[Federal Register Volume 77, Number 72 (Friday, April 13, 2012)]
[Proposed Rules]
[Pages 22392-22441]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-7820]



[[Page 22391]]

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

[[Page 22392]]


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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 (CO<INF>2</INF>) for new 
affected fossil fuel-fired electric utility generating units (EGUs). 
The EPA is proposing these requirements because CO<INF>2</INF> 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 CO<INF>2</INF> per megawatt-hour (lb CO<INF>2</INF>/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 CO<INF>2</INF> 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 CO<INF>2</INF>/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 CO<INF>2</INF> 
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 CO<INF>2</INF> 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 (919) 541-7966; email: <a href="/cdn-cgi/l/email-protection#5d3a3c2f2f382929732d3c3038313c1d382d3c733a322b"><span class="__cf_email__" data-cfemail="17707665657263633967767a727b765772677639707861">[email protected]</span></a>. 
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 <a href="/cdn-cgi/l/email-protection#19783478777d346b347d767a727c6d597c6978377e766f"><span class="__cf_email__" data-cfemail="345519555a50194619505b575f5140745144551a535b42">[email protected]</span></a>, Attn: Docket ID No. EPA-HQ-OAR-2011-0660.
    Facsimile: Fax your comments to (202) 566-9744, 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-

[[Page 22393]]

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 (202) 566-1744, and the telephone 
number for the Air Docket is (202) 566-1742. Visit the EPA Docket 
Center homepage at http://www.epa.gov/epahome/dockets.htm for 
additional information about the EPA's public docket.
    In addition to being available in the docket, an electronic copy of 
this proposed rule will 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 (919) 541-4003, 
facsimile number (919) 541-5450; email address: 
<a href="/cdn-cgi/l/email-protection#c5a3a0a9a9aba0b7eba6adb7acb6b1aca4ab85a0b5a4eba2aab3"><span class="__cf_email__" data-cfemail="0660636a6a68637428656e746f75726f67684663766728616970">[email protected]</span></a> or Dr. Nick Hutson, Energy Strategies Group, 
Sector Policies and Programs Division (D243-01), U.S. EPA, Research 
Triangle Park, NC 27711; telephone number (919) 541-2968, facsimile 
number (919) 541-5450; email address: <a href="/cdn-cgi/l/email-protection#e48c9190978b8aca8a8d878fa4819485ca838b92"><span class="__cf_email__" data-cfemail="18706d6c6b77763676717b73587d6879367f776e">[email protected]</span></a>.

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
CH<INF>4</INF> Methane
CHP Combined Heat and Power
CO<INF>2</INF> 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
H<INF>2</INF> 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 CO<INF>2</INF>/MMBtu Pound of CO<INF>2</INF> per Million British 
Thermal Unit
lb CO<INF>2</INF>/MWh Pound of CO<INF>2</INF> per Megawatt-hour
lb CO<INF>2</INF>/yr Pound of CO<INF>2</INF> per Year
lb/lb-mole Pound per Pound-Mole
MATS Mercury and Air Toxic Standards
MW Megawatt
MWe Megawatt Electric
MWh Megawatt-hour
N<INF>2</INF>O 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
O<INF>2</INF> Oxygen Gas
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbon
PM Particulate Matter
PM<INF>2.5</INF> 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
SF<INF>6</INF> Sulfur Hexafluoride
SIP State Implementation Plan
SNCR Selective Non-Catalytic Reduction

[[Page 22394]]

SO<INF>2</INF> 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 CO<INF>2</INF> 
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 CO<INF>2</INF>/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 CO<INF>2</INF>/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 
CO<INF>2</INF>/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 
CO<INF>2</INF> emission limit of no more than 600 lb CO<INF>2</INF>/MWh 
(gross) on a 12-month annual average basis for the remaining 20 years 
of the 30-year period, such that the weighted average CO<INF>2</INF> 
emissions rate from the facility over the 30-year time period would be 
equivalent to the proposed standard of performance of 1,000 lb 
CO<INF>2</INF>/MWh.
    Today's proposal to require an emission rate of 1,000 lb 
CO<INF>2</INF>/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

[[Page 22395]]

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 CO<INF>2</INF> 
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 CO<INF>2</INF> 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 
CO<INF>2</INF> pollution from fossil fuel-fired power plants because 
they are responsible for approximately 40 percent of all U.S. 
anthropogenic CO<INF>2</INF> 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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[[Page 22396]]

    <bullet> 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.
    <bullet> 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.
    <bullet> 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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    <bullet> 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\
---------------------------------------------------------------------------

    \9\ Endangerment Finding, 74 66497.
---------------------------------------------------------------------------

    <bullet> 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\
---------------------------------------------------------------------------

    \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.
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    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 CO<INF>2</INF> 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 CO<INF>2</INF> emissions than 
uncontrolled coal-fired power plants. Natural gas combustion inherently 
emits less CO<INF>2</INF> 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 CO<INF>2</INF>/MWh. New 
coal-fired power plants can install CCS technology and can thereby 
limit their CO<INF>2</INF> 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

[[Page 22397]]

regulatory requirement to reduce CO<INF>2</INF>.\18\ The standard 
established in this proposal would help create the regulatory certainty 
that CCS is the path forward for new coal-fired generation.
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    \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 CO<INF>2</INF> 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 
CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF>, 
provide a rational basis for regulating CO<INF>2</INF> 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\
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    \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.''
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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

[[Page 22398]]

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 
CO<INF>2</INF>/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 CO<INF>2</INF>/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 
CO<INF>2</INF>/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 
CO<INF>2</INF> emission limit of no more than 600 lb CO<INF>2</INF>/MWh 
(gross) on a 12-month annual average basis for the remaining 20 years 
of the 30-year period, such that the weighted average CO<INF>2</INF> 
emissions rate from the facility over the 30-year time period would be 
equivalent to the proposed standard of performance of 1,000 lb 
CO<INF>2</INF>/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 
CO<INF>2</INF>/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 CO<INF>2</INF>/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 
CO<INF>2</INF>/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 CO<INF>2</INF> 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 
CO<INF>2</INF> 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,

[[Page 22399]]

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 CO<INF>2</INF>/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 CO<INF>2</INF>/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 CO<INF>2</INF>.
    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 
CO<INF>2</INF>/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.
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    \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 CO<INF>2</INF>/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 CO<INF>2</INF>, 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 CO<INF>2</INF>/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 
CO<INF>2</INF> emissions from biologically-based material, otherwise 
called biogenic CO<INF>2</INF> emissions.\24\
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    \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 CO<INF>2</INF> 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 CO<INF>2</INF> emissions from stationary sources, and a 
proposed method to account for a stationary source's onsite 
CO<INF>2</INF> 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

[[Page 22400]]

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 CO<INF>2</INF> 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 CO<INF>2</INF> 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\
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    \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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 
CO<INF>2</INF>/hr), even while decreasing its actual output based 
emission rate (lb CO<INF>2</INF>/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 
CO<INF>2</INF> 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.

[[Page 22401]]

    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

[[Page 22402]]

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 (CO<INF>2</INF>), nitrous oxide 
(N<INF>2</INF>O), methane (CH<INF>4</INF>), perflurocarbons (PFCs), 
hydrofluorocarbons (HFCs), and sulfur hexafluoride (SF<INF>6</INF>).
---------------------------------------------------------------------------

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

[[Page 22403]]

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 CO<INF>2</INF> 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 CO<INF>2</INF>, 
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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 
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 
CO<INF>2</INF> 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 CO<INF>2</INF> emissions in 2009. Total 
CO<INF>2</INF> emissions from fossil fuel-fired EGUs, for years 1990, 
2000 and 2009, are shown below in Table 3.

[[Page 22404]]



           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 (N<INF>2</INF>O) (and to a lesser 
extent, methane (CH<INF>4</INF>)) 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 
NO<INF>X</INF> control. We are not proposing separate N<INF>2</INF>O or 
CH<INF>4</INF> emission limits or an equivalent CO<INF>2</INF> 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 N<INF>2</INF>O and 
CH<INF>4</INF> from fossil fuel-fired EGUs (9.0 and 0.7 Tg of 
CO<INF>2</INF> equivalent, respectively) is about 0.4 percent of total 
CO<INF>2</INF> 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 N<INF>2</INF>O and 
CH<INF>4</INF> 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 
SO<INF>2</INF> emissions by 73 percent and NO<INF>X</INF> 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

[[Page 22405]]

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 NO<INF>X</INF> program. On February 7, 2012, 
EPA issued two sets of minor adjustments to the CSAPR (77 FR 10324, 
February 21, 2012).
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    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 SO<INF>2</INF> 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:

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

[[Page 22406]]

under CAA section 129 would not be subject to requirements under this 
proposed rule.
2. CO<INF>2</INF> Emissions Only
    This action proposes to regulate covered EGU emissions of 
CO<INF>2</INF>, 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 CO<INF>2</INF> 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 CO<INF>2</INF> 
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 CO<INF>2</INF> emission 
limit that must be met by all affected sources.\41\ Specifically, the 
EPA is proposing a standard of 1,000 lb CO<INF>2</INF>/MWh, but, as 
discussed below, is taking comment on a range from 950 lb 
CO<INF>2</INF>/MWh to 1,100 lb CO<INF>2</INF>/MWh.
---------------------------------------------------------------------------

    \41\ As discussed below, we are not proposing such a limit for 
modifications, transitional sources, or reconstructed sources.
---------------------------------------------------------------------------

    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 CO<INF>2</INF>/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 
CO<INF>2</INF> emissions limit based on the best demonstrated 
performance of a coal-fired facility without CCS, which is 1,800 lb 
CO<INF>2</INF>/MWh (816 kg CO<INF>2</INF>/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 CO<INF>2</INF>/MWh (272 kg CO<INF>2</INF>/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 
CO<INF>2</INF> emissions rate from the facility over the 30-year time 
period would be equivalent to the proposed standard of performance of 
1,000 lb CO<INF>2</INF>/MWh. This reduced emissions standard during the 
remainder of the 30-year period would be met with some level of 
CCS.\42\
---------------------------------------------------------------------------

    \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 CO<INF>2</INF>/MWh, and whether the 
emissions standard that reflects supercritical efficiency should be 
somewhat higher or lower than 1,800 lb CO<INF>2</INF>/MWh. If EPA 
does promulgate a higher or lower standard in either case, then EPA 
may revise the 600 lb CO<INF>2</INF>/MWh amount accordingly.
---------------------------------------------------------------------------

    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 CO<INF>2</INF>/MWh. 
For instance, if an owner or operator wished to operate at a rate of 
2,000 lb CO<INF>2</INF>/MWh for the first period, it would have to 
commit to something more stringent than achieving a 600 lb 
CO<INF>2</INF>/MWh standard by the 11th year. Potential compliance 
pathways could include committing to a limit of 500 lb CO<INF>2</INF>/
MWh by the 11th year or committing to a limit of 600 lb CO<INF>2</INF>/
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 CO<INF>2</INF> 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

[[Page 22407]]

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 CO<INF>2</INF>/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 CO<INF>2</INF> may be dependent upon construction 
by a third party of a pipeline that will be transporting the 
CO<INF>2</INF> 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 
CO<INF>2</INF>/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 CO<INF>2</INF>/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 CO<INF>2</INF> 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 CO<INF>2</INF> 
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

[[Page 22408]]

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.
    In the event that a source fails to comply with the applicable CAA 
section 111 standards as a result of a malfunction event, the EPA would 
determine an appropriate response based on, among other things, the 
good faith efforts of the source to minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses to ascertain and rectify excess emissions. 
The EPA would also consider whether the source's failure to comply with 
the CAA section 111 standard was, in fact, ``sudden, infrequent, not 
reasonably preventable'' and was not instead ``caused in part by poor 
maintenance or careless operation.'' 40 CFR section 60.2 (definition of 
malfunction).
    Finally, the EPA recognizes that even equipment that is properly 
designed and maintained can sometimes fail and that such failure can 
sometimes cause an exceedance of the relevant emission standard. (See, 
e.g., ``State Implementation Plans: Policy Regarding Excessive 
Emissions During Malfunctions, Startup, and Shutdown'' (Sept. 20, 
1999); Policy on Excess Emissions During Startup, Shutdown, 
Maintenance, and Malfunctions (Feb. 15, 1983), which are both included 
in the docket for this rulemaking.) The EPA is therefore proposing to 
add to the final rule an affirmative defense to civil penalties for 
exceedances of emission limits that are caused by malfunctions. See 40 
CFR 60.10042 (defining ``affirmative defense'' to mean, in the context 
of an enforcement proceeding, a response or defense put forward by a 
defendant, regarding which the defendant has the burden of proof, and 
the merits of which are independently and objectively evaluated in a 
judicial or administrative proceeding.). We also are proposing other 
regulatory provisions to specify the elements that are necessary to 
establish this affirmative defense: The source must prove by a 
preponderance of the evidence that it has met all of the elements set 
forth in 60.10001. (See 40 CFR 22.24). The criteria ensure that the 
affirmative defense is available only where the event that causes an 
exceedance of the emission limit meets the narrow definition of 
malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably 
preventable and not caused by poor maintenance and or careless 
operation). For example, to successfully assert the affirmative 
defense, the source must prove by a preponderance of the evidence that 
excess emissions ``[w]ere caused by a sudden, infrequent, and 
unavoidable failure of air pollution control and monitoring equipment, 
process equipment, or a process to operate in a normal or usual manner 
* * *.'' The criteria also are designed to ensure that steps are taken 
to correct the malfunction, to minimize emissions in accordance with 
section 60.10001 and to prevent future malfunctions. For example, the 
source must prove by a preponderance of the evidence that ``[r]epairs 
were made as expeditiously as possible when the applicable emission 
limitations were being exceeded * * *'' and that ``[a]ll possible steps 
were taken to minimize the impact of the excess emissions on ambient 
air quality, the environment and human health * * *.'' In any judicial 
or administrative proceeding, the Administrator may challenge the 
assertion of the affirmative defense and, if the respondent has not met 
its burden of proving all of the requirements in the affirmative 
defense, appropriate penalties may be assessed in accordance with 
section 113 of the CAA (see also 40 CFR part 22.77).
    The EPA is including an affirmative defense in an attempt to 
balance a tension, inherent in many types of air regulation, to ensure 
adequate compliance while simultaneously recognizing that despite the 
most diligent of efforts, emission limits may be exceeded under 
circumstances beyond the control of the source. The EPA must establish 
emission standards that ``limit the quantity, rate, or concentration of 
emissions of air pollutants on a continuous basis.'' 42 U.S.C. 7602(k) 
(defining ``emission limitation and emission standard''). See generally 
Sierra Club v. EPA, 551 F.3d 1019, 1021 (DC Cir. 2008) Thus, the EPA is 
required to ensure that section 112 emissions limitations are 
continuous. The affirmative defense for malfunction events meets this 
requirement by ensuring that even where there is a malfunction, the 
emission limitation is still enforceable through injunctive relief.\43\ 
While ``continuous'' limitations, on the one hand, are required, there 
is also case law indicating that in many situations it is appropriate 
for the EPA to account for the practical realities of technology. For 
example, in Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (DC Cir. 
1973), the DC Circuit acknowledged that in setting standards under CAA 
section 111 ``variant provisions'' such as provisions allowing for 
upsets during startup, shutdown and equipment

[[Page 22409]]

malfunction ``appear necessary to preserve the reasonableness of the 
standards as a whole and that the record does not support the `never to 
be exceeded' standard currently in force.'' See also, Portland Cement 
Association v. Ruckelshaus, 486 F.2d 375 (DC Cir. 1973). Though 
intervening case law such as Sierra Club v. EPA and the CAA 1977 
amendments undermine the relevance of these cases today, they support 
the EPA's view that a system that incorporates some level of 
flexibility is reasonable. The affirmative defense simply provides for 
a defense to civil penalties for excess emissions that are proven to be 
beyond the control of the source. By incorporating an affirmative 
defense, the EPA has formalized its approach to upset events. In a 
Clean Water Act setting, the Ninth Circuit required this type of 
formalized approach when regulating ``upsets beyond the control of the 
permit holder.'' Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th 
Cir. 1977). But see, Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 
(DC Cir. 1978) (holding that an informal approach is adequate). The 
affirmative defense provisions give the EPA the flexibility to both 
ensure that its emission limitations are ``continuous'' as required by 
42 U.S.C. 7602(k), and account for unplanned upsets and thus support 
the reasonableness of the standard as a whole.
---------------------------------------------------------------------------

    \43\ Note that the Ninth Circuit recently upheld EPA's decision 
to apply this affirmative defense approach to only actions seeking 
civil penalties, and not also to actions seeking injunctive relief. 
Montana Sulfur & Chemical Co. v. EPA, No. 02-71657 (9th Cir. August 
31, 2011) (slip op. at 456).
---------------------------------------------------------------------------

    We propose that these same requirements for malfunctions would 
apply to the 30-year averaging compliance option; however, we take 
comment on whether it is appropriate to have an affirmative defense for 
the 30-year averaging portion of that compliance option, given that we 
would expect malfunctions to only impact shorter emissions limits, and 
the longer the compliance period, the less likely malfunction events 
are to impact a source's ability to meet the standard.

D. What are the continuous monitoring requirements?

    The EPA is proposing that a CO<INF>2</INF> mass rate CEMS and the 
associated automatic data acquisition and handling system must be 
installed and operated in accordance with the requirements below.
    1. Prepare a site-specific monitoring plan that addresses the 
monitoring system design, data collection, and the quality assurance 
and quality control elements consistent with the requirements in 40 CFR 
part 75.
    2. Use all the data collected during all other required data 
collection periods in assessing the operation of the control device and 
associated control system.
    3. Report any periods for which the monitoring system failed to 
collect required data.
    4. Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required monitoring 
system quality assurance or quality control activities (including, as 
applicable, calibration checks and required zero and span adjustments); 
failure to collect required data is a deviation of the monitoring 
requirements.
    We propose that owners/operators would install the CEMS and 
complete the CEMS certification in accordance with the schedule 
required in 40 CFR part 75, section 75.4(b).
    We also request comment on the appropriateness of applying the 
backup monitor requirements in 40 CFR part 75.10(e), the missing data 
procedures in 40 CFR part 75, sections 75.31 through 75.37, and 
appendix C for this proposed rule.
    We propose that these same monitoring requirements would apply to 
the 30-year averaging compliance option.

E. What are the emissions performance testing requirements?

    Consistent with the performance testing requirements in the CAA 
section 111 regulatory general provisions (40 CFR part 60.8) and CEMS 
certification requirements (40 CFR part 75.4(b)), we propose that 
owners/operators of a new unit, conduct an initial performance test to 
demonstrate compliance with the CO<INF>2</INF> emissions limits 
beginning in the calendar month following initial certification of the 
CO<INF>2</INF> and flow rate monitoring CEMS.
    We propose that the initial performance test consist of collection 
of hourly CO<INF>2</INF> average concentration, mass flow rate 
(standard cubic feet per hour) recorded with the certified 
CO<INF>2</INF> concentration and flow rate CEMS and the corresponding 
electrical power generation data for all of the hours of operation for 
the first calendar year beginning on the first day of the first month 
following completion of the CEMS installation and certification. For 
all of the operating hours during each monthly period, including 
startup and shutdown, you would calculate compliance with the emissions 
limit by dividing the sum of the hourly CO<INF>2</INF> mass values by 
the sum of the hourly useful energy output produced over the first 12 
months of data.
    We propose that these same emissions performance testing 
requirements would apply to the 30-year averaging compliance option.

F. What are the continuous compliance requirements?

    In this rulemaking, we propose that compliance with the applicable 
average CO<INF>2</INF> mass emissions rate (lb/MWh) must be calculated 
as a 12-month rolling average, updated monthly, using the reported 
hourly CO<INF>2</INF> average concentration and flow rate values from 
the certified CEMS data collected for the previous month's process 
operating days along with generation data tracked by the facility for 
the unit. We propose that compliance with the emissions limit must be 
calculated by dividing the sum of the hourly CO<INF>2</INF> mass 
emissions values by the sum of the useful energy output produced for 
each calendar month period and that the 12-month rolling average must 
be updated as the average of the previous 12 months' calculations. 
Affected sources will continue to be subject to the standards and 
maintenance requirements in the section 111 regulatory general 
provisions. 40 CFR part 60, subpart A.
    We solicit comment on, in the alternative, an annual (calendar 
year) average emission limit, which would be calculated through 
comparable methodology as just described.
    We propose that these same continuous compliance requirements would 
apply to the 30-year averaging compliance option.

G. What are the notification, recordkeeping, and reporting 
requirements?

    In this rulemaking, the EPA is proposing that you, as the owner or 
operator of a new unit, must comply with the notification and 
recordkeeping requirements in the section 111 regulatory general 
provisions, 40 CFR part 60, subpart A, and need to report results of 
performance testing and excess emissions; as well as record and 
maintain hourly average CO<INF>2</INF> emissions concentration, hourly 
average flow rate, and hourly useful electrical generation. Note that 
the summary form identified as Figure 1 in 40 CFR part 60.7(d) will be 
revised to include CO<INF>2</INF> as a pollutant. We are also seeking 
comments on whether the EPA should require initial notification of 
compliance status reports. In most rules, an initial notification of 
compliance status report, where owners and operators of sources subject 
to a particular rule notify the EPA and State and Local Air Pollution 
Control Agencies that their source is subject to the rule and how they 
intend to comply with the rule, is required. Regulators find this 
information very helpful in implementing and enforcing particular 
rules. In this case, most, if not

[[Page 22410]]

all, of the sources that are potentially subject to this rule have 
already been identified because they are subject to other New Source 
Performance Standards and Part 75 Acid Rain provisions.
    As part of an Agency-wide effort to facilitate reporting of 
environmental data and reports, we are requiring electronic reporting 
of selected reports, required by this regulation, to the EPA. We are 
proposing that owners and operators subject to this regulation must 
electronically submit excess emissions, continuous monitoring systems 
performance and-or summary reports required under section 60.7(c). 
Owners and operators would need to submit these reports to the EPA's 
WebFIRE database by using the Compliance and Emissions Data Reporting 
Interface (CEDRI) that is accessed in the Central Data Exchange (CDX). 
The CDX is the EPA's portal for submitting and managing electronic 
environmental data and reports and is accessed at www.epa.gov/cdx. The 
CDX is needed to meet the EPA standards for electronic reporting set by 
the Cross-Media Electronic Reporting Rule. For more information, please 
see http://www.epa.gov/cromerr/. Owners and operators required to 
submit electronic reports would need to register to use the CDX and for 
the CEDRI node at http://cdx.epa.gov/epa_home.asp. Once a user has 
access to CDX and CEDRI, the owners and operators would use the subpart 
specific forms in CEDRI to enter the information for the 60.7(c) 
required reports.
    In most New Source Performance Standards owners and operators are 
required to keep records of their reports on site for at least 2 years. 
Since the owner or operator would be submitting the data in these 
reports to be housed in CDX and WebFIRE, we are proposing to forgo 
recordkeeping requirements for those reports required to be submitted 
in proposed section 60.5555(a)(1). We believe that since the WebFIRE 
database is public that the need for recordkeeping onsite for certain 
information will not be needed as the information will be readily 
available for all stakeholders to access.
    We are aware that owners or operators of many existing EGUs are 
required to submit some emissions data through the EPA Acid Rain 
Program's Emissions Collection and Monitoring Plan System (ECMPS) for 
SO<INF>2</INF>, NO<INF>X</INF>, CO<INF>2</INF>, and other related data. 
We propose for affected sources to continue to use ECMPS with 
modifications to allow for collecting CO<INF>2</INF> mass emissions 
data and the CEMS relative accuracy reports proposed in this rule.
    We request comment on these and other modifications to ECMPS 
appropriate for implementing this rule and any other EPA rules that 
apply to EGUs in order to streamline and focus all applicable emissions 
data reporting requirements. We request comment on modification of the 
ECMPS system to collect, track, and calculate CO<INF>2</INF> emissions 
rates based on hourly useful energy output for the unit. We also 
request comment on tracking and making use of useful steam data for new 
facilities.
    We are also aware that owners or operators of existing units are 
required to submit electrical generation data according to procedures 
required by the DOE's Energy Information Administration (EIA) for its 
reports. We request comment on the appropriateness of using these 
electrical generation data in this proposed rule.
    The EPA proposes that these same notice, recordkeeping, and 
reporting requirements would apply to the 30-year averaging compliance 
option. The EPA requests comment on whether any alterations or 
additions are appropriate for the notice, recordkeeping, and reporting 
requirements that would apply to the 30-year averaging compliance 
option. The EPA also requests comment on whether sources that utilize 
the 30-year averaging compliance option should include, as applicable 
requirements in their title V permits, a specific explanation of their 
compliance plan, including when CCS would be deployed, what capture 
rate(s) would be achieved, how the CO<INF>2</INF> would be sequestered, 
and whether the company anticipates receiving government financial 
assistance or other incentives for the CCS.

IV. Rationale for the Proposed Standards for New Sources

A. How did the EPA establish the emission limits?

1. Rationale for Proposing to Combine the Subpart Da Category and a 
Component of the Subpart KKKK Category into a New Category for Purposes 
of Regulating GHG Emissions
    The EPA is proposing to create a new subpart in 40 CFR part 60 by 
combining the sources in subpart Da (the Da category) and a subset of 
the sources in subpart KKKK (the KKKK category)--stationary combined 
cycle units, but not stationary simple cycle units--for purposes of 
promulgating standards of performance for emissions of GHGs from new 
sources. This new subpart will be numbered TTTT. Consistent with 
standard practice and Executive Order 13563, and in particular its 
emphasis on ``the open exchange of information and perspectives'' and 
``providing an opportunity for public comment on all pertinent parts of 
the rulemaking docket, including relevant scientific and technical 
findings'' and on consideration of alternatives, we invite comments on 
our decision to combine the two source categories.
    At this time, the EPA is not proposing to subcategorize new sources 
and is not proposing to combine the Da category and components of the 
KKKK category for purposes of regulating criteria pollutants.
    CAA section 111 provides legal authority for combining the 
categories into a new category. Clean Air Act section 111(b)(1)(A) 
provides:

    The Administrator shall, within 90 days after December 31, 1970, 
publish (and from time to time thereafter shall revise) a list of 
categories of stationary sources. He shall include a category of 
sources in such a list if in his judgment it causes or contributes 
significantly to air pollution which may reasonably be anticipated 
to endanger public health or welfare.

(Emphasis added.)

    As quoted, this provision grants to the Administrator the authority 
to ``revise'' the list of categories. Combining categories, in whole or 
in part, is a form of ``revis[ing]'' the list of categories (along with 
taking other actions, such as adding more categories or delisting 
categories), and accordingly is authorized.
    For three principal reasons, it is appropriate for the EPA to 
combine the Da category and the stationary combined cycle component of 
the KKKK category at this time for purposes of regulating GHGs. First, 
all of the plants covered by the new combined category (including 
fossil fuel-fired boilers, IGCC units and NGCC units) perform the same 
essential function, which is to provide generation to serve baseload or 
intermediate load demand. It is sensible to treat as part of the same 
category units that generate baseload or intermediate load electricity, 
regardless of their design or fossil fuel type.
    Second, all newly constructed sources have options in selecting 
their design (although it is true that natural gas-fired plants are 
inherently lower emitting with regard to CO<INF>2</INF> than coal-fired 
plants. As a result, prospective owners and operators of new sources 
could readily comply with the proposed emission standards by choosing 
to construct a NGCC unit. These two factors provide sufficient legal 
rationale for the EPA to combine the Da category and the combined cycle 
component of the KKKK category for purposes of

[[Page 22411]]

establishing a standard of performance for GHG emissions.
    The agency has previously combined one type of baseload and 
intermediate load combined cycle unit (IGCC, previously covered under 
Subpart GG) with Da units for the purposes of setting a standard [40 
CFR 60.41Da(b), Feb. 28, 2005]. This action now similarly combines 
another type of baseload and intermediate load combined cycle unit 
(NGCC, previously covered under Subpart KKKK) with Subpart Da units for 
the purposes of setting a standard.
    A third factor lends additional support. Combining the categories 
does not raise adverse policy concerns. On the basis of comments made 
during the listening sessions, we anticipate that some commenters may 
question whether combining the categories and applying the NGCC 
standard to all new plants within the combined category may limit 
construction of new coal-fired power plants, and thereby have a 
disruptive effect on the electric power industry, increase electricity 
prices and/or have adverse implications for energy diversity in new 
generation. We do not believe that this action would have those 
effects. As discussed below, and importantly, economic models forecast 
no new construction of coal-fired generation without CCS through the 
analysis period, which extends until 2020 (when the standard will be 
revisited). Accordingly, economic conditions are expected to be the 
main driver precluding, or at least limiting, construction of coal-
fired EGUs. Because of those economic conditions, there is a strong 
independent movement of power plants serving baseload generation toward 
NGCC. In light of that movement, it is appropriate for the EPA to focus 
on this technology in developing the standard, rather than 
subcategorizing and providing a separate standard for new coal units. 
See Portland Cement Ass'n v. EPA, 665 F.3d 177, 190 (D.C. Cir. 2011) 
(affirming the EPA's decision not to subcategorize in part because of 
``the universal movement in the portland cement industry towards 
adoption of preheater/precalciner technology'').
    Notwithstanding these points, we recognize the possibility that a 
limited amount of new coal-fired construction may nevertheless occur. 
Today's action would not foreclose construction of new coal-fired EGUs. 
Rather, the new coal-fired EGUs that may be expected to be built in the 
foreseeable future (and for reasons stated above, this is anticipated 
to be a relatively small number) may install CCS control equipment (if 
not at the time of construction, then not long thereafter). By doing 
so, they may achieve the same average CO<INF>2</INF> emission rate (at 
least over time) as a natural gas-fired combined cycle unit. It is 
reasonable to expect that some coal-fired power plants may be able to 
implement CCS at the present time, and thereby achieve the 1,000 lb 
CO<INF>2</INF>/MWh standard immediately. As noted elsewhere, CCS has 
been demonstrated to be technologically achievable, and, even though it 
is costly, there are some State and Federal programs that can make CCS 
more affordable. Several power companies have announced plans to 
incorporate CCS at six already permitted coal-fired EGU construction 
projects in this country (as we discuss below in section V.B., 
concerning transitional sources). Programs exist that provide some 
funding for CCS through pilot or other demonstration programs, and we 
expect those to continue. In addition, we reasonably expect the costs 
of CCS to decline over time. As discussed below, we are not proposing 
that CCS does or does not qualify as the ``best system of emission 
reduction'' that ``has been adequately demonstrated'' for new coal-
fired power plants. Rather, the feasibility of CCS and its availability 
for the limited amount of new coal-fired construction that may be 
expected, means that this action to combine the categories and 
establish the NSPS at the proposed 1,000 lb CO<INF>2</INF>/MWh emission 
limit will not have notable adverse effects on new coal-fired 
construction or, therefore, on the electric utility industry, 
electricity prices, or energy diversity. We welcome public comments on 
this discussion.
    On the other hand, at this time, we do not consider it appropriate 
to include simple cycle facilities as an affected source in the new 40 
CFR part 60, subpart TTTT for GHG emissions from new facilities. The 
reason for this is that the function of a new simple cycle power plant 
is different than that of a new combined cycle plant or coal-fired 
plant. Combined cycle plants and coal-fired plants are typically 
designed to provide baseload or intermediate-load power, while simple 
cycle turbines are designed to provide peaking power. Because combined 
cycle power plants and coal-fired power plants both serve the same 
purpose and have design options to emit CO<INF>2</INF> at similar 
levels, we believe it is appropriate to combine them. Because peaking 
turbines operate less and because it would be much more expensive to 
lower their emission profile to that of a combined cycle power plant or 
a coal-fired plant with CCS, the EPA does not believe it is appropriate 
to include them in this source category.
    As noted above, some commenters in the listening sessions did 
suggest that the EPA not combine the two source categories. The EPA has 
rejected that option for all the reasons outlined above: (1) Fossil-
fuel-fired boilers, combined cycle natural gas units, and IGCC units 
all serve the same basic function, generating baseload or intermediate 
load power; (2) the proposed standards can be met by different types of 
units in the category (NGCC units or coal-fired units with CCS); and 
(3) it is consistent with industry trends (as further explained 
elsewhere in this notice: Due largely to current and projected gas and 
coal price trends, new fossil-fuel-fired builds are projected to be 
natural gas combined cycle units or coal-fired units with CCS supported 
by federal funding). There is an additional reason for rejecting the 
option of retaining (and establishing separate standards for) separate 
source categories. The EPA's analysis (in Section 5.10 of the RIA) 
suggests that over a wide range of market conditions, constructing a 
new unit that meets a limit of 1,000 lb CO<INF>2</INF>/MWh instead of 
an advanced coal-fired unit without CCS would likely produce net social 
benefits. For all of these reasons, retaining separate source 
categories would be unlikely to generate substantial private cost 
savings, but at the same time, would create the risk of significantly 
higher GHG emissions and other air pollutants from some new units, 
resulting, in turn, in higher social costs.
    By the same token, at this time, we do not consider it appropriate 
to combine the Da category and the combined cycle component of the KKKK 
category for any pollutants other than GHGs, that is, for criteria 
pollutants. This is because although coal-fired EGUs have an array of 
control options for criteria and air toxic air pollutants to choose 
from, those controls generally do not reduce their criteria and air 
toxic emissions to the level of conventional emissions from natural 
gas-fired EGUs.
2. Endangerment and Cause-or-Contribute-Significantly Finding
    a. Overview. In today's rulemaking, we propose or solicit comment 
on alternative interpretations for whether section 111 includes 
prerequisites to rulemaking that involve an endangerment finding and a 
cause-or-contribute-significantly finding. By its terms, CAA section 
111 provides that once the EPA lists a source category for regulation 
because the category causes or contributes significantly to air 
pollution that may reasonably be anticipated to endanger public health 
or

[[Page 22412]]

welfare, the EPA then establishes requirements for new sources in that 
source category. The EPA proposes to interpret these provisions so that 
it is authorized to promulgate the rulemaking proposed today because it 
has already determined that both the Da and KKKK source categories 
cause or contribute significantly to air pollution that may reasonably 
be anticipated to endanger public health or welfare. The EPA solicits 
comment on interpreting CAA section 111 in the alternative so as to 
require (i) an endangerment finding for air pollution not specifically 
covered by the endangerment finding the EPA made when listing the 
source category, but that in this case, the EPA's 2009 Endangerment 
Finding for GHGs under Section 202(a) of the CAA (along with the EPA's 
2010 denial of petitions to reconsider (2010 Reconsideration Denial)), 
fulfills that requirement; and (ii) a cause-or-contribute-significantly 
finding for air pollutants not specifically covered by the cause-or-
contribute-significantly finding the EPA made when listing the source 
category, and that in this case, the large amounts of CO<INF>2</INF> 
emissions from power plants provide a compelling basis allowing the EPA 
to propose that finding. The EPA also solicits comment on another 
alternative, which is interpreting CAA section 111 so as not to require 
a specific endangerment finding or cause or contribute finding, but 
simply to require the EPA to establish a rational basis for regulating 
an air pollutant from a source category. In this case, the EPA's 2009 
Endangerment Finding for GHGs and the 2010 denial of petitions to 
reconsider the Endangerment Finding, as well as the large amounts of 
CO<INF>2</INF> emissions from power plants, provide that rational 
basis. Finally, as an alternative for the basis for a rational basis 
determination, the 2010 and 2011 Assessment Reports from the National 
Academies confirm the Endangerment Finding and the denial of petitions 
to reconsider.
    b. Proposal: Previous Source Category Findings Meet Any 
Endangerment Prerequisite to Regulation. In this rulemaking, the EPA 
proposes to interpret CAA section 111 so that we are not required, as a 
prerequisite to regulating CO<INF>2</INF> emissions from EGUs, to issue 
a new finding as to the health or welfare impacts of GHG air pollution 
or a finding as to the extent that affected sources contribute to that 
air pollution.
    Clean Air Act section 111(b)(1)(A), by its terms, requires that the 
Administrator list a source category for regulation if the ``category * 
* * in [the Administrator's] judgment, * * * causes or contributes 
significantly to air pollution which may reasonably be anticipated to 
endanger public health or welfare.'' Clean Air Act section 111(b)(1)(B) 
goes on to provide that after listing the source category, the EPA must 
promulgate regulations ``establishing federal standards of performance 
for new sources within such category.'' In turn, CAA section 111(a)(1) 
defines a ``standard of performance'' as a ``standard for emissions of 
air pollutants which reflects the degree of emission reduction which 
(taking into account * * * cost * * * and any nonair quality health and 
environmental impact and energy requirements) * * * has been adequately 
demonstrated.''
    Thus, although CAA section 111 clearly requires the EPA to list a 
source category if its emissions contribute significantly to air 
pollution that endangers public health or welfare, and then to 
promulgate standards of performance for particular pollutants, section 
111 does not by its terms require that the EPA make any endangerment 
finding with respect to those particular pollutants, or any cause-or-
contribute-significantly finding with respect to the source category, 
at the time the EPA promulgates the standards of performance for those 
pollutants. The lack of any such requirement contrasts with (i) the 
definition of ``standard of performance,'' which specifically requires 
the EPA to consider ``nonair quality health and environmental impact,'' 
CAA section 111(a)(1) (emphasis added); and (ii) other CAA provisions 
that do require the EPA to make endangerment and cause-or-contribute 
findings for the particular pollutant that the EPA regulates under 
those provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 
231(a)(2)(A).
    Accordingly, under our proposal, once the EPA has listed a source 
category, and the EPA proceeds to regulate particular pollutants from 
that source category, CAA section 111 does not require that the EPA 
make an endangerment finding for the relevant air pollution or a cause-
or-contribute-significantly finding for the relevant air pollutants 
from that source category. The fact that the EPA is, in this 
rulemaking, proposing to partially combine the Da and KKKK source 
categories does not alter this outcome. As noted above, under CAA 
section 111(b)(1)(A), the EPA may add a source category to the list of 
categories only after determining that the source category ``causes, or 
contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' The EPA has 
previously determined that each of the Da and KKKK categories causes or 
contributes significantly to such air pollution. Combining the Da 
category and some of the sources in the KKKK category does not 
necessitate that the EPA make a new cause-or-contribute-significantly 
finding for the expanded Da category. This is because the EPA has 
already found that at least one component of the new category--the 
former Da sources--by itself causes or contributes significantly to 
such air pollution. There is no reason why this expansion of the Da 
category to include the pre-existing Da sources plus additional sources 
could be considered to contribute to such air pollution to an extent 
that is less than the contribution from the pre-existing Da sources 
alone. As a result, the new category must necessarily be considered to 
cause or contribute significantly to such air pollution.
    In addition to proposing this interpretation, we also solicit 
comment on alternative interpretations under CAA section 111, including 
those described next.
    c. First Alternative Interpretation: Endangerment Finding 
Prerequisite. We solicit comment on an alternative interpretation under 
which the EPA is required, as a prerequisite to promulgating standards 
of performance under CAA section 111(b), to have issued an endangerment 
finding specifically for the relevant air pollution and a cause-or-
contribute-significantly finding specifically for the relevant source 
category and air pollutant. In particular, what would be the legal 
basis for such an interpretation?
    Even if CAA section 111 is interpreted to require those findings, 
then, in a case in which the EPA did not make those findings under CAA 
section 111, it is the EPA's view that the EPA would satisfy the need 
for a CAA section 111 endangerment finding through an endangerment or 
comparable finding that the EPA made or that Congress adopted under any 
other provision of the CAA. For example, the EPA may regulate, under 
CAA section 111, (i) NAAQS pollutants because of the determinations the 
EPA made under CAA sections 108 and 109 and (ii) HAPs that Congress 
listed under CAA section 112(b)(1). It is the EPA's interpretation that 
once an endangerment or comparable finding is made with respect to the 
relevant air pollution under another CAA provision, regulation under 
CAA section 111 of source categories that cause or contribute 
significantly to that same air pollution may proceed without any need 
for the EPA to revisit or update that endangerment finding as part of 
the

[[Page 22413]]

CAA section 111 regulatory process. Instead, any concerns about the 
continued validity of that endangerment finding may be resolved through 
a petition to reconsider that finding under the applicable CAA 
provision.
    Applying this alternative interpretation of CAA section 111 to this 
rulemaking, the 2009 Endangerment Finding for GHG air pollution 
fulfills any requirement under CAA section 111 that the EPA issue a 
finding that GHG air pollution may reasonably be anticipated to 
endanger public health or welfare in order for the EPA to establish 
standards of performance for GHG emissions from EGUs. As discussed 
above, the EPA already issued this endangerment finding under CAA 
section 202(a)(1), as part of its process for promulgating the Light 
Duty Vehicle Rule.
    The EPA recognizes that under this alternative interpretation, the 
EPA could be required to issue a cause-or-contribute-significantly 
finding for CO<INF>2</INF> emissions from the fossil fuel-fired EGUs, 
as a prerequisite to regulating such emissions under CAA section 111. 
Therefore, under this alternative interpretation, in today's 
rulemaking, the EPA proposes to find that CO<INF>2</INF> emissions from 
fossil fuel-fired EGUs cause or contribute significantly to the GHG air 
pollution. The EPA's basis for this proposed finding is, in part, that 
the large amounts of CO<INF>2</INF> emitted by fossil fuel-fired EGUs 
clearly exceed the low hurdle necessary for the cause-or-contribute-
significantly finding. As noted above in Tables 2 and 3, fossil fuel-
fired EGUs emit almost one-third of all U.S. GHG emissions, and 
constitute by far the largest single stationary source category of GHG 
emissions. Indeed, so great is the contribution of CO<INF>2</INF> air 
pollutants from EGUs to GHG air pollution, that it is simply not 
necessary in this rulemaking to determine thresholds for when a 
contribution may be considered to be a ``significant[]'' contribution. 
If it were necessary, the EPA proposes that a limited amount of 
contribution would meet that standard in light of the fact that GHG air 
pollution is caused by a large number of types of sources and that no 
one source category dominates the entire inventory.
    d. Second alternative interpretation: Rational Basis Prerequisite. 
As a second alternative interpretation, the lack of any requirement in 
CAA section 111 addressing whether and how the EPA is to evaluate 
emissions of particular pollutants from sources in the listed source 
category as a prerequisite for regulation may be viewed as a statutory 
gap that requires a Chevron step 2 interpretation. In this case, the 
EPA is authorized to develop an interpretation that reasonably 
effectuates the purposes of CAA section 111. Under this alternative 
interpretation, the EPA must demonstrate a rational basis for 
controlling the emissions of the particular pollutants. That rational 
basis may consist of some type of factual showing that is consistent 
with the purposes of CAA section 111, but may be something short of an 
endangerment and a cause-or-contribute-significantly finding.
    There are several options for the factual showings that comprise a 
rational basis. Under the first option, the EPA would be justified in 
the present case in taking action with respect to GHG air pollution 
because of the EPA's 2009 Endangerment Finding that GHG air pollution 
may reasonably be anticipated to endanger public health and welfare. 
The EPA issued that Endangerment Finding quite recently, in December, 
2009, and by notice dated August 13, 2010, the EPA denied ten petitions 
to reconsider that Finding, an action that entailed further review of 
scientific information.
    Under the second option, the EPA could conclude that the recent 
Endangerment Finding and denial of reconsideration, coupled with the 
even more recent assessments from the NAS, published in 2010 and 2011, 
which lend further credence to the science supporting the Endangerment 
Finding, suffice to provide a rational basis for promulgating 
regulations under CAA section 111 designed to address contributions to 
the GHG air pollution.
    Under either of these options, the EPA would need to establish a 
rational basis for regulating CO<INF>2</INF> emissions from affected 
EGUs. The fact that affected EGUs emit almost one-third of all U.S. 
GHGs and comprise by far the largest stationary source category of GHG 
emissions, as discussed above, would readily provide such a rational 
basis.
3. Rationale for Emission Limits
    a. Few New Coal-fired Power Plants. An important part of the basis 
for the EPA's proposal for new sources in this rulemaking is that all 
indications suggest that very few new coal-fired power plants will be 
constructed in the foreseeable future. Although a small number of new 
coal-fired power plants have been built recently, the industry 
generally is not building these kinds of power plants at present and is 
not expected to do so for the foreseeable future. The reasons include 
the current economic environment, which has lead to lower electricity 
demand, and competitive natural gas prices. Natural gas prices have 
stabilized over the past few years as new drilling techniques have 
brought additional supply to the marketplace. As a result, natural gas 
prices are expected to be competitive for the foreseeable future and 
utilities are likely to rely heavily on natural gas to meet new demand 
for electricity generation. On average, the cost of generation from a 
new NGCC power plant is expected to be lower than the cost of 
generation from a new coal-fired power plant.\44\
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    \44\ Levelized Cost of New Generation in the Annual Energy 
Outlook 2011 http://205.254.135.24/oiaf/aeo/electricity_generation.html.
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    Other drivers that may influence decisions to build new power 
plants are State and Federal energy and tax policies. Many states have 
adopted renewable portfolio standards (RPS), which require that a 
certain portion of electricity come from renewable energy sources like 
solar or wind. The federal government has also adopted incentives for 
electric generation from renewable energy sources and loan guarantees 
for new nuclear power plants.
    These economic, cost, and policy factors create an environment in 
which natural gas-fired power plants, renewable energy, and nuclear 
power are the forms of energy generation that are most often predicted 
to be built to meet new electricity demand over the coming years.
    Various energy sector modeling efforts, including projections from 
both the EIA and the EPA, show results that are consistent with these 
findings. The Annual Energy Outlook (AEO) for 2011 shows a very modest 
amount of new coal-fired power coming online beyond 2012, although 
there are a number of coal-fired power plants that are currently under 
construction and expected to begin operation in the next year or two. 
According to the AEO 2011, the majority of new generating capacity will 
be either natural gas-fired or renewable, with some lesser amounts of 
nuclear power. The AEO 2011 is based on existing policy and 
regulations, such as state RPS programs and Federal tax credits for 
renewables.\45\ The new generation that EIA does show coming on-line 
after 2012 fits into one of three categories: generation that is 
currently under construction, generation that will include CCS or 
industrial CHP. Units in the first group would not be subject to this 
rule because, since they have commenced construction, they are 
considered existing sources. Units in the second group would include 
either units in the transitional category or new

[[Page 22414]]

units. In either case, they could be built consistent with this action. 
Units in the third group would not be subject to this rule because CHP 
units that generate primarily on-site power are not considered EGUs and 
are thus not affected by the rule.
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    \45\ http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
---------------------------------------------------------------------------

    The EPA modeling using the Integrated Planning Model (IPM), a 
detailed power sector model that the EPA uses to support power sector 
regulations, is keyed to the AEO in a number of respects and shows 
similar patterns of little future construction of new coal-fired power 
plants under the base case.\46\ The EPA's projections from IPM can be 
found in the RIA.
---------------------------------------------------------------------------

    \46\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

    As discussed below, the fact that the expected number of coal-fired 
power plants is so limited supports both (i) basing the standard of 
performance on NGCC, which is expected to be the most commonly built 
new fossil fuel-fired generating technology; and (ii) allowing 30-year 
averaging as an alternative compliance option for coal- and pet coke-
fired power plants because CCS is feasible and sufficiently available 
for the few such plants expected, in light of the demonstration 
programs or other incentives available for CCS, coupled with the 
prospects that the costs of CCS will decline over time.
    b. Basis for the Proposed Standard of Performance. In this section, 
we describe our basis for proposing a standard of 1,000 lb/MWh, and for 
taking comment on a range of 950 to 1,100 lb/MWh (430 to 500 kg/MWh). 
We first describe our method for calculating these levels of 
CO<INF>2</INF> emissions, and then note that several states are already 
requiring these levels of CO<INF>2</INF> emissions.
    (1) Calculation of the Standard. For reasons explained below (see 
``d. Legal Justification for the Standard of Performance and 30-year 
averaging compliance option''), a NGCC facility is the best system of 
emission reduction for new baseload and intermediate load EGUs. To 
establish an appropriate, natural gas-based standard, we reviewed the 
emissions rate of natural gas-fired (non-CHP) combined cycle facilities 
used in the power sector that commenced operation between 2006 and 2010 
and that report complete generation data to EPA. Based on this 
analysis, nearly 95% of these facilities meet the proposed standards on 
an annual basis. These units represent a wide range of geographic 
locations (with differing elevations and ambient temperatures), 
operational characteristics, and sizes.
    We are requesting comment on a range of 950 to 1,100 lb/MWh (430 to 
500 kg/MWh) for the final rule. The upper limit would incorporate 
essentially all available new combined cycle designs and would have 
limited impact on improving efficiency of combined cycle facilities. 
This upper limit would also be consistent with standards promulgated by 
some states, as noted elsewhere. The stricter standard would in general 
eliminate designs without a steam reheat cycle and similar lower 
efficiency designs for use in electric-only generation, and could limit 
presently available options for generation below approximately 40 MW. 
However, an owner/operator of combined cycle facilities with higher 
heat rates could either implement CHP or integrated solar thermal for 
feedwater heating to achieve the proposed standard.
    (2) States Implementing a Comparable Standard. Several states have 
recently established emission performance standards or other measures 
to limit emissions of GHGs from new EGUs that are comparable to the 
proposal in this rulemaking. For example, in September 2006, California 
Governor Schwarzenegger signed into law Senate Bill 1368. The law 
limits long-term investments in baseload generation by the state's 
utilities to power plants that meet an emissions performance standard 
jointly established by the California Energy Commission and the 
California Public Utilities Commission. The Energy Commission has 
designed regulations that establish a standard for new and existing 
baseload generation owned by, or under long-term contract to publicly 
owned utilities, of 1,100 lb CO<INF>2</INF>/MWh.
    In May 2007, Washington Governor Gregoire signed Substitute Senate 
Bill 6001, which established statewide GHG emissions reduction goals, 
and imposed an emission standard that applies to any baseload electric 
generation that commenced operation after June 1, 2008 and is located 
in Washington, whether or not that generation serves load located 
within the state. Baseload generation facilities must initially comply 
with an emission limit of 1,100 lb CO<INF>2</INF>/MWh.
    In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, 
which mandated that facilities generating baseload electricity, whether 
gas- or coal-fired, must have emissions equal to or less than 1,100 lb 
CO<INF>2</INF>/MWh, and prohibited utilities from entering into long-
term purchase agreements for baseload electricity with out-of-state 
facilities that do not meet that standard. Natural gas- and petroleum 
distillate-fired facilities that are primarily used to serve peak 
demand or to integrate energy from renewable resources are specifically 
exempted from the performance standard.
    c. Basis for CCS as a Feasible Technology Option. In this section, 
we describe the basis for our position that CCS is a feasible 
technology option for new coal-fired power plants because CCS is 
technically feasible and sufficiently available in light of the limited 
amount of new coal-fired construction expected in the foreseeable 
future. In brief, first, at present, CCS is technologically feasible 
for implementation at new coal-fired power plants and its core 
components (CO<INF>2</INF> capture, compression, transportation and 
storage) have already been implemented at commercial scale. Second, 
although the costs of CCS are presently high, we have reason to expect 
that the costs of CCS will decrease over time. This action will itself 
contribute to downward pressure on CCS costs by shifting the regulatory 
landscape towards CCS, consistent with the recent report by the 
Interagency Task Force on Carbon Capture and Storage, established by 
President Obama on February 3, 2010, which we describe below. Third, we 
expect construction of no more than a few new coal-fired power plants 
by 2020 and those plants may well be able to take advantage of 
demonstration programs or other sources of funding for CCS. Fourth, 
several states have set emission standards that will make 
implementation of CCS necessary for new coal-fired power plants, some 
projects that implement CCS or components of it are proceeding, and 
other CCS projects are in the planning stages.
    (1) Technological Feasibility of CCS. The current state of affairs 
concerning CCS was described and analyzed by the Interagency Task Force 
on Carbon Capture and Storage, established by President Obama on 
February 3, 2010, co-chaired by the DOE and the EPA, and composed of 14 
executive departments and federal agencies. The Task Force was charged 
with proposing a plan to overcome the barriers to the widespread, cost-
effective deployment of CCS within 10 years, with a goal of bringing 
five to ten commercial demonstration projects online by 2016. The Task 
Force found that, although early CCS projects face economic challenges 
related to climate policy uncertainty, first-of-a-kind technology 
risks, and the current high cost of CCS relative to other technologies, 
there are no insurmountable technological, legal, institutional, 
regulatory or other barriers that prevent CCS from playing a role in

[[Page 22415]]

reducing GHG emissions. The Task Force also identified the need for 
comprehensive review of the overall environmental impacts of CCS.
    (a) Capture and Compression Technologies and Costs. Capture of 
CO<INF>2</INF> from industrial gas streams has occurred since the 1930s 
using a variety of approaches to separate CO<INF>2</INF> from other 
gases. These processes have been used in the natural gas industry and 
to produce food and chemical-grade CO<INF>2</INF>. Although current 
capture technologies are feasible, the costs of CO<INF>2</INF> capture 
and compression represent the largest stumbling block to widespread 
commercialization of CCS. Currently available CO<INF>2</INF> capture 
and compression processes are estimated to represent seventy to ninety 
percent of the overall CCS costs.\47\
---------------------------------------------------------------------------

    \47\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010).
---------------------------------------------------------------------------

    In general, CO<INF>2</INF> capture technologies applicable to coal-
fired power generation can be categorized into three approaches: \48\
---------------------------------------------------------------------------

    \48\ IPCC, 2005; DOE, 2007.
---------------------------------------------------------------------------

    <bullet> Pre-combustion systems are designed to separate 
CO<INF>2</INF> and H<INF>2</INF> in the high-pressure syngas produced 
at IGCC power plants.
    <bullet> Post-combustion systems are designed to separate 
CO<INF>2</INF> from the flue gas produced by fossil-fuel combustion in 
air.
    <bullet> Oxy-combustion uses high-purity O<INF>2</INF>, rather than 
air, to combust coal and therefore produces a highly concentrated 
CO<INF>2</INF> stream.

    Each of these three carbon capture approaches (pre-combustion, 
post-combustion, and oxy-combustion) is technologically feasible. 
However, each results in increased capital and operating costs and 
decreased electricity output (that is, an energy penalty), with a 
resulting increase in the cost of electricity. The energy penalty 
occurs because the CO<INF>2</INF> capture process uses some of the 
energy produced from the plant.
    (b) Current Availability of Transportation and Sequestration. The 
remaining steps for CCS (i.e., pipeline transportation and storage), 
are also well established but less expensive than capture and 
compression.
    Carbon dioxide has been transported via pipelines in the U.S. for 
nearly 40 years. Approximately 50 million metric tons of CO<INF>2</INF> 
are transported each year through 3,600 miles of pipelines. Moreover, a 
review of the 500 largest CO<INF>2</INF> point sources in the U.S. 
shows that 95 percent are within 50 miles of a possible geologic 
sequestration site,\49\ which would lower transportation costs. For 
these reasons, the transportation component of CCS is not expected to 
be a significant stumbling block to the commercial availability of CCS 
in the future.
---------------------------------------------------------------------------

    \49\ JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH 
Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: 
A Key Component of a Global Energy Technology Strategy to Address 
Climate Change. Joint Global Change Research Institute, Battelle 
Pacific Northwest Division. PNWD-3602. College Park, MD.
---------------------------------------------------------------------------

    With respect to sequestration, globally, there are at least four 
commercial integrated CCS facilities sequestering captured 
CO<INF>2</INF> into deep geologic formations and applying a suite of 
technologies to monitor and verify that the CO<INF>2</INF> remains 
sequestered.\50\ These four sites represent over 25 years of cumulative 
experience on safely and effectively storing anthropogenic 
CO<INF>2</INF> in appropriate deep geologic formations.\51\ Estimates 
based on DOE studies indicate that areas of the U.S. with appropriate 
geology have a storage potential of 1,800 billion to more than 20,000 
billion metric tons of CO<INF>2</INF> in deep saline formations, oil 
and gas reservoirs and un-mineable coal seams.\52\ The U.S. experience 
with large-scale CO<INF>2</INF> injection, such as at enhanced oil and 
gas recovery projects, combined with ongoing research, development, and 
demonstration programs in the U.S. and throughout the world, provide 
confidence that the storage--along with capture, compression and 
transport--of large amounts of CO<INF>2</INF> can be achieved.
---------------------------------------------------------------------------

    \50\ These projects are: Sleipner in the North Sea, 
Sn[oslash]hvit in the Barents Sea, In Salah in Algeria, and Weyburn 
in Canada.
    \51\ Dooley, J. J., et al. (2009). An Assessment of the 
Commercial Availability of Carbon Dioxide Capture and Storage 
Technologies as of June 2009. U.S. Department of Energy, Pacific 
Northwest National Laboratory, under Contract DE-AC05-76RL01830.
    \52\ U.S. Department of Energy National Energy Technology 
Laboratory (2010). Carbon Sequestration Atlas of the United States 
and Canada, Third Edition.
---------------------------------------------------------------------------

    It should be noted that the EPA recently finalized two rules that 
aim to protect drinking water and track the amount of CO<INF>2</INF> 
that is sequestered from facilities that carry out geologic 
sequestration. The Underground Injection Control (UIC) Class VI rule, 
established under authority of the Safe Drinking Water Act, sets 
requirements to ensure that geologic sequestration wells are 
appropriately sited, constructed, tested, monitored, and closed in a 
manner that ensures protection of underground sources of drinking 
water.\53\ The UIC Class VI regulations contain monitoring requirements 
to protect underground sources of drinking water, including the 
development of a comprehensive testing and monitoring plan. This 
includes testing of the mechanical integrity of the injection well, 
ground water monitoring, and tracking of the location of the injected 
CO<INF>2</INF> using direct and indirect methods. Projects are also 
required to do extended post-injection monitoring and site care to 
track the location of the injected CO<INF>2</INF> and monitor 
subsurface pressures until it can be demonstrated that underground 
sources of drinking water are no longer endangered. Subpart RR of the 
Greenhouse Gas Reporting Program, which was established under authority 
of the CAA and builds on UIC requirements, provides requirements for 
quantifying the amount of CO<INF>2</INF> sequestered by these 
facilities.\54\ In addition, the EPA recently proposed a rule that 
would conditionally exclude CO<INF>2</INF> streams from the definition 
of hazardous waste under RCRA, where these streams are being injected 
for purposes of geologic sequestration, provided that they are managed 
in accordance with certain conditions.\55\ That proposed rule is based 
upon the EPA's conclusion that the management of CO<INF>2</INF> 
streams, under the proposed conditions, does not present a substantial 
risk to human health or the environment, and was based upon a review of 
existing regulatory programs applicable to the transportation of 
CO<INF>2</INF> streams, and their injection into permitted UIC Class VI 
wells. Together, these actions help create a consistent national 
framework to ensure the safe and effective deployment of geologic 
sequestration.
---------------------------------------------------------------------------

    \53\ Federal Requirements under the Underground Injection 
Control (UIC) Program for Carbon Dioxide (CO<INF>2</INF>) Geologic 
Sequestration (GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).
    \54\ Mandatory Reporting of Greenhouse Gases: Injection and 
Geologic Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060 
(Dec. 1, 2010).
    \55\ Hazardous Waste Management System: Identification and 
Listing of Hazardous Waste: Carbon Dioxide (CO<INF>2</INF>) Streams 
in Geologic Sequestration Activities, Proposed Rule, 76 FR 48073 
(Aug. 8, 2011).
---------------------------------------------------------------------------

    (2) Expected reduction in CCS costs. Research is underway to reduce 
CO<INF>2</INF> capture costs and to improve performance. The DOE/
National Energy Technology Laboratory (NETL) sponsors an extensive 
research, development and demonstration program that is focused on 
developing advanced technology options that will dramatically lower the 
cost of capturing CO<INF>2</INF> from fossil-fuel energy plants 
compared to today's available capture technologies. The DOE/NETL 
estimates that using today's commercially available CCS technologies 
would add around 80 percent to the cost of electricity for a new 
pulverized coal (PC) plant, and around 35 percent to the cost of 
electricity for a new advanced

[[Page 22416]]

gasification-based (IGCC) plant. The CCS research, development and 
demonstration program is aggressively pursuing efforts to reduce these 
costs to a less than 30 percent increase in the cost of electricity for 
PC power plants and a less than 10 percent increase in the cost of 
electricity for new gasification-based power plants.\56\ The large-
scale CO<INF>2</INF> capture demonstrations that are currently planned 
and in some cases underway, under DOE's initiatives, as well as other 
domestic and international projects, will generate operational 
knowledge and enable continued commercialization and deployment of 
these technologies.
---------------------------------------------------------------------------

    \56\ DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap, 
U.S. Department of Energy National Energy Technology Laboratory, 
December 2010.
---------------------------------------------------------------------------

    Gas absorption processes using chemical solvents, such as amines, 
to separate CO<INF>2</INF> from other gases have been in use since the 
1930s in the natural gas industry and to produce food and chemical 
grade CO<INF>2</INF>. The advancement of amine-based solvents is an 
example of technology development that has improved the cost and 
performance of CO<INF>2</INF> capture. Most single component amine 
systems are not practical in a flue gas environment as the amine will 
rapidly degrade in the presence of oxygen and other contaminants. The 
Fluor Econamine FG process uses a monoethanolamine (MEA) formulation 
specially designed to recover CO<INF>2</INF> and contains a corrosion 
inhibitor that allows the use of less expensive, conventional materials 
of construction. Other commercially available processes use sterically 
hindered amine formulations (for example, the Mitsubishi Heavy 
Industries KS-1 solvent) which are less susceptible to degradation and 
corrosion issues. The DOE/NETL and private industry are continuing to 
sponsor research on advanced solvents (including new classes of amines) 
to improve the CO<INF>2</INF> capture performance and reduce costs.
    Significant reductions in the cost of CO<INF>2</INF> capture would 
be consistent with overall experience with the cost of pollution 
control technology. A significant body of literature suggests that the 
per-unit cost of producing or using a given technology declines as 
experience with that technology increases over time,\57\ and this has 
certainly been the case with air pollution control technologies. 
Reductions in the cost of air pollution control technologies as a 
result of learning-by-doing, research and development investments, and 
other factors have been observed over the decades.
---------------------------------------------------------------------------

    \57\ These studies include John M. Dutton and Annie Thomas, 
``Treating Progress Functions as a Managerial Opportunity,'' 2, 235-
247; Dennis Epple, Linda Argote, and Rukmini Devadas, 
``Organizational Learning Curves: A Method for Investigating Intra-
plant Transfer of Knowledge Acquired Through Learning by Doing,'' 
Organizational Science, Vol. 2, No. 1, February 1991; International 
Energy Agency, Experience Curves for Energy Technology Policy, 2000; 
and Paul L. Joskow and Nancy L. Rose, ``The Effects of Technological 
Change, Experience, and Environmental Regulation on the Construction 
Cost of Coal-Burning Generating Units,'' RAND Journal of Economics, 
Vol. 16,Issue 1, 1-27, 1985. See discussion in ``The Benefits and 
Costs of the Clean Air Act from 1990 to 2020,'' U.S. EPA, Office of 
Air and Radiation, April 2011.
---------------------------------------------------------------------------

    We expect that the costs of capture technology will follow this 
pattern. Rubin et al. assessed the historical rates of cost reductions 
achieved by other energy and environmental process technologies and 
then, by analogy, estimated future cost reductions that might be 
achieved by four types of new power plants employing CO<INF>2</INF> 
capture.\58\ The results of the study suggested that total costs of 
CO<INF>2</INF> capture can be expected to decline by the following 
percentages: NGCC by 40 percent, PC by 26 percent, IGCC by 13 percent, 
and Oxyfuel by 13 percent after installation of the first 100 GW of 
capacity.
---------------------------------------------------------------------------

    \58\ Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison, 
J.; ``Use of experience curves to estimate the future cost of power 
plants with CO<INF>2</INF> capture'', Intl. J. of Greenhouse Gas 
Control, 1, 188 (2007).
---------------------------------------------------------------------------

    In a subsequent study, the model used in the initial study was 
extended with learning curves for several key performance variables, 
including overall energy loss in power plants, the energy required for 
CO<INF>2</INF> capture, the CO<INF>2</INF> capture ratio (removal 
efficiency) and the power plant availability. The model predicted 
continued reductions in cost with increased implementation.\59\
---------------------------------------------------------------------------

    \59\ Van den Broek, M.; Hoefnagels, R.; Rubin, E.; Turkenburg, 
W.; Faaij, A.; ``Effects of technological learning on future cost 
and performance of power plants with CO<INF>2</INF> capture'', 
Progress in Energy and Combustion Science 35 (2009) 457-480.
---------------------------------------------------------------------------

    In addition, we note that the Administration's CCS Task Force 
report recognized that CCS would not become more widely available 
without the advent of a regulatory framework that promoted CCS or a 
strong price signal for CO<INF>2</INF>. Today's action is an important 
component in developing that framework.
    (3) Limited amount of construction of new coal-fired power plants; 
opportunities for CCS funding. A third factor that supports CCS as a 
feasible technology option is that through the IPM model period of up 
to 2020, we expect few, if any, new builds of coal-fired EGUs, beyond 
those that already have approved PSD permits. We also expect continued 
opportunities for financial support for some CCS projects through a 
variety of potential mechanisms such as direct grants, tax incentives 
and/or regulatory programs (e.g. Clean Energy Standards or guaranteed 
electricity purchase price agreements).\60\ Accordingly, the few new 
coal-fired generation projects that may occur over this timeframe may 
well find that financial support for CCS is available.
---------------------------------------------------------------------------

    \60\ See Center for Climate and Energy Solutions, ``Financial 
Incentives for CCS''--http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=8380.
---------------------------------------------------------------------------

    (4) State Requirements for CCS; Projects and Permits for CCS. 
Several states have recently established requirements that new coal-
fired EGUs must implement CCS, and a number of projects with CCS have 
been approved and/or are under construction.
    In May 2007, Montana Governor Schweitzer signed House Bill 25, 
adopting a CO<INF>2</INF> emissions performance standard for electric 
generating units in the state. House Bill 25 prohibits the state Public 
Utility Commission from approving new electric generating units 
primarily fueled by coal unless a minimum of 50 percent of the 
CO<INF>2</INF> produced by the facility is captured and sequestered.
    On January 12, 2009, Illinois Governor Blagojevich signed Senate 
Bill 1987, the Clean Coal Portfolio Standard Law. The legislation 
establishes emission standards for new power plants that use coal as 
their primary feedstock. From 2009-2015, new coal-fueled power plants 
must capture and store 50 percent of the carbon emissions that the 
facility would otherwise emit; from 2016-2017, 70 percent must be 
captured and stored; and after 2017, 90 percent must be captured and 
stored.
    The following is a brief summary of currently operating or planned 
CO<INF>2</INF> capture or storage systems, including, in some cases, 
components necessary for coal-based power plant CCS applications.
    AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point 
(Panama, OK) power plants are equipped with amine scrubbers developed 
by ABB/Lummus. They were designed to process a relatively small 
percentage of each plant's flue gas. At Warrior Run, approximately 
110,000 tonnes of CO<INF>2</INF> per year are captured, whereas at 
Shady Point 66,000 tonnes of CO<INF>2</INF> per year are captured. The 
CO<INF>2</INF> from both plants is subsequently used in the food 
processing industry.\61\
---------------------------------------------------------------------------

    \61\ Dooley, J.J., et al. (2009). An Assessment of the 
Commercial Availability of Carbon Dioxide Capture and Storage 
Technologies as of June 2009. U.S. DOE, Pacific Northwest National 
Laboratory, under Contract DE-AC05-76RL01830.

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[[Page 22417]]

    At the Searles Valley Minerals soda ash plant in Trona, CA, 
approximately 270,000 tonnes of CO<INF>2</INF> per year are captured 
from the flue gas of a coal power plant via amine scrubbing and used 
for the carbonation of brine in the process of producing soda ash.\62\
---------------------------------------------------------------------------

    \62\ IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.
---------------------------------------------------------------------------

    A pre-combustion Rectisol[supreg] system is used for CO<INF>2</INF> 
capture at the Dakota Gasification Company's synthetic natural gas 
production plant located in North Dakota, which is designed to remove 
approximately 1.6 million tonnes of CO<INF>2</INF> per year from the 
synthesis gas. The CO<INF>2</INF> is purified, transported via a 200-
mile pipeline, and injected into the Weyburn oilfield in Saskatchewan, 
Canada.
    In September 2009, American Electric Power Co. (AEP) began a pilot-
scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The 
Mountaineer Plant is a 1,300 MWe coal-fired unit that was retrofitted 
with Alstom's patented chilled ammonia CO<INF>2</INF> capture 
technology on a 20 MWe portion, or ``slipstream'', of the plant's 
exhaust flue gas. In May 2011, Alstom Power announced the successful 
operation of the chilled-ammonia CCS validation project. The AEP-Alstom 
project, the world's first facility to both capture and store 
CO<INF>2</INF> from a coal-fired power plant, represents a successful 
scale-up of ten times the size of previous field pilots (e.g., at We 
Energies Pleasant Prairie). The demonstration achieved capture rates 
from 75 percent (design value) to as high as 90 percent, produced 
CO<INF>2</INF> at purity of greater than 99 percent, with energy 
penalties within a few percent of predictions. The facility reported 
robust steady-state operation during all modes of power plant operation 
including load changes, and saw an availability of the CCS system of 
greater than 90 percent.
    AEP, with assistance from the DOE, had planned to expand the 
slipstream demonstration to a commercial scale, fully integrated 
demonstration at the Mountaineer facility. The commercial-scale system 
was designed to capture at least 90 percent of the CO<INF>2</INF> from 
235 MW of the plant's 1,300 MW total capacity. Plans were for the 
project to be completed in four phases, with the system to begin 
commercial operation in 2015. However, in July 2011, AEP announced that 
it is terminating its cooperative agreement with the DOE and placing 
its plans to advance CO<INF>2</INF> capture and storage technology to 
commercial scale on hold, citing the current uncertain status of U.S. 
climate policy and the continued weak economy as contributors to the 
decision.
    Oxy-combustion of coal is being demonstrated in a 10 MWe facility 
in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe) 
has been operating since September 2008. It is designed to capture 
70,000 tonnes of CO<INF>2</INF> per year.
    In June 2011, Mitsubishi Heavy Industries, an equipment 
manufacturer, announced the successful launch of operations at a 25 MW 
coal-fired carbon capture facility at Southern Company's Alabama Power 
Plant Barry. The demonstration is planned to capture approximately 
150,000 tons of CO<INF>2</INF> annually at a CO<INF>2</INF> capture 
rate of over 90 percent. The captured CO<INF>2</INF> will be 
permanently stored underground in a deep saline geologic formation.
    Southern Company has begun construction of Mississippi Power Plant 
Ratcliffe (formerly the Kemper County IGCC Project). Plant Ratcliffe is 
a 582 MW IGCC plant that will utilize local Mississippi lignite and 
include pre-combustion carbon capture to reduce CO<INF>2</INF> 
emissions by 65 percent. Operation is expected to begin in 2014. The 
CO<INF>2</INF> captured from Plant Ratcliffe will be used for enhanced 
oil recovery (EOR) in the Heidelberg Oil Fields in Jasper County, MS.
    The Texas Clean Energy Project, a 400 MW IGCC facility located near 
Odessa, TX will capture 90 percent of its CO<INF>2</INF>, which is 
approximately 3 million tonnes annually. The captured CO<INF>2</INF> 
will be used for EOR in the West Texas Permian Basin. (Additionally, 
the plant will produce urea and smaller quantities of commercial-grade 
sulfuric acid, argon, and inert slag, all of which will also be 
marketed.) Construction is expected to begin in 2012.
    d. Legal Justification for the Standard of Performance and 30-year 
Averaging Compliance Option. This section describes our legal 
justification for proposing that new affected facilities in the TTTT 
category--which combines the Da and part of the KKKK categories--(i) 
must limit their CO<INF>2</INF> emissions to 1,000 lb CO<INF>2</INF>/
MWh, which an affected facility could achieve by constructing a NGCC 
unit or by constructing a coal-fired boiler that implements CCS 
immediately; or (ii) in the case of a coal- or pet coke-fired power 
plant, may either meet the 1,000 lb CO<INF>2</INF>/MWh standard or 
implement an 30-year averaging compliance option that allows an 
affected facility to meet an initial CO<INF>2</INF> emission limit of 
1,800 lb CO<INF>2</INF>/MWh (gross), and then--through the 
implementation of CCS--meet the 1,000 lb CO<INF>2</INF>/MWh standard, 
on a time-averaged basis, over no longer than a 30-year period.
    (1) Legal Justification for the Standard of Performance. The EPA 
proposes that the emission limit of 1,000 lb CO<INF>2</INF>/MWh meets 
the requirements for a ``standard of performance'' applicable to new 
sources under CAA section 111(b)(1)(B). The term ``standard of 
performance'' is defined under CAA section 111(a)(1) as follows:

    Definitions. For purposes of this section: (1) The term 
``standard of performance'' means 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 apply this definition, in effect, from the bottom up. That is, 
first, we determine the ``best system of emission reduction which 
(taking into account * * * cost [and other factors]) the Administrator 
determines has been adequately demonstrated.'' For EGUs, that is a NGCC 
facility, for reasons discussed below. Then, we calculate the ``degree 
of emission limitation achievable through the application of'' such 
best system; and after that, we formulate ``a standard for emissions of 
air pollutants which reflects'' that degree of emission limitation. 
This standard is 1,000 lb of CO<INF>2</INF>/MWh. These analytical steps 
are also discussed further below.
    In determining the ``best system of emission reduction'' for this 
category of boilers and combined cycle units, we considered a range of 
natural gas-fired and coal-fired generation technologies, with 
available controls. We considered modern supercritical and ultra-
supercritical coal-fired boilers. This technology is available--it is 
currently deployed in Europe and is now being widely deployed in Asia 
(especially China)--and it offers much more efficient operation than 
the subcritical boilers that have more often been constructed in the 
U.S. These supercritical and ultra-supercritical boilers have 
CO<INF>2</INF> emissions of approximately 1,800 lb/MWh and provide the 
lowest overall costs for conventional coal-based electricity. We also 
considered new IGCC, or ``coal gasification'' facilities, which can 
have CO<INF>2</INF> emissions levels very similar to those of ultra-
supercritical coal-fired units--albeit at a higher price.
    We also considered natural gas-fired boilers which have 
CO<INF>2</INF> emissions of approximately 1,350 lb/MWh, obviously

[[Page 22418]]

much lower than the advanced coal-fired or coal gasification 
technologies. However, it seems unlikely that utilities would choose a 
natural gas-fired boiler as the generation technology of choice when 
NGCC is a much more efficient, less expensive, and more widely used 
technology.
    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 CO<INF>2</INF> emissions that 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 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. 
Indeed, those models do not project construction of any new coal-fired 
EGUs during that period that would not comply with the proposed 
standard. This state of affairs has come about primarily because 
technological development and discoveries of abundant 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.
    Essentially because natural gas generation is cleaner and cheaper 
than coal, natural gas-fired EGUs qualify as 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 recognize that today's proposed approach of combining the Da 
category and a portion of the KKKK category, and applying as the 
standard of performance the rate that natural gas-fired EGUs can meet, 
represents a departure from prior agency practice. We consider this 
departure warranted in light of both the emissions benefits and the 
changed economic circumstances, notably the lowered prices of natural 
gas due to technological development and recent discoveries that have 
boosted recoverable reserves. We are aware that in theory, those 
economic circumstances could change and if they do, then a change in 
the standard of performance may be warranted. In this regard, we note 
that CAA section 111(b)(1)(B) requires that the EPA ``shall, at least 
every 8 years, review and, if appropriate, revise [the] standards [of 
performance].'' This 8-year review cycle provides a mechanism for the 
EPA to assure that the standard of performance for any particular 
source category continues to reflect the ``best system.''
    (2) Legal Justification for the 30-year Averaging Compliance 
Option. Although the IPM model projects that for economic reasons, new 
coal- or pet coke-fired EGUs will not be built in the foreseeable 
future (beyond early CCS projects), we recognize that in a few 
instances, owners or operators may in fact seek to build coal- or pet 
coke-fired EGUs. As discussed in detail below, those owners or 
operators could avail themselves of CCS as a 30-year averaging 
compliance option. In addition, today's proposed rulemaking offers 
flexibility for CCS installation: The owners or operators could (i) 
achieve the supercritical efficiency level for an initial period (e.g., 
up to the first 10 years), and (ii) after that, implement CCS so as to 
achieve a 600 lb CO<INF>2</INF>/MWh rate on a 12-month annual average 
during the latter period (i.e., the back 20 years) and thereby achieve 
the 1,000 lb CO<INF>2</INF>/MWh rate on an average annual basis over 
the 30-year period. The alternative compliance option could also allow 
them to install and operate CCS much earlier and use the 10-year period 
to address any startup challenges related to being an early adopter of 
the technology.
    Because CO<INF>2</INF> is long-lived in the atmosphere, the 30-year 
averaging period, as structured, with shorter term compliance 
requirements, is not expected to have a different impact on climate 
compared to meeting the standard of performance.
    (a) CCS. The significance of CCS as a compliance alternative is 
several-fold. As a practical matter, it offers a vehicle for the 
construction of new coal-fired EGUs in those few instances in which 
owners or operators decide to construct such EGUs, notwithstanding the 
underlying economics. Also, it offers a vehicle for the continued 
scaling of CCS, a process that can be expected to lower the costs of 
CCS in the future. In addition, this compliance alternative provides 
further support for the reasonableness of the EPA's proposals in this 
rulemaking to combine the Da category and a portion of the KKKK 
category and to determine that a NGCC facility is the ``best system of 
emission reduction.'' This is because this compliance alternative, by 
providing a vehicle for new coal-fired power plant builds, would 
minimize any disruptions that the EPA's proposals might, at least in 
theory, otherwise entail to the power plant industry.
    CCS as a compliance alternative does not achieve these goals by 
necessarily qualifying, under the CAA section 111(a)(1) definition of 
``standard of performance,'' as the ``best system of emission reduction 
which (taking into account cost [and other factors]) the Administrator 
determines has been adequately demonstrated.'' Instead, this compliance 
alternative is feasible and sufficiently available for the limited 
amount of new coal-fired construction that is expected, whether or not 
it would qualify as the ``best system.''
    First, it is reasonable to expect that some coal-fired power plants 
may be able to implement CCS at the present time, and thereby achieve 
the 1,000 lb CO<INF>2</INF>/MWh standard immediately. As noted 
elsewhere, CCS has been demonstrated to be technologically achievable, 
and, even though it is costly, there are some state and Federal subsidy 
programs that can make CCS more affordable, particularly in tandem with 
use of captured CO<INF>2</INF> for enhanced oil recovery, and those 
programs may be sufficient for the very few new coal-fired plants that 
are expected to be constructed in the foreseeable future. Some of these 
programs are discussed above.
    We note that the need for governmental subsidies to reduce the 
costs of CCS is hardly unique in the electricity generation sector. 
Each of the major types of energy used to generate electricity has been 
or is currently supported by some type of government subsidy--such as 
tax benefits, loan guarantees, low-cost leases, or direct 
expenditures--for some aspect of development and utilization, ranging 
from exploration to control installation. This is true of fossil fuel-
fired; as well as nuclear-, geothermal, wind-, and solar-generated 
electricity. These subsidies have been designed to overcome cost 
barriers to the utilization of the energy. In this context, the need 
for subsidies for CCS to overcome cost barriers does not mean that CCS 
cannot be considered an alternative compliance method in this 
rulemaking.
    Second, it is reasonable to expect that some coal-fired power 
plants may be able to implement the supercritical efficiency standard 
for an initial period of time (the first 10 years) and then implement 
CCS and achieve lower 12-month annual average rates after that, so that 
the source achieves the 1,000 lb CO<INF>2</INF>/MWh standard on average 
over the

[[Page 22419]]

30-year period following construction.\63\ This is because, again, CCS 
is feasible and can be expected to be sufficiently available--in light 
of continued subsidies and lower future costs--in light of the limited 
demand.
---------------------------------------------------------------------------

    \63\ Note that under today's proposed rulemaking, the 30-year 
averaging proposal is associated only with the implementation of CCS 
at new coal- or pet coke-fired EGUs. This proposal does not allow 
30-year averaging for any other purpose.
---------------------------------------------------------------------------

    Third, although we do not propose that the 30-year averaging 
compliance option meets the definition of the ``best system of emission 
reduction [(BSER)] * * * adequately demonstrated,'' under CAA section 
111, we note that identifying CCS as a compliance option based in part 
on the expectation that CCS will cost less in the future is consistent 
with the section 111 requirements for determining the BSER adequately 
demonstrated. In determining what emissions controls qualify as the 
BSER adequately demonstrated--which must take costs into account--the 
EPA is authorized under CAA section 111 to anticipate that technology 
that is costly at present will come down in price in the future. It is 
clear from the legislative history of section 111 and relevant case law 
that the EPA may anticipate future developments--as long as supported 
by an adequate record--in determining whether a particular system of 
emission reduction is the BSER adequately demonstrated. The Senate 
Committee Report to the 1970 CAA Amendments, which first enacted CAA 
section 111, made clear that the EPA may anticipate future developments 
in determining the BSER adequately demonstrated:

    As used in this section, the term ``available control 
technology'' is intended to mean that the Secretary should examine 
the degree of emission control that has been or can be achieved 
through the application of technology which is available or normally 
can be made available. This does not mean that the technology must 
be in actual, routine use somewhere. It does mean that the 
technology must be available at a cost and at a time which the 
Secretary determines to be reasonable. The implicit consideration of 
economic factors in determining whether technology is ``available'' 
should not affect the usefulness of this section. The overriding 
purpose of this section would be to prevent new air pollution 
problems, and toward that end, maximum feasible control of new 
sources at the time of their construction is seen by the committee 
as the most effective and, in the long run, the least expensive 
approach.

Sen. Rep. 91-1196 at 16 (emphasis added). As quoted, this statement 
makes clear that a standard of performance may be based on a technology 
that is not ``in actual routine use somewhere,'' but that ``normally 
can be made available.'' Moreover, the technology need not be available 
until ``a time which the Secretary determines to be reasonable.'' Id.
    In addition, the D.C. Circuit has been explicit that in setting a 
CAA section 111 standard of performance, the EPA may make reasonable 
projections of what technology will be available to the regulated 
industry in the future. The Court stated, in Portland Cement Ass'n v. 
Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):

    We begin by rejecting the suggestion of the cement manufacturers 
that the Act's requirement that emission limitations be ``adequately 
demonstrated'' necessarily implies that any cement plant now in 
existence be able to meet the proposed standards. Section 111 looks 
toward what may fairly be projected for the regulated future, rather 
than the state of the art at present, since it is addressed to 
standards for new plants--old stationary source pollution being 
controlled through other regulatory authority. It is the 
``achievability'' of the proposed standard that is in issue. * * *
The * * * standard is analogous to the one examined in International 
Harvester * * *. The Administrator may make a projection based on 
existing technology, though that projection is subject to the 
restraints of reasonableness and cannot be based on ``crystal ball'' 
inquiry.\64\

Id. at 391 (emphasis added). Again, although these statements in the 
legislative history and case law are in the context of establishing the 
basis for a standard of performance, the same principle -- that the EPA 
may reasonably project the path of technological development -- 
supports treating CCS as a compliance alternative.
    Although, for the reasons noted above, we do expect the costs of 
CCS to decline, we recognize that the amount of the decrease is 
uncertain. Even so, the presence of cost uncertainty by itself does not 
mean that prospective power plants cannot be expected to adopt the 30-
year averaging compliance option. We note that prospective power plants 
face significant cost uncertainties in any event.
    For example we note that recently, several owner/operators have 
announced that they do not intend to construct coal-fired power plants 
without CCS. They have explained that they anticipate more widespread 
CO<INF>2</INF> control requirements in the future, so that constructing 
coal-fired plants at this time without CCS could leave them subject to 
liability for high retrofit control costs in the future. This sentiment 
indicates that some sources may avail themselves of the 30-year 
averaging compliance option.
    The inclusion of a 30-year averaging compliance option has 
precedent in EPA rulemaking under the CAA. In the past, the EPA has 
promulgated rules that adopt an emission limit based on a particular 
technology (such as, in the present rulemaking, NGCC), but has 
supported that action on grounds that sources have compliance 
alternatives, even though higher priced. See ``Finding of Significant 
Contribution and Rulemaking for Certain States in the Ozone Transport 
Assessment Group Region for Purposes of Reducing Regional Transport of 
Ozone: Final Rule'' 63 FR 57356, 57378 (Oct. 27, 1998) (in the rule 
that became known as the ``NO<INF>X</INF> SIP Call,'' the EPA based 
NO<INF>X</INF> emission limits that states were required to meet on the 
assumption that states could adopt specified control measures that were 
``highly cost-effective,'' but the EPA identified other control 
measures that, even though not as cost-effective, the states could 
adopt instead).
    (b) 30-year Period. We propose a 30-year period because (i) we 
generally expect that ten years provides sufficient time either for 
owners/operators who are interested in considering cost improvements 
that occur as a result of the lessons learned from early adopters, or 
provides early adopters sufficient time to address any startup 
challenges; and (ii) as noted above, 30 years provides enough time for 
sources to achieve the 1,000 lb CO<INF>2</INF>/MWh emission limit 
following an elevated level of emissions over the first 10-year period.
    (c) Supercritical Efficiency Level. According to the Department of 
Energy Cost and Performance Baseline for Fossil Energy Plants reports, 
the use of supercritical steam is the most cost effective option for 
new conventional coal-fired generation and results in the lowest 
overall costs. In addition, the increased efficiency results in reduced 
cooling water requirements and reduced environmental impacts associated 
with coal mining, delivery, and handling. Therefore, considering the 
benefits and minimal, if any, cost of using supercritical steam 
conditions, as opposed to subcritical steam conditions, we have 
concluded that an annual standard based on the best performing 
conventional coal-fired generation is appropriate.
    There are a dozen bituminous-fired and 2 subbituminous-fired EGUs 
that have demonstrated the proposed annual standard is achievable on a 
long term basis. Furthermore, we have concluded that with coal drying 
technology, which is being used on a number of power plants today, the 
annual standard is achievable by a wide range of units

[[Page 22420]]

firing a variety of coal types, including lignites. There are multiple 
vendors that offer processes to upgrade lignites to heating values that 
are equal to or greater than those of subbituminous coals. The best 
performing subbituminous-fired EGU has maintained a 12-month emissions 
rate of 1,730 lb CO<INF>2</INF>/MWh. A new EGU using a similar design 
would be able to burn upgraded lignite and be in compliance with the 
proposed annual standard.
    We solicit comment on all aspects of the alternative compliance 
option, including the 30-year averaging period we propose in this 
action. Although we are not proposing that CCS, including the 30-year 
averaging compliance option, does or does not qualify as the BSER 
adequately demonstrated, we also solicit comment on that issue.

B. How did the EPA determine the other requirements for the proposed 
standards?

1. Compliance Requirements
    The proposed compliance requirements, to the extent possible, 
incorporate monitoring already being performed as part of existing part 
60 and part 75 requirements.
    In addition, we intend to recognize the environmental benefit of 
electricity generated by CHP facilities to account for the increased 
end use efficiency resulting from avoided transmission and distribution 
losses. Actual line losses vary from location to location, but we 
intend to assume a benefit of 5 percent avoided transmission and 
distribution losses when determining the electric output for CHP 
facilities. This provision would be restricted to facilities where the 
useful thermal output is at least 20 percent of the total output.
    We also propose to base compliance requirements on a 12-month 
rolling average basis. The variability in GHG emissions rates is such 
that establishing a shorter averaging period would necessitate 
establishing a standard to account for the conditions that result in 
the lowest efficiency and therefore the highest GHG emissions rate. A 
12-month rolling average accounts for variable operating conditions, 
allows consistent emissions rate averaging, allows for a more 
protective standard and decreased compliance burden, and simplifies 
compliance for state permitting authorities. Because the 12-month 
rolling average can be calculated each month, this form of standard 
makes it possible to assess compliance and take any needed corrective 
action on a monthly basis. The EPA proposes that it is not necessary to 
have a shorter averaging period for CO<INF>2</INF> from these sources 
because the effect of GHGs on climate change depends on global 
atmospheric concentrations which are dependent on cumulative total 
emissions over time, rather than hourly or daily emissions fluctuations 
or local pollutant concentrations.
    Even so, we solicit comment on, in the alternative basing 
compliance requirements on an annual (calendar year) average basis.

V. Requirements for Modifications, Transitional Sources, 
Reconstructions

A. Requirements for Modifications

1. Overview
    Under CAA section 111, existing sources are treated as new sources 
if they undertake ``modification[s],'' which are generally defined as 
physical or operational changes that increase emissions. CAA section 
111(a)(2) and (4). The EPA's regulations exempt certain types of 
changes from the definition of modification. 40 CFR 60.14(e). Available 
information does not provide an adequate basis for the EPA to develop 
proposed standards of performance for modifications. 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.
    We note that the types of projects that these EGUs are most likely 
to undertake that could increase GHG emissions are projects that put on 
pollution controls required under other CAA provisions and that emit 
CO<INF>2</INF> as a byproduct, and those types of projects are 
specifically exempted from the definition of ``modifications'' under 40 
CFR 60.14(e)(5). In addition, based on past experience, we expect that 
actions that do constitute modifications to be from different types of 
sources and to take different forms. In light of this, the EPA does not 
have sufficient information to develop standards of performance for 
modifications, and therefore the EPA is not proposing any standards for 
modifications. As a result, EGUs that undertake pollution control 
projects or other physical or operational changes would continue to be 
treated as existing sources.
2. Statutory and Regulatory Requirements
    Clean Air Act section 111(b)(1)(B) requires the EPA to promulgate 
``standards of performance'' for ``new sources'' within source 
categories. For certain pollutants, CAA section 111(d)(1) requires the 
EPA to prescribe regulations for state plans covering ``existing 
source[s]'' in a category regulated for that pollutant under section 
111(b). Clean Air Act section 111(a)(2) defines a ``new source'' as 
``any stationary source, the construction or modification of which is 
commenced after the publication of regulations (or, if earlier, 
proposed regulations) prescribing a standard of performance under this 
section which will be applicable to such source.'' Clean Air Act 
section 111(a)(6) defines an ``existing source'' as ``any stationary 
source other than a new source.'' Clean Air Act section 111(a)(4) 
defines ``modification'' as ``any physical change in, or change in the 
method of operation of, a stationary source 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.''
    The EPA's regulations provide that under CAA section 111(a)(4), for 
purposes of determining whether an existing electric utility steam 
generating unit undertakes a modification, a physical or operational 
change is treated as increasing emissions only when it increases the 
``maximum hourly emissions'' above the ``maximum hourly emissions 
achievable'' at the unit. 40 CFR 60.14(h). In addition, the EPA's 
regulations exempt certain physical or operational changes from the 
definition of modification. 40 CFR 60.14(e)(5). The exemptions include 
pollution control projects:

    (e) The following shall not, by themselves, be considered 
modifications * * *:
* * * * *
    (5) The addition or use of any system or device whose primary 
function is the reduction of air pollutants, except when an emission 
control system is removed or is replaced by a system which the 
Administrator determines to be less environmentally beneficial.

40 CFR 60.14(e)(5). Thus, the EPA's current regulations define a 
modification as a physical or operational change that increases an 
existing affected EGU'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.
3. The EPA's Proposed Course of Action
    We expect EGUs to undertake changes in the foreseeable future that 
would increase their maximum achievable hourly rate of CO<INF>2</INF> 
emissions for

[[Page 22421]]

purposes of the NSPS. We expect that most of those actions 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 conventional air pollutants. We expect that 
these increases in CO<INF>2</INF> emissions would occur as a chemical 
byproduct of the operation of the control equipment, and would be 
small. In other cases, those projects will involve equipment changes to 
meet the requirements of this rulemaking and that may have the effect 
of increasing the sources' maximum hourly achievable emission rate, 
even while decreasing actual emission rate. Because such 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.
    Aside from pollution control projects, in the past, there have also 
been, as noted, a limited number of instances, on an annual basis, in 
which power plants have undertaken actions that should be treated as 
NSPS modifications. The sources that took these actions vary widely, 
one from another, depending on, among other things, size, fuel type, 
and physical plant configuration. The diversity of sources undertaking 
modifications has reflected the diversity among power plants as a 
whole. Moreover, the types of modifications they have undertaken have 
also varied widely.
    Because of the limited number of modifications, their disparate 
nature, and the disparate type of sources, we do not at present have an 
adequate base of information to propose standards of performance for 
modifications. For example, we do not have adequate information as to 
the types of physical or operational changes sources may undertake or 
the amount of increase in CO<INF>2</INF> emissions from those changes. 
Nor do we have adequate information as to the types of control actions 
sources could take to reduce emissions, including the types of controls 
that may be available or the cost or effectiveness of those controls. 
The most likely candidates for control actions would be efficiency 
measures and we do not have adequate information as to the types of 
sources and types of changes at issue that could provide the basis for 
a proposal for efficiency measures. If there were a more robust set of 
data on facilities of a particular type undertaking NSPS modifications 
of a particular kind, the EPA may be able to develop a standard of 
performance for that type. But, as noted, that is not the case here.
    As a result, in this action, the EPA is not proposing standards of 
performance for NSPS modifications for GHGs. The EPA is soliciting 
comment on the types of sources that may be expected to undertake 
modifications, the types of modifications, the types of control 
measures, and all other aspects of this issue. This solicitation of 
comment is in the nature of an advance notice of proposed rulemaking. 
If we receive sufficient additional information, we may issue a 
proposal for modifications in the future. However, to reiterate, we are 
not proposing any standards of performance for these modifications at 
this time. Accordingly, the EPA does not expect to promulgate any 
standards of performance for modifications when it takes final action 
on this rulemaking.
    The definitional provisions of CAA section 111, quoted above, make 
clear that a stationary source that undertakes construction or 
modification is considered a ``new source'' only if there is a proposed 
or final ``standard of performance under this section which will be 
applicable to such source.'' CAA section 111(a)(2). Accordingly, if 
there is no proposed or promulgated standard of performance applicable 
to a particular source, then the source cannot be considered a ``new 
source'' and therefore will not be subject to any standards of 
performance we finalize for new sources.
    Further, under the definitional provisions, any source that is not 
a ``new'' source is an ``existing source.'' CAA section 111(a)(6). 
Therefore, affected EGUs that undertake NSPS modifications for GHGs 
will continue to be treated as existing sources. Although modified 
sources would not be subject to the 1,000 lb CO<INF>2</INF>/MWh 
standard for new sources, the EPA anticipates that modified sources 
would become subject to the requirements the EPA would promulgate at 
the appropriate time, for existing sources under 111(d). It is 
important to note that at the same time that the EPA promulgated the 
pollution control provision in the EPA's regulations under CAA section 
111, the EPA promulgated a similar provision in EPA's NSR regulations. 
The DC Circuit, in New York v. EPA, 413 F.3d 3, 40 (DC Cir. 2005), 
vacated the NSR pollution-control-project exemption. Because of the 
similarities between the NSR and the section 111 pollution control 
project regulatory provisions, the Court's vacatur of the NSR 
regulatory provision may call into question the continued validity of 
the section 111 regulatory provision. As a result, we are soliciting 
comment on whether this exemption from the definition of 
``modification'' for pollution control projects, under 40 CFR 
60.14(e)(5), continues to be valid or not, and what course of action, 
if any, would be appropriate for the EPA to take.

B. Requirements for Transitional Sources

1. Overview
    In this action, the EPA is not proposing a standard of performance 
for transitional sources. We define these sources as coal-fired power 
plants that, by the date of this proposal, have received approval for 
their PSD preconstruction permits that meet CAA PSD requirements (or 
that have approved PSD permits that expired and are in the process of 
being extended, if those sources are participating in a Department of 
Energy CCS funding program), and that commence construction within a 
year of the date of this proposal. For convenience, we refer to the new 
sources for which we are proposing a standard of performance as non-
transitional sources.
    Transitional sources are a distinct set of sources with unique 
circumstances.\65\ We have identified 15 proposed sources that may 
qualify as transitional sources based on the above criteria. These 
proposed sources differ considerably one from another. They range in 
size from as small as 80 megawatts (MW) to as large as 1320 MWs; they 
will burn different fuels: Conventional coal, waste coal, or petcoke; 
and they will use different technologies: Circulating fluidized bed 
(CFB), integrated gasification combined cycle (IGCC), supercritical 
pulverized coal, or sub-critical pulverized coal. Recent industry 
practice raises the probability that no more than a few of these 15 
proposed sources will in fact be constructed.
---------------------------------------------------------------------------

    \65\ Nothing in this discussion of the unique circumstances of 
transitional sources facing new GHG requirements should be 
interpreted as providing a defense to any violation of the CAA by 
sources that, for example, fail to obtain PSD permits or comply with 
NSPS before construction.
---------------------------------------------------------------------------

    We recognize that by the date of this proposal, some of the 15 
proposed sources may have incurred substantial sunk costs and may have 
progressed in their preconstruction planning to the point where they 
are poised to commence construction in the very near future. Under 
these circumstances, the 1,000 lb CO<INF>2</INF>/MWh standard of 
performance that applies to non-transitional sources would not be 
appropriate for these proposed sources. As noted, that standard is 
based on natural gas combined cycle (NGCC) as the ``best system of 
emission reduction * * * adequately demonstrated'' because NGCC is the 
least expensive

[[Page 22422]]

and lowest emitting design for a fossil-fuel fired power plant, and 
because a proposed new source may choose to construct as an NGCC 
facility. However, proposed coal-fired power plants that have already 
received a PSD permit and that have incurred substantial sunk costs and 
developed plans to commence construction in the very near future are 
not in the same position as non-transitional sources. Applying the 
1,000 lb CO<INF>2</INF>/MWh standard would likely result in the loss of 
their sunk costs and would likely cause multi-year delays, or even 
abandonment, of their plans to construct. (Nor is the 1,000 lb 
CO<INF>2</INF>/MWh standard appropriate for CCS sources, as discussed 
below.) This is not within the scope of BSER.
    However, we do not have sufficient information concerning the 15 
proposed sources to identify which ones may be in this position. 
Specifically, we do not have information as to the extent of their sunk 
costs, their preconstruction planning, or their overall business plans.
    Accordingly, we propose to include a requirement that proposed 
sources must commence construction within 12 months of today's 
rulemaking proposal as a mechanism for revealing which of these sources 
qualifies as a transitional source. We believe that any of these 15 
proposed sources that commences construction within 12 months of 
today's rulemaking proposal should be considered to have incurred 
substantial sunk costs and will have engaged in sufficient 
preconstruction planning so that the 1,000 lb CO<INF>2</INF>/MWh 
standard should not apply. Any of these 15 proposed sources that do not 
commence construction within this period should not be considered to be 
similarly situated. For any of these latter sources that ultimately are 
constructed, the 1,000 lb CO<INF>2</INF>/MWh standard would apply.
    Having identified which proposed sources could qualify as 
transitional sources, we further believe that for several reasons, it 
is not appropriate to propose any standard of performance for those 
sources. As noted above, we necessarily lack information specifically 
as to which of the 15 proposed sources will actually qualify as 
transitional sources, and, given the range of size, fuel types, and 
technologies among these proposed sources, that renders it problematic 
to propose standards of performance. In addition, for the proposed 
sources that are planning to install CCS, we lack important information 
concerning the extent to which they are planning to capture 
CO<INF>2</INF> or their costs to do so. We also lack information as to 
whether they have made contractual arrangements for the sale of the 
CO<INF>2</INF> or carbon credits, which may be critical to their 
financing arrangements. In addition, attempting to propose a standard 
of performance would give rise to serious practical problems that would 
undermine the usefulness of the requirement that sources commence 
construction within 12 months of today's rulemaking proposal as a 
mechanism for revealing which of these sources qualifies as a 
transitional source. These include creating uncertainty as to the level 
of the final standard of performance to which the proposed sources 
would be subject, which may have the effect of forcing them to delay 
commencing construction until after we finalize the standards, at which 
time they would have missed their 12-month window to commence 
construction and as a result, would fail to qualify as transitional 
sources. We note that CAA section 111 does not require that we propose 
or promulgate standards of performance for all sources in a source 
category, and on numerous occasions in past rulemakings the EPA has 
taken the similar approach of not proposing standards of performance 
for all sources in the source category.
    Even without an applicable standard of performance, transitional 
sources will remain constrained in their emissions of CO<INF>2</INF> by 
the requirements of their PSD permits. In addition, although 
transitional sources would not be subject to the 1,000 lb 
CO<INF>2</INF>/MWh standard for new sources, the EPA anticipates that 
transitional sources would become subject to the requirements the EPA 
would promulgate at the appropriate time, for existing sources under 
111(d).
2. Identification of Transitional Sources
    For purposes of this action, we define a transitional source as a 
coal-fired power plant that has received approval for its complete PSD 
preconstruction permit by the date of this proposal (or that has an 
approved PSD permit that expired and for which the source is seeking an 
extension, if the source has been issued or awarded a DOE CCS loan 
guarantee or grant) for the project, and that commences construction 
within 12 months of the date of this proposal. For this purpose, the 
date of this proposal is the date of publication in the Federal 
Register of this notice of proposed rulemaking. The 12-month period 
would not be extended for any reason, including because of any 
challenges to the permit that may be brought in any Federal or State 
court or agency.
    The EPA is aware of approximately 15 sources that could potentially 
qualify as transitional sources because, except as otherwise noted, 
they have obtained PSD permits but have not yet commenced construction. 
These proposed sources vary considerably one from another. They range 
in size from as small as 80 megawatts (MW) to as large as 1320 MWs; 
they will burn different fuels: conventional coal, waste coal, or 
petcoke; and they will use different technologies: Circulating 
fluidized bed (CFB), integrated gasification combined cycle (IGCC), 
supercritical pulverized coal, or sub-critical pulverized coal.
    Based on recent industry practice, it appears that no more than a 
few of these sources will be constructed.\66\
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    \66\ Since 2008, some 15 proposed coal-fired power plants with 
approved PSD permits have cancelled plans to construct, and since 
2009, only one coal-fired power plant has constructed (Southern 
Company's Kemper County Project, which installed CCS and received 
DOE funding).
---------------------------------------------------------------------------

    Of these 15 identified potential transitional sources, six have 
indicated that they plan to install CCS (and in most if not all cases 
have been issued or awarded a DOE CCS loan guarantee or grant). These 
six projects are: The Texas Clean Energy Project in Texas, the 
Trailblazer project in Texas, the Taylorville project in Illinois, the 
Good Spring facility in Pennsylvania, the Power County Advanced Energy 
Center in Idaho and the Cash Creek Generation Plant in Kentucky. The 
remaining nine plants, which are without CCS, are: Limestone 3, White 
Stallion and Coletto Creek in Texas, Holcomb 2 in Kansas, James De 
Young and Wolverine in Michigan, Washington County in Georgia, Bonanza 
in Utah, and Two Elk in Wyoming.\67\
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    \67\ We note that there may be some proposed natural gas-fired 
EGUs that are similarly situated to the coal-fired transitional 
sources because the natural-gas fired sources have received PSD 
permits but have not commenced construction by the date of this 
proposal. Because they are new gas-fired EGUs, we expect that they 
will be able to meet the requirements of the proposed new source 
standard of performance.
---------------------------------------------------------------------------

    We request that during the public comment period on this 
rulemaking, each of these EGUs confirm to us that we have correctly 
identified the status of their PSD permits and, in the case of any 
sources that had approved permits that are in the process of being 
extended, and that plan to install CCS, that they have been issued or 
awarded a DOE CCS loan guarantee or grant. We also request that the 
sources indicate whether their permits are undergoing challenges before 
Federal or state authorities or courts. We further request that any 
other EGU not listed above that has a complete PSD permit and that 
otherwise meets the parameters for transitional sources described in 
this

[[Page 22423]]

section identify itself to us (including indicating whether its PSD 
permit is undergoing challenge before Federal or state authorities or 
courts). In our final rulemaking, we intend to include a confirmed list 
of sources that would qualify as transitional sources if they commence 
construction within the 12-month period following publication of this 
proposal in the Federal Register.
    As commenters have noted, among these 15 proposed sources, some may 
have incurred substantial sunk costs associated with processing their 
permits as well as taking additional preconstruction steps (e.g., 
purchasing land) so that they may be able to commence construction 
within the near term. As examples of these types of steps, several 
sources, such as the Texas Clean Energy Project, have signed contracts 
for the sale of electricity, the sale or disposal of CO<INF>2</INF> or 
other enabling products, or supporting systems.\68\ Although the 
Taylorville project's PSD permit has expired, the source is seeking to 
extend it, and the source has entered into CCS funding arrangements 
with DOE. These actions indicate that this proposed source, too, has 
sunk costs and may be in a position to commence construction within the 
near term, and therefore is similarly situated to the other 14 proposed 
plants (assuming that it is able to secure an extension of its PSD 
permit).
---------------------------------------------------------------------------

    \68\ http://www.texascleanenergyproject.com/news-room/.
---------------------------------------------------------------------------

    Even so, we face major gaps in our information about these sources 
that would inform us at this point as to which of these sources have 
incurred costs and material commitments to the extent that a 1,000 lb 
CO<INF>2</INF>/MWh standard would be so costly and disruptive as not to 
be BSER. For example, we do not have specific information as to those 
sources' specific sunk costs, specific project development actions to 
date, or overall business plan. Accordingly, we are not able to 
determine which ones are in a position to commence construction in the 
near term. In addition, for the sources whose PSD permit indicates that 
they will install CCS, we do not have specific information as to the 
amount of CO<INF>2</INF> that they plan to capture; their costs to 
operate CCS; or their possible revenue streams associated with CCS, 
such as from the sale or use of CO<INF>2</INF> in enhanced oil recovery 
or the possible sale of carbon credits in voluntary or other carbon 
markets.
    Instead, the 12-month period, serving as a surrogate for the 
missing information, provides a mechanism for revealing the 
qualification of proposed sources for treatment as transitional 
sources. In light of the complex of requirements, which range from 
siting to financing, needed to commence construction of a project as 
large and expensive as a power plant, any proposed source that does 
commence construction within the relatively short period of 12 months 
of the date of proposal can be said to have incurred substantial sunk 
costs and to have taken preconstruction steps by the time of this 
proposal. It is these sources that would be most disadvantaged by being 
subjected to the standards of performance proposed in today's 
rulemaking. The one-year period serves as a type of surrogate for more 
precise information as to the amount of sunk costs sources must incur 
or steps leading to commencement of construction that sources must 
undertake in order to qualify as transitional sources, as well as which 
sources have incurred those costs or taken those steps, which 
information is not available at this time. In addition, 12 months is 
long enough to give these sources a reasonable period to commence 
construction in accordance with the terms of their permit. Any proposed 
source that does not commence construction within 12 months cannot be 
said to be similarly situated.
3. The EPA's Treatment of Transitional Sources
    In this action, the EPA is treating transitional sources as a 
distinct set of sources. We make clear that the proposed standard of 
performance for non-transitional sources of 1,000 lb CO<INF>2</INF>/MWh 
is not applicable to transitional sources because that standard is not 
based on the BSER adequately demonstrated for transitional sources. In 
addition, in light of the unique circumstances of transitional sources, 
including a lack of information and other considerations, we do not 
propose any other standard of performance for transitional sources.\69\
---------------------------------------------------------------------------

    \69\ EPA intends that its treatment of transitional and non-
transitional sources be severable from each other and considers that 
severability is logical because of the record-based differences 
between the two types of sources and because there is no 
interdependency in EPA's treatment of the two types of sources. This 
statement concerning severability for these components in this 
rulemaking should not be construed to have implications for whether 
other components in this rulemaking are severable.
---------------------------------------------------------------------------

    Although a transitional source would not be subject to new source 
CO<INF>2</INF> emissions controls under CAA section 111(b), it would be 
subject to CO<INF>2</INF> emissions limits due to any CO<INF>2</INF> 
limits in the source's PSD permit. If the source received the permit 
prior to January 2, 2011, the permit will not include CO<INF>2</INF> 
limits, but in that case, as a practical matter, CO<INF>2</INF> 
emissions would be limited by whatever design or operating constraints 
are imposed on the source under the PSD permit.
    We also note that the fact that transitional sources would not be 
subject to the proposed standard of performance, would not relieve them 
from any requirements applicable to existing sources under section 
111(d) and related state plans.
4. Legal Basis for the EPA's Treatment of Transitional Sources
    In this section, we describe the legal basis for our treatment of 
transitional sources. First, we identify the relevant CAA section 111 
provisions. Second, we explain why the standard of performance we 
propose for non-transitional sources does not apply to transitional 
sources, which is because that standard does not reflect the best 
system of emission reduction adequately demonstrated for transitional 
sources. Third, we explain why we are not proposing any other standard 
of performance for transitional sources, which is due to lack of 
information and other considerations. In the course of these 
explanations, we discuss the relevant CAA section 111 requirements and 
our interpretations of them.
a. Key CAA Section 111 Provisions
    As the first step in the process of promulgating regulations under 
section 111, under CAA section 111(b)(1)(A), the Administrator must 
``publish * * * a list of categories of stationary sources.'' Then, the 
Administrator must ``[propose] * * * Federal standards of performance 
for new sources within [the source] category,'' and then ``promulgate * 
* * such standards with such modifications as he deems appropriate.'' 
Section 111(b)(1)(B). Section 111(b)(2) goes on to provide that ``[t]he 
Administrator may distinguish among classes, types, and sizes within 
categories of new sources for the purpose of establishing such 
standards.''
    Section 111 includes several key definitions. The provision defines 
a ``new source'' as ``any stationary source, the construction or 
modification of which is commenced after the publication of regulations 
(or, if earlier, proposed regulations) prescribing a standard of 
performance under this section which will be applicable to such 
source.'' CAA section 111(a)(2).\70\ A

[[Page 22424]]

``standard of performance'' is defined as a--
---------------------------------------------------------------------------

    \70\ The CAA does not include a definition of the term 
``commenced'' for these purposes, but the EPA framework regulations 
promulgated under section 111 define this term as follows:
    Commenced means, with respect to the definition of new source in 
section 111(a)(2) of the Act, that an owner or operator has 
undertaken a continuous program of construction or modification or 
that an owner or operator has entered into a contractual obligation 
to undertake and complete, within a reasonable time, a continuous 
program of construction or modification.
    40 CFR 60.2.

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.

CAA section 111(a)(2).

    Once the Administrator promulgates standards for new sources under 
CAA section 111(b), the States, consistent with EPA regulatory 
requirements, must take action under CAA section 111(d) to establish 
requirements for ``any existing source for any air pollutant (i) [that 
falls into specified categories] but (ii) to which a standard of 
performance under this section would apply if such existing source were 
a new source. * * *'' Section 111(d)(1). An ``existing source'' is 
defined as ``any stationary source other than a new source.'' Section 
111(a)(6).
b. Reasons for Not Applying the 1,000 lb CO<INF>2</INF>/MWh Standard of 
Performance to Transitional Sources
(i) Introduction
    In this action, the EPA is treating transitional sources as a 
distinct set of sources, although the EPA is not establishing a 
specific subcategory for these sources in the regulatory 
provisions.\71\ Under CAA section 111, the EPA may not apply a standard 
of performance to sources unless it reflects the ``best system of 
emission reduction'' (BSER) adequately demonstrated.
---------------------------------------------------------------------------

    \71\ Section 111(b)(2) authorizes the EPA to ``distinguish among 
classes, types, and sizes within categories of new sources for the 
purpose of establishing such standards.'' In other words, once the 
EPA selects the set of sources for which to propose regulations, the 
EPA may establish subcategories among those new sources and 
promulgate different standards for those subcategories.
---------------------------------------------------------------------------

    As noted, the EPA proposes that non-transitional source fossil-
fired power plants that commence construction after the date of 
proposal are subject to the standard of 1,000 lb CO<INF>2</INF>/MWh, 
and the EPA proposes to base this standard on the EPA's identification 
of natural gas combined cycle (NGCC) as the BSER adequately 
demonstrated. The EPA justifies this proposal because owners or 
operators contemplating construction of non-transitional power plants 
to serve baseload and intermediate load demand have choices: They can 
choose the type of facility and therefore may choose to construct a 
NGCC plant. As a result, for these sources, NGCC constitutes the BSER, 
and the 1,000 lb CO<INF>2</INF>/MWh emission limit reflects that BSER 
and therefore is the appropriate standard of performance under section 
111. Moreover, for those that choose to construct a coal-fired unit, 
they may choose to construct the plant in a place and a manner that 
allows installation of CCS--and thereby meet the 1,000 lb 
CO<INF>2</INF>/MWh standard--either at the time of construction or, in 
accordance with the 30-year averaging proposal, some years later.
(ii) Transitional Sources and NGCC
    In contrast, the circumstances surrounding transitional sources are 
quite different. Transitional sources are a very small group of sources 
with a distinct profile of costs, preconstruction planning, overall 
business plans, technical and design concerns, and equitable concerns. 
Because they are such large facilities, their sunk costs and planning 
horizons are substantial.
    Transitional sources have already incurred substantial costs in 
permitting and taking other steps preparatory to commencing 
construction as coal-fired power plants within 12 months of the date of 
this proposal, which may include purchasing land for the new facility. 
Considering these sunk costs, converting their plant design to NGCC 
would be significantly more expensive than for proposed non-
transitional sources that have not reached the stage of development 
that transitional sources have reached. The EPA is required to consider 
costs in determining the BSER adequately demonstrated, and under these 
circumstances, the costs factor points away from treating NGCC as BSER 
for transitional sources.
    In addition, because transitional sources have obtained a PSD 
permit and have developed their plans to the point where they are on 
the verge of commencing construction, the converting of their plant 
design to NGCC would be significantly more disruptive to their plans 
than for proposed non-transitional sources. It may require them to 
start over the process of developing the plant, and thereby render 
futile the planning and steps they have taken to date. These losses 
would, at a minimum, lead to delays in their commencing construction 
that realistically would be measured in years, and in fact may lead 
them to abandon the project.
    Although the potentially significant planning impacts at issue here 
are not explicitly identified as part of the definition of the 
``standard of performance,'' they should nevertheless be considered in 
determining the BSER. This is because CAA section 111(a)(2), in its 
definition of ``new source,'' clearly contemplates that sources are 
expected to be able to commence construction after the EPA proposes, 
and before the EPA promulgates, a standard of performance applicable to 
them. There is nothing in CAA section 111 that suggests that Congress 
expected that the EPA may determine the BSER in a way that would 
significantly disrupt the plans of the regulated sources that are 
implicated here. Therefore, for this reason, too, the 1,000 lb 
CO<INF>2</INF>/MWh standard cannot be considered to reflect the BSER 
for transitional sources, and therefore cannot be the appropriate 
standard of performance.
    Nor can transitional sources reasonably be expected to meet the 
1,000 lb CO<INF>2</INF>/MWh standard through the installation of CCS, 
for the reasons discussed below.
    Note that the EPA takes the position that in this particular 
action, both of those factors--sunk costs and extent of planning to 
commence construction--must be considered in determining whether the 
1,000 lb CO<INF>2</INF>/MWh standard reflects the BSER adequately 
demonstrated. That is, both are necessary conditions, and neither one, 
by itself, is a sufficient condition. We believe that these reasons 
concerning costs and planning suffice to justify our position that the 
1,000 lb CO<INF>2</INF>/MWh standard is not appropriate for 
transitional sources.
(iii) Coal-Fired Transitional Sources Not Designed for CCS
    As noted, while it is generally the case that proposed new sources 
could choose to build coal-fired power plants with CCS and thereby meet 
the 1,000 lb CO<INF>2</INF>/MWh standard, that is not the case for 
those transitional sources that are not designed for CCS. As a 
practical matter, it would be challenging for such a source to proceed 
with construction without substantial re-design of the project in order 
to install CCS and thereby be in compliance with the 1,000 lb 
CO<INF>2</INF>/MwH standard. There are several reasons for this. First, 
captured CO<INF>2</INF> must be sequestered or used. If this was not 
considered as part of the original site selection, the source will 
likely be significantly challenged in its efforts to adopt CCS. Second, 
if CCS was not considered in the original project

[[Page 22425]]

design, space considerations may make it difficult to now accommodate 
it in the facility's design. Third, the requirement to use CCS could 
necessitate a change in the very power generation technology that a 
source may choose to use. For instance, instead of building a 
pulverized coal boiler, IGCC technology may be more appropriate. This 
is not to say that CCS could not be added to a project at this stage. 
Projects like the AEP Mountaineer project have shown that CCS can be 
successfully retrofitted into an existing plant. However, unlike in an 
existing facility where retrofit decisions must take into account 
previously made design decisions, in a facility in the pre-design 
phase, there is more opportunity for cost savings from re-designing the 
project, rather than having to adapt through retrofit.
    It bears emphasis that the requirements created by the new source 
standard in today's action are fundamentally different from post-
combustion controls required to meet new source standards for 
conventional pollutants in the sense that those controls could be much 
more easily re-designed into an already planned plant without changing 
the plant's basic underlying characteristics (such as type of unit or 
even location). In contrast, CCS is more fundamental to both the design 
and siting of a unit, and therefore would likely involve fundamental 
changes to the underlying project. This is much more difficult in a 
project that has progressed through the permitting stage and is very 
close to commencing construction than it would be in other types of 
projects.
(iv) Coal-Fired Transitional Sources Designed for CCS
    Although some of the proposed sources that may qualify as 
transitional sources are planning for CCS, that does not provide a 
basis for concluding that the 1,000 lb CO<INF>2</INF>/MWh standard is 
appropriate for them. As noted, the EPA is not, in this rulemaking, 
proposing that CCS is the BSER adequately demonstrated for coal-fired 
EGUs.
    Moreover, these proposed sources have established their location 
and developed their business plans without the expectation that the 
proposal in this rulemaking for CCS would apply to them. For example, 
their plans may assume installing CCS in a manner that results in 
emissions at levels higher than 1,000 lb CO<INF>2</INF>/MWh, or it may 
assume the sale of emission reduction credits based on an allowable 
emission rate above 1,000 lb CO<INF>2</INF>/MWh. Imposition of an 
unexpected emission rate requirement at such a late date could upset 
carefully crafted financial plans, causing delay or even cancellation 
of the project.
    Importantly, we do not have information as to key components of 
their proposed project and business plan, including, among other 
things, the amount of capture from the planned CCS system or possible 
revenue streams associated with CCS. Any proposal for what is BSER 
would depend on those costs and other information. Accordingly, we are 
not able to propose determinations that are essential to proposing the 
BSER for these proposed sources. As a result, we are not able to 
propose a standard of performance for these proposed sources.
(v) Equitable Considerations
    For all transitional sources, the costs and delays discussed above 
give rise to equitable considerations that also support our treatment 
of these proposed sources. As noted, owners or operators of 
transitional sources have incurred significant expenses and undertaken 
a long planning period that has led them to being able to commence 
construction in the very near future, and, having invested so 
substantially in their current plans, should as an equitable matter be 
allowed to proceed without concern about requirements other than those 
in their PSD permits. To reiterate, they are in a posture that is 
fundamentally different from non-transitional sources.
c. Reasons for Not Applying Other Standard of Performance
    Although, for the reasons described above, the 1,000 lb 
CO<INF>2</INF>/MWh standard that the EPA proposes for non-transitional 
sources does not reflect BSER for transitional sources, the EPA is not 
proposing any other standard of performance for transitional sources. 
It is reasonable to read section 111 not to require the EPA to propose 
a standard of performance when faced with the specific circumstances 
presented by transitional sources in the context of this rulemaking. 
These circumstances include: (1) The EPA's lack of information with 
regard to these sources and the appropriate BSER for these sources; (2) 
the unique challenges with regard to adaptation of proposed projects to 
the requirements of this standard; (3) the small number of these 
sources and the possibility that promulgating a standard of performance 
would not have a beneficial environmental impact; and (4) although 
transitional sources would not be subject to the 1,000 lb 
CO<INF>2</INF>/MWh standard for new sources, the EPA anticipates that 
transitional sources would become subject to the requirements the EPA 
would promulgate at the appropriate time, for existing sources under 
111(d).
(i) CAA Requirements for Promulgating Standards of Performance for 
Sources in a Source Category
    The EPA interprets the CAA provisions described above to authorize 
the EPA not to promulgate a standard of performance for transitional 
sources. Under section 111(b)(1)(B), once the EPA lists a category of 
sources, the EPA is required to propose and promulgate standards of 
performance for new sources in that category. The EPA is not, however, 
required to promulgate standards of performance that cover all new 
sources . This is clear from the directive in section 111(b)(1)(B), 
which requires that the EPA propose standards of performance ``for new 
sources'' within the category, but does not require that the EPA 
propose such standards for all new sources or for any new source. The 
EPA may fulfill that directive by proposing standards that cover some, 
but not all, sources that newly commence construction or modification.
    Similarly, the term ``new source'' in section 111(a)(2) is defined 
to incorporate the limitation that the EPA must propose or promulgate a 
standard applicable to the source for the source to be considered 
``new.'' That is, section 111(a)(2) defines a ``new source'' as any 
source for which construction or modification commences after the EPA 
proposes ``a standard of performance * * * which will be applicable to 
such source.'' By its terms, this provision contemplates that the EPA 
may not propose a standard of performance applicable to certain 
sources, and that if the EPA does not, those sources would not be 
considered to be ``new source[s]'' and therefore not subject to any new 
source standard of performance.
    Thus, these provisions do not, by their terms, mandate that the EPA 
propose standards for each and every source in the source category. 
Under Chevron step 1, these provisions do not unambiguously require 
that the EPA propose standards of performance for all sources in the 
source category. We read these provisions as according the EPA some 
measure of discretion for the EPA to determine not to set standards for 
a particular portion of the source category, where appropriate, bounded 
by the principle of rationality. If these provisions are read to be 
ambiguous as to whether the EPA has discretion to propose and 
promulgate standards of performance for all sources in the source 
category, we believe it reasonable to read the provisions to provide 
such discretion in appropriate circumstances and that such reading is 
entitled to

[[Page 22426]]

deference under Chevron step 2. In addition, interpreting these 
provisions to give the EPA the discretion not to propose and promulgate 
standards covering all sources in a category under appropriate 
circumstances--such as those present here--is consistent with the 
caselaw that authorizes agencies to establish a regulatory framework in 
an incremental fashion, that is, a step at a time.\72\
---------------------------------------------------------------------------

    \72\ As the U.S. Supreme Court recently stated in Massachusetts 
v. EPA, 549 U.S. 497, 524 (2007): ``Agencies, like legislatures, do 
not generally resolve massive problems in one fell regulatory 
swoop;'' and instead they may permissibly implement such regulatory 
programs over time, ``refining their preferred approach as 
circumstances change and as they develop a more nuanced 
understanding of how best to proceed.'' See Grand Canyon Air Tour 
Coalition v. F.A.A., 154 F.3d 455 (DC Cir. 1998), City of Las Vegas 
v. Lujan, 891 F.2d 927, 935 (DC Cir. 1989), National Association of 
Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (DC Cir. 1984).
---------------------------------------------------------------------------

(ii) Precedents in Prior NSPS Rulemakings
    In applying section 111 over the past several decades, there have 
been a number of rulemakings in which the EPA has promulgated new 
source performance standards that do not cover all sources within the 
relevant source category that newly commence construction or 
modification. Some examples include the following: (i) In an early 
NSPS, involving lime kilns, the EPA promulgated an NSPS for certain 
types of kilns, but not for all types of sources that remained within 
the relevant source category. The DC Circuit, in its opinion reviewing 
the rule, noted this state of affairs, without expressing concerns. 
National Lime Ass'n v. EPA, 627 F.2d 416, 426 & n. 28 (DC Cir. 1980) 
(noting that ``of the various types of kilns that may be used in the 
calcinations of limestone, only rotary kilns are regulated by the 
standards,'' and not ``the vertical kiln; the rotary hearth kiln; and 
the fluidized bed kiln''). (ii) In the EPA's initial promulgation of 
NSPS regulations for petroleum refineries, the EPA did not promulgate 
standards of performance for certain units, including fluid coking 
units, delayed coking units, and process heaters, instead promulgating 
standards of performance for those units subsequently. See 40 CFR 
60.100a(a); ``Standards of Performance for Petroleum Refineries: 
Proposed Rules,'' 72 FR 27178 (May 14, 2007). (iii) Similarly, in the 
EPA's recent revision of the NSPS regulations for coal preparation and 
processing plants, the EPA ``expand[ed] applicability of the existing 
NSPS by revising the definitions of thermal dryers, pneumatic coal-
cleaning equipment, and coal. It also establishe[d] work practice 
standards for open storage piles. The final rule amend[ed] the 
definition of thermal dryer for units constructed, reconstructed, or 
modified after May 27, 2009, to include both direct and indirect dryers 
drying all coal ranks (i.e., bituminous, subbituminous, lignite, and 
anthracite coals) and coal refuse.'' ``Standards of Performance for 
Coal Preparation and Processing Plants,'' 74 FR 51950, 51952 (Oct. 8, 
2009). (iv) In subpart KKKK of the NSPS regulations, the EPA 
promulgated regulations for the source category of stationary 
combustion turbines. The EPA did not promulgate regulations for 
turbines with smaller than 10 MMBtu/hr heat input, emergency units, or 
combustion turbine test cells. 40 CFR 60.4305(a), 60.4310(a), (d). (v) 
For other source categories, the EPA also declined to propose and 
promulgate standards of performance for the smaller sources. For 
example, for the source category of metal furniture coating operations, 
the EPA did not apply standards of performance to metal furniture 
surface coating operations that use less than 3.842 liters of coating 
(as applied) per year. 40 CFR 60.310(b). (vi) In proposing standards of 
performance for natural gas processing plants, the EPA proposed 
standards for only two of the three emission points in the plants 
(``storage emission sources'' and ``equipment leaks'') and declined to 
propose standards for the third emission point (``process emission 
sources'') on grounds that ``[b]est demonstrated control technology has 
not been identified for [the latter] sources.'' ``Standards of 
Performance for New Stationary Sources; Onshore Natural Gas Processing 
Plants in the Natural Gas Production Industry, Equipment Leaks of 
VOC,'' 49 FR 2636, 2637 (January 20, 1984).
(iii) Lack of Basis for Specifying Information
    A major reason why the EPA is not proposing a standard of 
performance for transitional sources is that it is relying, in part, on 
the one-year commence-construction limit to qualify a source as 
transitional: The EPA does not have sufficient information about the 
proposed sources' sunk costs and preconstruction steps to be able to 
identify which of these proposed sources may qualify as transitional 
sources. In addition, even if the EPA could determine that a particular 
proposed source would in fact become a transitional source, the EPA 
lacks information that, under these circumstances, may be important for 
determining BSER. For example, the EPA lacks information as to the 
amount of the proposed source's sunk costs, which may be relevant in 
determining BSER for these proposed sources. In addition, for proposed 
CCS sources, as noted above, the EPA does not have information as to 
key components of their proposed project and business plan, including, 
among other things, the amount of capture from the planned CCS system 
or possible revenue streams associated with CCS.
    Moreover, because transitional sources are defined by reference to 
the fact that they will commence construction within 12 months of the 
date of this proposal, it would be futile for the EPA to attempt to 
develop that information and then issue a proposal. By the time the EPA 
could do this, which would likely take at least a year, this set of 
sources will have become a null set: They either will have commenced 
construction, such that they would no longer be deemed ``new sources'' 
for purposes of CAA section 111, or they will not have commenced 
construction, such that they would be subject to the new source 
standard for non-transitional sources we are proposing today.\73\
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    \73\ Note that because the basic rationale for EPA's treatment 
of transitional sources is that they have already incurred 
substantial sunk costs and have positioned themselves to be close to 
commencing construction, and the one-year period for commencing 
construction is a surrogate for that, this treatment of transitional 
sources cannot logically be stretched to cover sources that do not 
commence within a substantially longer period. There is no reason to 
believe those latter sources would have, by the time of the proposal 
for the rest of the source category, already incurred significant 
costs and moved close to commencing construction.
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(iv) Practical Problems
    In addition, the EPA's lack of information and other considerations 
give rise to several serious practical problems that would arise were 
the EPA to propose a standard of performance for transitional sources. 
Importantly, were the EPA to propose a standard of performance, all 
transitional sources would face substantial uncertainty as to what 
final standard the EPA would promulgate. This uncertainty would arise 
for several reasons. As noted, the EPA lacks information concerning 
transitional sources. In addition, transitional sources differ one from 
another in terms of design and in other respects, which would render 
the EPA's task more complex. As a result, there is risk that the EPA 
might finalize standards of performance different from what the EPA 
proposed. The final standards of performance may be more difficult for 
a given transitional source to meet.

[[Page 22427]]

    Other forms of uncertainty may arise as well. For example, a 
possible standard of performance that the EPA would consider would be 
based on identifying the BSER for transitional sources as the controls 
to which they would be subject under the terms of their PSD permits, 
with no further controls under section 111.\74\ With this approach, the 
EPA would need to determine the emission rate for each source that 
would reflect that source's level of CO<INF>2</INF> emissions in accord 
with the terms of its PSD permit. This emission rate would constitute 
the ``no-further-control'' standard of performance. Note that under 
such an approach, each source would receive an emission limit unique to 
that source. However, some of the transitional sources may have a PSD 
permit that does not regulate CO<INF>2</INF> because GHGs were not 
subject to PSD until the January 2, 2011 effective date of the first 
regulatory action controlling CO<INF>2</INF> emissions under the CAA. 
Particularly for those sources, this approach could create uncertainty 
as to what the EPA would promulgate as the emission rate in the final 
standard of performance. This is because since these sources' permits 
do not specify a CO<INF>2</INF> limit, the EPA would have to develop 
limits based on the design of the unit (including the project's type of 
technology and fuels).
---------------------------------------------------------------------------

    \74\ This type of standard of performance could take one of 
several different forms, such as a standard that would not limit the 
source's CO<INF>2</INF> emissions, or a standard that the 
transitional source itself would identify as equaling the emission 
limit it would achieve through compliance with the applicable terms 
of its permit.
---------------------------------------------------------------------------

    The uncertainties that the sources could experience as to what the 
final standards of performance would entail could well deter those 
sources from commencing construction until the EPA promulgated the 
final standard of performance. Such delay would undermine the 
usefulness of the requirement that sources commence construction within 
12 months of today's rulemaking proposal as a mechanism for revealing 
which of these sources qualifies as a transitional source, and thus 
defeat the policy underlying the EPA's approach to transitional 
sources, which, for the reasons explained above, is to exclude from 
coverage by this new source standard only those sources that commence 
construction within 12 months of proposal. If sources are deterred from 
commencing construction until after the final rule, they will have lost 
the benefit of the 12-month window. As another practical problem, we 
also note concern with attempting to promulgate standards of 
performance for transitional sources at a time when it may reasonably 
be expected that some of the 15 sources with PSD permits may well not 
commence construction within 12 months (or may never do so). As a 
result, the effort to develop a standard of performance for those 
sources would have been unnecessary.
(v) Small Number of Transitional Sources, Lack of Environmental Benefit
    As part of our reasoning for not proposing a standard of 
performance for transitional sources, we also take into consideration 
the fact that we expect the number of transitional sources to be small, 
no more than a few of the 15 potential sources listed above. Further, 
if we were to propose a ``no further control'' standard of performance, 
as described above, that approach would provide little, if any, 
environmental benefit because that standard would not likely provide 
further control beyond the limits of the sources' PSD permits. In fact, 
treating transitional sources as existing sources may achieve more 
reductions than a no-further-control NSPS standard for those sources by 
including them under the flexible existing source standard that the EPA 
expects to promulgate.
(vi) Other Considerations
    The EPA's approach of not proposing a standard of performance for 
transitional sources does not leave these sources uncontrolled. Rather, 
they would remain subject to whatever CO<INF>2</INF> emission limits 
are included in, or result from compliance with, their PSD permits. 
And, although transitional sources would not be subject to the 1,000 lb 
CO<INF>2</INF>/MWh for new sources, the EPA anticipates that 
transitional sources would become subject to the requirements the EPA 
would promulgate at the appropriate time for existing sources under 
111(d).
    In notable contrast, in the previous rulemakings cited above in 
which the EPA did not propose coverage of all sources within the 
relevant source category, because of the pollutants at issue in these 
actions, the decision not to propose coverage of all sources within the 
relevant source category operated without the assurance afforded by 
section 111(d) that uncovered sources would necessarily be picked up as 
existing sources subject to existing source guidelines. Where, as here, 
that assurance mechanism applies, the recognition and application of 
the Agency's discretion to not propose coverage of all sources in the 
source category is all the more appropriate.
    We recognize that this approach of not proposing a standard of 
performance for transitional sources could raise the question of 
consistency with the requirement implicit in the definition of ``new 
source'' under CAA section 111(a)(2) that a source be subject to a 
standard of performance when it commences construction after the date 
of proposal for that standard. We believe the approach is consistent 
with, and does not circumvent, that requirement. As noted, CAA section 
111 does not require that all sources that newly commence construction 
be treated as new sources, and in past section 111 rulemakings, the EPA 
has not applied the standards of performance that it proposes and 
promulgates to all sources that newly commence construction in a source 
category. In addition to the reasons for not promulgating a standard 
for transitional sources provided above, where, as here, the pollutants 
covered by the proposed new source standard give rise to an obligation 
to develop section 111(d) guidelines for existing sources with the 
source category, ultimate coverage of the sources in question is 
inevitable, eliminating any prospect of a regulatory gap of any 
material concern.

C. Requirements for Reconstructions

1. Overview
    The EPA's framework regulations under CAA section 111 provide that 
reconstructed sources --which, in general, are existing sources that 
conduct extensive replacement of components--are to be treated as new 
sources and, therefore, subject to new source standards of performance. 
In today's rulemaking, we do not propose any standard of performance 
for reconstructed sources, and we take comment how to approach 
reconstructions. We note that if we do not establish a new standard of 
performance for reconstructions, as a practical matter, that would mean 
that reconstructed sources would be treated as existing sources.
2. Background
    a. The EPA Regulations. The EPA's framework regulations, 
interpreting the definition of ``new source'' in CAA section 
111(a)(2),\75\ provide that an existing source, ``upon 
reconstruction,'' becomes subject to the standard of performance for 
new sources. 40 CFR 60.15(a). The regulations define ``reconstruction'' 
as--

    \75\ CAA section 111 does not explicitly include provisions for 
reconstructed sources.

[T]he replacement of components of an existing facility to such an 
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extent that:


[[Page 22428]]


    (1) The fixed capital cost of the new components exceeds 50 
percent of the fixed capital cost that would be required to 
construct a comparable entirely new facility, and
    (2) It is technologically and economically feasible to meet the 
applicable standards set forth in this part.

40 CFR 60.15(b). Thus, a reconstruction occurs if the existing source 
replaces components to such an extent that the capital costs of the new 
components exceed 50 percent of the capital costs of an entirely new 
facility, even if the existing source does not increase emissions. In 
addition, the component replacement constitutes a reconstruction only 
if it is technologically and economically feasible for the source to 
meet the applicable standards.
    The regulations go on to require the owner or operator of an 
existing source that proposes to replace components to an extent that 
exceeds the 50 percent level, to notify the EPA and to provide 
specified information, including ``a discussion of any economic or 
technical limitations the facility may have in complying with the 
applicable standards of performance after the proposed replacements.'' 
In addition, the regulations require the EPA to determine, within a 
specified time period, whether the proposed replacement constitutes a 
reconstruction. 40 CFR 60.15(d)-(e).
    b. Reconstructions. As with 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. The EPA is not aware that any power plants are 
presently planning any project that could meet the requirements for a 
reconstruction.
2. Options
    In this action, the EPA is not issuing a proposal for affected 
sources that undertake reconstructions. Our reasoning is much the same 
as with NSPS modifications, which is that the lack of 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, precludes proposing a standard of 
performance. Instead of issuing a proposal, the EPA solicits comment on 
all issues related to reconstructions, including the aspects just 
noted. Depending on the information the EPA acquires about 
reconstructions, the EPA may, in the future, propose and promulgate 
standards of performance for them.

VI. Implications for PSD and Title V Programs

A. Overview

    The proposal in this rulemaking would, for the first time, regulate 
GHGs under CAA section 111. Under the EPA's regulations for the CAA PSD 
preconstruction permit program, and the CAA Title V operating permit 
program, regulation of GHGs under CAA section 111 triggers the 
applicability of PSD. Even so, today's proposal should not require any 
additional SIP revisions to make clear that the Tailoring Rule 
thresholds--described below--continue to apply to the PSD program.
    This issue arises because States with approved PSD programs in 
their state implementation plans (SIPs) implement PSD, and most of 
these States have recently revised their SIPs to incorporate the higher 
thresholds for PSD applicability to GHGs that the EPA promulgated under 
what we call the Tailoring Rule.\76\ Commenters have queried whether 
under the EPA's PSD regulations, promulgation of a section 111 standard 
of performance GHGs would require these states to revise their SIPs 
again to incorporate the Tailoring Rule thresholds again. The EPA 
included an interpretation in the Tailoring Rule preamble, which makes 
clear that the Tailoring Rule thresholds continue to apply if and when 
the EPA promulgates requirements under CAA section 111. Even so, in 
today's proposal, the EPA is including a provision in the CAA section 
111 regulations that confirms this interpretation.
---------------------------------------------------------------------------

    \76\ ``Prevention of Significant Deterioration and Title V 
Greenhouse Gas Tailoring Rule; Final Rule,'' 75 FR 31514 (June 3, 
2010). In the Tailoring Rule, EPA established a process for phasing 
in PSD and Title V applicability to sources based on the amount of 
their GHG emissions, instead of immediately applying PSD and title V 
at the 100 or 250 ton per year or thresholds included under the PSD 
and title V applicability provisions.
---------------------------------------------------------------------------

    However, if a state with an approved PSD SIP program that applies 
to GHGs believes that were the EPA to finalize the rulemaking proposed 
today, the state would be required to revise its SIP to make clear that 
the Tailoring Rule thresholds continue to apply, then (i) the EPA 
encourages the state to do so as soon as possible, and (ii) the EPA 
will proceed with a separate rulemaking action to narrow its approval 
of that state's SIP so as to assure that for federal purposes, the 
Tailoring Rule thresholds will continue to apply as of the effective 
date of today's rulemaking.
    In the alternative, if the Tailoring Rule thresholds did not 
continue to apply when the EPA promulgates requirements under CAA 
section 111, then the EPA would shortly proceed with a separate 
rulemaking action to narrow its approval of all of the State's approved 
SIP PSD programs to assure that for federal purposes, the Tailoring 
Rule thresholds will continue to apply as of the effective date of 
today's proposal.
    As discussed below, in the case of title V, today's rulemaking does 
not have implications for the Tailoring Rule thresholds established 
with respect to sources subject to title V requirements.

B. Implications for PSD Program

    Under the PSD program in part C of title I of the CAA, in areas 
that are classified as attainment or unclassifiable for NAAQS 
pollutants, a new or modified source that emits any air pollutant 
subject to regulation at or above specified thresholds, is required to 
obtain a preconstruction permit. This permit assures that the source 
meets specified requirements, including application of best available 
control technology. States authorized for the PSD program may issue PSD 
permits. If a state is not authorized, then the EPA issues the PSD 
permits.
    Regulation of GHG emissions in the Light Duty Vehicle Rule (75 FR 
25324) triggered applicability of stationary sources to regulations for 
GHGs under the PSD and title V provisions of the CAA. Hence, on June 3, 
2010 (75 FR 31514), the EPA issued the ``Tailoring Rule,'' which 
establishes thresholds for GHG emissions in order to define and limit 
when new and modified industrial facilities must have permits under the 
PSD and title V programs. The rule addresses emissions of six GHGs: 
CO<INF>2</INF>, CH<INF>4</INF>, N<INF>2</INF>O, HFCs, PFCs and 
SF<INF>6</INF>. On January 2, 2011, large industrial sources, including 
power plants, became subject to permitting requirements for their GHG 
emissions if they were already are required to obtain PSD or title V 
permits due to emissions of other (non-GHG) air pollutants.
    Commenters have queried whether, because of the way that the EPA's 
PSD regulations are written, promulgating the rule we propose today may 
raise questions as to whether the EPA must revise its PSD regulations--
and, by the same token, whether states must revise their SIPs--to 
assure that the Tailoring Rule thresholds will continue to apply to 
sources subject to PSD. That is, under the EPA's regulations, PSD 
applies to a ``major stationary source'' that

[[Page 22429]]

undertakes construction, 40 CFR 51.166(a)(7)(i), and to a ``major 
modification.'' 40 CFR 51.166(a)(7)(iii). A ``major modification'' is 
defined as ``any physical change in or change in the method of 
operation of a major stationary source that would result in a 
significant emissions increase * * * and a significant net emissions 
increase. * * *'' Thus, for present purposes, the key component of 
these applicability provisions is that PSD applies to a ``major 
stationary source.'' This term is the regulatory replacement for the 
term ``major emitting facility,'' which is central to the PSD 
applicability requirements established in the CAA itself, under 
sections 165(a)(1) and 169(1).
    The EPA's regulations define the term ``major stationary source'' 
as a ``stationary source of air pollutants which emits, or has the 
potential to emit, 100 [or, depending on the source category, 250] tons 
per year or more of any regulated NSR pollutant.'' 40 CFR 
51.166(b)(1)(i)(a). The EPA's regulations go on to define ``regulated 
NSR pollutant'' to include, among other things, ``Any pollutant that is 
subject to any standard promulgated under section 111 of the Act.'' 40 
CFR 51.166(b)(49)(ii).
    Thus, the PSD regulations contain a separate PSD trigger for 
pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the 
``NSPS trigger provision''), so that as soon as the EPA promulgates the 
first NSPS for a particular air pollutant, as we are doing in this 
rulemaking with respect to the GHG air pollutant, then PSD is triggered 
for that air pollutant.
    The Tailoring Rule, on the face of its regulatory provisions, 
incorporated the revised thresholds it promulgated into only the fourth 
prong (``[a]ny pollutant that otherwise is subject to regulation under 
the Act''), and not the second prong (``[a]ny pollutant that is subject 
to any standard promulgated under section 111 of the Act''). For this 
reason, a question may arise as to whether the Tailoring Rule 
thresholds apply to the PSD requirement as triggered by the NSPS that 
the EPA is promulgating in this rulemaking.
    However, although the Tailoring Rule thresholds on their face apply 
to only the term, ``subject to regulation'' in the definition of 
``regulated NSR pollutant,'' the EPA stated in the Tailoring Rule 
preamble that the thresholds should be interpreted to apply to other 
terms in the definition of ``major stationary source'' and in the 
statutory provision, ``major emitting facility.'' Specifically, the EPA 
stated:

3. Other Mechanisms

    As just described, we selected the ``subject to regulation'' 
mechanism because it most readily accommodated the needs of States 
to expeditiously revise--through interpretation or otherwise--their 
state rules. Even so, it is important to recognize that this 
mechanism has the same substantive effect as the mechanism we 
considered in the proposed rule, which was revising numerical 
thresholds in the definitions of major stationary source and major 
modification. Most importantly, although we are codifying the 
``subject to regulation'' mechanism, that approach is driven by the 
needs of the states, and our action in this rulemaking should be 
interpreted to rely on any of several legal mechanisms to accomplish 
this result. Thus, our action in this rule should be understood as 
revising the meaning of several terms in these definitions, 
including: (1) The numerical thresholds, as we proposed; (2) the 
term, ``any source,'' which some commenters identified as the most 
relevant term for purposes of our proposal; (3) the term, ``any air 
pollutant; or (4) the term, ``subject to regulation.'' The specific 
choice of which of these constitutes the nominal mechanism does not 
have a substantive legal effect because each mechanism involves one 
or another of the components of the terms ``major stationary 
source''--which embodies the statutory term, ``major emitting 
facility''--and ``major modification,'' which embodies the statutory 
term, ``modification,'' and it is those statutory and regulatory 
terms that we are defining to exclude the indicated GHG-emitting 
sources. \[Footnote]\
    [Footnote: We also think that this approach better clarifies our 
long standing practice of interpreting open-ended SIP regulations to 
automatically adjust for changes in the regulatory status of an air 
pollutant, because it appropriately assures that the Tailoring Rule 
applies to both the definition of ``major stationary source'' and 
``regulated NSR pollutant.'']

75 FR 31582.

    Thus, according to the preamble, the definition of ``major 
stationary source'' itself already incorporates the Tailoring Rule 
thresholds, and not just through one component (the ``subject to 
regulation'' prong of the term ``regulated NSR pollutant'') of that 
definition. For this reason, it is the EPA's position that the 
Tailoring Rule thresholds continue to apply even when the EPA 
promulgates the first NSPS for GHGs (which, as noted above, triggers 
the PSD requirement under the NSPS trigger provision in the definition 
of ``regulated NSR pollutant'').\77\ To clarify and confirm that the 
Tailoring Rule thresholds apply to the section 111 prong of the 
definition of regulated NSR pollutant, in this proposed rulemaking, the 
EPA is proposing to revise the NSPS regulations, although not the PSD 
regulations, to explicitly make clear that the NSPS trigger provision 
in the PSD regulations incorporate the Tailoring Rule thresholds.
---------------------------------------------------------------------------

    \77\ This position reads the regulations to be consistent with 
the CAA PSD provisions themselves. Under those provisions, PSD 
applies to any ``major emitting facility,'' which is defined to mean 
stationary sources that emit or have the potential to emit ``any air 
pollutant'' at either 100 or 250 tons per year, depending on the 
source category. CAA section 165(a), 169(1). EPA has long 
interpreted these provisions to apply PSD to a stationary source 
that emits the threshold amounts of any air pollutant subject to 
regulation. See Tailoring Rule, 75 FR 31579. Under these provisions, 
at present, PSD is already applicable to GHGs because GHGs are 
already subject to regulation, and regulating GHGs under CAA section 
111 does not any additional type of PSD trigger.
---------------------------------------------------------------------------

    As a result, the EPA believes that states that incorporated the 
Tailoring Rule thresholds into their SIPs may take the position that 
they also incorporated the EPA's interpretation in the preamble that 
the thresholds apply to the definition ``major stationary source.''
    The EPA requests that all States with approved SIP PSD programs 
that apply to GHGs indicate during the comment period on this rule 
whether they can interpret their SIPs already to apply the Tailoring 
Rule thresholds to the NSPS prong or whether they must revise their 
SIPs. For any State that says it must revise its SIP (or that does not 
respond), the EPA expects to propose a rule that is comparable to the 
SIP PSD Narrowing Rule shortly after the close of the comment period, 
and expects to finalize that rule at the same time that it finalizes 
this NSPS rule.

C. Implications for Title V Program

    Under the title V program, a source that emits any air pollutant 
subject to regulation at or above specified thresholds (along with 
certain other sources) is required to obtain an operating permit. This 
permit includes all of the CAA requirements applicable to the source. 
These permits are generally issued through EPA-approved State title V 
programs.
    As the EPA explained in the Tailoring Rule preamble, title V 
applies to a ``major source,'' CAA section 502(a), which is defined to 
include, among other things, certain sources, including any ``major 
stationary source,'' CAA section 501(2)(B), which, in turn, is defined 
to include a stationary source of ``any air pollutant'' at or above 100 
tpy. CAA section 302(j). The EPA's regulations under title V define the 
term ``major source,'' and in the Tailoring Rule, the EPA revised that 
definition to make clear that the term is limited to stationary sources 
that emit any air pollutant ``subject to regulation.'' The EPA 
incorporated the Tailoring Rule threshold within this definition of 
``subject to regulation.'' The EPA

[[Page 22430]]

described its action as follows in the preamble to the Tailoring Rule:

    Thus, EPA is adding the phrase ``subject to regulation'' to the 
definition of ``major source'' under 40 CFR 70.2 and 71.2. EPA is 
also adding to these regulations a definition of ``subject to 
regulation.'' Under the part 70 and part 71 regulatory changes 
adopted, the term ``subject to regulation,'' for purposes of the 
definition of ``major source,'' has two components. The first 
component codifies the general approach EPA recently articulated in 
the ``Reconsideration of Interpretation of Regulations That 
Determine Pollutants Covered by Clean Air Act Permitting.'' 75 FR 
17704. Under this first component, a pollutant ``subject to 
regulation'' is defined to mean a pollutant subject to either a 
provision in the CAA or regulation adopted by EPA under the CAA that 
requires actual control of emissions of that pollutant and that has 
taken effect under the CAA. See id. at 17022-23; Wegman Memorandum 
at 4-5. To address tailoring for GHGs, EPA includes a second 
component of the definition of ``subject to regulation,'' specifying 
that GHGs are not subject to regulation for purposes of defining a 
major source, unless as of July 1, 2011, the emissions of GHGs are 
from a source emitting or having the potential to emit 100,000 tpy 
of GHGs on a CO<INF>2</INF>e basis.

75 FR at 31,583.

    Unlike the PSD regulations described above, the title V definition 
of ``major source'', as revised by the Tailoring Rule, does not on its 
face distinguish among types of regulatory triggers for title V. 
Because title V has already been triggered for GHG-emitting sources, 
the promulgation of CAA section 111 requirements has no further impact 
on title V requirements for major sources of GHGs. Accordingly, today's 
rulemaking has no title V implications with respect to the Tailoring 
Rule threshold. Of course, unless exempted by the Administrator through 
regulation under CAA section 502(a), sources subject to a NSPS are 
required to apply for, and operate pursuant to, a title V permit that 
assures compliance with all applicable CAA requirements for the source, 
including any GHG-related requirements. We have concluded that this 
rule will not affect non-major sources and there is no need to consider 
whether to exempt non-major sources

VII. Impacts of the Proposed Action

A. What are the air impacts?

    The EPA believes that electric power companies would choose to 
build new EGUs that comply with the regulatory requirements of this 
proposal even in the absence of this proposal, because of existing and 
expected market conditions. We do not project any new coal-fired EGUs 
without CCS to be built in the absence of this proposal. Accordingly, 
the EPA believes that this proposed rule is not likely to produce 
changes in emissions of greenhouse gases or other pollutants although 
it does encourage the current trend towards cleaner generation.

B. What are the energy impacts?

    This proposed rule is not anticipated to have a notable effect on 
the supply, distribution, or use of energy. As previously stated, we 
believe that electric power companies would choose to build new EGUs 
that comply with the regulatory requirements of this proposal even in 
the absence of the proposal, because of existing and expected market 
conditions. In addition, we do not project any new coal-fired EGUs 
without CCS to be built in the absence of this proposal.

C. What are the compliance costs?

    The EPA believes this proposed rule will have no notable compliance 
costs associated with it, because electric power companies would be 
expected to build new EGUs that comply with the regulatory requirements 
of this proposal even in the absence of the proposal, due to existing 
and expected market conditions. The EPA does not project any new coal-
fired EGUs without CCS to be built in the absence of the proposal.

D. How will this proposal contribute to climate change protection?

    As previously explained, 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 gas. Fossil-fueled 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 proposed rule will limit GHG emissions from new sources in 
this source category to levels consistent with current projections for 
new fossil-fuel-fired generating units. The proposed rule will also 
serve as a necessary predicate for the regulation of existing sources 
within this source category under CAA section 111(d). In these ways, 
the proposed rule will contribute to the actions required to slow or 
reverse the accumulation of GHG concentrations in the atmosphere, which 
is necessary to protect against projected climate change impacts and 
risks.

E. What are the economic and employment impacts?

    The EPA does not anticipate that this proposed rule will result in 
notable CO<INF>2</INF> emission changes, energy impacts, monetized 
benefits, costs, or economic impacts by 2020. Essentially the EPA 
believes that owners of newly built electric generating units will 
choose technologies that meet these standards even in the absence of 
this proposal due to existing economic conditions as normal business 
practice. Likewise, we believe this rule will not have any impacts on 
the price of electricity, employment or labor markets, or the US 
economy.

F. What are the benefits of the proposed standards?

    As previously stated, the EPA does not anticipate that the power 
industry will incur compliance costs as a result of this proposal and 
we do not anticipate any notable CO<INF>2</INF> emission changes 
resulting from the rule. Therefore, there are no direct monetized 
climate benefits in terms of CO<INF>2</INF> emission reductions 
associated with this rulemaking. However, by clarifying that in the 
future, new coal-fired power plants will be required to install CCS, 
this rulemaking eliminates uncertainty about the status of coal and may 
well enhance the prospects for new coal-fired generation and the 
deployment of CCS, and thereby promote energy diversity.

VIII. Request for Comments

    We request comments on all aspects of the proposed rulemaking 
including the RIA. All significant comments received will be considered 
in the development and selection of the final rule. We specifically 
solicit comments on additional issues under consideration as described 
below.
    CEMS. We are considering and requesting comment on requiring the 
use of CO<INF>2</INF> CEMS including stack gas flow rate monitoring for 
all new affected facilities, including those burning exclusively 
natural gas and/or distillate oil. In addition, we are requesting 
comment on requiring the use the following measurement procedures in 
conducting CEMS relative accuracy testing:
    a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during 
the relative accuracy test audit and performance testing. Method 2F 
provides velocity data for three dimensions and provides measurements 
more representative of actual gas flow rates than EPA Method 2 or 2G of 
40 CFR part 60.
    b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method 
(CTM)-041

[[Page 22431]]

(see: http://www.epa.gov/airmarkets/emissions/docs/square-ducts-wall-effects-test-method-ctm-041.pdf) to account for wall effects on for 
stack gas flow rate calculations during CEMS relative accuracy 
determinations and for performance testing.
    c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow 
rate during CEMS relative accuracy determinations and for performance 
test calculations.
    d. EPA Method 3A of 40 CFR part 60 for CO<INF>2</INF> concentration 
measurement and for molecular weight determination during CEMS relative 
accuracy determinations or for performance testing. Account for ambient 
air argon concentration of 0.93 percent \78\ and a molecular weight of 
39.9 lb/lb-mol in calculating the dry gas molecular weight.
---------------------------------------------------------------------------

    \78\ http://www.physicalgeography.net/fundamentals/7a.html.
---------------------------------------------------------------------------

    e. Measure the stack diameter at the CEMS measurement site and the 
reference method sampling site with a laser distance measurement 
device. Determine the mean average of three separate diameter 
measurements for circular stack areas or the mean average of three 
depth and width measurements for rectangular measurement areas. 
Calculate the effective stack area for all flow rate measurements, both 
CEMS system and Reference Method, using this measurement data. This 
would be a one-time measurement that would fix the effective area of 
the stack emissions point unless a new location is chosen for the CEMS 
or Reference Method measurement point. All calculations involving pi 
would use a value of 3.14159.
    f. Apply a daily calibration drift criteria not to exceed 0.3 
percent CO<INF>2</INF> for CO<INF>2</INF> CEMS.
    g. Do not exceed a relative accuracy specification of 2.5 percent 
for both CO<INF>2</INF> and flow rate measurement CEMS.
    We also request comment on whether Method 3B of 40 CFR part 60 
(integrated bag sample), in addition to Method 3A, should be allowed 
for CO<INF>2</INF> concentration measurement and for molecular weight 
determination during CEMS relative accuracy determinations or for 
performance testing.
    Coal refuse. Due to the multiple environmental benefits of 
remediating coal refuse piles, we are considering and requesting 
comment on subcategorizing EGUs that burn over 75 percent coal refuse 
on an annual basis. As part of the GHG listening sessions, one 
commenter mentioned the advantages of utilizing coal refuse to create 
electricity. The commenter stated that if net emissions caused by using 
mining waste to generate electricity are calculated, then mining waste 
facility would produce no net GHG emissions in the long term and 
emissions would be no greater than the short term emissions of a 
combined cycle gas plant in. The comment states that due to the size of 
the piles, mining waste pile exposure to atmospheric oxygen and 
pressure promotes heat-generating reactions, primarily oxidation of the 
mining waste itself (i.e., the coal refuse piles are slowly burning). 
This process emits CO<INF>2</INF> and other air pollutants. Remediation 
would stop current and future CO<INF>2</INF> emissions resulting from 
the uncontrolled combustion of waste piles.
    Coordinates. We realize that geographic latitude and longitude 
coordinates of each stack in terms of decimal degrees are presently 
reported to the EPA's Clean Air Markets Division in terms of four 
decimal points to the right of the decimal point. We are requesting 
comment on whether we should require owners/operators of affected 
facilities to submit to the EPA Administrator the geographic latitude 
and longitude coordinates of each stack to have at least six values to 
the right of the decimal for each location. By way of example, the 
coordinates for the monument next to Zachary Taylor's tomb in 
Louisville, KY are 38.279401 latitude and -85.643751 longitude.
    Combined Heat and Power. We are also considering and requesting 
comment on if exempting all CHP facilities where useful thermal output 
accounts for at least 20 percent of the total useful output from this 
proposed rule would recognize the environmental benefit of CHP and 
result in additional installations that would otherwise no occur. In 
considering exemption of CHP units, the EPA is particularly interested 
in the overall impact this would have on the composition of new builds. 
The definition of affected sources under this rule already exempts CHP 
sources that primarily generate on-site power. Therefore, as explained 
earlier, today's proposal does not impact any of the small amount of 
projected coal-fired CHP in EIA's AEO 2011. CHPs that would be covered 
by this rule generate and sell large quantities of electricity. While 
building such units is more energy efficient and results in some GHG 
reductions, building new coal-fired units to meet a standard of 1,000 
lb CO<INF>2</INF>/MWh would likely result in greater reductions. If 
potential developers of new coal-fired generation opted instead to 
build coal-fired CHP to avoid the CO<INF>2</INF> limitations proposed 
under today's rule, it could result in greater emissions of 
CO<INF>2</INF>. Furthermore, requiring such units to meet a standard of 
1,000 lb CO<INF>2</INF>/MWh does not preclude new coal-fired units from 
being CHP units.
    Format of the Proposed Standards. Although we have proposed gross 
output-based emission standards, the EPA believes that the net power 
supplied to the end user is a better indicator of environmental 
performance than gross output from the power producer. Net output is 
the combination of the gross electrical output of the electric 
generating unit minus the parasitic power requirements. A parasitic 
load for an electric generating unit is any of the loads or devices 
powered by electricity, steam, hot water, or directly by the gross 
output of the electric generating unit that does not contribute 
electrical, mechanical, or thermal output. In general, less than 7.5 
percent of coal-fired station power output, and about 2.5 percent of a 
combined cycle station power output, is used internally by parasitic 
energy demands, but the amount of these parasitic loads vary from 
source to source. Reasons for using net output include (1) recognizing 
the efficiency gains of selecting EGU designs and control equipment 
that require less auxiliary power, (2) selecting fuels that require 
less emissions control equipment, and (3) recognizing the environmental 
benefit of higher efficiency motors, pumps, and fans. In addition, use 
of a gross output-based standard could potentially drive the 
installation of electrically driven feed pumps instead of steam driven 
feed pumps, even though from an overall net efficiency basis, it may be 
more efficient to use steam-driven feed pumps. Further, monitoring net 
output for new and reconstructed facilities can be designed into the 
facility at low costs. Thus, we are requesting comment on the use of 
net output-based emission standards for owners/operators of new 
facilities.
    Stationary Simple Cycle Turbines. As stated in the preamble, the 
intent of the proposed regulations is to cover stationary combustion 
turbines use for intermediate and base load electric power generation 
and to exempt stationary combustion turbines used for peaking 
operations (i.e., simple cycle turbines). We are considering and 
requesting comment on not including a definition of simple cycle 
turbines in the final rule. The potential electric output requirement 
in the definition of electric generating unit would already exclude 
facilities with permit restricting limiting operation to less than \1/
3\ of their potential electric output, approximately 2,900 hours of 
full load

[[Page 22432]]

operation annually. The peaking season is generally considered to be 
less than 2,500 hours annually, and we are requesting comment on if the 
capacity factor exemption is sufficient such that specifically 
exempting simple cycle turbine is unnecessary. We are also requesting 
comment on whether the exemption would provide a perverse incentive to 
build less efficient simple cycle combustion turbines in order to avoid 
applicability with the proposed rule. While few existing simple cycle 
turbines presently generate greater than \1/3\ of their potential 
electric output for sale, we are requesting comment on whether the 
exemption for simple cycle turbines would result in the greater use of 
simple cycle turbines for intermediate load applications when more 
efficient combined cycle facilities would have otherwise been built. In 
addition, it is our understanding that combined cycle facilities are 
sometimes built in stages with the combustion turbine engine 
installation occurring first and the heat recovery steam generator 
being installed in later years as electricity demand increases. We are 
requesting comment on whether the exemption would potentially delay the 
installation of the heat recovery steam generator portion of new 
combined cycle facilities. Finally, in the event we use the definition 
approach in the final rule, we are requesting comment on whether a CHP 
facility that uses the recovered exhaust heat for purposes other than 
to generate steam and recuperated combustion turbines should be 
considered simple or combined cycle combustion turbines.

IX. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and Executive 
Order 13563, Improving Regulation and Regulatory Review

    Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 1993), 
this action is a ``significant regulatory action'' because it ``raises 
novel legal or policy issues arising out of legal mandates''. 
Accordingly, the EPA submitted this action to the Office of Management 
and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 
FR 3821, January 21, 2011) and any changes made in response to OMB 
recommendations have been documented in the docket for this action. In 
addition, the EPA prepared an analysis of the potential costs and 
benefits associated with this action. This analysis is contained in the 
Regulatory Impact Analysis for the Standards of Performance for 
Greenhouse Gas Emissions for New Stationary Sources: Electric Utility 
Generating Units.
    The EPA believes this rule will have no notable compliance costs 
associated with it over a range of likely sensitivity conditions 
because electric power companies would choose to build new EGUs that 
comply with the regulatory requirements of this proposal even in the 
absence of the proposal, because of existing and expected market 
conditions. (See the RIA for further discussion of sensitivities.) 
Because our modeling shows that natural gas-fired plants are the 
facilities of choice, the proposed standard of performance--which is 
based on the emission rate of a new NGCC unit--would not add costs. The 
EPA does not project any new coal-fired EGUs without CCS to be built in 
the absence of this proposal.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by the EPA has 
been assigned EPA ICR number 2465.01.
    This proposed action would impose minimal new information 
collection burden on affected sources beyond what those sources would 
already be subject to under the authorities of CAA parts 75 and 98. OMB 
has previously approved the information collection requirements 
contained in the existing part 75 and 98 regulations (40 CFR part 75 
and 40 CFR part 98) under the provisions of the Paperwork Reduction 
Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-
0626 and 2060-0629, respectively. Apart from certain reporting costs 
based on requirements in the NSPS General Provisions (40 CFR part 60, 
subpart A), which are mandatory for all owners/operators subject to CAA 
section 111 national emission standards, there are no new information 
collection costs, as the information required by this proposed rule is 
already collected and reported by other regulatory programs. The 
recordkeeping and reporting requirements are specifically authorized by 
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA 
pursuant to the recordkeeping and reporting requirements for which a 
claim of confidentiality is made is safeguarded according to Agency 
policies set forth in 40 CFR part 2, subpart B.
    The EPA believes that electric power companies will choose to build 
new EGUs that comply with the regulatory requirements of this proposal 
because of existing and expected market conditions. The EPA does not 
project any new coal-fired EGUs that commence construction after this 
proposal to commence operation over the 3-year period covered by this 
ICR. We estimate that 17 new affected NGCC units would commence 
operation during that time period. As a result of this proposal, those 
units would be required to prepare a summary report, which includes 
reporting of excess emissions and downtime, every 6 months.
    When a malfunction occurs, sources must report them according to 
the applicable reporting requirements of 40 CFR part 60, subpart TTTT. 
An affirmative defense to civil penalties for exceedances of emission 
limits that are caused by malfunctions is available to a source if it 
can demonstrate that certain criteria and requirements are satisfied. 
The criteria ensure that the affirmative defense is available only 
where the event that causes an exceedance of the emission limit meets 
the narrow definition of malfunction (sudden, infrequent, not 
reasonable preventable, and not caused by poor maintenance and or 
careless operation) and where the source took necessary actions to 
minimize emissions. In addition, the source must meet certain 
notification and reporting requirements. For example, the source must 
prepare a written root cause analysis and submit a written report to 
the Administrator documenting that it has met the conditions and 
requirements for assertion of the affirmative defense.
    To provide the public with an estimate of the relative magnitude of 
the burden associated with an assertion of the affirmative defense 
position adopted by a source, the EPA has estimated what the 
notification, recordkeeping, and reporting requirements associated with 
the assertion of the affirmative defense might entail. The EPA's 
estimate for the required notification, reports, and records, including 
the root cause analysis, associated with a single incident totals 
approximately totals $3,141, and is based on the time and effort 
required of a source to review relevant data, interview plant 
employees, and document the events surrounding a malfunction that has 
caused an exceedance of an emission limit. The estimate also includes 
time to produce and retain the record and reports for submission to the 
EPA. The EPA provides this illustrative estimate of this burden, 
because these costs are only incurred if there has been a violation, 
and a source chooses to take advantage of the affirmative defense.

[[Page 22433]]

    The EPA provides this illustrative estimate of this burden because 
these costs are only incurred if there has been a violation and a 
source chooses to take advantage of the affirmative defense. Given the 
variety of circumstances under which malfunctions could occur, as well 
as differences among sources' operation and maintenance practices, we 
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is 
important to note that the EPA has no basis currently for estimating 
the number of malfunctions that would qualify for an affirmative 
defense. Current historical records would be an inappropriate basis, as 
source owners or operators previously operated their facilities in 
recognition that they were exempt from the requirement to comply with 
emissions standards during malfunctions. Of the number of excess 
emissions events reported by source operators, only a small number 
would be expected to result from a malfunction (based on the definition 
above), and only a subset of excess emissions caused by malfunctions 
would result in the source choosing to assert the affirmative defense. 
Thus, we believe the number of instances in which source operators 
might be expected to avail themselves of the affirmative defense will 
be extremely small. In fact, we estimate that there will be no such 
occurrences for any new sources subject to 40 CFR part 60, subpart TTTT 
over the 3-year period covered by this ICR. We expect to gather 
information on such events in the future, and will revise this estimate 
as better information becomes available.
    The annual information collection burden for this collection 
consists only of reporting burden as explained above. The reporting 
burden for this collection (averaged over the first 3 years after the 
effective date of the standards) is estimated to be $15,570 and 396 
labor hours. This estimate includes semi-annual summary reports which 
include reporting of excess emissions and downtime. All burden 
estimates are in 2010 dollars. Average burden hours per response are 
estimated to be 16.5 hours. The total number of respondents over the 3-
year ICR period is estimated to be 36. Burden is defined at 5 CFR 
1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, the EPA has established a public docket 
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2011-0660. Submit any comments related to the ICR to the EPA and 
OMB. See ADDRESSES section at the beginning of this notice for where to 
submit comments to the EPA. Send comments to OMB at the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street, NW., Washington, DC 20503, Attention: Desk Officer for 
EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after April 13, 2012, a comment to OMB is best 
assured of having its full effect if OMB receives it by May 14, 2012. 
The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq.

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small 
entities, small entity is defined as:
    (1) A small business that is defined by the SBA's regulations at 13 
CFR 121.201 (for the electric power generation industry, the small 
business size standard is an ultimate parent entity defined as having a 
total electric output of 4 million MWh or less in the previous fiscal 
year. The NAICS codes for the affected industry are in Table 4 below);
    (2) A small governmental jurisdiction that is a government of a 
city, county, town, school district or special district with a 
population of less than 50,000; and
    (3) A small organization that is any not-for-profit enterprise 
which is independently owned and operated and is not dominant in its 
field.

                            Table 4--Potentially Regulated Categories and Entities a
----------------------------------------------------------------------------------------------------------------
                 Category                    NAICS Code          Examples of potentially 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
  (includes 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.

    After considering the economic impacts of this proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.
    We do not include an analysis of the illustrative impacts on small 
entities that may result from implementation of this proposed rule 
because we do not anticipate any compliance costs over a range of 
likely sensitivity conditions as a result of this proposal. Thus the 
cost-to-sales ratios for any affected small entity would be zero costs 
as compared to annual sales revenue for the entity. The EPA believes 
that electric power companies will choose to build new EGUs that comply 
with the regulatory requirements of this proposal because of existing 
and expected market conditions. (See the RIA for further discussion of 
sensitivities.) Because our modeling shows that natural gas-fired 
plants are the facilities of choice, the proposed standard of 
performance--which is based on the emission rate of a new NGCC unit--
would not add costs. The EPA does not project any new coal-fired EGUs 
without CCS to be built. Accordingly, there are no anticipated

[[Page 22434]]

economic impacts as a result of this proposal.
    Nevertheless, the EPA is aware that there is substantial interest 
in this rule among small entities (municipal and rural electric 
cooperatives). In light of this interest, the EPA determined to seek 
early input from representatives of small entities while formulating 
the provisions of this proposed regulation. Such outreach is also 
consistent with the President's January 18, 2011 Memorandum on 
Regulatory Flexibility, Small Business, and Job Creation, which 
emphasizes the important role small businesses play in the American 
economy. This process has enabled the EPA to hear directly from these 
representatives, at a very preliminary stage, about how it should 
approach the complex question of how to apply Section 111 of the CAA to 
the regulation of GHGs from these source categories. The EPA's outreach 
regarded planned actions for new and existing sources, but only new 
sources would be affected by this proposed action.
    The EPA conducted an initial outreach meeting with small entity 
representatives on April 6, 2011. The purpose of the meeting was to 
provide an overview of recent EPA proposals impacting the power sector. 
Specifically, overviews of the Transport Rule, the Mercury and Air 
Toxics Standards, and the Clean Water Act 316(b) Rule proposals were 
presented.
    The EPA conducted outreach with representatives from 20 various 
small entities that potentially would be affected by this rule. The 
representatives included small entity municipalities, cooperatives, and 
private investors. We distributed outreach materials to the small 
entity representatives; these materials included background, an 
overview of affected sources and GHG emissions from the power sector, 
an overview of CAA section 111, an assessment of CO<INF>2</INF> 
emissions control technologies, potential impacts on small entities, 
and a summary of the listening sessions. We met with eight of the small 
entity representatives, as well as three participants from 
organizations representing power producers, on June 17, 2011, to 
discuss the outreach materials, potential requirements of the rule, and 
regulatory areas where the EPA has discretion and could potentially 
provide flexibility.
    A second outreach meeting was conducted on July 13, 2011. We met 
with nine of the small entity representatives, as well as three 
participants from organizations representing power producers. During 
the second outreach meeting, various small entity representatives and 
participants from organizations representing power producers presented 
information regarding issues of concern with respect to development of 
standards for GHG emissions. Specifically, topics suggested by the 
small entity representatives and discussed included: boilers with 
limited opportunities for efficiency improvements due to NSR 
complications for conventional pollutants; variances per kilowatt-hour 
and in heat rates over monthly and annual operations; significance of 
plant age; legal issues; importance of future determination of carbon 
neutrality of biomass; and differences between municipal government 
electric utilities and other utilities.
    Small entities expressed concern regarding units making 
modifications being regulated as new sources. As explained above, we 
are not proposing a standard of performance for modifications. As a 
result, sources that undertake modifications would be treated as 
existing sources and thus would not be subject to the requirements 
proposed in this notice. As also explained above, the EPA is not 
proposing standards of performance for existing proposed EGUs, which 
are referred to 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, any 
transitional sources owned by small entities would not be subject to 
the standards of performance proposed in today's rule.
    We invite comments on all aspects of the proposal and its impacts, 
including potential adverse impacts, on small entities.

D. Unfunded Mandates Reform Act of 1995

    This proposed rule does not contain a Federal mandate that may 
result in expenditures of $100 million or more for State, local, and 
tribal governments, in the aggregate, or the private sector in any one 
year. The EPA believes this proposed rule will have no compliance costs 
associated with it over a range of likely sensitivity conditions 
because electric power companies will choose to build new EGUs that 
comply with the regulatory requirements of this proposal because of 
existing and expected market conditions. (See the RIA for further 
discussion of sensitivities.) As previously explained, because our 
modeling shows that natural gas-fired plants are the facilities of 
choice, the proposed standard of performance--which is based on the 
emission rate of a new NGCC unit--would not add costs. The EPA does not 
project any new coal-fired EGUs without CCS to be built. Thus, this 
proposed rule is not subject to the requirements of sections 202 or 205 
of UMRA.
    This proposed rule is also not subject to the requirements of 
section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments.
    In light of the interest in this rule among governmental entities, 
the EPA initiated consultations with governmental entities. The EPA 
invited the following 10 national organizations representing state and 
local elected officials to a meeting held on April 12, 2011, in 
Washington DC: (1) National Governors Association; (2) National 
Conference of State Legislatures, (3) Council of State Governments, (4) 
National League of Cities, (5) U.S. Conference of Mayors, (6) National 
Association of Counties, (7) International City/County Management 
Association, (8) National Association of Towns and Townships, (9) 
County Executives of America, and (10) Environmental Council of States. 
These 10 organizations representing elected state and local officials 
have been identified by the EPA as the ``Big 10'' organizations 
appropriate to contact for purpose of consultation with elected 
officials. The purposes of the consultation were to provide general 
background on the proposal, answer questions, and solicit input from 
state/local governments. The EPA's consultation regarded planned 
actions for new and existing sources, but only new sources would be 
affected by this proposed action.
    During the meeting, officials asked clarifying questions regarding 
CAA section 111 requirements and efficiency improvements that would 
reduce CO<INF>2</INF> emissions. In addition, they expressed concern 
with regard to the potential burden associated with impacts on state 
and local entities that own/operate affected utility boilers, as well 
as on state and local entities with regard to implementing the rule. 
Subsequent to the April 12, 2011 meeting, the EPA received a letter 
from the National Conference of State Legislatures. In that letter, the 
National Conference of State Legislatures urged the EPA to ensure that 
the choice of regulatory options maximizes benefit and minimizes 
implementation and compliance costs on state and local governments; to 
pay particular attention to options that would provide states with as 
much flexibility as possible; and to take into consideration the 
constraints of the state legislative calendars and ensure that 
sufficient time is allowed for state

[[Page 22435]]

actions necessary to come into compliance.

E. Executive Order 13132, Federalism

    This proposed action does not have federalism implications. It 
would not have substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government, as specified in EO 13132. This proposed action would not 
impose substantial direct compliance costs on state or local 
governments, nor would it preempt state law. Thus, Executive Order 
13132 does not apply to this action. The EPA consulted with state and 
local officials in the process of developing the proposed rule to 
permit them to have meaningful and timely input into its development. 
The EPA's consultation regarded planned actions for new and existing 
sources, but only new sources would be affected by this proposed 
action. The EPA met with 10 national organizations representing state 
and local elected officials to provide general background on the 
proposal, answer questions, and solicit input from state/local 
governments. The UMRA discussion in this preamble includes a 
description of the consultation. In the spirit of EO 13132, and 
consistent with EPA policy to promote communications between the EPA 
and state and local governments, the EPA specifically solicits comment 
on this proposed action from state and local officials.

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

    Subject to the EO 13175 (65 FR 67249, November 9, 2000) the EPA may 
not issue a regulation that has tribal implications, that imposes 
substantial direct compliance costs, and that is not required by 
statute, unless the Federal government provides the funds necessary to 
pay the direct compliance costs incurred by tribal governments, or the 
EPA consults with tribal officials early in the process of developing 
the proposed regulation and develops a tribal summary impact statement.
    The EPA has concluded that this proposed action would not have 
tribal implications. It would neither impose substantial direct 
compliance costs on tribal governments, nor preempt Tribal law. This 
proposed rule would impose requirements on owners and operators of new 
EGUs. The EPA is aware of three coal-fired EGUs located in Indian 
Country but is not aware of any EGUs owned or operated by tribal 
entities. The EPA notes that this proposal does not affect existing 
sources such as the three coal-fired EGUs located in Indian Country, 
but addresses CO<INF>2</INF> emissions for new EGU sources only.
    Because the EPA is aware of Tribal interest in this proposed rule, 
the EPA offered consultation with tribal officials early in the process 
of developing this proposed regulation to permit them to have 
meaningful and timely input into its development. The EPA's 
consultation regarded planned actions for new and existing sources, but 
only new sources would be affected by this proposed action.
    Consultation letters were sent to 584 tribal leaders. The letters 
provided information regarding the EPA's development of NSPS and 
emission guidelines for EGUs and offered consultation. A consultation/
outreach meeting was held on May 23, 2011, with the Forest County 
Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa 
Reservation, and the Leech Lake Band of Ojibwe. Other tribes 
participated in the call for information gathering purposes. In this 
meeting, the EPA provided background information on the GHG emission 
standards to be developed and a summary of issues being explored by the 
Agency. Tribes suggested that the EPA consider expanding coverage of 
the GHG standards to include combustion turbines, lowering the 250 
MMBtu per hour heat input threshold so as to capture more EGUs, and 
including credit for use of renewables. The tribes were also interested 
in the scope of the emissions averaging being considered by the Agency 
(e.g., over what time period, across what units). In addition, the EPA 
held a series of listening sessions on this proposed action. Tribes 
participated in a session on February 17, 2011 with the state agencies, 
as well as in a separate session with tribes on April 20, 2011.
    The EPA will also hold additional meetings with tribal 
environmental staff to inform them of the content of this proposal as 
well as provide additional consultation with tribal elected officials 
where it is appropriate. We specifically solicit additional comment on 
this proposed rule from tribal officials.

G. Executive Order 13045, Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as 
applying to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the Order 
has the potential to influence the regulation. This proposed action is 
not subject to EO 13045 because it is based solely on technology 
performance. The proposal is not expected to produce notable changes in 
emissions of greenhouse gases or other pollutants but does encourage 
the current trend towards cleaner generation, helping to protect air 
quality and children's health. The Agency recognizes that children are 
among the groups most vulnerable to climate change impacts and the 
public is invited to submit comments or identify peer reviewed studies 
relevant to this proposal.

H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This proposed action is not a ``significant energy action'' as 
defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it is not 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy. This proposed action is not anticipated 
to have notable impacts on emissions, costs or energy supply decisions 
for the affected electric utility industry.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the NTTAA of 1995 (Pub. L. 104-113; 15 U.S.C. 272 
note) directs the EPA to use Voluntary Census Standards in their 
regulatory and procurement activities unless to do so would be 
inconsistent with applicable law or otherwise impractical. Voluntary 
consensus standards are technical standards (e.g., materials 
specifications, test methods, sampling procedures, business practices) 
developed or adopted by one or more voluntary consensus bodies. The 
NTTAA directs the EPA to provide Congress, through annual reports to 
the OMB, with explanations when an agency does not use available and 
applicable VCS.
    This proposed rulemaking involves technical standards. The EPA 
cites the following standards in this proposed rule: D5287-08 (Standard 
Practice for Automatic Sampling of Gaseous Fuels), D4057-06 (Standard 
Practice for Manual Sampling of Petroleum and Petroleum Products), and 
D4177-95(2010) (Standard Practice for Automatic Sampling of Petroleum 
and Petroleum Products). The EPA is proposing use of Appendices B, D, 
F, and G to 40 CFR part 75; these Appendices contain standards that 
have already been reviewed under the NTTAA.
    The EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this 
action.

[[Page 22436]]

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
Federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the U.S.
    The EPA has determined that this proposed rule would not result in 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations, including any minority, 
low-income population or indigenous populations.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference, Intergovernmental 
relations, Reporting and recordkeeping requirements.

    Dated: March 27, 2012.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, part 
60 of the Code of the Federal Regulations is proposed to be amended as 
follows:

PART 60--[AMENDED]

    1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

    2. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for 
Electric Utility Generating Units

Applicability

Sec.
60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?
60.5510 What is the affected EGU of this subpart?

Emissions Standards

60.5515 What greenhouse gases are regulated by this subpart?
60.5520 What CO<INF>2</INF> emissions standards must I meet?

General Compliance Requirements

60.5525 What are my general requirements for complying with this 
subpart?
60.5530 Affirmative Defense for Exceedance of Emission Limit During 
Malfunction

Monitoring and Compliance Determination Procedures

60.5535 How do I monitor and collect data to demonstrate compliance?
60.5540 How do I demonstrate compliance and determine excess 
emissions with my CO<INF>2</INF> emissions limit?

Notifications, Reports, and Records

60.5550 What notifications must I submit and when?
60.5555 What reports must I submit and when?
60.5560 What records must I keep?
60.5565 In what form and how long must I keep my records?

Other Requirements and Information

60.5570 What parts of the General Provisions apply to me?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?
Table 1 to Subpart TTTT of Part 60--Applicability of Subpart A 
General Provisions to Subpart TTTT

Applicability


Sec.  60.5508  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance 
schedules for the control of greenhouse gas (GHG) emissions from 
electric utility generating units that commenced construction after 
April 13, 2012.


Sec.  60.5509  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an electric 
utility generating unit that commences construction after April 13, 
2012 with a base load rating of more than 73 megawatts (MW) (250 
million British thermal units per hour (MMBtu/h)) heat input of fossil 
fuel except as specified under Sec.  60.5510(b).


Sec.  60.5510  What is the affected EGU of this subpart?

    (a) The affected facility to which this subpart applies is each 
electric utility generating unit (EGU) except as provided for in 
paragraph (b) of this section.
    (b) An electric utility generating unit that meets the conditions 
specified in paragraphs (b)(1) through (b)(3) of this section is exempt 
from this subpart.
    (1) A steam electric generating unit that meets the definition of 
municipal waste combustor unit and is subject to subpart Eb of this 
part.
    (2) A steam electric generating unit that meets the definition of a 
commercial or industrial solid waste incineration unit and is subject 
to subpart CCCC of this part.
    (3) Transitional sources.
    (i) You are not subject to this subpart if you own or operate a 
transitional source that commences construction within 12 months after 
April 13, 2012.
    (ii) For purposes of paragraph (b)(3)(ii) a ``transitional source'' 
is defined as an EGU with a base load rating of more than 73 megawatts 
(MW) (250 million British thermal units per hour (MMBtu/h)) heat input 
of fossil fuel, except as provided for in Sec.  60.5510(b)(1) and (2), 
and that received a complete permit that meets the requirements of the 
Prevention of Significant Deterioration Program under part C of Title I 
of the Clean Air Act prior to April 13, 2012 (or that had an approved 
PSD permit that has expired and is in the process of being extended, if 
the source is participating in a Department of Energy CCS funding 
program).

Emissions Standards


Sec.  60.5515  What greenhouse gases are regulated by this subpart?

    The greenhouse gas regulated by this subpart is carbon dioxide 
(CO<INF>2</INF>).


Sec.  60.5520  What CO<INF>2</INF> emissions standards must I meet?

    (a) You must not discharge any gases that contain CO<INF>2</INF> 
from any affected EGU into the atmosphere in excess of 454 kilograms 
(kg) of CO<INF>2</INF> per gross output in Megawatt-hours (MWh) (454 
kg/MWh) (1,000 lb/MWh) on a 12-operating month annual average basis, 
except as provided for in paragraphs (b) through (d) of this section.
    (b) If the affected EGU utilizes coal or petroleum coke for fuel 
and is designed to allow installation and operation of a carbon capture 
and storage (CCS) system, you may comply with each standard in 
paragraphs (b)(1) through (3) as an alternative to complying with 
paragraph (a) of this section.
    (1) For each year until the 11th year of operation, you must not 
discharge any gases that contain CO<INF>2</INF> from the affected EGU 
into the atmosphere in excess of 816 kg/MWh (1,800 lb/MWh) gross output 
on a 12-operating month annual average basis, and
    (2) Beginning with the 11th year of operation, the CCS system must 
be operational and you must not discharge any gases that contain 
CO<INF>2</INF> from the affected EGU into the atmosphere in excess of 
272 kg/MWh (600 lb/MWh) gross output on a 12-operating month annual 
average basis, and
    (3) You must not discharge any gases that contain CO<INF>2</INF> 
from the affected EGU into the atmosphere in excess of 454 kg/MWh gross 
output on a 30-year average basis.

[[Page 22437]]

    (c) Electric utility generating units located in a non-continental 
area are not subject to the requirements of this subpart.
    (d) Simple cycle combustion turbines are not subject to the 
requirements of this subpart.

General Compliance Requirements


Sec.  60.5525  What are my general requirements for complying with this 
subpart?

    (a) You must be in compliance with the emissions limits in this 
subpart applicable to your affected EGU. These limits apply at all 
times.
    (b) At all times you must operate and maintain each affected EGU, 
including associated equipment and monitoring equipment, in a manner 
consistent with safety and good practices for minimizing CO<INF>2</INF> 
emissions. Determination of whether such operation and maintenance 
procedures are being used will be based on information available to the 
Administrator which may include, but is not limited to, fuel use 
records, monitoring results, review of operation and maintenance 
procedures, review of operation and maintenance records, review of 
reports required by this subpart, and inspection of the facility.
    (c) For each affected EGU subject to the CO<INF>2</INF> emissions 
limits in Sec.  60.5520, you must measure or calculate a 12 month 
rolling average CO<INF>2</INF> emission rate, calculated per calendar 
month, in terms of tons/MWh.
    (1) If your EGU is subject to the requirements of 40 CFR 
75.10(a)(3)(i), you must use the CO<INF>2</INF> CEMS to measure the 12 
month rolling average CO<INF>2</INF> emissions rate.
    (d) You must conduct an initial compliance determination for your 
affected EGU according to the requirements in this subpart within 30 
days following the first day of the 13th operating month following the 
date of initial operations. Thereafter, you must demonstrate continuous 
compliance according to the requirements in this subpart each calendar 
month determined to be an operating month.


Sec.  60.5530  Affirmative Defense for Exceedance of Emission Limit 
During Malfunction.

    In response to an action to enforce the standards you may assert an 
affirmative defense to a claim for civil penalties for exceedances of 
such standards that are caused by malfunction, as defined at 40 CFR 
60.2. Appropriate penalties may be assessed, however, if the respondent 
fails to meet its burden of proving all of the requirements in the 
affirmative defense. The affirmative defense shall not be available for 
claims for injunctive relief.
    (a) To establish the affirmative defense in any action to enforce 
such a limit, the owners or operators of facilities must timely meet 
the notification requirements in paragraph (b) of this section, and 
must prove by a preponderance of evidence that:
    (1) The excess emissions:
    (i) Were caused by a sudden, infrequent, and unavoidable failure of 
air pollution control and monitoring equipment, process equipment, or a 
process to operate in a normal or usual manner;
    (ii) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (iii) Did not result from any activity or event that could have 
been foreseen and avoided, or planned for; and
    (iv) Were not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance;
    (2) Repairs were made as expeditiously as practicable when the 
applicable emission limitations were being exceeded. Off-shift and 
overtime labor were used, to the extent practicable to make these 
repairs;
    (3) The frequency, amount and duration of the excess emissions 
(including any bypass) were minimized to the maximum extent practicable 
during periods of such emissions;
    (4) If the excess emissions resulted from a bypass of control 
equipment or a process, then the bypass was unavoidable to prevent loss 
of life, personal injury, or severe property damage;
    (5) All practicable steps were taken to minimize the impact of the 
excess emissions on ambient air quality, the environment and human 
health;
    (6) All emissions monitoring and control systems were kept in 
operation if at all practicable, consistent with safety and good air 
pollution control practices;
    (7) All of the actions in response to the excess emissions were 
documented by properly signed, contemporaneous operating logs;
    (8) At all times, the facility was operated in a manner consistent 
with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of 
which is to determine, correct, and eliminate the primary causes of the 
malfunction and the excess emissions resulting from the malfunction 
event at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of excess emissions that 
were the result of the malfunction.
    (b) The owner or operator of an affected EGU experiencing an 
exceedance of its emission limit(s) during a malfunction shall notify 
the Administrator by telephone or facsimile (FAX) transmission as soon 
as practicable, but no later than two (2) business days after the 
initial occurrence of the malfunction, if it wishes to avail itself of 
an affirmative defense to civil penalties for that malfunction. The 
owner or operator seeking to assert an affirmative defense shall also 
submit a written report to the Administrator within 45 days of the 
initial occurrence of the exceedance of the standard to demonstrate, 
with all necessary supporting documentation, that it has met the 
requirements set forth in paragraph (a) of this section. The owner or 
operator may seek an extension of this deadline for up to 30 additional 
days by submitting a written request to the Administrator before the 
expiration of the 45-day period. Until a request for an extension has 
been approved by the Administrator, the owner or operator is subject to 
the requirement to submit such report within 45 days of the initial 
occurrence of the exceedances.

Monitoring and Compliance Determination Procedures


Sec.  60.5535  How do I monitor and collect data to demonstrate 
compliance?

    (a) You must prepare a site-specific monitoring plan that addresses 
the monitoring system design, data collection and the quality assurance 
and quality control elements consistent with the applicable 
requirements in Sec.  60.13, 40 CFR part 75, and this section.
    (b) Follow the applicable quality assurance procedures for 
CO<INF>2</INF> emissions in appendices B, D, and G to 40 CFR part 75.
    (c) If you determine the your affected EGU's CO<INF>2</INF> mass 
emissions rate by monitoring fuel combusted in the affected EGU and 
periodic fuel sampling as allowed under Sec.  60.5525(c)(2), you must 
use the procedures specified in 40 CFR part 75, appendix G.
    (1) Determine a site-specific F factor using the ultimate analysis 
and GCV in equation F-7a of 40 CFR part 75, Appendix F; and
    (2) Monitor and determine the affected EGU's daily fuel consumption 
for each type of fuel combusted in the affected EGU.
    (3) Use ASTM D5287-08 (Standard Practice for Automatic Sampling of 
Gaseous Fuels) to collect a representative gaseous fuel sample.

[[Page 22438]]

    (4) Use one of the following methods to collect a representative 
liquid oil fuel sample:
    (i) ASTM D4057-06 (Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products) or
    (ii) ASTM D4177-95 (2010) (Standard Practice for Automatic Sampling 
of Petroleum and Petroleum Products).
    (d) You must monitor and record the applicable data needed to 
determine your affected EGU's gross output for each operating month.
    (e) Follow the applicable missing data substitution procedures in 
40 CFR part 75 for CO<INF>2</INF> concentration, stack gas flow rate, 
fuel flow rate, high heating value, and fuel carbon content.


Sec.  60.5540  How do I demonstrate compliance and determine excess 
emissions with my CO<INF>2</INF> emissions limit?

    (a) If you use a CO<INF>2</INF> CEMS to demonstrate compliance you 
must use the procedure specified in paragraphs (a)(1) through (5) of 
this section to determine the 12-operating month rolling average 
CO<INF>2</INF> emissions rate for your affected EGU.
    (1) Calculate hourly CO<INF>2</INF> mass emissions for each hour of 
the operating month in terms of kilograms CO<INF>2</INF> using CFR 40 
part 75 appendix G.
    (2) Determine hourly gross output in terms of MWh for each hour of 
the operating month.
    (3) Sum the hourly CO<INF>2</INF> mass emissions for the operating 
month, and sum the hourly gross output for the operating month.
    (4) Divide the total CO<INF>2</INF> mass emissions calculated for 
the month by the total hourly gross output calculated for the operating 
month.
    (5) Add the quotient to the sum of the quotients of the previous 11 
operating months and divide by 12 to determine the 12-operating month 
rolling average.
    (6) If the 12-operating month rolling average value does not exceed 
the applicable emissions limit in Sec.  60.5520, your affected EGU is 
determined to be in compliance with the emissions limit. Otherwise, 
your affected EGU is determined to have excess emissions.
    (b) If you use fuel sampling to demonstrate compliance, you must 
use the procedure specified in paragraphs (b)(1) through (5) of this 
section to determine the 12-operating month rolling average 
CO<INF>2</INF> emissions rate for your affected EGU.
    (1) Calculate monthly CO<INF>2</INF> mass emissions by multiplying 
the monthly F factor by the monthly fuel consumption.
    (2) Sum the hourly gross output in terms of MWh for the month.
    (3) Divide the monthly CO<INF>2</INF> mass emissions by the sum of 
the hourly gross output for the month.
    (4) Add the quotient to the sum of the quotients of the previous 11 
operating months to determine the 12-operating month rolling average.
    (5) If the 12-operating month rolling average value does not exceed 
the applicable emissions limit in Sec.  60.5520, your affected EGU is 
determined to be in compliance with the emissions limit. Otherwise, 
your affected EGU is determined to have excess emissions.
    (c) If you elect to comply with Sec.  60.5520(b), the 30-year 
average CO<INF>2</INF> emissions rate for your affected EGU is the sum 
of the monthly CO<INF>2</INF> emissions for each operating month for 
the 30-year period divided by the sum of the monthly gross output in 
terms of MWh for the 30-year period. Use the procedure specified in 
paragraphs (c)(1) through (4) of this section to determine the 12-month 
annual average CO<INF>2</INF> emissions rate for your affected EGU.
    (1) If you do not use a CO<INF>2</INF> CERMS to demonstrate 
compliance with Sec.  60.5520(b), you must calculate hourly 
CO<INF>2</INF> mass emissions for each hour of the 12-month annual 
period in terms of kilograms CO<INF>2</INF> using CFR 40 Part 75 
Appendix G. If you use a CO<INF>2</INF> CERMS to demonstrate compliance 
with Sec.  60.5520(b) you must calculate hourly CO<INF>2</INF> mass 
emissions for each hour of the 12-month annual period in terms of 
kilograms CO<INF>2</INF> using the CERMS hourly mass emissions 
measurements.
    (2) Determine hourly gross output in terms of MWh for each hour of 
the 12-month annual period.
    (3) Sum the hourly CO<INF>2</INF> mass emissions for the 12-month 
annual operating period, and sum the hourly gross output for the 12-
month annual operating period.
    (4) Divide the total CO<INF>2</INF> mass emissions calculated for 
the 12-month annual operating period by the total hourly gross output 
calculated for the 12-month annual operating period.
    (5) If the 12-month annual average value does not exceed the 
applicable emissions limit in Sec.  60.5520, your affected EGU is 
determined to be in compliance with the emissions limit. Otherwise, 
your affected EGU is determined to have excess emissions.

Notification, Reports, and Records


Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit notifications specified in Sec.  
60.7(a) and Sec.  60.19, as applicable to your affected EGU.
    (b) You must prepare and submit notifications specified in 40 CFR 
part 75.61, as applicable to your affected EGU.


Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports specified in Sec.  60.7(c) 
through (e) and Sec.  60.19, as applicable to your affected EGU. All 
reports required under Sec.  60.7 must be submitted by the 30th day 
following the end of each 6-month period.
    (1) The excess emissions and continuous monitoring systems 
performance reports and-or summary report forms required in Sec.  
60.7(c) must be submitted to the EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through the EPA's Central Data Exchange (CDX)(www.epa.gov/cdx). In CEDRI, the owner or operator shall use the appropriate 
electronic reporting form for this subpart or provide an alternate 
electronic file consistent with EPA's form output format.
    (b) You must follow the applicable reporting requirements and 
submit reports as required in subpart G of 40 CFR part 75. You must 
report CO<INF>2</INF> mass emissions data, and other related data 
electronically using the Emissions Collection and Monitoring Plan 
System (ECMPS).


Sec.  60.5560  What records must I maintain?

    (a) You must maintain records of your information used to 
demonstrate compliance with this subpart as specified in Sec.  60.7 (b) 
and (f).
    (1) Notwithstanding the requirements of this section you do not 
need to maintain records of the reports that have been submitted to the 
EPA's WebFIRE database as required in Sec.  60.5555(a)(1).
    (b) You must follow the applicable recordkeeping requirements and 
maintain records as required in subpart F of 40 CFR part 75.
    (c) If you determine the CO<INF>2</INF> mass emissions rate by 
monitoring fuel combusted in an affected EGU and periodic fuel sampling 
according to the requirements in this rule then you must maintain 
records of fuel type and quantity combusted in the affected EGU for 
each operating month the information specified in paragraphs (c) (1) 
and (2) of this section.
    (1) Records of fuel type and quantity combusted in the affected EGU 
for each operating month.
    (2) Records of the calculations performed to determine the site-
specific F factor and monthly total CO<INF>2</INF> mass emissions 
rates.
    (d) Records of the applicable data recorded and calculations 
performed used to determine your affected EGU's gross output for each 
operating month.

[[Page 22439]]

Sec.  60.5565  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review.
    (b) You must keep each record for 5 years following the date of 
each occurrence, measurement, maintenance, corrective action, report, 
or record except those records required to demonstrate compliance with 
the emissions limits in Sec.  60.5520(b). Records required to 
demonstrate compliance with the emissions limits in Sec.  60.5520(b) 
must be kept for at least 40 years following the date of initial 
startup of the affected EGU.
    (c) You must keep each record on site for at least 2 years after 
the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec.  60.10. You can keep the 
records off site for the remaining years as required by this subpart.

Other Requirements and Information


Sec.  60.5570  What parts of the General Provisions apply to me?

    Table 1 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  60.1 through 60.19 apply to you.


Sec.  60.5575  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the EPA, or a 
delegated authority such as your state, local, or tribal agency. If the 
Administrator has delegated authority to your state, local, or tribal 
agency, then that agency (as well as the EPA) has the authority to 
implement and enforce this subpart. You should contact your EPA 
Regional Office to find out if this subpart is delegated to your state, 
local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a state, local, or tribal agency, the authorities listed in 
paragraphs (b)(1) through (5) of this section are retained by the 
Administrator and are not transferred to the state, local, or tribal 
agency; however, the EPA retains oversight of this subpart and can take 
enforcement actions, as appropriate.
    (1) Approval of alternatives to the emission standards.
    (2) Approval of major alternatives to test methods.
    (3) Approval of major alternatives to monitoring.
    (4) Approval of major alternatives to recordkeeping and reporting.
    (5) Performance test and data reduction waivers under Sec.  
60.8(b).


Sec.  60.5580  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the 
meaning given them in the Clean Air Act and in subpart A (General 
Provisions of this part).
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
    Base load rating means the maximum amount of heat input (fuel) that 
a steam generating unit can combust on a steady state basis, as 
determined by the physical design and characteristics of the steam 
generating unit at ISO conditions. For a stationary combustion turbine 
base load means 100 percent of the design heat input capacity of the 
stationary combustion turbine engine at ISO conditions.
    Carbon capture and storage (CCS) means a process that includes 
capture and compression of CO<INF>2</INF> produced by an electric 
utility generating unit before release to the atmosphere; transport of 
the captured CO<INF>2</INF> (usually in pipelines); and storage of that 
CO<INF>2</INF> in geologic formations, such as deep saline formations, 
oil and gas reservoirs, and unmineable coal seams.
    Coal means all solid fuels classified as anthracite, bituminous, 
subbituminous, or lignite by the American Society of Testing and 
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17), 
coal refuse, and petroleum coke. Synthetic fuels derived from coal for 
the purpose of creating useful heat, including but not limited to 
solvent-refined coal, gasified coal (not meeting the definition of 
natural gas), coal-oil mixtures, and coal-water mixtures are included 
in this definition for the purposes of this subpart.
    Coal refuse means waste products of coal mining, physical coal 
cleaning, and coal preparation operations (e.g. culm, gob, etc.) 
containing coal, matrix material, clay, and other organic and inorganic 
material.
    Combined cycle means a stationary turbine combustion system where 
heat from the turbine exhaust gases is recovered by a heat recovery 
steam generating unit.
    Combined heat and power, also known as ``cogeneration,'' means a 
steam-generating unit that simultaneously produces both electric (and 
mechanical) and useful thermal energy from the same primary energy 
source.
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17), 
diesel fuel oil numbers 1 and 2, as defined by the American Society for 
Testing and Materials in ASTM D975 (incorporated by reference, see 
Sec.  60.17), kerosene, as defined by the American Society of Testing 
and Materials in ASTM D3699 (incorporated by reference, see Sec.  
60.17), biodiesel as defined by the American Society of Testing and 
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17), 
or biodiesel blends as defined by the American Society of Testing and 
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
    Electric utility generating unit or EGU means any steam electric 
generating unit or stationary combustion turbine that is constructed 
for the purpose of supplying more than one-third of its potential 
electric output capacity and more than 25 MW net-electrical output to 
any utility power distribution system for sale. Also, any steam 
supplied to a steam distribution system for the purpose of providing 
steam to a steam-electric generator that would produce electrical 
energy for sale is considered in determining the electrical energy 
output capacity of the affected EGU.
    Excess emissions means a specified averaging period over which the 
CO<INF>2</INF> emissions rate are higher than the applicable emissions 
standard.
    Federally enforceable means all limitations and conditions that are 
enforceable by the Administrator, including the requirements of 40 CFR 
parts 60 and 61, requirements within any applicable State 
implementation plan, and any permit requirements established under 40 
CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid, liquid, or gaseous fuel derived from such material for the 
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at standard 
conditions and includes, but is not limited to, natural gas, refinery 
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Gross output means the gross electrical or mechanical output from 
the unit plus 75 percent of the useful thermal output measured relative 
to ISO conditions that is not used to generate additional electrical or 
mechanical output or to enhance the performance of

[[Page 22440]]

the unit (i.e., steam delivered to an industrial process).
    Integrated gasification combined cycle electric utility generating 
unit means an electric utility combined cycle gas turbine that is 
designed to burn fuels containing 50 percent (by heat input) or more 
solid-derived fuel not meeting the definition of natural gas. The 
Administrator may waive the 50 percent solid-derived fuel requirement 
during periods of the gasification system construction or repair. No 
solid fuel is directly burned in the unit during operation.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative 
humidity and 101.3 kilopascals pressure.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous state under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
    Net-electric output means the gross electric sales to the utility 
power distribution system minus purchased power on a calendar year 
basis.
    Non-continental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern 
Mariana Islands.
    Operating month means a calendar month during which any fuel is 
combusted in the electric utility generating unit at any time.
    Out-of-control period means any period beginning with the quadrant 
corresponding to the completion of a daily calibration error, linearity 
check, or quality assurance audit that indicates that the instrument is 
not measuring and recording within the applicable performance 
specifications and ending with the quadrant corresponding to the 
completion of an additional calibration error, linearity check, or 
quality assurance audit following corrective action that demonstrates 
that the instrument is measuring and recording within the applicable 
performance specifications.
    Potential electric output means 33 percent of the maximum design 
heat input capacity of the steam generating unit, divided by 3,413 Btu/
KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 
steam generating unit with a 100 MW (340 MMBtu/h) fossil-fuel heat 
input capacity would have a 289,080 MWh 12 month potential electrical 
output capacity).
    Simple cycle combustion turbine means a stationary combustion 
turbine that which does not recover heat from the combustion turbine 
exhaust gases for purposes other than enhancing the performance of the 
combustion turbine itself.
    Solid fuel means any fuel that has a definite shape and volume, has 
no tendency to flow or disperse under moderate stress, and is not 
liquid or gaseous at ISO conditions. This includes, but is not limited 
to, coal, biomass, and pulverized solid fuels.
    Stationary combustion turbine means all equipment, including but 
not limited to the turbine, the fuel, air, lubrication and exhaust gas 
systems, control systems (except emissions control equipment), heat 
recovery system, fuel compressor, heater, and/or pump, post-combustion 
emission control technology, and any ancillary components and sub-
components comprising any simple cycle stationary combustion turbine, 
any combined cycle combustion turbine, and any combined heat and power 
combustion turbine based system. Stationary means that the combustion 
turbine is not self propelled or intended to be propelled while 
performing its function. It may, however, be mounted on a vehicle for 
portability.
    Steam electric generating unit means any furnace, boiler, or other 
device used for combusting fuel for the purpose of producing steam 
(including fossil fuel-fired steam generators associated with combined 
cycle gas turbines; nuclear steam generators are not included) plus any 
integrated device that provides electricity or useful thermal output to 
either the boiler or to power auxiliary equipment.
    Useful thermal output means the thermal energy made available for 
use in any industrial or commercial process, or used in any heating or 
cooling application, i.e., total thermal energy made available for 
processes and applications other than electrical generation or to 
enhance the performance of the stationary combustion turbine. Thermal 
output for this subpart means the energy in recovered thermal output 
measured against the energy in the thermal output at ISO conditions.

        Table 1 to Subpart TTTT of Part 60--Applicability of Subpart A General Provisions to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
    General provisions citation        Subject of citation     Applies to  subpart TTTT         Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1........................  Applicability.........  Yes.                         ......................
Sec.   60.2........................  Definitions...........  Yes........................  Additional terms
                                                                                           defined in Sec.
                                                                                           60.5580.
Sec.   60.3........................  Units and               Yes.                         ......................
                                      Abbreviations.
Sec.   60.4........................  Address...............  Yes.                         ......................
Sec.   60.5........................  Determination of        Yes.                         ......................
                                      construction or
                                      modification.
Sec.   60.6........................  Review of plans.......  Yes.                         ......................
Sec.   60.7........................  Notification and        Yes........................  Except for the
                                      Recordkeeping.                                       requirements to
                                                                                           submit written excess
                                                                                           emissions reports
                                                                                           under Sec.   60.7(c).
Sec.   60.8........................  Performance tests.....  No.                          ......................
Sec.   60.9........................  Availability of         Yes.                         ......................
                                      Information.
Sec.   60.10.......................  State authority.......  Yes.                         ......................
Sec.   60.11.......................  Compliance with         No.                          ......................
                                      standards and
                                      maintenance
                                      requirements.
Sec.   60.12.......................  Circumvention.........  Yes.                         ......................
Sec.   60.13.......................  Monitoring              Yes.                         ......................
                                      requirements.
Sec.   60.14.......................  Modification..........  No.                          ......................
Sec.   60.15.......................  Reconstruction........  No.                          ......................

[[Page 22441]]

 
Sec.   60.16.......................  Priority list.........  No.                          ......................
Sec.   60.17.......................  Incorporations by       Yes.                         ......................
                                      reference.
Sec.   60.18.......................  General control device  No.                          ......................
                                      requirements.
Sec.   60.19.......................  General notification    Yes.                         ......................
                                      and reporting
                                      requirements.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2012-7820 Filed 4-12-12; 8:45 am]
BILLING CODE 6560-50-P


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