Vol. 79 Wednesday, 

No. 117 June 18, 2014 

Part III 

Environmental Protection Agency 

40 CFR Part 60 

Carbon Pollution Standards for Modified and Reconstructed Stationary 

Sources: Electric Utility Generating Units; Proposed Rules 


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34960 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

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 gasfired 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 

October 16, 2014. 

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 June 18, 

2014, a comment to the OMB is best 

assured of having its full effect if the 

OMB receives it by July 18, 2014. 

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 document 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 Web sites: http://

www2.epa.gov/carbon-pollutionstandards and http://www2.epa.gov/

cleanpowerplan. If any dates, times or 

locations of announced public hearings 

are changed for the proposed emission 

guidelines, then the public hearing 

dates, times and locations for this action 

will also change accordingly. If you 

would like to speak at the public 

hearing(s), please register by following 

instructions provided in the document 

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 Web site http://

www.regulations.gov: Follow the 

instructions for submitting comments. 

Email: Send your comments by 

electronic mail (email) to a-and-rdocket@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 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 electronically within 

the disk or CD–ROM the specific 

information you claim as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, you must submit a copy 

of the comment that does not contain 

the information claimed as CBI for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

The EPA requests that you also 

submit a separate copy of your 

comments to the contact person 

identified below (see FOR FURTHER

INFORMATION CONTACT). If the comment 

includes information you consider to be 

CBI or otherwise protected, you should 

send a copy of the comment that does 

not contain the information claimed as 

CBI or otherwise protected. 

The www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties, and cannot 

contact you for clarification, the EPA 

may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption and be free of any defects 

or viruses. 

Docket: All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34961 

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 

will be posted at the following address: 

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

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 

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 Megawatthour 

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 

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 Fuel-Fired Utility 

Boilers and IGCC Units 

A. Introduction 

B. Identification of the Best System of 

Emission Reduction 

C. Determination of the Level of the 

Standard 

D. Compliance Period 

VIII. Rationale for Emission Standards for 

Reconstructed Natural Gas-Fired 

Stationary Combustion Turbines 

A. Identification of the Best System of 

Emission Reduction 

B. Determination of the Standards of 

Performance 

IX. Rationale for Emission Standards for 

Modified Natural Gas-Fired 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 


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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 

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-fired utility boilers and IGCC 

units, and (4) reconstructed natural gasfired 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 

and equipment upgrades.

Co-proposed Alternative #1 

1. Source would be required to meet a unit-specific emission limit determined 

by the unit’s best historical annual CO2 emission rate (from 2002 to the date 

of the modification) plus an additional 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. 

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 

Gas-Fired Stationary Combustion Turbines.

Efficient NGCC technology .................... 1. Sources with heat input >850 MMBtu/h would be required to meet an emission limit of 1,000 lb CO2/MWh-gross. 

2. Sources with heat input ≤850 MMBtu/h would be required to meet an emission limit of 1,100 lb CO2/MWh-gross. 

Reconstructed Utility 

Boilers and IGCC 

Units.

Most efficient generating technology at 

the affected source.

1. Sources with heat input >2,000 MMBtu/h would be required to meet an emission limit of 1,900 lb CO2/MWh-net. 

2. Sources with heat input ≤2,000 MMBtu/h would be required to meet an emission limit of 2,100 lb CO2/MWh-net. 

Reconstructed Natural Gas-Fired 

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. 


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1The ‘‘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.’’ 

2See 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.’’). 

3The 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. 

4For 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 cobenefits in this summary at a 3 percent discount 

rate. We provide estimates based on additional 

discount rates in the RIA. 

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 

For the reasons discussed in the 

‘‘Legal Memorandum’’ 1 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 

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 gas-fired 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 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 

benefits, and costs for a unit that is 

subject to the modification provision. In 

this illustrative example, based on a 

hypothetical 500 MW coal-fired unit, we 

estimate costs, net of fuel savings, of 

$0.78 million to $4.5 million (2011$) 

and CO2 reductions of 133,000 to 

266,000 tons in 2025. The climate 

benefits from reductions in CO2,

combined with the health co-benefits 

from reductions in 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? 

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. 

Connecticut 7 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 

sources.8 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. 

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 nonVerDate Mar<15>2010 19:40 Jun 17, 2014 Jkt 232001 PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 E:\FR\FM\18JNP3.SGM 18JNP3

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

10 40 CFR 60.15(b). 

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 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 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 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 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 fuelfired utility boilers and IGCC units? 

The EPA proposes that the BSER for 

modified fossil fuel-fired 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 unit-specific 

emission standards consistent with this 

BSER determination and is co-proposing 

two alternative standards for modified 

utility steam generating units. In the 

first co-proposed alternative, modified 

utility boilers and IGCC units would be 

subject to a single emission standard. 

Specifically, under the first co-proposed 

alternative, a modified source would be 

required to meet a unit-specific 

emission limit determined by the 

affected source’s best demonstrated 

historical performance (in the years 

from 2002 to the time of the 

modification) with an additional 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 


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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. 

12Steam with higher temperature and pressure 

has more thermal energy which can be more 

efficiently converted to electrical energy. 

13Legal Memorandum available in rulemaking 

docket ID: EPA–HQ–OAR–2013–0602. 

rate as a result of a CAA section 111(d) 

plan would have lower baseline 

emissions from which to calculate their 

required rate. 

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 unitspecific 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 unitspecific energy efficiency improvement 

opportunities. The BSER and standards 

of performance for modified fossil-fired 

electric utility steam generating units 

are discussed further in section VII of 

this preamble. 

6. What is the BSER and standard of 

performance for modified natural gasfired 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/MWhgross 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 (i.e., 

reconstructing the boiler to use higher 

steam, temperature and pressure, even if 

the boiler was not originally designed to 

do so 12). The proposed emission limit 

for these sources is 1,900 lb CO2/MWhnet 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 

Memorandum,13 a reconstruction would 

have no effect on the applicability of an 

approved CAA section 111(d) plan; 

thus, a source that is subject to 

requirements in a CAA section 111(d) 

plan would remain subject to those 

requirements. 

8. What are BSER and the standard of 

performance for reconstructed natural 

gas-fired stationary combustion 

turbines? 

The EPA is proposing to find efficient 

NGCC technology to be the BSER for 

reconstructed stationary combustion 

turbines. Therefore, the EPA is 

proposing that larger units be required 

to meet a standard of 1,000 lb CO2/

MWh-gross and that smaller units be 

required to meet a standard of 1,100 lb 

CO2/MWh-gross. This is discussed 

further in section VIII below. 

A reconstruction would have no effect 

on the applicability of an approved CAA 

section 111(d) plan on the existing 

source; thus, a source that is subject to 

requirements in a CAA section 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 co-proposed two options for 

codifying applicable requirements for 

covered sources. Under the first option 

the EPA proposed to codify the 

standards of performance for the 

respective sources within existing 40 

CFR part 60 subparts so that applicable 

GHG standards for electric utility steam 

generating units would be included in 

subpart Da and applicable GHG 

standards for stationary combustion 

turbines would be included in subpart 

KKKK. Under the second option, the 

EPA co-proposed to create a new 

subpart TTTT and to include all GHG 

standards of performance for covered 

sources in that newly created subpart. 

In this action for modified and 

reconstructed sources, the EPA coproposes 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 reconstructed fossil fuel-fired 

utility boilers and IGCC units and 

modified fossil fuel-fired utility boilers 

and IGCC units, as well as for 


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34966 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

14This 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’’). 16The 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’’). 

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’’). 

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. 

TABLE 2—POTENTIALLY AFFECTED ENTITIES a

Category NAICS code Examples of potentially affected entities 

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

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

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

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

a Includes 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). bFederal, state or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

This table is not intended to be 

exhaustive, but rather to provide a guide 

for readers regarding entities likely to be 

affected by this proposed action. To 

determine whether your facility, 

company, business, 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 

In this section,14 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 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 Finding 17

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 cold-related 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 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 Finding 18

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 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34967 

19National Research Council, Understanding 

Earth’s Deep Past, p. 1. 

20 Id., p.138. 

21National Research Council, Climate 

Stabilization Targets, p. 3. 

22U.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/. 

23 ftp://aftp.cmdl.noaa.gov/products/trends/co2/

co2_annmean_mlo.txt. 

24http://www.esrl.noaa.gov/gmd/ccgg/trends/. 

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. 

face increased risks from storm and 

flooding damage to property, as well as 

adverse impacts from rising sea level, 

such as land loss due to inundation, 

erosion, wetland submergence and 

habitat loss. Climate change is expected 

to result in an increase in peak 

electricity demand, and extreme 

weather from climate change threatens 

energy, transportation, and water 

resource infrastructure. Climate change 

may exacerbate ongoing environmental 

pressures in certain settlements, 

particularly in Alaskan indigenous 

communities. Climate change also is 

very likely to fundamentally rearrange 

U.S. ecosystems over the 21st century. 

Though some benefits may balance 

adverse effects on agriculture and 

forestry in the next few decades, the 

body of evidence points towards 

increasing risks of net adverse impacts 

on U.S. food production, agriculture and 

forest productivity as temperature 

continues to rise. These impacts are 

global and may exacerbate problems 

outside the U.S. that raise humanitarian, 

trade, and national security issues for 

the U.S. 

3. New Scientific Assessments 

As outlined in Section VIII.A. of the 

2009 Endangerment Finding, the EPA’s 

approach to providing the technical and 

scientific information to inform the 

Administrator’s judgment regarding the 

question of whether GHGs endanger 

public health and welfare was to rely 

primarily upon the recent, major 

assessments by the U.S. Global Change 

Research Program (USGCRP), the 

Intergovernmental Panel on Climate 

Change (IPCC), and the National 

Research Council (NRC) of the National 

Academies. These assessments 

addressed the scientific issues that the 

EPA was required to examine, were 

comprehensive in their coverage of the 

GHG and climate change issues, and 

underwent rigorous and exacting peer 

review by the expert community, as 

well as rigorous levels of U.S. 

government review. Since the 

administrative record concerning the 

Endangerment Finding closed following 

the EPA’s 2010 Reconsideration Denial, 

a number of 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 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, 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 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 FuelFired 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. 

The EPA prepares the official U.S. 

Inventory of Greenhouse Gas Emissions 

and Sinks 25 (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. 


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26Sinks are a physical unit or process that stores 

GHGs, such as forests or underground or deep sea 

reservoirs of carbon dioxide. 

27From 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. 

28From 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. 

29From 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. 

30From 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. 

31U.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. 

32Based 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=epmt_6_03. 

anthropogenic emissions and sinks 26 of 

GHGs, including CO2 emissions, for the 

years 1990, 2005 and 2012. 

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 

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 fuelfired 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

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 

—from natural gas ........................................................................................................................ 175.3 318.8 492 .2 

—from petroleum .......................................................................................................................... 97.5 99.2 18 .8 

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

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 

CAA section 111 authorizes the EPA 

to prescribe new source performance 

standards (NSPS) applicable to certain 

new stationary sources (including 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34969 

33CAA section 111(b)(1)(A). 34See generally 40 CFR part 60, subparts 

D–MMMM. 35CAA section 111(b)(1)(B). 36CAA section 111(a)(2). 37CAA section 111(a)(4). 38 40 CFR 60.2, 60.14(e). 39 40 CFR 60.15. 

40CAA section 111(b)(5). 41CAA section 111(b)(2). 42 36 FR 5931 (March 31, 1971) 43 ‘‘Standards of Performance for Fossil-FuelFired 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). 

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-CommercialInstitutional 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. 

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 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 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 

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-Commercial-Institutional 

Steam Generating Units’’) and Dc 

(‘‘Standards of Performance for Small 

Industrial-Commercial-Institutional 

Steam Generating Units’’)—in order to 

codify separate requirements that it 

established for these subcategories.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 DC 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 

EGUs 50 includes a discussion of the 

GHG-related litigation of the 2006 Final 

Rule as well as other GHG-associated 

litigation. 

F. Stakeholder Outreach 

The EPA has engaged extensively 

with a broad range of stakeholders and 

the general public regarding climate 

change, carbon pollution from power 

plants, and carbon pollution reduction 

opportunities. These stakeholders 

included industry and electric utility 

representatives, state and local officials, 

tribal officials, labor unions and nongovernmental 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. 


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34970 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

51The 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. 

53 40 CFR 60.14. 

54The proposal was subsequently withdrawn 

with the publication of the January 8, 2014 

proposal. 

55The comments are available in the rulemaking 

docket. Docket ID: EPA–HQ–OAR–2011–0660. 

56 79 FR 1352. 

57 40 CFR 60.15(a). 

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 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 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 regulations 51

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 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 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) 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. 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34971 

58 40 CFR 60.15(d)–(e). 

59The comments are available in the rulemaking 

docket. Docket ID: EPA–HQ–OAR–2011–0660. 

Thus, a reconstruction occurs if the 

existing source replaces components to 

such an extent that the capital costs of 

the new components exceed 50 percent 

of the capital costs of an entirely new 

facility, even if the existing source does 

not increase its emissions. In addition, 

the component replacement constitutes 

a reconstruction only if it is 

technologically and economically 

feasible for the source to meet the 

applicable standards. The purpose of 

the reconstruction provision is to 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, 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 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), 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 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 plant. The 

commenters expressed concern that 

such reconstructed sources would face a 

standard that is much less stringent than 

a newly constructed greenfield source. 


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34972 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

60See 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 

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. 

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

63 40 CFR 60.41Da (definition of (‘‘Electric utility 

steam-generating unit’’). 

64 Id. 

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. 

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 

sale 63 (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 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, smaller EGUs that are colocated 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) fossilfuel 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 ‘‘netelectric output’’ (i.e., the proposed 

definition would read ‘‘. . . the gross 

electric sales to the utility power 

distribution system minus purchased 

power of the thermal host facility or 

facilities on a calendar year basis’’ 

(emphasis added). 

Finally, consistent with the January 

2014 proposal, to avoid circumvention 

of the intent of the emission standards 

(e.g., by having auxiliary equipment 

provide steam to the EGU to increase 

the output of the EGU and not including 

the CO2 emissions in determining the 

emission rate) and to provide additional 

flexibility to the regulated community 

through additional compliance options, 

we are proposing to amend the 

definition of a steam generating unit to 

include ‘‘plus any integrated equipment 

that provides electricity or useful 

thermal output to either the affected 

facility or auxiliary equipment’’ in place 

of the existing language ‘‘plus any 

integrated combustion turbines and fuel 

cells.’’ The proposed definition would 

read, ‘‘any furnace, boiler, or other 

device used for combusting fuel for the 

purpose of producing steam (nuclear 

steam generators are not included) plus 

any integrated equipment that provides 

electricity or useful thermal output to 

either the affected facility or auxiliary 

equipment’’ (emphasis added). We are 

also proposing to add the additional 

language to the definition of IGCC in 

subpart Da (or subpart TTTT) and 

stationary combustion turbine in 

subpart KKKK (or subpart TTTT). 

This action proposes to set standards 

only for emissions of CO2. The pollutant 

we propose to regulate could also be 

identified as a broader suite of GHGs. 

However, we are not proposing to set 

standards for any other GHGs, such as 

methane (CH4) or nitrous oxide (N2O), 

because they represent less than 1 

percent of total estimated GHG 

emissions from fossil fuel-fired electric 

power generating units. This is 

consistent with the approach that was 

taken in the proposed standards for 

newly constructed EGUs (79 FR 1430). 

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 

one-third or less of their potential 

output and 219,000 MWh or less to the 

grid. These units are not covered under 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34973 

65Oil-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). 

66Additional detail can be found in the Technical 

Support Document: ‘‘GHG Abatement Measures’’ 

(Chapter 2: Heat Rate Improvement at Existing Coalfired EGUs), available in rulemaking docket ID: 

EPA–HQ–OAR–2013–0602. 

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 fuel-fired EGUs. The second 

type of units is modified or 

reconstructed non-natural gas-fired 

stationary combustion turbines.65 Under 

the proposed approach, applicability 

with the NSPS for stationary 

combustion turbines could change on an 

annual basis depending on electric sales 

and for facilities burning fuels other 

than natural gas (e.g., burning backup 

oil). 

B. Emission Standards 

In this rulemaking, the EPA is 

proposing standards of performance for 

CO2 emissions from modified and 

reconstructed EGUs within two 

categories and several subcategories of 

affected fossil fuel-fired EGUs. 

The proposed standards of 

performance for the utility boiler and 

IGCC category are in the form of net 

energy output-based CO2 emission 

limits expressed in units of mass of CO2

per unit of net energy output (e.g., net 

electrical output plus 75 percent of the 

useful thermal output), specifically, in 

lb CO2/MWh-net. This emission limit 

would apply to affected sources upon 

the effective date of the final action. In 

this 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 of 

mass of CO2 per unit of gross energy 

output, specifically, in lb CO2/MWhgross. We also solicit comment on 

whether we should use a net outputbased 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, coaldrying could be done at a separate 

offsite facility by an industrial boiler 

prior to delivery at the power plant. In 

that scenario, the CO2 emissions from 

the industrial boiler would not be 

included when the coal-fired boiler 

determined compliance with the 

proposed standards even though the 

overall emissions to the atmosphere 

could be greater than for an integrated 

system where the thermal energy for the 

drying is supplied by the power plant. 

Therefore, we are proposing that 

thermal energy used for reducing fuel 

moisture 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 

°C and 14.5 pounds per square inch 

(psi)) instead of International 

Organization for Standardization (ISO) 

conditions (15 °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 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, 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 


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34974 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

67Legal Memorandum available in rulemaking 

docket ID: EPA–HQ–OAR–2013–0602. 

facility. For example, should large 

subcritical steam generating units have 

a most stringent standard that is less 

stringent (i.e., greater than) 1,900 lb 

CO2/MWh-net, which is based on the 

use of a supercritical steam cycle. 

As we discuss in the Legal 

Memorandum 67, 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 unitspecific 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 unit-specific energy efficiency 

improvement opportunities. We seek 

comment on all aspects of these coproposals, 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 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 

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. 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. Under this option 

the modified utility boilers and IGCC 

units would be considered to be only 

‘‘new sources’’ under 111(a)(2). 

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 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 

performance that are based on efficient 

NGCC technology as the BSER. The 

emission limits proposed for these 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34975 

68This 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. 

69Legal Memorandum available in rulemaking 

docket ID: EPA–HQ–OAR–2013–0602. 

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). 

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

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 

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 units with a heat input 

rating that is greater than 2,000 MMBtu/ 

h, a range of 1,700–2,100 lb CO2/MWhnet; 

(2) for reconstructed fossil fuel-fired 

boilers and IGCC units with a heat input 

rating of 2,000 MMBtu/h or less, a range 

of 1,900–2,300 lb CO2/MWh-net; 

(3) for reconstructed stationary 

combustion turbines with a heat input 

rating greater than 850 MMBtu/h, a 

range of 950–1,100 lb CO2/MWh-gross; 

and 

(4) for reconstructed stationary 

combustion turbines with a heat input 

rating of 850 MMBtu/h or less, a range 

of 1,000–1,200 lb CO2/MWh-gross. 

We also solicit comment on whether: 

(1) The standards for utility boilers and 

IGCC units should be subcategorized by 

primary fuel type, (2) the small utility 

boiler and IGCC unit subcategory should 

be limited to utility boilers so that all 

IGCC units would be in the large 

subcategory regardless of size, or if there 

are sufficient alternate compliance 

technologies (e.g., co-firing natural gas) 

that the small unit subcategory is 

unnecessary and should be eliminated 

so that those sources would be required 

to meet the same emission standard as 

large utility boilers and IGCC units, and 

(3) an annual short-term performance 

test should be required for stationary 

combustion turbines in addition to the 

12-operating-month rolling average 

standard. Requiring an initial and 

annual short term compliance test that 

is numerically more stringent than the 

12-operating-month standard for 

modified and reconstructed stationary 

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 

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 

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 


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34976 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

72The 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. 

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. 

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-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’). In addition, emissions 

during a malfunction event can be 

significantly higher than emissions at 

any other time of source operation and 

thus accounting for malfunctions could 

lead to standards that are significantly 

less stringent than levels that are 

achieved by a well-performing, nonmalfunctioning 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 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 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 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 flexibility, as 

appropriate. Further, as the DC 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 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
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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 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 

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 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 qualityassured data are collected and recorded 

for all of the parameters used to 

calculate CO2 mass emissions. EGU 

owners or operators would have the 

option to use backup monitoring 

systems, as provided in 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 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, 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 

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 

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. 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
34978 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

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 

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 total CO2 mass emissions and gross 

output for each operating month. 

Records would be kept of the 

calculations performed to determine the 

average CO2 mass emission rate (kg/

MWh) and the percentage of valid CO2

mass emission rates in each compliance 

period. The proposed rule would also 

require records to be kept of 

calculations performed to determine 

site-specific carbon-based F-factors for 

use in Equation G–4 of Part 75, 

Appendix G (if applicable). 

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 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. 

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 coproposal with regard to categories and 

codification for modified and 

reconstructed sources that it made with 

regard to new construction sources in 

the January 2014 proposal. That is, the 

EPA proposes to create subcategories 

within each category and to codify the 

regulatory requirements in 40 CFR part 

60, subparts Da and KKKK, respectively; 

and in addition, the EPA co-proposes to 

combine the two categories for purposes 

of regulating CO2 emissions, and to 

codify all the CO2 regulatory 

requirements in a new subpart TTTT. 

See 79 FR 1452 through 1454. 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34979 

73Requests 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. 

V. Rationale for Applicability 

Requirements 

The rationale for several of the 

proposed applicability requirements for 

modified and reconstructed sources is 

the same as that in the January 2014 

proposal. This section provides a 

summary of the rationale for these 

requirements along with rationale for 

differences with the applicability 

included in the January 2014 proposal. 

In addition, we are soliciting comment 

on multiple alternative approaches to 

the applicability criteria. 

The following four proposed 

applicability criteria are consistent with 

the January 2014 proposal. First, this 

proposal includes within the definition 

of a utility boiler, IGCC unit, and 

stationary combustion turbine that is 

subject to the proposed requirements, 

any integrated device that provides 

electricity or useful thermal output to 

the boiler, the stationary combustion 

turbine or to power auxiliary 

equipment. The rationale behind 

including integrated equipment 

recognizes that the integrated 

equipment may be a type of combustion 

unit that emits GHGs, and that it is 

important to assure that those GHG 

emissions are included as part of the 

overall GHG emissions from the affected 

source. Also consistent with the January 

2014 proposal, we are considering 

including in the definition of the 

affected facility co-located non-emitting 

energy generation 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 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 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 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 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 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
34980 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

74All public comments on the January 2014 

proposal are available in the rulemaking docket, 

Docket ID: EPA–HQ–OAR–2013–0495. 

the installation, modification or 

reconstruction of smaller, less efficient 

simple cycle combustion turbines rather 

than larger, more efficient simple cycle 

combustion turbines. For simple cycle 

combustion turbines that are smaller 

than approximately 70 MW, the 219,000 

MWh sales would be the determining 

criteria for whether the facility is subject 

to an emission standard. Smaller EGUs 

can sell over one-third of their potential 

electric output and still not be subject 

to a GHG emission standard. This could 

potentially place larger, more efficient 

simple cycle combustion turbines at a 

disadvantage since they would be 

limited to selling less (e.g., one-third) of 

their potential electric output. This 

could result in higher GHG emissions, 

and we are soliciting comment on 

approaches to minimize this outcome. 

One approach we are considering is 

changing the ‘‘one-third potential 

electric output’’ sales criteria to ‘‘the 

design net efficiency 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 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 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. 

In addition, some of the initial 

feedback we received in public 

comments 74 on the January 2014 

proposal suggests that the emissions 

data that the EPA used in developing 

the natural gas-fired 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. 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 


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75Portland 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). 

76As discussed in the January 2014 Proposal, the 

D.C. Circuit’s case law formulates the cost 

consideration in various ways: The costs must not 

be ‘‘exorbitant [ ]’’, Essex Chemical Corp. v. 

Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), see 

Lignite Energy Council v. EPA, 198 F.3d 930, 933 

(D.C. Cir. 1999); ‘‘greater than the industry could 

bear and survive,’’ Portland Cement Association v. 

EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or 

‘‘excessive’’ or ‘‘unreasonable.’’ Sierra Club v. 

Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). In the 

January 2014 Proposal, EPA stated that ‘‘these 

various formulations of the cost standard . . . are 

synonymous,’’ and, for convenience, EPA used 

‘‘reasonableness’’ as the formulation. EPA takes the 

same approach in this proposal. 

77See discussion of case law and legislative 

history in the January 2014 proposal. 79 FR 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. 

79 40 FR 58417–58418, December 16, 1975 (final 

NSPS modification, notification, and reconstruction 

provisions). 

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 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 

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 

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 industrywide level, and, at least in the case of 

the power sector, on the national level 

in terms of the overall costs of 

electricity and the impact on the 

national economy over time.76

• The EPA must also consider that 

CAA section 111 is designed to promote 

the deployment, development and 

implementation of technology.77 78

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 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 60.15. These reconstruction 

provisions have not been amended since 

originally promulgated in 1975, and 

have been implemented for numerous 

source categories. 

B. Identification of Best System of 

Emissions Reduction 

The EPA evaluated seven different 

control technology configurations as 

potentially representing the BSER for 

reconstructed fossil fuel-fired boiler and 

IGCC EGUs: (1) The use of partial 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 


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34982 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

80Note that we also evaluated these seven 

different technology configurations 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. 

81Technical Support Document, ‘‘Effect of 

EPAct05 on BSER for New Fossil Fuel-fired Boilers 

and IGCCs,’’ available in rulemaking docket ID: 

EPA–HQ–OAR–2013–0495. 

82Chapter 2, GHG Abatement Measures Technical 

Support Document, available in Docket EPA–HQ– 

OAR–2013–0602. 83Fuel 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 coal-fired EGU would be reduced by 4 

percent. 

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 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 sourcespecific basis or an industry-wide basis. 

In particular, retrofitting a plant with 

partial CCS would entail integrating the 

carbon capture equipment with the 

affected unit’s steam cycle (or with an 

external source of steam or heat) in 

order to release the 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 

fuel-fired 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 co-firing 

to range from approximately $83/ton to 

$150/ton of CO2 avoided.82 Even for 

cases where the natural gas could be cofired without any capital investment or 

impact on the performance of the 

affected facility (e.g., an existing IGCC 

facility that already has a sufficient 

natural gas supply), the costs of CO2

reduction would still be approximately 

$75/ton of CO2 avoided. Therefore, we 

are not proposing natural gas co-firing 

as part of the BSER for modified or 

reconstructed steam generating units. 

However, we specifically solicit 

comment on whether natural gas 

reburning (NGR) and/or similar 

technologies 83 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 coal-fired boiler, the 

CO2 emission rate would be reduced by 

6 percent and 8 percent, respectively. In 

addition to reducing CO2 emissions, a 

potential financial benefit of NGR 

compared to natural gas co-firing is the 

generation of additional NOX

reductions. These reductions could 

reduce costs a 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 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. 


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84Note 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. 

Both coal-fired and NGCC EGUs have 

demonstrated the technical feasibility of 

integrating concentrating solar thermal 

energy for use in boiler feed water 

heating, preheating makeup water, and/ 

or producing steam for use in the steam 

turbine or to power the boiler feed 

pumps. While hybrid power plants can 

reduce the CO2 emission rate by several 

percent compared to similar non-hybrid 

power plants, not all modified and 

reconstructed EGUs may have the space 

or meteorological conditions to generate 

enough solar thermal energy to 

successfully convert to a hybrid power 

plant. Solar thermal facilities require 

abundant sunshine and significant land 

area and the EPA does not have 

sufficient information about the range of 

specific configurations that would be 

necessary to estimate the cost of 

implementation, on either a sourcespecific 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 nonemitting (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 non-emitting 

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 nonemitting solar thermal generation in a 

hybrid power plant is the costs of the 

mirrors, additional piping, and a steam 

turbine that is 10 to 20 percent larger 

than a comparable fossil only EGU to 

accommodate the additional steam load 

during sunny hours. 

We specifically solicit comment on an 

alternate, but similar, approach for 

modified and reconstructed fossil fuelfired EGUs to integrate lower emitting 

generation. The recovered thermal 

energy from natural gas-fired 

combustion turbines, fuel cells, or other 

combustion technology could be used to 

reheat or preheat boiler feed water 

(minimizing the steam that is otherwise 

extracted from the steam turbine), 

preheat makeup water and combustion 

air, produce steam for use in the steam 

turbine or to power the boiler feed 

pumps, or use the exhaust directly in 

the boiler to generate steam. In theory, 

this could 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 

fuel-fired EGUs, the EPA considered 

numerous measures that can and are 

being implemented to improve emission 

rates and to limit overall CO2 emissions 

from fossil fuel-fired EGUs. The EPA 

grouped those measures into four main 

categories, or ‘‘building blocks.’’ The 

EPA proposed that each of the building 

blocks represents a method of CO2

emission reduction at existing fossil 

fuel-fired EGUs that, when combined 

with the other building blocks, 

represent the ‘‘best system of emission 

reduction . . . adequately 

demonstrated’’ for existing fossil-fuelfired 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 

cost-effectively by shifting generation to 

less carbon-intensive existing NGCC 

units, including NGCC units that are 

under construction; 

3. Reducing emissions of carbonemitting 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 carbonemitting EGUs to the extent that this can 

be accomplished cost-effectively by 

increasing demand-side energy 

efficiency. 

In this rulemaking, we are, in effect, 

utilizing building block one—lowering 

the carbon intensity of generation at 

individual affected EGUs through heat 

rate improvements—as part of the BSER 

determination for modified units, but 

we are not proposing that building 

blocks two, three, or four are 

components of the BSER determination. 

We solicit comment on whether 

building blocks two, three and four 

would be appropriate in light of the fact 

that, unlike the CAA section 111(d) 

emission guidelines proposal, which 

will result in state plans that cover all 

existing sources, this proposal will 

result in a federal rule that covers only 

those sources that modify or 

reconstruct. We note that it is not 

possible in advance to determine which 

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 

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 °C (1,120 °F) 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. 


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34984 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

It should be noted that this approach 

identifies as the BSER changes in 

production technology that would result 

in fewer emissions, and not add-on 

technology that would control 

emissions. The kraft pulp mill NSPS (40 

CFR 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 °C (980 °F) and 40 

percent have no steam reheat. Increasing 

the steam pressure to 20 MPa (2,900 

psig) and 568 °C (1,054 °F) would 

reduce the CO2 emission rate by 6 

percent. In addition, the use of a single 

steam reheat cycle reduces the CO2

emission rate by 10 percent compared to 

an equivalent EGU without a steam 

reheat cycle. 

While the percent reduction in CO2

emissions rate using efficiency 

improvements achieved through the use 

of the most efficient generation 

technology is less than could be 

achieved by a number of the other 

alternatives for the BSER that the EPA 

considered, as noted above, those other 

alternatives do not meet other criteria 

for the BSER. Efficiency improvements 

achieved through the use of the most 

efficient generation technology do 

achieve the greatest emission reductions 

of any of the remaining alternatives that 

the EPA is considering. 

c. Costs, Structure of the Energy Sector 

DOE/NETL has estimated, based on 

the levelized cost of electricity (LCOE), 

that the capital costs of a SCPC EGU are 

approximately 3 percent more than a 

comparable subcritical EGU. In fact, the 

reduced fuel costs are significant 

enough that the overall cost to generate 

electricity is actually lower for a SCPC 

EGU compared to a subcritical EGU. 

Therefore, the emission reductions are 

considered cost effective for larger 

EGUs. 

For smaller boilers, less than 

approximately 200 MW, it is the 

understanding of the EPA that 

manufacturers of steam turbines do not 

currently offer turbines that have been 

thermodynamically optimized to use 

supercritical steam conditions. Instead, 

for smaller applications, they would 

typically adapt their larger turbines for 

the application. The resulting designs 

have a higher cost premium than larger 

supercritical steam turbines and do not 

take full advantage of the potential 

efficiency improvements and the 

benefits of using a supercritical steam 

cycle are reduced. Therefore, for smaller 

reconstructed EGUs the EPA has 

determined that the BSER is the use of 

highest available subcritical steam 

conditions. The maximum viable 

subcritical steam parameters are 21 MPa 

(3,000 psi) and 570 °C (1,060 °F). 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. 

For the same reason, designation of 

the most efficient generation technology 

as the BSER for reconstructed fossil 

fuel-fired 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 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. 

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 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34985 

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). 

86Advanced ultra-supercritical steam conditions 

are 700–760 °C (1,290–1,400 °F) and 36 MPa (5,000 

psi). 

that system or technology. To determine 

an achievable emission standard, we 

reviewed the emission rate information 

submitted by owners/operators of coalfired 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 (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/MWhnet for small units. An emission rate of 

1,700 lb CO2/MWh-net could potentially 

be met by an EGU using advanced ultrasupercritical 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 ultra-supercritical steam 

cycle, and instead would be required to 

implement partial CCS, co-fire 

approximately 40 percent natural gas 

directly in the boiler, or integrate non 

emitting or lower emitting technology in 

the facility’s design (i.e., a hybrid power 

plant). We are not currently considering 

a standard more stringent than 1,900 lb 

CO2/MWh-net for small units because 

available information indicates that a 

small EGU facility could only meet a 

standard of 1,800 lb CO2/MWh-net 

burning bituminous coal and using the 

best available subcritical steam cycle. 

Modified facilities burning other coal 

types would be required to implement 

partial CCS, co-fire approximately 10 

percent natural gas directly in the 

boiler, or integrate non-emitting or 

lower emitting technology in the 

facility’s design (i.e., a hybrid power 

plant). 

We are not currently considering a 

standard less stringent than 2,100 lb 

CO2/MWh-net for large units because at 

that level, the NSPS would not 

necessarily promote the use of the best 

available steam cycle. At an emissions 

rate of 2,200 lb CO2/MWh, large EGUs 

would not be required to use efficient 

generation technologies (e.g., they could 

use subcritical steam conditions). We 

are not currently considering a standard 

less stringent than 2,300 lb CO2/MWhnet 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 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-operatingmonth rolling average explicitly 

accounts for variable operating 

conditions, allows for a more protective 

standard and decreased compliance 

burden, allows EGUs to have and use a 

consistent basis for calculating 

compliance (i.e., ensuring that 12 

operating months of data would be used 

to calculate compliance irrespective of 

the number of long-term outages), and 

simplifies compliance for state 

permitting authorities. 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 shortterm higher CO2 emission rates as long 

as the 12-month average emissions rate 

is maintained. 

VII. Rationale for Emission Standards 

for Modified Fossil Fuel-Fired Utility 

Boilers and IGCC Units 

A. Introduction 

In this section we explain our 

rationale for proposing, as the ‘‘best 

system of emission reduction . . . 

adequately demonstrated’’ for modified 

fossil fuel-fired utility boiler and IGCC 

EGUs, a combination of best operating 

practices and equipment upgrades. 

We include in this discussion: (1) Our 

rationale for rejecting other alternatives 

as BSER, (2) a description of efficiency 

improvements achieved through a 

combination of best operating practices 

and equipment upgrades and our 

rationale for selecting it as BSER, and 

(3) our rationale for co-proposed 

alternative standards of performance 

based on this BSER (including varying 

the standard depending upon whether 

the affected source would be subject to 

a CAA section 111(d) 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) 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
34986 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

87Subcritical 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. 

88The 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 kilowatthour (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. 

89Chapter 2: Heat Rate Improvement at Existing 

Coal-fired EGUs, Available in the rulemaking 

docket. Docket ID: EPA–HQ–OAR–2013–0603. 

90Coal-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. 

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 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 87 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 

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 coproposed alternative, all modified 

utility boilers and IGCC units will be 

required to meet a unit-specific 

emission standard. In the second coproposed 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 

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 literature and 

selected the Sargent & Lundy 2009 

study 90 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 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34987 

91Legal Memorandum available in rulemaking 

docket ID: EPA–HQ–OAR–20913–0602. 

four upgrade methods, equipment or 

system upgrades could provide a 4 

percent heat rate improvement if all 

were applied on an EGU that has not 

already made those upgrades. 

The 2009 Sargent & Lundy study 

included an estimated range of heat rate 

improvement, and the associated range 

of capital cost for each heat rate 

improvement method, for units ranging 

in size from 200 MW to 900 MW. If the 

methods and unit sizes are combined, as 

though they were all applied on a single 

EGU, the range of Sargent & Lundy 

estimated Btu reductions (412 to 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 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 unit-specific 

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 unitspecific standard of performance will 

not have significant impacts on 

nationwide electricity prices or on the 

structure of the nation’s energy sector. 

d. Incentive for Technological 

Development 

As noted previously, the case law 

makes clear that the EPA is to consider 

the effect of its selection of the BSER on 

technological innovation or 

development, but that the EPA also has 

the authority to weigh this factor, along 

with the various other factors. With the 

selection of emissions controls, 

modified sources face inherent 

constraints that newly constructed 

greenfield and even reconstructed 

sources do not; as a result, modified 

sources present different, and in some 

ways more limited, opportunities for 

technological innovation or 

development. In this case, the proposed 

standards promote technological 

development by promoting further 

development and market penetration of 

equipment upgrades and process 

changes that improve plant efficiency. 

C. Determination of the Level of the 

Standard 

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 sub-categorization 

approach, but, as is detailed in Chapter 

2 of the TSD, ‘‘GHG Abatement 

Measures,’’ analysis of available data 

did not support a number of potential 

sub-categorization options—such as unit 

size, type or age—that intuitively 

seemed logical. 

In this action, the EPA is co-proposing 

two alternative standards of 

performance for modified utility boilers 

and IGCC units. In the first co-proposed 

alternative, all modified sources would 

meet a unit-specific emission limit. In 

the second co-proposed alternative, the 

modified source would be required to 

meet a unit-specific emission limit that 

will depend on the timing of the 

modification. 

For utility boilers or IGCC units 

undertaking modifications, the EPA is 

proposing that the BSER has two 

components: (1) That the source 

operates consistently with its own best 

demonstrated historical performance; 

and (2) that the 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 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 coproposing 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 coproposed 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 we discuss in the Legal 

Memorandum,91 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 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
34988 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

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. 

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 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 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). 

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 

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 50001 92 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 

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 . . . 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34989 

93 ‘‘Standard of Performance for Natural Gas-Fired 

Combustion Turbines’’ Technical Support 

Document, Docket ID: EPA–HQ–OAR–2013–0495. 

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 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 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 onethird. 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—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 

gas-fired 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 

proposal for newly constructed sources, 

respectively—to finalize the same 

standards for newly constructed, 

modified and reconstructed natural gasfired 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 rulemaking 93 and is also 

included in the docket for this proposal. 

Consistent with the January 2014 

proposal, the EPA proposes to 

subcategorize the turbines into the same 

two size-related subcategories currently 

in subpart KKKK for standards of 

performance for the combustion turbine 

criteria pollutants. These subcategories 

are based on whether the design heat 

input rate to the turbine engine is either 

850 MMBtu/h or less, or greater than 

850 MMBtu/h. We further propose to 

establish different standards of 

performance for these two 

subcategories. 

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/MWh-gross 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/MWhgross 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 Gas-Fired 

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 


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34990 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

94Technical Support Document ‘‘Standard of 

Performance for Natural Gas-Fired Combustion 

Turbines’’ available in the rulemaking docket. 

Docket ID: EPA–HQ–OAR–2013–0603. 

95Note 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. 

96For 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. 

turbines.94 The only potential difference 

that the EPA has identified is 

consideration of cost because the 

actions that could trigger modification 

are less extensive changes at the 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., Pre2000) Combined Cycle Unit 

Because the performance of combined 

cycle technology has improved so 

significantly since 2000, we believe that 

upgrading to current technology is 

likely to be cost effective when one 

considers a combination of fuel savings, 

and performance benefits (the ability to 

start up the unit more quickly and 

operate more efficiently over a wider 

range of loads). 

2. Modifications to a Newer Combined 

Cycle Unit 

These modifications are likely to be 

made to return the unit to close to its 

original operating performance, would 

be consistent with the requirements of 

today’s proposal, and are not likely to 

significantly increase the cost of the 

project. 

3. Upgrading a Simple Cycle Turbine to 

a Combined Cycle Unit 

These modifications would be made 

to upgrade the efficiency of the unit, are 

consistent with the requirements of 

today’s 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 gasfired stationary combustion turbines. 

We are requesting comment on a 

range of 950 to 1,100 lb CO2/MWh-gross 

(430 to 500 kg CO2/MWh) for the large 

turbine subcategory and 1,000 to 1,200 

lb CO2/MWh-gross (450 to 540 kg CO2/ 

MWh) for the small turbine subcategory. 

For sources that are subject to a CAA 

section 111(d) plan, the EPA is also 

soliciting comment on whether the 

sources should be allowed to elect, as an 

alternative to the otherwise applicable 

numeric standard, to meet a unitspecific 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 Action 95

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 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 coreductions of SO2, NOX, and PM2.5. 

B. What are the energy impacts? 

This proposed rule is not anticipated 

to have significant impacts on the 

supply, distribution, or use of energy. 

As previously stated, the EPA expects 

few 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 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 fuelVerDate Mar<15>2010 19:40 Jun 17, 2014 Jkt 232001 PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 E:\FR\FM\18JNP3.SGM 18JNP3

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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34991 

97For 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. 

98The 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. 

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. 

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 

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 

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 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 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 


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34992 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

modified to comply with proposed net 

energy output based CO2 emission 

limits. Specifically, the EPA estimates 

that it would take approximately 3 

working months for a technician to 

retrofit existing energy metering 

equipment to meet the proposed net 

energy output requirements. In addition, 

after modifications are made that enable 

a facility to measure net energy output, 

each EGU’s Data Acquisition System 

(DAS) would need to be upgraded to 

accommodate reporting of net energy 

output rate based emissions. A modified 

or reconstructed EGU would be required 

to prepare a quarterly summary report, 

which includes reporting of emissions 

and downtime, every 3 months. The 

reporting burden for such a unit 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $17,217 and 205 labor 

hours. Estimated cost burden is based 

on 2013 Bureau of Labor Statistics (BLS) 

labor cost data. Average burden hours 

per response are estimated to be 47.3 

hours and the average number of annual 

responses over the 3-year ICR period is 

4.33 per year. Burden is defined at 5 

CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

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 proposed 

rule 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 

June 18, 2014, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by July 18, 2014. The 

final rule will respond to any OMB or 

public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, small 

entity is defined as: 

(1) A small business that is defined by 

the SBA’s regulations at 13 CFR 121.201 

(for the electric power generation 

industry, the small business size 

standard is an ultimate parent entity 

with less than 750 employees.); 

(2) a small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and 

(3) a small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The EPA expects few 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 fuel-fired electric 

utility steam generating units (utility 

boilers and IGCC units) or stationary 

combustion turbines in the period of 

analysis. Reconstruction occurs when a 

single project replaces components or 

equipment in an existing facility and 

exceeds 50 percent of the fixed capital 

cost that would be required to construct 

a comparable entirely new facility. Due 

to the limited data available on 

reconstructions, it is not possible to 

conduct a representative illustrative 

analysis of what costs and benefits 

might result from this proposal in the 

unlikely case that a unit were to 

reconstruct. However, based on the low 

number of previous reconstructions and 

the BSER determination based on the 

most efficient available generating 

technology, we would expect this 

proposal to result in no significant CO2

emission changes, quantified benefits, 

or costs for NSPS reconstructions. 

Accordingly, there are no anticipated 

economic impacts as a result of the 

proposed standards for reconstructed 

EGUs. 

Nevertheless, the EPA is aware that 

there is substantial interest in the 

proposed rule among small entities 

(municipal and rural electric 

cooperatives). As summarized in section 

II.G. of this preamble, the EPA has 

conducted an unprecedented amount of 

stakeholder outreach. As part of that 

outreach, agency officials participated 

in many meetings with individual 

utilities as well as meetings with 

electric utility associations. Specifically, 

the EPA Administrator, Gina McCarthy, 

participated in separate meetings with 

both the National Rural Electric 

Cooperative Association (NRECA) and 

the American Public Power Association 

(APPA). The meetings brought together 

leaders of the rural cooperatives and 

public power utilities from across the 

country. The Administrator discussed 

and exchanged information on the 

unique challenges, in particular the 

financial structure, of NRECA and 

APPA member utilities. A detailed 

discussion of the stakeholder outreach 

is included in the preamble to the 

emission guidelines for existing affected 

electric utility generating units being 

proposed in a separate action. 

In addition, as described in the RFA 

section of the preamble to the proposed 

standards of performance for GHG 

emissions from new EGUs (79 FR 1499 

and 1500), 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 


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Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 34993 

and its impacts, including potential 

impacts on small entities. 

D. Unfunded Mandates Reform Act 

This proposed rule does not contain 

a federal mandate that may result in 

expenditures of $100 million or more 

for state, local and tribal governments, 

in the aggregate, or the private sector in 

any 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 

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 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 preproposal update on the emission 

guidelines for existing EGUs and 

emission standards for modified and 

reconstructed EGUs. While formulating 

the provisions of these proposed 

standards, the EPA also considered the 

input provided over the course of the 

extensive stakeholder outreach 

conducted by the EPA (see section II.G. 

of this preamble). In the spirit of 

Executive Order 13132 and consistent 

with the EPA policy to promote 

communications between the EPA and 

state and local governments, the EPA 

specifically solicits comment on this 

proposed action from state and local 

officials. 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It would neither impose 

substantial direct compliance costs on 

tribal governments, nor preempt Tribal 

law. This proposed rule would impose 

requirements on owners and operators 

of reconstructed and modified EGUs. 

The EPA is aware of three coal-fired 

EGUs located in Indian country but is 

not aware of any EGUs owned or 

operated by tribal entities. The EPA 

notes that this proposal 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 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 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 


emcdonald on DSK67QTVN1PROD with PROPOSALS3
34994 Federal Register / Vol. 79, No. 117 / Wednesday, June 18, 2014 / Proposed Rules 

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 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 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 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)). 

List of Subjects in 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. 

Proposed Rule Amendment With 

Changes 

The Environmental Protection Agency 

proposed rule amending 40 CFR parts 

60, 70, 71, and 98, which was published 

at 79 FR 1430, January 8, 2014, 

proposed amendments to the regulatory 

text of 40 CFR part 60, subparts Da and 

KKKK, and, as an alternative to 

amending subparts Da and KKKK, to 

create a new subpart (40 CFR part 60, 

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. 

[FR Doc. 2014–13725 Filed 6–17–14; 8:45 am] 

BILLING CODE 6560–50–P 


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