[Federal Register Volume 79, Number 117 (Wednesday, June 18, 2014)]
[Proposed Rules]
[Pages 34959-34994]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-13725]



[[Page 34959]]

Vol. 79

Wednesday,

No. 117

June 18, 2014

Part III





Environmental Protection Agency





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40 CFR Part 60





Carbon Pollution Standards for Modified and Reconstructed Stationary 
Sources: Electric Utility Generating Units; Proposed Rules

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

[[Page 34960]]


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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.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing 
standards of performance for emissions of greenhouse gases from 
affected modified and reconstructed fossil fuel-fired electric utility 
generating units. Specifically, the EPA is proposing standards to limit 
emissions of carbon dioxide from affected modified and reconstructed 
electric utility steam generating units and from natural gas-fired 
stationary combustion turbines. This rule, as proposed, would continue 
progress already underway to reduce carbon dioxide emissions from the 
electric power sector in the United States.

DATES: Comments on the proposed standards. Comments on the proposed 
standards must be received on or before 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-pollution-standards 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-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0603.
    Facsimile: Fax your comments to (202) 566-9744, Attn: Docket ID No. 
EPA-HQ-OAR-2013-0603.
    Mail: Send your comments to the EPA Docket Center, U.S. EPA, Mail 
Code 28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Attn: 
Docket ID No. EPA-HQ-OAR-2013-0603. Comments on the information 
collection provisions should be mailed to the Office of Information and 
Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St. NW., 
Washington, DC 20503.
    Hand Delivery or Courier: Deliver your comments to the EPA 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

[[Page 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-pollution-standards.

FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy 
Strategies Group, Sector Policies and Programs Division (D243-01), U.S. 
EPA, Research Triangle Park, NC 27711; telephone number (919)541-4003, 
facsimile number (919)541-5450; email address: 
fellner.christian@epa.gov or Dr. Nick Hutson, Energy Strategies Group, 
Sector Policies and Programs Division (D243-01), U.S. EPA, Research 
Triangle Park, NC 27711; telephone number (919)541-2968, facsimile 
number (919)541-5450; email address: hutson.nick@epa.gov.

SUPPLEMENTARY INFORMATION:
    Acronyms. A number of acronyms and chemical symbols are used in 
this preamble. While this may not be an exhaustive list, to ease the 
reading of this preamble and for reference purposes, the following 
terms and acronyms are defined as follows:

AEO Annual Energy Outlook
APPA American Public Power Association
BSER Best System of Emission Reduction
CAA Clean Air Act
CAP Climate Action Plan
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CFB Circulating Fluidized Bed
CH4 Methane
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE/NETL Department of Energy/National Energy Technology Laboratory
EGU Electric Utility Generating Unit
EO Executive Order
EPA Environmental Protection Agency
FB Fluidized Bed
FR Federal Register
GHG Greenhouse Gas
HFC Hydrofluorocarbon
HRSG Heat Recovery Steam Generator
ICR Information Collection Request
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
lb CO2/MWh Pounds of CO2 per Megawatt-hour
lb CO2/MWh-net Pounds of CO2 per Megawatt-hour 
on a net output basis
LCOE Levelized Cost of Electricity
MMBtu/h Million British Thermal Units per Hour
MPa Megapascal
MW Megawatt
MWe Megawatt Electrical
MWh Megawatt-hour
N2 Nitrogen Gas
N2O Nitrous Oxide
NOX Nitrogen Oxide
NAICS North American Industry Classification System
NGCC Natural Gas Combined Cycle
NGR Natural Gas Reburning
NRC National Research Council
NRECA National Rural Electric Cooperative Association
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act
OFA Overfire Air
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbons
PM2.5 Particular Matter less than 2.5 micrometer in 
diameter
PRA Paperwork Reduction Act
psi Pounds per square inch
psig Pounds per square inch-guage
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
SBA Small Business Administration
SCC Social cost of carbon
SCPC Supercritical pulverized coal
SF6 Sulfur Hexafluoride
SO2 Sulfur dioxide
Tg Teragram (one trillion (10\12\) 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

[[Page 34962]]

    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 gas-fired 
stationary combustion turbines. Consistent with the requirements of CAA 
section 111(b), these proposed standards reflect the degree of emission 
limitation achievable through the application of the best system of 
emission reduction (BSER) that the EPA has determined has been 
adequately demonstrated for each type of unit.
    In a separate action, under CAA section 111(d), the EPA is 
proposing emission guidelines for states to use in developing plans to 
limit CO2 emissions from existing fossil fuel-fired EGUs. 
States must then submit plans to the EPA under timing set by that 
action.
2. Summary of the Major Provisions
    The proposed standards for the affected modified and reconstructed 
sources are summarized below in Table 1.

  Table 1--Summary of BSER and Proposed Standards for Affected Sources
------------------------------------------------------------------------
        Affected source                BSER               Standard
------------------------------------------------------------------------
Modified Utility Boilers and    Most efficient     Co-proposed
 IGCC Units.                     generation at      Alternative 1
                                 source            1. Source would be
                                 achievable         required to meet a
                                 through a          unit-specific
                                 combination of     emission limit
                                 best operating     determined by the
                                 practices and      unit's best
                                 equipment          historical annual
                                 upgrades.          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    Most efficient     Co-proposed
 IGCC Units.                     generation at      Alternative 2
                                 source            Source would be
                                 achievable         required to meet a
                                 through a          unit-specific
                                 combination of     emission limit
                                 best operating     dependent upon when
                                 practices and      the modification
                                 equipment          occurs.
                                 upgrades.
                                                   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      Efficient NGCC     1. Sources with heat
 Stationary Combustion           technology.        input >850 MMBtu/h
 Turbines.                                          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   Most efficient     1. Sources with heat
 and IGCC Units.                 generating         input >2,000 MMBtu/h
                                 technology at      would be required to
                                 the affected       meet an emission
                                 source.            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-      Efficient NGCC     1. Sources with heat
 Fired Stationary Combustion     technology.        input >850 MMBtu/h
 Turbines.                                          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.
------------------------------------------------------------------------


[[Page 34963]]

    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).
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    \1\ The ``Legal Memorandum'' supporting document is available in 
the rulemaking docket for the proposed emission guidelines for 
existing source power plants, Docket ID: EPA-HQ-OAR-2013-0602.''
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    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.
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    \2\ See K Mart Corp. v. Cartier, Inc., 486 U.S. 281, 294 (1988) 
(holding that a regulation was severable because the ``[t]he 
severance and invalidation of [the subsection at issue would] not 
impair the function of the statute as a whole, and there [was] no 
indication that the regulation would not have been passed but for 
its inclusion.'').
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    The EPA is proposing that the form of the standards for modified 
and reconstructed natural gas-fired stationary combustion turbines be 
consistent with the standards for newly constructed natural gas-fired 
stationary combustion turbines proposed on January 8, 2014 (79 FR 
1430). In that proposal, the EPA proposed standards for turbines on a 
gross output basis, but also took comment on standards on a net output 
basis. The EPA is similarly proposing standards on a gross output 
basis, while soliciting comment on net output based standards, in 
today's proposal for modified and reconstructed natural gas-fired 
stationary combustion turbines. To the extent that the EPA finalizes 
modified and reconstructed standards for stationary combustion turbines 
that are consistent with the standards for newly constructed stationary 
combustion turbines, the EPA intends to take the same approach with 
regards to the use of net or gross output in both final actions.
3. Costs and Benefits
    As explained in the regulatory impact analysis (RIA) \3\ for this 
proposed rule and further below, the EPA expects few 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\
---------------------------------------------------------------------------

    \3\ The RIA for this proposal is presented as Chapter 9 of the 
RIA for the companion rulemaking for proposed Emission Guidelines 
for Greenhouse Gas Emissions from Existing Stationary Sources: 
Electric Utility Generating Units.
    \4\ For purposes of this summary, we present climate benefits 
from CO2 that were estimated using the model average 
social cost of carbon (SCC) at a 3 percent discount rate. We 
emphasize the importance and value of considering the full range of 
SCC values, however, which include the model average at 2.5 and 5 
percent, and the 95th percentile at 3 percent. Similarly, we 
summarize the health co-benefits in this summary at a 3 percent 
discount rate. We provide estimates based on additional discount 
rates in the RIA.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \8\ 40 CFR part 60 subpart A
---------------------------------------------------------------------------

    For more than four decades, the EPA has used its authority under 
CAA section 111 to set cost-effective emission standards that ensure 
newly constructed, reconstructed and modified stationary sources use 
the best performing technologies to limit emissions of harmful air 
pollutants. In this proposal, the EPA is following the same well-
established interpretation and application of the law under CAA section 
111 to address GHG emissions from modified and reconstructed fossil 
fuel-fired electric steam generating units and natural gas-fired 
stationary combustion turbines.
2. What sources would be regulated by the proposed standards?
    The proposed standards of performance would regulate GHG emissions 
from modified and reconstructed (1) fossil fuel-fired electric steam 
generating units--utility boilers and IGCC units--whose non-

[[Page 34964]]

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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \10\ 40 CFR 60.15(b).
---------------------------------------------------------------------------

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 fuel-fired 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

[[Page 34965]]

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 unit-specific 
emission limit determined by the affected source's best demonstrated 
historical performance (in the years from 2002 to the time of the 
modification) with an additional 2 percent emission reduction (based on 
equipment upgrades). Sources that modify after becoming subject to a 
CAA section 111(d) plan would be required to meet a unit-specific 
emission limit that would be determined by the CAA section 111(d) 
implementing authority and would be based on the source's expected 
performance after implementation of identified unit-specific energy 
efficiency improvement opportunities. The BSER and standards of 
performance for modified fossil-fired electric utility steam generating 
units are discussed further in section VII of this preamble.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

6. What is the BSER and standard of performance for modified natural 
gas-fired stationary combustion turbines?
    For modified natural gas-fired stationary combustion turbines, the 
EPA is proposing standards of performance based on efficient Natural 
Gas Combined Cycle (NGCC) technology as the BSER. The emission limits 
proposed for these sources are 1,000 lb CO2/MWh-gross for 
facilities with heat input ratings greater than 850 MMBtu/h, and 1,100 
lb CO2/MWh-gross for facilities with heat input ratings of 
850 MMBtu/h or less. For sources that are subject to a CAA section 
111(d) plan, the EPA is also soliciting comment on whether the sources 
should be allowed to elect, as an alternative to the otherwise 
applicable numeric standard, to instead meet a unit-specific emission 
standard that is determined by the CAA section 111(d) implementing 
authority based on implementation of identified energy efficiency 
improvement opportunities applicable to the source. This is discussed 
further in section IX of this preamble.
7. What are BSER and the standard of performance for reconstructed 
fossil fuel-fired utility boilers and IGCC units?
    For reconstructed utility boilers and IGCC units, the EPA is 
proposing a standard of performance with BSER based on the most 
efficient generating technology for these types of units (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/MWh-net for sources with a heat input rating of greater 
than 2,000 MMBtu/h or 2,100 lb CO2/MWh-net for sources with 
a heat input rating of 2,000 MMBtu/h or less. The difference in the 
proposed standards for larger and smaller units is based on greater 
availability of higher pressure/temperature steam turbines (e.g. 
supercritical steam turbines) for larger units. The standards could 
also be met through other technology options such as natural gas co-
firing. This is discussed further in section VI below.
---------------------------------------------------------------------------

    \12\ Steam with higher temperature and pressure has more thermal 
energy which can be more efficiently converted to electrical energy.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \13\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
---------------------------------------------------------------------------

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 co-
proposes the same two options for codifying the applicable standards. 
For consistency, the EPA intends--when it takes final action on this 
proposal and on the January 2014 proposal for newly constructed 
sources, respectively--to codify the standards in the same way for the 
sources addressed under the two proposals.
10. What is the organization and approach for this proposal?
    Section II of this preamble provides a brief summary of background 
information on climate change impacts of GHG emissions, GHG emissions 
from fossil-fuel fired EGUs, the utility power sector, the statutory 
and regulatory background relevant to this rulemaking, and the EPA's 
stakeholder outreach activities. Section II also contains additional 
information on the regulatory and litigation history of CAA section 
111.
    The specific proposed requirements for modified and reconstructed 
sources are described in detail in section III of this preamble. The 
rationale for reliance on a rational basis to regulate GHG emissions 
from fossil fuel-fired EGUs and the rationale for the applicability 
requirements in today's proposal are presented in sections IV and V of 
this preamble, respectively. Sections VI through IX of this preamble 
describe the rationale for each of the proposed emission standards, 
including an explanation of the determination of the BSER for 
reconstructed fossil fuel-fired utility boilers and IGCC units and 
modified fossil fuel-fired utility boilers and IGCC units, as well as 
for

[[Page 34966]]

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
----------------------------------------------------------------------------------------------------------------
                                                                                Examples of potentially affected
                           Category                               NAICS code                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).
\b\ Federal, state or local government-owned and operated establishments are classified according to the
  activity in which they are engaged.

    This table is not intended to be exhaustive, but rather to provide 
a guide for readers regarding entities likely to be affected by this 
proposed action. To determine whether your facility, company, business, 
or organization, would be regulated by this proposed action, you should 
examine the applicability criteria in 40 CFR 60.1. If you have any 
questions regarding the applicability of this action to a particular 
entity, consult either the air permitting authority for the entity or 
your EPA regional representative as listed in 40 CFR 60.4 (General 
Provisions).

II. Background

    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.
---------------------------------------------------------------------------

    \14\ This background section is intended to provide the same or 
very similar background information as provided in the companion 
proposals for new sources (79 FR 1430) and existing sources (the CAA 
section 111(d) proposal in today's Federal Register). Any minor 
differences in phrasing between this proposal and the companion 
proposals are not intended to state a substantive difference.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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'').
    \16\ The January 8, 2014, preamble to the proposed GHG standards 
for new EGUs (79 FR 1430) and the RIA supporting that proposal 
include a more detailed summary of the public health and welfare 
impacts detailed in the 2009 Endangerment Finding, as well as a 
discussion of the science supporting the EPA's conclusions regarding 
the question of whether GHG endanger public health and welfare 
including: (1) The process by which the Administrator reached the 
Endangerment Finding in 2009; (2) the EPA's response in 2010 to ten 
administrative petitions for reconsideration of the Endangerment 
Finding (the Reconsideration Denial); and (3) the decision by the 
United States Court of Appeals for the District of Columbia Circuit 
in 2012 to uphold the Endangerment Finding and the Reconsideration 
Denial.
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding \17\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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

[[Page 34967]]

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\
---------------------------------------------------------------------------

    \19\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \20\ Id., p.138.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \21\ National Research Council, Climate Stabilization Targets, 
p. 3.

    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.
---------------------------------------------------------------------------

    \22\ U.S. Global Change Research Program, Climate Change Impacts 
in the United States: The Third National Climate Assessment, May 
2014 Available at http://nca2014.globalchange.gov/.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \23\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
    \24\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
---------------------------------------------------------------------------

B. GHG Emissions From Fossil Fuel-Fired EGUs

    Fossil fuel-fired EGUs are by far the largest emitters of GHGs, 
primarily in the form of CO2, among stationary sources in 
the U.S., and among fossil fuel-fired units, coal-fired units are by 
far the largest emitters. This section describes the amounts of those 
emissions and places those amounts in the context of the national 
inventory of GHGs.
    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.

[[Page 34968]]

anthropogenic emissions and sinks \26\ of GHGs, including 
CO2 emissions, for the years 1990, 2005 and 2012.
---------------------------------------------------------------------------

    \25\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2012'', Report EPA 430-R-14-003, United States Environmental 
Protection Agency, April 15, 2014.
    \26\ Sinks are a physical unit or process that stores GHGs, such 
as forests or underground or deep sea reservoirs of carbon dioxide.

             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           13.7         25.5          37.8
 Forestry......................
Waste..........................        165.0        133.2         124.0
                                ----------------------------------------
    Total Emissions............      6,233.2      7,253.8       6,525.6
Land Use, Land-Use Change and        (831.3)    (1,030.7)        (979.3)
 Forestry (Sinks)..............
                                ----------------------------------------
    Net Emissions (Sources and       5,402.1      6,223.1       5,546.3
     Sinks)....................
------------------------------------------------------------------------

    Total fossil energy-related CO2 emissions (including 
both stationary and mobile sources) are the largest contributor to 
total U.S. GHG emissions, representing 77.7 percent of total 2012 GHG 
emissions.\28\ In 2012, fossil fuel combustion by the electric power 
sector--entities that burn fossil fuel and whose primary business is 
the generation of electricity--accounted for 38.7 percent of all 
energy-related CO2 emissions.\29\ Table 4 below presents 
total CO2 emissions from fossil fuel-fired EGUs, for years 
1990, 2005 and 2012.
---------------------------------------------------------------------------

    \27\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2012, Report EPA 430-R-14-003, United 
States Environmental Protection Agency, April 15, 2014.
    \28\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2012'', Report EPA 430-R-14-003, United 
States Environmental Protection Agency, April 15, 2014.
    \29\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States 
Environmental Protection Agency, April 15, 2014.

     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           1,820.8      2,402.1       2,022.7
 combustion EGUs...............
    --from coal................      1,547.6      1,983.8       1,511.2
    --from natural gas.........        175.3        318.8         492.2
    --from petroleum...........         97.5         99.2          18.8
------------------------------------------------------------------------

C. The Utility Power Sector
---------------------------------------------------------------------------

    \30\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States 
Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------

    Electricity in the United States is generated by a range of 
sources--from power plants that use fossil fuels like coal, oil, and 
natural gas, to non-fossil sources, such as nuclear, solar, wind and 
hydroelectric power. In 2013, over 67 percent of power in the U.S. was 
generated from the combustion of coal, natural gas, and other fossil 
fuels, over 40 percent from coal and over 26 percent from natural 
gas.\31\ In recent years, though, the proportion of new renewable 
generation coming on line has increased dramatically. For instance, 
over 38 percent of new generating capacity (over 5 GW out of 13.5 GW) 
built in 2013 used renewable power generation technologies.\32\
---------------------------------------------------------------------------

    \31\ U.S. Energy Information Administration (EIA), ``Table 7.2b 
Electricity Net Generation: Electric Power Sector Electric Power 
Sector,'' data from April 2014 Monthly Energy Review, release date 
April 25, 2014. Available at: http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&freq=m.
    \32\ Based on Table 6.3 (New Utility Scale Generating Units by 
Operating Company, Plant, Month, and Year) of the U.S. Energy 
Information Administration (EIA) Electric Power Monthly, data for 
December 2013, for the following renewable energy sources: Solar, 
wind, hydro, geothermal, landfill gas, and biomass. Available at: 
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_03.
---------------------------------------------------------------------------

    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

[[Page 34969]]

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\
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    \33\ CAA section 111(b)(1)(A).
    \34\ See generally 40 CFR part 60, subparts D-MMMM.
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    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\
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    \35\ CAA section 111(b)(1)(B).
    \36\ CAA section 111(a)(2).
    \37\ CAA section 111(a)(4).
    \38\ 40 CFR 60.2, 60.14(e).
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    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\
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    \39\ 40 CFR 60.15.
---------------------------------------------------------------------------

    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\
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    \40\ CAA section 111(b)(5).
    \41\ CAA section 111(b)(2).
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    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\
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    \42\ 36 FR 5931 (March 31, 1971)
    \43\ ``Standards of Performance for Fossil-Fuel-Fired Steam 
Generators for Which Construction Is Commenced After August 17, 
1971,'' 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40-46.
    \44\ 42 FR 53657 (October 3, 1977).
    \45\ ``Standards of Performance for Electric Utility Steam 
Generating Units for Which Construction is Commenced After September 
18, 1978,'' 44 FR 33580 (June 11, 1979).
---------------------------------------------------------------------------

    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).
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    \46\ 44 FR 33580 (June 11, 1979).
    \47\ 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 
(March 20, 2009).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \48\ ``Standards of Performance for Electric Utility Steam 
Generating Units, Industrial-Commercial-Institutional Steam 
Generating Units, and Small Industrial-Commercial-Institutional 
Steam Generating Units, Final Rule.'' 71 FR 9866 (February 27, 
2006).
    \49\ State of New York, et al. v. EPA, No. 06-1322.
    \50\ 79 FR 1430.
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F. Stakeholder Outreach

    The EPA has engaged extensively with a broad range of stakeholders 
and the general public regarding climate change, carbon pollution from 
power plants, and carbon pollution reduction opportunities. These 
stakeholders included industry and electric utility representatives, 
state and local officials, tribal officials, labor unions and non-
governmental organizations.
    In February and March 2011, early in the process of developing 
carbon pollution standards for new power plants, the EPA held five 
listening sessions to obtain information and input from key 
stakeholders and the public.

[[Page 34970]]

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\
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    \51\ The discussion of the EPA's regulations in this rulemaking 
is for background purposes only. The EPA is not re-opening, and thus 
is not soliciting comment on, any provision in its existing 
regulations.
    \52\ 40 CFR 60.2, 60.14.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \53\ 40 CFR 60.14.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \54\ The proposal was subsequently withdrawn with the 
publication of the January 8, 2014 proposal.
    \55\ The comments are available in the rulemaking docket. Docket 
ID: EPA-HQ-OAR-2011-0660.
    \56\ 79 FR 1352.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \57\ 40 CFR 60.15(a).

---------------------------------------------------------------------------

[[Page 34971]]

    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.
---------------------------------------------------------------------------

    \58\ 40 CFR 60.15(d)-(e).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \59\ The comments are available in the rulemaking docket. Docket 
ID: EPA-HQ-OAR-2011-0660.
---------------------------------------------------------------------------

    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.

[[Page 34972]]

III. Proposed Requirements for Modified and Reconstructed Sources

A. Applicability Requirements

    We generally refer to fossil fuel-fired electric generating units 
that would be subject to an emission standard in this rulemaking as 
``affected'' or ``covered'' sources, units, facilities or simply as 
EGUs. These sources meet both the definition of ``affected'' and 
``covered'' EGUs subject to an emission standard as provided by this 
proposed rule, and the criteria for being considered ``modified'' and 
``reconstructed'' sources as defined under the provisions of CAA 
section 111 and the EPA's regulations.
    The EPA is proposing generally similar applicability requirements, 
for purposes of this rule, that the EPA proposed in the January 2014 
proposal.\60\ \61\ This section describes those requirements.
---------------------------------------------------------------------------

    \60\ See 79 FR 1445 and 1446. Note that the statements in the 
January 2014 Proposal that ``existing sources undertaking 
modifications or reconstructions; or certain projects under 
development, including the proposed Wolverine EGU project in Rogers 
City, Michigan (and, perhaps, up to two others)'' are not subject to 
that rulemaking, 79 FR 1446, are not relevant for 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \62\ E.g., 40 CFR 60.40Da(a)(1).
    \63\ 40 CFR 60.41Da (definition of (``Electric utility steam-
generating unit'').
    \64\ Id.
---------------------------------------------------------------------------

    We are proposing and soliciting comment on an additional amendment, 
not included in the January 2014 proposal, to clarify that net-electric 
sales, for applicability purposes, includes electricity supplied to 
other facilities that produce electricity to offset auxiliary loads. 
Without this amendment, smaller EGUs that are co-located with larger 
EGUs could claim that they do not meet the rule applicability criteria 
because their generated power is used to offset the parasitic loads of 
the larger facility. We are also soliciting comment if the 10 percent 
fossil fuel use criteria should be based on 3 consecutive calendar 
years or on a 3 year rolling average basis.
    Consistent with the January 2014 proposal, we are proposing several 
additional adjustments to the way applicability is currently determined 
under subpart Da for purposes of modifications and reconstructions. 
First, we are proposing that the definition of ``potential electric 
output'' be revised to include ``or the design net electric output 
efficiency'' as an alternative to the default one-third efficiency 
value (i.e., the proposed definition is ``33 percent or the design net 
electric output efficiency times the maximum design heat input capacity 
of the steam generating unit, divided by 3,413 Btu/KWh, divided by 
1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent 
efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel 
heat input capacity would have a 310,000 MWh 12 month potential 
electrical output capacity)'' (emphasis added)). Next, we are proposing 
to add ``of the thermal host facility or facilities'' to the definition 
of ``net-electric output'' (i.e., the proposed definition would read 
``. . . the gross electric sales to the utility power distribution 
system 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

[[Page 34973]]

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).
---------------------------------------------------------------------------

    \65\ Oil-fired stationary combustion turbines, including both 
simple and combined cycle units, are not subject to these proposed 
standards. These units are typically used only in areas that do not 
have reliable access to pipeline natural gas (for example, in non-
continental areas).
---------------------------------------------------------------------------

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/MWh-gross. We also solicit comment on whether we should 
use a net output-based approach.
    The proposed method to calculate compliance is the same as was 
proposed in the January 2014 proposal. Compliance would be calculated 
as the sum of the emissions for all operating hours divided by the sum 
of the useful energy output over a rolling 12-operating-month period. 
In the alternative, as in the January 2014 proposal, we solicit comment 
on requiring calculation of compliance on an annual (calendar year) 
period. See 79 FR 1477.
    We are proposing additional amendments to the definition of useful 
thermal output. The current definition excludes energy used to enhance 
the performance of the affected facility from being considered as 
useful thermal output. The intent of this restriction is to clarify 
that thermal energy that is directly used by the affected facility to 
create additional output (e.g., the economizer) is not counted as 
useful thermal output. Without this restriction, the energy could be 
doubled counted--once as useful thermal output and again as electric 
output. This could also be interpreted to exclude thermal energy used 
to reduce fuel moisture (e.g., coal drying) as being useful thermal 
output because it enhances the performance of the affected facility. 
However, coal-drying could be done at a separate offsite facility by an 
industrial boiler prior to delivery at the power 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 [deg]C and 
14.5 pounds per square inch (psi)) instead of International 
Organization for Standardization (ISO) conditions (15 [deg]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

[[Page 34974]]

facility. For example, should large subcritical steam generating units 
have a most stringent standard that is less stringent (i.e., greater 
than) 1,900 lb CO2/MWh-net, which is based on the use of a 
supercritical steam cycle.
---------------------------------------------------------------------------

    \66\ Additional detail can be found in the Technical Support 
Document: ``GHG Abatement Measures'' (Chapter 2: Heat Rate 
Improvement at Existing Coal-fired EGUs), available in rulemaking 
docket ID: EPA-HQ-OAR-2013-0602.
---------------------------------------------------------------------------

    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 unit-
specific numeric emission standard that would be dependent on the 
timing of the modification relative to the adoption of a CAA section 
111(d) plan that covers the source. Specifically, the EPA proposes that 
sources that modify prior to becoming subject to a CAA section 111(d) 
plan would be required to meet the same standard described in the first 
co-proposed alternative--that is, the modified source would be required 
to meet a unit-specific emission limit determined by the affected 
source's best demonstrated historical performance (in the years from 
2002 to the time of the modification) with an additional 2 percent 
emission reduction. Sources that modify after becoming subject to a CAA 
section 111(d) plan would be required to meet a unit-specific emission 
limit that would be determined by the CAA section 111(b) implementing 
authority and would be based on the source's expected performance after 
implementation of identified unit-specific energy efficiency 
improvement opportunities. We seek comment on all aspects of these co-
proposals, including whether the CAA section 111(b) implementing 
authority would determine the unit-specific emission limit, even when 
the implementing authority is a state, as opposed to the EPA.
---------------------------------------------------------------------------

    \67\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
---------------------------------------------------------------------------

    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

[[Page 34975]]

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\
---------------------------------------------------------------------------

    \68\ This subcategorization of stationary combustion turbines is 
consistent with the subcategories used in the combustion turbine 
(subpart KKKK) criteria pollutant NSPS. The size limit of 850 MMBtu/
h corresponds to approximately 100 MWe.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \69\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
---------------------------------------------------------------------------

    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/MWh-net;
    (2) for reconstructed fossil fuel-fired boilers and IGCC units with 
a heat input rating of 2,000 MMBtu/h or less, a range of 1,900-2,300 lb 
CO2/MWh-net;
    (3) for reconstructed stationary combustion turbines with a heat 
input rating greater than 850 MMBtu/h, a range of 950-1,100 lb 
CO2/MWh-gross; and
    (4) for reconstructed stationary combustion turbines with a heat 
input rating of 850 MMBtu/h or less, a range of 1,000-1,200 lb 
CO2/MWh-gross.
    We also solicit comment on whether: (1) The standards for utility 
boilers and IGCC units should be subcategorized by primary fuel type, 
(2) the small utility boiler and IGCC unit subcategory should be 
limited to utility boilers so that all IGCC units would be in the large 
subcategory regardless of size, or if there are sufficient alternate 
compliance technologies (e.g., co-firing natural gas) that the small 
unit subcategory is unnecessary and should be eliminated so that those 
sources would be required to meet the same emission standard as large 
utility boilers and IGCC units, and (3) an annual short-term 
performance test should be required for stationary combustion turbines 
in addition to the 12-operating-month rolling average standard. 
Requiring an initial and annual short term compliance 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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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

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

[[Page 34976]]

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-by-case enforcement discretion, not 
for specification in advance by regulation.''). In addition, emissions 
during a malfunction event can be significantly higher than emissions 
at any other time of source operation and thus accounting for 
malfunctions could lead to standards that are significantly less 
stringent than levels that are achieved by a well-performing, non-
malfunctioning source. It is reasonable to interpret 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.
---------------------------------------------------------------------------

    \72\ The court's reasoning in NRDC focuses on civil judicial 
actions. The court noted that ``EPA's ability to determine whether 
penalties should be assessed for Clean Air Act violations extends 
only to administrative penalties, not to civil penalties imposed by 
a court.'' Id.
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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

[[Page 34977]]

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 quality-assured data are collected and recorded for all of the 
parameters used to calculate CO2 mass emissions. EGU owners 
or operators would have the option to use backup monitoring systems, as 
provided in sections 75.10(e) and 75.20(d), to help meet this proposed 
data capture requirement.
    We are proposing two additional amendments to the monitoring 
requirements. First, we are proposing that 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.

[[Page 34978]]

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 co-proposal for the treatment of the two 
affected source categories, and for how the regulatory requirements 
applicable to these source categories would be codified in 40 CFR part 
60. Specifically, the EPA proposed to create subcategories within each 
category, and to codify the regulatory requirements for each 
subcategory in 40 CFR part 60, subparts Da and KKKK, respectively. In 
addition, the EPA co-proposed to combine the two categories for 
purposes of regulating the CO2 emissions, and to codify all 
the CO2 regulatory requirements in a new subpart, TTTT.
    As noted, the EPA expects to finalize the January 2014 proposal by 
the time that it finalizes this proposed rulemaking for modified and 
reconstructed fossil fuel-fired EGUs. It is the EPA's intent that the 
approach for categorization and codification will be the same in the 
final action for this proposal as is finalized for the January 2014 
proposal. However, because this rulemaking is a separate action from 
the January 2014 proposal, the EPA is making the same proposal and co-
proposal with regard to categories and codification for modified and 
reconstructed sources that it made with regard to new construction 
sources in the January 2014 proposal. That is, the EPA proposes to 
create subcategories within each category and to codify the regulatory 
requirements in 40 CFR part 60, subparts Da and KKKK, respectively; and 
in addition, the EPA co-proposes to combine the two categories for 
purposes of regulating CO2 emissions, and to codify all the 
CO2 regulatory requirements in a new subpart TTTT. See 79 FR 
1452 through 1454.

[[Page 34979]]

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 third-party-
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.
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    \73\ Requests for comment in the January 2014 proposal regarding 
the appropriateness of certain applicability requirements that are 
based on a source's operations do not apply to this proposed 
rulemaking. Whereas newly constructed sources would not have a 
history of operating, in this rulemaking, the affected sources that 
would be undertaking modifications or reconstructions do have an 
operating history.
---------------------------------------------------------------------------

    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

[[Page 34980]]

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.
---------------------------------------------------------------------------

    \74\ All public comments on the January 2014 proposal are 
available in the rulemaking docket, Docket ID: EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

    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

[[Page 34981]]

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:
---------------------------------------------------------------------------

    \75\ Portland Cement Association v. Ruckelshaus, 486 F.2d 375 
(D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 
1981); Portland Cement Association v. EPA, 665 F.3d 177 (D.C. Cir. 
2011).
---------------------------------------------------------------------------

     The system of emission reduction must be technically 
feasible.
     The EPA must consider the amount of emissions reductions 
that the system would generate.
     The costs of the system must be reasonable. The EPA may 
consider the costs on the source level, the industry-wide level, and, 
at least in the case of the power sector, on the national level in 
terms of the overall costs of electricity and the impact on the 
national economy over time.\76\
---------------------------------------------------------------------------

    \76\ As discussed in the January 2014 Proposal, the D.C. 
Circuit's case law formulates the cost consideration in various 
ways: The costs must not be ``exorbitant [ ]'', Essex Chemical Corp. 
v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), see Lignite 
Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999); ``greater 
than the industry could bear and survive,'' Portland Cement 
Association v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or 
``excessive'' or ``unreasonable.'' Sierra Club v. Costle, 657 F.2d 
298, 343 (D.C. Cir. 1981). In the January 2014 Proposal, EPA stated 
that ``these various formulations of the cost standard . . . are 
synonymous,'' and, for convenience, EPA used ``reasonableness'' as 
the formulation. EPA takes the same approach in this proposal.
---------------------------------------------------------------------------

     The EPA must also consider that CAA section 111 is 
designed to promote the deployment, development and implementation of 
technology.77 78
---------------------------------------------------------------------------

    \77\ See 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \79\ 40 FR 58417-58418, December 16, 1975 (final NSPS 
modification, notification, and reconstruction provisions).
---------------------------------------------------------------------------

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

[[Page 34982]]

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\
---------------------------------------------------------------------------

    \80\ Note 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \81\ Technical 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.
---------------------------------------------------------------------------

    However, the EPA does not, at present, have sufficient information 
about costs to propose that partial CCS is the BSER for reconstructed 
utility boilers and IGCC units. Utility boilers are numerous and 
diverse in size and configuration, and the EPA does not have sufficient 
information about the range of specific configurations that would be 
necessary to estimate the cost of partial CCS, on either a source-
specific basis or an industry-wide basis. In particular, retrofitting a 
plant with partial CCS would entail integrating the carbon capture 
equipment with the affected unit's steam cycle (or with an external 
source of steam or heat) in order to release the 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 co-fired 
without any capital investment or impact on the performance of the 
affected facility (e.g., an existing IGCC facility that already has a 
sufficient natural gas supply), the costs of CO2 reduction 
would still be approximately $75/ton of CO2 avoided. 
Therefore, we are not proposing natural gas co-firing as part of the 
BSER for modified or reconstructed steam generating units.
---------------------------------------------------------------------------

    \82\ Chapter 2, GHG Abatement Measures Technical Support 
Document, available in Docket EPA-HQ-OAR-2013-0602.
---------------------------------------------------------------------------

    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.
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    \83\ Fuel lean gas reburning (FLGR\TM\), also known as 
controlled gas injection, similar to NGR. In FLGR\TM\, 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 FLGR\TM\ 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.
---------------------------------------------------------------------------

    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.

[[Page 34983]]

Both coal-fired and NGCC EGUs have demonstrated the technical 
feasibility of integrating concentrating solar thermal energy for use 
in boiler feed water heating, preheating makeup water, and/or producing 
steam for use in the steam turbine or to power the boiler feed pumps. 
While hybrid power plants can reduce the CO2 emission rate 
by several percent compared to similar non-hybrid power plants, not all 
modified and reconstructed EGUs may have the space or meteorological 
conditions to generate enough solar thermal energy to successfully 
convert to a hybrid power plant. Solar thermal facilities require 
abundant sunshine and significant land area and the EPA does not have 
sufficient information about the range of specific configurations that 
would be necessary to estimate the cost of implementation, on either a 
source-specific basis or an industry-wide basis. We solicit comment on 
whether hybrid power plant technology is broadly applicable to modified 
and reconstructed EGUs and on the costs of integrating non-emitting 
generation.
    Our understanding is that one of the benefits of hybrid fossil EGUs 
is decreased incremental cost of the non-emitting (e.g., solar thermal) 
generated electricity due to the ability to use equipment (e.g., HRSG, 
steam turbine, condenser, etc.) already included at the fossil fuel-
fired EGU, as well as improvement of the electrical generation 
efficiency of the 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 non-emitting solar thermal generation in a 
hybrid power plant is the costs of the mirrors, additional piping, and 
a steam turbine that is 10 to 20 percent larger than a comparable 
fossil only EGU to accommodate the additional steam load during sunny 
hours.
    We specifically solicit comment on an alternate, but similar, 
approach for modified and reconstructed fossil fuel-fired 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-fuel-
fired EGUs under a 111(d) program. The building blocks are:
    1. Lowering the carbon intensity of generation at individual 
affected EGUs (e.g., through heat rate improvements);
    2. Reducing emissions of the most carbon-intensive affected EGUs to 
the extent that this can be accomplished cost-effectively by shifting 
generation to less carbon-intensive existing NGCC units, including NGCC 
units that are under construction;
    3. Reducing emissions of carbon-emitting EGUs to the extent that 
this can be accomplished cost-effectively by expanding the amount of 
new, lower (or no) carbon-intensity generation; and,
    4. Reducing emissions of carbon-emitting EGUs to the extent that 
this can be accomplished cost-effectively by increasing demand-side 
energy efficiency.
    In this rulemaking, we are, in effect, utilizing building block 
one--lowering the carbon intensity of generation at individual affected 
EGUs through heat rate improvements--as part of the BSER determination 
for modified units, but we are not proposing that building blocks two, 
three, or four are components of the BSER determination. We solicit 
comment on 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\
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    \84\ Note that the discussion of efficiency improvements in this 
section is limited to reconstructed utility boilers and IGCC units. 
We discussed efficiency improvements for modifications below.
---------------------------------------------------------------------------

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 [deg]C (1,120 [deg]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.

[[Page 34984]]

    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 [deg]C (980 [deg]F) and 40 percent have no steam 
reheat. Increasing the steam pressure to 20 MPa (2,900 psig) and 568 
[deg]C (1,054 [deg]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 [deg]C 
(1,060 [deg]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

[[Page 34985]]

that system or technology. To determine an achievable emission 
standard, we reviewed the emission rate information submitted by 
owners/operators of coal-fired EGUs to the EPA's Clean Air Markets 
Division. For reconstructed fossil fuel-fired boiler and IGCC EGUs, the 
EPA proposes to find that the best available steam cycle--which qualify 
as the BSER--supports a standard of 1,900 lb CO2/MWh-net for 
large EGUs (i.e., those with heat input greater than 2,000 MMBtu/h), 
and 2,100 lb CO2/MWh-net for small EGUs (i.e., those with a 
heat input 2,000 MMBtu/h or less). The DOE/NETL estimates that an IGCC 
unit emission rate is comparable to those achieved by a supercritical 
coal-fired EGU. Therefore, for both technologies, these levels of the 
standard are based on the emission performance that can be achieved by 
a large pulverized or CFB coal unit using supercritical steam 
conditions and a small unit using subcritical steam conditions.
    We are also soliciting comment on whether the emission limit may be 
more appropriately set at a different level. Based on the rationale 
included in the Technical Support Document (TSD),\85\ we are soliciting 
comment on a range of 1,700 to 2,100 lb CO2/MWh-net for 
large units and 1,900 to 2,300 lb CO2/MWh-net for small 
units. An emission rate of 1,700 lb CO2/MWh-net could 
potentially be met by an EGU using advanced ultra-supercritical steam 
conditions.\86\
---------------------------------------------------------------------------

    \85\ ``Best System of Emissions Reduction (BSER) for 
Reconstructed Electric Utility Steam Generating Units (EGUs) and 
Integrated Gasification Combined Cycle Facilities (IGCC)'' Technical 
Support Document available in the rulemaking docket (EPA-HQ-OAR-
2013-0603).
    \86\ Advanced ultra-supercritical steam conditions are 700-760 
[deg]C (1,290-1,400 [deg]F) and 36 MPa (5,000 psi).
---------------------------------------------------------------------------

    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/MWh-net for small units because at that level, the NSPS 
would not necessarily promote the use of the best available steam 
conditions because many smaller subcritical units are operating well 
below 2,300 lb CO2/MWh-net.

D. Compliance Period

    The EPA is proposing that sources would be required to meet the 
proposed standards on a 12 operating-month rolling basis. The proposed 
compliance period requirements and rationale are the same as in the 
January 2014 proposal. This section provides a summary of the 
rationale. For additional detail, see 79 FR 1481 and 1482.
    The 12-operating-month averaging period being proposed is important 
because of the inherent variability in power plant GHG emissions rates. 
Establishing a shorter averaging period would necessitate establishing 
a standard to account for the conditions that result in the lowest 
efficiency and therefore the highest GHG emissions rate.
    EGU efficiency has a significant impact on the source's GHG 
emission rate. EGU efficiency can vary from month to month throughout 
the year. For example, high ambient temperature can negatively impact 
the efficiency of combustion turbine engines and steam generating 
units. As a result, an averaging period shorter than 12 operating-
months would require us to set a standard that could be achieved under 
these conditions. This standard could potentially be high enough that 
it would not be a meaningful constraint during other parts of the year. 
In addition, operation at low load conditions can also negatively 
impact efficiency. It is likely that for some short period of time an 
EGU will operate at an unusually low load. A short averaging period 
that accounts for this operation would again not produce a meaningful 
constraint for typical loads.
    On the other hand, a 12-operating-month rolling average explicitly 
accounts for variable operating conditions, allows for a more 
protective standard and decreased compliance burden, allows EGUs to 
have and use a consistent basis for calculating compliance (i.e., 
ensuring that 12 operating months of data would be used to calculate 
compliance irrespective of the number of long-term outages), and 
simplifies compliance for state permitting authorities. The EPA 
proposes that it is not necessary to have a shorter averaging period 
for CO2 from these sources because the effect of GHGs on 
climate change depends on global atmospheric concentrations which are 
dependent on cumulative total emissions over time, rather than hourly 
or daily emissions fluctuations or local pollutant concentrations. 
Unlike for emissions of criteria and hazardous air pollutants, we do 
not believe that there are measureable implications to health or 
environmental impacts from short-term higher CO2 emission 
rates as long as the 12-month average emissions rate is maintained.

VII. Rationale for Emission Standards for Modified Fossil 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)

[[Page 34986]]

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.
---------------------------------------------------------------------------

    \87\ Subcritical coal-fired boilers are designed and operated 
with a steam cycle below the critical point of water. Supercritical 
coal-fired boilers are designed and operated with a steam cycle 
above the critical point of water. Increasing the steam pressure and 
temperature improves the efficiency of a steam turbine converting 
thermal energy to electricity, which in turn leads to increased 
efficiency and a lower emission rate.
---------------------------------------------------------------------------

    Unlike in the case of reconstruction explained above, it is the 
understanding of the EPA that modifications do not typically involve 
the type of boiler rebuilding that would make this an option with 
reasonable cost. Consequently, the EPA does not propose to find that 
the use of the most efficient generation technology meets the criteria 
for the BSER for a uniform nationwide standard of performance.
3. Best Operating Practices and Equipment Upgrades
    The second option that EPA considered for modified fossil fuel-
fired utility boilers and IGCC units is a combination of best operating 
practices and equipment upgrades. Best operating practices includes 
both operating the unit in the most efficient manner for a given 
operating condition and replacing worn components in a timely manner. 
Equipment upgrades involve replacing existing components with upgraded 
ones or a more extensive overhaul of major equipment (turbine or 
boiler). We propose to find that this option meets the criteria for 
BSER for these EGUs.
    In addition, we are co-proposing two alternative standards of 
performance reflective of this BSER. In the first co-proposed 
alternative, all modified utility boilers and IGCC units will be 
required to meet a unit-specific emission standard. In the second co-
proposed alternative, modified sources will be required to meet unit-
specific emission limits that will depend on whether the affected unit 
undertakes the modification before it becomes subject to a CAA section 
111(d) state plan (or promulgated federal plan), or after it becomes 
subject to such a plan. Each variation of the BSER meets the criteria, 
which we discuss next. We describe the variations in more detail in the 
section concerning the standards of performance, which follows the 
discussion of the criteria.
a. Technical Feasibility
    A wide range of studies have been performed evaluating the 
opportunity to improve the heat rate (or efficiency) \88\ of an 
existing power plant without upgrading to the most efficient generation 
technology available. These studies are summarized in Chapter 2 of the 
TSD, ``GHG Abatement Measures'' \89\ which explains that, while the 
studies are different in the level of detail and 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.
---------------------------------------------------------------------------

    \88\ The heat rate is a common way to measure EGU efficiency. As 
the efficiency of a fossil fuel-fired EGU is increased, less fuel is 
burned per kilowatt-hour (kWh) generated by the EGU. This results in 
a corresponding decrease in CO2 and other air pollutant 
emissions. Heat rate is expressed as the number of British thermal 
units (Btu) or kilojoules (kJ) that are required to generate 1 kWh 
of electricity. Lower heat rates are associated with more efficient 
fossil fuel-fired EGUs.
    \89\ Chapter 2: Heat Rate Improvement at Existing Coal-fired 
EGUs, Available in the rulemaking docket. Docket ID: EPA-HQ-OAR-
2013-0603.
---------------------------------------------------------------------------

    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

[[Page 34987]]

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.
---------------------------------------------------------------------------

    \90\ Coal-fired Power Plant Heat Rate Reductions, SL-009597 
Final Report, January 2009. Available in the rulemaking docket and 
at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.
---------------------------------------------------------------------------

    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 unit-specific standard of 
performance will not have significant impacts on nationwide electricity 
prices or on the structure of the nation's energy sector.
d. Incentive for Technological Development
    As noted previously, the case law makes clear that the EPA is to 
consider the effect of its selection of the BSER on technological 
innovation or development, but that the EPA also has the authority to 
weigh this factor, along with the various other factors. With the 
selection of emissions controls, modified sources face inherent 
constraints that newly constructed greenfield and even reconstructed 
sources do not; as a result, modified sources present different, and in 
some ways more limited, opportunities for technological innovation or 
development. In this case, the proposed standards promote technological 
development by promoting further development and market penetration of 
equipment upgrades and process changes that improve plant efficiency.

C. Determination of the Level of the Standard

    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 co-proposing standards of performance 
that are dependent on the timing of the modification. Specifically, a 
source that modifies prior to becoming subject to a CAA section 111(d) 
plan would be required to meet an emission limit that is determined 
using the same methodology described in the first co-proposed 
alternative. The modified utility boiler or IGCC unit would be required 
to maintain an emission rate that equals the unit's best demonstrated 
annual performance during the years from 2002 to the year the 
modification occurs, multiplied by 98 percent (i.e., a 2 percent 
further reduction based on equipment upgrades), but not to be more 
stringent than the emission limit applicable to a corresponding 
reconstructed source. The EPA is proposing that units undertaking 
modifications after they become subject to a CAA section 111(d) plan 
would be required to meet a unit-specific emission limit that is 
determined by the CAA section 111(d) implementing authority from an 
assessment to identify energy efficiency improvement opportunities for 
the affected source. This standard is informed by the fact that, as 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.
---------------------------------------------------------------------------

    \91\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-20913-0602.
---------------------------------------------------------------------------

    The EPA also solicits comment on whether the period of best 
historical performance should be the years from

[[Page 34988]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 . 
. .

[[Page 34989]]

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 
one-third. As we explained in the proposal, few simple cycle turbines 
operate at an annual capacity factor of greater than one-third. (79 FR 
1459)
d. Incentive for Technology Innovation
    We recognize that because NGCC technology is already the state of 
the art technology, and is widely used, for natural gas stationary 
combustion turbines, identifying this technology as the BSER may not 
provide significant incentive for technology innovation. However, we 
are according less weight to this factor in this case because we 
consider this technology to be highly efficient and because the only 
more stringent alternative--CCS--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 gas-fired stationary combustion turbines. The EPA 
solicits comment on this approach and on any reasons why these sources 
should not have consistent standards.
    In the January 2014 proposal, the EPA indicated that it had 
reviewed the CO2 emissions data from 2007 to 2011 for 
natural gas-fired (non-CHP) combined cycle units that commenced 
operation on or after January 1, 2000, and that reported complete 
electric generation data, including output from the steam turbine, to 
the EPA. A more detailed description of the emissions data analysis is 
included in a TSD in the docket for that rulemaking \93\ and is also 
included in the docket for this proposal.
---------------------------------------------------------------------------

    \93\ ``Standard of Performance for Natural Gas-Fired Combustion 
Turbines'' Technical Support Document, Docket ID: EPA-HQ-OAR-2013-
0495.
---------------------------------------------------------------------------

    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/MWh-gross for the 
large turbine subcategory and 1,000 to 1,200 lb CO2/MWh-
gross for the small turbine subcategory.

IX. Rationale for Emission Standards for Modified Natural 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

[[Page 34990]]

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.
---------------------------------------------------------------------------

    \94\ Technical Support Document ``Standard of Performance for 
Natural Gas-Fired Combustion Turbines'' available in the rulemaking 
docket. Docket ID: EPA-HQ-OAR-2013-0603.
---------------------------------------------------------------------------

1. Modifications to an Older (e.g., Pre-2000) Combined Cycle Unit
    Because the performance of combined cycle technology has improved 
so significantly since 2000, we believe that upgrading to current 
technology is likely to be cost effective when one considers a 
combination of fuel savings, and performance benefits (the ability to 
start up the unit more quickly and operate more efficiently over a 
wider range of loads).
2. Modifications to a Newer Combined Cycle Unit
    These modifications are likely to be made to return the unit to 
close to its original operating performance, would be consistent with 
the requirements of today's proposal, and are not likely to 
significantly increase the cost of the project.
3. Upgrading a Simple Cycle Turbine to a Combined Cycle Unit
    These modifications would be made to upgrade the efficiency of the 
unit, are consistent with the requirements of today's proposal, and are 
not likely to significantly increase the cost of the project.
4. Modifications to a Simple Cycle Turbine Other Than Upgrading to 
Combined Cycle
    As was noted above--and in the proposal for newly constructed 
sources--when operating at higher capacity factors, the use of combined 
cycle technology instead of simple cycle technology pays for itself in 
fuel savings alone.
    For these reasons, we find the use of NGCC technology to be BSER 
for modified natural gas-fired combustion turbines.

B. Determination of the Standards of Performance

    We propose that the same standards of performance described above 
for reconstructed natural gas-fired stationary combustion turbines are 
also appropriate for modified natural gas-fired stationary combustion 
turbines.
    We are requesting comment on a range of 950 to 1,100 lb 
CO2/MWh-gross (430 to 500 kg CO2/MWh) for the 
large turbine subcategory and 1,000 to 1,200 lb CO2/MWh-
gross (450 to 540 kg CO2/MWh) for the small turbine 
subcategory.
    For sources that are subject to a CAA section 111(d) plan, the EPA 
is also soliciting comment on whether the sources should be allowed to 
elect, as an alternative to the otherwise applicable numeric standard, 
to meet a unit-specific emission standard, determined by the CAA 111(d) 
implementing authority, based on implementation of identified energy 
efficiency improvement opportunities applicable to the source.

X. Impacts of the Proposed Action \95\
---------------------------------------------------------------------------

    \95\ Note that the EPA does not project any difference in the 
impacts between the alternative to regulate sources under subparts 
Da and KKKK versus regulating them under new subpart TTTT.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \96\ For purposes of this summary, we present climate benefits 
from CO2 that were estimated using the model average SCC 
at a 3 percent discount rate. We emphasize the importance and value 
of considering the full range of SCC values, however, which include 
the model average at 2.5 and 5 percent, and the 95th percentile at 3 
percent. Similarly, we summarize the health co-benefits in this 
synopsis at a 3 percent discount rate. We provide estimates based on 
additional discount rates in the RIA.
---------------------------------------------------------------------------

A. What are the air impacts?

    As explained immediately above, the EPA expects few modified or 
reconstructed EGUs in the period of analysis. Because there have been a 
limited number of units that have notified the EPA of NSPS 
modifications in the past, we have conducted an illustrative analysis 
of the impacts for a hypothetical unit that triggered the modification 
provision. For this illustrative example, we estimate CO2 
reductions of 133,000 to 266,000 tons in 2025. Additionally, we 
estimate co-reductions of SO2, NOX, and 
PM2.5.

B. What are the energy impacts?

    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 
fuel-

[[Page 34991]]

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\
---------------------------------------------------------------------------

    \97\ For purposes of this summary, we present climate benefits 
from CO2 that were estimated using the model average 
social cost of carbon (SCC) at a 3 percent discount rate. We 
emphasize the importance and value of considering the full range of 
SCC values, however, which include the model average at 2.5 percent 
and 5 percent, and the 95th percentile at 3 percent. Similarly, we 
summarize the health co-benefits in this synopsis at a 3 percent 
discount rate. We provide estimates based on additional discount 
rates in the RIA.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \98\ The information collection requirements in the January 2014 
proposal have been submitted for approval to the OMB under the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR document 
prepared by the EPA for the January 2014 proposal has been assigned 
the EPA ICR number 2465.02.
---------------------------------------------------------------------------

    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

[[Page 34992]]

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

[[Page 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 pre-proposal update on 
the emission guidelines for existing EGUs and emission standards for 
modified and reconstructed EGUs. While formulating the provisions of 
these proposed standards, the EPA also considered the input provided 
over the course of the extensive stakeholder outreach conducted by the 
EPA (see section II.G. of this preamble). In the spirit of Executive 
Order 13132 and consistent with the EPA policy to promote 
communications between the EPA and state and local governments, the EPA 
specifically solicits comment on this proposed action from state and 
local officials.

F. Executive Order 13175, Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It would neither 
impose substantial direct compliance costs on tribal governments, nor 
preempt Tribal law. This proposed rule would impose requirements on 
owners and operators of reconstructed and modified EGUs. The EPA is 
aware of three 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

[[Page 34994]]

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