From: Culligan, Kevin 

Sent: Friday, May 30, 2014 4:58 PM 

To: Higgins, Cortney 

Subject: Mods rule - think this should be very close 

Would be very good for you to check language we discussed this morning and make sure I got it 

right. 

<< EO12866_GHG EGU ModifiedSources 2060-AR88 Proposal__20140530.docx >> 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

6560-50 

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

Stationary Sources: Electric Utility Generating Units 

AGENCY: Environmental Protection Agency. 

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 

utility generating units. Specifically, the EPA is proposing 

standards to limit emissions of carbon dioxide from affected 

modified and reconstructed electric 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. 

DATES: Comments on the proposed standards. Comments on the 

proposed standards must be received on or before [INSERT DATE 

120 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

Deleted: -P

Deleted: (EPA)

Deleted: 60 
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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 Carbon Pollution Emission Guidelines for Existing 

Stationary Sources: Electric Utility Generating Units, we will 

hold joint hearings on both proposed rulemakings. Please consult 

the Federal Register notice proposing Emission Guidelines for 

Existing Sources for information on public hearings for both 

actions. Additionally, information for the joint public hearings 

will be posted on the following websites: 

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

http://www2.epa.gov/cleanpowerplan. If any dates, times or 

locations of announced public hearings are changed for the 
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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(s). 

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. 

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 
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Page 4 of 182

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 

Morales, OAQPS Document Control Officer (C404-02), Office of Air 

Quality Planning and Standards, U.S. EPA, Research Triangle 

Park, NC 27711, Attention Docket ID No. EPA-HQ-OAR-2013-0603. 

Clearly mark the information 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 
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electronically within the disk or CD-ROM the specific 

information you claim as CBI. In addition to one complete 

version of the comment that includes information claimed as CBI, 

you must submit a copy of the comment that does not contain the 

information claimed as CBI for inclusion in the public docket. 

Information so marked will not be disclosed except in accordance 

with procedures set forth in 40 CFR part 2. 

 The EPA requests that you also submit a separate copy of 

your comments to the contact person identified below (see FOR 

FURTHER INFORMATION CONTACT). If the comment includes 

information you consider to be CBI or otherwise protected, you 

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

information claimed as CBI or otherwise protected. 

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

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

contact information unless you provide it in the body of your 

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

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

address will be automatically captured and included as part of 

the comment that is placed in the public docket and made 

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

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 
***E.O.12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

Page 6 of 182

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 20004. The Public Reading 

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

excluding federal holidays. The telephone number for the Public 

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

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

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

additional information about the EPA’s public docket. 

 In addition to being available in the docket, an electronic 

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

Web (WWW). Following signature, a copy of this proposed rule 
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will be posted at the following address: 

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

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 

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 

DOE/NETL Department of Energy/National Energy Technology 

Laboratory 

EGU Electric Utility Generating Unit 

EO Executive Order 
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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 

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 

OFA Overfire Air 

OMB Office of Management and Budget 

PC Pulverized Coal 

PFC Perfluorocarbons 

PM2.5 Particular Matter less than 2.5 micrometer in 

diameter 

PRA Paperwork Reduction Act 

psi Pounds per square inch 

psig Pounds per square inch - guage 

RFA Regulatory Flexibility Act 

RIA Regulatory Impact Analysis 

SBA Small Business Administration 

SCC Social cost of carbon 

SCPC Supercritical pulverized coal 

SF6 Sulfur Hexafluoride 

SO2 Sulfur dioxide 

Tg Teragram (one trillion (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 
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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 

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 
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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 

XII. Statutory Authority 

I. General Information 

A. Executive Summary

1. Purpose of the Regulatory Action 

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

his Climate Action Plan (CAP), President Obama issued a 
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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. The proposal 

was published on January 8, 2014 (79 FR 1430; January 2014 

proposal). Specifically, under the authority of 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 

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

natural gas-fired stationary combustion turbines. Consistent 

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

standards reflect the degree of emission limitation achievable 

through the application of the best system of emission reduction 

(BSER) that the EPA has determined has been adequately 

demonstrated for each type of unit. 

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

proposing emission guidelines for states to use in developing 

plans to limit CO2 emissions from existing fossil fuel-fired 

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

by that action. 

2. Summary of the Major Provisions 

The proposed standards for the affected modified and 

reconstructed sources are summarized below in Table 1. 

Table 1. Summary of BSER and Proposed Standards for Affected 

Sources

Affected 

Source 

BSER Standard

Modified 

Utility 

Boilers and 

IGCC Units 

Most 

efficient 

generation 

at the 

affected 

source 

achievable 

through a 

combination 

of best 

operating 

practices 

Co-proposed Alternative #1

1. Source would be required to meet 

a unit-specific emission limit 

determined by the unit’s best 

historical annual CO2 emission 

rate (from 2002 to the date of 

the modification) plus an 

additional 2 percent emission 

reduction; the emission limit 

will be no lower than:

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

sources with heat input > 

Deleted: two
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and 

equipment 

upgrades 

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 

2 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. 

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. 

Deleted: two
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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 CAA 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 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 

 

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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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. 

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 

 

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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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 units 

would trigger either the modification or the reconstruction 

provisions that we are proposing today. Because there have been 

a limited number of units that have notified the EPA of NSPS 

modifications in the past, we have conducted an illustrative 

analysis of the costs and benefits for a representative modified 

unit. Based on the analysis, the EPA projects that this proposed 

rule will result in potential CO2 emission changes, quantified 

 

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

modification provision. In this illustrative example, based on a 

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

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

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

benefits from reductions in CO2, combined with the health cobenefits from reductions in sulfur dioxide (SO2), nitrogen oxides 

(NOx), and fine particulate matter (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 

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

CO2 emissions?

 

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 3 percent discount rate. We emphasize the 

importance and value of considering the full range of SCC 

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

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

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

discount rate. We provide estimates based on additional discount 

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

greenhouse gases (GHGs)5

 meet 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, CAA 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 CAA section 111(a)(1), the EPA must 

set these standards at the level of emission reduction that 

reflects the “best system of emission reduction ... adequately 

demonstrated,” taking into account technical feasibility, costs, 

and other factors. 

 

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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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. 

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 
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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 

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 

 

9

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

10 40 CFR 60.15(b).
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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 

newly constructed fossil fuel-fired electric steam generating 

units (utility boilers and IGCC units) and newly constructed

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 fuel-fired electric steam generating units 

and modified and reconstructed natural gas-fired stationary 

combustion turbines.

Although we expect that the modification and reconstruction 

standards of performance in this rulemaking will apply to few 
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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 

the system are reasonable, the amount of emissions reductions 

that the system would generate, and whether the standard would 
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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 we are proposing for each category of affected 

sources and the proposed standards of performance based on these 

BSER – as described immediately below – are based on that 

evaluation, as discussed in sections VI-IX below. 

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

modified fossil fuel-fired utility boilers and IGCC units? 

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

performance based on a combination of best operating practices 

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

determination and is co-proposing two alternative standards for 

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

would be subject to a single emission standard. Specifically, 
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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 2 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 section 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 section 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 CAA section 111(d) plan would 

have lower baseline emissions from which to calculate their 

required rate. 

Deleted: two
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It is our interpretation that, as we discuss in detail in 

the Legal Memorandum,11 an existing source would continue to be 

subject to CAA section 111(d) requirements after it becomes a 

modified source, whether the modification occurs before or after 

the promulgation of a CAA section 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 2 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 CAA section 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 

 

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.

Deleted: two
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for modified fossil-fired electric utility steam generating 

units are discussed further in section VII of this preamble. 

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 Natural Gas Combined Cycle (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 CAA section 111(d) implementing authority 

based on implementation of identified energy efficiency 

improvement opportunities applicable to the source. This is 

discussed further in section IX of this preamble. 

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. 

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. 
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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 newly constructed power plants (79 FR 1430), the EPA coproposed 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 newly constructed 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 of 

this preamble. 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 of this preamble, 

respectively. Sections VI through IX of this preamble describe 

the rationale for each of the proposed emission standards, 

including an explanation of the determination of the BSER for 
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reconstructed fossil fuel-fired utility boilers and IGCC units 

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

as well as for reconstructed natural gas-fired stationary 

combustion turbines and modified natural gas-fired stationary 

combustion turbines. Impacts of the proposed action are 

described in section X of this preamble. A discussion of 

statutory and executive order reviews is provided in section XI

of this preamble, and the statutory authority for this action is 

provided in section XII of this preamble. 

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 newly constructed

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 cross-reference 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. 
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Table 2. Potentially Affected Entitiesa

Category NAICS 

Code 

Examples of Potentially Affected 

Entities 

Industry 221112 Fossil fuel electric power generating 

units. 

Federal 

Government 

221112b Fossil fuel electric power generating 

units owned by the federal government.

State/Local 

Government 

221112b Fossil fuel electric power generating 

units owned by municipalities. 

Tribal 

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

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, or organization, 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 

Deleted: etc.
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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 United States, the Administrator 

found that elevated concentrations of GHGs in the atmosphere may 

reasonably be anticipated to endanger public health and welfare 

 

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 

CAA section 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 Under Section 202(a) of the Clean Air Act,” 74 FR 66496 

(December 15, 2009) (“Endangerment Finding”).
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of current and future generations. We summarize these adverse 

effects on public health and welfare briefly here.16

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 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 

 

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

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

include a more detailed summary of the public health and welfare 

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

discussion of the science supporting the EPA’s conclusions 

regarding the question of whether GHG endanger public health and 

welfare including: 1) the process by which the Administrator 

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

in 2010 to ten administrative petitions for reconsideration of 

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

the decision by the United States Court of Appeals for the 

District of Columbia Circuit in 2012 to uphold the Endangerment 

Finding and the Reconsideration Denial.

17 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases under Section 202(a) of the Clean Air Act,” 74 FR 66496 

(Dec. 15, 2009) (“Endangerment Finding”). 
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risk of morbidity and mortality. Other public health threats 

also stem from projected increases in intensity or frequency of 

extreme weather associated with climate change, such as 

increased hurricane intensity, increased frequency of intense 

storms, and heavy precipitation. Increased coastal storms and 

storm surges due to rising sea levels are expected to cause 

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 

 

18 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases under Section 202(a) of the Clean Air Act,” 74 FR 66496 

(Dec. 15, 2009) (“Endangerment Finding”).
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weather from climate change threatens energy, transportation, 

and water resource infrastructure. Climate change may exacerbate 

ongoing environmental pressures in certain settlements, 

particularly in Alaskan indigenous communities. Climate change 

also is very likely to fundamentally rearrange U.S. ecosystems 

over the 21st century. Though some benefits may balance adverse 

effects on agriculture and forestry in the next few decades, the 

body of evidence points towards increasing risks of net adverse 

impacts on U.S. food production, agriculture and forest 

productivity as temperature continues to rise. These impacts are 

global and may exacerbate problems outside the U.S. that raise 

humanitarian, trade, and national security issues for the U.S.3. 

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 
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exacting peer review by the expert community, as well as 

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

administrative record concerning the Endangerment Finding closed 

following the EPA’s 2010 Reconsideration Denial, a number of 

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 NRC 

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, 

some of which could become very severe. Therefore, 

 

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

1.

20 Id., p.138.
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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 “National Climate Assessment”22

emphasizes that climate change is already happening now and it 

is happening in the 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 increases 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 

atmospheric concentrations for thousands of years, and raised 

Earth system temperatures for even longer. Emission reductions 

 

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/. 
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today will benefit the public health and public welfare of 

current and future generations. 

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

the atmosphere continues to rise dramatically. In 2009, the year 

of the Endangerment Finding, the average concentration of CO2 as 

measured on top of Mauna Loa was 387 parts per million (ppm).23

The average concentration in 2013 was 396 ppm. And the monthly 

concentration in April of 2014 was 401 ppm, the first time a 

monthly average has exceeded 400 ppm 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 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 and places those amounts in the 

context of the national inventory of GHGs. 

 

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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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 

Waste 165.0 133.2 124.0 

Total Emissions 6,233.2 7,253.8 6,525.6 

 

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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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 

Total CO2 from fossil fuel 

combustion EGUs 1,820.8 2,402.1 2,022.7 

 - from coal 1,547.6 1,983.8 1,511.2
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C. The Utility Power Sector 

Electricity in the United States is generated by a range of 

sources - from power plants that use fossil fuels like coal, 

oil, and natural gas, to non-fossil sources, such as nuclear, 

solar, wind and hydroelectric power. In 2013, over 67 percent of 

power in the U.S. was 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 

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 

 - 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 pulverized 

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

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

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

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

the coal is burned in a layer of heated particles suspended in 

flowing air. 

Power can also be generated using gasification technology. 

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

composed of carbon monoxide and hydrogen, which can be combusted 

in a combined cycle system to generate power. 

D. Statutory Background
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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 CAA 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 

“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 

 

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). 37 CAA section 111(a)(4).
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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. 

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 

 

38 40 CFR 60.2, 60.14(e). 39 40 CFR 60.15.
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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 

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 

 

40 CAA section 111(b)(5) 41 CAA section 111(b)(2) 
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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 

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 

 

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 53657 (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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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 

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 

 

46 44 FR 33580 (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).

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

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 
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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 

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 
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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 

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 

 

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. 

52 40 CFR 60.2, 60.14. 
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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 CAA section 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 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 

 

53 40 CFR 60.14.
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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 

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 carbon capture and storage (CCS)

(or partial CCS) is not appropriate for modified EGUs. Some 

commenters suggested that a well-designed CAA section 111(d) 

 

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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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 

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 

 

57 40 CFR 60.15(a) 
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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 

avoid creating any regulatory incentive to perpetuate the 

operation 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 

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, 
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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 

existing coal-fired EGUs will undertake projects that will 

qualify the unit to be a reconstructed source during the 

analysis period of this rulemaking (i.e., through 2025). The EPA 

also does not expect existing NGCC units to undertake 

reconstructions during the analysis period (i.e., 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 

 

58 40 CFR 60.15(d)–(e) 
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implementing regulations at 40 CFR 60.15 on what constitutes a 

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

guidance on when an existing source replaces components to such 

a degree that it goes beyond a reconstruction and becomes 

essentially a newly constructed source. Historically there has 

been little need to distinguish between reconstructed sources 

and newly constructed sources as the standards of performance 

are typically the same for either. However, the standards 

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

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

delineate between a reconstructed source and a newly constructed 

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

facility would constitute a newly constructed source. It is 

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

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

existing source – would also constitute a newly constructed 

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

all practical purposes, completely replaces an existing sources 

by being constructed on the replaced source’s existing footprint 

would also constitute a newly constructed source. The EPA 

solicits comment on the delineation between a reconstructed 

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 1430), 
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for those situations where significant equipment is being 

replaced (enough to exceed the reconstruction threshold) but the 

entire unit is not being rebuilt. 

In addition, the EPA requests comment on having an upper 

capital cost threshold for reconstruction, such that facilities 

that exceed that threshold would be subject to the standard of 

performance for newly constructed sources. With respect to this 

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

having an upper threshold and (2) the appropriate upper 

threshold. With respect to the appropriate upper threshold, EPA 

specifically requests comment on an upper threshold within the 

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

comparable facility. Finally, the EPA requests comment on 

whether this upper threshold should be coupled with a provision 

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

facility that exceeded the upper threshold would not be subject 

to the new construction standard if it was technologically and 

economically infeasible for that facility to meet the new 

construction standard. 

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

to Reconstructions 

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 
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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 

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 

 

59 The comments are available in the rulemaking docket. Docket 

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

in the January 2014 proposal.60,61 This section describes those 

requirements. 

 

60 See 79 FR 1445 and 1446. 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 1446, are not relevant for 
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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-electric output to the grid. This proposed change 

to 219,000 MWh net sales is consistent with the EPA Acid Rain 

Program (ARP) definition, and we have concluded that it is 

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

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

25 MW of electricity on an annual basis, which is equivalent to 

 

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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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 one-third of its 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, and (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. 

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, 

Deleted: three

Deleted: three

Deleted: three
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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. We are also soliciting comment if the 10 

percent fossil fuel use criteria should be based on 3 

consecutive calendar years or on a 3 year rolling average basis. 

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 

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 
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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 

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 
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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). 

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 type of units 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 amount of the CO2 emissions from fossil fuelfired EGUs. The second type of units is modified or 

reconstructed non-natural gas-fired stationary combustion 
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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.” 

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 

 

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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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. In the alternative, as in the January 

2014 proposal, we solicit comment on requiring calculation of 

compliance on an annual (calendar year) period. See 79 FR 1477. 

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) is 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 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 
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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 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 o

C and 14.5 pounds per square inch (psi)) instead of 

International Organization for Standardization (ISO) conditions 

(15 o

C and 14.7 psi). In other words, at standard ambient 

temperature and pressure (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 combined heat and power (CHP) 

facilities with high energy condensate return would measure the 

energy in the condensate when determining the useful thermal 
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output. In addition, we are soliciting comment on providing 

credit for useful thermal output in the range of two-thirds 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 alternative, modified sources would 

be required to meet a unit-specific numeric emission standard 

that is 2 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: best operating practices that have the 

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

equipment upgrades that have the potential to improve heat rate, 

Deleted: 75 

Deleted: two

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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 

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

Deleted: two

Deleted: the 
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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 CAA section 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 co-proposed 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 2 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 CAA section 111(b) 

implementing authority and would be based on the source’s 

expected performance after implementation of identified unitspecific energy efficiency improvement opportunities. We seek 

 

67 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-2013-0602.

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comment on all aspects of these co-proposals, including whether 

the CAA section 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 2 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 section 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 2 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 CAA section 111(d) 

plan, or (2) the emission rate that is 2 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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Deleted: two
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IGCC units subject to a CAA section 111(d) plan could be 

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

CAA section 111(b) standard, they should continue to be subject 

to the CAA section 111(d) requirements to which they are 

subject. Under this option the modified utility boilers and IGCC 

units would be considered to be only “new sources” under 

111(a)(2). One method of doing this might be through a 

delegation of the EPA's CAA section 111(b) authority over that 

source to the state administering the applicable CAA section 

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 section 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 
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determined from the results of an energy assessment or audit. 

The EPA also requests comment on whether this approach should be 

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

reason, implemented energy efficiency measures in the time 

period between 2002 and the date of the modification and whether 

those sources should be required to provide evidence of those 

energy efficiency improvements. 

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

have proposed in this action - have different standards of 

performance for modified utility boilers and IGCC units 

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

submitted (or a federal plan promulgated). On the one hand, a 

CAA 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. A state, in developing a CAA section 111(d) 

plan, may choose to confer with its sources to determine whether 

any expect to modify, and, if any do, to 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 

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performance that are 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.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 CAA 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 Memorandum.69 Under this 

interpretation, a modified or reconstructed source would be 

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

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

reconstructed source standard under CAA section 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 

 

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. 

Deleted: best system of emission 

reduction (

Deleted: )
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combustion turbine after that unit becomes subject to a CAA 

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

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

emission limit that is determined by the CAA section 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 of 

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 
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units with a heat input rating that is greater than 

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

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

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

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

(3) for reconstructed stationary combustion turbines with a 

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

950 – 1,100 lb CO2/MWh-gross; and 

(4) for reconstructed stationary combustion turbines with a 

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

1,000 – 1,200 lb CO2/MWh-gross. 

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

utility boilers and IGCC units should be subcategorized by 

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

subcategory should be limited to utility boilers so that all 

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

or if there are sufficient alternate compliance technologies 

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

unnecessary and should be eliminated so that those sources would 

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 
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test that is numerically more stringent than the 12-operatingmonth standard for modified and reconstructed stationary 

combustion turbines would insure that efficient stationary 

combustion turbines are installed and properly maintained. The 

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

a level that would account for operating conditions where the 

emission rate is higher than design conditions. 

4. 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.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 

 

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

standards as gross output emission rates, See 79 FR 1447 and 

1448. In the rulemaking for existing sources that we are 

proposing concurrently with this rulemaking, we are proposing 

emission guidelines that call for state standards as net output 

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

rates).

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Deleted: s
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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, 

the EPA has taken into account startup and shutdown periods, 

which are included in the compliance calculation 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 electric 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, during which 

fuel is combusted and emissions monitors are not out of control, 

in addition to 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 

 

71 551 F.3d 1019 (D.C. Cir. 2008). 
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Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

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

infrequent, and not reasonably preventable failure of air 

pollution control equipment, process equipment, or a process to 

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

part by poor maintenance or careless operation are not 

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

section 111 does not require that emissions that occur during 

periods of malfunction be factored into development of CAA 

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

requires that the EPA anticipate and account for the innumerable 

types of potential malfunction events in setting emission 

standards. CAA section 111 provides that the EPA set standards 

of performance which reflect the degree of emission limitation 

achievable through “the application of the best system of 

emission reduction” that the EPA determines is adequately 

demonstrated. 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 units operating in such a way as to avoid 

malfunctions. 
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Further, accounting for malfunctions in setting emission 

standards would be difficult, if not impossible, given the 

myriad different types of malfunctions that can occur across all 

sources in the category and given the difficulties associated 

with predicting or accounting for the frequency, degree, and 

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

performance of units that are malfunctioning is not “reasonably” 

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

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

determining the extent of data-gathering necessary to solve a 

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

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 
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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 CAA section 111 to avoid such a result. The EPA’s 

approach to malfunctions is consistent with CAA section 111 and 

is a reasonable interpretation of the statute. 

In the event that a source fails to comply with the 

applicable CAA section 111 standards as a result of a 

malfunction event, the EPA would determine an appropriate 

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

the source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as 

undertake root cause analyses to ascertain and rectify excess 

emissions. The EPA would also consider whether the source's 

failure to comply with the CAA section 111 standard was, in 

fact, “sudden, infrequent, not reasonably preventable” and was 

not instead “caused in part by poor maintenance or careless 

operation.” 40 CFR section 60.2 (containing the 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 at federal district court will determine what, if any, 

relief is appropriate. The same is true for citizen enforcement 
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actions. Similarly, the presiding officer in an administrative 

proceeding can consider any defense raised and determine whether 

administrative penalties are appropriate. 

In several prior rules, the EPA had included an affirmative 

defense to civil penalties for violations caused by malfunctions 

in an effort to create a system that incorporates some 

flexibility, recognizing that there is a tension, inherent in 

many types of air regulation, in ensuring 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 
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penalties would not be assessed. Recently, the U.S. Court of 

Appeals for the District of Columbia Circuit vacated such an 

affirmative defense in one of the EPA’s CAA section 112(d) 

regulations. NRDC v. EPA, No. 10-1371, 2014 U.S. App. LEXIS 7281 

(D.C. Cir. April 18, 2014) (vacating affirmative defense 

provisions in CAA section 112(d) rule establishing emission 

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

EPA lacked authority to establish an affirmative defense for 

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

to determine civil penalty amounts lies exclusively with the 

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

language of the statute makes clear, the courts determine, on a 

case-by-case basis, whether civil penalties are ‘appropriate.’” 

See also id. 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 

 

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.

Deleted: United States

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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.id. at *24. (stating that 

arguments that violation were caused by unavoidable technology 

failure can be made to the courts in future civil cases when the 

issue arises). The same logic applies to EPA administrative 

enforcement actions. 

D. Continuous Monitoring Requirements 

We are proposing the same monitoring requirements for 

modified and reconstructed sources as were proposed for newly 

constructed sources in the January 2014 proposal. This section 

provides a summary of the requirements. For additional detail, 

see 79 FR 1450 and 1451. 

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 
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to 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 to part 75. 

In addition to requiring monitoring of the CO2 mass emission 

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

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

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

electrical output plus any mechanical output, plus 75 percent of 

any useful thermal output. 

The proposed rule would require EGU owners or operators to 

prepare and submit a monitoring plan that includes both 

electronic and hard copy components, in accordance with 40 CFR 

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

to determine the CO2 mass emission rates would have to be 

certified according to section 75.20 and section 6 of part 75, 

Appendix A within the 180-day window of time allotted under 

section 75.4(b), and would be required to meet the applicable 

on-going quality assurance procedures in Appendices B and D to 

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 

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unadjusted stack gas flow rate values would be used in the 

emissions calculations. In this proposal, part 75 bias 

adjustment factors (BAFs) would not be applied to the flow rate 

data. These restrictions on the use of Part 75 data for Part 60 

compliance are consistent with previous NSPS regulations and 

revisions. 

 Certain variations from and additions to the basic Part 75 

monitoring would be required and are detailed in the January 

2014 proposal (See 79 FR 1451). 

Special compliance provisions for units with common stack 

or multiple stack configurations, consistent with section 

60.13(g), would be required and are detailed in the January 2014 

proposal (see 79 FR 1451). 

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 

sections 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 
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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. 

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 

CHP 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 manufacturers’ maintenance 

recommendations be followed and include, at a minimum, annual 

inspection and calibration requirements for the flow meters, 

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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 

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 operating 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 alternative 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 
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We are proposing the same emissions performance testing 

requirements for modified and reconstructed sources as were 

proposed for newly constructed sources in the January 2014 

proposal. This section provides a summary of the requirements. 

For additional detail, see 79 FR 1451. 

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

would require an EGU owner or operator to begin reporting 

emissions data when monitoring system certification is completed 

or when the 180-day window in 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 
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We are proposing the same continuous compliance 

requirements for modified and reconstructed sources as were 

proposed for newly constructed sources in the January 2014 

proposal. This section provides a summary of the requirements. 

For additional detail, see 79 FR 1451. 

Today’s proposed rule specifies that compliance with the 

mass emissions rate limits would be determined on a 12-

operating-month rolling average basis, updated after each new 

operating month. For each 12-operating-month compliance period, 

quality-assured data from the certified Part 75 monitoring 

systems would be used together with the gross output over that 

period of time to calculate the average CO2 mass emissions rate. 

The proposed rule specifies that the first operating month 

included in the initial 12-operating-month compliance period 

would be the month in which reporting of emissions data is 

required to begin under section 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 

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requirements in the CAA 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 newly constructed sources in the January 2014 

proposal. This section provides a summary of the requirements. 

For additional detail, see 79 FR 1451 and 1452. 

Today’s proposed rule would require an EGU owner or 

operator to comply with the applicable notification requirements 

in sections 60.7(a)(1) and (a)(3), section 60.19 and section 

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 
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total CO2 mass emissions and gross output for each operating 

month. Records would be kept of the calculations performed to 

determine the average CO2 mass emission rate (kg/MWh) and the 

percentage of valid CO2 mass emission rates in each compliance 

period. The proposed rule would also require records to be kept 

of calculations performed to determine site-specific carbonbased F-factors for use in Equation G-4 of Part 75, Appendix G 

(if applicable). 

The proposed rule would require all affected EGU 

owners/operators to submit quarterly electronic emissions 

reports in accordance with subpart G of Part 75. The proposed 

rule would require these reports to be submitted using the 

Emissions Collection and Monitoring Plan System (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 
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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 newly constructed fossil fuel-fired 

EGUs, the EPA needed a rational basis, but that CAA section 111 

did not require an endangerment finding. The EPA further 

proposed that even if CAA 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 1452 through 1456. 
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B. Source Categories 

This proposal addresses the same two source categories – 

fossil fuel-fired steam generating units (utility boilers and 

IGCC units) and natural gas-fired stationary combustion turbines 

– that were addressed by the January 2014 proposal. In the 

January 2014 proposal, the EPA included a proposal and coproposal for the treatment of the two affected source 

categories, and for how the regulatory requirements applicable 

to these source categories would be codified in 40 CFR part 60. 

Specifically, the EPA proposed to create subcategories within 

each category, and to codify the regulatory requirements for 

each subcategory in 40 CFR part 60, subparts Da and KKKK, 

respectively. In addition, the EPA co-proposed to combine the 

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 co-
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proposal with regard to categories and codification for modified 

and reconstructed sources that it made with regard to new 

construction sources in the January 2014 proposal. That is, the 

EPA proposes to create subcategories within each category and to 

codify the regulatory requirements in 40 CFR part 60, subparts 

Da and KKKK, respectively; and in addition, the EPA co-proposes 

to combine the two categories for purposes of regulating CO2

emissions, and to codify all the CO2 regulatory requirements in a 

new subpart, TTTT. See 79 FR 1452 through 1454. 

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. 
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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 

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 3-year basis instead of an annual basis 

for stationary combustion turbines for multiple reasons. First, 

extending the period to 3 years would ensure that the CO2

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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 3-year average capacity factor of greater than 

one-third between 2000 and 2012. We are soliciting comment 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 3 years (since applicability 

is determined on a 3-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 

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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 

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 is 

different from the January 2014 proposal. To clarify that 

existing boiler and IGCC facilities would continue to be 

included in CAA section 111(d) state programs regardless of 

their actual electric sales or fossil fuel use, we are deleting 

the criteria to be considered an EGU. These criteria include 

that the facility must (1) actually sell one-third 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 heat input during a 3-year 

rolling average period. The sales criteria exemption was 

intended to exempt low capacity factor facilities since they 

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would have additional difficulties meeting the standards in the 

January 2014 proposal. However, the proposed standards for 

boilers and IGCC facilities in this 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 primarily non fossil 

fuels. These facilities (e.g., wood-fired EGUs) typically are 

inherently less efficient than fossil fuel-fired EGUs, and we 

are soliciting comment on if we should subcategorize boilers and 

IGCC facilities where 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 1459 

 

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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through 1461. 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 CAA section 111(b) NSPS potentially impacts the CAA 

section 111(d) rulemaking, since only EGUs that would be 

included under the CAA section 111(b) applicability if they were 

newly constructed, modified or reconstructed are included in the 

state CAA section 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 3-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 

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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 

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 currently 

available to sell approximately 38 percent of their potential 

electric output on a 3-year rolling average before an emission 

standard would apply. The smallest aeroderivative stationary 

combustion turbine designs have efficiencies of approximately 30

percent or greater, but these combustion turbine engines are 

smaller in size and the 219,000 MWh sales limit would still be 

the controlling criterion. Lower efficiency industrial frame 

turbines have efficiencies of approximately 28 percent. 

Therefore, in this approach, applicability with an emission 

standard would in general increase the electric sales criteria

for the larger, more efficient aeroderivative simple cycle 

combustion turbines and decrease it larger, less efficient 

industrial frame simple cycle turbines. We are soliciting 

comment on if this change would be sufficient to avoid the 

potential adverse environmental impact mentioned previously or 

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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 approximately 42 

percent of their potential electric output prior to becoming 

subject to a GHG standard. Conversely, the least efficient 

simple cycle turbines would be limited to selling 31 percent of 

their potential electric output prior to becoming subject to a 

GHG standard. The 42 percent sales criterion is approximately 

equivalent to allowing 4,000 hours of operation on a 3-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 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 smaller, less efficient stationary 

combustion turbines rather than fewer larger, more efficient 

stationary combustion turbines. This approach would recognize 

the environmental benefit of installing more efficient simple 

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cycle turbines regardless of size. 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. 

As an alternative, we are soliciting comment on an applicability 

exemption, and the criteria for that exemption, for highly 

efficient CHP facilities. 

We are also soliciting comment on whether 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 

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. 

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In addition, some of the initial feedback we received in 

public comments74 on the January 2014 proposal suggests that the 

emissions data that the EPA used in developing the natural gasfired stationary combustion turbine standards do 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. 

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. 

 

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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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 requesting comment on a full range of alternatives 

for low capacity factor stationary combustion turbines and/or 

simple cycle combustion turbines to the general applicability 

thresholds we proposed in the January 2014 proposal. This 

includes soliciting comment on whether we should: establish a 

separate numerical limit for low capacity factor stationary 

combustion turbines and/or simple cycle combustion turbines; 

exempt all such units; set a higher capacity factor threshold 

applicable to all simple cycle turbines; establish a variable 

capacity factor that would allow more efficient, lower emitting 

turbines to run and be permitted for longer periods of operation 

(e.g., a higher capacity factor for the most efficient turbines 

being progressively lowered for lower efficiency turbines); or 

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establish a CO2 emission limitation in the form of an annual 

tonnage cap based on allowable emissions from smaller, less 

efficient units that do not exceed the 33 percent and 219,000 

MWh thresholds regardless of hours operated. The EPA is 

considering all these options in its treatment of simple cycle 

combustion turbines and solicits comments on the merits of these 

options or variations of them. The EPA intends – when it takes 

final action on this proposal and on the January 2014 proposal 

for newly constructed sources – to finalize the same standards 

and applicability criteria for newly constructed, modified and 

reconstructed natural gas-fired stationary 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 

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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 

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 
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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 

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 

 

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). 

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

to promote the deployment, development and implementation 

of technology.7778

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 1462 

 

“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 

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. 
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through 1467, 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 CAA section 111(b), as part of the 1975 framework 

regulations, and the EPA is not re-opening that determination.79 

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 

 

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

notification, and reconstruction provisions).
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use of partial CCS, (2) conversion to (or co-firing with) 

natural gas, (3) the use of CHP, (4) hybrid power plants (5) 

reductions in generation associated with dispatch changes, 

renewable generation, and demand side energy efficiency,(6) 

efficiency improvements achieved through the use of the most 

efficient generation technology, and (7) efficiency improvements 

achieved through a combination of best operating practices and 

equipment upgrades.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 

 

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.

Deleted: carbon capture and storage (

Deleted: )
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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. 

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 

 

81 Technical Support Document, “Impact of EPACT 2005 on BSER” 

available in rulemaking docket ID: EPA-HQ-OAR-2013-0495.

Deleted: 

Deleted: January 8, 2014 

http://www2.epa.gov/sites/productio

n/files/2014-

01/documents/2013_proposed_cps_for_

new_power_plants_tsd.pdf
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industry-wide basis. In particular, retrofitting a plant with 

partial CCS would entail integrating the carbon capture 

equipment with the affected unit’s steam cycle (or with an 

external source of steam or heat) in order to release the 

captured CO2 and regenerate the solvent or sorbent. The cost of a 

retrofit would depend on many site-specific details, including 

the space available for the capture equipment, and the EPA lacks 

information on such details for a significant portion of the 

industry. 

Therefore, the EPA does not propose to find that partial 

CCS is the BSER for CO2 emissions from reconstructed fossil fuelfired utility boilers and IGCC units. 

2. Conversion to or Co-firing with Natural Gas 

While conversion to or co-firing with natural gas in a 

utility boiler is a technically feasible option to reduce CO2

emission rates, it is an inefficient way to generate electricity 

compared to use of an NGCC and the resultant CO2 reductions are 

relatively expensive. The EPA found costs for natural gas cofiring to range from approximately $83/ton to $150/ton of CO2

avoided.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 

 

82 Chapter 2, GHG Abatement Measures Technical Support Document, 

available in Docket EPA-HQ-OAR-2013-0602.

Deleted: c

Deleted: n

Deleted: g
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already has a sufficient natural gas supply), the costs of CO2

reduction would still be approximately $75/ton of CO2 avoided. 

Therefore, we are not proposing natural gas co-firing as part of 

the BSER for modified or reconstructed steam generating units. 

However, we specifically solicit comment on whether natural 

gas reburning (NGR) and/or similar 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 

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 coalfired boiler, the CO2 emission rate would be reduced by 6 percent 

 

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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and 8 percent, respectively. In addition to reducing CO2

emissions, a potential financial benefit of NGR compared to 

natural gas co-firing is the generation of additional NOX

reductions. These reductions could reduce costs a source is 

currently paying for compliance with NOX requirements, including 

operations and maintenance costs associated with existing 

controls such as selective catalytic reduction systems and/or 

the cost of emission allowances under certain pollution control 

programs. 

The EPA also requests 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. CHP

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 

Deleted: takes

Deleted: Combined Heat and Power
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enough to thermal hosts to economically or efficiently use the 

recovered thermal energy. Therefore, we are not proposing to 

find that CHP is the BSER for reconstructed utility boilers and 

IGCC units or stationary combustion turbines. 

4. Hybrid Power Plant 

Hybrid power plants combine two or more forms of energy 

input into a single facility with an integrated mix of 

complementary generation methods. While there are multiple types 

of hybrid power plants, the most relevant type for this proposal 

is the integration of solar energy (e.g., concentrating solar 

thermal with or without photovoltaic generation) with a fossil 

fuel-fired EGU. Both coal-fired and NGCC EGUs have demonstrated 

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 

Deleted: p

Deleted: p
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the cost of implementation, on either a source-specific basis or 

an industry-wide basis. We solicit comment on whether hybrid 

power plant technology is broadly applicable to modified and 

reconstructed EGUs and on the costs of integrating non-emitting 

generation. 

Our understanding is that one of the benefits of hybrid 

fossil EGUs is decreased incremental cost of the non-emitting 

(e.g., solar thermal) generated electricity due to the ability 

to use equipment (e.g., HRSG, steam turbine, condenser, etc.) 

already included at the fossil fuel-fired EGU, as well as 

improvement of the electrical generation efficiency of the nonemitting generation. For example, solar thermal often produces 

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 
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comparable fossil only EGU to accommodate the additional steam 

load during sunny hours. 

We specifically solicit comment on an alternate, but 

similar, approach for modified and reconstructed fossil fuelfired EGUs to integrate lower emitting generation. The recovered 

thermal energy from natural gas-fired combustion turbines, fuel 

cells, or other combustion technology could be used to reheat or 

preheat boiler feed water (minimizing the steam that is 

otherwise extracted from the steam turbine), preheat makeup 

water and combustion air, produce steam for use in the steam 

turbine or to power the boiler feed pumps, or use the exhaust 

directly in the boiler to generate steam. In theory, this could 

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 
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grouped those measures into four main categories, or “building 

blocks.” The EPA proposed that each of the building blocks 

represents a method of CO2 emission reduction at existing fossil 

fuel-fired EGUs that, when combined with the other building 

blocks, represent the “best system of emission reduction... 

adequately demonstrated” for existing fossil-fuel-fired EGUs 

under a 111(d) program. The building blocks are: 

1. Lowering the carbon intensity of generation at individual 

affected EGUs (e.g., through heat rate improvements); 

2. Reducing emissions of the most carbon-intensive affected 

EGUs to the extent that this can be accomplished costeffectively by shifting generation to less carbon-intensive 

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 
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part of the BSER determination for modified units, but we are 

not proposing that building blocks two, three, or four are 

components of the BSER determination. We solicit comment on 

whether building blocks two, three and four would be appropriate 

in light of the fact that, unlike the CAA section 111(d) 

emission guidelines proposal, which will result in state plans 

that cover all existing sources, this proposal will result in a 

federal rule that covers only those sources that modify or 

reconstruct. We note that it is not possible in advance to 

determine which 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 

supercritical pulverized coal (SCPC) or supercritical 

circulating fluidized bed (CFB) boiler for large sources, and 

subcritical for small sources. We propose to find that these 
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technologies meet the criteria for the BSER.84

a. Technical Feasibility 

The use of supercritical steam conditions has been 

demonstrated by many facilities since the 1960s for both large 

and small EGUs. In fact, the world’s first commercial 

supercritical pressure EGU was the 125 MW Philo Unit 6 that 

commenced operation in 1957. Currently commercially available 

materials capable of tolerating steam conditions of 30 

megapascal (MPa) (4,350 psi) and 605 o

C (1,120 oF) have been 

demonstrated at coal-fired EGUs. In addition, even though the 

majority of recently constructed coal-fired EGUs use a single 

steam reheat cycle, the use of a dual steam reheat cycle has 

been demonstrated by multiple facilities as technically 

feasible. For a facility to be considered reconstructed for NSPS 

purposes, the boiler itself would have to be substantially 

refurbished. As part of a reconstruction, an owner/operator 

would be able to replace the steam tubing and other necessary 

equipment to allow the use of the best demonstrated steam cycle. 

Therefore, this option is technically feasible. 

It should be noted that this approach identifies as the 

BSER changes in production technology that would result in fewer 

 

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.

Deleted: pounds per square inch (

Deleted: )
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emissions, and not add-on technology that would control 

emissions. The kraft pulp mill NSPS (40 CFR part 60, subpart BB) 

is an example in which different equipment design (rather than 

add-on control) is the BSER for a modification or 

reconstruction. 

b. CO2 Reductions 

The U.S. Department of Energy National Energy Technology 

Laboratory (DOE/NETL) has estimated that a new SCPC boiler using 

subbituminous coal would emit 7 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 7

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 pounds per square inch 

guage (psig)) and 527 o

C (980 oF) and 40 percent have no steam 

reheat. Increasing the steam pressure to 20 MPa (2,900 psig) and 

568 o

C (1,054 oF) would reduce the CO2 emission rate by 6 

percent. In addition, the use of a single steam reheat cycle 

reduces the CO2 emission rate by 10 percent compared to an 

Deleted: seven

Deleted: seven
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equivalent EGU without a steam reheat cycle. 

While the percent reduction in CO2 emissions rate using 

efficiency improvements achieved through the use of the most 

efficient generation technology is less than could be achieved 

by a number of the other alternatives for the BSER that the EPA 

considered, as noted above, those other alternatives do not meet 

other criteria for the BSER. Efficiency improvements achieved 

through the use of the most efficient generation technology do 

achieve the greatest emission reductions of any of the remaining 

alternatives that the EPA is considering. 

c. Costs, Structure of the Energy Sector 

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 
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resulting designs have a higher cost premium than larger 

supercritical steam turbines and do not take full advantage of 

the potential efficiency improvements and the benefits of using 

a supercritical steam cycle are reduced. Therefore, for smaller 

reconstructed EGUs the EPA has determined that the BSER is the 

use of highest available subcritical steam conditions. The 

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

psi) and 570 o

C (1,060 oF). The EPA specifically solicits comment 

on the efficiency benefits and the costs of using supercritical 

steam conditions for smaller EGU designs. Modern materials are 

widely available that can tolerate the maximum subcritical steam 

parameters. Therefore, we anticipate the incremental cost of 

increasing steam parameters within subcritical conditions 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. 

Deleted: ¶

While we do not have data for the 

incremental costs of increasing 

steam parameters within subcritical 

conditions, m

Deleted: is
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For the same reason, designation of the most efficient 

generation technology as the BSER for reconstructed fossil fuelfired utility boilers and IGCC units will not have adverse 

effects on the structure of the power sector, will not impact 

fuel diversity, and will not have adverse effects on the supply 

of electricity. 

d. Incentive for Technological Innovation 

As noted above, the case law makes clear that the EPA is to 

consider the effect of its selection of BSER on technological 

innovation or development, but that the EPA also has the 

authority to weigh this factor along with the other ones. When 

it comes to the selection of the BSER, the EPA recognizes that 

reconstructed sources face inherent constraints that newly 

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 
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is based on the use of the best available steam cycle, other 

energy efficiency measures will likely be developed and used 

(improved economizers, etc.) and these technologies will be 

transferrable to other EGUs. 

7. Efficiency Improvements Achieved Through a Combination of 

Best Operating Practices and Equipment Upgrades 

The EPA also considered whether a combination of best 

operating practices and equipment upgrades would qualify as the 

BSER for a reconstruction. These measures are discussed in 

greater detail in Section VII of this preamble. A 

reconstruction, because it occurs only when an owner/operator 

spends more than 50 percent 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.
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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 system or technology. To determine an 

achievable emission standard, we reviewed the emission rate 

information submitted by owners/operators of coal-fired EGUs to 

the EPA’s Clean Air Markets Division. For reconstructed fossil 

fuel-fired boiler and IGCC EGUs, the EPA proposes to find that 

the best available steam cycle – which qualify as the BSER - 

supports 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 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 Technical Support Document 
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(TSD)85, 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.86

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 

 

85 “Best System of Emissions Reduction (BSER) for Reconstructed 

Electric Utility Steam Generating Units (EGUs) and Integrated 

Gasification Combined Cycle Facilities (IGCC)” Technical Support 

Document available in the rulemaking docket (EPA-HQ-OAR-2013-

0603).

86 Advanced ultra-supercritical steam conditions are 700 – 760 o

C 

(1,290 – 1,400 o

F) and 36 MPa (5,000 psi) 
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to implement partial CCS, co-fire approximately 10 percent 

natural gas directly in the boiler, or integrate non-emitting or 

lower emitting technology in the facility's design (i.e., a 

hybrid power plant). 

We are not currently considering a standard less stringent 

than 2,100 lb CO2/MWh-net for large units because at that level, 

the NSPS would not necessarily promote the use of the best 

available steam cycle. At an emissions rate of 2,200 lb CO2/MWh, 

large EGUs would not be required to use efficient generation 

technologies (e.g., they could use subcritical steam 

conditions). We are not currently considering a standard less 

stringent than 2,300 lb CO2/MWh-net for small units because at 

that level, the NSPS would not necessarily promote the use of 

the best available steam conditions because many smaller 

subcritical units are operating well below 2,300 lb CO2/MWh-net. 

D. Compliance Period 

The EPA is proposing that sources would be required to meet 

the proposed standards on a 12 operating-month rolling basis. 

The proposed compliance period requirements and rationale are 

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

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

1481 and 1482. 

The 12-operating-month averaging period being proposed is 

important because of the inherent variability in power plant GHG 
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emissions rates. Establishing a shorter averaging period would 

necessitate establishing a standard to account for the 

conditions that result in the lowest efficiency and therefore 

the highest GHG emissions rate. 

EGU efficiency has a significant impact on the source’s GHG 

emission rate. EGU efficiency can vary from month to month 

throughout the year. For example, high ambient temperature can 

negatively impact the efficiency of combustion turbine engines 

and steam generating units. As a result, an averaging period 

shorter than 12 operating-months would require us to set a 

standard that could be achieved under these conditions. This 

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

meaningful constraint during other parts of the year. In 

addition, operation at low load conditions can also negatively 

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

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

averaging period that accounts for this operation would again 

not produce a meaningful constraint for typical loads. 

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 
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of long-term outages), and simplifies compliance for state 

permitting authorities. The EPA proposes that it is not 

necessary to have a shorter averaging period for CO2 from these 

sources because the effect of GHGs on climate change depends on 

global atmospheric concentrations which are dependent on 

cumulative total emissions over time, rather than hourly or 

daily emissions fluctuations or local pollutant concentrations. 

Unlike for emissions of criteria and hazardous air pollutants, 

we do not believe that there are measureable implications to 

health or environmental impacts from short-term higher CO2

emission rates as long as the 12-month average emissions rate is 

maintained. 

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

A. Introduction 

In this section we explain our rationale for proposing, as 

the “best system of emission reduction ... adequately 

demonstrated” for modified fossil fuel-fired utility boiler and 

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 
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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) 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 

utility boiler and IGCC units: (1) the use of partial CCS, (2) 

conversion to (or co-firing with) natural gas, (3) the use of 

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 

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available, which we believe is a supercritical87 unit (i.e., a 

SCPC or supercritical CFB boiler) for large sources, and a 

subcritical unit for small sources. However, as was previously 

noted, the existing fleet of fossil fuel-fired steam-generating 

boilers is numerous and diverse in size and configuration 

(including steam parameters), and the EPA does not have 

sufficient information about the range of configurations that 

would be necessary to estimate the cost of upgrading the steam 

cycle (switching to higher grade of materials in the furnace, 

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 

 

87 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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unit, when it was not originally designed to do so, could 

require significant modifications to both the boiler and turbine 

that could start to approach the replacement cost for the unit. 

Unlike in the case of reconstruction explained above, it is 

the understanding of the EPA that modifications do not typically 

involve the type of boiler rebuilding that would make this an 

option with reasonable cost. Consequently, the EPA does not 

propose to find that the use of the most efficient generation 

technology meets the criteria for the BSER for a uniform 

nationwide standard of performance. 

3. Best Operating Practices and Equipment Upgrades 

The second option that EPA considered for modified fossil 

fuel-fired utility boilers and IGCC units is a combination of 

best operating practices and equipment upgrades. Best operating 

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 
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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 CAA section 111(d) state plan (or 

promulgated federal plan), or after it becomes subject to such a 

plan. Each variation of the BSER meets the criteria, which we 

discuss next. We describe the variations in more detail in the 

section concerning the standards of performance, which follows 

the discussion of the criteria. 

a. Technical Feasibility 

A wide range of studies have been performed evaluating the 

opportunity to improve the heat rate (or efficiency)88 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”89 which explains 

that, while the studies are different in the level of detail and 

 

88 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 1 kWh of electricity. Lower heat rates are 

associated with more efficient fossil fuel-fired EGUs.

89 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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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) feed water 

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 
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literature and selected the Sargent & Lundy 2009 study90 as the 

basis for its assessment of heat rate improvement potentials 

from equipment and system upgrades. We focused on thirteen heat 

rate improvement methods discussed by Sargent & Lundy and listed 

in Table 2-13 of the “GHG Abatement Measures” TSD. We used the 

average of the estimated costs (in $/kW) for each method to 

develop the cost-ranked list of heat rate improvement methods 

(listed by costs from lowest to highest in the table). The first 

nine items in Table 2-13 contribute about 15 percent of the 

total average $/kW cost for all items. We believe it is 

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 

 

90 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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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 1,205 

Btu) resulted in associated combined capital costs in the range 

of $40-150/kW. The wide ranges of estimated Btu reductions and 

capital costs are indicative of the wide range of real 

differences in the many details of site specific EGU designs, 

fuel types, age, size, ambient conditions, current physical 

condition, etc. The EPA’s analysis, therefore, assumed $100/kW 

as a representative combined heat rate improvement capital cost 

to achieve whatever Btu reduction is possible at an average 

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 
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is about $75/kW or less. 

 Even at a capital cost of $100/kW and an Integrated 

Planning Model (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 2 percent reduction (which captures minimum 

opportunities for additional heat rate improvements from 

equipment and system upgrades) can be achieved at reasonable 

cost. 

The EPA’s modeling tools do not allow projection of any 

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. 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 

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has the authority to weigh this factor, along with the various 

other factors. With the selection of emissions controls, 

modified sources face inherent constraints that newly 

constructed greenfield and even reconstructed sources do not; as 

a result, modified sources present different, and in some ways 

more limited, opportunities for technological innovation or 

development. In this case, the proposed standards promote 

technological development by promoting further development and 

market penetration of equipment upgrades and process changes 

that improve plant efficiency. 

C. Determination of the Level of the Standard 

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. 
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In this action, the EPA is co-proposing two alternative 

standards of performance for modified utility boilers and IGCC 

units. In the first co-proposed alternative, all modified 

sources would meet a unit-specific emission limit. In the second 

co-proposed alternative, the modified source would be required 

to meet a unit-specific emission limit that will depend on the 

timing of the modification. 

For utility boilers or IGCC units undertaking 

modifications, the EPA is proposing that the BSER has two 

components: (1) that the source operates consistently with its 

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

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 2 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 CAA section 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 

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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 section 111(d) plan would be required 

to meet an emission limit that is determined using the same 

methodology described in the first co-proposed alternative. The 

modified utility boiler or IGCC unit would be required to 

maintain an emission rate that equals the unit’s best 

demonstrated annual performance during the years from 2002 to 

the year the modification occurs, multiplied by 98 percent 

(i.e., a 2 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 

unit-specific emission limit that is determined by the CAA 

section 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 

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we discuss in the Legal Memorandum91, 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 section 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 CAA section 111(d) plan 

because we are concerned that, as a result of implementation of 

state plans, the additional 2 percent efficiency improvement may 

be unachievable for a substantial number of sources that make 

efficiency improvements as part of a CAA section 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 2 percent reduction (based on equipment upgrades) 

that we are considering. We recognize that in some states, CAA 

 

91 Legal Memorandum available in rulemaking docket ID: EPA-HQOAR-20913-0602.

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section 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 CAA section

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 2 percent (based on equipment upgrades) that we are 

considering for sources that modify prior to becoming subject to 

a state plan. 

For this co-proposal, the EPA is proposing that the date 

for determining whether a unit is subject to a CAA section 

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

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 CAA section 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 CAA section 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 

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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 CAA section 111(d) implementing authority from 

the results of an energy efficiency audit to identify 

technically feasible heat rate improvement opportunities at the 

affected source. 

An energy efficiency audit, or assessment, is an in-depth 

energy study identifying all energy conservation measures 

appropriate for a facility given its operating parameters. 

An energy audit is a process that involves a thorough 

examination of potential savings from energy efficiency 

improvements, pollution prevention, and productivity 

improvement. It leads to the reduction of emissions of 

pollutants through process changes and other efficiency 

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). 
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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 the basis of the 

certification should be; and (3) whether there are organizations 

that provide certification of specialists in evaluating energy 

systems. We propose that the CAA section 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 
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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 5000192 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 

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 

 

92 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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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 1481 and 1482. 

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: 

(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 

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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 

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 

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is likely to be cost effective based on consideration of fuel 

savings alone. In the proposal for newly constructed sources (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 

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 

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– 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 

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 newly constructed natural gasfired stationary combustion turbine sources, as described in the 

January 2014 proposal (79 FR 1430). The EPA intends – when it 

takes final action on this proposal and on the January 2014 

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proposal for newly constructed sources, respectively – to 

finalize the same standards for newly constructed, modified and 

reconstructed natural gas-fired stationary combustion turbines. 

The EPA solicits comment on this approach and on any reasons why 

these sources should not have consistent standards. 

In the January 2014 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 rulemaking93 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 

 

93 “Standard of Performance for Natural Gas-Fired Combustion 

Turbines” Technical Support Document, Docket ID: EPA-HQ-OAR2013-0495.
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greater than 850 MMBtu/h. We further propose to establish 

different standards of performance for these two subcategories. 

This subcategorization has a basis in differences in 

several types of equipment used in the differently sized units, 

which affect the efficiency of the units. 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.94 The only potential difference that the EPA 

 

94 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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has identified is consideration of cost because the actions that 

could trigger modification are less extensive changes at the 

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 

 

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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 

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 proposal for newly 

constructed sources - 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. 

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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 CAA 111(d) implementing authority, 

based on implementation of identified energy efficiency 

improvement opportunities applicable to the source. 

X. Impacts of the Proposed Action95

As explained in the RIA for this proposed rule, the EPA 

expects few 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

 

95 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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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 

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

A. What are the air impacts? 

As explained immediately above, the EPA expects few 

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? 

 

96 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average SCC at a 3 

percent discount rate. We emphasize the importance and value of 

considering the full range of SCC values, however, which include 

the model average at 2.5 and 5 percent, and the 95th percentile 

at 3 percent. Similarly, we summarize the health co-benefits in 

this synopsis at a 3 percent discount rate. We provide estimates 

based on additional discount rates in the RIA. 
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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 reconstructed or modified 

EGUs in the period of analysis and the nationwide cost impacts 

to be minimal as a result. 

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 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 

GHGs make it important to take action to control the largest 

emissions categories without delay. Unlike most traditional air 

pollutants, GHGs persist in the atmosphere for time periods 

ranging from decades to millennia, depending on the gas. Fossil 
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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 

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 

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 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. 
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F. What are the benefits of the proposed standards? 

 As previously stated, the EPA anticipates few units will 

trigger the proposed modification or reconstruction provisions. 

Because there have been a limited number of units that have 

notified the EPA of NSPS modifications in the past, we have 

conducted an illustrative analysis of the costs and benefits for 

a representative unit. Based on the analysis, which is presented 

in Chapter 9 of the RIA, the combined climate benefits from 

reductions in CO2 and health co-benefits from reductions in SO2, 

NOx, and PM2.5 total $18 to $33 million (2011$) 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.97 

XI. Statutory and Executive Order Reviews 

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

Executive Order 13563, Improving Regulation and Regulatory 

Review 

 

97 For purposes of this summary, we present climate benefits from 

CO2 that were estimated using the model average social cost of 

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

importance and value of considering the full range of SCC 

values, however, which include the model average at 2.5 percent

and 5 percent, and the 95th percentile at 3 percent. Similarly, 

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

percent discount rate. We provide estimates based on additional 

discount rates in the RIA.

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 Under Executive Order 12866 (58 FR 51735, October 4, 1993), 

this action is a “significant regulatory action” because it 

“raises novel legal or policy issues arising out of legal 

mandates.” Accordingly, the EPA submitted this action to the OMB 

for review under Executive Orders 12866 and 13563 (76 FR 3821, 

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

recommendations have been documented in the docket for this 

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 

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 
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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 modified or reconstructed EGUs in the period of 

analysis. Specifically, the EPA believes it unlikely that fossil 

fuel-fired electric utility steam generating units (utility 

boilers and IGCC units) or stationary combustion turbines will 

take actions that would constitute modifications 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 Information Collection Request (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 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 newly constructed sources and is proposing the same 

recordkeeping and reporting requirements that were included in 

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the January 2014 proposal.98 See 79 FR 1498 and 1499. Although 

not anticipated, if an EGU were to modify or reconstruct, this 

proposed action would impose minimal information collection 

burden on affected sources beyond what those sources would 

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

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 

 

98 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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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 sources will 

trigger either the NSPS modification or reconstruction 

provisions that we are proposing, if an EGU were to modify or 

reconstruct during the 3-year period covered by this ICR, it is 

likely that an EGU’s energy metering equipment would need to be 

modified to comply with proposed net energy 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 
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of annual responses over the 3-year ICR period is 4.33 per year. 

Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

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

part 9. 

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]. 
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The final rule will respond to any OMB or public comments on the 

information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions. 

For purposes of assessing the impacts of this rule on small 

entities, small entity is defined as: 

(1) a small business that is defined by the SBA’s 

regulations at 13 CFR 121.201 (for the electric power generation 

industry, the small business size standard is an ultimate parent 

entity 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. 
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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 modified utility boilers, IGCC units, 

or stationary combustion turbines in the period of analysis. An 

NSPS modification is defined as a physical or operational change 

that increases the source’s maximum achievable hourly rate of 

emissions. The EPA does not believe that there are likely to be 

EGUs that will take actions that would constitute modifications 

as defined under the EPA’s NSPS regulations. 

Because there have been a limited number of units that have 

notified the EPA of NSPS modifications in the past, the RIA for 

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 reconstructed fossil fuelfired electric utility steam generating units (utility boilers 

and IGCC units) or stationary combustion turbines in the period 
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of analysis. Reconstruction occurs when a single project 

replaces components or equipment in an existing facility and 

exceeds 50 percent of the fixed capital cost that would be 

required to construct a comparable entirely new facility. Due to 

the limited data available on reconstructions, it is not 

possible to conduct a representative illustrative analysis of 

what costs and benefits might result from this proposal in the 

unlikely case that a unit were to reconstruct. However, based on 

the low number of previous reconstructions and the BSER 

determination based on the most efficient available generating 

technology, we would expect this proposal to result in no 

significant CO2 emission changes, quantified benefits, or costs 

for NSPS reconstructions. Accordingly, there are no 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 
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National Rural Electric Cooperative Association (NRECA) and the 

American Public Power Association (APPA). The meetings brought 

together leaders of the rural cooperatives and public power 

utilities from across the country. The Administrator discussed 

and exchanged information on the unique challenges, in 

particular the financial structure, of NRECA and APPA member 

utilities. A detailed discussion of the stakeholder outreach is 

included in the preamble to the emission guidelines for existing 

affected electric utility generating units being proposed in a 

separate action. 

In addition, as described in the RFA section of the 

preamble to the proposed standards of performance for GHG 

emissions from new EGUs (79 FR 1499 and 1500), 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 newly constructed, 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
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This proposed rule does not contain a federal mandate that 

may result in expenditures of $100 million or more for state, 

local and tribal governments, in the aggregate, or the private 

sector in any one year. As previously stated, the EPA expects 

few modified or reconstructed fossil fuel-fired electric utility 

steam generating units (utility boilers and IGCC units) or 

stationary combustion turbines in the period of analysis. 

Accordingly, this proposed rule is not subject to the 

requirements of sections 202 or 205 of UMRA. 

This proposed rule is also not subject to the requirements 

of section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. 

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 

newly constructed, reconstructed, modified and existing sources. 

As described in the UMRA discussion in the preamble to the 

proposed standards of performance for GHG emissions from newly 

constructed EGUs (79 FR 1500 and 1501), 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 
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Governments; (4) National League of Cities; (5) U.S. Conference 

of Mayors; (6) National Association of Counties; (7) 

International City/County Management Association; (8) National 

Association of Towns and Townships; (9) County Executives of 

America; and (10) Environmental Council of States. On February 

26, 2014, the EPA re-engaged with those governmental entities to 

provide a pre-proposal update on the emission guidelines for 

existing EGUs and emission standards for modified and 

reconstructed EGUs. 

While formulating the provisions of these proposed 

standards, the EPA also considered the input provided over the 

course of the extensive stakeholder outreach conducted by the 

EPA (see section II.G. of this preamble). 

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 
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preamble to the proposed standards of performance for GHG 

emissions from newly constructed 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 

newly constructed, reconstructed, modified and existing sources. 

The EPA engaged 10 national organizations representing state and 

local elected officials. The UMRA discussion in the preamble to 

the proposed standards of performance for GHG emissions from 

newly constructed EGUs (79 FR 1500 and 1501) 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 
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This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

would neither impose substantial direct compliance costs on 

tribal governments, nor preempt Tribal law. This proposed rule 

would impose requirements on owners and operators of 

reconstructed and modified EGUs. The EPA is aware of three coalfired EGUs located in Indian country but is not aware of any 

EGUs owned or operated by tribal entities. The EPA notes that 

this proposal would only affect existing sources such as the 

three coal-fired EGUs located in Indian country, if those EGUs 

were to take actions constituting modifications or 

reconstructions as defined under the EPA’s NSPS regulations. 

However, as previously stated the EPA expects few 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 newly constructed 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 

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consultation regarded planned actions for newly constructed, 

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 newly constructed EGUs (79 FR 1501) includes a 

description of that consultation. 

During development of this proposed regulation, 

consultation letters were sent to 584 tribal leaders. The 

letters provided information regarding the EPA’s development of 

both the NSPS for modified and reconstructed EGUs and emission 

guidelines for existing EGUs and offered consultation. No tribes 

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 

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separate action today. The EPA also held a series of listening 

sessions prior to proposal of GHG standards for newly 

constructed power plants. Tribes participated in a session on 

February 17, 2011, with the state agencies, as well as in a 

separate session with tribes on April 20, 2011. 

The EPA will also hold additional meetings with tribal 

environmental staff during the public comment period, to inform 

them of the content of this proposal, as well as offer further 

consultation with tribal 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 

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the supply, distribution, or use of energy. As previously 

stated, the EPA expects few 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 

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 
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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 

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 
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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 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. 

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 

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: June 2, 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 at 79 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 newly constructed 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.