that are malfunctioning is not “reasonably” 

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

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

determining the extent of data-gathering necessary to solve a 

problem. We generally defer to an agency's decision to proceed 

on the basis of imperfect scientific information, rather than to 

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

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

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

even any upset provision can anticipate all upset situations. 

After a certain point, the transgression of regulatory limits 

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

strikes, sabotage, operator intoxication or insanity, and a 

variety of other eventualities, must be a matter for the 

administrative exercise of case-by-case enforcement discretion, 

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

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. 
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In the event that a source fails to comply with the 

applicable CAA section 111 standards as a result of a 

malfunction event, the EPA would determine an appropriate 

response based on, among other things, the good faith efforts of 

the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. The 

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

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

infrequent, not reasonably preventable” and was not instead 

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

CFR § 60.2 (definition of malfunction). 

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 
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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 

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 
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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 

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.”).72 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). 

 

72 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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The same logic applies to EPA administrative enforcement 

actions. 

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 2014, proposal. This section provides a 

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

1,450 and 1,451. 

Today’s proposed rule would require owners or operators of 

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

operate continuous emission monitoring systems (CEMS) to measure 

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

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

determine hourly CO2 mass emissions rates (tons/h). 

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 
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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. 

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. 
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 Certain variations from and additions to the basic Part 75 

monitoring would be required and are detailed in the January 

2014 proposal (see 79 FR 1,451). 

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 2014 proposal 

(see 79 FR 1,451). 

The proposed rule would require 95 percent of the operating 

hours in each compliance period (including the compliance 

periods for the intermediate emission limits) to be valid hours, 

i.e., operating hours in which quality-assured data are 

collected and recorded for all of the parameters used to 

calculate CO2 mass emissions. EGU owners or operators would have 

the option to use backup monitoring systems, as provided in §§ 

75.10(e) and 75.20(d), to help meet this proposed data capture 

requirement. 

We are proposing two additional amendments to the 

monitoring requirements. First, we are proposing that

measurements of electricity output (both gross and net) be 

measured using 0.2 class electricity metering instrumentation 

and calibration procedures as specified under ANSI Standards No. 

C12.20. Second, we are proposing that hours with no gross 

generation or where the gross generation is less than the 

auxiliary loads be reported as zero instead of a negative value. 
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Steam is the most common type of useful thermal output for 

NSPS purposes. The amount of useful energy flowing in a steam 

header is measured with the following components: a flow meter 

(to determine the volumetric flow rate of steam in cubic meters 

per hour or the mass flow rate in kilograms per hour), a 

thermocouple or resistance temperature detector (to determine 

the temperature of the steam), and an electromechanical 

transmitter (to determine the pressure of the steam). The 

accuracy of the measurement of useful thermal energy calculation 

is the product of the accuracies of the flow, temperature, and 

pressure measurements. The January 2014 proposal includes 

requirements for the measurement of useful thermal output from 

combined heat and power systems, but does not include associated 

specifications for quality assurance of the underlying flow, 

temperature, and pressure measurements. The EPA is considering 

and soliciting comment on requiring that manufacturer 

maintenance recommendations be followed and include, at a 

minimum, annual inspection and calibration requirements for the 

flow meters, thermocouples or resistance temperature detectors 

(RTDs), and electromechanical transmitters used to acquire the 

steam flow rates and properties integral to calculation of 

useful thermal output. 

The EPA is soliciting information on: (1) the technologies 

that are appropriate for continuous monitoring of useful thermal 
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output, and (2) whether the EPA should specify the technologies 

to be used. For example, should technology choices be limited to 

ultrasonic, coriolis, averaging pitot tube with 2 differential 

pressure cells, or shedding vortex since they appear to be the 

most accurate? The EPA is also soliciting information on the 

costs of operation of these systems, including ongoing 

maintenance, calibration intervals, and other quality assurance 

costs. Finally, with regard to the quality assurance 

requirements for continuous monitoring of useful thermal output, 

the EPA is soliciting comment on the appropriate ASTM, ANSI, or 

ASME standards (e.g., ASME PTC 4-2013, ASME PTC 19.5-2004 and 

ASME MFC-6-2013) that should be incorporated by reference into 

the final standards of performance. This would be an alternate 

to specifying technologies in order to ensure monitoring data 

are of sufficient quality for demonstrating compliance with the 

proposed efficiency standards. 

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 2014 proposal. This 

section provides a summary of the requirements. For additional 

detail, see 79 FR 1,451. 

In accordance with § section 75.64(a), the proposed rule 

would require an EGU owner or operator to begin reporting 
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emissions data when monitoring system certification is completed 

or when the 180-day window in § section 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 § section 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. 

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 2014 proposal. This 

section provides a summary of the requirements. For additional 

detail, see 79 FR 1,451. 

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 
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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 

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 

were proposed for new sources in the January 2014 proposal. This 

section provides a summary of the requirements. For additional 

detail, see 79 FR 1,451 and 1,452. 
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Today’s proposed rule would require an EGU owner or 

operator to comply with the applicable notification requirements 

in §§ 60.7(a)(1) and (a)(3), § 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. 

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). 
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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 

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. 

IV. Rationale for Reliance on Rational Basis to Regulate GHG 

from Fossil Fuel-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 
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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 

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 1,452 through 1,456; 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 
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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 

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 
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new subpart, TTTT. See 79 FR 1,452 through 1,454; 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 

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. 

The following four proposed applicability criteria are 

consistent with the January 2014 proposal. First, 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 

GHG emissions are included as part of the overall GHG emissions 

from the affected source. Also consistent with the January 2014 

proposal, we are considering including in the definition of the 

affected facility co-located non-emitting energy generation 
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equipment included in the facility operating permit but that is 

not integrated into the operation of the affected facility.

Second, 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. 

Third, we are proposing to apply the one-third sales 

criterion on a rolling three year basis instead of an annual 

basis for stationary combustion turbines for multiple reasons. 

First, extending the period to three years would ensure that the 

CO2 standards apply only to intermediate and base load EGUs by 

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. We are soliciting comment 
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on ways to address potential complications resulting from having 

different time periods for applicability and the actual emission 

standard. For example, a stationary combustion turbine that runs 

at a 60 percent capacity factor for years one and two but only a 

5 percent capacity factor on year three would meet the proposed 

applicability requirements for all three years (since 

applicability is determined on a three-year rolling average 

basis). However, the emission standard is on a 12-month rolling 

average basis and if the hours of operation on year three are 

even and spread out in each month the facility likely operated 

at low loads and may have difficulty achieving the proposed 

standard. This could be further complicated if the facility 

burned fuels other than natural gas during year 3 since the 90 

percent natural gas applicability would still apply even though 

other fuels were burned during the emissions standard period. 

Finally, 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 net-electric output for 

qualifying CHP facilities (i.e., the clause would read, “the 
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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 thirdparty-owned CHP. 

The rationale for following applicability criteria areis

different thanfrom 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 andan EGU. These criteria include that 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 thethis 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 exempt 

facilities that are capable of combusting fossil fuel, but burn 
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primarily non fossil fuels. These facilities (e.g., wood-fired 

EGUs) typically are inherently less efficient than fossil fuelfired EGUs, and we are soliciting comment on if we should 

subcategorize boilers and IGCC facilities thatwhere 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. 

In the January 2014 proposal, we proposed a dual electric 

sales applicability criterion for stationary combustion turbines 

of 219,000 MWh and 33 percent sales of potential electric output 

on a three-year rolling average basis. In addition, we 

specifically solicited comment on a range of 20 to 40 percent 

sales of potential electric output. However, the dual electric 

sales applicability could potentially result in the 

installation, modification or reconstruction of smaller, less 

efficient simple cycle combustion turbines rather than larger, 

more efficient simple cycle combustion turbines. For simple 

cycle combustion turbines that are smaller than approximately 70 

MW, the 219,000 MWh sales would be the determining criteria for 

whether the facility is subject to an emission standard. Smaller 

EGUs can sell over one-third of their potential electric output 

and still not be subject to a GHG emission standard. This could 

potentially place larger, more efficient simple cycle combustion 

turbines at a disadvantage since they would be limited to 

selling less (e.g., one-third) of their potential electric 

output. This could result in higher GHG emissions, and we are 

soliciting comment on approaches to minimize this outcome. One 

approach we are considering is changing the “one-third potential 

electric output” sales criteria to “the design net efficiency 
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times the potential electric output” for simple cycle combustion 

turbines. This would have the effect of allowing the most 

efficient larger simple cycle combustion turbines to sell 

approximately 38 percent of their potential electric output on a 

3-year rolling average before an emission standard would apply. 

Even the smallest aeroderivative stationary combustion turbine 

designs have efficiencies of approximately 32 percent, but these 

combustion turbine engines are smaller in size and the 219,000 

MWh sales limit would still be the controlling criterion. 

Therefore, in this approach, applicability with an emission 

standard would only be amended for the larger, more efficient 

simple cycle combustion turbines. We are soliciting comment on

if this change would be sufficient to avoid the potential 

adverse environmental impact mentioned previously or if a 

multiplication factor, such as 1.1 (we are soliciting comment on 

an appropriate factor), should be applied to the design net 

efficiency to determine the percent sales applicability 

criterion. The percent electric sales criterion would read, for 

example, “1.1 times the design net efficiency times the 

potential electric output” for simple cycle combustion turbines. 

The result of this approach is that the most efficient simple 

cycle turbines would be able to sell 42 percent of their 

potential electric output prior to becoming subject to a GHG 

standard. This is approximately equivalent to allowing 4,000 
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hours of operation on a three-year average at 90 percent load 

before a GHG standard would apply. We are also soliciting 

comment on eliminating the additional 219,000 MWh sales 

criterion for stationary combustion turbines so that smaller 

stationary combustion turbines would be subject to a GHG 

emission standard once they sell the specified percentage of 

potential electric output to the grid. This would eliminate any 

incentive to install multiple less efficient smaller stationary 

combustion turbines rather than fewer more efficient larger 

stationary combustion turbines. However, this change could also 

potentially cover a larger percentage of industrial combined 

heat and power facilities. We are therefore soliciting comment 

on if the 219,000 MWh electric sales criterion should only be 

eliminated for non-CHP stationary combustion turbines. Finally, 

we are also soliciting comment on establishing a CO2 emission 

limit in the form of an annual tonnage cap based on allowable 

emissions from smaller, less efficient combustion turbines that 

do not exceed the 33 percent and 219,000 MWh annual threshold,

regardless of hours operated. 

We are also soliciting comment on if the percent sales of 

potential electric output is sufficient to account for the 

potential increased use of simple cycle combustion turbines due 

to the expected increased percentage of electricity generated 

from renewable generation in the future. Due to the intermittent 
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nature of some renewable technologies, such as wind and solar, 

the electric grid must be balanced by using some type of quick 

response backup generation or rapid reductions in load. The EPA 

is soliciting comment on the extent to which simple cycle 

combustion turbines will be used to support additional renewable 

generation. We also solicit comment on the ability, relative 

costs and overall GHG emissions of energy storage systems (e.g., 

utility battery stations or flywheels) and on demand response 

programs to balance demand and generation from renewable 

electricity generation. 

In addition, some of the initial feedback we received from 

the regulated community in public comments74 on the January 2014 

proposal suggests that the emissions data that the EPA used in 

developing the natural gas-fired stationary combustion turbine 

standards does not completely account for degradation in 

performance over the entire life of an NGCC. Also, commenters 

noted that NGCC units are expected to operate differently in the 

future due to the increased percentage of power generated from 

renewable sources, such as wind and solar. In addition, initial 

feedback suggested that the size distinction between large and 

small stationary combustion turbines should be adjusted. 

 

74 All public comments on the January 2014 proposal are available 

in the rulemaking docket, Docket ID: EPA-HQ-OAR-2013-0495.
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The EPA is soliciting comment on whether a separate 

standard should be established for load-following (i.e., 

intermediate capacity factor) NGCC EGUs. The more stringent 

standard would apply only during periods of high annual capacity 

factors and a less stringent standard would apply during periods 

of intermediate load (e.g., when electric sales are between 33 

to 60 percent of the potential electric output). This approach 

addresses two potential issues with the standards in the January 

2014 proposal. First, certain NGCC units are designed to be 

highly efficient when operated as load-following units, but 

these design characteristics reduce the efficiency at base load. 

Conversely, the NGCC units with the highest base load design 

efficiencies are not necessarily as efficient as NGCC designed 

and intended to be used as load-following EGUs. Therefore, a 

full-load efficiency performance test would not necessarily 

result in the lowest CO2 emissions in practice. Second, NGCC 

units operating as load-following EGUs are inherently less 

efficient than NGCC units operating at base load. Establishing a 

standard that varies with load would assure that NGCC units that 

are operated as base load units are as efficient as possible and 

still account for inherent lower efficiencies at part-load 

conditions. We are also soliciting comment on whether we should 

establish a separate numerical limit for low capacity factor 
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stationary combustion turbines and/or simple cycle combustion 

turbines. 

Consistent with the January 2014 proposal, the EPA is 

proposing the size distinction between large and small 

combustion turbines be a base load heat input rating of the 

combustion turbine engine of 850 MMBtu/h. As explained in the 

January 2014 proposal, this distinction is consistent with the 

criteria pollutant NSPS for stationary combustion turbines, 

which was based on the largest aeroderivative turbine design 

available at the time. However, incremental adjustments have 

been made to aeroderivative designs and the base load rating of 

the largest aeroderivative turbines now exceeds 850 MMBtu/h. The 

EPA is soliciting comment on increasing the size distinction 

between large and small stationary combustion turbines to 900 

MMBtu/h to account for larger aeroderivative designs or to 1,000 

MMBtu/h to account for future incremental increases in base load 

ratings. Alternately, the EPA is soliciting comment on 

increasing the size distinction to between 1,300 to 1,800 

MMBtu/h. There are currently no combined cycle combustion 

turbines offered with turbine engine base load rating between 

those sizes. 

VI. Rationale for Emission Standards for Reconstructed Fossil 

Fuel-Fired Utility Boilers and IGCC Units. 

A. Overview 
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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 

its component elements.75 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 

 

75 Portland Cement Association 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 v. EPA, 665 F.3d 177 

(D.C. Cir. 2011). 
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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.76 

 The EPA must also consider that CAA section 111 is designed 

to promote the deployment, development and implementation 

of technology.7778

 

76 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 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. 

77 See discussion of case law and legislative history in the 

January 2014 proposal. 79 Fed. Reg. 1430, 1465 (cols. 1-2) 

(January 8, 2014).

78 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 
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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 1,462 

through 1,467, and incorporates by reference that discussion in 

this rulemaking. 

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.79 

 

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. 

7940 FR 58417-58418, December 16, 1975 (final NSPS modification, 

notification, and reconstruction provisions).
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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 

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 
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through a combination of best operating practices and equipment 

upgrades.80

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 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 

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. 

 

80 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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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 expected to begin operation 

in 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.81

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 

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 

 

81 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
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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.82 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 

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. 

 

82 Chapter 2, GHG Abatement Measures TSD
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However, we specifically solicit comment on whether natural 

gas reburning (NGR) and/or similar technologies83 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 

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 

 

83 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. 
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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. 

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 

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. 
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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 

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 
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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 

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 HRSG) 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 
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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 

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 
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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 

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 
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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 sources will do so. We solicit comment on any 

additional considerations that the EPA should take into 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.84

a. Technical Feasibility 

The use of supercritical steam conditions has been 

 

84 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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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 oC 

(1,120 oF) have been demonstrated at coal-fired EGUs. In 

addition, even though the majority of recently constructed coalfired 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 
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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 

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 oC (980 oF) 

and 40 percent have no steam reheat. Increasing the steam 

pressure to 20 MPa (2,900 psig) and 568 oC (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 
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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 

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 
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use of highest available subcritical steam conditions. The 

maximum viable subcritical steam parameters are 21 MPa (3,000 

psi) and 570 oC (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 

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 
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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 

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. 
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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 

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 
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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 

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.85

 

85 Advanced ultra-supercritical steam conditions are 700 – 760 oC 

(1,290 – 1,400 oF) and 36 MPa (5,000 psi) 
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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 

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 
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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 

the same as in the January 2014 proposal. This section provides 

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

1,481 and 1,482. 

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 
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standard that could be achieved under these conditions. This 

standard could potentially be high enough that it would not be a 

meaningful constraint during other parts of the year. In 

addition, operation at low load conditions can also negatively 

impact efficiency. It is likely that for some short period of 

time an EGU will operate at an unusually low load. A short 

averaging period that accounts for this operation would again 

not produce a meaningful constraint for typical loads. 

On the other hand, a 12-operating-month rolling average 

explicitly accounts for variable operating conditions, allows 

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
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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 

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 

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 
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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. 

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 supercritical86 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 

 

86 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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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, 

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 
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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 

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 
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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 

opportunity to improve the heat rate (or efficiency)87 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”88 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 

 

87 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.

88 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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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 

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 study89 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 

 

89 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.
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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 

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, 
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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 

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 
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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 

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. Hence, 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. 
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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 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 
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own best demonstrated historical performance; and (2) that the 

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 
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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 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) 

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 Memorandum90, 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 

 

90 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-20913-0602.
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state plans, the additional two percent efficiency improvement 

(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 
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111(d) plan is the date that the plan is initially submitted to 

the EPA. Although a state’s plan is still subject to the EPA’s 

approval, we 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 
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pollutants through process changes and other efficiency 

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 
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systems. We propose that the 111(d) implementing authority will 

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 the 

improvements should be. 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 5000191 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 

 

91 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. 
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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 1,481 and 1,482. 

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 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 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 rulemaking92 and is also included in the docket 

for this proposal. 

Consistent with the January 2014 proposal, the EPA proposes 

to subcategorize the turbines into the same two size-related 

subcategories currently in subpart KKKK for standards of 

performance for the combustion turbine criteria pollutants. 

These subcategories are based on whether the design heat input 

rate to the turbine engine is either 850 MMBtu/h or less, or 

greater than 850 MMBtu/h. We further propose to establish 

different standards of performance for these two subcategories. 

 

92 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.93 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 

 

93 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, 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, 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 

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 

standard, determined by the 111(d) implementing authority, based 
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on implementation of identified energy efficiency improvement 

opportunities applicable to the source. 

X. Impacts of the Proposed Action94

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 

 

94 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.95

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. 

 

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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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. 

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 
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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 $33 million (2011$) 

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.96 

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, 

 

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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January 21, 2011) and any changes made in response to the OMB 

recommendations have been documented in the docket for this 

action. In addition, the EPA prepared an analysis of the 

potential costs and benefits associated with this action. This 

analysis is contained in 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 is 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 
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(utility boilers and IGCC units) or stationary combustion 

turbines will take actions that would constitute modifications 

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 1,498 and 1,499. Although not 

anticipated, if an EGU were to modify or reconstruct, this 

proposed action would impose minimal information collection 

 

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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burden on affected sources beyond what those sources would 

already be subject to under the authorities of CAA parts 75 and 

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 
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this ICR, it is likely that an EGU’s energy metering equipment 

would need to be modified to comply with proposed net energy 

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 
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numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. 

To comment on the Agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes this 

ICR, under Docket ID number EPA-HQ-OAR-2013-0603. 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.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 
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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.); 

(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.

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 
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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 

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 
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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 

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 
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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), 

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. 
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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. 

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 
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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). 

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. 
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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 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). 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 
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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,

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 
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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 

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 
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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 

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 and 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 
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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 

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 D388-12 (Standard Classification of Coals by Rank), 

ASTM D396-13c (Standard Specification for Fuel Oils), ASTM D975-

14 (Standard Specification for Diesel Fuel Oils), 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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Page 179 of 181

(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 Changes 

The Environmental Protection Agency proposed rule amending 40 

CFR parts 60, 70, 71, which was published at79 FR 1430, January 8, 

2014, 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 

Document in the docket for this rulemaking in track changes that 

shows the proposed amendments considering the amendments proposed 

in the January 8, 2014, Federal register publication.