[Federal Register Volume 77, Number 72 (Friday, April 13, 2012)]
[Proposed Rules]
[Pages 22392-22441]
[FR Doc No: 2012-7820]

Vol. 77

Friday,

No. 72

April 13, 2012

Part II

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources; Electric Utility Generating Units; Proposed Rule

Federal Register / Vol. 77, No. 72 / Friday, April 13, 2012 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2011-0660; FRL-9654-7]
RIN 2060-AQ91

Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The United States EPA is proposing new source performance
standards for emissions of carbon dioxide (CO2) for new
affected fossil fuel-fired electric utility generating units (EGUs).
The EPA is proposing these requirements because CO2 is a
greenhouse gas (GHG) and fossil fuel-fired power plants are the
country's largest stationary source emitters of GHGs. The EPA in 2009
found that by causing or contributing to climate change, GHGs endanger
both the public health and the public welfare of current and future
generations. The proposed requirements, which are strictly limited to
new sources, would require new fossil fuel-fired EGUs greater than 25
megawatt electric (MWe) to meet an output-based standard of 1,000
pounds of CO2 per megawatt-hour (lb CO2/MWh),
based on the performance of widely used natural gas combined cycle
(NGCC) technology. Because of the economics of the energy sector, the
EPA and others project that NGCC will be the predominant choice for new
fossil fuel-fired generation even absent this rule. In its base case
analysis, the EPA does not project any new coal-fired EGUs without CCS
to be built in the absence of this proposal through 2030. New coal-
fired or pet coke-fired units could meet the standard either by
employing carbon capture and storage (CCS) \1\ of approximately 50% of
the CO2 in the exhaust gas at startup, or through later
application of more effective CCS to meet the standard on average over
a 30-year period. The 30-year averaging option could also provide
flexibility for owners and operators of coal or pet coke units
implementing CCS at the outset of the unit's operation that were
designed and operated to emit at less than 1,000 lb CO2/MWh
to address startup concerns or short term interruptions in their
ability to sequester captured carbon dioxide. The EPA is not proposing
standards of performance for existing EGUs whose CO2
emissions increase as a result of installation of pollution controls
for conventional pollutants, or for proposed EGUs, which are referred
to here as transitional sources, that have acquired a complete
preconstruction permit by the time of this proposal and that commence
construction within 12 months of this proposal. As a result, those
sources would not be subject to the standards of performance proposed
in today's rule.
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    \1\ Throughout this preamble, we refer to `carbon capture and
storage' or CCS. By this, we mean the use of a technology for
separating and capturing CO2 from the flue gas or syngas
stream with subsequent compression and transportation to a suitable
location for long term storage and monitoring. Many references refer
to CCS as `carbon capture and sequestration'. In this preamble,
`storage' and `sequestration' mean the same thing and the words are
used interchangeably.

DATES: Comments. Comments must be received on or before June 12, 2012.
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 April 13,
2012, a comment to the OMB is best assured of having its full effect if
the OMB receives it by May 14, 2012.
    Public Hearing. The EPA will hold public hearings on this proposal.
The dates, times, and locations of the public hearings will be
announced separately. Oral testimony will be limited to 5 minutes per
commenter. The EPA encourages commenters to provide written versions of
their oral testimonies either electronically or in paper copy. Verbatim
transcripts and written statements will be included in the rulemaking
docket. If you would like to present oral testimony at one of the
hearings, please notify Ms. Pamela Garrett, Sectors Policies and
Programs Division (C504-03), U.S. EPA, Research Triangle Park, NC
27711, telephone number<PHONE_NUMBER>; email<EMAIL_ADDRESS>
Persons wishing to provide testimony should notify Ms. Garrett at least
2 days in advance of the public hearings. The public hearings will
provide interested parties the opportunity to present data, views, or
arguments concerning the proposed rule. The EPA officials may ask
clarifying questions during the oral presentations, but will not
respond to the presentations or comments at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as any oral comments and
supporting information presented at the public hearing. For updates and
additional information on the public hearings, please check the EPA's
Web site for this rulemaking, http://www.epa.gov/airquality/carbonpollutionstandards.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2011-0660, by one of the following methods:
    At the Web site http://www.regulations.gov: Follow the instructions
for submitting comments.
    At the Web site http://www.epa.gov/oar/docket.html: Follow the
instructions for submitting comments on the EPA Air and Radiation
Docket web site.
    Email: Send your comments by electronic mail (email) to<EMAIL_ADDRESS>Attn: Docket ID No. EPA-HQ-OAR-2011-0660.
    Facsimile: Fax your comments to<PHONE_NUMBER>, Attn: Docket ID No.
EPA-HQ-OAR-2011-0660.
    Mail: Send your comments to the EPA Docket Center, U.S. EPA, Mail
Code 2822T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Attn:
Docket ID No. EPA-HQ-OAR-2011-0660. Please include a total of two
copies. In addition, please mail a copy of your comments on the
information collection provisions 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, EPA West, Room 3334, 1301 Constitution Ave., NW., Room 3334,
Washington, DC, 20460, Attn: Docket ID No. EPA-HQ-OAR-2011-0660. Such
deliveries are accepted only during the Docket's normal hours of
operation (8:30 a.m. to 4:20 p.m., Monday through Friday, excluding
legal holidays), and special arrangements should be made for deliveries
of boxed information.
    Instructions: All submissions must include agency name and docket
ID number (EPA-HQ-OAR-2011-0660). The EPA's policy is that all comments
received will be included in the public docket without change and may
be made available online at http://www.regulations.gov, including any
personal information provided, 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, North Carolina 27711,
Attention Docket ID No. EPA-

HQ-OAR-2011-0660. Clearly mark the part or all of the information that
you claim to be CBI. For CBI information in 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 that is claimed as CBI. In addition to one complete version
of the comment that includes information claimed as CBI, a copy of the
comment that does not contain the information claimed as CBI must be
submitted 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 a separate copy of your comments also be sent
to the contact person identified below (see FOR FURTHER INFORMATION
CONTACT). If the comment includes information you consider to be CBI or
otherwise protected, a copy of the comment that does not contain the
information claimed as CBI or otherwise protected should be sent.
    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 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 in http://www.regulations.gov or in hard copy at the EPA
Docket Center, EPA West, Room 3334, 1301 Constitution Ave. NW.,
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding legal holidays. The telephone
number for the Public Reading Room is<PHONE_NUMBER>, and the telephone
number for the Air Docket is<PHONE_NUMBER>. 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 also be available on the Worldwide Web (WWW)
through the Technology Transfer Network (TTN). Following signature, a
copy of the proposed rule will be posted on the TTN's policy and
guidance page for newly proposed or promulgated rules at the following
address: http://www.epa.gov/ttn/oarpg/. The TTN provides information
and technology exchange in various areas of air pollution control.

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<PHONE_NUMBER>,
facsimile number<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>or Dr. Nick Hutson, Energy Strategies Group,
Sector Policies and Programs Division (D243-01), U.S. EPA, Research
Triangle Park, NC 27711; telephone number<PHONE_NUMBER>, facsimile
number<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
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:

AB Assembly Bill
AEP American Electric Power
AEO Annual Energy Outlook
ANSI American National Standards Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing of Materials
BACT Best Available Control Technology
BDT Best Demonstrated Technology
BSER Best System of Emission Reduction
Btu/kWh British Thermal Units per Kilowatt Hour
Btu/lb British Thermal Units per Pound
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting
CEMS Continuous Emissions Monitoring System
CH4 Methane
CHP Combined Heat and Power
CO2 Carbon Dioxide
CSAPR Cross-State Air Pollution Rule
DOE Department of Energy
DOT Department of Transportation
ECMPS Emissions Collection and Monitoring Plan System
EERS Energy Efficiency Resource Standards
EGU Electric Utility Generating Units
EIA Energy Information Administration
EO Executive Order
EOR Enhanced Oil Recovery
EPA Environmental Protection Agency
FR Federal Register
GHG Greenhouse Gas
H2 Hydrogen Gas
HAP Hazardous Air Pollutant
HFC Hydrofluorocarbon
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
kg/MWh Kilogram per Megawatt-hour
kJ/kg Kilojoules per Kilogram
kWh Kilowatt Hour
lb CO2/MMBtu Pound of CO2 per Million British
Thermal Unit
lb CO2/MWh Pound of CO2 per Megawatt-hour
lb CO2/yr Pound of CO2 per Year
lb/lb-mole Pound per Pound-Mole
MATS Mercury and Air Toxic Standards
MW Megawatt
MWe Megawatt Electric
MWh Megawatt-hour
N2O Nitrous Oxide
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NETL National Energy Technology Laboratory
NGCC Natural Gas Combined Cycle
NRC National Research Council
NSPS New Source Performance Standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
O2 Oxygen Gas
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbon
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
SBA Small Business Administration
SCC Social Cost of Carbon
SCR Selective Catalytic Reduction
SF6 Sulfur Hexafluoride
SIP State Implementation Plan
SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide
SSM Startup, Shutdown, and Malfunction
Tg Teragram
Tpy Tons per Year
TSD Technical Support Document
TTN Technology Transfer Network
UIC Underground Injection Control
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
USGCRP U.S. Global Climate 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. Does this action apply to me?
II. Background
    A. Statutory Background for This Rule
    B. Overview of Climate Change Impacts From GHG Emissions
    C. GHGs From Fossil Fuel-Fired EGUs
    D. Litigation Directly Leading to This Rule
    E. Coordination With Other Rulemakings
III. Summary of the Proposed Requirements for New Sources
    A. What is the affected source?
    B. What emissions limitations must I meet?
    C. What are the startup, shutdown, and malfunction requirements?
    D. What are the continuous monitoring requirements?
    E. What are the emissions performance testing requirements?
    F. What are the continuous compliance requirements?
    G. What are the notification, recordkeeping, and reporting
requirements?
IV. Rationale for the Proposed Standards: New Sources
    A. How did the EPA establish the emission limits?
    B. How did the EPA determine the other requirements for the
proposed standards?
V. Implications for PSD and Title V Programs
    A. Overview
    B. Implications for PSD Program
    C. Implications for Title V Program
VI. Discussion of Modified Sources
    A. CAA Section 111 Requirements
    B. Timing for Promulgation of Standards of Performance for
Modifications
VII. 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?
VIII. Request for Comments
IX. 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 as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq.
    D. Unfunded Mandates Reform Act of 1995
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. General Information

A. Summary

1. Executive Summary
    In this rulemaking, the EPA proposes to limit GHG emissions from
new fossil fuel-fired power plants by limiting CO2
emissions. The proposed rule is undertaken pursuant to section 111 of
the Clean Air Act, which establishes a several step process for the EPA
and the States to regulate air pollutants from stationary sources.
Under section 111, the EPA must regulate emissions from new sources in
the source category by issuing a standard of performance, which is
defined 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 * * *
cost [and other factors]) * * * has been adequately demonstrated.''
    In today's action, the EPA is proposing to combine electric utility
steam generating units (boilers and IGCC units, which are currently
included in the Da category) and combined cycle units that generate
electricity for sale and meet certain size criteria (which are
currently included in the KKKK category), into a new category for new
sources (the TTTT category) for the purposes of GHG emissions. The EPA
is proposing standards of performance that require that all new fossil
fuel-fired EGUs meet an electricity-output-based emission rate of 1,000
lb CO2/MWh of electricity generated on a gross basis. This
proposed standard is based on the demonstrated performance of natural
gas combined cycle (NGCC) units, which are currently in wide use
throughout the country, and are likely to be the predominant fossil
fuel-fired technology for new generation in the future.
    New coal-, coal refuse-, oil- and petroleum coke-fired boilers and
IGCC units should also be able to meet this standard by employing
carbon capture and storage (CCS) technology. While a coal unit with CCS
may be more expensive to construct than NGCC generation, for reasons
explained below, we expect the difference to decrease over time as CCS
becomes more mature and less expensive.
    We include in today's proposed rulemaking a 30-year averaging
compliance option under which affected coal- and pet coke-fired sources
could comply with the 1,000 lb CO2/MWh standard on a 30-year
average basis. Coal- and pet coke-fired EGUs that use this compliance
alternative must meet an immediate performance standard of 1,800 lb
CO2/MWh (gross) on a 12-month annual average basis, which
can be achieved by a ``supercritical'' efficiency level, during the
period before installation of CCS. By no later than the beginning of
the 11th year, the facility would be required to meet a reduced
CO2 emission limit of no more than 600 lb CO2/MWh
(gross) on a 12-month annual average basis for the remaining 20 years
of the 30-year period, such that the weighted average CO2
emissions rate from the facility over the 30-year time period would be
equivalent to the proposed standard of performance of 1,000 lb
CO2/MWh.
    Today's proposal to require an emission rate of 1,000 lb
CO2/MWh meets the requirements for a ``standard of
performance,'' as defined under CAA section 111(a)(1). This proposed
standard is based on the degree of emission limitation achievable
through natural gas combined cycle generation. NGCC qualifies as the
``best system of emission reduction'' (BSER) that the EPA has
determined has been adequately demonstrated. New natural gas-fired EGUs
are less costly than new coal-fired EGUs, and as a result, our
Integrated Planning Model (IPM) model projects that for economic
reasons, natural gas-fired EGUs will be the facilities of choice until
at least 2020, which is the analysis period for this rulemaking.
    Indeed, our IPM model does not project construction of any new
coal-fired EGUs during that period. This state of affairs has come
about primarily because technological developments and discoveries of
abundant natural gas reserves have caused natural gas prices to decline
precipitously in recent years and have secured those relatively low
prices for the near-future. We emphasize that, in light of a number of
economic factors, including the increased availability and
significantly lower price

of natural gas, energy industry modeling forecasts uniformly predict
that few, if any, new coal-fired power plants will be built in the
foreseeable future.
    We recognize that some owners/operators may nevertheless seek to
construct new coal-fired capacity. This may be beneficial from the
standpoint of promoting energy diversity, and today's proposal does not
interfere with construction of new coal-fired capacity. At present,
while CCS would add considerably to the costs of a new coal-fired power
plant, there are sources of funding available to support the deployment
of CCS, including a limited number of government demonstration
programs. Even if companies decide to construct a few new coal-fired
power plants under any circumstance, those few may well have access to
those government programs. We expect that the costs of CCS will decline
in the future as CCS matures and is utilized more widely.
    For purposes of today's action, the EPA does not have a sufficient
base of information to develop a proposal for the anticipated
relatively few affected sources that may be expected to take actions
that would constitute ``modifications'' (as defined under the EPA's
NSPS regulations) and therefore be subject to requirements for new
sources. As a result, the EPA is not proposing requirements for NSPS
modifications.
    The EPA is aware that approximately 15 proposed EGUs have received
CAA permitting authority approval for their preconstruction permits,
but may not have ``commenced construction'' by the date of today's
proposed rulemaking. For this proposed rule, these sources that, as of
the date of this proposal, have a PSD permit and are poised to commence
construction within the very near future are referred to as
``transitional sources.'' In today's proposed rulemaking, the EPA is
not proposing a standard of performance for transitional sources, which
we define as sources that have been issued a PSD permit by the date of
proposal (including sources that have approved permits that are in the
process of being amended, if those sources are intending to install CCS
as evidenced by participating in any of the DOE CCS funding programs,
either loan guarantee or grant programs) and that commence construction
within 12 months of the date of publication of this proposal in the
Federal Register. Upon finalization of this rulemaking without a
standard of performance applicable to these sources, they will not be
treated as new sources subject to the specific limitations set forth in
the final new source standards.
    Our IPM modeling, using Energy Information Administration (EIA)
reference case assumptions, projects that there will be no construction
of new coal-fired generation without CCS by 2030. Under these
assumptions, the proposed rule will not impose costs by 2030. We also
examined a scenario with both increased future natural gas prices and
increased future electric demand. In this sensitivity case, we saw
small amounts of coal-fired generation being built in 2030. Even under
this sensitivity analysis with small amounts of new coal generation
under conditions of high natural gas prices and simultaneously high
electricity demand in 2030, we do not project that this proposed rule
will impose notable costs upon sources.
    We seek comments on all aspects of this proposal and identify a
number of aspects of the proposal on which comments are specifically
requested.

B. Overview and Outline

1. Overview
    In this rulemaking, the EPA proposes to limit GHG emissions from
new fossil fuel-fired power plants by limiting CO2
emissions. In 2009, the EPA issued a finding that GHG air pollution may
reasonably be anticipated to endanger Americans' public health and
welfare, now and in the future, by contributing to climate change.
Fossil fuel-fired power plants emit more GHG emissions than any other
stationary source category in the United States, and among new GHG
emissions sources, the largest individual sources are in this source
category. This rulemaking proposes federal standards of performance for
new fossil fuel-fired power plants that can be met with existing
technology.
    Note that in this preamble, while we refer to these sources,
interchangeably, as power plants, steam generating units, affected
sources, fossil fuel-fired electric generating units, covered EGUs, or,
simply, EGUs, the proposed standards apply to only those sources
identified in Section III.A. as the affected source category.
2. Why is the EPA proposing this rule?
    This proposed rule reflects the EPA's common-sense approach to
reducing CO2 and other GHG emissions, which by causing
climate change, pose a serious threat to public health and welfare. The
EPA is focusing first on reducing emissions from the largest emitters
through measures with reasonable costs. The EPA is proposing to control
CO2 pollution from fossil fuel-fired power plants because
they are responsible for approximately 40 percent of all U.S.
anthropogenic CO2 emissions.\2\ Individual new coal-fired
power plants are among the largest individual new sources of GHGs.
Furthermore, design and technology choices, such as NGCC, exist that
can be readily and cost-effectively used to reduce GHG emissions from
new fossil fuel-fired power plants. Thus, this proposed rule is a
rational first step to control GHG emissions from the largest-emitting
stationary sources under CAA section 111.
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    \2\ Or 32.4% of all anthropogenic GHG emissions; from
information in Table 2-1 from `Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2009,' U.S. Environmental Protection
Agency, EPA 430-R-11-005, April 2011.
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    a. The Serious Threat of Climate Change to the Public's Health and
Welfare. Climate change, including global warming, is a significant
threat to the global environment. The National Research Council (NRC)
of the National Academies \3\ stated in a 2011 report, ``Each
additional ton of greenhouse gases emitted commits us to further change
and greater risks. In the judgment of the [NRC] Committee on America's
Climate Choices, the environmental, economic, and humanitarian risks of
climate change indicate a pressing need for substantial action to limit
the magnitude of climate change and to prepare to adapt to its
impacts.'' \4\
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    \3\ The National Academies comprise the National Academy of
Sciences, National Academy of Engineering, Institute of Medicine and
National Research Council.
    \4\ National Research Council (2011) America's Climate Choices,
Committee on America's Climate Choices, Board on Atmospheric
Sciences and Climate, Division on Earth and Life Studies, The
National Academies Press, Washington, DC.
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    Action to reduce emissions is warranted because, as the EPA stated
in its 2009 Endangerment Finding,\5\ GHGs endanger the public health
and public welfare of current and future generations. The anthropogenic
buildup of GHGs in the atmosphere is very likely (90 to 99 percent
probability) the cause of most of the observed global warming over the
last 50 years.\6\ Based on the Endangerment Finding and its underlying
technical support document (TSD),\7\ reasons to reduce GHG emissions
include the following:
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    \5\ EPA, ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases under Section 202(a) of the Clean Air Act'' (74 FR
66,496; Dec. 15, 2009). http://epa.gov/climatechange/endangerment.html.
    \6\ Endangerment Finding at 74 FR 66,518, which notes that the
2007 conclusion of the Intergovernmental Panel on Climate Change was
re-confirmed by the June 2009 assessment by the U.S. Global Change
Research Program.
    \7\ EPA, ``Technical Support Document for Endangerment and Cause
or Contribute Findings for Greenhouse Gases under Section 202(a) of
the Clean Air Act, Dec. 9, 2009.'' Both the Federal Register Notice
and the TSD for Endangerment and Cause or Contribute Findings are
found in the public docket established for the endangerment
rulemaking, Docket No. EPA-OAR-2009-0171 and at http://epa.gov/climatechange/endangerment.html.

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     The key effects of climate change observed to date and
projected to occur in the future include, but are not limited to, more
frequent and intense heat waves, more severe wildfires, degraded air
quality, heavier and more frequent downpours and flooding, increased
drought, greater sea level rise and storm surge, more intense storms,
harm to water resources, continued ocean acidification, harm to
agriculture, and harm to wildlife and ecosystems.
     These effects are anticipated to result in premature
deaths, illnesses, damage to property and infrastructure, and other
harm to people's welfare in the U.S.
     Those ``most vulnerable'' to climate related health
effects, such as children, the elderly and the poor--and future
generations--face disproportionate risks.\8\
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    \8\ Endangerment Finding, 74 FR 66498.
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     Human-induced climate change impacts have the potential to
be far-reaching and multidimensional, though not all risks and
potential impacts can be quantified.\9\
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    \9\ Endangerment Finding, 74 66497.
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     A supporting consideration is that climate change impacts
in certain regions of the world (potentially leading, for example, to
food scarcity, conflicts or mass migration) may exacerbate problems
that raise humanitarian, trade and national security issues for the
United States.\10\
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    \10\ Endangerment Finding, 74 FR 66535.
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    The TSD further notes that some risks, such as the extinction of
many species, would be irreversible.\11\ Also, the TSD points to
research on the potential for ``abrupt changes'' \12\ which have
uncertain or low probability but high potential impact. The NRC has
said abrupt changes are an important consideration because, if
triggered, they could occur so quickly and unexpectedly that human or
natural systems would have difficulty adapting to them.\13\ Examples
include severe drought in subtropical areas, release of large amounts
of GHGs stored in the sea floor and frozen Arctic soils, and rapid
disintegration of Greenland ice sheet or collapse of the West Antarctic
ice sheet leading to many feet of sea level rise.\14\
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    \11\ Endangerment TSD, p. 136.
    \12\ Endangerment TSD, p. 75-78. The U.S. Climate Change Science
Program defined ``abrupt change'' as a ``large-scale change in the
climate system that takes place over a few decades or less, persists
(or is anticipated to persist) for at least a few decades, and
causes substantial disruptions in human and natural systems.''
Synthesis and Assessment Product (SAP) 3.4: Abrupt Climate Change
(2008).
    \13\ Endangerment TSD, p. 75, citing National Research Council
(2002).
    \14\ Endangerment TSD, pp. 76-78.
---------------------------------------------------------------------------

    The special characteristics of GHGs make it important to take
initial steps 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 greenhouse gas. Greenhouse gases will continue to
accumulate in the atmosphere at higher and higher concentrations each
year unless substantial reductions in global greenhouse gas emissions
are achieved. The NRC notes that emissions reduction choices made today
matter in determining the level of impacts experienced not just over
the next few decades, but in the coming centuries and millennia.\15\
Also, the longer that the U.S. and other countries take to reduce
emissions, the greater the future emissions reductions that will be
required to limit global temperature increase to any given level.
---------------------------------------------------------------------------

    \15\ National Research Council (NRC) (2011). Climate
Stabilization Targets. Committee on Stabilization Targets for
Atmospheric Greenhouse Gas Concentrations; Board on Atmospheric
Sciences and Climate, Division of Earth and Life Sciences, National
Academy Press. Washington, DC.
---------------------------------------------------------------------------

    This proposed rule to limit GHG emissions from the largest U.S.
stationary source category will contribute to the emissions reductions
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. Reducing GHG emissions reduces the impacts
and risks articulated in the Endangerment Finding and TSD.
    b. The High Level of GHG Emissions from Fossil-Fuel-Fired Power
Plants and the Opportunities to Reduce these Emissions. Fossil fuel-
fired power plants comprise the largest category of stationary source
GHG emissions in the U.S. These sources account for approximately 40
percent of total U.S. anthropogenic CO2 emissions, based on
2009 data.\16\ Among all stationary sources of GHG emissions, fossil-
fuel-fired power plants generally constitute the largest individual
sources.
---------------------------------------------------------------------------

    \16\ Or 32.4% of all anthropogenic GHG emissions; from
information in Table 2-1 from `Inventory of U. S. Greenhouse Gas
Emissions and Sinks: 1990--2009', U. S. Environmental Protection
Agency, EPA 430-R-11-005, April 2011.
---------------------------------------------------------------------------

    Furthermore, a range of options are available to reduce emissions
of new power plants. For economic reasons, most new power plants being
built in the U.S. today are either natural gas-fired or are powered by
renewable sources of energy, such as wind and solar, and therefore
generally produce significantly fewer CO2 emissions than
uncontrolled coal-fired power plants. Natural gas combustion inherently
emits less CO2 than coal combustion and the technology of
choice for generating electricity with natural gas, stationary combined
cycle gas turbines, is also more efficient. Almost all the stationary
combined cycle gas turbines built in the U.S. in the last five years
can meet the proposed standard of 1,000 lb CO2/MWh. New
coal-fired power plants can install CCS technology and can thereby
limit their CO2 emissions per MWh generated to levels
similar to, or even lower than, those of natural gas-fired combined
cycle plants without CCS. New coal-fired power plants with CCS are
being permitted and built today, albeit usually with considerable
financial assistance from the federal government.
    c. Alignment with Industry's Other CAA Obligations. Establishing
the overall regulatory requirements for GHG emissions from new fossil
fuel-fired power plants at this time is efficient because the EPA has
recently issued regulations to limit criteria and hazardous air
pollutants from these sources. Aligning the timing of these GHG rules
with the rules for criteria and air toxics pollutants gives the
industry more regulatory certainty, will facilitate the industry's
investment decisions, and will help inform its compliance decisions to
meet all of its CAA obligations.
    d. Promotion of Energy Diversity. This proposed rule is consistent
with the President's goal to ensure that ``by 2035 we will generate 80%
of our electricity from a diverse set of clean energy sources--
including renewable energy sources like wind, solar, biomass and
hydropower, nuclear power, efficient natural gas and clean coal.'' \17\
The proposed rule will assist the deployment of CCS technology for new
coal-fired power plants and reinforce incentives for the use of
efficient natural gas-fired generation. Regulatory uncertainty may be
hindering the development and deployment of CCS, as evidenced by
American Electric Power (AEP)'s recent deferral of a large-scale CCS
retrofit demonstration project on one of its coal-fired power plants
because the State's utility regulators would not approve CCS without a

regulatory requirement to reduce CO2.\18\ The standard
established in this proposal would help create the regulatory certainty
that CCS is the path forward for new coal-fired generation.
---------------------------------------------------------------------------

    \17\ ``Blueprint for a Secure Energy Future'', March 30, 2011.
    \18\ In a July 17, 2011, press release, AEP's chairman said,
``We are placing the project on hold until economic and policy
conditions create a viable path forward * * * We are clearly in a
classic `which comes first?' situation. The commercialization of
this technology is vital if owners of coal-fueled generation are to
comply with potential future climate regulations without prematurely
retiring efficient, cost-effective generating capacity. But as a
regulated utility, it is impossible to gain regulatory approval to
recover our share of the costs for validating and deploying the
technology without federal requirements to reduce greenhouse gas
emissions already in place. The uncertainty also makes it difficult
to attract partners to help fund the industry's share.''
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3. Legal Proceedings Leading up to This Rulemaking
    In April 2007, the U.S. Supreme Court ruled, in Massachusetts v.
EPA,\19\ that GHGs meet the definition of ``air pollutant'' in the CAA.
This decision clarified that the authorities and requirements of the
CAA, including section 111, apply to GHG emissions.
---------------------------------------------------------------------------

    \19\ 549 U.S. 497 (2007).
---------------------------------------------------------------------------

    As a result of this decision, the EPA obtained a voluntary remand
from the U.S. Court of Appeals for the District of Columbia Circuit
(the ``Court'') to reconsider the EPA's actions in a 2006 rulemaking
for EGUs under CAA section 111, in which the EPA had promulgated
standards for criteria air pollutants, but had declined to regulate GHG
emissions. In part in response to threatened litigation over the EPA's
failure to act on the remand, the EPA agreed to propose today's action
to regulate GHG emissions from new fossil fuel-fired EGUs.
4. Legal Basis for CAA Standards for Fossil-Fired Power Plants
    a. General Legal Requirements. Clean Air Act section 111
establishes a several step process for the EPA and the States to
regulate air pollutants from stationary sources. First, the EPA must
list categories of stationary sources that cause or contribute
significantly to air pollution that may reasonably be anticipated to
endanger public health or welfare. Then, the EPA must regulate
emissions from new sources in the source category by issuing a standard
of performance, which is defined 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 * * * cost [and other factors]) * * * has been
adequately demonstrated.'' New sources include new construction, and,
as discussed below, modifications to existing sources as well as
reconstructed sources. Standards of performance for new sources are
often referred to as new source performance standards (NSPS).
    b. Cause-or-Contribute-Significantly Finding for Fossil Fuel-Fired
Power Plants and Endangerment Finding for GHG Air Pollution. The EPA is
authorized to regulate GHGs from power plants based on earlier actions
concerning endangerment. Before today's rulemaking, the EPA listed
different types of fossil fuel-fired EGUs as source categories that
caused or contributed significantly to air pollution that may
reasonably be anticipated to endanger public health or welfare.
Specifically, the EPA listed electric utility steam generating boilers,
including coal-fired boilers, and initially regulated them in subpart D
of its regulations under CAA section 111. Subsequent regulation of
utility boilers has been under subpart Da. The EPA listed stationary
combustion turbine engines and initially regulated them under subpart
GG. The stationary combustion turbine engine portions of combined cycle
facilities were also regulated under subpart GG. Heat recovery steam
generators (HRSG) associated with combined cycle facilities with duct
burners were regulated under either subpart Da or one of the industrial
boiler regulations, depending on the specific characteristics of the
HRSG. To minimize the compliance burden for owners/operators of
combined cycle facilities some monitoring harmonization was done, but
the two subparts were still applicable. In 2005, the EPA proposed
subpart KKKK as a replacement for subpart GG and specifically covered
the entire combined cycle facility under subpart KKKK such that only a
single set of requirements would apply. In that same year, the EPA
proposed to include Integrated Gasification Combined Cycle (IGCC)
facilities under the applicability of subpart Da. The EPA is authorized
to promulgate the rulemaking proposed today--which would establish
standards of performance for CO2 emissions from EGUs
currently in the Da and KKKK source categories--because the EPA has
already determined that both those source categories cause or
contribute significantly to air pollution that may reasonably be
expected to endanger public health or welfare. Clean Air Act section
111 does not require the EPA, as a prerequisite to regulating any
particular air pollutant, to issue an endangerment finding or a cause-
or-contribute-significantly finding for that air pollutant from that
source category.
    As an alternative, the EPA is considering whether CAA section 111
should be interpreted to require that the EPA base its regulation of
CO2 emissions from EGUs on two findings: (i) A finding that
GHG air pollution may reasonably be anticipated to endanger public
health or welfare; and (ii) a finding that CO2 emissions
from EGUs cause or contribute significantly to that air pollution. If
section 111 were so interpreted, the EPA believes that (a) the 2009
Endangerment Finding, along with the EPA's 2010 action denying
petitions to reconsider that finding (which action reviewed scientific
developments after the Endangerment Finding) would fulfill any
requirement to make the endangerment finding concerning GHG air
pollution; and (b) the large amount of CO2 emissions from
EGUs clearly exceeds the low applicability threshold upon which the EPA
would make the cause-or-contribute-significantly finding.
    As another alternative, the EPA is also considering whether CAA
section 111 should be interpreted to require that the EPA base its
regulation of CO2 emissions from EGUs on a rational basis
for protection of the public health or welfare. If section 111 were so
interpreted, the EPA believes that (i) its 2009 Endangerment Finding
and 2010 denial of petitions to reconsider, by themselves, and
particularly in conjunction with the National Academy of Sciences'
assessment reports issued since then, coupled with (ii) the fact that
EGUs are the largest stationary source emitters of CO2,
provide a rational basis for regulating CO2 emissions from
EGUs. There is no reason to revisit the 2009 Endangerment Finding given
recent scientific findings that strengthen the scientific conclusion
that GHG air pollution endangers public health and welfare.\20\
---------------------------------------------------------------------------

    \20\ These recent scientific findings are described in section
II of this notice, titled ``Background.'' See subsection II.B.3.,
``Climate Impacts Detailed in Recent NRC Assessments.'' The legal
options introduced here are presented in detail below in section
IV.A.2, ``Endangerment and Cause-or-Contribute-Significantly
Finding.''
---------------------------------------------------------------------------

5. Summary of Today's Proposed Requirements To Reduce GHG Emissions
From New Fossil Fired Power Plants, and Rationale for Those
Requirements
a. Summary of Proposed Revisions to Categories and Requirements for New
Sources
    i. Revisions to Categories of EGUs. In today's action, the EPA is
proposing to

combine electric utility steam generating units (boilers and IGCC
units, which are currently included in the Da category) and combined
cycle units that generate electricity for sale and meet certain size
criteria (which are currently included in the KKKK category), into a
new category for new sources (the TTTT category) for the purposes of
GHG emissions. Today's proposed rulemaking would not affect NSPS
requirements for criteria air pollutants, simple cycle turbines or EGUs
located in non-continental areas.\21\ It also would not affect biomass-
fired boilers (including those that sell electricity to the grid) that
co-fire with less than 250 MMBtu/h of any fossil fuel (biomass boilers
currently subject to subpart Db, the Industrial-Commercial-
Institutional Steam Generating Unit NSPS).
---------------------------------------------------------------------------

    \21\ Thus, today's rulemaking does not affect the Da and KKKK
categories for conventional pollutants and does not affect the KKKK
category for simple cycle turbines.
---------------------------------------------------------------------------

    ii. Control Requirements for New Sources. The EPA is proposing
standards of performance that require that all new fossil fuel-fired
EGUs meet an electricity-output-based emission rate of 1,000 lb
CO2/MWh of electricity generated on a gross basis. This
proposed standard is based on the demonstrated performance of natural
gas combined cycle (NGCC) units, which are currently in wide use
throughout the country, and are likely to be the predominant fossil
fuel-fired technology for new generation in the future.
    New coal-, coal refuse-, oil- and petroleum coke-fired boilers and
IGCC units should also be able to meet this standard by employing CCS
technology. There are currently a number of coal- and pet coke-fired
EGU projects under development that include CCS. While a coal unit with
CCS may be more expensive to construct than NGCC generation, for
reasons explained below, we expect the difference to decrease over time
as CCS becomes more mature and less expensive.
    We include in today's proposed rulemaking a 30-year averaging
compliance option under which affected coal- and pet coke-fired sources
could comply with the 1,000 lb CO2/MWh standard on a 30-year
average basis. Coal- and pet coke-fired EGUs that use this compliance
alternative must meet an immediate performance standard of 1,800 lb
CO2/MWh (gross) on a 12-month annual average basis, which
can be achieved by a ``supercritical'' efficiency level, during the
period before installation of CCS. By no later than the beginning of
the 11th year, the facility would be required to meet a reduced
CO2 emission limit of no more than 600 lb CO2/MWh
(gross) on a 12-month annual average basis for the remaining 20 years
of the 30-year period, such that the weighted average CO2
emissions rate from the facility over the 30-year time period would be
equivalent to the proposed standard of performance of 1,000 lb
CO2/MWh.
    We seek comment on this compliance option and on reasonable
variations on the framework we propose to establish, and in particular
on a mechanism for establishing practicably enforceable short term
limits during the 30-year period. The potential approaches here include
(1) requiring the owner/operator to identify and obtain approval of, at
the time of construction, an alternative 30-year emission trajectory to
the 10- and 20-year limits described immediately above; and (2)
specifying the emission rate for each year during the 30-year period
consistent with meeting a 30-year average emission rate of 1,000 lb
CO2/MWh. Such an option would provide coal-fired sources
that intend to use a reduction technology, such as CCS, significant
flexibility in how that reduction technology is implemented. They could
install the technology as part of the original project but use some or
all of the initial ten year period to optimize the system. Such
flexibility could be particularly useful to early adopters (i.e.,
``first movers'') of the technology. Alternatively, they could delay
installation of the technology for a period of up to ten years to take
advantage of advancements in the technology that could reduce costs and
enhance performance. Under CAA section 111(b)(1)(B), the EPA is
required to conduct a review of the new source standards in eight years
and we intend at that time to review the availability and cost of CCS.
As proposed, this 30-year averaging compliance option is available only
to new coal- and pet coke-fired EGUs. We do not believe that it is
necessary for NGCC units, as they should be able to meet the proposed
performance with no need for add-on technology. We also solicit comment
on the need to extend the applicability for the 30-year averaging
compliance option to other fossil fuels beyond just coal and pet coke.
    b. Rationale. Today's proposal to combine the relevant parts of the
Da and KKKK categories is authorized under CAA section 111(b)(1)(A)
because that provision authorizes the EPA, after drawing up the list of
affected source categories, to ``revise'' that list from time to time.
Combining the relevant parts of the categories, as the EPA proposes to
do, is one method to ``revise'' the list. Moreover, the EPA's action to
combine the relevant parts of the categories is reasonable because with
the combination, all new fossil fuel-fired electricity generating units
that meet specified minimum criteria will be subject to the same
requirements, and therefore will be treated alike because they serve
the same function, that is to serve baseload or intermediate demand.
The EPA is not including stationary simple cycle turbines in this rule
because they generally operate differently than the other units covered
by today's rule. The units covered by today's rule are generally used
to serve baseload or intermediate demand, while simple cycle turbines
are generally used much less often (and thus have lower GHG emissions)
and are generally used to meet peak demand rather than base or
intermediate load requirements.
    Today's proposal does not apply to new sources in non-continental
areas, which include Hawaii and the territories. This is because non-
continental areas do not have available pipeline quality natural gas
and, accordingly, a natural-gas-fired plant that could comply with the
1,000 lb CO2/MWh may not be feasible. At present, we do not
have information to identify what types of new power plants may be
constructed in those areas. Those types of power plants may range from
liquified natural gas (LNG)-, to oil-, to coal-fired to renewables. Our
lack of more specific information precludes us from proposing, at this
time, a standard for new sources in non-continental areas.
    Today's proposal to require an emission rate of 1,000 lb
CO2/MWh meets the requirements for a ``standard of
performance,'' as defined under CAA section 111(a)(1). This proposed
standard is based on the degree of emission limitation achievable
through natural gas combined cycle generation. NGCC qualifies as the
``best system of emission reduction'' (BSER) that the EPA has
determined has been adequately demonstrated because NGCC emits the
least amount of CO2 and does so at the least cost. We
propose that a NGCC facility is the best system of emission reduction
for two main reasons. First, natural gas is far less polluting than
coal. Combustion of natural gas emits only about 50 percent of the
CO2 emissions that the combustion of coal does per unit of
energy generated. Second, new natural gas-fired EGUs are less costly
than new coal-fired EGUs, and as a result, our Integrated Planning
Model (IPM) model projects that for economic reasons, natural gas-fired
EGUs will be the facilities of choice until at least 2020,

which is the analysis period for this rulemaking. Indeed, our IPM model
does not project construction of any new coal-fired EGUs during that
period. This state of affairs has come about primarily because
technological developments and discoveries of abundant natural gas
reserves have caused natural gas prices to decline precipitously in
recent years and have secured those relatively low prices for the near-
future. Importantly, because the IPM modeling shows that natural gas-
fired plants are the facilities of choice, the proposed standard of
performance in today's rulemaking -- which is based on the emission
rate of a new NGCC unit -- does not add costs. In addition, compared to
coal-fired EGUs, natural gas-fired EGUs have fewer nonair quality
health and environmental impacts. This is true under not only a set of
base-case assumptions, but also under a sensitivity considering
significantly higher gas prices.
    The just-described reasons are sufficient as a legal matter to
justify today's proposed actions to combine source categories and
establish the 1,000 lb CO2/MWh standard. Such a standard
could also be met today by new coal-fired units using CCS. In addition,
we propose to include the compliance alternative of allowing new coal-
and pet coke-fired power plants to meet the 1,000 lb CO2/MWh
standard over a 30-year period so that plant developers can take
advantage of future advancements cost savings in CCS technology that
could lower its cost. This compliance alternative allows owners/
operators to install CCS when the unit is first constructed but also
provides the operational flexibility that may be necessary to optimize
the performance and to have additional time to address any startup
challenges related to issues such as business arrangements related to
the sale or storage of the captured CO2.
    We recognize that, in light of a number of economic factors,
including the increased availability and significantly lower price of
natural gas, energy industry modeling forecasts uniformly predict that
few, if any, new coal-fired power plants will be built in the
foreseeable future. For these economic reasons, and independent of this
proposed standard, the fossil fuel-fired electricity generating
industry has been trending towards increased use of natural gas and
decreased use of coal for new generating capacity. Today's proposed
action is consistent with that trend; but, at the same time, today's
proposal is not intended to affect that apparent trend.
    We recognize that some owners/operators may nevertheless seek to
construct new coal-fired capacity. This may be beneficial from the
standpoint of promoting energy diversity, and today's proposal does not
interfere with construction of new coal-fired capacity. In the first
instance, a new coal-fired power plant may be able to meet the 1,000 lb
CO2/MWh standard by installing CCS at the time of
construction. At present, while CCS would add considerably to the costs
of a new coal-fired power plant, there are sources of funding available
to support the deployment of CCS, including a limited number of
government demonstration programs.\22\ Even if companies decide to
construct a few new coal-fired power plants under any circumstance,
those few may well have access to those government programs.
---------------------------------------------------------------------------

    \22\ A number of the sources that EPA has identified as
transitional sources have received some form of DOE financial
assistance to demonstrate CCS. In addition, several additional
projects have received funding but have not yet received air
permits. Beyond these projects, prospects for additional federal
funding are dependent on the overall budget process.
---------------------------------------------------------------------------

    The proposed 30-year averaging compliance option adds additional
flexibility for new coal- and pet coke-fired power plants by allowing
them to construct and begin operations without CCS, and then to install
and operate CCS at some time in the future, as long as they install CCS
within ten years and operate it in a manner that allows them to meet
the 1,000 lb CO2/MWh standard, on a weighted average basis,
over the 30-year period.
    We expect that the costs of CCS will decline in the future as CCS
matures and is utilized more widely. Today's action, if finalized,
would promote utilization and further development of CCS by making it
clear that CCS would be necessary for new coal-fired power plants to
meet the performance standard. The prospect of declining CCS costs, in
conjunction with the possibility of continued availability of
additional funding mechanisms (e.g. demonstration funding such as
Department of Energy (DOE) grants, tax credits (for investment and/or
EOR), State incentives such as clean energy standards), and sale of
other usable products such as CO2, sulfur and hydrogen based
products, indicates that CCS may well be sufficiently accessible in the
near term to the few coal-fired power plants that are expected to
commence construction. Thus, the 30-year averaging compliance option,
along with the potential opportunities for funding to implement CCS
immediately, helps to alleviate any concerns that today's action could
restrict new coal-fired construction.
    It should be noted that we are not required to justify the 30-year
averaging compliance option on grounds that it qualifies as the ``best
system of emission reduction'' adequately demonstrated, and we are not
stating in this action whether that compliance alternative does or does
not qualify as such. Thus, it is not necessary to determine that our
expectation that costs will go down meets the standards for determining
that CCS is ``adequately demonstrated.'' Rather, to reiterate, the 30-
year averaging compliance option, along with the opportunity to
implement CCS to meet the 1,000 lb CO2/MWh standard
immediately upon startup, make CCS an available option for the limited
number of new coal-fired power plants that may construct to serve the
policy goals of promoting energy diversity, as well as other policy
objectives.\23\ Indeed, by clarifying that, in the future, new coal-
fired power plants will need to implement CCS, this rulemaking
eliminates uncertainty about the status of new coal and may well
enhance the prospects for new coal-fired generation.
---------------------------------------------------------------------------

    \23\ EIA analysis (AEO 2012 early release) shows that ``coal
remains the dominant energy source for electricity generation.''
---------------------------------------------------------------------------

    In addition, there may also be other potential compliance options
available that were not considered in this proposal. In the analysis
for today's proposal, the EPA did not include unique treatment of
CO2 emissions from biologically-based material, otherwise
called biogenic CO2 emissions.\24\
---------------------------------------------------------------------------

    \24\ Biologically-based material is defined as non-fossilized
and biodegradable organic material originating from modern or
contemporaneously grown plants, animals or micro-organisms
(including products, by-products, residues and waste from
agriculture, forestry and related industries as well as the non-
fossilized and biodegradable organic fractions of industrial and
municipal wastes, including gases and liquids recovered from the
decomposition of non-fossilized and biodegradable organic material).
---------------------------------------------------------------------------

    In 2011, the EPA prepared and submitted the draft Accounting
Framework for Biogenic CO2 Emissions from Stationary Sources
(http://www.epa.gov/climatechange/emissions/biogenic_emissions/study.html ). The draft Framework includes both a detailed examination
of the scientific and technical issues related to accounting for
biogenic CO2 emissions from stationary sources, and a
proposed method to account for a stationary source's onsite
CO2 emissions, taking the biological cycling of carbon into
consideration, in a scientifically and technically rigorous manner. The
independent Science Advisory Board (SAB) has convened a Biogenic Carbon

Emissions Panel (http://yosemite.epa.gov/sab/sabproduct.nsf/0/2F9B572C712AC52E8525783100704886?OpenDocument) to conduct a peer review
of the draft Framework. The peer review report will be finalized later
in 2012.
    The SAB's peer review of the EPA's discussion on the science
related to the impacts of biogenic CO2 is not yet finalized
and the EPA looks forward to the SAB's conclusions later in 2012. Given
that the SAB's peer review is ongoing, the EPA is not suggesting
specific methods of accounting or otherwise making particular proposals
for treatment of biogenic CO2 emissions in any stationary
source program, including NSPS. As more information, including the SAB
peer review, becomes available, the EPA will consider its options and
move forward as warranted.
    c. Requirements and Rationale for NSPS Modifications for GHGs. For
purposes of today's action, the EPA does not have a sufficient base of
information to develop a proposal for the affected sources that may be
expected to take actions that would constitute ``modifications'' (as
defined under the EPA's NSPS regulations) for GHGs and therefore be
subject to requirements for new sources. As a result, the EPA is not
proposing requirements for NSPS modifications for GHGs.\25\
---------------------------------------------------------------------------

    \25\ Note that any analysis of the cost and feasibility of CCS
that EPA has undertaken for purposes of this proposal has focused
solely on new sources. In today's action, EPA has not undertaken any
analysis of the cost or feasibility of CCS for existing units that
undergo modifications.
---------------------------------------------------------------------------

    The EPA's current regulations define an NSPS ``modification'' as a
physical or operational change that increases the source's maximum
achievable hourly rate of emissions, but specifically exempt from that
definition pollution control projects, which are projects that entail
the installation of pollution control equipment or systems. Based on
current information, most of the projects that we believe EGUs are most
likely to undertake in the foreseeable future that could increase the
maximum achievable hourly rate of CO2 emissions would
constitute pollution control projects. In many cases, those projects
would involve the installation of add-on control equipment required to
meet CAA requirements for criteria and air toxics air pollutants. These
increases in CO2 emissions would generally be small and
would occur as a chemical byproduct of the operation of the control
equipment. In other cases, those projects would involve equipment
changes to improve efficiency to meet the requirements of a future
111(d) rulemaking for existing sources and would have the effect of
increasing a source's maximum achievable hourly emission rate (lb
CO2/hr), even while decreasing its actual output based
emission rate (lb CO2/MWh). Because all of these actions
would be treated as pollution control projects under the EPA's current
NSPS regulations, they would be specifically exempted from the
definition of modification.
    Our base of knowledge concerning NSPS modifications has depended
largely on the enforcement actions brought against power plants and on
self-reporting by power plants. Over the lengthy history of the NSPS
program, those have been too few in number to allow us to develop a
sufficiently robust base of knowledge to propose a standard of
performance for NSPS modifications for GHGs at this time.
    In addition, the sources that took these actions vary widely one
from another, and the types of actions were disparate. In light of
this, as noted, we do not have adequate information as to the types of
actions that qualify as modifications, the amount of increase in
CO2 emissions they cause, the types of control measures, or
the costs and effectiveness of control measures, on which to base a
proposed standard of performance. Therefore, in today's action, we are
not proposing a standard of performance for modifications. We note that
the statute contemplates that in circumstances such as these (where
section 111(d) is implicated), sources not subject to the new source
standards would be treated as existing sources subject to section
111(d).
    In today's action, we solicit comment on the types of modifications
power plants may undertake and the appropriate control measures.
Depending on the information we develop, we may issue proposed
standards of performance in the future.
    d. Requirements for Transitional sources. The EPA is aware that
approximately 15 proposed EGUs have received CAA permitting authority
approval for their preconstruction permits, but may not have
``commenced construction'' by the date of today's proposed rulemaking.
    A few of these sources have taken additional action preparatory to
commencing construction. For this proposed rule, these sources that, as
of the date of this proposal, have a PSD permit and are poised to
commence construction within the very near future are referred to as
``transitional sources.'' We are aware that approximately six of these
sources have plans to implement CCS to some degree.
    CAA section 111 provides by its terms that sources that have not
``commenced construction'' before the date of proposed standards for
new sources will be subject to the NSPS when they do commence
construction. The EPA's regulations define ``commenced construction''
as, in general, undertaking a continuous program of construction or
entering into a binding contract to do so. 40 CFR 60.2.
    Commenters \26\ have pointed out that absent different treatment,
transitional sources will be subject to the same requirements that
apply to new sources that did not obtain their permit before the date
of proposal. These commenters have suggested that today's proposed rule
should treat transitional sources differently, especially in light of
the substantial redesign that meeting such the proposed standard would
have and the impact that redesign would have on the schedule for a
project that was nearly ready to commence construction. The
transitional sources at issue are coal-fired EGUs that, absent special
treatment, would be subject to the standard of performance proposed in
this rulemaking.
---------------------------------------------------------------------------

    \26\ As mentioned elsewhere, the EPA held a series of listening
sessions and allowed for a period of additional comment after
announcing it was moving forward with development of new source
performance standards for GHGs emitted from fossil fuel-fired EGUs.
The term ``commenters'' here refers to those who commented during
the listening sessions or during the subsequent comment period.
---------------------------------------------------------------------------

    In today's proposed rulemaking, the EPA is not proposing a standard
of performance for transitional sources, which we define as sources
that have been issued a PSD permit by the date of proposal (including
sources that have approved permits that are in the process of being
amended, if those sources are intending to install CCS as evidenced by
participating in any of the DOE CCS funding programs, either loan
guarantee or grant programs) and that commence construction within 12
months of the date of publication of this proposal in the Federal
Register. Upon finalization of this rulemaking without a standard of
performance applicable to these sources, they will not be treated as
new sources subject to the specific limitations set forth in the final
new source standards. These sources would remain obligated, by the
terms of their permits, to construct and operate in accordance with
their permits. In addition, these sources will be treated as existing
sources and would be subject to any requirements that a State
promulgates to meet its obligations under section 111(d). Sources that
do not commence construction within 12 months of the date of this
proposed action will be subject to this standard of performance for new
sources.

    e. Requirements for Reconstructed Sources, and Rationale. The EPA's
CAA section 111 regulations provide that reconstructed sources are to
be treated as new sources and, therefore, subject to new source
standards of performance. The regulations define reconstructed sources
as, in general, existing sources (i) that replace 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, and (ii) for which
compliance with standards of performance for new sources is
technologically and economically feasible. 40 CFR 60.15.
    As with NSPS modifications, our base of knowledge concerning
reconstructions has depended largely on the enforcement actions brought
against power plants and on self-reporting by power plants. Over the
lengthy history of the NSPS program, those have been too few in number
to allow us to develop a sufficiently robust base of knowledge to
propose a standard of performance for reconstructions for GHGs at this
time. Thus, we lack adequate information about the type of source; the
type of changes; the extent of emissions increases; and the type of
control measures, including their cost and emissions reductions, that
we need to propose a standard of performance for reconstructions.
    As a result, in today's action, the EPA is not including a proposal
for reconstructed units for GHGs. Instead, we solicit comment on how we
should approach reconstructions and, depending on the information we
receive, we may propose and finalize a standard for reconstructions at
a later time.
6. Summary of Emissions Impacts, Costs and Benefits
    Our IPM modeling, using Energy Information Administration (EIA)
reference case assumptions, projects that there will be no construction
of new coal-fired generation without CCS. In addition we examined a
case with higher future electric demand and another case with higher
future natural gas prices. We did not see any additional new
construction of coal-fired generation through 2030 in either of these
cases. Under the relevant assumptions, we do not project that this rule
will impose notable costs.
    We also examined a scenario with both increased future natural gas
prices and increased future electric demand. In this sensitivity case
we saw small amounts of coal-fired generation being built in 2030. Even
under this sensitivity analysis with small amounts of new coal
generation under conditions of high natural gas prices and
simultaneously high electricity demand in 2030, we do not project that
this proposed rule will impose notable costs upon sources. (See the RIA
for further discussion of sensitivities).
    While this proposed rule also will not have direct impact on U.S.
emissions of greenhouse gases under expected economic conditions, it
provides assurance that emission rates from new fossil fuel-fired
generation will not exceed the level of the standard and will send a
strong signal both domestically and internationally. Domestically, this
proposed rule can further stimulate investment in CCS and other clean
coal technologies, by making it clear that such technologies do provide
a clear path forward for new coal-fired generating capacity.
Internationally, this rule may encourage others to consider less GHG-
intensive forms of power generation.

B. Does this action apply to me?

    The entities potentially affected by the proposed standards are
shown in Table 1 below.

                Table 1--Potentially Affected Entities a
------------------------------------------------------------------------
                                                 Examples of potentially
            Category               NAICS Code       regulated 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\ Include NAICS categories for source categories that own and operate
  electric power generating units (including boilers and stationary
  combined cycle combustion turbines).
\b\ Federal, state, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

    This table is not intended to be exhaustive but rather to provide a
guide for readers regarding entities likely to be affected by this
proposed action. To determine whether your facility, company, business,
organization, etc., would be regulated by this proposed action, you
should examine the applicability criteria in 40 CFR 60.1. If you have
any questions regarding the applicability of this action to a
particular entity, consult either the air permitting authority for the
entity or your EPA regional representative as listed in 40 CFR 60.4 or
40 CFR 63.13 (General Provisions).

II. Background

A. Statutory Background for This Rule

    Clean Air Act section 111 establishes mechanisms for controlling
emissions of air pollutants from stationary sources. As a preliminary
step, CAA section 111(b)(1)(A) requires the EPA to 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.''
\27\
---------------------------------------------------------------------------

    \27\ The EPA has made endangerment findings under this section
for more than 60 stationary source categories and subcategories that
are now subject to NSPS.
---------------------------------------------------------------------------

    Once it has listed a source category, the EPA establishes
``standards of performance'' that apply to new sources, which are
sources that are constructed, or that undertake modifications or
reconstruction, after the EPA proposes the standards of performance for
the relevant source category. CAA section 111(b)(1)(B). Specific
statutory and regulatory provisions define what constitutes a
modification or reconstruction of a facility. An existing facility
undertakes a modification if it undergoes ``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.'' CAA section
111(a)(4). The EPA's NSPS regulations provide exemptions for several
types of changes, including the installation of pollution control
projects. 40 CFR 60.2, 60.14(e). An existing facility undertakes a
reconstruction if it replaces components to such an extent that the
capital costs of the new equipment or components exceed 50 percent of
what is believed to be the cost of a completely new facility. 40 CFR
60.15. In promulgating standards of performance, the EPA has
significant

discretion to create subcategories based on source type, class or size.
CAA section 111(b)(2).
    Clean Air Act 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.

We call this level of control the best system of emission reduction
(BSER).\28\ The standard that the EPA develops, based on the BSER, is
commonly a numerical emissions 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 remain free to elect whatever
combination of measures will achieve equivalent or greater control of
emissions.
---------------------------------------------------------------------------

    \28\ This level of control has historically been referred to as
best demonstrated technology (BDT).
---------------------------------------------------------------------------

B. Overview of Climate Change Impacts From GHG Emissions

    In 2009, the EPA Administrator issued the 2009 Endangerment
Finding,\29\ under CAA section 202(a)(1), as part of the process for
promulgating the Light Duty Vehicle Rule.\30\ With the Endangerment
Finding, the Administrator found that elevated concentrations of GHGs
in the atmosphere may reasonably be anticipated to endanger public
health and welfare. These adverse effects on public health and welfare
are summarized here, and described in more detail in the RIA. As
explained in the Endangerment Finding, the EPA made this determination
based primarily upon the recent, major assessments by the U.S. Global
Change Research Program (USGCRP), Intergovernmental Panel on Climate
Change (IPCC), and the National Research Council (NRC).\31\ In brief,
these assessments addressed the scientific issues that the EPA was
required to examine, were comprehensive in their coverage of the GHG
and climate change problem, and underwent rigorous and exacting peer
review by the expert community, as well as rigorous levels of U.S.
government review and acceptance. Below is a brief, non-comprehensive
summary of effects noted in the Endangerment Finding and the assessment
reports.
---------------------------------------------------------------------------

    \29\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act.'' 74 FR
66496 (December 15, 2009).
    \30\ ``Light-Duty Vehicle Greenhouse Gas Emission Standards and
Corporate Average Fuel Economy Standards; Final Rule.'' 75 FR 25324
(May 7, 2010).
    \31\ 74 FR 66510-66511.
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Climate change threatens public health through a number of impacts
such as increases in hot weather, ozone pollution, and the severity and
frequency of extreme weather events. Children, the elderly, and the
poor are among the most vulnerable to these climate-related health
effects.
    By increasing higher average temperatures, climate change increases
the likelihood of heat waves, which are associated with increased
deaths and illnesses. While climate change also leads to decreases in
cold-related mortality, some evidence suggests that the net impact on
mortality is more likely to be adverse. Heat is already the leading
cause of weather-related deaths in the U.S.
    Climate change is expected to increase ozone pollution over broad
areas of the country including large population areas with unhealthy
surface ozone levels. Ozone health studies indicate that elevated
surface ozone increases risks of premature death, acute bronchitis,
heart attacks, asthma aggravation, and other respiratory effects.
    Public health threats also stem from 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. The assessment literature indicates that there
is the potential for hurricanes to become more intense, and there is
some evidence that Atlantic hurricanes have already become more
intense. Hurricanes and floods from human-induced climate change can
cause deaths, injuries, waterborne diseases, and mental health problems
such as post-traumatic stress disorders. Drownings and other health
impacts from coastal storms and storm surges are expected to increase
due to rising sea levels.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
    Climate change is expected to have numerous effects on public
welfare. Large areas of the country are at serious risk of reduced
water supplies, increased water pollution, and increased occurrence of
extreme events such as floods and droughts. Coastal areas face
increased risks from storm and flooding damage to property, as well as
adverse impacts from sea level rise 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 changes in extreme weather threaten energy,
transportation, and water resource infrastructure. Climate changes may
exacerbate ongoing environmental pressures in certain settlements,
particularly in Alaskan indigenous communities. Over the 21st century,
climate change will fundamentally rearrange U.S. ecosystems.
    It is possible that in the next few decades, adverse effects in
certain parts of the agriculture and forestry sectors--such as enhanced
pest and weed growth, increased surface ozone, changes in the intensity
and frequency of droughts and heavy storms, and increased wildfires--
may be offset by benefits resulting from a stimulatory carbon dioxide
effect and a longer growing season. However, the body of evidence
points towards increasing risks of net adverse impacts on U.S. food
production, agriculture, and forest productivity as temperatures
continue to rise, with the potential for significant disruptions and
crop failure.
    Human-induced climate change has the potential to be far-reaching
and multidimensional. Given the long atmospheric lifetime of the six
GHGs,\32\ which range from roughly a decade to centuries, future
atmospheric greenhouse gas concentrations for the remainder of this
century and beyond will be influenced not only by future emissions but
indeed by present-day emissions. The severity of all the described
risks and impacts is likely to increase over time with accumulating GHG
concentrations and the associated temperature increases and
precipitation changes. Finally, these impacts are global, and may
exacerbate problems that raise humanitarian, trade, and national
security issues for the U.S.
---------------------------------------------------------------------------

    \32\ Carbon dioxide (CO2), nitrous oxide
(N2O), methane (CH4), perflurocarbons (PFCs),
hydrofluorocarbons (HFCs), and sulfur hexafluoride (SF6).
---------------------------------------------------------------------------

3. Climate Impacts Detailed in Recent NRC Assessments
    Since the EPA issued the 2009 Endangerment Finding, the NAS, which
is a society established by an Act of Congress that is composed of
distinguished scholars engaged in scientific and engineering research,
has

issued assessments with similar conclusions to those of the assessments
upon which the EPA based the Endangerment Finding. In May 2010, the
NRC, which is the operating arm of the National Academy of Sciences
(NAS) that conducts most of the science policy and technical work,
published its comprehensive assessment, ``Advancing the Science of
Climate Change'' (the 2010 NRC Assessment).\33\ It concluded that
``climate change is occurring, is caused largely by human activities,
and poses significant risks for--and in many cases is already
affecting--a broad range of human and natural systems.'' \34\
Furthermore, the NRC stated that this conclusion is based on findings
that are ``consistent with the conclusions of recent assessments by the
U.S. Global Change Research Program, the Intergovernmental Panel on
Climate Change's (IPCC) Fourth Assessment Report, and other assessments
of the state of scientific knowledge on climate change.'' \35\ These
are the same assessments that served as the primary scientific
references underlying the 2009 Endangerment Finding. The 2010 NRC
Assessment also warned of risks associated with abrupt changes and
surprises that might occur when certain thresholds are crossed, such as
the release of large quantities of GHGs stored in frozen soils in the
Arctic or irreversible drying and desertification in the subtropics;
and of potential for broad, ``catastrophic'' impacts on marine
ecosystems resulting from ocean acidification.
---------------------------------------------------------------------------

    \33\ NRC (2010). Advancing the Science of Climate Change.
National Academy Press. Washington, DC.
    \34\ NRC (2010). Advancing the Science of Climate Change.
National Academy Press. Washington, DC. Page 3.
    \35\ NRC (2010). Advancing the Science of Climate Change.
National Academy Press. Washington, DC. Page 286.
---------------------------------------------------------------------------

    Another NRC assessment, ``Climate Stabilization Targets: Emissions,
Concentrations, and Impacts over Decades to Millenia'', was published
in 2011 (the 2011 NRC Assessment). This report found that climate
change due to CO2 emissions will persist for many centuries.
The report also estimates a number of specific climate change impacts,
finding that every degree Celsius ([deg]C) of warming could lead to
increases in heavy rainfall and decreases in crop yields and Arctic sea
ice extent, along with other precipitation and stream flow changes. The
assessment also found that with an increase of 4 [deg]C, the average
summer would be as warm as the warmest summers of the past century,
that for an increase of 1 to 2 [deg]C the area burnt by wildfires in
western North America will likely more than double, that coral
bleaching and erosion will increase due both to warming and ocean
acidification, and that sea level will rise 1.6 to 3.3 feet by 2100 in
a 3 [deg]C scenario. The assessment notes that many important aspects
of climate change are difficult to quantify but that the risk of
adverse impacts is likely to increase with increasing temperature, and
that the risk of surprises can be expected to increase with the
duration and magnitude of the warming. Importantly, these recent NRC
assessments represent another independent and critical inquiry of the
state of climate change science, separate and apart from the previous
IPCC, NRC, and USGCRP assessments.

C. GHGs From Fossil Fuel-Fired Power Plants

    Fossil fuel-fired electric utility generating units are by far the
largest emitters of GHGs, primarily in the form of CO2,
among stationary sources in the U.S. This section describes the amount
of those emissions and places that amount in the context of the
national inventory of GHGs.
    The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \36\ (the U.S. GHG Inventory) to comply with
existing commitments under the United Nations Framework Convention on
Climate Change. This inventory, which includes recent trends, is
presented by industrial sectors. It is the source for the information
provided in Table 2 below concerning total U.S. anthropogenic emissions
and sinks of GHGs and CO2 emissions, by industrial sector--
including fossil fuel-fired EGUs--for the years 1990, 2000, and 2009.
---------------------------------------------------------------------------

    \36\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2009'', Report EPA 430-R-11-005, United States Environmental
Protection Agency, April 15, 2011.
    \37\ From Table 2-3 of the EPA GHG Emissions and Sinks
Inventory, EPA 430-R-11-005.

                                 Table 2--U.S. GHG Emissions and Sinks by Sector
                             [Teragram Carbon Dioxide Equivalent (Tg CO2 Eq.)] \37\
----------------------------------------------------------------------------------------------------------------
                         Sector                                 1990               2000               2009
----------------------------------------------------------------------------------------------------------------
Energy.................................................           5,287.8            6,168.0            5,751.1
Industrial Processes...................................             315.8              348.8              282.9
Solvent and Other Product Use..........................               4.4                4.9                4.4
Agriculture............................................             383.6              410.6              419.3
Land Use, Land-Use Change and Forestry (Emissions).....              15.0               36.3               25.0
Waste..................................................             175.2              143.9              150.5
                                                        --------------------------------------------------------
    Total Emissions....................................           6,181.8            7,112.7            6,633.2
Land Use, Land-Use Change and Forestry (Sinks).........            (861.5)            (576.6)          (1,015.1)
                                                        --------------------------------------------------------
    Net Emissions (Sources and Sinks)..................           5,320.3            6,536.1            5,618.2
----------------------------------------------------------------------------------------------------------------

    Energy-related CO2 emissions are the largest contributor
to total U.S. GHG emissions, representing 86.7 percent of total 2009
GHG emissions. In 2009, the electric power sector--consisting of those
entities whose primary business is the generation of electricity--
accounted for 40 percent of all energy-related CO2
emissions. The transportation sector, with emissions principally from
the combustion of gasoline, diesel, and jet fuel, was the second-
largest source, at 32 percent of the total. Other energy-related
CO2 emission sources included industrial, residential, and
commercial fossil fuel combustion, natural gas and petroleum systems,
and incineration of waste.
    Direct fuel use in the residential and commercial sectors accounted
for 26 percent of total CO2 emissions in 2009. Total
CO2 emissions from fossil fuel-fired EGUs, for years 1990,
2000 and 2009, are shown below in Table 3.

           Table 3--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels
                                                  [Tg CO2 Eq.]
----------------------------------------------------------------------------------------------------------------
                          GHG Emissions                                1990            2000            2009
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel combustion...........................         1,820.8         2,296.9         2,154.0
    --from coal.................................................         1,547.6         1,927.4         1,747.6
    --from natural gas..........................................           175.3           280.8           373.1
    --from petroleum............................................            97.5            88.4            32.9
From use of limestone and dolomite..............................             2.6             2.5             3.8
Total CH4--stationary combustion................................             0.6             0.7             0.7
Total N2O--stationary combustion................................             8.1            10.0             9.0
----------------------------------------------------------------------------------------------------------------

    We are aware that nitrous oxide (N2O) (and to a lesser
extent, methane (CH4)) may be emitted from fossil fuel-fired
EGUs, especially from coal-fired circulating fluidized bed (CFB)
combustors and from units with selective catalytic reduction (SCR) and
selective non-catalytic reduction (SNCR) systems installed for
NOX control. We are not proposing separate N2O or
CH4 emission limits or an equivalent CO2 emission
limit in today's action because of a lack of available data for these
affected sources. Additional information on the quantity and
significance of emissions and on the availability of cost-effective
controls would be needed before proposing standards for these
pollutants. The estimated emissions for N2O and
CH4 from fossil fuel-fired EGUs (9.0 and 0.7 Tg of
CO2 equivalent, respectively) is about 0.4 percent of total
CO2 equivalent emissions from fossil fuel-fired electric
power generating units. We are requesting comment on this approach and
on the need to collect additional data on N2O and
CH4 emissions from these affected sources.

D. Litigation Directly Leading to This Rule

    As discussed below, in section II.E., on February 27, 2006, the EPA
published a final rule that revised the standards of performance for
criteria pollutant emissions of EGUs included in the Da category.
''Standards of Performance for Electric Utility Steam Generating Units,
Industrial-Commercial-Institutional Steam Generating Units, and Small
Industrial-Commercial-Institutional Steam Generating Units,'' 71 FR
9866 (Feb. 27, 2006) (the ``2006 Final Rule''). The 2006 Final Rule did
not establish standards of performance for GHG emissions. Two groups of
petitioners filed petitions for judicial review of this rule in the
U.S. Court of Appeals for the District of Columbia Circuit (the Court),
contending, among other things, that the rule was required to include
standards of performance for GHG emissions from EGUs. The two groups of
petitioners were (1) the States of New York, California, Connecticut,
Delaware, Maine, New Mexico, Oregon, Rhode Island, Vermont, and
Washington, the Commonwealth of Massachusetts, the District of
Columbia, and the City of New York (collectively ``State
Petitioners''); and (2) Natural Resources Defense Council (NRDC),
Sierra Club, and Environmental Defense Fund (EDF)(collectively
``Environmental Petitioners'').
    The portions of State and Environmental Petitioners' petitions for
review of the 2006 Final Rule that related to GHG emissions were
severed from other petitions for review of that rule, and were formally
pending before the Court under the caption State of New York, et al. v.
EPA, No. 06-1322. Following the U.S. Supreme Court's decision in
Massachusetts, discussed above, the Court, upon motion from the EPA,
remanded the 2006 Final Rule for further consideration of the issues
related to GHG emissions in light of Massachusetts. The EPA did not act
on that remand. To avoid further litigation, the State and
Environmental Petitioners and the EPA negotiated a proposed settlement
agreement that set deadlines for the EPA to propose and take final
action on (1) a rule under CAA section 111(b) that includes standards
of performance for GHGs for new and modified EGUs that are subject to
40 CFR part 60, subpart Da; and (2) a rule under CAA section 111(d)
that includes emission guidelines for GHGs from existing EGUs that
would have been subject to 40 CFR part 60, subpart Da if they were new
sources. Pursuant to CAA section 113(g), the EPA published a notice of
the proposed settlement agreement in the Federal Register, and provided
for a public comment period. 75 FR 82392 (December 30, 2010).\38\ The
EPA considered the comments received and concluded that they did not
disclose facts or considerations indicating that the proposed
settlement agreement was inappropriate, improper, inadequate or
inconsistent with the CAA. Therefore, the EPA concluded that the
proposed settlement agreement should be finalized.
---------------------------------------------------------------------------

    \38\ Copies of the Federal Register notice, the settlement
agreement, other supporting documents and the comments received are
available online at fdms.gov under docket EPA-HQ-2010-1057.
---------------------------------------------------------------------------

E. Coordination With Other Rulemakings

    EGUs are the subject of several CAA rulemakings that have been
recently completed. The EPA recognizes that it is important that all of
these efforts achieve their intended environmental objectives in a
common sense manner. The confluence of these rulemakings allows the
industry to look across the regulatory requirements and design cost
effective integrated compliance strategies.\39\
---------------------------------------------------------------------------

    \39\ We include this discussion of other rulemakings for
background purposes. The effort to coordinate rulemakings does not
provide a defense to a violation to the CAA. Sources cannot defer
compliance with existing requirements because of other upcoming
regulations.
---------------------------------------------------------------------------

    On July 6, 2011, the EPA finalized the Cross-State Air Pollution
Rule (CSAPR)\40\. 76 FR 48208 (August 8, 2011). Also known as the
Transport Rule, the CSAPR requires a total of 28 states and the
District of Columbia to improve air quality by reducing power plant
emissions that contribute to ozone and fine particle pollution in other
States. The CSAPR applies to 3,642 EGUs at 1,081 coal-, gas- and oil-
fired facilities in the eastern half of the U.S. By 2014, combined with
other final state and EPA actions, the CSAPR will reduce power plant
SO2 emissions by 73 percent and NOX emissions by
54 percent from 2005 levels in the CSAPR region. The CSAPR was
scheduled to begin on January 1, 2012. However, on December 30, 2011,
the U.S. Court of Appeals for the DC Circuit issued a ruling to stay
the rule pending judicial review. This decision is not a ruling on the
merits of the CSAPR. While this decision delays implementation of the

CSAPR and the significant health benefits associated with the rule, it
leaves the Clean Air Interstate Rule (CAIR), the predecessor regulation
to CSAPR, in place while the Court considers the merits of the
challenges to the CSAPR. Oral arguments are scheduled for April 13,
2012.
---------------------------------------------------------------------------

    \40\ On December 15, 2011, EPA finalized a supplemental rule (76
FR 80760, December 27, 2012) to include five additional states in
the CSAPR ozone season NOX program. On February 7, 2012,
EPA issued two sets of minor adjustments to the CSAPR (77 FR 10324,
February 21, 2012).
---------------------------------------------------------------------------

    On December 16, 2011, the EPA signed the Mercury and Air Toxic
Standards (MATS) rule to reduce emissions of mercury and other HAP
emissions from coal- and oil-fired power plants. This regulation
requires investments in pollution controls to reduce emissions of
mercury, other metals and acid gases by 2015 or 2016. In the same
notice, the EPA also revised the NSPS for criteria pollutants from
these sources. Because the control technologies and strategies that
reduce SO2 can also reduce or help to reduce HAP emissions,
coordinating compliance strategies for the CSAPR and MATS rules,
including the revised NSPS for criteria pollutants, will allow cost-
effective compliance options.
    In April, 2011, the EPA proposed standards under the Clean Water
Act (CWA) to reduce injury and death of fish and other aquatic life
caused by cooling water intake structures existing at power plants and
factories. 76 FR 22174 (April 20, 2011). These facilities pull in large
volumes of cooling water from lakes, rivers, estuaries or oceans to
cool their machinery. The EPA is currently considering a wide range of
comments to this proposal.
    The EPA recognizes that it is important that each of these efforts
achieves its intended environmental objectives in a common-sense, cost
effective manner, that is consistent with the underlying statutory
requirements and that allows the industry to comply with all of its
obligations under these rules as efficiently as possible and to do so
by making coordinated investment decisions and, to the greatest extent
possible, by adopting integrated compliance strategies. In addition, EO
13563 states that ``[i]n developing regulatory actions and identifying
appropriate approaches, each agency shall attempt to promote * * *
coordination, simplification, and harmonization. Each agency shall also
seek to identify, as appropriate, means to achieve regulatory goals
that are designed to promote innovation.'' Recent guidance from the
Office of Information and Regulatory Affairs has emphasized the
importance of, where appropriate and feasible, considering cumulative
effects and of seeking to harmonize rules in terms of both content and
timing.
    Thus, the EPA recognizes that it needs to approach these
rulemakings, to the extent that its legal obligations permit, in ways
that allow the industry to make practical investment decisions that
minimize costs in complying with all of the final rules, while still
achieving the fundamentally important environmental and public health
benefits that the rulemakings must achieve.

F. PSD and Title V Implications

    Commenters have asked whether the rulemaking the EPA is proposing
today has implications for EGUs and other stationary sources under the
prevention of significant deterioration (PSD) and Title V programs. We
discuss this issue in section VI, below, and we include relevant
background information in that discussion.

G. Stakeholder Input

    The EPA has been engaged in extensive interactions with many
different stakeholders on the subjects of climate change, source
contributions, and potential emission reduction opportunities. These
stakeholders have included industries, environmental organizations, and
many regional, State, and local air quality management agencies that
have been actively engaged in efforts to address GHG emissions over a
period of several years. In addition to these conversations, as part of
developing this proposed rule, the EPA held five listening sessions in
February and March 2011 to obtain additional information and input from
key stakeholders and the public. Each of the five sessions had a
particular target audience: The electric power industry, environmental
and environmental justice organizations, States and Tribes, coalition
groups, and the petroleum refinery industry. Each session lasted two
hours and featured a facilitated round table discussion among
stakeholder representatives who were identified and selected for their
expertise in the CAA standard-setting process. The EPA had asked key
stakeholder groups to identify these round table participants in
advance of the listening sessions. The EPA accepted comments from the
public at the end of each session and via the electronic docket system.
    From the listening sessions and written submissions, the EPA
received a wide range of comments and ideas for this proposed rule. The
main topics of the comments, which concerned requirements for both new
and existing sources, included the following:

     Feasibility and availability of control technologies
     Output-based standards
     Subcategorization factors
     Fleet-wide averaging
     Neutrality of fuels
     Role of efficiency improvements
     Equivalency of state and regional reduction programs
     Recognition of early action by industries and states
achieving reductions
     Use of a multi-pollutant, multi-media approach
     Market-based flexibility
     Use of a tiered structure, with requirements evolving over
time
     Credit for replacement of older, less efficient generation
units
     Role of biomass
     Consideration of compliance issues arising from conflicts
with other regulatory programs
     Schedule for proposing and promulgating this rule
     Small business impacts

    Comments submitted via the electronic docket system concerning
development of this proposed rule are available at www.regulations.gov
(docket number EPA-HQ-OAR-2011-0090).

III. Proposed Requirements for New Sources

    This section describes the proposed requirements in this rulemaking
for new sources. Our rationale for these proposed requirements is
provided in Section IV of this preamble.

A. What is the affected source?

    Sources affected by today's proposal for new source provisions are
sources that are considered both covered EGUs as defined by this rule
and ``new'' sources as defined under the provisions of CAA section 111.
1. Covered EGUs, Generally
    The EPA is proposing to define a covered EGU, which is a source
that is subject to this rule, as any fossil fuel-fired combustion unit
that supplies more than one-third of its potential annual electric
output and more than 25 MW net-electrical output (MWe) to any utility
power distribution system for sale, with certain exceptions noted
below. For this proposed rule, covered EGUs include electric utility
steam generating units (``boilers''), stationary combined cycle
combustion turbines and their associated HRSG) and duct burners; and
IGCC units, including their combustion turbines and associated HRSG.
However, for purposes of this rule, covered EGUs do not include
stationary simple cycle combustion turbines or EGUs located in Hawaii
or other non-continental areas. In addition, units subject to emission
requirements

under CAA section 129 would not be subject to requirements under this
proposed rule.
2. CO2 Emissions Only
    This action proposes to regulate covered EGU emissions of
CO2, and not other constituent gases of the air pollutant
GHG, although we identify the pollutant we propose to regulate as GHGs.
Note that emissions of criteria pollutants for covered EGUs remain
covered under 40 CFR part 60 subparts Da and KKKK.
3. ``New'' Sources
    CAA section 111(a)(2) defines a ``new source'' as ``any stationary
source, the construction or modification of which is commenced after
publication of regulations (or, if early, proposed regulations)
prescribing a standard of performance under [CAA section 111] which
will be applicable to such source.'' In contrast, CAA section 111(a)(6)
defines an ``existing source'' as ``any stationary source other than a
new source.'' The definition of a ``new source'' applies according to
its terms for purposes of this rulemaking, except that special
considerations come into play for sources undertaking physical or
operational changes, transitional sources, and sources undertaking
reconstruction, as discussed below in Section V of this preamble.

B. What emissions limitations must I meet?

    In this rulemaking, the EPA is proposing a standard of performance
(NSPS), and we are requesting comment on a 30-year averaging compliance
option, for CO2 emissions from affected sources, which are
new fossil fired EGUs described above in Section III.A.
1. Standard of Performance
    The standard of performance is a gross output-based CO2
emission limit expressed in units of emissions mass per unit of useful
recovered energy (specifically, in pounds per megawatt-hour (lb/MWh)).
This emission limit would be effective upon the effective date of the
final action.
    We are not proposing any subcategories for new affected sources.
Instead, we are proposing a single output-based CO2 emission
limit that must be met by all affected sources.\41\ Specifically, the
EPA is proposing a standard of 1,000 lb CO2/MWh, but, as
discussed below, is taking comment on a range from 950 lb
CO2/MWh to 1,100 lb CO2/MWh.
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    \41\ As discussed below, we are not proposing such a limit for
modifications, transitional sources, or reconstructed sources.
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    As discussed below, the proposed method to calculate compliance is
to sum the emissions for all operating hours and to divide that value
by the sum of the electrical energy output and useful thermal energy
output, where applicable for combined heat and power (CHP) EGUs, over a
rolling 12-month period. In the alternative, we solicit comment on
requiring calculation of compliance on an annual (calendar year)
period.
    Under this proposal, no averaging or emissions trading among
affected sources would be allowed.
    We seek comment on all aspects of the proposed standard of
performance, including using net, instead of gross, generation-based
emissions rate measurement.
2. 30-Year Averaging Compliance Option
    We also propose a 30-year averaging compliance option that would be
available only for affected coal- and pet coke-fired sources that
comply with the standard through the use of CCS. This approach involves
a performance standard that includes both a 12-month annual average
limit and a longer-term limit that may be met on an average basis by
the end of a 30-year period. The 12-month limit is important because it
is a practicably enforceable mechanism to ensure that the source is on
a path to comply with the 30-year average limit. The annual limit will
ensure that the source takes timely action to meet a 30-year limit. For
instance, if meeting the 30-year limit was predicated on installing CCS
technology before year eleven of operation, the annual compliance
limits would provide an enforceable measure to ensure that CCS was
installed and operating well before a 30-year average could be
calculated. Note that after the 30th year, the source would be required
to meet the 12-month annual average 1,000 lb CO2/MWh
emission limit.
    Specifically, for the first ten years of operation, the affected
source would be required to comply with a 12-month annual average
CO2 emissions limit based on the best demonstrated
performance of a coal-fired facility without CCS, which is 1,800 lb
CO2/MWh (816 kg CO2/MWh) (gross). This proposed
emission limit can be met by modern coal-fired facilities using
supercritical steam conditions, IGCC facilities, and pressurized CFBs
boilers. By no later than the 11th year from the effective date of the
rule, the facility would be required to meet a reduced emission limit
of no more than 600 lb CO2/MWh (272 kg CO2/MWh)
(gross) on a 12-month annual average basis for the remaining 20 years
of the 30-year averaging period, such that the weighted average
CO2 emissions rate from the facility over the 30-year time
period would be equivalent to the proposed standard of performance of
1,000 lb CO2/MWh. This reduced emissions standard during the
remainder of the 30-year period would be met with some level of
CCS.\42\
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    \42\ As discussed elsewhere, EPA is soliciting comment on
whether the emissions standard that reflects CCS should be somewhat
higher or lower than 1,000 lb CO2/MWh, and whether the
emissions standard that reflects supercritical efficiency should be
somewhat higher or lower than 1,800 lb CO2/MWh. If EPA
does promulgate a higher or lower standard in either case, then EPA
may revise the 600 lb CO2/MWh amount accordingly.
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    For added flexibility, under this option, we are taking comment on
allowing the owner/operator to select a different emission trajectory
to achieving the 30-year average as long as the owner/operator obtains
EPA approval of that rate before beginning operations. Such a
trajectory would have to assure that, assuming similar amounts of
operation in each year, the overall overage emission rate would be at
or below the required 30-year average of 1,000 lb CO2/MWh.
For instance, if an owner or operator wished to operate at a rate of
2,000 lb CO2/MWh for the first period, it would have to
commit to something more stringent than achieving a 600 lb
CO2/MWh standard by the 11th year. Potential compliance
pathways could include committing to a limit of 500 lb CO2/
MWh by the 11th year or committing to a limit of 600 lb CO2/
MWh by the 8th year.
    The EPA is also soliciting comment on what additional requirements
would be necessary to implement the 30-year averaging requirement.
Specifically, if the owners or operators did not intend to install CCS
when the unit commenced operation, they could be required to submit a
plan that includes a location to store CO2 and a schedule
for construction and operation of their carbon capture system. The
schedule would include key milestone dates such as soliciting
proposals, obtaining financing, beginning construction, and beginning
operation. The EPA requests comment on the appropriateness of including
these, and/or other requirements to ensure that the owners or operators
of the facility have adequate plans in place to meet the 30-year
average emission rate requirement. Further, the shorter term emission
limits for the entire 30-year period must be included in the source's
title V permit. We solicit comment on the

enforceability of the 30-year averaging period, how we can ensure that
the owner/operator will comply with the second phase of the standard,
and what sort of compliance demonstrations are appropriate with such a
long-term standard. We also solicit comment on whether this alternative
compliance mechanism should automatically terminate in 2020 such that
only facilities that commenced construction prior to 2020 would be able
to use the 30-year average.
    The EPA suggests that this 30-year averaging compliance option may
be warranted for at least two reasons. First, it provides power
companies with the option of building a coal-fired power plant in the
near term and installing CCS at a later time when costs will likely be
lower and further experience from demonstration projects will have been
gained. The 30-year averaging period is sufficiently long to allow
sources, before they install CCS, to benefit from the experience that
will be gained from commercial-scale CCS demonstration projects
operating over the next decade from a number of DOE-funded
demonstration projects. A new coal- or pet coke-fired unit could
operate for at least a decade before installing CCS and still have
enough years operating at a controlled emission rate to reach a 1,000
lb CO2/MWh standard on a 30-year basis. A second reason that
this alternative may be practicable is that, even for sources
installing and operating CCS at the beginning of a project, there may
be startup issues (other than those related to the capture technology
or the arrangements for sequestration). For instance, a company's
ability to sequester CO2 may be dependent upon construction
by a third party of a pipeline that will be transporting the
CO2 to a site to be used for enhanced oil recovery or
permanent sequestration. Because the owner or operator does not have
direct control over this part of the project, there may be concerns
that it will not be completed on time and that even after spending all
of the money to construct a coal-fired unit capable of capture, it will
have to remain non-operational for a period of time until the pipeline
project or sequestration destination is completed. The 30-year
averaging compliance option could provide flexibility to operate the
unit until the pipeline was completed as long as the carbon capture
system is designed to meet a rate sufficiently below 1,000 lb
CO2/MWh to allow for compliance with a 30-year averaging
period. Such flexibility is likely to be most important for the first
several CCS projects (i.e., ``first movers'') because of the complexity
of integration of the technologies and the fact that the business model
is new for the power sector. Because the policy purpose of this 30-year
averaging compliance option is to leave open the option of building a
coal-fired unit in the near term and installing CCS after several years
or to allow for flexibility during startup of the system, a long-term
averaging period is needed to allow time for such a unit to achieve the
1,000 lb CO2/MWh level.
    We note that under CAA section 111(b)(1)(B), ``the Administrator
shall, at least every 8 years, review and, if appropriate, revise [the]
standards [of performance] * * * ''. This review is required to take
place in 2020, if not sooner. In the event that the EPA adopts the 30-
year averaging compliance option, then at the time of the next required
review, the EPA will evaluate the state of development or
commercialization of CCS technologies and make a determination as to
whether or not the 30-year averaging approach is still warranted for
new sources. Because we expect CCS technology to advance significantly
over the next several years, we believe that it may not be necessary to
include this type of compliance option for a 30-year average the next
time we review this NSPS. In light of this, we further solicit comment
as to whether the 30-year averaging compliance option should
automatically terminate in 2020, so that it would be available only for
facilities that commenced construction prior to 2020.
    We recognize that this compliance option, by authorizing sources to
average the CO2 emission level over a 30-year period, is
unique. We recognize that the uniqueness of this approach may give rise
to new issues concerning compliance and enforcement. We solicit comment
on any practical difficulties in compliance and enforcement. Along
these lines, although we propose that sources be required to retain
records to demonstrate compliance with the emission limits for at least
30 years following the date of initial startup of the affected EGU, we
solicit comment on the merits of extending this period to 50 years. As
with the proposed standard of performance, no averaging or emissions
trading among affected sources would be allowed for this 30-year
averaging compliance option.
    This 30-year averaging compliance option is available only to new
coal- and pet coke-fired EGUs. We do not believe that it is necessary
for NGCC units, as they should be able to meet the proposed performance
with no need for add-on technology. We also solicit comment on the need
to extend the applicability for the 30-year averaging compliance option
to other fossil fuels beyond just coal and pet coke. We seek comment on
all other aspects of this 30-year averaging compliance option.

C. What are the startup, shutdown, and malfunction requirements?

1. Startups and Shutdowns
    The NSPS that the EPA is proposing in this action would apply at
all times, including during startups and shutdowns. In establishing the
level of the proposed NSPS, the EPA has taken into account startup and
shutdown periods. The EPA is not proposing different standards for
those periods.
    To establish the proposed NSPS's output-based CO2
standard, we accounted for periods of startup and shutdown by
considering periods of part-load operation. As noted above, the
proposed method to calculate compliance is to sum the emissions for all
operating hours and to divide that value by the sum of the electrical
energy output and useful thermal energy output, where applicable for
CHP EGUs, over a rolling 12-month period. This averaging approach gives
more weight to high-load hours and more accurately reflects overall
environmental performance. In addition, because low-load hours do not
factor as heavily into the calculated average, the impact of including
periods of startup and shutdown is minimized when calculating emission
rates.
    We solicit comment on the alternative of requiring compliance
through an annual (calendar year) average.
    We propose that these same requirements for startups and shutdowns
would apply to the 30-year averaging compliance option.
2. Malfunctions
    The NSPS that the EPA is proposing in this action would apply at
all times, including during malfunctions. Periods of startup, normal
operations, and shutdown are all predictable and routine aspects of a
source's operations. By contrast, malfunction is defined as a ``sudden,
infrequent, and not reasonably preventable failure of air pollution
control and monitoring equipment, process equipment or a process to
operate in a normal or usual manner * * * ''(40 CFR 60.2). The EPA has
determined that CAA section 111 does not require that emissions that
occur during periods of malfunction be factored into development of CAA
section 111 standards. Further, nothing in 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. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058
(DC 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.'')
    Further, it is reasonable to interpret CAA section 111 as not
requiring the EPA to account for malfunctions in setting emissions
standards. For example, we note that section 111 provides that the EPA
set standards of performance which reflect the degree of emission
limitation achievable through ``the application of the best system of
emission reduction'' that the EPA determines is adequately
demonstrated. Applying the concept of ``the application of the best
system of emission reduction'' to periods during which a source is
malfunctioning presents difficulties. The ``application of the best
system of emission reduction'' is more appropriately understood to
include operating units in such a way as to avoid malfunctions.
    Further, accounting for malfunctions 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 (DC 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.''). In addition, the goal of a best controlled or best
performing source is to operate in such a way as to avoid malfunctions
of the source and accounting for malfunctions could lead to standards
that are significantly less stringent than levels that are achieved by
a well-performing non-malfunctioning source. The EPA's approach to
malfunctions is consistent with section 111 and is a reasonable
interpretation of the statute.