Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units, 1429-1519 [2013-28668]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 79, Number 5 (Wednesday, January 8, 2014)]
[Proposed Rules]
[Pages 1429-1519]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-28668]



[[Page 1429]]

Vol. 79

Wednesday,

No. 5

January 8, 2014

Part II





Environmental Protection Agency





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40 CFR Parts 60, 70, 71, et al.





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

Federal Register / Vol. 79 , No. 5 / Wednesday, January 8, 2014 / 
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60, 70, 71, and 98

[EPA-HQ-OAR-2013-0495; FRL-9839-4]
RIN 2060-AQ91


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: On April 13, 2012, the EPA proposed a new source performance 
standard for emissions of carbon dioxide for new affected fossil fuel-
fired electric utility generating units. The EPA received more than 2.5 
million comments on the proposed rule. After consideration of 
information provided in those comments, as well as consideration of 
continuing changes in the electricity sector, the EPA determined that 
revisions in its proposed approach are warranted. Thus, in a separate 
action, the EPA is withdrawing the April 13, 2012, proposal, and, in 
this action, the EPA is proposing new standards of performance for new 
affected fossil fuel-fired electric utility steam generating units and 
stationary combustion turbines. This action proposes a separate 
standard of performance for fossil fuel-fired electric utility steam 
generating units and integrated gasification combined cycle units that 
burn coal, petroleum coke and other fossil fuels that is based on 
partial implementation of carbon capture and storage as the best system 
of emission reduction. This action also proposes standards for natural 
gas-fired stationary combustion turbines based on modern, efficient 
natural gas combined cycle technology as the best system of emission 
reduction. This action also includes related proposals concerning 
permitting fees under Clean Air Act Title V, the Greenhouse Gas 
Reporting Program, and the definition of the pollutant covered under 
the prevention of significant deterioration program.

DATES: Comments. Comments must be received on or before March 10, 2014. 
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 January 8, 
2014, a comment to the OMB is best assured of having its full effect if 
the OMB receives it by February 7, 2014.
    Public Hearing. A public hearing will be held on January 28, 2014, 
at the William Jefferson Clinton Building East, Room 1153 (Map Room), 
1201 Constitution Avenue NW., Washington DC 20004. The hearing will 
convene at 9:00 a.m. (Eastern Standard Time) and end at 8:00 p.m. 
(Eastern Standard Time). Please contact Pamela Garrett at (919) (541-
7966) or at garrett.pamela@epa.gov to register to speak at the hearing. 
The last day to pre-register in advance to speak at the hearing will be 
2 business days in advance of the public hearing. Additionally, 
requests to speak will be taken the day of the hearing at the hearing 
registration desk, although preferences on speaking times may not be 
able to be fulfilled. If you require the service of a translator or 
special accommodations such as audio description, please let us know at 
the time of registration.
    The hearing will provide interested parties the opportunity to 
present data, views or arguments concerning the proposed action. The 
EPA will make every effort to accommodate all speakers who arrive and 
register. Because this hearing is being held at U.S. government 
facilities, individuals planning to attend the hearing should be 
prepared to show valid picture identification to the security staff in 
order to gain access to the meeting room. In addition, you will need to 
obtain a property pass for any personal belongings you bring with you. 
Upon leaving the building, you will be required to return this property 
pass to the security desk. No large signs will be allowed in the 
building, cameras may only be used outside of the building and 
demonstrations will not be allowed on federal property for security 
reasons.
    The EPA may ask clarifying questions during the oral presentations 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral comments and 
supporting information presented at the public hearing. Commenters 
should notify Ms. Garrett if they will need specific equipment, or if 
there are other special needs related to providing comments at the 
hearing. The EPA will provide equipment for commenters to show overhead 
slides or make computerized slide presentations if we receive special 
requests in advance. Oral testimony will be limited to 5 minutes for 
each commenter. The EPA encourages commenters to provide the EPA with a 
copy of their oral testimony electronically (via email or CD) or in 
hard copy form. Verbatim transcripts of the hearings and written 
statements will be included in the docket for the rulemaking. The EPA 
will make every effort to follow the schedule as closely as possible on 
the day of the hearing; however, please plan for the hearing to run 
either ahead of schedule or behind schedule. Information regarding the 
hearing (including information as to whether or not one will be held) 
will be available at: https://www2.epa.gov/carbon-pollution-standards/.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2013-0495, by one of the following methods:
    At the Web site https://www.regulations.gov: Follow the instructions 
for submitting comments.
    At the Web site https://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-and-r-docket@epa.gov, Attn: Docket ID No. EPA-HQ-OAR-2013-0495.
    Facsimile: Fax your comments to (202) 566-9744, Attn: Docket ID No. 
EPA-HQ-OAR-2013-0495.
    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-2013-0495. 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, William Jefferson Clinton Building West, Room 3334, 1301 
Constitution Ave. NW., Washington, DC 20004, Attn: Docket ID No. EPA-
HQ-OAR-2013-0495. Such deliveries are accepted only during the Docket 
Center's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding federal holidays), and special arrangements 
should be made for deliveries of boxed information.
    Instructions: All submissions must include the agency name and 
docket ID number (EPA-HQ-OAR-2013-0495). The EPA's policy is to include 
all comments received without change, including any personal 
information provided, in the public docket, available online at https://www.regulations.gov, unless the comment includes information claimed to 
be Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through https://

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www.regulations.gov or email. Send or deliver information identified as 
CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S. EPA, Research Triangle Park, North Carolina 27711, 
Attention Docket ID No. EPA-HQ-OAR-2013-0495. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
a disk or CD-ROM that you mail to the EPA, mark the outside of the disk 
or CD-ROM as CBI and then identify electronically within the disk or 
CD-ROM the specific information you claim as CBI. In addition to one 
complete version of the comment that includes information claimed as 
CBI, you must submit a copy of the comment that does not contain the 
information claimed as CBI for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2.
    The EPA requests that you also submit a separate copy of your 
comments to the contact person identified below (see FOR FURTHER 
INFORMATION CONTACT). If the comment includes information you consider 
to be CBI or otherwise protected, you should send a copy of the comment 
that does not contain the information claimed as CBI or otherwise 
protected.
    The www.regulations.gov Web site is an ``anonymous access'' system, 
which means the EPA will not know your identity or contact information 
unless you provide it in the body of your comment. If you send an email 
comment directly to the EPA without going through https://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 https://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 https://www.regulations.gov or in hard copy at the EPA 
Docket Center, William Jefferson Clinton Building West, Room 3334, 1301 
Constitution Ave. NW., Washington, DC. The Public Reading Room is open 
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal 
holidays. The telephone number for the Public Reading Room is (202) 
566-1744, and the telephone number for the Air Docket is (202) 566-
1742. Visit the EPA Docket Center homepage at https://www.epa.gov/epahome/dockets.htm for additional information about the EPA's public 
docket.
    In addition to being available in the docket, an electronic copy of 
this proposed rule will be available on the 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: 
https://www.epa.gov/ttn/oarpg/.

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

SUPPLEMENTARY INFORMATION: Comments on the April 13, 2012 proposal. The 
EPA considered comments submitted in response to the original April 13, 
2012, proposal in developing this new proposal. However, we are 
withdrawing the original proposal. If you would like comments submitted 
on the April 13, 2012 rulemaking to be considered in connection with 
this new proposal, you should submit new comments or re-submit your 
previous comments. Commenters who submitted comments concerning any 
aspect of the original proposal will need to consider the applicability 
of those comments to this current proposal and submit them again, if 
applicable, even if the comments are exactly or substantively the same 
as those previously submitted, to ensure consideration in the 
development of the final rulemaking.
    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 Interface
CEMS Continuous Emissions Monitoring System
CFB Circulating Fluidized Bed
CH4 Methane
CHP Combined Heat and Power
CO2 Carbon Dioxide
CSAPR Cross-State Air Pollution Rule
DOE Department of Energy
DOT Department of Transportation
ECMPS Emissions Collection and Monitoring Plan System
EERS Energy Efficiency Resource Standards
EGU Electric Generating Unit
EIA Energy Information Administration
EO Executive Order
EOR Enhanced Oil Recovery
EPA Environmental Protection Agency
FB Fluidized Bed
FGD Flue Gas Desulfurization
FOAK First-of-a-kind
FR Federal Register
GHG Greenhouse Gas
GW Gigawatts
H2 Hydrogen Gas
HAP Hazardous Air Pollutant
HFC Hydrofluorocarbon
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
IRPs Integrated Resource Plans
kg/MWh Kilogram per Megawatt-hour
kJ/kg Kilojoules per Kilogram
kWh Kilowatt-hour
lb CO2/MMBtu Pounds of CO2 per Million British 
Thermal Unit
lb CO2/MWh Pounds of CO2 per Megawatt-hour
lb CO2/yr Pounds of CO2 per Year
lb/lb-mole Pounds per Pound-Mole
LCOE Levelized Cost of Electricity
MATS Mercury and Air Toxic Standards
MMBtu/hr Million British Thermal Units per Hour
MW Megawatt

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MWe Megawatt Electrical
MWh Megawatt-hour
N2O Nitrous Oxide
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NETL National Energy Technology Laboratory
NGCC Natural Gas Combined Cycle
NOAK nth-of-a-kind
NRC National Research Council
NSPS New Source Performance Standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
O2 Oxygen Gas
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbon
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
PUC Public Utilities Commission
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
RTC Response to Comments
RTP Response to Petitions
SBA Small Business Administration
SCC Social Cost of Carbon
SCR Selective Catalytic Reduction
SF6 Sulfur Hexafluoride
SIP State Implementation Plan
SNCR Selective Non-Catalytic Reduction
SO2 Sulfur Dioxide
SSM Startup, Shutdown, and Malfunction
Tg Teragram (one trillion (10\12\) grams)
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 Change Research Program
VCS Voluntary Consensus Standard
WGS Water Gas Shift
WWW Worldwide Web

    Organization of This Document. The information presented in this 
preamble is organized as follows:

I. General Information
    A. Executive Summary
    B. Overview
    C. Does this action apply to me?
II. Background
    A. Climate Change Impacts from GHG Emissions
    B. GHG Emissions from Fossil Fuel-fired EGUs
    C. The Utility Power Sector and How its Structure is Changing
    D. Statutory Background
    E. Regulatory and Litigation Background
    F. Coordination with Other Rulemakings
    G. Stakeholder Input
III. Proposed Requirements for New Sources
    A. Applicability Requirements
    B. Emission Standards
    C. Startup, Shutdown, and Malfunction Requirements
    D. Continuous Monitoring Requirements
    E. Emissions Performance Testing Requirements
    F. Continuous Compliance Requirements
    G. Notification, Recordkeeping, and Reporting Requirements
IV. Rationale for Reliance on Rational Basis To Regulate GHGs from 
Fossil-fired EGUs
    A. Overview
    B. Climate Change Impacts From GHG Emissions; Amounts of GHGs 
From Fossil Fuel-Fired EGUs
    C. CAA Section 111 Requirements
    D. Interpretation of CAA Section 111 Requirements
    E. Rational Basis To Promulgate Standards for GHGs From Fossil-
Fired EGUs
    F. Alternative Findings of Endangerment and Significant 
Contribution
    G. Comments on the State of the Science of Climate Change
V. Rationale for Applicability Requirements
    A. Applicability Requirements--Original Proposal and Comments
    B. Applicability Requirements--Today's Proposal
    C. Certain Projects Under Development
VI. Legal Requirements for Establishing Emission Standards
    A. Overview
    B. CAA Requirements and Court Interpretation
    C. Technical Feasibility
    D. Factors To Consider in Determining the ``Best System''
    E. Nationwide Component of Factors in Determining the ``Best 
System''
    F. Chevron Framework
    G. Agency Discretion
    H. Lack of Requirement That Standard Be Able To Be Met by All 
Sources
VII. Rationale for Emission Standards for New Fossil Fuel-Fired 
Boilers and IGCCs
    A. Overview
    B. Identification of the Best System of Emission Reduction
    C. Determination of the Level of the Standard
    D. Extent of Reductions in CO2 Emissions
    E. Technical Feasibility
    F. Costs
    G. Promotion of Technology
    H. Nationwide, Longer-Term Perspective
    I. Deference
    J. CCS and BSER in Locations Where Costs Are Too High To 
Implement CCS
    K. Compliance Period
    L. Geologic Sequestration
VIII. Rationale for Emission Standards for Natural Gas-Fired 
Stationary Combustion Turbines
    A. Best System of Emission Reduction
    B. Determination of the Standards of Performance
IX. Implications for PSD and Title V Programs
    A. Overview
    B. Applicability of Tailoring Rule Thresholds Under the PSD 
Program
    C. Implications for BACT Determinations Under PSD
    D. Implications for Title V Program
    E. Implications for Title V Fee Requirements for GHGs
X. Impacts of the Proposed Action
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. How will this proposal contribute to climate change 
protection?
    E. What are the economic and employment impacts?
    F. What are the benefits of the proposed standards?
XI. Request for Comments
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866, Regulatory Planning and Review, and 
Executive Order 13563, Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132, Federalism
    F. Executive Order 13175, Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045, Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898, Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
XIII. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action
    On April 13, 2012, under the authority of Clean Air Act (CAA) 
section 111, the EPA proposed a new source performance standard (NSPS) 
to limit emissions of carbon dioxide (CO2) from new fossil 
fuel-fired electric utility generating units (EGUs), including, 
primarily, coal- and natural gas-fired units (77 FR 22392). After 
consideration of the information provided in more than 2.5 million 
comments on the proposal, as well as consideration of continuing 
changes in the electricity sector, the EPA is issuing a new proposal. 
Today's action proposes to establish separate standards for fossil 
fuel-fired electric steam generating units (utility boilers and 
Integrated Gasification Combined Cycle (IGCC) units) and for natural 
gas-fired stationary combustion turbines. These proposed standards 
reflect separate determinations of the best system of emission 
reduction (BSER) adequately demonstrated for utility boilers and IGCC 
units and for natural gas-fired stationary combustion turbines. In 
contrast, the April 2012 proposal relied on a single standard and a 
single BSER determination for all new fossil fuel-

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fired units. In addition, the applicability requirements proposed today 
differ from the applicability requirements in the original proposal. In 
light of these and other differences, the EPA is issuing a document 
(published separately in today's Federal Register) that withdraws the 
original proposal, as well as issuing this new proposal.
2. Summary of the Major Provisions
    This action proposes a standard of performance for utility boilers 
and IGCC units based on partial implementation of carbon capture and 
storage (CCS) as the BSER. The proposed emission limit for those 
sources is 1,100 lb CO2/MWh.\1\ This action also proposes 
standards of performance for natural gas-fired stationary combustion 
turbines based on modern, efficient natural gas combined cycle (NGCC) 
technology as the BSER. The proposed emission limits for those sources 
are 1,000 lb CO2/MWh for larger units and 1,100 lb 
CO2/MWh for smaller units. At this time, the EPA is not 
proposing standards of performance for modified or reconstructed 
sources.
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    \1\ In this rulemaking, all references to lb CO2/MWh 
are on a gross output basis, unless specifically noted otherwise.
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3. Costs and Benefits
    As explained in the Regulatory Impact Analysis (RIA) for this 
proposed rule, available data--including utility announcements and EIA 
modeling--indicate that, even in the absence of this rule, (i) existing 
and anticipated economic conditions mean that few, if any, solid fossil 
fuel-fired EGUs will be built in the foreseeable future; and (ii) 
electricity generators are expected to choose new generation 
technologies (primarily natural gas combined cycle) that would meet the 
proposed standards. Therefore, based on the analysis presented in 
Chapter 5 of the RIA, the EPA projects that this proposed rule will 
result in negligible CO2 emission changes, quantified 
benefits, and costs by 2022.\2\ These projections are in line with 
utility announcements and Energy Information Administration (EIA) 
modeling that indicate that coal units built between now and 2020 would 
have CCS, even in the absence of this rule. However, for a variety of 
reasons, some companies may consider coal units that the modeling does 
not anticipate. Therefore, in Chapter 5 of the RIA, we also present an 
analysis of the project-level costs of a new coal-fired unit with 
partial CCS alongside the project-level costs of a new coal-fired unit 
without CCS.
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    \2\ Conditions in the analysis year of 2022 are represented by a 
model year of 2020.
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B. Overview

1. Why is the EPA issuing this proposed rule?
    Greenhouse gas (GHG) pollution \3\ threatens the American public's 
health and welfare by contributing to long-lasting changes in our 
climate that can have a range of negative effects on human health and 
the environment. The impacts could include: longer, more intense and 
more frequent heat waves; more intense precipitation events and storm 
surges; less precipitation and more prolonged drought in the West and 
Southwest; more fires and insect pest outbreaks in American forests, 
especially in the West; and increased ground level ozone pollution, 
otherwise known as smog, which has been linked to asthma and premature 
death. Health risks from climate change are especially serious for 
children, the elderly and those with heart and respiratory problems.
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    \3\ Greenhouse gas pollution is the aggregate group of the 
following gases: CO2, methane (CH4), nitrous 
oxide (N2O), sulfur hexafluoride (SF6), 
hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).
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    The U.S. Supreme Court ruled that GHGs meet the definition of ``air 
pollutant'' in the CAA, and this decision clarified that the CAA's 
authorities and requirements apply to GHG emissions. Unlike most other 
air pollutants, GHGs may persist in the atmosphere from decades to 
millennia, depending on the specific greenhouse gas. This special 
characteristic makes it crucial to take initial steps now to limit GHG 
emissions from fossil fuel-fired power plants, specifically emissions 
of CO2, since they are the nation's largest sources of 
carbon pollution. This rule will ensure that the next generation of 
fossil fuel-fired power plants in this country will use modern 
technologies that limit harmful carbon pollution.
    On April 13, 2012, the EPA issued a proposed rule to limit GHG 
emissions from fossil fuel-fired power plants by establishing a single 
standard applicable to all new fossil fuel-fired EGUs serving 
intermediate and base load power demand. After consideration of the 
information provided in more than 2.5 million comments on the proposal, 
as well as consideration of continuing changes in the electricity 
sector,\4\ the EPA is issuing a new proposal to establish separate 
standards for fossil fuel-fired electric steam generating units 
(utility boilers and IGCC units) and for natural gas-fired stationary 
combustion turbines. These proposed standards reflect separate 
determinations of the BSER adequately demonstrated for utility boilers 
and IGCC units and for natural gas-fired stationary combustion 
turbines. Because, in contrast, the April 2012 proposal relied on a 
single standard for all new fossil fuel-fired units, the EPA is 
issuing, as a final action, a document (published separately in today's 
Federal Register) that withdraws the original proposal, as well as 
issuing this new proposal.
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    \4\ For example, since April 2012, there has been significant 
progress on two CCS projects (Kemper County and Boundary Dam), and 
they are now both over 75 percent complete. Two other projects have 
continued to make progress toward construction (Texas Clean Energy 
Project and Hydrogen Energy California Project).
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2. What authority is the EPA relying on to address power plant 
CO2 emissions?
    Congress established requirements under section 111 of the 1970 CAA 
to control air pollution from new stationary sources through NSPS. 
Specifically, section 111 requires the EPA to set technology-based 
standards for new stationary sources to minimize emissions of air 
pollution to the environment. For more than four decades, the EPA has 
used its authority under section 111 to set cost-effective emission 
standards that ensure newly constructed sources use the best performing 
technologies to limit emissions of harmful air pollutants. In this 
proposal, the EPA is following the same well-established, customary 
interpretation and application of the law under section 111 to address 
GHG emissions from new fossil fuel-fired power plants.
3. What sources should the EPA include as it develops proposed 
standards for GHGs for power plants?
    Before determining the appropriate technologies and levels of 
control that represent BSER for GHG emissions, the EPA must first 
identify the appropriate sources to control.
    The starting point is to consider whether, given current trends 
concerning coal-fired and natural gas-fired power plants and the nature 
of GHGs, the EPA should regulate CO2 from these power plants 
through the same NSPS regulatory structure that EPA has established for 
conventional pollutants. The EPA's NSPS regulations already regulate 
conventional pollutants from these sources under two 40 CFR part 60 
subparts: subpart Da, electric utility steam generating units, which 
includes both steam electric utility boilers and IGCC units, and 
subpart KKKK, stationary combustion turbines, which includes both 
simple cycle and combined cycle stationary combustion turbines.
    For sources covered under subpart Da, the original proposal relied 
on analyses,

[[Page 1434]]

primarily undertaken by EIA, indicating that, while substantial 
reliance on coal-fired electricity generation would continue in the 
future, few, if any, new coal-fired power plants were likely to be 
built by 2025. Based in part on these results, the EPA concluded that 
it was appropriate to propose in April 2012 a single fuel-neutral 
standard covering all intermediate and base load units based on the 
performance of recently constructed NGCC units. In light of 
developments in the electricity sector since the April 2012 proposal, 
and in response to numerous comments on the proposal itself, the EPA is 
changing the approach in today's document and proposing to set separate 
standards for new sources covered by subpart Da.\5\
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    \5\ While the emphasis of EPA's BSER determination is on coal- 
and petcoke-fired units, the subpart covers all fossil fuel-fired 
EGU boilers and IGCC units, including those burning oil and gas.
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    The EPA notes that, since the original April 2012 proposal, a few 
coal-fired units have reached the advanced stages of construction and 
development, which suggests that proposing a separate standard for 
coal-fired units is appropriate. Since the original proposal, progress 
on Southern Company's Kemper County Energy Facility, an IGCC facility 
that will implement partial CCS, has continued, and the project is now 
over 75 percent complete. Similarly, SaskPower's Boundary Dam CCS 
Project in Estevan, Saskatchewan, a project that will fully integrate 
the rebuilt 110 MW coal-fired Unit 3 with available CCS 
technology to capture 90 percent of its CO2 emissions, is 
more than 75 percent complete. Performance testing is expected to 
commence in late 2013 and the facility is expected to be fully 
operational in 2014.
    Additionally, two other IGCC projects, Summit Power's Texas Clean 
Energy Project (TCEP) and the Hydrogen Energy California Project 
(HECA)--both of which are IGCC units with CCS--continue to move 
forward. Further, NRG Energy is developing a commercial-scale post-
combustion carbon capture project at the company's W.A. Parish 
generating station southwest of Houston, Texas. The facility is 
expected to be operational in 2015. Continued progress on these 
projects is consistent with the EIA modeling which projects that few, 
if any, new coal-fired EGUs would be built in this decade and that 
those that are built would include CCS.\6\ The existence and apparent 
ongoing viability of these projects which include CCS justify a 
separate BSER determination for new fossil fuel-fired utility boilers 
and IGCC power plants.
---------------------------------------------------------------------------

    \6\ Even in its sensitivity analysis, the EIA does not project 
any additional coal projects beyond its reference case until 2023, 
in a case where power companies assume no emission limitations for 
GHGs, and until 2024 in any sensitivity analysis in which there are 
emission limitations for GHGs.
---------------------------------------------------------------------------

    In addition to these projects, a number of commenters (on the April 
2012 proposal) noted that, if natural gas prices increase, there could 
be greater interest in the construction of additional coal-fired 
generation capacity. This, too, is consistent with the EIA analysis, 
which also suggests that, in a limited number of potential scenarios 
generally associated with both significantly higher than anticipated 
electric demand and significantly higher than expected natural gas 
prices, some additional new coal-fired generation capacity may be built 
beyond 2020. It is also consistent with publicly available electric 
utility Integrated Resource Plans (IRPs).\7\
---------------------------------------------------------------------------

    \7\ IRPs are planning documents that many Public Utility 
Commissions require utilities to file outlining their plans to meet 
future demand. Many of the IRPs that the EPA has reviewed included 
planning horizons of ten years or more.
---------------------------------------------------------------------------

    Many of those IRPs indicated the utilities' interest in developing 
some amount of generating capacity using other intermediate-load and 
base load technologies, in addition to new NGCC capacity, to meet 
future demand (albeit, almost always at a higher cost than NGCC 
technology). Only a few utilities' IRPs indicated that new coal-fired 
generation without CCS was a technology option that was being 
considered to meet future demand. Finally, a number of commenters 
suggested that it was important to set standards that preserve options 
for fuel diversity, particularly if natural gas prices exceed projected 
levels. Given this information, the EPA believes that it is appropriate 
to set a separate standard for solid fossil fuel-fired EGUs, both to 
address the small number of coal plants that evidence suggests might 
get built and to set a standard that is robust across a full range of 
possible futures in the energy and electricity sectors.
    Utility announcements about the status of coal projects, IRPs, and 
EIA projections suggest that, by far, the largest sources of new fossil 
fuel-fired electricity generation are likely to be NGCC units. The EPA 
believes, therefore, that it is also appropriate to set a standard for 
stationary combustion turbines used as EGUs. These units are currently 
covered under subpart KKKK (stationary combustion turbines).
    The EPA also proposes to maintain the definition of EGUs under the 
NSPS that differentiates between EGUs (sources used primarily for 
generating electricity for sale to the grid) and non-EGUs (turbines 
primarily used to generate steam and/or electricity for on-site use). 
That definition defines EGUs as units that sell more than one-third of 
their potential electric output to the grid. Under this definition, 
most simple cycle ``peaking'' stationary combustion turbines, which 
typically sell significantly less than one-third of their potential 
electric output to the grid, would not be affected by today's proposal.
    Finally, the EPA is not proposing standards today for one 
conventional coal-fired EGU project which, based on current 
information, appears to be the only such project under development that 
has an active air permit and that has not already commenced 
construction for NSPS purposes. If the EPA observes that the project is 
truly proceeding, it may propose a new source performance standard 
specifically for that source at the time the EPA finalizes today's 
proposed rule.
4. What is the EPA's general approach to setting standards for new 
sources under Section 111(b)?
    Section 111(b) requires the EPA to identify the ``best system of 
emission reduction [hellip] adequately demonstrated'' (BSER) available 
to limit pollution. The CAA and subsequent court decisions (detailed 
later in this notice) identify the factors for the EPA to consider in a 
BSER determination. For this rulemaking, the following factors are key: 
feasibility, costs, size of emission reductions and technology.
    Feasibility: The EPA considers whether the system of emission 
reduction is technically feasible.
    Costs: The EPA considers whether the costs of the system are 
reasonable.
    Size of emission reductions: The EPA considers the amount of 
emissions reductions that the system would generate.
    Technology: The EPA considers whether the system promotes the 
implementation and further development of technology.
    After considering these four factors, we propose that efficient 
generation technology implementing partial CCS is the BSER for new 
affected fossil fuel-fired boilers and IGCC units (subpart Da sources) 
and modern, efficient NGCC technology is the BSER for new affected 
combustion turbines (subpart KKKK sources). The foundations for these 
determinations are described in Sections VII and VIII.
5. What is BSER for new fossil fuel-fired utility boilers and IGCC 
units?
    Power generated from the combustion or gasification of coal emits 
more CO2 than power generated from the combustion of natural 
gas or by other

[[Page 1435]]

means, such as solar or wind. If any new coal-fired unit is built, its 
CO2 emissions would be approximately double that of a new 
NGCC unit of comparable capacity. Thus, it is important to set a 
standard for any new coal plant that might be built.
    The three alternatives the EPA considered in the BSER analysis for 
new fossil fuel-fired utility boilers and IGCC units are: (1) highly 
efficient new generation that does not include CCS technology, (2) 
highly efficient new generation with ``full capture'' CCS and (3) 
highly efficient new generation with ``partial capture'' CCS.
    Generation technologies representing enhancements in operational 
efficiency (e.g., supercritical or ultra-supercritical coal-fired 
boilers or IGCC units) are clearly technically feasible and present 
little or no incremental cost compared to the types of technologies 
that some companies are considering for new coal-fired generation 
capacity. However, they do not provide meaningful reductions in 
CO2 emissions from new sources. Efficiency-improvement 
technologies alone result in only very small reductions (several 
percent) in CO2 emissions, especially in contrast to those 
achieved by the application of CCS. Determining that these high-
efficiency generating technologies represent the BSER for 
CO2 emissions from coal-fired generation would fail to 
promote the development and deployment of CO2 pollution-
reduction technology from power plants. In fact, a determination that 
this efficiency-enhancing technology alone, as opposed to CCS, is the 
BSER for CO2 emissions from new coal-fired generation likely 
would inhibit the development of technology that could reduce 
CO2 emissions significantly, thus defeating one of the 
purposes of the CAA's NSPS provisions. For example, during its pilot-
scale CCS demonstration at the Mountaineer Plant in New Haven, WV, 
American Electric Power (AEP) announced in 2011 that it was placing on 
hold its plans to scale-up the CCS system, citing the uncertain status 
of U.S. climate policy as a key contributing factor to its decision.
    An assessment of the technical feasibility and availability of CCS 
indicates that nearly all of the coal-fired power plants that are 
currently under development are designed to use some type of CCS. In 
most cases, the projects will sell or use the captured CO2 
to generate additional revenue. These projects include the following 
(note that each of the projects has obtained some governmental 
financial assistance):
    Southern Company's Kemper County Energy Facility, a 582 MW IGCC 
power plant that is currently under construction in Kemper County, 
Mississippi. The plant will include a CCS system designed to capture 
approximately 65 percent of the produced CO2.
    SaskPower's Boundary Dam CCS Project, in Estevan, Saskatchewan, 
Canada, is a commercial-scale CCS project that will fully integrate the 
rebuilt 110 MW coal-fired Unit 3 with available CCS technology 
to capture 90 percent of its CO2 emissions.
    Texas Clean Energy Project (TCEP), an IGCC plant near Odessa, 
Texas, that is under development by the Summit Power Group, Inc. 
(Summit). TCEP is a 400 MW IGCC plant that expects to capture 
approximately 90 percent of the produced CO2.
    Hydrogen Energy California, LLC (HECA), is proposing to build a 
plant similar to TCEP in western Kern County, California. The HECA 
plant is an IGCC plant fueled by coal and petroleum coke that will 
produce 300 MW of power and will capture CO2 for use in 
enhanced oil recovery (EOR) operations. They expect to capture 
approximately 90 percent of the produced CO2.
    The above examples suggest that project developers who are 
incorporating CCS generally considered two variants: either a partial 
CCS system or a full CCS system (i.e., usually 90 percent capture or 
greater). Therefore, the EPA considered both options.
    In assessing whether the cost of a certain option is reasonable, 
the EPA first considered the appropriate frame of reference. Power 
companies often choose the lowest cost form of generation when 
determining what type of new generation to build. Based on both the EIA 
modeling and utility IRPs, there appears to be a general acceptance 
that the lowest cost form of new power generation is NGCC.
    Many states find value in coal investments and have policies and 
incentives to encourage coal energy generation. Utility IRPs (as well 
as comments on the April 2012 proposal) suggest that many companies 
also find value in other factors, such as fuel diversity, and are often 
willing to pay a premium for it. Utility IRPs suggest that a range of 
technologies can meet the preference for fuel diversity from a 
dispatchable form of generation that can provide intermediate or base-
load power, including coal without CCS, coal with CCS and nuclear. 
Biomass-fired power generation \8\ and geothermal power generation are 
other technologies that are dispatchable and that could potentially 
meet this objective. These technologies all cost significantly more 
than natural gas-fired generation, which ranges from a levelized cost 
of electricity (LCOE) \9\ of $59/MWh to $86/MWh, depending upon 
assumptions about natural gas prices. In assessing whether the cost of 
coal with CCS would have an unreasonable impact on the cost of power 
generation, the EPA believes it is appropriate to compare coal with CCS 
to this range of non-natural gas-fired electricity generation options. 
Based on data from the EIA and the DOE National Energy and Technology 
Laboratory (NETL), the EPA believes that the levelized cost of 
technologies other than coal with CCS and NGCC range from $80/MWh to 
$130/MWh. These include nuclear, from $103/MWh to $114/MWh; biomass, 
from $97/MWh to $130/MWh; and geothermal, from $80/MWh to $99/MWh.
---------------------------------------------------------------------------

    \8\ The proposed CO2 emission standards would only 
apply to new fossil fuel-fired EGUs. New EGUs that primarily fire 
biomass would not be subject to these proposed standards.
    \9\ The levelized cost of electricity is an economic assessment 
of the cost of electricity from a new generating unit or plant, 
including all the costs over its lifetime: initial investment, 
operations and maintenance, cost of fuel, and cost of capital. The 
LCOE value presented here are in $2007.
---------------------------------------------------------------------------

    The EPA believes the cost of ``full capture'' CCS without EOR is 
outside the range of costs that companies are considering for 
comparable generation and therefore should not be considered BSER for 
CO2 emissions for coal-fired power plants. The EPA projects 
the LCOE of generation technologies with full capture CCS to be in the 
range of $136/MWh to $147/MWh (without EOR benefits).\10\ Because these 
``full capture'' CCS costs without EOR are significantly above the 
price range of potential alternative generation options, the EPA 
believes that full capture CCS does not meet the cost criterion of 
BSER.
---------------------------------------------------------------------------

    \10\ The cost assumptions and technology configurations for 
these cost estimates are provided in the DOE/NETL ``Cost and 
Performance Baseline'' reports. For these cost estimates, we used 
costs for new SCPC and IGCC units utilizing bituminous coal from the 
reports ``Cost and Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity'', Revision 
2, Report DOE/NETL-2010/1397 (November 2010) and ``Cost and 
Performance of PC and IGCC Plants for a Range of Carbon Dioxide 
Capture'', DOE/NETL-2011/1498, May 27, 2011. Additional cost and 
performance information can be found in additional volumes that are 
available at https://www.netl.doe.gov/energy-analyses/baseline_studies.html.
---------------------------------------------------------------------------

    Finally, the EPA considered whether implementation of ``partial 
capture'' CCS should be proposed to be BSER for new fossil fuel-fired 
utility boilers and IGCC units.
    Partial capture CCS has been implemented successfully in a number 
of facilities over many years. The Great

[[Page 1436]]

Plains Synfuels Facility \11\ is a coal gasification facility that has 
captured at least 50 percent of its produced CO2 for use in 
EOR operations since 2000. Projects such as AEP Mountaineer have 
successfully demonstrated the performance of partial capture CCS on a 
significant portion of their exhaust stream. The Southern Company 
Kemper County Energy Facility will use partial CCS to capture 
approximately 65 percent of the produced CO2 for use in 
nearby EOR operations. The facility is now more than 75 percent 
complete and is expecting to begin operation in 2014. The Global CCS 
Institute maintains a database of international CCS projects in various 
stages of development.\12\
---------------------------------------------------------------------------

    \11\ While this facility is not an EGU, it has significant 
similarities to a coal gasification combined cycle EGU, and the 
implementation of the partial CCS technology would be similar enough 
for comparison.
    \12\ The Global CCS Institute, https://www.globalccsinstitute.com/projects/browse.
---------------------------------------------------------------------------

    The EPA analysis shows that the costs of partial CCS are comparable 
to costs of other non-NGCC generation. The EPA projects LCOE generation 
ranging from $92/MWh to $110/MWh, depending upon assumptions about 
technology choices and the amount, if any, of revenue from sale of 
CO2 for EOR. This range compares to levelized costs in a 
range of $80/MWh to $130/MWh for various forms of other non-natural 
gas-fired electricity generation. When considered against the range of 
costs that would be incurred by projects deploying non-natural gas-
fired electricity generation, the implementation costs of partial CCS 
are reasonable.
    The projects in development for new coal-fired generation are few 
in number, and most would already meet an emission limit based on 
implementation of CCS.\13\ As a result, a standard based on partial CCS 
would not have a significant impact on nationwide energy prices. 
Moreover, the fact that IGCC developers could meet the requirements of 
the standard through the use of a conventional turbine (i.e., a syngas 
turbine, rather than a more advanced hydrogen turbine) reinforces both 
the technical feasibility and cost basis of today's proposal to 
determine that CCS with partial capture is the BSER.
---------------------------------------------------------------------------

    \13\ For example, the Hydrogen Energy California facility plans 
to capture approximately 90 percent of the CO2 in the 
emission stream.
---------------------------------------------------------------------------

    Partial CCS designed to meet an emission standard of 1,100 lb 
CO2/MWh would also achieve significant emission reductions, 
emitting on the order of 30 to 50 percent less CO2 than a 
coal-fired unit without CCS. Finally, a standard based on partial CCS 
clearly promotes implementation and further development of CCS 
technologies, and does so as much as, and perhaps even more than, a 
standard based on a full capture CCS requirement would.
    After conducting a BSER analysis of the three options described 
above, the EPA proposes that new fossil fuel-fired utility boilers and 
IGCC units implementing partial CCS best meets the requirements for 
BSER. It ensures that any new fossil fuel-fired utility boiler or IGCC 
unit will achieve meaningful emission reductions in CO2, and 
it will also encourage greater use, development, and refinement of CCS 
technologies. CCS technology has been adequately demonstrated, and its 
implementation costs are reasonable. Therefore, the EPA is basing the 
standards for new fossil fuel-fired utility boilers and IGCC units on 
partial CCS technology operating to a level of 1,100 lb CO2/
MWh.
6. What is BSER for natural gas-fired stationary combustion turbines?
    We considered two alternatives in evaluating the BSER for new 
fossil fuel-fired stationary combustion turbines: (1) modern, efficient 
NGCC units and (2) modern, efficient NGCC units with CCS.
    NGCC units are the most common type of new fossil fuel-fired units 
being planned and built today. The technology is in wide use. Nearly 
all new fossil fuel-fired EGUs being constructed today are using this 
advanced, efficient system for generating intermediate and base load 
power. Importantly, NGCC is an inherently lower CO2-emitting 
technology. Almost every natural gas-fired stationary combined cycle 
unit built in the U.S. in the last five years emits approximately 50 
percent less CO2 per MWh than a typical new coal-fired plant 
of the same size. The design is technically feasible, and evidence 
shows that NGCC units are currently the lowest-cost, most efficient 
option for new fossil fuel-fired power generation.
    By contrast, NGCC with CCS is not a configuration that is being 
built today. The EPA considered whether NGCC with CCS could be 
identified as the BSER adequately demonstrated for new stationary 
combustion turbines, and we decided that it could not. At this time, 
CCS has not been implemented for NGCC units, and we believe there is 
insufficient information to make a determination regarding the 
technical feasibility of implementing CCS at these types of units. The 
EPA is aware of only one NGCC unit that has implemented CCS on a 
portion of its exhaust stream. This contrasts with coal units where, in 
addition to demonstration projects, there are several full-scale 
projects under construction and a coal gasification plant which has 
been demonstrating much of the technology needed for an IGCC to capture 
CO2 for more than ten years. The EPA is not aware of any 
demonstrations of NGCC units implementing CCS technology that would 
justify setting a national standard. Further, the EPA does not have 
sufficient information on the prospects of transferring the coal-based 
experience with CCS to NGCC units. In fact, CCS technology has 
primarily been applied to gas streams that have a relatively high to 
very high concentration of CO2 (such as that from a coal 
combustion or coal gasification unit). The concentration of 
CO2 in the flue gas stream of a coal combustion unit is 
normally about four times higher than the concentration of 
CO2 in a natural gas-fired unit. Natural gas-fired 
stationary combustion turbines also operate differently from coal-fired 
boilers and IGCC units of similar size. The NGCC units are more easily 
cycled (i.e., ramped up and down as power demands increase and 
decrease). Adding CCS to a NGCC may limit the operating flexibility in 
particular during the frequent start-ups/shut-downs and the rapid load 
change requirements.\14\ This cyclical operation, combined with the 
already low concentration of CO2 in the flue gas stream, 
means that we cannot assume that the technology can be easily 
transferred to NGCC without larger scale demonstration projects on 
units operating more like a typical NGCC. This would be true for both 
partial and full capture.
---------------------------------------------------------------------------

    \14\ ``Operating Flexibility of Power Plants with CCS'', 
International Energy Agency (IEAGHG) report 2012/6, June 2012.
---------------------------------------------------------------------------

    After considering both technology options, the EPA is proposing to 
find modern, efficient NGCC technology to be the BSER for stationary 
combustion turbines, and we are basing the proposed standards on the 
performance of recently constructed NGCC units. The EPA is proposing 
that larger units be required to meet a standard of 1,000 lb 
CO2/MWh and that smaller units (typically slightly less 
efficient, as noted in comments on the original proposal) be required 
to meet a standard of 1,100 lb CO2/MWh.
7. How is EPA proposing to codify the requirements?
    The EPA is considering two options for codifying the requirements. 
Under the first option EPA is proposing to codify the standards of 
performance for the respective sources within existing 40 CFR Part 60 
subparts. Applicable

[[Page 1437]]

GHG standards for electric utility steam generating units would be 
included in subpart Da and applicable GHG standards for stationary 
combustion turbines would be included in subpart KKKK. In the second 
option, the EPA is co-proposing to create a new subpart TTTT (as in the 
original proposal for this rulemaking) and to include all GHG standards 
of performance for covered sources in that newly created subpart. 
Unlike the original proposal, the subpart would contain two different 
categories, one for utility boilers and IGCC units and one for natural 
gas-fired stationary combustion turbines.
8. What is the organization and approach for the proposal?
    This action presents the EPA's proposed approach for setting 
standards of performance for new affected fossil fuel-fired electric 
utility steam generating units (utility boilers) and stationary 
combustion turbines. The rationale for regulating GHG emissions from 
the utility power sector, including related regulatory and litigation 
background and relationship to other rulemakings, is presented below in 
Section II. The specific proposed requirements for new sources are 
described in detail in Section III. The rationale for reliance on a 
rational basis to regulate GHG emissions from fossil fuel-fired EGUs is 
presented in Section IV, followed by the rationale for applicability 
requirements in Section V. The legal requirements for establishing 
emission standards are discussed in detail in Section VI. Sections VII 
and VIII describe the rationale for each of the proposed emission 
standards, including an explanation of the determination of BSER for 
new fossil fuel-fired utility boilers and IGCC units and for natural 
gas-fired stationary combustion turbines, respectively. Implications 
for Prevention of Significant Deterioration (PSD) and title V programs 
are described in Section IX, and impacts of the proposed action are 
described in Section X. In Section XI, the agency specifically requests 
comments on the proposal. A discussion of statutory and executive order 
reviews is provided in Section XII, and the statutory authority for 
this action is provided in Section XIII. Also published today in the 
Federal Register is the document withdrawing the original April 13, 
2012 proposal.
    Today's proposal outlines an approach for setting standards of 
performance for emissions of carbon dioxide for new affected fossil 
fuel-fired electric utility steam generating units (utility boilers) 
and stationary combustion turbines.

C. 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      Affected Entities
------------------------------------------------------------------------
Industry.........................       221112  Fossil fuel electric
                                                 power generating units.
Federal Government...............   \b\ 221112  Fossil fuel electric
                                                 power generating units
                                                 owned by the federal
                                                 government.
State/Local Government...........   \b\ 221112  Fossil fuel electric
                                                 power generating units
                                                 owned by
                                                 municipalities.
Tribal Government................       921150  Fossil fuel electric
                                                 power generating units
                                                 in Indian Country.
------------------------------------------------------------------------
a Includes 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

    In this section we discuss climate change impacts from GHG 
emissions, both on public health and public welfare, and the science 
behind the agency's conclusions. We present information about GHG 
emissions from fossil-fuel fired EGUs, and we describe the utility 
power sector and its changing structure. We then provide the statutory, 
regulatory, and litigation background for this proposed rule. We close 
this section by discussing how this proposed rule coordinates with 
other rulemakings and describing actions to obtain stakeholder input on 
this topic and the original proposed rule.

A. Climate Change Impacts From GHG Emissions

    In 2009, the EPA Administrator issued the document we refer to as 
the Endangerment Finding under CAA section 202(a)(1).\15\ In the 
Endangerment Finding, which focused on public health and public welfare 
impacts within the United States, the Administrator found that elevated 
concentrations of GHGs in the atmosphere may reasonably be anticipated 
to endanger public health and welfare of current and future 
generations. We summarize these adverse effects on public health and 
welfare briefly here and in more detail in the RIA.
---------------------------------------------------------------------------

    \15\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Anthropogenic emissions of GHGs and consequent climate change 
threaten public health in multiple aspects. By raising average 
temperatures, climate change increases the likelihood of heat waves, 
which are associated with increased deaths and illnesses. While climate 
change also leads to reductions in cold-related mortality, evidence 
indicates that the increases in heat mortality will be larger than the 
decreases in cold mortality. Climate change is expected to increase 
ozone pollution over broad areas of the country, including large 
population areas with already unhealthy surface ozone levels, and 
thereby increase morbidity and mortality. Other 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. 
Increased coastal storms and storm surges due to rising sea levels are 
expected to cause increased drownings and other health

[[Page 1438]]

impacts. Children, the elderly, and the poor are among the most 
vulnerable to these climate-related health effects.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
    Anthropogenic emissions of GHGs and consequent climate change also 
threaten public welfare in multiple aspects. Climate changes are 
expected to place large areas of the country at serious risk of reduced 
water supplies, increased water pollution, and increased occurrence of 
extreme events such as floods and droughts. Coastal areas are expected 
to face increased risks from storm and flooding damage to property, as 
well as adverse impacts from rising sea level, such as land loss due to 
inundation, erosion, wetland submergence and habitat loss. Climate 
change is expected to result in an increase in peak electricity demand, 
and extreme weather from climate change threatens energy, 
transportation, and water resource infrastructure. Climate change may 
exacerbate ongoing environmental pressures in certain settlements, 
particularly in Alaskan indigenous communities. Climate change also is 
very likely to fundamentally rearrange U.S. ecosystems over the 21st 
century. Though some benefits may balance adverse effects on 
agriculture and forestry in the next few decades, the body of evidence 
points towards increasing risks of net adverse impacts on U.S. food 
production, agriculture and forest productivity as temperature 
continues to rise. These impacts are global and may exacerbate problems 
outside the U.S. that raise humanitarian, trade, and national security 
issues for the U.S.
3. The Science Upon Which the Agency Relies
    The EPA received comments in response to the April 2012 proposed 
NSPS rule (77 FR 22392) that addressed the scientific underpinnings of 
the EPA's 2009 Endangerment Finding and hence the proposed rule. The 
EPA carefully reviewed all of those comments. It is important to place 
these comments in the context of the history and associated voluminous 
record on this subject that has been compiled over the last few years, 
including: (1) the process by which the Administrator reached the 
Endangerment Finding in 2009; (2) the EPA's response in 2010 to ten 
administrative petitions for reconsideration of the Endangerment 
Finding (the Reconsideration Denial) \16\; and (3) the decision by the 
United States Court of Appeals for the District of Columbia Circuit 
(the D.C. Circuit or the Court) in 2012 to uphold the Endangerment 
Finding and the Reconsideration Denial.17 18
---------------------------------------------------------------------------

    \16\ ``EPA's Denial of the Petitions to Reconsider the 
Endangerment and Cause or Contribute Findings for Greenhouse Gases 
Under Section 202(a) of the Clean Air Act,'' 75 FR 49557 (Aug. 13, 
2010) (``Reconsideration Denial'').
    \17\ Coalition for Responsible Regulation, Inc. v. Environmental 
Protection Agency (CRR), 684 F.3d at 102 (D.C. Cir.), reh'g en banc 
denied, 2012 U.S. App. LEXIS 25997, 26313 (D.C. Cir. 2012), 
petitions for cert. filed, No. 12-1253 (U.S. Apr. 2013).
    \18\ We discuss litigation history involving this rulemaking in 
more detail later in this section.
---------------------------------------------------------------------------

    As outlined in Section VIII.A. of the 2009 Endangerment Finding, 
the EPA's approach to providing the technical and scientific 
information to inform the Administrator's judgment regarding the 
question of whether GHGs endanger public health and welfare was to rely 
primarily upon the recent, major assessments by the U.S. Global Change 
Research Program (USGCRP), the Intergovernmental Panel on Climate 
Change (IPCC), and the National Research Council (NRC) of the National 
Academies. These assessments addressed the scientific issues that the 
EPA was required to examine, were comprehensive in their coverage of 
the GHG and climate change issues, and underwent rigorous and exacting 
peer review by the expert community, as well as rigorous levels of U.S. 
government review. The EPA received thousands of comments on the 
proposed Endangerment Finding and responded to them in depth in an 11-
volume Response to Comments (RTC) document.\19\ While the EPA gave 
careful consideration to all of the scientific and technical 
information received, the agency placed less weight on the much smaller 
number of individual studies that were not considered or reflected in 
the major assessments; often these studies were published after the 
submission deadline for those larger assessments. Primary reliance on 
the major scientific assessments provided the EPA greater assurance 
that it was basing its judgment on the best available, well-vetted 
science that reflected the consensus of the climate science community. 
The EPA reviewed individual studies not incorporated in the assessment 
literature largely to see if they would lead the EPA to change its 
interpretation of, or place less weight on, the major findings 
reflected in the assessment reports. From its review of individual 
studies submitted by commenters, the EPA concluded that these studies 
did not change the various conclusions and judgments the EPA drew from 
the more comprehensive assessment reports. The major findings of the 
USGCRP, IPCC, and NRC assessments supported the EPA's determination 
that GHGs threaten the public health and welfare of current and future 
generations. The EPA presented this scientific support at length in the 
Endangerment Finding, in its Technical Support Document (which 
summarized the findings of USGCRP, IPCC and NRC) \20\ and in the RTC.
---------------------------------------------------------------------------

    \19\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases under Section 202(a) of the Clean Air Act: EPA's 
Response to Public Comments,'' https://www.epa.gov/climatechange/endangerment/#comments (``Response to Comments'' or ``RTC'').
    \20\ ``Technical Support Document for Endangerment and Cause or 
Contribute Findings for Greenhouse Gases under Section 202(s) of the 
Clean Air Act (Dec. 7, 2009), https://www.epa.gov/climatechange/Downloads/endangerment/Endangerment_TSD.pdf (TSD).
---------------------------------------------------------------------------

    The EPA then reviewed ten administrative petitions for 
reconsideration of the Endangerment Finding in 2010. In the 
Reconsideration Denial, the Administrator denied those petitions on the 
basis that the Petitioners failed to provide substantial support for 
the argument that the EPA should revise the Endangerment Finding and 
therefore their objections were not of ``central relevance'' to the 
Finding. The EPA prepared an accompanying three-volume Response to 
Petitions (RTP) document to provide additional information, often more 
technical in nature, in response to the arguments, claims, and 
assertions by the petitioners to reconsider the Endangerment 
Finding.\21\
---------------------------------------------------------------------------

    \21\ https://www.epa.gov/climatechange/endangerment/petitions.html.
---------------------------------------------------------------------------

    The 2009 Endangerment Finding and the 2010 Reconsideration Denial 
were challenged in a lawsuit before the D.C. Circuit. On June 26, 2012, 
the Court upheld the Endangerment Finding and the Reconsideration 
Denial, ruling that the Finding (including the Reconsideration Denial) 
was not arbitrary or capricious, was consistent with the U.S. Supreme 
Court's decision in Massachusetts v. EPA, which granted to the EPA the 
authority to regulate GHGs,\22\ and was adequately supported by the 
administrative record.\23\ The Court found that the EPA had based its 
decision on ``substantial scientific evidence'' and noted that the 
EPA's reliance on assessments was consistent with the methods decision-
makers often use to make a science-based judgment.\24\ The Court also 
agreed with the EPA that the Petitioners had ``not provided substantial 
support for their argument

[[Page 1439]]

that the Endangerment Finding should be revised.'' \25\ Moreover, the 
Court supported the EPA's reliance on the major scientific assessment 
reports conducted by USGCRP, IPCC, and NRC and found that:
---------------------------------------------------------------------------

    \22\ 549 U.S. 497 (2007).
    \23\ CRR, 684 F.3d at 117-27.
    \24\ Id. at 121.
    \25\ Id. at 125.

    The EPA evaluated the processes used to develop the various 
assessment reports, reviewed their contents, and considered the 
depth of the scientific consensus the reports represented. Based on 
these evaluations, the EPA determined the assessments represented 
the best source material to use in deciding whether GHG emissions 
may be reasonably anticipated to endanger public health or 
welfare.\26\
---------------------------------------------------------------------------

    \26\ Id. at 120.

---------------------------------------------------------------------------
    As the Court stated--

    It makes no difference that much of the scientific evidence in 
large part consisted of `syntheses' of individual studies and 
research. Even individual studies and research papers often 
synthesize past work in an area and then build upon it. This is how 
science works. The EPA is not required to re-prove the existence of 
the atom every time it approaches a scientific question.\27\
---------------------------------------------------------------------------

    \27\ Id. at 120.

    In the context of this extensive record and the recent affirmation 
of the Endangerment Finding by the Court, the EPA considered all of the 
submitted comments and reports for the April 2012 proposed NSPS rule. 
As it did in the Endangerment Finding, the EPA gave careful 
consideration to all of the scientific and technical comments and 
information in the record. The major peer-reviewed scientific 
assessments, however, continue to be the primary scientific and 
technical basis for the Administrator's judgment regarding the threats 
to public health and welfare posed by GHGs.
    Commenters submitted two major peer-reviewed scientific assessments 
released after the administrative record concerning the Endangerment 
Finding closed following the EPA's 2010 Reconsideration Denial: the 
IPCC's 2012 ``Special Report on Managing the Risks of Extreme Events 
and Disasters to Advance Climate Change Adaptation'' (SREX) and the 
NRC's 2011 ``Report on Climate Stabilization Targets: Emissions, 
Concentrations, and Impacts over Decades to Millennia'' (Climate 
Stabilization Targets).
    According to the IPCC in the SREX, ``A changing climate leads to 
changes in the frequency, intensity, spatial extent, duration, and 
timing of extreme weather and climate events, and can result in 
unprecedented extreme weather and climate events.\28\'' The SREX 
documents observational evidence of changes in some weather and climate 
extremes that have occurred globally since 1950. The assessment also 
provides evidence regarding the cause of some of these changes to 
elevated concentrations of GHGs, including warming of extreme daily 
temperatures, intensified extreme precipitation events, and increases 
in extreme coastal high water levels due to rising sea level. The SREX 
projects further increases in some extreme weather and climate events 
during the 21st century. Combined with increasing vulnerability and 
exposure of populations and assets, changes in extreme weather and 
climate events have consequences for disaster risk, with particular 
impacts on the water, agriculture and food security and health sectors.
---------------------------------------------------------------------------

    \28\ SREX, p. 7.
---------------------------------------------------------------------------

    In the Climate Stabilization Targets assessment, the NRC states:

    Emissions of carbon dioxide from the burning of fossil fuels 
have ushered in a new epoch where human activities will largely 
determine the evolution of Earth's climate. Because carbon dioxide 
in the atmosphere is long lived, it can effectively lock Earth and 
future generations into a range of impacts, some of which could 
become very severe.\29\
---------------------------------------------------------------------------

    \29\ Climate Stabilization Targets, p. 3.

    The assessment concludes that carbon dioxide emissions will alter 
the atmosphere's composition and therefore the climate for thousands of 
years; and attempts to quantify the results of stabilizing GHG 
concentrations at different levels. The report also projects the 
occurrence of several specific climate change impacts, finding warming 
could lead to increases in heavy rainfall and decreases in crop yields 
and Arctic sea ice extent, along with other significant changes in 
precipitation and stream flow. For an increase in global average 
temperature of 1 to 2 [deg]C above pre-industrial levels, the 
assessment found that the area burnt by wildfires in western North 
America will likely more than double and coral bleaching and erosion 
will increase due both to warming and ocean acidification. An increase 
of 3 [deg]C will lead to a sea level rise of 0.5 to 1 meter by 2100. 
With an increase of 4 [deg]C, the average summer in the United States 
would be as warm as the warmest summers of the past century. The 
assessment notes that although many important aspects of climate change 
are difficult to quantify, the risk of adverse impacts is likely to 
increase with increasing temperature, and the risk of surprises can be 
expected to increase with the duration and magnitude of the warming.
    Several other National Academy assessments regarding climate have 
also been released recently. The EPA has reviewed these assessments and 
finds that in general, the improved understanding of the climate system 
they and the two assessments described above present strengthens the 
case that GHGs are endangering public health and welfare. Three of the 
new NRC assessments provide estimates of projected global sea level 
rise that are larger than, and in some cases more than twice as large 
as, the rise estimated in a 2007 IPCC assessment of between 0.18 and 
0.59 meters by the end of the century, relative to 1990. (It should be 
noted that in 2007, the IPCC stated that including poorly understood 
ice sheet processes could lead to an increase in the projections.) \30\ 
While these three NRC assessments continue to recognize and 
characterize the uncertainty inherent in accounting for ice sheet 
processes, these revised estimates strongly support and strengthen the 
existing finding that GHGs are reasonably anticipated to endanger 
public health and welfare. Other key findings of the recent assessments 
are described briefly below:
---------------------------------------------------------------------------

    \30\ Climate Stabilization Targets; ``National Security 
Implications for U.S. Naval Forces'' (2011) (National Security 
Implications); ``Sea Level Rise for the Coasts of California, 
Oregon, and Washington: Past, Present, and Future'' (2012) (Sea 
Level Rise).
---------------------------------------------------------------------------

    One of these assessments projects a global sea level rise of 0.5 to 
1.4 meters by 2100, which is sufficient to lead to rising relative sea 
level even in the northern states.\31\ Another assessment considers 
potential impacts of sea level rise and suggests that ``the Department 
of the Navy should expect roughly 0.4 to 2 meters global average sea-
level rise by 2100.\32\ This assessment also recommends preparing for 
increased needs for humanitarian aid; responding to the effects of 
climate change in geopolitical hotspots, including possible mass 
migrations; and addressing changing security needs in the Arctic as sea 
ice retreats. A third NRC assessment found that it would be ``prudent 
for security analysts to expect climate surprises in the coming decade 
. . . and for them to become progressively more serious and more 
frequent thereafter[.]'' \33\
---------------------------------------------------------------------------

    \31\ Sea Level Rise, p. 4.
    \32\ National Security Implications, p. 9.
    \33\ ``Climate and Social Stress: Implications for Security 
Analysis'' (2012), p.3.
---------------------------------------------------------------------------

    Another NRC assessment finds that ``the magnitude and rate of the 
present greenhouse gas increase place the climate system in what could 
be one of the most severe increases in radiative forcing of the global 
climate system in

[[Page 1440]]

Earth history.'' \34\ This assessment finds that CO2 
concentrations by the end of the century, without a reduction in 
emissions, are projected to increase to levels that Earth has not 
experienced for more than 30 million years.\35\ The report draws 
potential parallels with non-linear events such as the Paleo-Eocene 
Thermal Maximum, a rapid global warming event about 55 million years 
ago associated with mass extinctions and other disruptions. The 
assessment notes that acidification and warming caused by GHG increases 
similar to the changes expected over the next hundred years likely 
caused up to four of the five major coral reef crises of the past 500 
million years.
---------------------------------------------------------------------------

    \34\ ``Understanding Earth's Deep Past: Lessons for Our Climate 
Future'' (2011), p.138.
    \35\ Ibid, p. 1.
---------------------------------------------------------------------------

    Similarly, another NRC assessment finds that ``[t]he chemistry of 
the ocean is changing at an unprecedented rate and magnitude due to 
anthropogenic carbon dioxide emissions; the rate of change exceeds any 
known to have occurred for at least the past hundreds of thousands of 
years.'' \36\ The assessment notes that the full range of consequences 
is still unknown, but the risks ``threaten coral reefs, fisheries, 
protected species, and other natural resources of value to society.'' 
\37\
---------------------------------------------------------------------------

    \36\ ``Ocean Acidification: A National Strategy to Meet the 
Challenges of a Changing Ocean'' (2010), p. 5.
    \37\ Id.
---------------------------------------------------------------------------

    Comments were submitted in support of the Endangerment Finding, 
which provided additional documentation showing that climate change is 
a threat to public health and welfare. Commenters provided several 
individual studies and documentation of observed or projected climate 
changes of local importance or concern to commenters. The EPA 
appreciates these comments, but as previously stated, we place lesser 
weight on individual studies than on major scientific assessments. 
Local observed changes must be assessed in the context of the broader 
scientific picture, as it is more difficult to draw robust conclusions 
regarding climate change over short time scales and in small geographic 
regions.
    The EPA plans to continue relying on the major assessments by the 
USGCRP, the IPCC, and the NRC. Studies from these bodies address the 
scientific issues that the Administrator must examine, represent the 
current state of knowledge on the key elements for the endangerment 
analysis, comprehensively cover and synthesize thousands of individual 
studies to obtain the majority conclusions from the body of scientific 
literature and undergo a rigorous and exacting standard of review by 
the peer expert community and U.S. government.
    Several commenters argued that the Endangerment Finding should be 
reconsidered or overturned based on those commenters' reviews of 
specific climate science literature, including publications that have 
appeared since the EPA's 2010 Reconsideration Denial. Some commenters 
presented their own compilations of individual studies and other 
documents to support their assertions that climate change will have 
beneficial effects in many cases and that climate impacts will not be 
as severe or adverse as the EPA, and the assessment reports upon which 
the EPA relied, have stated. Some commenters also concluded that U.S. 
society will easily adapt to climate change and that it therefore does 
not threaten public health and welfare, and some commenters questioned 
the Endangerment Finding based on a 2011 EPA Inspector General's 
report.
    The EPA reviewed the submitted information and found that overall, 
the commenters' critiques of the rule's scientific basis were addressed 
in the EPA's response to comments for the 2009 Endangerment Finding, 
the EPA's responses in the 2010 Reconsideration Denial, or the D.C. 
Circuit's 2012 decision upholding the EPA's 2009 Endangerment Finding. 
The EPA nonetheless carefully reviewed these comments and associated 
documents and found that nothing in them would change the conclusions 
reached in the Endangerment Finding. These recent publications 
submitted by commenters, and any new issues they may present, do not 
undermine either the significant body of scientific evidence that has 
accumulated over the years or the conclusions presented in the 
substantial peer-reviewed assessments of the USGCRP, NRC, and IPCC.
    One commenter submitted emails between climate change researchers 
from the period 1999 to 2009 that were surreptitiously obtained from a 
University of East Anglia server in 2009 and publicly released in 2011. 
According to the commenter, these emails showed that the climatologists 
distorted their research results to prove that climate change causes 
adverse effects. The EPA reviewed these emails and found that they 
raised no issues that Petitioners had not already raised concerning 
other emails from the same incident, released in 2009. The commenter's 
unsubstantiated assumptions and subjective assertions regarding what 
the emails purport to show about the state of climate change science is 
not adequate evidence to challenge the voluminous and well-documented 
body of science that underpins the Administrator's Endangerment 
Finding.
    Some commenters argued for reconsideration based on uncertainty 
regarding climate science. However, the EPA made the decision to find 
endangerment with full and explicit recognition of the uncertainty 
involved, stating that ``[t]he Administrator acknowledges that some 
aspects of climate change science and the projected impacts are more 
certain than others.'' \38\ The D.C. Circuit subsequently noted that 
``the existence of some uncertainty does not, without more, warrant 
invalidation of an endangerment finding.'' \39\
---------------------------------------------------------------------------

    \38\ 74 FR 66524.
    \39\ CRR, 684 F.3d at 121.
---------------------------------------------------------------------------

    Some commenters also argued that the U.S. will adapt to climate 
change impacts and that therefore climate change impacts pose no 
threat. However, the D.C. Circuit, in CRR, held that considerations of 
adaption are irrelevant to the Endangerment determination. The Court 
stated, ``These contentions are foreclosed by the language of the 
statute and the Supreme Court's decision in Massachusetts v. EPA'' 
because ``predicting society's adaptive response to the dangers or 
harms caused by climate change'' does not inform the ``scientific 
judgment'' that the EPA is required to make regarding an Endangerment 
Finding.\40\
---------------------------------------------------------------------------

    \40\ Id. at 117. The EPA took a similar position in the 
Endangerment Finding, in which we responded to similar comments 
regarding society's ability to adapt to climate change by stating: 
``Risk reduction through adaptation and GHG mitigation measures is 
of course a strong focal area of scientists and policy makers, 
including the EPA; however, the EPA considers adaptation and 
mitigation to be potential responses to endangerment, and as such 
has determined that they are outside the scope of the endangerment 
analysis.'' 74 FR 66512.
---------------------------------------------------------------------------

    Some commenters raised issues regarding the EPA Inspector General's 
report, Procedural Review of EPA's Greenhouse Gases Endangerment 
Finding Data Quality Processes.\41\ These commenters mischaracterized 
the report's scope and conclusions and thus overstated the significance 
of the Inspector General's procedural recommendations. Nothing in the 
Inspector General's report questions the scientific validity of the 
Endangerment Finding, because that report did not evaluate the 
scientific basis of the Endangerment Finding. Rather, the Inspector 
General offers recommendations for clarifying and standardizing 
internal procedures for documenting data quality and peer

[[Page 1441]]

review processes when referencing existing peer reviewed science in the 
EPA actions.\42\
---------------------------------------------------------------------------

    \41\ Report No. 11-P-0702 (September 26, 2011).
    \42\ Unrelated to the Endangerment Finding and its validation by 
the Court, the EPA has made progress towards implementing the 
recommendations from the Inspector General.
---------------------------------------------------------------------------

    In addition, some commenters argued that the Endangerment Finding 
should be overturned because of the carbon dioxide fertilization 
effect, that is, the proposition that increased amounts of carbon 
dioxide can spur growth of vegetation. However, these commenters did 
not show how the science they provide on the subject differs from the 
carbon dioxide fertilization science already considered by the 
Administrator in the Endangerment Finding or how the existence of some 
benefits from the carbon dioxide fertilization effect could outweigh 
the numerous negative impacts of climate change.
    In sum, the EPA reviewed all of the comments purporting to refute 
the Endangerment Finding to determine whether they provide evidence 
that the Administrator's judgment that climate change endangers public 
health and welfare was flawed, because the Administrator misinterpreted 
the underlying assessments, because the science in new peer reviewed 
assessments differs from that in previous assessments, or because new 
individual studies provide compelling reasons for the EPA to change its 
interpretation of, or place less weight on, the major findings 
reflected in the assessment reports. In all cases, the commenters 
failed to demonstrate that the science that the Administrator relied on 
was inaccurate or that the additional information from the commenter is 
of central relevance to the Administrator's judgment regarding 
endangerment. For these reasons, the commenters on the original 
proposal that criticized the Endangerment Finding have not provided a 
sufficient basis to cast doubt on the Finding.

B. GHG Emissions From Fossil Fuel-Fired EGUs

    Fossil fuel-fired electric utility generating units are by far the 
largest emitters of GHGs, primarily in the form of CO2, 
among stationary sources in the U.S., and among fossil fuel-fired 
units, coal-fired units are by far the largest emitters. This section 
describes the amounts of those emissions and places those amounts in 
the context of the national inventory of GHGs.
    The EPA prepares the official U.S. Inventory of Greenhouse Gas 
Emissions and Sinks \43\ (the U.S. GHG Inventory) to comply with 
commitments under the United Nations Framework Convention on Climate 
Change (UNFCCC). This inventory, which includes recent trends, is 
organized by industrial sectors. It provides the information in Table 2 
below, which presents total U.S. anthropogenic emissions and sinks of 
GHGs, including CO2 emissions, for the years 1990, 2005 and 
2011.\44\
---------------------------------------------------------------------------

    \43\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2011'', Report EPA 430-R-13-001, United States Environmental 
Protection Agency, April 15, 2013.
    \44\ Sinks are a physical unit or process that stores GHGs, such 
as forests or underground or deep sea reservoirs of carbon dioxide.
    \45\ From Table 2-3 of ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2011'', April 15, 2013, EPA 430-R-13-001.

     Table 2--U.S. GHG Emissions and Sinks by Sector (Teragram Carbon Dioxide Equivalent (Tg CO2 Eq.)) \45\
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2011
----------------------------------------------------------------------------------------------------------------
Energy..........................................................         5,267.3         6,251.6         5,745.7
Industrial Processes............................................           316.1           330.8           326.5
Solvent and Other Product Use...................................             4.4             4.4             4.4
Agriculture.....................................................           413.9           446.2           461.5
Land Use, Land-Use Change and Forestry..........................            13.7            25.4            36.6
Waste...........................................................           167.8           136.9           127.7
Total Emissions.................................................         6,183.3         7,195.3         6,702.3
Land Use, Land-Use Change and Forestry (Sinks)..................         (794.5)         (997.8)         (905.0)
Net Emissions (Sources and Sinks)...............................         5,388.7         6,197.4         5,797.3
----------------------------------------------------------------------------------------------------------------

    Total fossil energy-related CO2 emissions (including 
both stationary and mobile sources) are the largest contributor to 
total U.S. GHG emissions, representing 78.7 percent of total 2011 GHG 
emissions. In 2011, fossil fuel combustion by the electric power 
sector--entities that burn fossil fuel and whose primary business is 
the generation of electricity--accounted for 39.6 percent of all 
energy-related CO2 emissions. Table 3 below presents total 
CO2 emissions from fossil fuel-fired EGUs, for years 1990, 
2005 and 2011.\46\
---------------------------------------------------------------------------

    \46\ Note that for the purposes of reporting national GHG 
emissions under the UNFCCC, the U.S. GHG Inventory is calculated 
using internationally accepted methodological guidance from the 
Intergovernmental Panel on Climate Change (IPCC). In accordance with 
IPCC guidance, CO2 emissions from combustion of biogenic 
feedstocks are not reported in the energy sector, but are instead 
reported separately as a ``Memo item'' in the U.S. GHG Inventory. 
Consistent with the IPCC guidance, any carbon stock changes related 
to the use of biogenic feedstocks in the energy sector, and the 
CO2 emissions associated with those carbon stock changes, 
are accounted for under the forestry and/or agricultural sectors of 
the U.S. GHG Inventory. Attribution of CO2 emissions from 
the combustion of biogenic feedstocks by stationary sources in the 
energy sector to the forestry and/or agricultural sectors, in the 
context of U.S. GHG emissions reporting to the UNFCCC, should not be 
interpreted as an indication that such emissions are ``carbon 
neutral.''

     Table 3--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels (Tg CO2 Eq.)
----------------------------------------------------------------------------------------------------------------
                          GHG Emissions                                1990            2005            2011
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel combustion EGUs......................         1,820.8         2,402.1         2,158.5
    --from coal.................................................         1,547.6         1,983.8         1,722.7
    --from natural gas..........................................           175.3           318.8           408.8
    --from petroleum............................................            97.5            99.2            26.6
----------------------------------------------------------------------------------------------------------------


[[Page 1442]]

    We are aware that nitrous oxide (N2O) and, to a lesser 
extent, methane (CH4) may be emitted from fossil fuel-fired 
EGUs, especially from coal-fired circulating fluidized bed (CFB) 
combustors and from units with selective catalytic reduction (SCR) and 
selective non-catalytic reduction (SNCR) systems installed for 
NOX control. The estimated emissions for N2O and 
CH4 from fossil fuel-fired EGUs are about 17.9 and 0.4 Tg of 
CO2 equivalent in 2011, respectively, which is about 0.8 
percent of total CO2 equivalent emissions from fossil fuel-
fired electric power generating units. However, we are not proposing 
separate N2O or CH4 emission limits or an 
equivalent CO2 emission limit in today's document because we 
lack more precise data on the quantity of these emissions and 
information on cost-effective controls. We request comment on this 
approach and we solicit information about the quantity of 
N2O and CH4 emissions from these affected sources 
and possible controls.

C. The Utility Power Sector and How Its Structure Is Changing

1. Utility Power Sector
    The majority of power in the U.S. is generated from the combustion 
of coal, natural gas and other fossil fuels.
    Natural gas-fired EGUs typically use one of two technologies: NGCC 
and simple cycle combustion turbines. NGCC units first generate power 
from a combustion turbine (the combustion cycle). The unused heat from 
the combustion turbine is then routed to a Heat Recovery Steam 
Generator (HRSG) which generates steam which is used to generate power 
using a steam turbine (the steam cycle). The combining of these 
generation cycles increases the overall efficiency of the system.
    Simple cycle combustion turbines only use a single combustion 
turbine to produce electricity (i.e., there is no heat recovery). The 
power output from these simple cycle combustion turbines can be easily 
ramped up and down making them ideal for ``peaking'' operations.
    Coal-fired utility boilers are primarily either pulverized coal 
(PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is 
crushed (pulverized) into a powder in order to increase its surface 
area. The coal powder is then blown into a boiler and burned. In a 
coal-fired boiler using fluidized bed combustion, the coal is burned in 
a layer of heated particles suspended in flowing air.
    Power can also be generated using gasification technology. An IGCC 
unit gasifies coal to form a syngas composed of carbon monoxide (CO) 
and hydrogen (H2), which can be combusted in a combined 
cycle system to generate power.
2. Changing Structure of the Power Sector
a. Technological Developments and Costs
    Since the April 2012 proposal, a few coal-fired units have reached 
the advanced stages of construction and development, which suggests 
that setting a separate standard for new fossil fuel-fired boilers and 
IGCC units is appropriate. Progress on Southern Company's Kemper County 
Energy Facility, which will deploy IGCC with partial CCS, has 
continued, and the project is now over 75 percent complete. 
Additionally, two other projects, Summit Power's Texas Clean Energy 
Project (TCEP) and the Hydrogen Energy California Project (HECA)--both 
of which will deploy IGCC with CCS--continue to move forward. The EIA 
modeling projects that coal-fired power generation will remain the 
single largest portion of the electricity sector beyond 2030. The EIA 
modeling also projects that few, if any, new coal-fired EGUs would be 
built in this decade and that those that are built would have CCS.\47\ 
Continued progress on these projects is consistent with the EIA 
modeling that suggests that a small number of coal-fired power plants 
may be constructed. The primary reasons for this rate of current and 
projected future development of new coal projects include highly 
competitive natural gas prices, lower electricity demand, and increases 
in the supply of renewable energy.
---------------------------------------------------------------------------

    \47\ Even in its sensitivity analysis that assumes higher 
natural gas prices and electricity demand, EIA does not project any 
additional coal beyond its reference case until 2023, in a case 
where power companies assume no GHGs emission limitations, and until 
2024 in a case where power companies do assume GHGs emission 
limitations.
---------------------------------------------------------------------------

    Natural gas prices have decreased dramatically and generally 
stabilized in recent years, as new drilling techniques have brought 
additional supply to the marketplace and greatly increased the domestic 
resource base. As a result, natural gas prices are expected to be 
competitive for the foreseeable future and EIA modeling and utility 
announcements confirm that utilities are likely to rely heavily on 
natural gas to meet new demand for electricity generation. On average, 
as discussed below, the cost of generation from a new natural-gas fired 
power plant (a NGCC unit) is expected to be significantly lower than 
the cost of generation from a new coal-fired power plant.\48\
---------------------------------------------------------------------------

    \48\ Levelized Cost of New Generation Resources in the Annual 
Energy Outlook 2011 https://www.eia.gov/forecasts/aeo/electricity_generation.html.
---------------------------------------------------------------------------

    Other drivers that may influence decisions to build new power 
plants are increases in renewable energy supplies, often due to state 
and federal energy policies. Many states have adopted renewable 
portfolio standards (RPS), which require a certain portion of 
electricity to come from renewable energy sources such as 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.
    Due to these factors, the EIA projections from the last several 
years show that natural gas is likely to be the most widely-used fossil 
fuel for new construction of electric generating capacity through 2020, 
along with renewable energy, nuclear power, and a limited amount of 
coal with CCS.\49\
---------------------------------------------------------------------------

    \49\ https://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf; https://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf; https://prod-http-80-800498448.us-east-1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pdf.
---------------------------------------------------------------------------

b. Energy Sector Modeling
    Various energy sector modeling efforts, including projections from 
the EIA and the EPA, forecast trends in new power plant construction 
and utilization of existing power plants that are consistent with the 
above-described technological developments and costs. The EIA forecasts 
the structure and developments in the power sector in its annual 
report, the Annual Energy Outlook (AEO). These reports are based on 
economic modeling that reflects existing policy and regulations, such 
as state RPS programs and federal tax credits for renewables.\50\ The 
current report, AEO 2013,\51\ (i) shows that a modest amount of coal-
fired power plants that are currently under construction are expected 
to begin operation in the next several years (referred to as 
``planned''); and (ii) projects in the reference case,\52\ that a very 
small amount of new (``unplanned'') conventional coal-fired capacity, 
with CCS, will come online after 2012, and through 2034 in response to 
Federal and State incentives. According to the AEO 2013,

[[Page 1443]]

the vast majority of new generating capacity during this period will be 
either natural gas-fired or renewable. Similarly, the EIA projections 
from the last several years show that natural gas is likely to be the 
most widely-used fossil fuel for new construction of electric 
generating capacity through 2020.\53\
---------------------------------------------------------------------------

    \50\ https://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
    \51\ Energy Information Adminstration's Annual Energy Outlook 
for 2013, Final Release available at https://www.eia.gov/forecasts/aeo/index.cfm.
    \52\ EIA's reference case projections are the result of its 
baseline assumptions for economic growth, fuel supply, technology, 
and other key inputs.
    \53\ Annual Energy Outlook 2010, 2011, 2012, and 2013.
---------------------------------------------------------------------------

    Specifically, the AEO 2013 projects the need for 25.9 GW of 
additional base load or intermediate load generation capacity through 
2020 (this includes projects that are under development--i.e., being 
constructed or in advance planning--and model-projected nuclear, coal, 
and NGCC projects). The vast majority of this new electric capacity 
(22.5 GW) is already under development (under construction or in 
advanced planning); it includes about 6.1 GW of new coal-fired 
capacity, 5.5 GW of new nuclear capacity, and 10.9 GW of new NGCC 
capacity. The EPA believes that most current fossil fuel-fired projects 
are already designed to meet limits consistent with today's proposal 
(or they have already commenced construction and are thus not impacted 
by today's notice). The AEO 2013 also projects an additional 3.4 GW of 
new base load capacity additions, which are model-projected 
(unplanned). This consists of 3.1 GW of new NGCC capacity, and 0.3 GW 
of new coal equipped with CCS (incentivized with some government 
funding). Therefore, the AEO 2013 projection suggests that this 
proposal would only impact small amounts of new power generating 
capacity through 2020, all of which is expected to already meet the 
proposed emissions standards without incurring further control costs. 
In AEO 2013, this is also true during the period from 2020 through 
2034, where new model-projected (unplanned) intermediate and base load 
capacity is expected to be compliant with the proposed standard without 
incurring further control costs (i.e., an additional 45.1 GW of NGCC 
and no additional coal, for a total, from 2013 through 2030, of 48.2 GW 
of NGCC and 0.3 GW of coal with CCS).
    It should be noted that under the EIA projections, existing coal-
fired generation will remain an important part of the mix for power 
generation. Modeling from both the EIA and the EPA predict that coal-
fired generation will remain the largest single source of electricity 
in the U.S. through 2040. Specifically, in the EIA's AEO 2013, coal 
will supply approximately 40 percent of all electricity in both 2020 
and 2025.
    The EPA modeling using the Integrated Planning Model (IPM), a 
detailed power sector model that the EPA uses to support power sector 
regulations, also shows limited future construction of new coal-fired 
power plants under the base case.\54\ The EPA's projections from IPM 
can be found in the RIA.
---------------------------------------------------------------------------

    \54\ https://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

c. Integrated Resource Plans
    The trends in the power sector described above are also apparent in 
publicly available long-term resource plans, known as IRPs.
    The EPA has reviewed publicly available IRPs from a range of 
companies (e.g., varying in size, location, current fuel mix), and 
these plans are generally consistent with both EIA and EPA modeling 
projections. Companies seem focused on demand-side management programs 
to lower future electricity demand and mostly reliant on a mix of new 
natural gas-fired generation and renewable energy to meet increased 
load demand and to replace retired generation capacity.
    Notwithstanding this clear trend towards natural gas-fired 
generation and renewables, many of the IRPs raise fuel diversity 
concerns and include options to diversify new generation capacity 
beyond natural gas and renewable energy. Several IRPs indicate that 
companies are considering new nuclear generation, including either 
traditional nuclear power plants or small modular reactors, and new 
coal-fired generation capacity with and without CCS technology. Based 
on these IRPs, the EPA acknowledges that a small number of new coal-
fired power plants may be built in the near future. While this is 
contrary to the economic modeling predictions, the Agency understands 
that economic modeling may not fully reflect the range of factors that 
a particular company may consider when evaluating new generation 
options, such as fuel diversification. By the same token, as discussed 
below, it is possible that some of this potential new coal-fired 
construction may occur because developers are able to design projects 
that can provide competitively priced electricity for a specific 
geographic region.

D. Statutory Background

    Section 111 of the Clean Air Act sets forth the standards of 
performance for new sources (NSPS) program, and with this program, 
establishes mechanisms for regulating emissions of air pollutants from 
stationary sources that are key in this rulemaking.\55\ As a 
preliminary step to regulation, the EPA must list categories of 
stationary sources that the Administrator, in his or her judgment, 
finds ``cause[ ], or contribute[ ] significantly to, air pollution 
which may reasonably be anticipated to endanger public health or 
welfare.''
---------------------------------------------------------------------------

    \55\ CAA section 111(b)(1)(A). The EPA has regulated more than 
60 stationary source categories under CAA section 111. See generally 
40 CFR subparts D-MMMM.
---------------------------------------------------------------------------

    Once the EPA has listed a source category, the EPA proposes and 
then promulgates ``standards of performance'' for ``new sources'' in 
the category.\56\ A ``new source'' is ``any stationary source, the 
construction or modification of which is commenced after,'' in general, 
the date of the proposal.\57\ A modification is ``any physical change . 
. . or change in the method of operation . . . which increases the 
amount of any air pollutant emitted by such source or which results in 
the emission of any air pollutant not previously emitted.'' \58\ The 
EPA, through regulations, has determined that certain types of changes 
are exempt from consideration as a modification.\59\ The EPA's 
regulations also provide that an existing facility is also considered a 
new source if it undertakes a ``reconstruction,'' which is the 
replacement of 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.\60\ In establishing 
standards of performance, the EPA has significant discretion to create 
subcategories based on source type, class or size.\61\
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    \56\ CAA section 111(b)(1)(B).
    \57\ CAA section 111(a)(2).
    \58\ CAA section 111(a)(4).
    \59\ 40 CFR 60.2, 60.14(e).
    \60\ 40 CFR 60.15.
    \61\ CAA section 111(b)(2).
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    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.
    This definition makes clear that the standard of performance must 
be based on controls that constitute ``the best system of emission 
reduction . . . adequately demonstrated'' (BSER).\62\

[[Page 1444]]

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 generally can select any 
measure or combination of measures that will achieve the emissions 
level of the standard.
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    \62\ As noted, we generally refer to this system of control as 
the best system of emission reduction, or BSER, but we may 
occasionally refer to it as the ``best demonstrated system.'' In the 
past, this level of control was frequently referred to as the ``best 
demonstrated technology'' (BDT).
---------------------------------------------------------------------------

    Regarding other titles in the CAA, this rulemaking has implications 
for EGUs and other stationary sources in the CAA PSD program under 
Title I, part C, and the operating permits program under Title V. We 
discuss these implications in section IX of this preamble.

E. Regulatory and Litigation Background

    The EPA initially included fossil fuel-fired EGUs (which includes 
EGUs that burn fossil fuel including coal, gas, oil and petroleum coke 
and that use different technologies, including boilers and combustion 
turbines) in a category that it listed under section 111(b)(1)(A), and 
the EPA promulgated the first set of standards of performance for EGUs 
in 1971, codified in subpart D.\63\ As discussed in Section IV.D. of 
this preamble, the EPA has revised those regulations, and in some 
instances, revised the subparts, several times over the ensuing 
decades. None of these rulemakings or codifications, however, have 
constituted a new listing under CAA section 111(b)(1)(A).
---------------------------------------------------------------------------

    \63\ ``Standards of Performance for Fossil-Fuel-Fired Steam 
Generators for Which Construction Is Commenced After August 17, 
1971,'' 36 FR 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 
FR 5931 (Mar. 31, 1971).
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    In 1979, the EPA revised subpart D of 40 CFR part 60; as part of 
this revision, the EPA formed subpart Da and promulgated NSPS for 
electric utility steam generating units.\64\ These NSPS on June 11, 
1979 apply to units capable of firing more than 73 megawatts (MW) (250 
MMBtu/h) heat input of fossil fuel that commenced construction, 
reconstruction, or modification after September 18, 1978. The NSPS for 
EGUs also apply to industrial-commercial-institutional cogeneration 
units that sell more than 25 MW and more than one-third of their 
potential output capacity to any utility power distribution system.
---------------------------------------------------------------------------

    \64\ ``Standards of Performance for Electric Utility Steam 
Generating Units for Which Construction is Commenced After September 
18, 1978,'' 44 FR 33580 (June 11, 1979)
---------------------------------------------------------------------------

    The EPA promulgated amendments to subpart Da in 2006, resulting in 
new criteria pollutant limitations for EGUs (the 2006 Final Rule).\65\ 
The 2006 Final Rule did not establish standards of performance for GHG 
emissions. Two groups of petitioners--13 governmental entities and 
three environmental groups--filed petitions for judicial review of this 
rule by the D.C. Circuit.\66\ These petitioners contended, among other 
issues, that the rule was required to include standards of performance 
for GHG emissions from EGUs.
---------------------------------------------------------------------------

    \65\ ''Standards of Performance for Electric Utility Steam 
Generating Units, Industrial-Commercial-Institutional Steam 
Generating Units, and Small Industrial-Commercial-Institutional 
Steam Generating Units, Final Rule.'' 71 FR 9866 (Feb. 27, 2006).
    \66\ State of New York, et al. v. EPA, No. 06-1322. 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 Court severed portions of the petitions for review of the 2006 
Final Rule that related to GHG emissions. Following the U.S. Supreme 
Court's 2007 decision in Massachusetts v. EPA, which gave authority to 
the EPA to regulate GHGs, the D.C. Circuit remanded the 2006 Final Rule 
to the EPA upon its own motion for further consideration of the issues 
related to GHG emissions in light of Massachusetts. The EPA did not act 
on that remand. Rather, these 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 provided for a notice-and-comment opportunity on the 
proposed settlement agreement and, after reviewing the comments 
received, finalized the agreement in late 2010.
    In June 2012, the D.C. Circuit, in Coalition for Responsible 
Regulation v. EPA, upheld the EPA's Endangerment Finding concerning 
GHGs and the EPA's companion finding that GHGs from motor vehicles 
contribute to the air pollution that endangers public health and 
welfare.\67\ The Court also upheld standards for motor vehicles that 
limited GHG emissions.\68\ In addition, the Court affirmed the EPA's 
view that the CAA PSD and title V permitting requirements became 
applicable to GHG-emitting stationary sources when the EPA regulated 
GHG emissions from motor vehicles, because PSD and title V are 
automatically applicable to a pollutant when that pollutant is 
regulated under any part of the Act. The Court also dismissed 
challenges to what we refer to as the Timing Decision,\69\ which 
established the January 2, 2011 date when the PSD and title V 
permitting requirements applied to GHG-emitting stationary sources; and 
the Tailoring Rule,\70\ which is the EPA's common sense approach to 
phasing in GHG permitting requirements to avoid an initial increase in 
the number of PSD and title V permit applications that would overwhelm 
the permitting authorities' administrative capacities.
---------------------------------------------------------------------------

    \67\ CRR, 684 F.3d at 102.
    \68\ ``Light-Duty Vehicle Greenhouse Gas Emission Standards and 
Corporate Average Fuel Economy Standards; Final Rule.'' 75 FR 25324 
(May 7, 2010).
    \69\ ``Interpretation of Regulations that Determine Pollutants 
Covered by Clean Air Act Permitting Programs.'' 75 FR 17004 (April 
2, 2010).
    \70\ ``Prevention of Significant Deterioration and Title V 
Greenhouse Gas Tailoring Rule; Final Rule.'' 75 FR 31514 (June 3, 
2010).
---------------------------------------------------------------------------

    In June 2012, several companies filed petitions for review of the 
original proposal for this rulemaking action in the D.C. Circuit. In 
December 2012, the D.C. Circuit dismissed these petitions on grounds 
that the challenged proposed rule is not final agency action subject to 
judicial review.\71\
---------------------------------------------------------------------------

    \71\ Las Brisas Energy Center, LLC v. Environmental Protection 
Agency, No. 12-1248, 2012 U.S. App. LEXIS 25535 (D.C. Cir. Dec. 13, 
2012).
---------------------------------------------------------------------------

    In April 2013, EPA completed rulemaking to regulate power plants in 
the Mercury and Air Toxics rule (``MATS'').\72\ In this same 
rulemaking, EPA promulgated revised standards of performance under CAA 
section 111(b) for criteria pollutant emissions from EGUs.
---------------------------------------------------------------------------

    \72\ ``Reconsideration of Certain New Source Issues: National 
Emission Standards for Hazardous Air Pollutants From Coal- and Oil-
Fired Electric Utility Steam Generating Units and Standards of 
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units, Final Rulemaking, '' 78 FR 
24073 (April 24, 2013).
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F. Coordination With Other Rulemakings

    EGUs are the subject of several recent CAA rulemakings.\73\ In 
general, most EPA rulemakings affecting the power sector focus on 
existing sources.

[[Page 1445]]

Therefore, few interactions are likely between other power sector rules 
and this rule, which focuses only on new sources.\74\
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    \73\ We discuss other rulemakings solely for background 
purposes. The effort to coordinate rulemakings is not a defense to a 
violation of the CAA. Sources cannot defer compliance with existing 
requirements because of other upcoming regulations.
    \74\ Other pending EPA regulatory actions in the power sector 
are discussed in more detail in Chapter 4 of the RIA.
---------------------------------------------------------------------------

    We note that the EPA recently finalized revisions to the MATS rule 
as related to new sources.\75\ The revised MATS new source emission 
standards for air toxics and new source performance standards for 
criteria pollutants, coupled with GHG performance standards in this 
proposed rule, provide a clear regulatory structure for new fossil 
fuel-fired generation.
---------------------------------------------------------------------------

    \75\ 78 FR 24073.
---------------------------------------------------------------------------

    The EPA recognizes that it is important that each of these 
regulatory efforts achieves its intended environmental objectives in a 
common-sense, cost-effective manner consistent with the underlying 
statutory requirements and assures a reliable power system. Executive 
Order (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 Management and Budget's Office of 
Information and Regulatory Affairs has emphasized the importance of, 
where appropriate and feasible, the consideration of cumulative effects 
in regulated industries and the harmonization of rules in terms of both 
content and timing. We believe that these recent finalized and proposed 
rules will allow industry to comply with its obligations as efficiently 
as possible, by making coordinated investment decisions and, to the 
greatest extent possible, adopting integrated compliance strategies.

G. Stakeholder Input

    The EPA has extensively interacted with many different stakeholders 
regarding climate change, source contributions, and emission reduction 
opportunities. These stakeholders included industry entities, 
environmental organizations and many regional, state, and local air 
quality management agencies, as well as the general public. As part of 
developing the original 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; these were 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 
roundtable discussion among stakeholder representatives. The EPA asked 
key stakeholder groups to identify these roundtable 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.\76\
---------------------------------------------------------------------------

    \76\ Comments related to the listening sessions submitted via 
the electronic docket system are available at www.regulations.gov 
(docket number EPA-HQ-OAR-2011-0090).
---------------------------------------------------------------------------

    On May 3, 2012, the EPA announced that it would hold two public 
hearings on the original proposed rule. The hearings were both held on 
May 24, 2012, in Washington, DC and Chicago, IL. Also on May 3, 2012, 
the EPA announced an extension of the public comment period for the 
original proposed rule, until June 25, 2012. The EPA received more than 
2.5 million public comments on the original proposed rule.\77\ While 
the Agency is not preparing a RTC document responding to the comments 
it received as part of that process, the EPA has taken into 
consideration those comments, as well as information received in the 
listening sessions, in developing this new proposal.
---------------------------------------------------------------------------

    \77\ Those comments are available at www.regulations.gov (docket 
number EPA-HQ-OAR-2011-0660).
---------------------------------------------------------------------------

III. Proposed Requirements for New Sources

    This section describes the proposed requirements in this rulemaking 
for new sources. We describe our rationale for several of these 
proposed requirements--the applicability requirements, the basis for 
the standards of performance for fossil-fuel fired boilers, and the 
basis for the standards of performance for combustion turbines--in 
Sections V-VIII of this preamble.

A. Applicability Requirements

    We generally refer to sources that would be subject to the 
standards of performance in this rulemaking as ``affected'' or 
``covered'' sources, units, facilities, or simply as EGUs. These 
sources meet both the definition of ``affected'' and ``covered'' EGUs 
subject to an emission standard as provided by this rule, and the 
requirements for ``new'' sources as defined under the provisions of CAA 
section 111.
1. Covered EGUs, Generally
    Subpart Da currently defines an EGU as a boiler that is: (1) 
``capable of combusting'' more than 250 MMBtu/h heat input of fossil 
fuel,\78\ (2) ``constructed for the purpose of supplying more than one-
third of its potential net- electric output capacity . . . to any 
utility power distribution system for sale'' \79\ (that is, to the 
grid), and (3) ``constructed for the purpose of supplying . . . more 
than 25 MW net-electric output'' to the grid.\80\ We are proposing to 
define an EGU slightly differently than it is currently defined in 
subpart Da or in the original proposal for this rulemaking. First, we 
are proposing to add additional criteria to be met in addition to the 
``constructed for the purpose of supplying more than one-third of its 
potential electric output capacity'' to the grid. One new criterion 
would be that a unit actually ``supplies more than one-third of its 
potential electric output'' to the grid. Both criteria would also be 
used in subparts KKKK and TTTT. Combined with the three year rolling 
average methodology to determine if the one-third criteria is met (as 
explained further below), this approach makes it clear that a unit that 
was not originally constructed to supply more than one-third of its 
potential electric output to the grid, but does so for one year does 
not automatically become affected. The EPA believes that coal-fired 
utility boilers, IGCCs and large NGCC units are constructed with the 
purpose of supplying more than one-third of their potential electric 
output to the grid, and, except in rare cases (such as very extended 
outages), usually do. Small NGCC units and simple cycle combustion 
turbines that are generally designed for operation during peak demand 
will usually supply less than one-third of their potential electric 
output to the grid. Even though these projects are not generally 
designed to supply more than one-third of their potential electric 
output to the grid, there can be rare instances when they do. For 
instance, when a large base load unit in a transmission-constrained 
area experiences a long, unexpected outage, it may be necessary to 
operate simple cycle combustion turbines significantly more than 
anticipated. The EPA believes the combination of the actual sales 
criteria and the three year rolling average to determine if the sales 
criteria are met will address this concern. Second, we are proposing to 
revise the

[[Page 1446]]

third criteria to be met if the EGU is constructed for the purpose of 
supplying ``more than 219,000 MWh,'' as opposed to ``25 MW,'' net-
electrical output to the grid. This proposed change to 219,000 MWh net 
sales is consistent with the EPA Acid Rain Program (ARP) definition, 
and we have concluded that it is functionally equivalent to the 25 MW 
net sales language. The 25 MW sales value has been interpreted to be 
the continuous sale of 25 MW of electricity on an annual basis, which 
is equivalent to 219,000 MWh. We are also proposing to revise the 
averaging period for electric sales from an annual basis to a three-
year rolling average for stationary combustion turbines. In addition, 
we are proposing to add a new applicability criterion that is not 
currently in subpart Da: EGUs, for which 10 percent or less of the heat 
input over a three-year period is derived from a fossil fuel, are not 
subject to any of the proposed CO2 standards.
---------------------------------------------------------------------------

    \78\ E.g., 40 CFR 60.40Da(a)(1).
    \79\ 40 CFR 60.41Da (definition of (``Electric utility steam-
generating unit'').
    \80\ Id.
---------------------------------------------------------------------------

    For the purposes of this rule, we are proposing several additional 
changes to the way applicability is currently determined under subpart 
Da. First, the proposed definition of potential electric output 
includes ``or the design net electric output efficiency'' as an 
alternative to the default one-third efficiency value for determining 
the value of the potential electric output. Next, we are proposing to 
add ``of the thermal host facility or facilities'' to the definition of 
net-electric output for determining electric sales with respect to the 
NSPS. Finally, consistent with our approach in the NSPS part of the 
MATS rule and the original proposal for this rulemaking, we are 
proposing to amend the definition of a steam generating unit to include 
``plus any integrated equipment that provides electricity or useful 
thermal output to either the affected facility or auxiliary equipment'' 
instead of the existing language ``plus any integrated combustion 
turbines and fuel cells''. We are also proposing to add the additional 
language to the definition of IGCC and stationary combustion turbine.
2. CO2 Emissions Only
    This action proposes to regulate covered EGU emissions of 
CO2, and not other constituent gases of the air pollutant 
GHGs. We identify the pollutant we propose to regulate as GHGs, but, 
again, only CO2 emissions are subject to the proposed 
standard of performance. We are not proposing separate emission limits 
for other GHGs (such as methane (CH4) or nitrous oxide 
(N2O)) as they represent less than 1 percent of total 
estimated GHG emissions from fossil fuel-fired electric power 
generating units.
    The proposed CO2 emission standards do not apply a 
different accounting method for biogenic CO2 emissions for 
the purpose of determining compliance with the standards. However, the 
proposed CO2 emission standards only apply to new fossil 
fuel-fired EGUs. Based on the applicability provisions in the proposal, 
as discussed above, an EGU that primarily fires biomass would not be 
subject to the CO2 emission standards. Such units could fire 
fossil fuels up to 10 percent on a three-year average annual heat input 
basis (e.g., for start-up and combustion stabilization) without 
becoming subject to the standards.
    Issues related to accounting for biogenic CO2 emissions 
from stationary sources are currently being evaluated by the EPA 
through its development of an Accounting Framework for Biogenic 
CO2 Emissions from Stationary Sources (Accounting 
Framework).\81\ In general, the overall net atmospheric loading of 
CO2 resulting from the use of a biogenic feedstock by a 
stationary source, such as an EGU, will ultimately depend on the 
stationary source process and the type of feedstock used, as well as 
the conditions under which that feedstock is grown and harvested. In 
September 2011, the EPA submitted a draft of the Accounting Framework 
to the Science Advisory Board (SAB) Biogenic Carbon Emissions (BCE) 
Panel for peer review. The SAB BCE Panel delivered its Peer Review 
Advisory to the EPA on September 28, 2012.\82\ In its Advisory, the SAB 
recommended revisions to the EPA's proposed accounting approach, and 
also noted that biomass cannot be considered carbon neutral a priori, 
without an evaluation of the carbon cycle effects related to the use of 
the type of biomass being considered. The EPA is currently reviewing 
the SAB peer review report, and will move forward as warranted once the 
review is complete.
---------------------------------------------------------------------------

    \81\ The EPA's draft accounting framework is available at https://www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
    \82\ The text of the SAB Peer Review Advisory is available at 
https://yosemite.epa.gov/sab/sabproduct.nsf/0/2f9b572c712ac52e8525783100704886!OpenDocument&TableRow=2.3#2.
---------------------------------------------------------------------------

3. Sources Not Subject to This Rulemaking
    We are not proposing standards for certain types of sources. These 
include new steam generating units and stationary combustion turbines 
that sell one-third or less of their potential output to the grid; new 
non-natural gas-fired stationary combustion turbines; \83\ existing 
sources undertaking modifications or reconstructions; or certain 
projects under development, including the proposed Wolverine EGU 
project in Rogers City, Michigan (and, perhaps, up to two others) as 
discussed below. As a result, under the CAA section 111(a) definitions 
of ``new source'' and ``existing source,'' \84\ if those types of 
sources commence construction or modification, they would not be 
treated as ``new source[s]'' subject to the standards of performance 
proposed today, and instead, they would be treated as existing sources.
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    \83\ Oil-fired stationary combustion turbines, including both 
simple and combined cycle units, are not subject to these proposed 
standards. These units are typically used only in areas that do not 
have reliable access to pipeline natural gas (for example, in non-
continental areas).
    \84\ CAA section 111(a)(2), (6).
---------------------------------------------------------------------------

B. Emission Standards

    In this rulemaking, the EPA is proposing NSPS for CO2 
emissions from several subcategories of affected sources, which are new 
fossil fired EGUs described above in Section III.A.
1. Standards of Performance for Affected Sources
a. Emission Standard
    The proposed standard of performance for each subcategory is in the 
form of a gross energy output-based CO2 emission limit 
expressed in units of emissions mass per unit of useful recovered 
energy, specifically, in pounds per megawatt-hour (lb/MWh). This 
emission limit would apply to affected sources upon the effective date 
of the final action. In this notice, we sometimes refer to ``gross 
energy output'' as ``gross output'' or ``adjusted gross output.''
    The subcategories, for which the EPA is proposing separate 
standards of performance, are (1) natural gas-fired stationary 
combustion turbines with a heat input rating that is greater than 850 
MMBtu/h; \85\ (2) natural gas-fired stationary combustion turbines with 
a heat input rating that is less than or equal to 850 MMBtu/h; and (3) 
all fossil fuel-fired boilers and IGCC units, which generally are 
solid-fuel fired.
---------------------------------------------------------------------------

    \85\ This subcategorization of stationary combustion turbines is 
consistent with the subcategories used in the combustion turbine 
(subpart KKKK) criteria pollutant NSPS. The size limit of 850 MMBtu/
h corresponds to approximately 100 MWe.
---------------------------------------------------------------------------

    We are proposing that all affected new fossil fuel-fired EGUs are 
required to meet an output-based emission rate of a specific mass of 
CO2 per MWh of useful output. Specifically, new combustion 
turbines with a heat input rating greater

[[Page 1447]]

than 850 MMBtu/h would be required to meet a standard of 1,000 lb 
CO2/MWh. New combustion turbines with a heat input rating 
less than or equal to 850 MMBtu/h would be required to meet a standard 
of 1,100 lb CO2/MWh. As discussed below, these proposed 
standards are based on the demonstrated performance of recently 
constructed NGCC units, which are currently in wide use throughout the 
country, and are currently the predominant fossil fuel-fired technology 
for new electric generating units in the near future.
    While the EPA is proposing specific standards of performance for 
each subcategory, we are also taking comment on a range of potential 
emission limitations. We solicit comment on a range of 950-1,100 lb 
CO2/MWh for new stationary combustion turbines with a heat 
input rating greater than 850 MMBtu/h. We also solicit comment on an 
emission limitation range of 1,000-1,200 lb CO2/MWh for new 
stationary combustion turbines with a heat input rating less than or 
equal to 850 MMBtu/h. In addition, we solicit comment on an emission 
limitation for new fossil fuel-fired boilers and IGCC units in the 
range of 1,000-1,200 lb CO2/MWh.
    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 
useful energy output over a rolling 12-operating-month period. In the 
alternative, we solicit comment on requiring calculation of compliance 
on an annual (calendar year) period.
b. Gross Output
    Subpart Da currently defines ``gross energy output'' from new units 
as the ``gross electrical or mechanical output from the affected 
facility minus any electricity used to power the feedwater pumps and 
any associated gas compressors (air separation unit main compressor, 
oxygen compressor, and nitrogen compressor) plus 75 percent of the 
useful thermal output measured relative to ISO conditions'' \86\ \87\ 
(referred to in today's document as ``adjusted gross output''). The 
current criteria pollutant emission standards for new subpart Da units 
were developed by analyzing the gross emission rates of PC and CFB 
facilities, and were finalized on February 16, 2013 (77 FR 9304). In 
that rulemaking, we applied the same standards to traditional coal-
fired and IGCC EGUs. The adjusted gross output definition accounts for 
the largest gas compressors at an IGCC facility. Consequently, IGCC 
facilities complying with the NSPS requirements would emit at 
approximately the same net output based emissions rate (i.e., gross 
output minus auxiliary power requirements) as a comparable traditional 
coal-fired EGU. Therefore, with the definition of gross energy output 
for criteria pollutant emission standards (i.e., adjusted gross 
output), both IGCC and traditional coal-fired EGUs that have the same 
gross energy output-based emissions rate would have a similar net 
output-based emissions rate. If we did not include the parasitic load 
from the primary gas compressors when determining the gross emissions 
rate of an IGCC facility, it would emit more pollutants to the 
atmosphere than a traditional coal-fired EGU when complying with the 
criteria pollutant NSPS.
---------------------------------------------------------------------------

    \86\ 40 CFR 60.41Da.
    \87\ International Standards Organization Metric (ISO) 
Conditions are 288 Kelvin (15 [deg]C), 60 percent relative humidity, 
and 101.325 kilopascals (kPa) pressure.
---------------------------------------------------------------------------

    In contrast, in the April 2012 proposal, we proposed a definition 
of gross output as ``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 the unit (i.e., 
steam delivered to an industrial process).'' This definition was 
appropriate since NGCC was the BSER for the combined subcategory and 
auxiliary loads associated with feedwater pumps and associated 
compressors (air separation unit main compressor, oxygen compressor, 
and nitrogen compressor) are not relevant to the gross efficiency of an 
NGCC. However, we requested comment on requiring the use of net output 
based standards. Part of the rationale behind the use of net output-
based standards is that the use of a gross output-based standard as 
defined could have potentially driven the installation of electrically 
driven feed pumps instead of steam driven feed pumps at a steam 
generating unit, even though from an overall net efficiency basis it 
may be more efficient to use steam-driven feed pumps.
    After further consideration and because many of the proposed IGCC 
facilities are actually co-production facilities (i.e., they produce 
useful byproducts and chemicals along with electricity), we have 
concluded that measuring the electricity used by the primary gas 
compressors associated with electricity production at IGCC facilities 
could be more challenging to implement.
    Therefore, we are proposing to define the gross energy output for 
traditional steam generating units to include the electricity measured 
at the generator terminals minus electric power used to run the 
feedwater pumps, and to define the gross electric output for IGCC and 
subpart KKKK affected facilities to include the electricity measured at 
the generator terminals. We are considering and requesting comment on 
(1) whether the definition of ``gross energy output'' in subpart Da for 
GHGs should be consistent with the current definition in subpart Da for 
criteria pollutants, (2) whether we should adopt the proposed 
definition of ``gross energy output'', and (3) whether the definition 
should be the same for both traditional and IGCC facilities. We seek 
comment on how to account for energy consumption associated with 
products other than electricity and useful thermal output created at a 
poly-generation facility and the impact of that energy use on the 
numerical emissions standard, all of which is relevant to possible 
adoption of an adjusted gross output definition.
    We are also considering and requesting comment on using net-output 
based standards either as a compliance alternative for, or in lieu of, 
gross-output based standards, including whether we should have a 
different approach for different subcategories. In the compliance 
alternative approach, owners/operators would elect to comply with 
either a gross-output based standard or an alternate net-output based 
standard. As described in the original proposal for this rulemaking, 
net output is the combination of the gross electrical output of the 
electric generating unit minus the parasitic (i.e., auxiliary) 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 non-IGCC and non-CCS coal-fired station power 
output, approximately 15 percent of non-CCS IGCC-based coal-fired 
station power output and about 2.5 percent of non-CCS 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.

[[Page 1448]]

While the EPA has concluded that the net power supplied to the end user 
is a better indicator of environmental performance than gross output 
from the power producer, we only have CEMS emissions data reported on a 
gross output basis because that is the way the data is currently 
reported under 40 CFR part 75. As noted, switching from gross output to 
net or adjusted gross output would have little or no impact on the 
required rates for gas-fired NGCC plants, which are likely to be the 
dominant fossil fuel-fired technology for new intermediate or base load 
power generation. Since the change would have little impact on these 
units in terms of environmental performance, the EPA has proposed to 
use a standard consistent with current reporting protocols. However, as 
is noted in Table 4, the use of net instead of gross output could have 
a much larger impact on coal-fired power plants.

                 Table 4--Subpart Da Emission Rates \88\
------------------------------------------------------------------------
                                      Approximate
                                      equivalent          Approximate
   Gross output based standard      adjusted gross      equivalent net
                                     output based        output based
                                       standard            standard
------------------------------------------------------------------------
450 kg/MWh (1,000 lb/MWh).......  510 kg/MWh (1,100   560 kg/MWh (1,200
                                   lb/MWh).            lb/MWh).
500 kg/MWh (1,100 lb/MWh).......  570 kg/MWh (1,300   620 kg/MWh (1,400
                                   lb/MWh).            lb/MWh).
540 kg/MWh (1,200 lb/MWh).......  610 kg/MWh (1,300   670 kg/MWh (1,500
                                   lb/MWh).            lb/MWh).
------------------------------------------------------------------------


                  Table 5--Subpart KKKK Emission Rates
------------------------------------------------------------------------
                                             Approximate  equivalent net
        Gross output based standard            output based  standard
------------------------------------------------------------------------
430 kg/MWh (950 lb/MWh)...................  440 kg/MWh (970 lb/MWh).
450 kg/MWh (1,000 lb/MWh).................  460 kg/MWh (1,000 lb/MWh).
500 kg/MWh (1,100 lb/MWh).................  510 kg/MWh (1,100 lb/MWh).
540 kg/MWh (1,200 lb/MWh).................  560 kg/MWh (1,200 lb/MWh).
------------------------------------------------------------------------

    Requiring or including an optional net-output based standard would 
provide more operational flexibility and expand the technology options 
available to comply with the standard for coal-fired PC and CFB EGUs.
---------------------------------------------------------------------------

    \88\ Rounding to two significant figures results in the same 
standard in units of lb/MWh in some cases.
---------------------------------------------------------------------------

    In addition, we are proposing that with respect to CO2 
emissions, 75 percent credit is the appropriate discount factor for 
useful thermal output. However, we are requesting comment on a range of 
two-thirds to three-fourths credit for useful thermal output in the 
final rule.
2. 84-Operating-Month Rolling Average Compliance Option
    We also propose an 84-operating-month rolling average compliance 
option that would be available for affected subpart Da boilers and IGCC 
facilities. The EPA suggests that this 84-operating-month rolling 
average compliance option will offer operational flexibility and will 
tend to dampen short-term emission excursions, which may be warranted 
especially at the initial startup of the facility and the CCS system.
    Thus, under our proposed approach, new fossil fuel-fired boilers 
and IGCC units would be required, based on the performance of currently 
available CCS technology, to meet a standard of 1,100 lb 
CO2/MWh on a 12-operating-month rolling average, or 
alternatively a lower--but equivalently stringent--standard on an 84-
operating-month rolling average, which we propose as between 1,000 lb 
CO2/MWh and 1,050 lb CO2/MWh. The EPA has 
previously offered sources optional, longer-term emission standards 
that are discounted from the primary emissions standard in combination 
with a longer averaging period. We are requesting comment on the 
appropriate numerical standard such that the 84-operating-month 
standard would be as stringent as or more stringent than the 12-
operating-month standard. We also request comment on whether owners/
operators electing to comply with the 84-operating-month standard 
should also be required to comply with a maximum 12-operating-month 
standard. This standard would be between the otherwise applicable 
proposed 1,100 lb CO2/MWh standard and an emissions rate of 
a coal-fired EGU without CCS (e.g., 1,800 lb CO2/MWh), and 
we solicit comment on what the standard should be. This shorter term 
standard would facilitate enforceability and assure adequate emission 
reductions.
    We have concluded that this alternative compliance option is not 
necessary for new stationary combustion turbine EGUs, as they should be 
able to meet the proposed performance standard with no need for add-on 
technology. We seek comment on all other aspects of this 84-operating-
month rolling averaging compliance option.
3. Combined Heat and Power
    To recognize the environmental benefit of reduced electric 
transmission and distribution losses of CHP, we are proposing that CHP 
facilities where at least 20.0 percent of the total gross useful energy 
output consists of electric or direct mechanical output and 20.0 
percent of the total gross useful energy output consists of useful 
thermal output on a rolling three calendar year basis receive similar 
credit as currently in subpart Da and the proposed amendments to 
subpart KKKK (77 FR 52554). Specifically, the measured electric output 
would be divided by 0.95 to account for a five percent avoided energy 
loss in the transmission of electricity. The minimal electric and 
thermal output requirements are to avoid owners/operators from selling 
trivial amounts of thermal output and claiming a line loss benefit when 
in reality they are similar to a central power station.
    Actual transmission and distribution losses vary from location to 
location, but we propose that this 5 percent of actual MWh represents a 
reasonable average amount for the avoided transmission and distribution 
losses for CHP facilities. Note that we propose to limit this 5 percent 
adjustment to facilities for which the useful thermal output is at 
least 20 percent of the total output.

C. Startup, Shutdown, and Malfunction Requirements

1. Startups and Shutdowns
    Consistent with Sierra Club v. EPA,\89\ the EPA is proposing 
standards in this rule that apply at all times, including during 
startups and shutdowns. In proposing the standards in this rule, the 
EPA has taken into account startup and shutdown periods and, for the 
reasons explained below has not proposed alternate standards for those 
periods. In the compliance calculation, periods of startup and shutdown 
are included as periods of partial load. To establish the proposed 
NSPS's output-based CO2 standard, we accounted for periods 
of startup and shutdown by incorporating them as periods of partial 
load operation. As noted above, the proposed

[[Page 1449]]

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-operating-month period. The EPA is 
proposing that sources incorporate in their compliance determinations 
emissions from all periods, including startup or shutdown, that fuel is 
combusted and emissions monitors are not out-of-control, as well as all 
power produced over the periods of emissions measurements. Given that 
the duration of startup or shutdown periods are expected to be small 
relative to the duration of periods of normal operation and that the 
fraction of power generated during periods of startup or shutdown is 
expected to be very small during startup or shutdown periods, the 
impact of these periods on the total average is expected to be minimal. 
Periods of startup and shutdown will be short, relative to total 
operating time. Since we are primarily concerned with overall 
environmental performance over extended periods of time, incorporating 
relatively short periods of partial load is believed to have a 
negligible effect on the performance of the source with respect to 
long-term efficiency.
---------------------------------------------------------------------------

    \89\ 551 F.3d 1019 (D.C. Cir. 2008).
---------------------------------------------------------------------------

    We solicit comment on any alternative to our proposal that the 
periods of startup and shutdown be included as periods of partial load 
in the 12- and 84-operating-month rolling averaging compliance option.
2. Malfunctions
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is defined as 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. Failures that are caused in part by poor maintenance or 
careless operations are not malfunctions.(40 CFR 60.2). The EPA has 
determined that CAA section 111 does not require that emissions that 
occur during periods of malfunction be factored into development of CAA 
section 111 standards. Nothing in CAA section 111 or in case law 
requires that the EPA anticipate and account for the innumerable types 
of potential malfunction events in setting emission standards. CAA 
section 111 provides that the EPA set standards of performance which 
reflect the degree of emission limitation achievable through ``the 
application of the best system of emission reduction'' that the EPA 
determines is adequately demonstrated. 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 (D.C. 
Cir. 1999) (The EPA typically has wide latitude in determining the 
extent of data-gathering necessary to solve a problem. We generally 
defer to an agency's decision to proceed on the basis of imperfect 
scientific information, rather than to ``invest the resources to 
conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590 
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general 
limit, individual permit, or even any upset provision can anticipate 
all upset situations. After a certain point, the transgression of 
regulatory limits caused by `uncontrollable acts of third parties,' 
such as strikes, sabotage, operator intoxication or insanity, and a 
variety of other eventualities, must be a matter for the administrative 
exercise of case-by-case enforcement discretion, not for specification 
in advance by regulation''). In addition, the goal of a source that 
uses the best system of emission reduction 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 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 a violation of the relevant emission standard. (See, 
e.g., State Implementation Plans: Response to Petition for Rulemaking; 
Finding of Excess Emissions During Periods of Startup, Shutdown, and 
Malfunction; Proposed Rule, 78 FR 12460 (Feb. 22, 2013): (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)). The EPA is therefore proposing to add an affirmative 
defense to civil penalties for violations of emission standards 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 Sec.  60.5530. (See 40 CFR 
22.24). The criteria are designed in part to ensure that the 
affirmative defense is available only where the event that causes a 
violation of the emission standard 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 
the violation ``[w]as caused by a sudden, infrequent, and unavoidable 
failure of air pollution control, 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 Sec.  60.5530 and to prevent 
future malfunctions. For example, the source must prove by a 
preponderance of the evidence that

[[Page 1450]]

``[r]epairs were made as expeditiously as possible when a violation 
occurred . . .'' and that ``[a]ll possible steps were taken to minimize 
the impact of the violation 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 
22.27).
    The EPA included an affirmative defense in the proposed rule 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 standards may be 
violated 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 
(D.C. Cir. 2008) Thus, the EPA is required to ensure that section 111 
emissions standards are continuous. The affirmative defense for 
malfunction events meets this requirement by ensuring that even where 
there is a malfunction, the emission standard is still enforceable 
through injunctive relief. The United States Court of Appeals for the 
Fifth Circuit recently upheld the EPA's view that an affirmative 
defense provision is consistent with section 113(e) of the Clean Air 
Act. Luminant Generation Co. LLC v. United States EPA, 2013 U.S. App. 
LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 427 (5th Cir. Oct. 12, 
2012) (upholding the EPA's approval of affirmative defense provisions 
in a CAA State Implementation Plan). While ``continuous'' standards, 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 (D.C. Cir. 1973), the D.C. Circuit 
acknowledged that in setting standards under CAA section 111 ``variant 
provisions'' such as provisions allowing for upsets during startup, 
shutdown and equipment 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 (D.C. 
Cir. 1973). Although due to intervening case law such as Sierra Club v. 
EPA and the CAA 1977 amendments (which added the ``continuous'' 
requirement of 42 U.S.C. 7602(k)) these cases are no longer good law on 
whether EPA can exempt malfunctions from liability, their core 
principle remains valid: regulatory accommodation is appropriate where 
a standard cannot be achieved 100 percent of the time due to 
circumstances out of the control of the owner/operator of the source, 
and a system that incorporates some level of flexibility is reasonable. 
The affirmative defense simply provides for a defense to civil 
penalties for violations that are proven to be beyond the control of 
the source. By incorporating an affirmative defense, the EPA has 
formalized its approach to malfunctions. 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). See also, Mont. 
Sulphur & Chem. Co. v. United States EPA, 666 F.3d. 1174 (9th Cir. 
2012) (rejecting industry argument that reliance on the affirmative 
defense was not adequate). But see, Weyerhaeuser Co. v. Costle, 590 
F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach 
is adequate). The affirmative defense provisions give the EPA the 
flexibility to both ensure that its emission standards 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.
    We propose that these same requirements, an affirmative defense to 
civil penalties for violations of emission limits that are caused by 
malfunctions, would apply to both the 12-operating-month standard and 
the 84-operating-month rolling average compliance option; however, we 
will take comment on whether it is appropriate to have an affirmative 
defense for the 84-operating-month rolling average portion of that 
compliance option, given that we would expect malfunctions to only 
impact shorter averaging periods, and the longer the compliance period, 
the less likely malfunction events are to impact a source's ability to 
meet the standard.

D. Continuous Monitoring Requirements

    Today's proposed rule would require owners or operators of EGUs 
that combust solid fuel to install, certify, maintain, and operate 
continuous emission monitoring systems (CEMS) to measure CO2 
concentration, stack gas flow rate, and (if needed) stack gas moisture 
content in accordance with 40 CFR Part 75, in order to determine hourly 
CO2 mass emissions rates (tons/hr).
    The proposed rule would allow owners or operators of EGUs that burn 
exclusively gaseous or liquid fuels to install fuel flow meters as an 
alternative to CEMS and to calculate the hourly CO2 mass 
emissions rates using Equation G-4 in Appendix G of part 75. To 
implement this option, hourly measurements of fuel flow rate and 
periodic determinations of the gross calorific value (GCV) of the fuel 
are also required, in accordance with Appendix D of part 75.
    In addition to requiring monitoring of the CO2 mass 
emission rate, the proposed rule would require EGU owners or operators 
to monitor the hourly unit operating time and ``gross output'', 
expressed in megawatt hours (MWh). The gross output includes electrical 
output plus any mechanical output, plus 75 percent of any useful 
thermal output.
    The proposed rule would require EGU owners or operators to prepare 
and submit a monitoring plan that includes both electronic and hard 
copy components, in accordance with Sec. Sec.  75.53(g) and (h). The 
electronic portion of the monitoring plan would be submitted to the 
EPA's Clean Air Markets Division (CAMD) using the Emissions Collection 
and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion 
of the plan would be sent to the applicable State and EPA Regional 
office. Further, all monitoring systems used to determine the 
CO2 mass emission rates would have to be certified according 
to Sec.  75.20 and section 6 of Appendix A to part 75 within the 180-
day window of time allotted under Sec.  75.4(b), and would be required 
to meet the applicable on-going quality assurance procedures in 
Appendices B and D of part 75.
    The proposed rule would require all valid data collected and 
recorded by the monitoring systems (including data recorded during 
startup, shutdown, and malfunction) to be used in assessing compliance. 
Failure to collect and record required data is a violation of the 
monitoring requirements, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities that temporarily interrupt the measurement of stack 
emissions (e.g., calibration error tests, linearity checks, and 
required zero and span

[[Page 1451]]

adjustments). An affirmative defense to civil penalties for 
malfunctions is available to a source if it can demonstrate that 
certain criteria and requirements are satisfied.
    The proposed rule would require only those operating hours in which 
valid data are collected and recorded for all of the parameters in the 
CO2 mass emission rate equation to be used for compliance 
purposes. Additionally for EGUs using CO2 CEMS, only 
unadjusted stack gas flow rate values would be used in the emissions 
calculations. In this proposal, Part 75 bias adjustment factors (BAFs) 
would not be applied to the flow rate data. These restrictions on the 
use of Part 75 data for Part 60 compliance are consistent with previous 
NSPS regulations and revisions.
    The following variations from and additions to the basic part 75 
monitoring would be required:
     If you determine compliance using CEMS, you would be 
required to use a laser device to measure the stack diameter at the 
flow monitor and the reference method sampling locations prior to the 
initial setup (characterization) of the flow monitor. For circular 
stacks, you would need to make measurements of the diameter at 3 or 
more distinct locations and average the results. For rectangular stacks 
or ducts, you would need to make measurements of each dimension (i.e., 
depth and width) at 3 or more distinct locations and average the 
results. If the flow rate monitor or reference method sampling site is 
relocated, you would repeat these measurements at the new location.
     If you elect to use Method 2 in Appendix A-1 of part 60 to 
perform the required relative accuracy test audits (RATAs) of the part 
75 flow rate monitoring system, you would have to use a calibrated 
Type-S pitot tube or pitot tube assembly. Use of the default Type-S 
pitot tube coefficient would not be permitted.
     If your EGU combusts natural gas and/or fuel oil and you 
elect to measure the CO2 mass emissions rate using Equation 
G-4 in Appendix G of part 75, you would be allowed to determine site-
specific carbon-based F-factors using Equation F-7b in section 3.3.6 of 
Appendix F of part 75, and you could use these Fc values in 
the emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature.
    Today's proposed rule includes the following special compliance 
provisions for units with common stack or multiple stack 
configurations; these provisions are consistent with Sec.  60.13(g):
     If two or more of your EGUs share a common exhaust stack, 
are subject to the same emission limit, and you are required to (or 
elect to) determine compliance using CEMS, you would be allowed to 
monitor the hourly CO2 mass emission rate at the common 
stack instead of monitoring each EGU separately. If this option is 
chosen, the hourly gross electrical load (or steam load) would be the 
sum of the hourly loads for the individual EGUs and the operating time 
would be expressed as ``stack operating hours'' (as defined in 40 CFR 
72.2). Then, if compliance with the applicable emission limit is 
attained at the common stack, each EGU sharing the stack would be in 
compliance with the CO2 emissions limit.
     If you are required to (or elect to) determine compliance 
using CEMS and the effluent from your EGU discharges to the atmosphere 
through multiple stacks (or, if the effluent is fed to a stack through 
multiple ducts and you choose to monitor in the ducts), you would be 
required to monitor the hourly CO2 mass emission rate and 
the ``stack operating time'' at each stack or duct separately. In this 
case, compliance with the applicable emission limit would be determined 
by summing the CO2 mass emissions measured at the individual 
stacks or ducts and dividing by the total gross output for the unit.
    The proposed rule would require 95 percent of the operating hours 
in each compliance period (including the compliance periods for the 
intermediate emission limits) to be valid hours, i.e., operating hours 
in which quality-assured data are collected and recorded for all of the 
parameters used to calculate CO2 mass emissions. EGU owners 
or operators would have the option to use backup monitoring systems, as 
provided in Sec. Sec.  75.10(e) and 75.20(d), to help meet this 
proposed data capture requirement.

E. Emissions Performance Testing Requirements

    In accordance with Sec.  75.64(a), the proposed rule would require 
an EGU owner or operator to begin reporting emissions data when 
monitoring system certification is completed or when the 180-day window 
in Sec.  75.4(b) allotted for initial certification of the monitoring 
systems expires (whichever date is earlier). For EGUs subject to the 
450 kg/MWh (1,000 lb/MWh) standard or the 500 kg/MWh (1,100 lb/MWh) 
emission standard, the initial performance test would consist of the 
first 12-operating-months of data, starting with the month in which 
emissions are first required to be reported. The initial 12-operating-
month compliance period would begin with the first month of the first 
calendar year of EGU operation in which the facility exceeds the 
capacity factor applicability threshold.
    The traditional 3-run performance tests (i.e., stack tests) 
described in Sec.  60.8 would not be required for this rule. Following 
the initial compliance determination, the emission standard would be 
met on a 12-operating-month rolling average basis. For EGUs that 
combust coal and/or petroleum coke and whose owners or operators elect 
to comply with the alternative 84-operating-month rolling average 
emissions standard, the first month in the compliance period would be 
the month in which emissions reporting is required to begin under Sec.  
75.64(a).

F. Continuous Compliance Requirements

    Today's proposed rule specifies that compliance with the 1,000 lb/
MWh (450 kg/MWh) and 1,100 lb/MWh (500 kg/MWh) CO2 mass 
emissions rate limits would be determined on a 12-operating-month 
rolling average basis, updated after each new operating month. For each 
12-operating-month compliance period, quality-assured data from the 
certified Part 75 monitoring systems would be used together with the 
gross output over that period of time to calculate the average 
CO2 mass emissions rate.
    The proposed rule specifies that the first operating month included 
in either the initial 12- or 84-operating-month compliance period would 
be the month in which reporting of emissions data is required to begin 
under Sec.  75.64(a), i.e., either the month in which monitoring system 
certification is completed or the month in which the 180-day window 
allotted to finish certification testing expires (whichever month is 
earlier).
    We are proposing that initial compliance with the applicable 
emissions limit in kg/MWh be calculated by dividing the sum of the 
hourly CO2 mass emissions values by the total gross output 
for the 12- or 84-operating-month period. Affected EGUs would continue 
to be subject to the standards and maintenance requirements in the 
section 111 regulatory general provisions contained in 40 CFR Part 60, 
subpart A.

G. Notification, Recordkeeping, and Reporting Requirements

    Today's proposed rule would require an EGU owner or operator to 
comply with the applicable notification requirements in Sec. Sec.  
75.61, 60.7(a)(1) and (a)(3) and 60.19. The proposed rule would also 
require the applicable recordkeeping requirements in subpart

[[Page 1452]]

F of part 75 to be met. For EGUs using CEMS, the data elements that 
would be recorded include, among others, hourly CO2 
concentration, stack gas flow rate, stack gas moisture content (if 
needed), unit operating time, and gross electric generation. For EGUs 
that exclusively combust liquid and/or gaseous fuel(s) and elect to 
determine CO2 emissions using Equation G-4 in Appendix G of 
part 75, the key data elements in subpart F that would be recorded 
include hourly fuel flow rates, fuel usage times, fuel GCV, gross 
electric generation.
    The proposed rule would require EGU owners or operators to keep 
records of the calculations performed to determine the total 
CO2 mass emissions and gross output for each operating 
month. Records would be kept of the calculations performed to determine 
the average CO2 mass emission rate (kg/MWh) and the 
percentage of valid CO2 mass emission rates in each 
compliance period. The proposed rule would also require records to be 
kept of calculations performed to determine site-specific carbon-based 
F-factors for use in Equation G-4 of part 75, Appendix G (if 
applicable).
    For EGU owners or operators who would elect to comply with the 84-
operating-month rolling average emissions standard, records must be 
kept for 10 years. All other records would be kept for a period of 
three years. All required records would be kept on-site for a minimum 
of two years, after which the records could be maintained off-site.
    The proposed rule would require all affected EGU owners/operators 
to submit quarterly electronic emissions reports in accordance with 
subpart G of part 75. The proposed rule would require these reports to 
be submitted using the ECMPS Client Tool. Except for a few EGUs that 
may be exempt from the Acid Rain Program (e.g., oil-fired units), this 
is not a new reporting requirement. Sources subject to the Acid Rain 
Program are already required to report the hourly CO2 mass 
emission rates that are needed to assess compliance with today's rule.
    Additionally, in the proposed rule and as part of an Agency-wide 
effort to streamline and facilitate the reporting of environmental 
data, the rule would require selected data elements that pertain to 
compliance under this rule, and that serve the purpose of traditional 
excess emissions reports, to be reported periodically using ECMPS.
    Specifically, for EGU owners/operators who would comply with a 12-
operating-month rolling average standard, quarterly electronic ``excess 
emissions'' reports must be submitted, within 30 days after the end of 
each quarter. The first report would be for the quarter that includes 
the final (12th) operating month of the initial 12-operating-month 
compliance period. For that initial report and any subsequent report in 
which the twelfth operating month of a compliance period (or periods) 
occurs during the calendar quarter, the average CO2 mass 
emissions rate (kg/MWh) would be reported for each compliance period, 
along with the dates (year and month) of the first and twelfth 
operating months in the compliance period and the percentage of valid 
CO2 mass emission rates obtained in the compliance period. 
The dates of the first and last operating months in the compliance 
period would clearly bracket the period used in the determination, 
which facilitates auditing of the data. Reporting the percentage of 
valid CO2 mass emission rates is necessary to demonstrate 
compliance with the requirement to obtain valid data for 95 percent of 
the operating hours in each compliance period. Any excess emissions 
that occur during the quarter would be identified. If there are no 
compliance periods that end in the quarter, a definitive statement to 
that effect would be included in the report. If one or more compliance 
periods end in the quarter but there are no excess emissions, a 
statement to that effect would be included in the report.
    For EGU owners or operators that would comply with an 84-operating-
month rolling average basis, quarterly electronic ``excess emissions'' 
reports would be submitted, within 30 days after the end of each 
quarter. The first report would be for the quarter that includes the 
final (60th) operating month of the initial 84-operating-month 
compliance period. For that initial report and any subsequent report in 
which the sixtieth operating month of a compliance period (or periods) 
occurs during the calendar quarter, the average CO2 mass 
emissions rate (kg/MWh) must be reported for each compliance period, 
along with the dates (year and month) of the first and sixtieth 
operating months in the compliance period and the percentage of valid 
CO2 mass emission rates obtained in the compliance period. 
The dates of the first and last operating months in the compliance 
period would clearly bracket the period used in the determination, 
which facilitates auditing of the data. Reporting of the percentage of 
valid CO2 mass emission rates is necessary to demonstrate 
compliance with the requirement to obtain valid data for 95 percent of 
the operating hours in each compliance period. Any excess emissions 
that occur during the quarter would be identified. If there are no 
compliance periods that end in the quarter, a definitive statement to 
that effect would be included in the report. If one or more compliance 
periods end in the quarter but there are no excess emissions, a 
statement to that effect would be included in the report.
    Currently, ECMPS is not programmed to receive excess emission 
report information from EGUs. However, we will make the necessary 
modifications to the system in order to fully implement the reporting 
requirements of this rule upon promulgation.
    For EGU owners or operators that would assert an affirmative 
defense for a failure to meet a standard due to malfunction, the owner 
or operator must follow the reporting requirements for affirmative 
defense. Those requirements are found in 40 CFR 60.5530. The report to 
the Administrator, with all necessary supporting documentation, 
explains how the source has met the requirements set forth in subparts 
Da, KKKK, and TTTT to assert affirmative defense. This report must be 
submitted on the same schedule as the next quarterly report required 
after the initial occurrence of the violation of the relevant standard 
(which may be the end of any applicable averaging period). If the 
quarterly report is due less than 45 days after the initial occurrence 
of the violation, the affirmative defense report may be included in the 
second quarterly report due after the initial occurrence of the 
violation of the relevant standard.

IV. Rationale for Reliance on Rational Basis To Regulate GHGs From 
Fossil-Fired EGUs

A. Overview

    In our original proposal, we proposed and solicited comment on what 
basis we are required to have concerning the health and welfare impacts 
of GHG emissions from fossil-fuel fired power plants in order to 
regulate those emissions under CAA section 111. However, we took the 
position that we are not required to make findings that GHGs from 
fossil-fired power plants ``cause [ ], or contribute [ ] significantly 
to, air pollution which may reasonably be anticipated to endanger 
public health or welfare,'' under CAA section 111(b)(1)(A).
    We have reconsidered that proposal in light of the numerous 
comments we received. In today's document, we propose that under 
section 111, the EPA is required to have a rational basis for

[[Page 1453]]

promulgating standards for GHG emissions from electricity generating 
plants, and that the EPA has such a basis because the EPA has already 
determined that GHG emissions may reasonably be anticipated to endanger 
public health and welfare, and because electricity generating plants, 
as an industry, constitute, by a significant margin, the largest 
emitters in the inventory. In the April 2012 proposal, the EPA 
discussed whether CAA section 111 requires that the EPA issue, as a 
prerequisite for this rulemaking, another ``endangerment'' finding. 
After reviewing the comments, recent scientific developments, the 
amount of emissions from the power plant sector, and the case law, the 
EPA has concluded that even if section 111 requires an endangerment 
finding, the rational basis described in today's action would qualify 
as an endangerment finding as well.
    As related matters, in this notice, we are proposing to establish 
regulatory requirements for CO2 emissions of affected units, 
which are included in source categories (both steam-generating units 
and turbines) that the EPA already listed under CAA section 
111(b)(1)(A) for regulation under CAA and we are not proposing a 
listing of a new source category. We are, however, proposing to 
subcategorize different sets of sources, and establish different 
CO2 standards of performance for them, in accordance with 
CAA section 111(b)(2). To avoid confusion, we are proposing to codify 
the CO2 standards of performance in the same subparts--Da 
and KKKK, depending on the types of units--that currently include the 
standards of performance for conventional pollutants. We are also co-
proposing, in the alternative, to codify the CO2 standards 
in a new subpart, TTTT, as we proposed in the original proposal for 
this rulemaking in April, 2012.\90\
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    \90\ It should be noted that CAA section 111 clearly applies to 
GHGs. The U.S. Supreme Court has made this clear because (i) section 
111 applies to ``any air pollutant,'' CAA section 111(a)(3), see 
section 111(d)(1)(A) (exempting, for purposes of section 111(d), 
certain air pollutants); and in Massachusetts v. EPA, 549 U.S. 497 
(2007), the Supreme Court held that the term ``air pollutant,'' as 
defined under CAA section 302(g), includes GHGs; and (ii) in 
American Electric Power Company v. Connecticut, 131 S.Ct. 2527 
(2011), the Supreme Court based its holding that ``the Clean Air Act 
and the EPA actions it authorizes displace any federal common law 
right to seek abatement of carbon-dioxide emissions from fossil 
fuel-fired power plants'' on the grounds that CAA section 111 
``provides a means to seek limits on emissions of carbon dioxide 
from domestic power plants * * *.'' Id. at 2538.
---------------------------------------------------------------------------

B. Climate Change Impacts From GHG Emissions; Amounts of GHGs From 
Fossil Fuel-Fired EGUs

    In 2009, the EPA Administrator issued the Endangerment Finding 
under CAA section 202(a)(1). 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 of current and future generations, and focused on public health 
and public welfare impacts within the United States. Fossil fuel-fired 
EGUs are by far the largest emitters of GHGs, primarily in the form of 
CO2, among stationary sources in the U.S. These adverse 
effects of GHGs on public health and welfare, and the amounts of GHGs 
emitted by fossil fuel-fired EGUs are briefly summarized in the Section 
II of this preamble and described in more detail in the RIA, and need 
not be recited here.

C. CAA Section 111 Requirements

    To review the key CAA section 111 requirements: CAA section 
111(b)(1)(A), by its terms, requires that the Administrator 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 list 
if in his judgment it causes, or contributes significantly to air 
pollution which may reasonably be anticipated to endanger public health 
or welfare.
    CAA 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.'' CAA 
section 111(b)(2) provides that ``The Administrator may distinguish 
among classes, types, and sizes within categories of new sources for 
the purpose of establishing such standards.''

D. Interpretation of CAA Section 111 Requirements

    CAA section 111(b)(1)(A) requires the EPA to list a source category 
if it contributes significantly to air pollution that endangers public 
health or welfare. The EPA must necessarily conduct this listing by 
making determinations as to the health or welfare impacts of the 
pollution to which the source category's pollutants contribute, and as 
to the significance of the amount of such contribution. However, by the 
terms of CAA section 111(b)(1)(A), the EPA may make these 
determinations on the basis of the impacts of the air pollution as a 
whole to which the source category's pollutants, taken as a whole, 
contribute. Nothing in CAA section 111(b)(1)(A) requires that the EPA 
make separate determinations for each type of pollution or each 
pollutant.
    After listing a source category, the EPA must proceed to promulgate 
standards of performance for the source category's pollutants under CAA 
section 111(b)(1)(B) and 111(a)(1). However, nothing in those 
provisions requires that, at the time when the EPA promulgates the 
standards of performance for the individual pollutants, the EPA must 
make a determination as to the health or welfare effects of those 
particular pollutants or as to the significance of the amount of the 
source category's emissions of those pollutants. Clearly, CAA section 
111 does not by its terms require that as a prerequisite for the EPA to 
promulgate a standard of performance for a particular pollutant, the 
EPA must first find that the pollutant causes or contributes 
significantly to air pollution that endangers public health or welfare. 
The lack of any such requirement contrasts with 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).
    The lack of any express requirement in CAA section 111 addressing 
whether and how the EPA is to evaluate emissions of a particular 
pollutant from the listed source category as a prerequisite for 
promulgation of a standard of performance is properly viewed as a 
statutory gap that requires the EPA to make what we refer to as a 
Chevron step 2 interpretation. Under the U.S. Supreme Court's 1984 
decision in Chevron U.S.A. Inc. v. NRDC, \91\ to interpret how a 
statute applies to a particular question, an agency must, at Step 1, 
determine whether Congress's intent as to the specific question is 
clear, and, if so, the agency must give effect to that intent. If 
congressional intent is not clear, then the agency, at Step 2, has 
discretion to fashion an interpretation that is a reasonable 
construction of the statute.\92\ In this

[[Page 1454]]

case, the EPA is authorized to develop a reasonable interpretation.
---------------------------------------------------------------------------

    \91\ 467 U.S. 837 (1984).
    \92\ Id. at 842-43.
---------------------------------------------------------------------------

    Our interpretation is that in order to promulgate a section 111 
standard of performance for a particular pollutant, we do not need to 
make a pollutant-specific endangerment finding, but instead must 
demonstrate a rational basis for controlling the emissions of the 
pollutant. That rational basis may be based on information concerning 
the health and welfare impacts of the air pollution at issue, and the 
amount of contribution that the source category's emissions make to 
that air pollution.
    Commenters on the April 2012 proposal stated that the EPA is 
required to make an endangerment finding for CO2 because 
when the EPA listed this source category, it was on the basis of other 
pollutants, and not CO2. However, to reiterate, CAA section 
111(b)(1)(A) by its terms requires that the EPA ``shall publish (and 
from time to time thereafter, shall revise) a list of categories of 
stationary sources,'' and that the EPA shall list ``a category of 
sources'' based on the EPA's judgment that the category ``causes, or 
contributes significantly to, air pollution'' that endangers public 
health or welfare. Thus, this provision requires that the EPA make the 
listing decision on a category basis, and not on a pollutant-by-
pollutant basis. That is, this provision does not require that the EPA 
establish separate lists of source categories, with each list covering 
a different pollutant. Therefore, this provision does not require that 
the EPA make an endangerment finding on a pollutant by pollutant basis.
    Commenters on the April 2012 proposal stated that the EPA was 
required to make an endangerment finding because by creating the new 
subpart TTTT in 40 CFR Part 60, the EPA was listing a new source 
category that included the affected units. However, in neither the 
original April 2012 proposal nor this new proposal has EPA proposed to 
list a new source category. The EPA initially included fossil fuel-
fired electric steam generating units (which included boilers) in a 
category that it listed under section 111(b)(1)(A) \93\ and the EPA 
promulgated the first set of standards of performance for this source 
category in 1971, which the EPA codified in subpart D.\94\ 
Subsequently, the EPA included fossil fuel-fired combustion turbines in 
a category that the EPA listed under section 111(b)(1)(A),\95\ and the 
EPA promulgated standards of performance for this source category in 
1979, which the EPA codified in subpart GG.\96\
---------------------------------------------------------------------------

    \93\ ``Air Pollution Prevention and Control: List of Categories 
of Stationary Sources,'' 36 FR 5931 (March 31, 1971).
    \94\ ``Standards of Performance for Fossil-Fuel-Fired Steam 
Generators for Which Construction Is Commenced After August 17, 
1971,'' 36 FR 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36 
FR 5931 (Mar. 31, 1971).
    \95\ 42 FR 53657 (Oct. 3, 1977).
    \96\ ``Standards of Performance for Electric Utility Steam 
Generating Units for Which Construction is Commenced After September 
18, 1978,'' 44 FR 33580 (June 11, 1979).
---------------------------------------------------------------------------

    The EPA has revised those regulations, and in some instances, has 
revised the codifications (that is, the subparts), several times over 
the ensuing decades. In 1979, the EPA divided subpart D into 3 
subparts--Da (``Standards of Performance for Electric Utility Steam 
Generating Units for Which Construction is Commenced After September 
18, 1978''), Db (``Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units'') and Dc (``Standards of 
Performance for Small Industrial-Commercial-Institutional Steam 
Generating Units'')--in order to codify separate requirements that it 
established for these subcategories.\97\ In 2006, the EPA created 
subpart KKKK, ''Standards of Performance for Stationary Combustion 
Turbines,'' which applied to certain sources previously regulated in 
subparts Da and GG.\98\ None of these rulemakings, including the 
revised codifications, however, constituted a new listing under CAA 
section 111(b)(1)(A).
---------------------------------------------------------------------------

    \97\ 44 FR 33580 (June 11, 1979).
    \98\ 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (Mar. 
20, 2009).
---------------------------------------------------------------------------

    In today's rulemaking, the EPA is promulgating new standards of 
performance for CO2 emissions from certain sets of sources, 
e.g., steam-generating boilers and turbines. Moreover, we are 
establishing different requirements for different sets of sources, 
including steam-generating boilers as well as smaller and larger 
combustion turbines, in accordance with CAA section 111(b)(2). That 
provision authorizes the EPA to ``distinguish among classes, types, and 
sizes within categories of new sources for the purpose of establishing 
. . . standards [of performance.]''
    In today's rulemaking, we are including a proposal and, in the 
alternative, a co-proposal, which take two different approaches to the 
source categories and their codification.\99\ Our proposal is to codify 
the new CO2 standards in the same subparts in which the 
standards of performance for conventional pollutants are codified. 
Thus, we propose to codify the GHG standards for steam-generating 
boilers as a new section in subpart Da, and the GHG standards for 
combustion turbines as new sections in subpart KKKK. This proposal does 
not list a new category under section 111(a)(1)(A). Nor does this 
proposal revise either of the two source categories--steam-generating 
boilers and combustion turbines--that EPA has already listed, or revise 
the codification of the new source requirements for those categories in 
subparts Da, GG, and KKKK. Under this proposal, the establishment of 
different requirements for different sets of sources--for example, 
coal-fired power plants, larger NGCC plants, and smaller NGCC plants--
constitute subcategorizations within the existing categories.
---------------------------------------------------------------------------

    \99\ In the original proposal for this rulemaking, the EPA 
proposed to create within 40 CFR part 60 a new subpart that would 
include GHG emission regulatory requirements for electric utility 
steam generating units (i.e., boilers and IGCC units), whose 
conventional pollutant regulatory requirements are codified under 
subpart Da; as well as stationary combustion turbines that generate 
electricity for sale and meet certain size and operational criteria, 
conventional pollutant regulatory requirements are codified under 
subpart KKKK. The EPA proposed to number this newly created subpart 
as subpart TTTT. The EPA explained that combining the GHG regulatory 
requirements for those sources in TTTT was appropriate because the 
EPA was establishing the same limit for all those sources based on 
the same BSER, which was NGCC. 77 FR 22410/2-22411/3.
---------------------------------------------------------------------------

    In the alternative, we co-propose to combine the two source 
categories--again, steam-generating boilers and combustion turbines--
for purposes of regulating CO2 emissions (but not for 
regulating emissions of conventional pollutants), and to codify all of 
the proposed regulatory requirements in a new subpart, TTTT.\100\ This 
category, created by combining two existing categories, cannot be 
considered a new source category that EPA is placing on the list of 
categories for regulation under CAA section 111(b)(1)(A). Under this 
co-proposal, the establishment of different requirements for different 
sets of sources continues to constitute subcategorizations within the 
existing category.
---------------------------------------------------------------------------

    \100\ Under this co-proposal, these regulatory requirements are 
substantively the same as the requirements proposed for inclusion in 
subparts Da and KKKK, and are simply collected in a separate 
subpart, TTTT.
---------------------------------------------------------------------------

    We solicit comment on the relative merits of each approach. In 
particular we seek comment on whether the co-proposal to combine the 
categories and codify the GHG standards for all new affected sources in 
subpart TTTT will offer any additional flexibility for any future 
emission guidelines for existing sources, for example, by facilitating 
a system-wide approach, such as emission rate averaging, that covers 
fossil-fuel

[[Page 1455]]

fired steam generating units and combustion turbines.

E. Rational Basis To Promulgate Standards for GHGs From Fossil-Fired 
EGUs

    In this rulemaking, the EPA has a rational basis for concluding 
that emissions of CO2 from fossil-fired power plants, which 
are the major U.S. source of greenhouse gas air pollution, merits 
taking action under CAA section 111. As noted, in 2009, the EPA made a 
finding that GHG air pollution may reasonably be anticipated to 
endanger public health or welfare, and in 2010, the EPA denied 
petitions to reconsider that finding. The EPA extensively reviewed the 
available science concerning GHG pollution and its impacts in taking 
those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit 
upheld the finding and denial of petitions to reconsider. In addition, 
assessments from the NRC and the IPCC, published in 2010, 2011, and 
2012 lend further credence to the validity of the Endangerment Finding. 
As discussed below, no information that commenters have presented or 
that the EPA has reviewed provides a basis for rescinding that finding. 
In addition, as noted, the high level of GHG emissions from the fossil-
fired EGUs makes clear that it is rational for the EPA to regulate GHG 
emissions from this sector. This information amply supports that the 
EPA has a rational basis for promulgating regulations under CAA section 
111 designed to address GHG air pollution.
    Our conclusion is consistent with the case law handed down by the 
D.C. Circuit. In its 1980 decision in National Lime Association v. 
EPA,\101\ the Court upheld EPA's determination that lime manufacturing 
plants emit particulates that contribute significantly to air pollution 
that endangers public health or welfare. The Court noted that (i) EPA's 
basis was its prior determination that ``the significant production of 
particulate emissions . . . cause[s] or contribute[s] to air pollution 
(which may reasonably be anticipated to endanger public health or 
welfare);'' and (ii) ``[t]he Agency has made this determination for 
purposes of establishing national primary and secondary ambient air 
quality standards under [CAA section 109].'' The Court held:
---------------------------------------------------------------------------

    \101\ 627 F.2d 416 (D.C. Cir. 1980).

    We think the danger of particulate emissions' effect on health 
has been sufficiently supported in the Agency's (and its 
predecessor's) previous determinations to provide a rational basis 
for the Administrator's finding in this case.\102\
---------------------------------------------------------------------------

    \102\ Id. at 431-32 n.48.

Similarly, in National Asphalt Pavement Ass'n v. Train,\103\ the D.C. 
Circuit upheld a determination by the EPA that asphalt cement plants 
contribute significantly to particulate matter air pollution that 
endangers public health and welfare. The Court indicated that the EPA's 
determination that particulate matter endangers is valid simply on 
grounds that the EPA established a NAAQS for that pollutant.\104\
---------------------------------------------------------------------------

    \103\ 539 F.2d 775 (D.C. Cir. 1976).
    \104\ Id. at 784.
---------------------------------------------------------------------------

    These cases support our relying primarily on the analysis and 
conclusions in our previous Endangerment Finding, and the subsequent 
assessments, as providing a rational basis for our decision to impose 
standards of performance on GHG emissions from fossil-fuel fired EGUs.
    In comments on the original proposal, commenters state that because 
the proposed rulemaking limits emissions of only CO2, and 
not other GHGs, the EPA cannot rely on the analysis and conclusions in 
the 2009 Endangerment Finding because it concerned a mix of six GHGs: 
carbon dioxide and five others. These commenters assert that as a 
prerequisite for regulating CO2 emissions alone, the EPA 
must make an endangerment finding for CO2 alone. Because the 
present proposal also limits emissions of only CO2, and not 
the other GHGs, we expect that the same issue may arise with respect to 
this proposal. Commenters' assertion is incorrect for two reasons. 
First, as discussed above, the EPA does not need to make an 
endangerment finding with respect to a particular pollutant to set 
standards for that pollutant under section 111(b)(1)(B). Second, the 
EPA may reasonably rely on the analysis and conclusions in the 2009 
Endangerment Finding on GHGs even when regulating only CO2. 
With respect to this proposed rulemaking, the air pollution at issue 
here is the mix of six GHGs. It is that air pollution that has caused 
the various impacts on health and welfare that formed the basis for the 
Endangerment Finding. The CO2 emissions from EGUs are a 
major component of that air pollution. As we noted in the 2009 
Endangerment Finding, CO2 is the ``dominant anthropogenic 
greenhouse gas.'' \105\ The fact that we are not regulating the other 
five GHGs in this rulemaking does not mean that we are required to 
identify the air pollution as CO2 alone rather than the mix 
of six GHGs. This is consistent with the EPA's past actions. In the 
2010 Light Duty Vehicle Rule for which the Endangerment Finding served 
as the predicate, the EPA regulated only four of the GHGs, not all 
six.\106\
---------------------------------------------------------------------------

    \105\ 74 FR 66496, 66519 (Dec. 15, 2009).
    \106\ 75 FR 25324, 25396-97 (May 7, 2010).
---------------------------------------------------------------------------

    Further, 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, along with the fact that the CO2 emissions 
from even a single new coal-fired power plant may amount to millions of 
tons each year, provide a rational basis for regulating CO2 
emissions from affected EGUs.\107\ This is consistent with previous EPA 
actions that have been upheld by the D.C. Circuit. In the National Lime 
Association v. EPA case, noted above, the Court upheld the EPA's 
regulation of lime plants on grounds that they were one of the 
largest--although not within the largest 10 percent--emitting 
industries of particulates. The Court stated,
---------------------------------------------------------------------------

    \107\ Commenters on the original proposal stated that new solid-
fuel fired power plants made no contribution to air pollution 
because EPA's modeling projected no new construction of those types 
of plants. However, CAA section 111(b)(1)(A) is clear by its terms 
that the source category listing that is the prerequisite to 
regulation is based on the contribution of the ``category'' to air 
pollution, and therefore is not based on the contribution of only 
new sources in the category. The same reasoning applies to the 
rational basis determination.

    EPA . . . focused . . . on the sheer quantity of dust generated 
by lime plants. 42 Fed. Reg. 22507 (``A study performed for EPA in 
1975 by the Research Corporation of New England ranked the lime 
industry twenty-fifth on a list of 112 stationary sources categories 
which are emitters of particulate matter''); SSEIS 8-2 (``In a study 
performed for EPA by Argonne National Laboratory in 1975, the lime 
industry ranked seventh on a list of the 56 largest particulate 
source categories in the U.S.'').\108\
---------------------------------------------------------------------------

    \108\ 627 F.2d at 432, n. 48.

In the National Asphalt Pavement Ass'n v. Train case, noted above, the 
Court upheld the EPA's determination that the asphalt industry 
contributed significantly to the air pollution based on ``the number of 
existing plants, the expected rate of growth in the number of plants, 
the rate of uncontrolled emissions, and the level of emissions 
currently tolerated.'' \109\
---------------------------------------------------------------------------

    \109\ 539 F.2d at 784-85.
---------------------------------------------------------------------------

F. Alternative Findings of Endangerment and Significant Contribution

    Even if CAA section 111 is interpreted to require that the EPA make 
endangerment and cause-or-contribute significantly findings as 
prerequisites for today's rulemaking, then our rational

[[Page 1456]]

basis, as described, should be considered to constitute those findings.
    As noted above, the EPA's rational basis for regulating under 
section 111 GHGs is based primarily on the analysis and conclusions in 
the EPA's 2009 Endangerment Finding and 2010 denial of petitions to 
reconsider that Finding, coupled with the 2010, 2011, and 2012 
assessments from the IPCC and NRC that describe scientific developments 
since those EPA actions. In addition, as noted above, we would review 
comments presenting other scientific information to determine whether 
that information has any meaningful impact on our primary basis.
    This rational basis approach is substantially similar to the 
approach the EPA took in the 2009 Endangerment Finding and the 2010 
denial of petitions to reconsider. As noted, the D.C. Circuit upheld 
that approach in the CRR case. Accordingly, that approach would support 
an endangerment finding for this rulemaking.
    By the same token, if the EPA were required to make a cause-or-
contribute-significantly finding for CO2 emissions from the 
fossil fuel-fired EGUs, as a prerequisite to regulating such emissions 
under CAA section 111, the same facts that support our rational basis 
determination would support such a finding. In particular, as noted, 
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; and the CO2 emissions from even a single new 
coal-fired power plant may amount to millions of tons each year. It 
should be noted that at present, it is not necessary for the EPA to 
decide whether it must identify a specific threshold for the amount of 
emissions from a source category that constitutes a significant 
contribution. Under any reasonable threshold or definition, the 
emissions from EGUs are a significant contribution.\110\
---------------------------------------------------------------------------

    \110\ Indeed, it is literally true that if fossil-fuel fired 
EGUs cannot be found to contribute significantly to GHG air 
pollution, then there is no source category in the U.S. that does 
contribute significantly to GHG air pollution, a result that would 
defeat the purposes of CAA section 111.
---------------------------------------------------------------------------

G. Comments on the State of the Science of Climate Change

    The EPA received a number of comments in response to the original 
proposed NSPS rule addressing the scientific underpinnings of the EPA's 
2009 Endangerment Finding and, in essence, the scientific justification 
for this rule. Because this action is not a final action, we are not 
required to respond to those comments. Even so, we have carefully 
reviewed all of those comments, and we do provide some responses in 
this action. It is important to place these comments in the context of 
the voluminous record on this subject that has been compiled over the 
last few years. This includes: (1) The process by which the 
Administrator reached the 2009 finding that GHGs are reasonably 
anticipated to endanger the public health and welfare of current and 
future generations; (2) the EPA's response in 2010 to ten 
administrative petitions for reconsideration of the Endangerment 
Finding, the ``Reconsideration Denial''; and, (3) the decision by the 
United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in 
2012 to uphold the Endangerment Finding and the Reconsideration Denial.
    As outlined in Section VIII.A. of the 2009 Endangerment Finding, 
the EPA's approach to providing the technical and scientific 
information to inform the Administrator's judgment regarding the 
question of whether GHGs endanger human health and welfare was to rely 
primarily upon the recent, major assessments by the U.S. Global Change 
Research Program (USGCRP), the Intergovernmental Panel on Climate 
Change (IPCC), and the National Research Council (NRC) of the National 
Academies. 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, in which the EPA took 
part. The EPA received thousands of comments on the proposed 
Endangerment Finding and responded to them in depth in an 11-volume RTC 
document. While the EPA gave careful consideration to all of the 
scientific and technical information received, it placed less weight on 
the much smaller number of individual studies that were not considered 
or reflected in the major assessments--often these studies were 
published after the submission deadline for those larger assessments. 
Primary reliance on the major scientific assessments provided the EPA 
greater assurance that it was basing its judgment on the best 
available, well-vetted science that reflected the consensus of the 
climate science community, rather than selecting the studies it would 
rely on. Nonetheless, the EPA reviewed individual studies not 
incorporated in the assessment literature to see if they would lead the 
EPA to change its interpretation of, or place less weight on, the major 
findings reflected in the assessment reports. From its review of 
individual studies submitted by commenters, the EPA concluded that 
these studies did not change the various conclusions or judgments the 
EPA would draw based on the more comprehensive assessment reports. The 
major findings of the USGCRP, IPCC, and NRC assessments supported the 
EPA's determination that GHGs threaten the public health and welfare of 
current and future generations. The EPA demonstrated this scientific 
support at length in the Endangerment Finding itself, in its Technical 
Support Document (which summarized the findings of USGCRP, IPCC and 
NRC), and in its RTC document.
    The EPA then reviewed ten administrative petitions for 
reconsideration of the Endangerment Finding in 2010. The Administrator 
denied those petitions in the ``Reconsideration Denial'' on the basis 
that the Petitioners failed to provide substantial support for the 
argument that the Endangerment Finding should be revised and therefore 
their objections were not of ``central relevance'' to the Finding.\111\ 
The EPA prepared an accompanying 3-volume RTP document to provide 
additional information, often more technical in nature, in response to 
the arguments, claims, and assertions by the petitioners to reconsider 
the Endangerment Finding.
---------------------------------------------------------------------------

    \111\ ``EPA's Denial of the Petitions To Reconsider the 
Endangerment and Cause or Contribute Findings for Greenhouse Gases 
Under Section 202(a) of the Clean Air Act'' (``Reconsideration 
Denial''), 75 FR 49556, 58 (Aug. 13, 2010).
---------------------------------------------------------------------------

    The 2009 Endangerment Finding and the 2010 Reconsideration Denial 
were challenged in a lawsuit, and on June 26, 2012, the D.C. Circuit 
upheld them, ruling that they were neither arbitrary nor capricious, 
were consistent with Massachusetts v. EPA,\112\ and were adequately 
supported by the administrative record.\113\ The Court found that the 
EPA had based its decision on ``substantial scientific evidence,'' 
\114\ and noted that the EPA's reliance on assessments was consistent 
with the methods decision-makers often use to make a science-based 
judgment.\115\ The Court also found that the Petitioners had ``not 
provided substantial support for their argument that the Endangerment 
Finding should be revised.'' \116\ Moreover, the Court assessed the 
EPA's reliance on the major scientific assessment reports that were

[[Page 1457]]

conducted by USGCRP, IPCC, and NRC, and subjected to rigorous expert 
and government review, and found that--
---------------------------------------------------------------------------

    \112\ Massachusetts v. EPA, 549 U.S. 497.
    \113\ CRR, 684 F.3d at 102.
    \114\ Id at 121.
    \115\ Id at 120.
    \116\ Id at 125.

    EPA evaluated the processes used to develop the various 
assessment reports, reviewed their contents, and considered the 
depth of the scientific consensus the reports represented. Based on 
these evaluations, the EPA determined the assessments represented 
the best source material to use in deciding whether GHG emissions 
may be reasonably anticipated to endanger public health or 
welfare.\117\
---------------------------------------------------------------------------

    \117\ Id at 120.

---------------------------------------------------------------------------
    As the Court stated,

    It makes no difference that much of the scientific evidence in 
large part consisted of `syntheses' of individual studies and 
research. Even individual studies and research papers often 
synthesize past work in an area and then build upon it. This is how 
science works. The EPA is not required to re-prove the existence of 
the atom every time it approaches a scientific question.\118\
---------------------------------------------------------------------------

    \118\ Id at 120.

    It is within the context of this extensive record, and recent 
affirmation of the Endangerment Finding by the Court, that the EPA has 
considered all of the submitted science-related comments and reports 
for the April 2012 proposed rule, and will consider any further 
comments in response to today's proposed rule. As we did in the 
original Endangerment Finding, the EPA is giving careful consideration 
to all of the scientific and technical information in the record. 
However, the major peer-reviewed scientific assessments continue to 
provide the primary scientific and technical basis upon which the 
Administrator's judgment relies regarding the threat to public health 
and welfare posed by GHGs.
    Commenters on the April 2012 proposed rule submitted two major 
peer-reviewed scientific assessments that were released since the 
administrative record concerning the Endangerment Finding was closed 
after the EPA's 2010 Reconsideration Denial: the IPCC Special Report on 
Managing the Risks of Extreme Events and Disasters to Advance Climate 
Change Adaptation (2012) (SREX) and the NRC Report on Climate 
Stabilization Targets: Emissions, Concentrations, and Impacts over 
Decades to Millennia (2011) (Climate Stabilization Targets). The EPA 
has reviewed these assessments and they are briefly characterized here:
    SREX. The IPCC SREX assessment states that, ``A changing climate 
leads to changes in the frequency, intensity, spatial extent, duration, 
and timing of extreme weather and climate events, and can result in 
unprecedented extreme weather and climate events.'' The SREX documents 
observational evidence of changes in some of the weather and climate 
extremes that have occurred globally since 1950. The SREX assessment 
provides evidence regarding the attribution of some of these changes to 
elevated concentrations of GHGs, including warming of extreme daily 
temperatures, intensification of extreme precipitation events, and 
rising extreme coastal high water due to increases in sea level. The 
assessment notes that further increases in some extreme weather and 
climate events are projected over the 21st century. The assessment also 
concludes that, combined with increasing vulnerability and exposure of 
populations and assets, changes in extreme weather and climate events 
have consequences for disaster risk, with particular impacts on the 
water, agriculture and food security, and health sectors.
    Climate Stabilization Targets. The NRC Climate Stabilization 
Targets assessment states that, ``Emissions of carbon dioxide from the 
burning of fossil fuels have ushered in a new epoch where human 
activities will largely determine the evolution of Earth's climate. 
Because carbon dioxide in the atmosphere is long lived, it can 
effectively lock Earth and future generations into a range of impacts, 
some of which could become very severe.'' The assessment addresses the 
fact that emissions of carbon dioxide will alter the composition of the 
atmosphere, and therefore the climate, for thousands of years and 
attempts to quantify the implications of stabilizing GHG concentrations 
at different levels. The report also estimates a number of specific 
climate change impacts, finding warming could lead to increases in 
heavy rainfall and decreases in crop yields and Arctic sea ice extent, 
along with other important changes in precipitation and stream flow. 
For an increase in global average temperature of 1 to 2 [deg]C above 
pre-industrial levels, the assessment found that the area burnt by 
wildfires in western North America will likely more than double and 
coral bleaching and erosion will increase due both to warming and ocean 
acidification; an increase of 3 [deg]C will lead to a sea level rise of 
0.5 to 1.0 meters by 2100; and with an increase of 4 [deg]C, the 
average summer in the United States would be as warm as the warmest 
summers of the past century. The assessment notes that although many 
important aspects of climate change are difficult to quantify, the risk 
of adverse impacts is likely to increase with increasing temperature, 
and the risk of dangerous surprises can be expected to increase with 
the duration and magnitude of the warming.
    A number of other National Academy assessments regarding climate 
have also been released recently. The EPA has reviewed these 
assessments, and finds that the improved understanding of the climate 
system resulting from the two assessments described above and the 
National Academy assessments strengthens the case that GHGs are 
endangering public health and welfare. Perhaps the most dramatic change 
relative to the prior assessments concern sea level rise. The previous 
2007 IPCC AR4 assessment projected a rise in global sea level of 
between 7 and 23 inches by the end of the century relative to 1990 
(with an acknowledgment that inclusion of ice sheet processes that were 
poorly understood would likely increase those projections). Three new 
NRC assessments have provided estimates of projected sea level rise 
that are much larger, in some cases more than twice as large as the 
previous IPCC estimates. Climate Stabilization Targets; National 
Security Implications for U.S. Naval Forces (2011); Sea Level Rise for 
the Coasts of California, Oregon, and Washington: Past, Present, and 
Future (2012). While the three NRC assessments continue to recognize 
and characterize the uncertainty inherent in accounting for ice sheet 
processes, these revised estimates strongly support and strengthen the 
existing finding that GHGs are reasonably anticipated to endanger human 
health and welfare. Other key findings of the recent assessments are 
described briefly below:
    The Sea Level Rise for the Coasts of California, Oregon, and 
Washington: Past, Present, and Future (2012) assessment notes that 
observations have shown that sea level rise on the West Coast has risen 
south of Cape Mendocino over the past century but dropped north of that 
point during that time due to tectonic uplift and other factors in 
Oregon and Washington. However, the assessment projects a global sea 
level rise of 1.6 to 4.6 feet by 2100, which is sufficient to lead to 
rising relative sea level even in the northern states. The National 
Security Implications of Climate Change for U.S. Naval Forces also 
considers potential impacts of sea level rise, using a range of 1.3 to 
6.6 feet by 2100. This assessment also suggests preparing for increased 
needs for humanitarian aid, responses to climate change in geopolitical 
hotspots including possible mass migrations, and addressing changing 
security needs in the Arctic as sea ice retreats. The Climate and 
Social Stress: Implications for Security Analysis (2012) assessment 
found that it

[[Page 1458]]

would be ``prudent for security analysts to expect climate surprises in 
the coming decade . . . and for them to become progressively more 
serious and more frequent thereafter[.]'' Understanding Earth's Deep 
Past: Lessons for Our Climate Future (2011) examines the period of 
Earth's history prior to the formation of the Antarctic and Greenland 
Ice Sheets because CO2 concentrations by the end of the 
century will have exceeded levels seen in the 30 million years since 
that time. The assessment discusses the possibility that analogous 
paleoclimate states might suggest higher climate sensitivity, less well 
regulated tropical surface temperatures, higher sea level rise, more 
anoxic oceans, and more potential for non-linear events such as the 
Paleo-Eocene Thermal Maximum than previously estimated. The assessment 
notes that three or four out of the five major coral reef crises of the 
past 500 million years were probably driven by acidification and 
warming caused by GHG increases similar to the changes expected over 
the next hundred years. The assessment states that ``the magnitude and 
rate of the present greenhouse gas increase place the climate system in 
what could be one of the most severe increases in radiative forcing of 
the global climate system in Earth history.'' Similarly, the Ocean 
Acidification: A National Strategy to Meet the Challenges of a Changing 
Ocean (2010) assessment found that ``[t]he chemistry of the ocean is 
changing at an unprecedented rate and magnitude due to anthropogenic 
carbon dioxide emissions; the rate of change exceeds any known to have 
occurred for at least the past hundreds of thousands of years.'' The 
assessment notes that the full range of consequences is still unknown, 
but the risks ``threaten coral reefs, fisheries, protected species, and 
other natural resources of value to society.''
    Several commenters on the April 2012 proposed rule argue that the 
Endangerment Finding should be reconsidered or overturned based on 
those commenters' reviews of specific climate science literature, 
particularly newer publications that have appeared since the EPA's 2010 
Denial of Petitions. Some commenters have presented their own 
compilations of individual studies as support for their assertions that 
climate change will have beneficial effects in many cases and that 
climate impacts will not be as severe or adverse as the EPA and 
assessments like the USGCRP (2009) report have stated. These commenters 
conclude that U.S. society will continue to easily adapt to climate 
change and that climate change therefore does not pose a threat to 
human health and welfare.
    The EPA has reviewed the information submitted and finds that, the 
fundamental issues raised in the comments that critique the scientific 
justification for the rule have been addressed by the EPA's 11-volume 
response to comments for the 2009 Endangerment Finding, the EPA's 
responses to all issues raised by Petitioners in the Reconsideration 
Denial, or the D.C. Circuit in its 2012 decision to uphold the EPA's 
2009 Endangerment Finding. These comments do not change the various 
conclusions or judgments that the EPA would draw based on the 
assessment reports relied upon in the recent 2009 Finding.
    These comments often highlight uncertainty regarding climate 
science as an argument for reconsideration. However, uncertainty was 
explicitly recognized in the 2009 Endangerment Finding: ``The 
Administrator acknowledges that some aspects of climate change science 
and the projected impacts are more certain than others'',\119\ and the 
decision to find endangerment was made with full recognition of the 
uncertainty involved. In addition, the D.C. Circuit Court decision 
noted that, ``the existence of some uncertainty does not, without more, 
warrant invalidation of an endangerment finding.'' \120\ In short, 
these recent publications submitted by commenters, and any new issues 
that are extracted from them, do not undermine either the significant 
body of scientific evidence that has accumulated over the years or the 
conclusions presented in the substantial peer-reviewed assessments of 
the USGCRP, NRC, and IPCC.
---------------------------------------------------------------------------

    \119\ 74 FR 66524.
    \120\ CRR, 684 F.3d at 121.
---------------------------------------------------------------------------

    Regarding the contentions that the U.S. will adapt to climate 
change impacts and that therefore climate change impacts pose no 
threat, the EPA stated in the 2009 Endangerment Finding,

    Risk reduction through adaptation and GHG mitigation measures is 
of course a strong focal area of scientists and policy makers, 
including the EPA; however, the EPA considers adaptation and 
mitigation to be potential responses to endangerment, and as such 
has determined that they are outside the scope of the endangerment 
analysis.\121\
---------------------------------------------------------------------------

    \121\ 74 FR 66512 (emphasis added).

The D.C. Circuit upheld this position, ruling that ``These contentions 
[that the U.S. can adapt] are foreclosed by the language of the statute 
and the Supreme Court's decision in Massachusetts v. EPA'' because 
``predicting society's adaptive response to the dangers or harms caused 
by climate change'' does not inform the ``scientific judgment'' that 
the EPA is required to take regarding Endangerment.\122\
---------------------------------------------------------------------------

    \122\ 984 F.3d at 117.
---------------------------------------------------------------------------

    Some commenters raise issues regarding the EPA Inspector General's 
report, Procedural Review of EPA's Greenhouse Gases Endangerment 
Finding Data Quality Processes (2011). These commenters mischaracterize 
the report's scope and conclusions and, thus, vastly overstate the 
significance of the Inspector General's procedural recommendations. 
Ultimately, nothing in the Inspector General report questions the 
validity of the EPA's Endangerment Finding because that report did not 
evaluate the scientific basis of the Endangerment Finding. Rather, the 
Inspector General offers recommendations for clarifying and 
standardizing internal procedures for documenting data quality and peer 
review processes when referencing existing peer reviewed science in the 
EPA actions. Unrelated to the Endangerment Finding and its validation 
by the Court, the EPA has made progress towards implementing the 
recommendations by the Inspector General.
    One commenter submitted a number of emails from the period 1999 to 
2009 that were obtained from a University of East Anglia server in 2009 
and publicly released in 2011. After reviewing these emails, the EPA 
finds that they raise no issues that were not previously raised by 
Petitioners in regard to an earlier group of emails from the same 
incident, released in 2009. The commenter makes unsubstantiated 
assumptions and subjective assertions regarding what the emails purport 
to show about the state of climate change science; this provides 
inadequate evidence to challenge the voluminous and well documented 
body of science that is the technical foundation of the Administrator's 
Endangerment Finding.
    A number of comments were also submitted in support of the 
Endangerment Finding and/or providing further evidence that climate 
change is a threat to human health and welfare. A number of individual 
studies were submitted and a number of observed or projected climate 
changes of local importance or concern to commenters were documented. 
Again, the EPA places lesser weight on individual studies than on the 
major scientific assessments. Local observed changes can be of great 
concern to individuals

[[Page 1459]]

and communities but must be assessed in the context of the broader 
science, as it is more difficult to draw robust conclusions regarding 
climate change over short time scales and in small geographic regions.

V. Rationale for Applicability Requirements

A. Applicability Requirements--Original Proposal and Comments

    The original proposal was designed to apply to new intermediate and 
base load EGUs, specifically, (1) fossil fuel-fired utility boilers and 
IGCC EGUs subject to subpart Da for criteria pollutant emissions, and 
(2) natural gas combined cycle EGUs subject to subpart KKKK for 
criteria pollutant emissions. The original proposal explicitly did not 
apply to simple cycle turbines because we concluded that they were 
operated infrequently and therefore only contributed small amounts to 
total GHG emissions. (For convenience, we occasionally refer to this 
explicit statement that the original proposed NSPS did not apply to a 
type of source as an exclusion.)
    We received comments that supported the simple cycle exclusion and 
others that opposed it. Commenters in support stated that a new simple 
cycle power plant serves a different purpose than a new combined cycle 
plant and that economics will drive the use of combined cycle 
facilities over simple cycle plants. They also stated that the original 
proposed standard is not achievable by, and therefore is not BSER for, 
simple cycle turbines. Commenters opposing the exclusion stated that it 
creates an opportunity to evade the standard and could thereby increase 
GHG emissions. According to these commenters, any applicability 
distinctions should be based on utilization and function rather than 
purpose or technology.
    After considering these comments, we are proposing a different 
approach to the applicability provisions with respect to simple cycle 
turbines.

B. Applicability Requirements--Today's Proposal

    In today's rulemaking, we propose that standards of performance 
apply to a facility if the facility supplies more than one-third of its 
potential electric output and more than 219,000 MWh net electric output 
to the grid per year. (We refer to a facility's sale of more than one-
third of its potential electric output as the one-third sales 
criterion, and we refer to the amount of potential electric output 
supplied to a utility power distribution system, expressed in MWh, as 
the capacity factor.) This proposed definition does not explicitly 
exclude simple cycle combustion turbines, but as a practical matter, it 
would exclude most of them because the vast majority of simple cycle 
turbines sell less than one-third of their potential electric output. 
The few simple-cycle combustion turbines that sell more than one-third 
of their potential electric output to the grid would be subject to the 
proposed standards of performance. As explained below, we have 
concluded that at this level of output, there are less expensive and 
lower emitting technologies that could be constructed consistent with 
today's proposed standards. Although, as noted, today's proposal does 
not explicitly exclude simple cycle combustion turbines, we solicit 
comment on whether to provide an explicit exclusion.
    We are proposing to apply the one-third sales criterion on a 
rolling three year basis instead of an annual basis for stationary 
combustion turbines for multiple reasons. First, extending the period 
to three years would ensure that the CO2 standards apply 
only to intermediate and base load EGUs by allowing facilities intended 
to generally operate at low capacity factors (e.g. simple cycle 
turbines that generally sell less than one-third of their potential 
electric output) to avoid applicability even though they may provide 
system capacity and, in fact, operate at high capacity factors during 
individual years with abnormally high electric demand. Second, only 0.2 
percent of existing simple cycle turbines had a three-year average 
capacity factor of greater than one-third between 2000 and 2012. 
Therefore, as noted, from a practical standpoint, few new simple cycle 
turbines will be subjected to the standards of performance in this 
rulemaking.
    The 2013 AEO cost and performance characteristics for new 
generation technologies include costs for advanced and conventional 
combined cycle facilities and advanced simple cycle turbines. According 
to the AEO 2013 values, advanced combined cycle facilities have a lower 
cost of electricity than advanced simple cycle turbine facilities above 
approximately a 20 percent capacity factor. Therefore, the use of a 
combined cycle technology would be BSER for higher capacity factor 
stationary combustion turbines. However, advanced combined cycle 
facilities do not have a lower cost of electricity than less capital 
intensive conventional combined cycle facilities until above 
approximately a 40 percent capacity factor. Between approximately 20 to 
40 percent capacity factors, conventional combined cycle facilities 
offer the lowest cost of electricity, and below approximately 20 
percent capacity factors advanced simple cycle turbines offer the 
lowest cost of electricity. A capacity factor exemption at 40 percent 
(i.e., sales of less than two-fifths of potential electric output per 
year) would allow conventional combined cycle facilities built with the 
intent to operate at relatively low capacity factors as an alternative 
technology to simple cycle turbines because neither would be subject to 
the NSPS requirements. Based on these cost considerations, we are 
specifically requesting comment on a range of 20 to 40 percent of 
potential electric output sales on a three-year basis for the capacity 
factor exemption. The 20 percent applicability limit is consistent with 
generating the lowest cost of electricity for advanced combined cycle 
turbines compared to advanced simple cycle turbines, and based on 
historical capacity factors would impact the operation of only 
approximately two percent of simple cycle turbines. The 40 percent 
applicability limit would be more consistent with the annual run hour 
limitations currently contained in many simple cycle operating permits.
    We are also requesting comments on whether applicability for 
stationary combustion turbines should be defined on a single calendar 
year basis, similar to the current subpart Da applicability provisions 
for criteria pollutants, instead of a three-year basis. With a single 
year basis, we are considering an applicability level of up to 40 
(instead of 33 and one-third) percent sales. Only 0.4 percent of 
existing simple cycle turbines had an annual capacity factor of greater 
than 40 percent between 2000 and 2012. Assuming the average hourly 
output of a simple cycle turbine is 80 percent of the maximum rated 
output, a simple cycle turbine could operate up to 4,400 hours annually 
before exceeding the capacity factor threshold. This is consistent with 
the operation hour limitation in many permits. Therefore, with this 40 
percent sales criterion on a single-year basis, as a practical matter, 
it is anticipated that few new simple cycle turbines would be subject 
to the proposed standards of performance. Thus, we are specifically 
requesting comment on a range of one-third to two-fifths of potential 
electric output annual sales. The lower range would be consistent with 
how an EGU is currently defined in the EPA rules, and would mean that 
the proposed standards of performance would impact approximately one 
percent of new simple cycle turbines.

[[Page 1460]]

    We are also proposing a different definition of potential electric 
output from the current definition that determines the potential 
electric output (in MWh on an annual basis) considering only the design 
heat input capacity of the facility and does not account for 
efficiency. It assumes a 33 percent net electric efficiency, regardless 
of the actual efficiency of the facility and could discourage the 
installation of more efficient facilities. For example, a 33 percent 
efficient 100 MW facility would have a heat input of 1,034 MMBtu/h and 
a 40 percent efficient 100 MW facility would have a heat input of 853 
MMBtu/h.\123\ The 33 percent efficient facility would become subject to 
the NSPS requirements when it sells more than one-third of its 
potential electric output, 880,000 MWh. The 40 percent efficient 
facility would become subject to the NSPS requirements when it sells 
more than 730,000 MWh.\124\ This could potentially encourage the 
construction of less efficient facilities, since they could have a 
higher actual capacity factor than a more efficient unit, while still 
not being an EGU subject to a CO2 standard. Therefore, we 
are proposing a definition of potential electric output that allows the 
source the option of calculating its potential electric output on the 
basis of its actual design electric output efficiency on a net output 
basis, as an alternative to the default one-third value. The proposed 
definition would permit the 40 percent efficient facility to use the 
actual efficiency of the facility so that the electric sales 
applicability criteria would be 880,000 MWh and applicability would be 
determined the same as for the less efficient facility.
---------------------------------------------------------------------------

    \123\ (100 MW)*(3.412 MMBtu/h/1 MWh)*(1/0.33) = 1,034 MMBtu/h. 
(100 MW)*(3.412 MMBtu/h/1 MWh)*(1/0.40) = 853 MMBtu/h.
    \124\ (1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) = 
880,000 MWh. (853 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) = 
730,000 MWh.
---------------------------------------------------------------------------

    The April 2012 proposal would have applied to facilities that 
primarily burn non-fossil fuels but also co-fire a fossil fuel. We have 
concluded that it is not appropriate to subject these facilities to the 
standards in today's proposal. This is because these types of units 
more closely resemble the non-fossil fuel-fired boilers and stationary 
combustion turbines that are not covered by today's proposed rule, than 
they do the fossil fuel-fired boilers and stationary combustion 
turbines that are covered by this rule. This approach is similar to the 
approach used in the Mercury and Air Toxics Standards, another CAA 
regulatory effort focused on fossil fuel-fired power plants. Therefore, 
we are proposing to limit the applicability of the standard to 
facilities where the heat input is comprised of more than 10.0 percent 
fossil fuel on a three-year rolling average basis. To simplify 
determining applicability with the CO2 standard, we also 
request comment on whether the applicability for facilities that co-
fire non-fossil fuels should be made on an annual average basis, 
instead of a three-year rolling average basis.
    In the original proposal, we requested comment on the applicability 
of the GHG NSPS to combined heat and power (CHP) facilities and if 
applicability should be changed from how it is currently determined in 
subpart Da. In today's action, we propose that if CHP facilities meet 
the general applicability criteria they should be subject to the same 
requirements as electric-only generators. However, one potential issue 
that we have identified is inequitable applicability to third-party CHP 
developers compared to CHP facilities owned by the facility using the 
thermal output from the CHP facility. As noted above, we propose that 
the proposed CO2 standard of performance apply to a facility 
that supplies more than one-third of its potential electricity output 
and more than 219,000 MWh ``net electric output'' to the grid per year. 
The current definition of net electric output for purposes of criteria 
pollutants is ``the gross electric sales to the utility power 
distribution system minus purchased power on a calendar year basis.'' 
40 CFR 60.41Da. Owners/operators of a CHP facility under common 
ownership as an adjacent facility using the thermal output from the CHP 
facility (i.e., the thermal host) can subtract out power purchased by 
the adjacent facility on an annual basis when determining 
applicability. However, third-party CHP developers would not be able to 
benefit from the ``minus purchased power on a calendar year basis'' 
provision in the definition of net electric output when determining 
applicability since the CHP facility and the thermal host(s) are not 
under common ownership. We are therefore proposing to add ``of the 
thermal host facility or facilities'' to the definition of net-electric 
output for qualifying CHP facilities (i.e., the clause would read, 
``the gross electric sales to the utility power distribution system 
minus purchased power of the thermal host facility or facilities on a 
calendar year basis'' (emphasis added)). This would make applicability 
consistent for both facility-owned CHP and third-party-owned CHP.
    This proposal includes within the definition of a steam electric 
generating unit, IGCC, and stationary combustion turbine that are 
subject to the proposed requirements, any integrated device that 
provides electricity or useful thermal output to the boiler, the 
stationary combustion turbine or to power auxiliary equipment. The 
rationale behind including integrated equipment recognizes that the 
integrated equipment may be a type of combustion unit that emits GHGs, 
and that it is important to assure that those GHG emissions are 
included as part of the overall GHG emissions from the affected source. 
Including integrated equipment avoids circumvention of the requirements 
by having a boiler not subject to the standard supplying useful energy 
input (e.g., an industrial boiler supplying steam for amine 
regeneration in a CCS system) without accounting for the GHG emissions 
when determining compliance with the NSPS. In addition, the proposed 
definition would provide additional compliance flexibility similar to 
when the HRSG was included in the combustion turbine NSPS by 
recognizing the environmental benefit of integrated equipment that 
lowers the overall emissions rate of the affected facility. Even 
without this specific language, the original 1979 steam electric 
generating unit definition in subpart Da allows the use of solar 
thermal equipment for feedwater heating as an approach to integrating 
non-emitting generation to reduce environmental impact and lower the 
overall emissions rate. The current definition expands the flexibility 
to include combustion turbines, fuel cells, or other combustion 
technology for reheating or preheating boiler feedwater, preheating 
combustion air, producing steam for use in the steam turbine or to 
power the boiler feedpumps, or using the exhaust directly in the boiler 
to generate steam. This in theory could lower generation costs as well 
as lower the GHG emissions rate for an EGU.
    We solicit comment on various issues concerning, and different 
approaches to, the applicability requirements for steam generating 
units and combustion turbines. In particular, we recognize that several 
of the requirements proposed today are based on the source's 
operations. These include, for both steam generating units and 
combustion turbines, the requirement that the source supply more than 
one-third of its potential electric output and more than 219,000 MWh 
net-electric output to the grid for sale on an annual or tri-annual 
basis (the one-third and 219,000 MWh sales requirement), as well as the 
requirement that the source burn fossil fuel for more than 10 percent 
of the heat input during three years; and for

[[Page 1461]]

combustion turbines, the additional requirement that the source combust 
over 90 percent natural gas on a heat input basis over three years.
    We solicit comment on whether these requirements raise 
implementation issues because they are based on source operation after 
construction has occurred. We also solicit comment on whether, to avoid 
any such implementation issues, these requirements should be recast to 
be based on the source's purpose at the time of construction. For 
example, should we recast the 10% percent requirement so that it would 
be met if the source was constructed for the purpose of burning fossil 
fuel for more than 10 percent of its heat input over any three-year 
period?
    In addition, we solicit comment on whether we should include these 
requirements not as applicability requirements for whether the source 
is subject to the standard of performance, but rather as criteria for 
which part of the standard of performance the source is subject to. 
Under this approach, at least for combustion turbines, the EPA would 
promulgate applicability requirements or a definition of utility unit 
designed to assure that combustion turbine utility units--but not 
combustion turbine industrial units or other types of non-utility 
units--would be subject to the standard of performance. For example, 
under this approach, all combustion turbine units that meet such 
applicability requirements or definition of utility units and that have 
a design heat input to the turbine engine greater than 250 MMBtu/h, 
would be subject to the standard of performance for CO2 
emissions. That standard would be: (i) during periods when certain 
conditions (noted below) are met, 1,000 or 1,100 lb CO2/MWh 
(depending on whether the unit has a design heat input to the turbine 
engine of greater than 850 MMBtu/h); and (ii) during periods when one 
or more of those conditions is not met, no emission limit (that is, the 
unit could emit at an uncontrolled level). In the latter case, although 
the unit would not be subject to an emission limit, it would remain 
subject to the standard of performance, and therefore would be subject 
to any monitoring, reporting, and recordkeeping requirements. The 
conditions could include, during any 3-year period on a rolling average 
basis, combusting over 10% fossil fuel on a heat input basis, 
combusting over 90% natural gas on a heat input basis, and selling more 
than one-third of potential electric output and more than 219,000 MWh 
net-electric output to the grid.
    Under this approach, as noted, in order to be consistent with 
today's proposal to apply the standard of performance for 
CO2 emissions to only utility units--and not to industrial 
or other non-utility units--we would need to include other 
applicability requirements or definitional provisions that would 
explicitly limit the standard to utility units.
    We solicit comment on all aspects of this approach, including the 
extent to which it would achieve the policy objectives of assuring that 
a simple cycle turbine and a combined cycle turbine are subject to the 
same standard if they sell more than one-third of their capacity and 
more than 219,000 KWh net electric output to the grid, and are subject 
to the same standard if they sell less than those amounts to the grid. 
We also solicit comment on how to implement the three-year requirements 
described above during the period within three years after an affected 
EGU begins operations. For example, under the approach where 
operational criteria that entail a three-year compliance period are 
used to determine to which standard of performance the facility is 
subject, the owner or operator and permitting authority would not know 
for certain what standard applies to the facility until three years 
after initial startup. For this scenario, we request comment on how to 
implement the three year operational requirements and what 
documentation should be collected and reported to the EPA during the 
period up to the end of the third year after a source begins operation.

C. Certain Projects Under Development

    This proposal does not apply to the proposed Wolverine EGU project 
in Rogers City, Michigan. Based on current information, the Wolverine 
project appears to be the only fossil fuel-fired boiler or IGCC EGU 
project presently under development that may be capable of ``commencing 
construction'' for NSPS purposes \125\ in the very near future and, as 
currently designed, could not meet the 1,100 lb CO2/MWh 
standard proposed for other new fossil fuel-fired boiler and IGCC EGUs. 
The EPA has not formulated a view as to the project's status in the 
development process or as to whether the proposed 1,100 lb 
CO2/MWh standard or some other CO2 standard of 
performance would be representative of BSER for this project, and 
invites comment on these questions.\126\ At the time of finalization of 
this proposal, if the Wolverine project remains under development and 
has not either commenced construction or been canceled, we anticipate 
proposing that the project either be made subject to the 1,100 lb 
CO2/MWh standard or be assigned to a subcategory with an 
alternate CO2 standard. Further discussion is provided in 
the technical support document in the docket entitled ``Fossil Fuel-
Fired Boiler and IGCC EGU Projects under Development: Status and 
Approach.''
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    \125\ The NSPS regulations include definitions of ``commenced'' 
and ``construction''. See 40 CFR 60.2.
    \126\ The EPA's lack of view regarding the appropriate 
CO2 standard is closely related to the existence of 
conflicting information on where the project stands in the 
development process. The developer has claimed that the project was 
delayed by issues related to the standards of performance for 
hazardous air pollutants promulgated in December 2011, 77 FR 9304 
(Feb. 16, 2012) (Mercury and Air Toxics Standards, or MATS). 
Specifically, the developer cited a perceived inability to obtain 
guarantees from pollution control equipment vendors that the plant 
would achieve the MATS standards. See Jim Dulzo, As Coal Plant 
Teeters, Groups Mount Legal Attack, Michigan Land Use Institute 
blog, Feb. 13, 2012, https://www.mlui.org/energy/news-views/news-views-articles/as-coal-plant-teeters-groups-mount-legal-attack.html. 
While some of the MATS new-unit standards were revised upon 
reconsideration in March 2013, 78 FR 24073 (Apr. 24, 2013), the 
developer's claims raise the possibility that the EPA's own actions 
may have delayed the project and contributed to the present 
uncertainty as to the project's development status.
---------------------------------------------------------------------------

    There are two other fossil fuel-fired boiler or IGCC EGU projects 
without CCS--the Washington County project in Georgia and the Holcomb 
project in Kansas--that appear to remain under development but whose 
developers have recently represented that the projects have commenced 
construction for NSPS purposes. Based solely on the developers' 
representations, the projects would be existing sources, and thus not 
subject to this proposal. However, neither developer has sought a 
formal EPA determination of NSPS applicability; and, if upon review it 
was determined that the projects have not commenced constructions, the 
projects should be situated similarly to the Wolverine project. 
Accordingly, if it is determined in the future that either of these 
projects has not commenced construction as of the date of this 
proposal, then that project will be addressed in the same manner as the 
Wolverine project.\127\ Further discussion

[[Page 1462]]

is provided in the technical support document in the docket referenced 
above.\128\
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    \127\ In this event, there will not be any proposed standard 
``which will be applicable to such source'' within the meaning of 
CAA section 111(a)(2), and to the extent that this proposal did, 
until the time of the construction commencement determination, apply 
to that project, this proposal will be considered automatically to 
be withdrawn as it applies to that project as of the time of that 
determination. The purpose of this automatic withdrawal is to ensure 
that the project is placed on the same footing as the Wolverine 
project as soon as possible. It is worth noting that nothing in this 
proposal binds the EPA to the position that the projects have 
``commenced construction'' for NSPS purposes.
    \128\ In the April 2012 GHG NSPS proposal, the Wolverine, 
Washington County, and Holcomb projects were among a group of 15 
projects distinguished from other EGU projects as ``potential 
transitional sources.'' This proposal does not continue that 
distinction. Except as described above for the Wolverine project, 
and possibly the Washington County and Holcomb projects, any former 
``potential transitional source'' that commences construction after 
publication of this proposal (and meets any other applicability 
criteria) will be subject to the final CO2 standards 
established in this rulemaking. Any former ``potential transitional 
source'' that commenced construction prior to publication of this 
proposal is an existing source not subject to the CO2 
standards established in this rulemaking, but instead subject to the 
CO2 standards that are required to be established for 
existing sources pursuant to CAA section 111(d).
---------------------------------------------------------------------------

    We invite comment on all aspects of this approach for addressing 
the Wolverine project (and the Washington County and Holcomb projects, 
if applicable).\129\
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    \129\ The EPA intends that its treatment of the Wolverine 
project (and the Washington County and Holcomb projects, if 
applicable) be severable from its treatment of differently situated 
sources and considers that severability is logical because of the 
record-based differences between these sources and differently 
situated sources and because there is no interdependency in the 
EPA's treatment of the different types of sources. This statement 
concerning severability should not be construed to have implications 
for whether other components in this rulemaking are severable.
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VI. Legal Requirements for Establishing Emission Standards

A. Overview

    In this section, we describe the principal legal requirement for 
the standards of performance under CAA section 111 that we propose in 
this rulemaking, which is that the standards must consist of emission 
limits that are based on the ``best system of emission reduction . . . 
adequately demonstrated,'' taking into account cost and other factors 
(BSER). In this manner, CAA section 111 provides that the EPA's central 
task is to identify the BSER. The D.C. Circuit has handed down case 
law, which we review in detail, that interprets this CAA provision, 
including its component elements. The Court's interpretation indicates 
the technical, economic, and energy-related factors that are relevant 
for determining the BSER, and provides the framework for analyzing 
those factors.
    According to the D.C. Circuit, EPA determines the best demonstrated 
system based on the following key considerations, among others:
     The system of emission reduction must be technically 
feasible.
     EPA must consider the amount of emissions reductions that 
the system would generate.
     The costs of the system must be reasonable. EPA may 
consider the costs on the source level, the industry-wide level, and, 
at least in the case of the power sector, on the national level in 
terms of the overall costs of electricity and the impact on the 
national economy over time.
     EPA must also consider that CAA section 111 is designed to 
promote the development and implementation of technology.
    Other considerations are also important, including that EPA must 
also consider energy impacts, and, as with costs, may consider them on 
the source level and on the nationwide structure of the power sector 
over time. Importantly, EPA has discretion to weigh these various 
considerations, may determine that some merit greater weight than 
others, and may vary the weighting depending on the source category.

B. CAA Requirements and Court Interpretation

1. Clean Air Act Requirements
    The EPA's basis for proposing that partial capture CCS is the BSER 
for new fossil fuel-fired utility boilers and IGCC units, and that NGCC 
is the BSER for natural gas-fired stationary combustion turbines, is 
rooted in the provisions of CAA section 111 requirements, as 
interpreted by the United States Court of Appeals for the D.C. Circuit 
(``D.C. Circuit'' or ``Court''), which is the federal Court of Appeals 
with jurisdiction over the EPA's CAA rulemaking.
    As the first step towards establishing standards of performance, 
the EPA ``shall publish . . . a list of categories of stationary 
sources . . . [that] cause[], or contribute[ ] significantly to, air 
pollution which may reasonably be anticipated to endanger public health 
or welfare.'' section 111(b)(1)(A). Following that listing, the EPA 
``shall publish proposed regulations, establishing federal standards of 
performance for new sources within such category'' and then 
``promulgate . . . such standards'' within a year after proposal. 
section 111(b)(1)(B). The EPA ``may distinguish among classes, types, 
and sizes within categories of new sources for the purpose of 
establishing such standards.'' section 111(b)(2). The term ``standard 
of performance'' is defined to ``mean[ ] 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.'' section 111(a)(1).
2. Court Interpretation
    For present purposes, the key section 111 provisions are the 
definition of ``standard of performance,'' under CAA section 111(a)(1), 
and, in particular, the ``best system of emission reduction which 
(taking into account . . . cost . . . nonair quality health and 
environmental impact and energy requirements) . . . has been adequately 
demonstrated.'' The D.C. Circuit has reviewed rulemakings under section 
111 on numerous occasions during the past 40 years, handing down 
decisions dated from 1973 to 2011,\130\ through which the Court has 
developed a body of case law that interprets the term ``standard of 
performance.'' These interpretations are of central importance to the 
EPA's justification for the standards of performance in the present 
rulemaking.
---------------------------------------------------------------------------

    \130\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. 
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 
Cir. 1973); Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 
2011).
---------------------------------------------------------------------------

    At the outset, it should be noted that Congress first included the 
definition of ``standard of performance'' when enacting CAA section 111 
in the 1970 Clean Air Act Amendments (CAAA), and then amended it in the 
1977 CAAA, and then amended it again in the 1990 CAAA, generally 
repealing the amendments in the 1977 CAAA and, therefore, reverting to 
the version as it read after the 1970 CAAA. The legislative history for 
the 1970 and 1977 CAAAs explained various aspects of the definition as 
it read at those times. Moreover, the various decisions of the D.C. 
Circuit interpreted the definition that was applicable to the 
rulemakings before the Court. Notwithstanding the amendments to the 
definition, the D.C. Circuit's interpretations discussed below remain 
applicable to the current definition.\131\
---------------------------------------------------------------------------

    \131\ In the 1970 CAAA, Congress defined ``standard of 
performance,'' under section 111(a)(1), 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) the Administrator determines has been adequately 
demonstrated.
    In the 1977 CAAA, Congress revised the definition to distinguish 
among different types of sources, and to require that for fossil 
fuel-fired sources, the standard (i) be based on, in lieu of the 
``best system of emission reduction . . . adequately demonstrated,'' 
the ``best technological system of continuous emission reduction . . 
. adequately demonstrated;'' and (ii) require a percentage reduction 
in emissions. In addition, in the 1977 CAAA, Congress expanded the 
parenthetical requirement that the Administrator consider the cost 
of achieving the reduction to also require the Administrator to 
consider ``any nonair quality health and environment impact and 
energy requirements.''
    In the 1990 CAAA, Congress again revised the definition, this 
time repealing the requirements that the standard of performance be 
based on the best technological system and achieve a percentage 
reduction in emissions, and replacing those provisions with the 
terms used in the 1970 CAAA version of section 111(a)(1) that the 
standard of performance be based on the ``best system of emission 
reduction . . . adequately demonstrated.'' This 1990 CAAA version is 
the current definition, which is applicable at present. Even so, 
because parts of the definition as it read under the 1977 CAAA were 
retained in the 1990 CAAA, the explanation in the 1977 CAAA 
legislative history, and the interpretation in the case law, of 
those parts of the definition remain relevant to the definition as 
it reads today.

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[[Page 1463]]

3. Overview of Interpretation
    By its terms, the definition of ``standard of performance'' under 
CAA section 111(a)(1) provides that the emission limit that the EPA 
promulgates must be ``achievable'' and must be based on a system of 
emission reduction--generally, but not required to be always, a 
technological control--that the EPA determines to be the ``best 
system'' that is ``adequately demonstrated,'' ``taking into account . . 
. cost . . . nonair quality health and environmental impact and energy 
requirements.'' The D.C. Circuit has stated that in determining the 
``best'' system, the EPA must also take into account ``the amount of 
air pollution'' \132\ and ``technological innovation.''\133\
---------------------------------------------------------------------------

    \132\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \133\ See Sierra Club v. Costle, 657 F.2d at 347.
---------------------------------------------------------------------------

    As discussed below, the D.C. Circuit has elaborated on the criteria 
and process for determining whether a standard is ``achievable,'' based 
on an ``adequately demonstrated'' technology or system. In addition, 
the Court has identified limits on the costs and other factors that are 
acceptable for the technology or system to qualify as the ``best.'' The 
Court has also held that the EPA may consider the costs and other 
factors on a regional or national level (e.g., the EPA may consider 
impacts on the national economy and the affected industry as a whole) 
and over time, and not just on a plant-specific level at the time of 
the rulemaking.\134\ In addition, the Court has emphasized that the EPA 
has a great deal of discretion in weighing the various factors to 
determine the ``best system.'' \135\ Moreover, the Court has stated 
that in considering the various factors and determining the ``best 
system,'' the EPA must be mindful of the purposes of section 111, and 
the Court has identified those purposes as ``not giv[ing] a competitive 
advantage to one State over another in attracting industry[,]''. . . 
``reducing emissions as much as practicable[,]''. . . ``forc[ing] the 
installation of all the control technology that will ever be necessary 
on new plants at the time of construction[,]. . .'' and ``forc[ing] the 
development of improved technology.''\136\ Finally, based on cases the 
D.C. Circuit has handed down under related provisions of the CAA and 
the EPA's regulatory precedent under section 111, the EPA may 
promulgate a standard of performance for a particular category of 
sources even if not every type of new source in the category would be 
able to achieve that standard.\137\
---------------------------------------------------------------------------

    \134\ See Sierra Club v. Costle, 657 F.2d at 330.
    \135\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \136\ Sierra Club v. Costle, 657 F.2d at 325 & n.83 (quoting 44 
FR 33580, 33581/3-33582/1).
    \137\ See, e.g., International Harvester Co. v. EPA, 478 F.2d 
615, 640 (D.C. Cir. 1973).
---------------------------------------------------------------------------

    We next discuss in more detail each of these components of the 
interpretation of ``standard of performance.''

C. Technical Feasibility

    The D.C. Circuit's first decision under section 111, Portland 
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), 
concerned whether EPA's standard of performance for the cement industry 
met the requirement to be ``achievable,'' which, in turn, depended on 
whether the technology on which EPA based the standard was ``adequately 
demonstrated.'' \138\ In this case, the Court interpreted these 
provisions to require that the technology must be technically feasible 
for the source category, and established criteria for determining 
technical feasibility.
---------------------------------------------------------------------------

    \138\ 486 F.2d at 390.
---------------------------------------------------------------------------

    The Court explained that a standard of performance is 
``achievable'' if a technology can reasonably be projected to be 
available to new sources at the time they are constructed that will 
allow them to meet the standard. Specifically, the D.C. Circuit 
explained:

    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. . . .--It is the 
``achievability'' of the proposed standard that is in issue . . . .
    The Senate Report made clear that it did not intend that the 
technology ``must be in actual routine use somewhere.'' The 
essential question was rather whether the technology would be 
available for installation in new plants. . . . 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.\139\
---------------------------------------------------------------------------

    \139\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

In subsequent cases, the D.C. Circuit has consistently reiterated this 
formulation of ``achievable.'' \140\

    \140\ See, e.g., National Asphalt Pavement Ass'n v. Train, 539 
F.2d 775, 785 (D.C. Cir. 1976); Lignite Energy Council v. EPA, 109 
F.3d 930, 934 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    It should be noted that in another of the early cases, Essex 
Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973), the D.C. 
Circuit upheld a standard of performance as ``achievable'' on the basis 
of test data showing that the tested plant emitted less than or at the 
standard on three occasions and emitted above the standard on 16 
occasions, and that, on average, it emitted 15 percent above the 
standard on a total of 19 occasions.\141\ The fact that the plant had 
achieved the standard on at least a few occasions, even though the 
plant had not done so on the great majority of occasions, ``adequately 
demonstrated'' that the standard was ``achievable.''
---------------------------------------------------------------------------

    \141\ Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 
27.
---------------------------------------------------------------------------

D. Factors To Consider in Determining the ``Best System''

1. Amount of Emissions Reductions
    Although the definition of ``standard of performance'' does not by 
its terms identify the amount of emissions from the category of sources 
and the amount of emission reductions achieved as factors the EPA must 
consider in determining the ``best system of emission reduction,'' the 
D.C. Circuit has stated that the EPA must do so. See Sierra Club v. 
Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (``we can think of no 
sensible interpretation of the statutory words ``best . . . system'' 
which would not incorporate the amount of air pollution as a relevant 
factor to be weighed when determining the optimal standard for 
controlling . . . emissions'').\142\ This is consistent with the 
Court's statements in Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 
(D.C. Cir. 1973) that it is necessary to ``[k]eep[ ] in mind Congress' 
intent that new plants be

[[Page 1464]]

controlled to the `maximum practicable degree.' '' \143\
---------------------------------------------------------------------------

    \142\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 
governed by the 1977 CAAA version of the definition of ``standard of 
performance,'' which revised the phrase ``best system'' to read, 
``best technological system.'' The 1990 CAAA deleted 
``technological,'' and thereby returned the phrase to how it read 
under the 1970 CAAA. The Sierra Club v. Costle's interpretation of 
this phrase to require consideration of the amount of air emissions 
remains valid for the phrase ``best system.''
    \143\ Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 & n. 
27 (citing ``Summary of the Provisions of Conference Agreement on 
the Clean Air Amendments of 1970,'' 116 Cong. Rec. 42384, 42385 
(1970)).
---------------------------------------------------------------------------

2. Costs
    In several cases, the D.C. Circuit has elaborated on the cost 
factor that the EPA is required to consider under CAA section 
111(a)(1), and has identified limits to how costly a control technology 
may be before it no longer qualifies as the ``best system of emission 
reduction . . . adequately demonstrated.'' As a related matter, 
although no D.C. Circuit case addresses how to account for revenue 
generated from the byproducts of pollution control, it is logical and a 
reasonable interpretation of the statute that any expected revenues 
from the sale of pollutants or pollution control byproducts associated 
with those controls may be considered when determining the overall 
costs of implementation of the control technology. Clearly, such a sale 
would offset regulatory costs and so must be included to accurately 
assess the costs of the standard.
a. Criteria for Costs
(i) Formulation
    In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), the D.C. Circuit stated that to be ``adequately 
demonstrated,'' the system must be ``reasonably reliable, reasonably 
efficient, and . . . reasonably expected to serve the interests of 
pollution control without becoming exorbitantly costly in an economic 
or environmental way.'' The Court has reiterated this limit in 
subsequent case law, including Lignite Energy Council v. EPA, 198 F.3d 
930, 933 (D.C. Cir. 1999), in which it stated: ``EPA's choice will be 
sustained unless the environmental or economic costs of using the 
technology are exorbitant.'' In Portland Cement Ass'n v. EPA, 513 F.2d 
506, 508 (D.C. Cir. 1975), the Court elaborated by explaining that the 
inquiry is whether the costs of the standard are ``greater than the 
industry could bear and survive.'' \144\
---------------------------------------------------------------------------

    \144\ The 1977 House Committee Report noted:
    In the [1970] Congress [sic: Congress's] view, it was only right 
that the costs of applying best practicable control technology be 
considered by the owner of a large new source of pollution as a 
normal and proper expense of doing business.
    1977 House Committee Report at 184. Similarly, the 1970 Senate 
Committee Report stated:
    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.
    S. Comm. Rep. No. 91-1196 at 16.
---------------------------------------------------------------------------

    In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981), the 
Court provided a substantially similar formulation of the cost standard 
when it held: ``EPA concluded that the Electric Utilities' forecasted 
cost was not excessive and did not make the cost of compliance with the 
standard unreasonable. This is a judgment call with which we are not 
inclined to quarrel.'' We believe that these various formulations of 
the cost standard--``exorbitant,'' ``greater than the industry could 
bear and survive,'' ``excessive,'' and ``unreasonable''--are 
synonymous; the D.C. Circuit has made no attempt to distinguish among 
them. For convenience, in this rulemaking, we will use reasonableness 
as the standard, so that a control technology may be considered the 
``best system of emission reduction . . . adequately demonstrated'' if 
its costs are reasonable, but cannot be considered the best system if 
its costs are unreasonable.
(ii) Examples
    In the case law under CAA section 111, the D.C. Circuit has never 
invalidated a standard of performance on grounds that it was too 
costly. In several cases, the Court upheld standards that entailed high 
costs. In Portland Cement Association v. Ruckelshaus, 486 F.2d 375 
(D.C. Cir. 1973), the Court considered a standard of performance that 
the EPA promulgated for particulate matter emissions from new and 
modified Portland cement plants. According to the Court, the cost for 
the control technologies that a new facility would need to install to 
meet the standard was about 12 percent of the capital investment for 
the total facility, and annual operating costs for the control 
equipment would be 5-7 percent of the total plant operating costs. The 
Court found that these costs ``could be passed on without substantially 
affecting competition'' because the demand for the product was not 
``highly elastic with regard to price and would not be very sensitive 
to small price changes.'' The Court held that the EPA gave appropriate 
consideration to the ``economic costs to the industry.'' \145\
---------------------------------------------------------------------------

    \145\ Portland Cement Association v. Ruckelshaus, 486 F.2d at 
387-88.
---------------------------------------------------------------------------

    In Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the D.C. 
Circuit upheld a standard of performance imposing costly controls on 
SO2 emissions from coal-fired power plants. The Court noted:

    The importance of the challenged standards arises not only from 
the magnitude of the environmental and health interests involved, 
but also from the critical implications the new pollution controls 
have for the economy at the local and national levels.
* * * * *
    Coal is the dominant fuel used for generating electricity in the 
United States. . . . In 1976 power plant emissions accounted for 64 
percent of the total estimated sulfur dioxide emissions and 24 
percent of the total estimated particulate matter emissions in the 
entire country.
    EPA's revised NSPS are designed to curtail these emissions. EPA 
predicts that the new standards would reduce national sulfur dioxide 
emissions from new plants by 50 percent and national particulate 
matter emissions by 70 percent by 1995. The cost of the new 
controls, however, is substantial. EPA estimates that utilities will 
have to spend tens of billions of dollars by 1995 on pollution 
control under the new NSPS. Consumers will ultimately bear these 
costs, both directly in the form of residential utility bills, and 
indirectly in the form of higher consumer prices due to increased 
energy costs.\146\
---------------------------------------------------------------------------

    \146\ Sierra Club v. Costle, 657 F.2d at 313 (citations omitted) 
(emphasis added).
---------------------------------------------------------------------------

b. Revenue Enhancements
    In determining the costs of pollution control technology, it is 
reasonable to take into account any revenues generated by the sale of 
any by-products of the control process. Many types of pollution control 
technology generate byproducts that must be disposed, and the costs of 
that disposal are considered part of the costs of the control 
technology. For example, CCS generates a stream of CO2 that 
must be disposed of through sequestration.
    In some instances, however, the by-products of pollution control 
have marketable value. In these cases, revenues from selling the by-
products would defray the costs of pollution control. For example, in a 
recent rulemaking under the CAA regional haze program that entailed 
determining the ``best available retrofit technology'' (BART) for power 
plants, revenue from fly ash generated during boiler combustion and 
sold for use in concrete production factored into the State's selection 
of BART).\147\
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    \147\ Similarly, the EPA has taken into account the value of 
fuel savings in determining the costs of rules that limit emissions 
from motor vehicles, which limits manufacturers are expected to 
achieve by reducing the rates of fuel consumption by the vehicles. 
See, e.g., 77 FR 62624, 62628-29; 62923-27; 62942-46 (October 15, 
2012) (rulemaking setting GHG emissions standards for Light-Duty 
Vehicles for Model Years 2017-2025).

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[[Page 1465]]

3. Expanded Use and Development of Technology
    In Sierra Club v. Costle, the Court made clear that technological 
innovation was grounded in the terms of section 111 itself, and 
therefore should be considered one of the factors to be considered in 
determining the ``best system of emission reduction:''

    Our interpretation of section 111(a) is that the mandated 
balancing of cost, energy, and nonair quality health and 
environmental factors embraces consideration of technological 
innovation as part of that balance. The statutory factors which EPA 
must weigh are broadly defined and include within their ambit 
subfactors such as technological innovation.\148\
---------------------------------------------------------------------------

    \148\ Sierra Club v. Costle, 657 F.2d at 347.

    The Court's interpretation finds firm grounding in the legislative 
---------------------------------------------------------------------------
history. For example, the 1970 Senate Committee Report stated:

    Standards of performance should provide an incentive for 
industries to work toward constant improvement in techniques for 
preventing and controlling emissions from stationary sources, since 
more effective emission control will provide greater latitude in the 
selection of sites for new facilities.\149\
---------------------------------------------------------------------------

    \149\ S. Rep. 91-1196 at 16 (1970). The technology-forcing 
nature of section 111 is consistent with the technology-forcing 
nature of the 1970 CAAA as a whole. The principal Senate author of 
the 1970 CAAA, Sen. Edmund Muskie (D-ME), during the Senate floor 
debate, described the overall requirements of the 1970 CAAA and then 
observed:
    These five sets of requirements will be difficult to meet. But 
the committee is convinced that industry can make compliance with 
them possible or impossible. It is completely within their control. 
Industry has been presented with challenges in the past that seemed 
impossible to meet, but has been made possible.
    116 Cong. Rec. 32902 (Sept. 21, 1970) (statement of Sen. 
Muskie).

---------------------------------------------------------------------------
    Similarly, the 1977 Senate Committee Report stated:

    In passing the Clean Air Amendments of 1970, the Congress for 
the first time imposed a requirement for specified levels of control 
technology. The section 111 Standards of Performance for New 
Stationary Sources required the use of the ``best system of emission 
reduction which (taking into account the cost of achieving such 
reduction) the Administrator determines has been adequately 
demonstrated.'' This requirement sought to assure the use of 
available technology and to stimulate the development of new 
technology.\150\
---------------------------------------------------------------------------

    \150\ S. Rep. 95-127 at 17 (1977), cited in Sierra Club v. 
Costle, 657 F.2d at 346 n. 174. The 1977 CAAA legislative history is 
replete with other references to the technology forcing nature of 
section 111 or the CAAA as a whole. See ``1977 Clean Air Act 
Conference Report: Statement of Intent; Clarification of Select 
Provisions,'' 123 Cong. Rec. 27071 (1977) (quoted in Sierra Club v. 
Costle, 657 F.2d at 346 n. 174) (one of the enumerated purposes of 
section 111 was to ``create incentives for new technology''); 123 
Cong. Reg. 16195 (May 24, 1977) (statement of Rep. Meads) (''The 
main purposes of the Clean Air Act Amendments of 1977 are as 
follows: [hellip] tenth, to promote the utilization of new 
technologies for pollution choice'').

    The legislative history just quoted identifies three different ways 
that Congress designed section 111 to authorize standards of 
performance that promote technological improvement: (i) the development 
of technology that may be treated as the ``best system of emission 
reduction . . . adequately demonstrated;'' under section 111(a)(1) 
\151\; (ii) the expanded use of the best demonstrated technology; \152\ 
and (iii) the development of emerging technology.\153\
---------------------------------------------------------------------------

    \151\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 
391 (D.C. Cir. 1973) (the best system of emission reduction must 
``look[ ] toward what may fairly be projected for the regulated 
future, rather than the state of the art at present'').
    \152\ See 1970 Senate Committee Report No. 91-1196 at 15 (``The 
maximum use of available means of preventing and controlling air 
pollution is essential to the elimination of new pollution 
problems'').
    \153\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

E. Nationwide Component of Factors in Determining the ``Best System''

    Another component of the D.C. Circuit's interpretations of section 
111 is that the EPA may consider the various factors it is required to 
balance on a national or regional level and over time, and not only on 
a plant-specific level at the time of the rulemaking.\154\ As the D.C. 
Circuit stated in Sierra Club v. Costle:
---------------------------------------------------------------------------

    \154\ Sierra Club v. Costle, 657 F.2d at 351.

    The language of [the definition of `standard of performance' in] 
section 111 . . . gives EPA authority when determining the best . . 
. system to weigh cost, energy, and environmental impacts in the 
broadest sense at the national and regional levels and over time as 
opposed to simply at the plant level in the immediate present.\155\
---------------------------------------------------------------------------

    \155\ Sierra Club v. Costle, 657 F.2d at 330.

    In that case, in upholding the EPA's variable standard for 
SO2 emissions, the D.C. Circuit justified and elaborated on 
that interpretation of the definition of ``standard of performance'' 
and then went on to evaluate the EPA's justification for its rulemaking 
in light of that interpretation. It is useful to set out these parts of 
the Court's opinion at some length in order to make clear the scope of 
the factors and the nature of the balancing exercise that the Court 
held section 111(a)(1) authorizes the EPA to take.
    The Court first recited the terms of the definition of ``standard 
of performance,'' as it read following the 1977 CAA Amendments:

    The pertinent portion of section 111 reads:
    A standard of performance shall reflect the degree of emission 
limitation . . . achievable through application of the best . . . 
system of . . . emission reduction which (taking into consideration 
the cost of achieving such emission reduction, any nonair quality 
health and environmental impact and energy requirements) the 
Administrator determines has been adequately demonstrated.\156\
---------------------------------------------------------------------------

    \156\ Sierra Club v. Costle, 657 F.2d at 330. Note that the 
elipses in the quotation of the definition of ``standard of 
performance'' in the text indicate the omission of terms repealed by 
the 1990 CAAA. The Court's analysis of the meaning of this 
definition did not turn on those repealed terms, and as a result, 
the Court's analysis remains relevant for the current definition of 
``standard of performance.''

    The Court then stated that these terms could reasonably be read to 
authorize the EPA to establish the standard of performance based on 
environmental, economic, and energy considerations ``on the grand 
---------------------------------------------------------------------------
scale:''

    Parsed, section 111 most reasonably seems to require that EPA 
identify the emission levels that are ``achievable'' with 
``adequately demonstrated technology.'' After EPA makes this 
determination, it must exercise its discretion to choose an 
achievable emission level which represents the best balance of 
economic, environmental, and energy considerations. It follows that 
to exercise this discretion EPA must examine the effects of 
technology on the grand scale in order to decide which level of 
control is best. For example, an efficient water intensive 
technology capable of 95 percent removal efficiency might be 
``best'' in the East where water is plentiful, but environmentally 
disastrous in the water-scarce West where a different technology, 
capable of only 80 percent reduction efficiency might be ``best.'' . 
. . The standard is, after all, a national standard with long-term 
effects.\157\
---------------------------------------------------------------------------

    \157\ Sierra Club v. Costle, 657 F.2d at 330 (emphasis added). 
As noted, after the 1990 CAAA--which changed the term ``best 
technological system . . . of emission reduction . . . adequately 
demonstrated'' to ``best system . . . of emission reduction . . . 
adequately demonstrated''--the Court's discussion of ``adequately 
demonstrated technology'' should be considered to hold true for 
adequately demonstrated system of emission reduction.

    The Court then justified its ``reading of . . . section 111 as 
authorizing the EPA to balance long-term national and regional impacts 
---------------------------------------------------------------------------
of alternative standards'' on the 1977 CAAA legislative history:

    The Conferees defined the best technology in terms of ``long-
term growth,'' ``long-term cost savings,'' effects on the ``coal 
market,'' including prices and utilization of coal reserves, and 
``incentives for improved technology.'' Indeed, the Reports from 
both Houses on the Senate and House bills illustrate very clearly 
that Congress itself was using a long-term lens with a broad focus 
on future costs, environmental and energy effects of different 
technological systems when it discussed section 111.\158\
---------------------------------------------------------------------------

    \158\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 
(citing legislative history).


[[Page 1466]]


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

    The Court then examined the EPA's justification for the variable 
standard, and held that the justification was reasonable.\159\ The 
Court quoted at length the EPA's discussion of how it ``justified the 
variable standard in terms of the policies of the Act,'' including 
balancing long-term national and regional impacts:
---------------------------------------------------------------------------

    \159\ Sierra Club v. Costle, 657 F.2d at 337-39.

    The standard reflects a balance in environmental, economic, and 
energy consideration by being sufficiently stringent to bring about 
substantial reductions in SO2 emissions (3 million tons 
in 1995) yet does so at reasonable costs without significant energy 
penalties. . . . By achieving a balanced coal demand within the 
utility sector and by promoting the development of less expensive 
SO2 control technology, the final standard will expand 
environmentally acceptable energy supplies to existing power plants 
and industrial sources.
    By substantially reducing SO2 emissions, the standard 
will enhance the potential for long term economic growth at both the 
national and regional levels.\160\
---------------------------------------------------------------------------

    \160\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 
33583/3-33584/1).
---------------------------------------------------------------------------

F. Chevron Framework

    Above, we discuss how in Sierra Club v. Costle the D.C. Circuit 
interpreted the definition of ``standard of performance'' in CAA 
section 111(a)(1), among other things, to authorize the EPA to balance 
economic, environmental, or energy factors through a nationwide lens, 
and to encompass technology forcing. The D.C. Circuit handed down this 
decision in 1981, and therefore it did not employ the two-step 
framework for statutory construction in federal rulemaking that the 
U.S. Supreme Court mandated in 1984, in Chevron U.S.A. Inc. v. NRDC, 
467 U.S. 837 (1984). However, the D.C. Circuit's interpretations are 
fully consistent with the Chevron framework.
    In Chevron, the Supreme Court held that an agency must, at Step 1, 
determine whether Congress's intent as to the specific matter at issue 
is clear, and, if so, the agency must give effect to that intent. If 
congressional intent is not clear, then, at Step 2, the agency has 
discretion to fashion an interpretation that is a reasonable 
construction of the statute.\161\
---------------------------------------------------------------------------

    \161\ Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984).
---------------------------------------------------------------------------

    As noted, under CAA section 111(a)(1), a standard of performance 
must be based on 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) . . . 
has been adequately demonstrated.'' The terms ``best system of emission 
reduction,'' ``cost,'' and ``energy requirements,'' on their face, can 
be interpreted to apply on a regionwide or nationwide basis, and are 
not limited to the individual source. Thus, this interpretation is 
supportable under Chevron step 1, but even if not, then the EPA 
considers the interpretation supportable under step 2 because it is 
reasonable and consistent with the purposes of the CAA. Similarly, the 
technology-development interpretation is supportable under Chevron step 
1 because encouraging the utilization or development of improved 
technology is a logical consideration in determining the ``best system 
of emission reduction'' and, as noted, was clearly a focus of the 
legislative history. Even if that interpretation is not supportable 
under Chevron step 1, however, then the EPA considers the 
interpretation supportable under step 2 because it is reasonable and 
consistent with the purposes of the CAA.

G. Agency Discretion

    The D.C. Circuit has made clear that the EPA has broad discretion 
in determining the appropriate standard of performance under the 
definition in CAA section 111(a)(1), quoted above. Specifically, in 
Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the Court 
explained that ``section 111(a) explicitly instructs the EPA to balance 
multiple concerns when promulgating a NSPS,'' \162\ and emphasized that 
``[t]he text gives the EPA broad discretion to weigh different factors 
in setting the standard.'' \163\ In Lignite Energy Council v. EPA, 198 
F.3d 930 (D.C. Cir. 1999), the Court reiterated:
---------------------------------------------------------------------------

    \162\ Sierra Club v. Costle, 657 F.2d at 319.
    \163\ Sierra Club v. Costle, 657 F.2d at 321.

    Because section 111 does not set forth the weight that should be 
assigned to each of these factors, we have granted the agency a 
great degree of discretion in balancing them. . . . EPA's choice [of 
the ``best system''] will be sustained unless the environmental or 
economic costs of using the technology are exorbitant. . . . EPA 
[has] considerable discretion under section 111.\164\
---------------------------------------------------------------------------

    \164\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999) (paragraphing revised for convenience).

    The important point is that Courts acknowledge that there are 
several factors to be considered and what is ``best'' depends on how 
much weight to give the factors. In promulgating certain standards of 
performance, EPA may give greater weight to particular factors than it 
may do so in promulgating other standards of performance. Thus, the 
determination of what is ``best'' is complex and necessarily requires 
an exercise of judgment. By analogy, the question of who is the 
``best'' sprinter in the 100-meter dash primarily depends on only one 
criterion--speed--and therefore is relatively straightforward, while 
the question of who is the ``best'' baseball player depends on a more 
complex weighing of several criteria and therefore requires a greater 
exercise of judgment.

H. Lack of Requirement That Standard Be Able To Be Met by All Sources

    Under CAA section 111, an emissions standard may meet the 
requirements of a ``standard of performance'' even if it cannot be met 
by every new source in the source category that would have constructed 
in the absence of that standard. As discussed below, this is clear in 
light of (i) the legislative history of CAA section 111, read in 
conjunction with the legislative history of the CAA as a whole; (ii) 
case law under analogous CAA provisions; and (iii) long-standing 
precedent in the EPA rulemakings under CAA section 111.
1. Legislative History
    As noted, Congress, in enacting section 111 in the 1970 CAAA, 
intended that the EPA promulgate uniform, nationwide controls. Congress 
was explicit that this meant that large industrial sources, including 
electric generating power plants, would be required to implement 
controls meeting the requirements regardless of their location. 
According to the 1970 Senate Committee Report:

    Major new facilities such as electric generating plants, kraft 
pulp mills, petroleum refineries, steel mills, primary smelting 
plants, and various other commercial and industrial operations must 
be controlled to the maximum practicable degree regardless of their 
location and industrial operations * * *.\165\
---------------------------------------------------------------------------

    \165\ S. Rep. 91-1116 at 16 (1970). See 116 Cong. Rec. 42,384 
(statement of Sen. Muskie) (summarizing the House-Senate Conference 
agreement).)

    Congress's purposes in designing a standard that called for uniform 
national controls were to prevent pollution havens--caused by some 
states seeking competitive advantage by limiting their pollution 
control requirements--and to assure that areas that had good air 
quality would be able to maintain good air quality even after new 
industrial sources located there, which, in turn, would allow more 
sources to locate there as well.\166\
---------------------------------------------------------------------------

    \166\ See S. Rep. 91-1196 at 16 (1970).
---------------------------------------------------------------------------

    At the same time, Congress recognized that in light of the 
attainment provisions of the CAAA of 1970, sources--particularly large 
industrial sources, again, including electric generating plants--may 
not be

[[Page 1467]]

able to construct new facilities anywhere in the country; that is, an 
area with air quality at or above the NAAQS limits might not have 
enough room in its airshed to accommodate these new facilities. The 
1970 Senate Committee Report stated, ``[l]and use policies must be 
developed to prevent location of facilities which are not compatible 
with implementation of national standards.'' \167\ Senator Muskie 
added:
---------------------------------------------------------------------------

    \167\ 1970 Senate Commitee Report at 2.

    Land use planning and control should be used by State, local, 
and regional agencies as a method of minimizing air pollution. Large 
industries and power generating facilities should be located in 
places where their adverse effect on the air is minimal. There is a 
need for State or regional agencies to revise proposed power plant 
sites to assure that a number of environmental values, including air 
pollution, are considered.\168\
---------------------------------------------------------------------------

    \168\ 116 Cong. Rec. 32,917 (1970) (statement of Sen. Muskie).

The 1970 CAAA legislative history includes other statements that also 
recognize that under the newly required air pollution control 
requirements, new sources may not be able to build anywhere in the 
country and, in fact, some existing sources might have to be shut 
down.\169\
---------------------------------------------------------------------------

    \169\ See 116 Cong. Rec. 42,385 (Dec. 18, 1970) (statement of 
Sen. Muskie) (sources of hazardous air pollutants could be required 
to close due to absence of control techniques).
---------------------------------------------------------------------------

    Thus, in 1970, Congress designed section 111 to require uniform 
national controls for large industrial facilities, while recognizing 
that those facilities could not necessarily construct in every place in 
the country. Although at the time, Congress expected that the reason 
why some sources would not be able to locate in certain places was 
related to local air quality concerns, if the reason turns out to be 
related to the emission limits that the EPA promulgates under section 
111, that should not be viewed as inconsistent with congressional 
intent for section 111. For example, if the EPA promulgates section 111 
emission limits based on a particular type of technology, and for 
economic or technical reasons, sources are able to utilize that 
technology in only certain parts of the country and not other parts, 
that result should not be viewed as inconsistent with congressional 
intent for CAA section 111. Rather, that result is consistent with 
Congress's recognition that certain sources may be precluded from 
locating in certain areas.
2. Case Law Under Analogous CAA Provisions
    Under analogous CAA provisions, the D.C. Circuit has recognized 
that the EPA may promulgate uniform standards that apply to new sources 
in a group or category of sources, even though some types of those new 
sources that would otherwise construct would no longer be able to 
construct because they could not meet the standard. One of these cases 
was International Harvester Co. v. EPA, 478 F.2d 615 (D.C. Cir. 1973). 
There, the EPA declined to exercise its discretion under the CAA mobile 
source provisions, as they read at that time (42 U.S.C. 1857f-
1(b)(5)(D) (1970 CAAA)), to grant automakers a one-year extension to 
comply with exhaust standards. The EPA stated that the automakers had 
failed to meet their burden of establishing that controls were not 
available. The EPA based its decision on grounds that certain 
technology was available for the motor vehicles in question. The EPA 
dismissed the automakers' objections that this technology could not 
feasibly be installed in all models or engine types, and the EPA 
explained that the public's ``basic demand'' for automobiles could be 
met by the models and engine types that could feasibly install that 
technology. 478 F.2d at 626.
    Although the Court remanded the EPA's decision not to grant the 
one-year extension, it agreed with the EPA on this point, stating:

    We are inclined to agree with the Administrator that as long as 
feasible technology permits the demand for new passenger automobiles 
to be generally met, the basic requirements of the Act would be 
satisfied, even though this might occasion fewer models and a more 
limited choice of engine types. The driving preferences of hot 
rodders are not to outweigh the goal of a clean environment.\170\
---------------------------------------------------------------------------

    \170\ International Harvester Co. v. EPA, 478--F.2d at 640.

    Similarly, in a 2007 decision under CAA section 112, NRDC v. EPA, 
489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circuit upheld the EPA's 
decision to apply the same hazardous air pollutant requirements to 
different types of plywood and composite wood products facilities--even 
though one of those types of facilities faced greater difficulties 
meeting the requirements than the other types of facilities--in part on 
the grounds that the facilities ``compet[ed] in the same markets.'' 
\171\
---------------------------------------------------------------------------

    \171\ NRDC v. EPA, 489 F.3d at 1376.
---------------------------------------------------------------------------

    Thus, these decisions supported EPA's emissions requirements, even 
though certain types of sources could meet those requirements more 
readily than others, on grounds that the requirements would not impede 
the manufacture of products that would satisfy overall consumer demand. 
By the same token, the inability of some coal-fired sources to locate 
in certain areas would not create reliability problems or prevent the 
satisfaction of overall demand for electricity.
3. Section 111 Rulemaking Precedent
    Through long-standing rulemaking precedent, the EPA has taken the 
position that section 111 authorizes a standard of performance for a 
source category that may not be feasible for all types of new sources 
in the category, as long as there are other types of sources in the 
category that can serve the same function and meet the standard. 
Specifically, in a 1976 rulemaking under section 111 covering primary 
copper, zinc, and lead smelters, the EPA established, as the standard 
of performance, a single standard for SO2 emissions for new 
construction or modifications of reverberatory, flash, and electric 
smelting furnaces in primary copper smelters that process materials 
with low levels of volatile impurities. The EPA acknowledged that 
although for flash and electric smelting furnaces, the cost of the 
controls was ``reasonable,'' for reverberatory smelting furnaces, the 
cost of the standard was ``unreasonable in most cases.'' Even so, the 
EPA determined that this standard would not adversely affect new 
construction or modification of primary copper smelters processing 
materials containing low levels of volatile impurities because new 
construction could use flash and electric smelting furnaces, and 
existing sources could expand without increasing emissions.\172\ The 
EPA explained:
---------------------------------------------------------------------------

    \172\ Standards of Performance for New Stationary Sources, 
Primary Copper, Zinc, and Lead Smelters, 41 FR 2331, 2333 (Jan. 15, 
1976).

    [T]he Agency believes that section 111 authorizes the 
promulgation of one standard applicable to all processes used by a 
class of sources, in order that the standard may reflect the maximum 
feasible control for that class. When the application of a standard 
to a given process would effectively ban the process, however, a 
separate standard must be prescribed for it unless some other 
process(es) is available to perform the function at reasonable cost. 
. . .
    The Administrator has determined that the flash copper smelting 
process is available and will perform the function of the 
reverberatory copper smelting process at reasonable cost. . . .\173\
---------------------------------------------------------------------------

    \173\ 41 FR 2333.

VII. Rationale for Emission Standards for New Fossil Fuel-Fired Boilers 
and IGCCs

A. Overview

    In this section we explain our rationale for emission standards for 
new fossil fuel-fired boiler and IGCC EGUs,

[[Page 1468]]

which are based on our proposal that efficient generating technology 
implementing partial CCS is the BSER adequately demonstrated for those 
sources.
    As noted, CAA section 111 and subsequent court decisions establish 
a set of factors for the EPA to consider in a BSER determination, 
including criteria listed in CAA section 111 or identified in the court 
decisions and the underlying purposes of section 111. Key factors 
include: emission reductions, technical feasibility, costs, and 
encouragement of technology. Other factors, such as energy impacts, may 
also be important. As also noted, the EPA has discretion in balancing 
those factors, and may balance them differently in promulgating 
standards for different source categories.
    The EPA considered three alternative control technology 
configurations as potentially representing the BSER for new fossil 
fuel-fired boilers and IGCC units. Power company announcements indicate 
that the few new coal-fired projects that may occur will likely 
consider one or more of these three configurations. The three 
alternatives are: (1) Highly efficient new generation technology that 
does not include any level of CCS, (2) highly efficient new generation 
technology with ``full capture'' CCS (that is, CCS with capture of at 
least 90 percent CO2 emissions) and (3) highly efficient new 
generation technology with ``partial capture'' CCS (that is, CCS with 
capture of a lower level of CO2 emissions).
    We discuss each of these alternatives below, and explain why we 
propose that partial capture CCS qualifies as the BSER. We first 
discuss the technical systems that we considered for the BSER, our 
evaluations of them, and our reasons for determining that only partial 
CCS meets the criteria to qualify as the BSER. We include in this 
discussion our rationale for selecting 1,100 lb CO2/MWh as 
the emission limitation for these sources and why we are considering a 
range from 1,000 to 1,200 lb CO2/MWh for the final rule. We 
next discuss our rationale for allowing an 84-operating-month averaging 
period as an alternative compliance method, with the requirement that 
sources choosing that method meet a limit of between 1,000 lb 
CO2/MWh and 1,050 lb CO2/MWh.\174\ We then 
explain our rationale for the requirements for geologic 
sequestration.\175\
---------------------------------------------------------------------------

    \174\ This is on a gross output basis. All emission rates in 
this section are on a gross output basis unless specifically noted 
otherwise.
    \175\ It should be noted that the standard of performance that 
we propose in this rulemaking for new fossil-fired utility steam-
generating units of 1,100 lb CO2/MWh applies to new 
liquid oil- and natural-gas fired units, as well as solid fuel-fired 
units. However, we are not conducting a separate analysis of the 
best system of emission reduction for new liquid oil- and natural 
gas-fired units. That is because no new utility steam-generating 
units designed to be fired primarily with liquid oil or natural gas 
have been built for many years, and none are expected to be built in 
the foreseeable future, due to the significantly lower costs of 
building combustion turbines to be fired with those fuels.
---------------------------------------------------------------------------

B. Identification of the Best System of Emission Reduction

1. Highly Efficient New Generation Without CCS Technology
    Some commenters on the April 2012 proposal suggested that the 
emission limitation for new coal-fired EGUs should be based on the 
performance of highly efficient generation technology that does not 
include CCS, such as (i) a supercritical \176\ pulverized coal (SCPC) 
or CFB boiler, or (ii) a modern, well-performing IGCC unit.
---------------------------------------------------------------------------

    \176\ Subcritical coal-fired boilers are designed and operated 
with a steam cycle below the critical point of water. Supercritical 
coal-fired boilers are designed and operated with a steam cycle 
above the critical point of water. Increasing the steam pressure and 
temperature increases the amount of energy within the steam, so that 
more energy can be extracted by the steam turbine, which in turn 
leads to increased efficiency and lower emissions.
---------------------------------------------------------------------------

    These options are technically feasible. However, we do not consider 
them to qualify as the BSER for the following reasons:
a. Lack of Significant CO2 Reductions
    Because of the large amount of CO2 emissions from solid-
fuel fired power plants, it is important, in promulgating a standard of 
performance for these sources, to give effect to the purpose of CAA 
section 111 of providing ``as much [emission reduction] as 
practicable.'' \177\ Accordingly, we reviewed the emission rates of 
efficient PC and CFB units. According to the DOE/NETL estimates, a new 
subcritical PC unit firing bituminous coal would emit approximately 
1,800 lb CO2/MWh,\178\ a new SCPC unit using bituminous coal 
would emit nearly 1,700 lb CO2/MWh, and a new IGCC unit 
\179\ would emit about 1,450 lb CO2/MWh.\180\
---------------------------------------------------------------------------

    \177\ Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR 33581/3--
33582/1).
    \178\ Exhibit ES-2 from ``Cost and Performance Baseline for 
Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to 
Electricity'', Revision 2, Report DOE/NETL-2010/1397 (November 
2010).
    \179\ ``Case 1'' from Exhibit ES-2 from ``Cost and Performance 
Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and 
Natural Gas to Electricity'', Revision 2, Report DOE/NETL-2010/1397 
(November 2010).
    \180\ The comparable emissions on a net basis are: subcritical 
PC--1,888 lb CO2/MWh; supercritical PC--1,768 lb 
CO2/MWh; and IGCC--1,723 lb CO2/MWh.
---------------------------------------------------------------------------

    New power sector projects using coal as a primary fuel that have 
been proposed or are currently under construction are generally SCPC or 
IGCC projects. For example, since 2007, almost all coal-fired EGUs that 
have broken ground have been high performing versions of SCPC or IGCC 
projects.\181\ Among those plants are: (1) AEP's John W. Turk, Jr. 
Power Plant, a 600 MW ultra-supercritical \182\ PC (USCPC) facility 
located in the southwest corner of Arkansas; (2) Duke Power's 
Edwardsport plant, a 618 MW coal IGCC unit located in Knox County, 
Indiana; and (3) Southern Company's Kemper County Energy Facility, a 
582 MW lignite IGCC unit located in Kemper County, Mississippi. These 
facilities all use advanced generation technology: Turk, as noted, is 
an ultra-supercritical boiler; Edwardsport is an IGCC unit that is 
``CCS ready;'' and Kemper is an IGCC unit that will implement partial 
CCS.
---------------------------------------------------------------------------

    \181\ The only exception that we are aware of is the Virginia 
City subcritical CFB unit.
    \182\ Ultra-supercritical (USC) and advanced ultra-supercritical 
(A-USC) are terms often used to designate a coal-fired power plant 
design with steam conditions well above the critical point.
---------------------------------------------------------------------------

    Under these circumstances, in this rule, identifying a new 
supercritical unit as the BSER and requiring the associated emission 
limitation, would provide little meaningful CO2 emission 
reductions for this source category. As noted, for the most part, new 
sources are already designed to achieve at least that emission 
limitation. Identifying IGCC as the BSER and requiring the associated 
emission limitation, would provide some CO2 emission 
reductions from the segment of the industry that would otherwise 
construct new PC units, but not from the segment of the industry that 
would already construct new IGCC units.
    As a result, emission reductions in the amount that would result 
from an emission standard based on SCPC/USCPC or even IGCC as the BSER 
would not be consistent with the purpose of CAA section 111 to achieve 
``as much [emission reduction] as practicable.'' \183\ As we discuss 
below, identifying CCS-partial capture as the BSER would provide for 
significantly greater emissions reductions.
---------------------------------------------------------------------------

    \183\ Sierra Club, F.2d at 327 & n. 83 (quoting 44 FR 33581/3--
33582/1).
---------------------------------------------------------------------------

b. Lack of Incentive for Technological Innovation
    Identifying highly efficient generation technology as the BSER 
would not achieve another purpose of CAA section 111, to encourage the 
development and implementation of control technology.

[[Page 1469]]

At present, CCS technologies are the most promising options to achieve 
significant reductions in CO2 emissions from fossil-fuel 
fired utility boilers and IGCC units. A standard based on the 
performance of highly efficient coal-fired generation does not advance 
the development and implementation of control technologies that reduce 
CO2 emissions. In addition, highly efficient generation 
technology does not develop control technology that is transferrable to 
existing EGUs. Further, highly efficient generation technology does not 
necessarily promote the development of generation technologies that 
would minimize the auxiliary load requirements and costs of future CCS 
requirements (e.g., developing an IGCC design where the costs and 
auxiliary load requirements of adding CCS are minimized).
    On the contrary, such a standard could impede the advancement of 
CCS technology by creating regulatory disincentives for such 
technology. In 2011, AEP deferred construction of a large-scale CCS 
retrofit demonstration project on one of their coal-fired power plants 
because the state's utility regulators would not approve cost recovery 
for CCS investments without a regulatory requirement to reduce 
CO2 emissions. AEP's chairman was explicit on this point, 
stating in a July 17, 2011 press release announcing the deferral:

    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.\184\
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    \184\ https://www.aep.com/newsroom/newsreleases/?id=1704.

    As we discuss below, regulatory requirements for CO2 
reductions with some level of CCS as the BSER will promote further 
development of the technology.
2. Carbon Capture and Storage
    We have also considered whether the emission limitation for new 
coal-fired EGUs should be based on the performance of CCS, including 
either ``full capture'' CCS that treats the entire flue gas or syngas 
stream to achieve on the order of 90 percent reduction in 
CO2 emissions, or ``partial capture'' CCS that achieves some 
level less than 90 percent of capture.
    We propose that implementation of partial capture CCS technology is 
the BSER for new fossil fuel-fired boilers and IGCC units because it 
fulfills the criteria established under CAA section 111. In the 
sections that follow, we explain the technical configurations that 
facilitate full and partial capture, describe the operational 
flexibilities that partial capture offers, and then identify and 
justify the emission rate that we propose based on partial capture. 
After that, we discuss the criteria for BSER, and describe why partial 
capture meets those criteria and why full capture does not. Among other 
things, partial capture provides meaningful emission reductions, it has 
been adequately demonstrated to be technically feasible, it can be 
implemented at a reasonable cost, and it promotes deployment and 
further development of the technology.
3. Technical Configurations for CCS
    The DOE's National Energy Technology Laboratory (NETL) performed a 
study to establish the cost and performance for a range of 
CO2 capture levels for new SCPC and IGCC power plants.\185\ 
The study identified technical configurations that were tailored to 
achieve a specific level of carbon capture.
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    \185\ ``Cost and Performance of PC and IGCC Plants for a Range 
of Carbon Dioxide Capture'', DOE/NETL-2011/1498, May 27, 2011.
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a. SCPC
    For the new SCPC case, the study assumed a new SCPC boiler with a 
combination of low-NOX burners (LNB) with overfire air (OFA) 
and a selective catalytic reduction (SCR) system for NOX 
control. The plant was assumed to have a fabric filter and a wet 
limestone flue gas desulfurization (FGD) scrubber for particulate 
matter and sulfur dioxide (SO2) control, respectively. The 
plant was also assumed to have a sodium hydroxide (NaOH) polishing 
scrubber to ensure that the flue gas entering the CO2 
capture system has a SO2 concentration of 10 ppmv or less. 
The SCPC plant was equipped with Fluor's Econamine FG Plus\SM\ process 
for post-combustion CO2 capture via temperature swing 
absorption with a monoethanolamine (MEA) solution as the chemical 
solvent.
    The study's authors identified two options for achieving partial 
capture (i.e., less than 90 percent CO2 capture) in the SCPC 
unit. The first option was to process the entire flue gas stream 
through the MEA capture system at reduced solvent circulation rates. 
The second option was to maintain the same high solvent circulation 
rate and steam stripping requirement as would be used for full capture 
but only treat a portion of the total flue gas stream. The authors 
determined that the second approach--the ``slip stream'' approach--was 
the most economical. The authors further noted that the cost of 
CO2 capture with an amine scrubbing process is dependent on 
the volume of gas being treated, and a reduction in flue gas flow rate 
will: (1) Decrease the quantity of energy consumed by flue gas blowers, 
(2) reduce the size of the CO2 absorption columns, and (3) 
trim the cooling water requirement of the direct contact cooling 
system. The slip stream approach leads to lower capital and operating 
costs. All of the partial capture cases in the NETL study assumed this 
approach.
b. IGCC
    For a new IGCC unit, the product syngas would contain primarily 
H2, CO and some lesser amount of CO2.\186\ The 
amount of CO2 can be increased by ``shifting'' the 
composition via the catalytic water-gas shift (WGS) reaction. This 
process involves the catalytic reaction of steam (``water'') with CO 
(``gas'') to form H2 and CO2. An emission 
standard that requires partial capture of CO2 from the 
syngas could be met by adjusting the level of CO2 in the 
syngas stream by controlling the level of syngas ``shift'' prior to 
treatment in the pre-combustion acid gas treatment system.
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    \186\ The amount of CO2 in un-shifted syngas depends 
upon the specific gasifier technology used, the operating 
conditions, and the fuel used; but is typically less than 20 volume 
percent (https://www.netl.doe.gov/technologies/coalpower/gasification/gasifipedia/4-gasifiers/4-3_syngas-table2.html).
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    For a new IGCC EGU, the study's authors assumed the use of the GE 
gasifier coupled with a variety of potential configurations (i.e., no 
WGS reactor, single-stage WGS, two-stage WGS, varying WGS bypass 
ratios, and CO2 scrubber removal efficiency). The study 
evaluated a number of IGCC plant configurations. The first was an IGCC 
that used the Selexol\TM\ process for acid gas control (i.e., hydrogen 
sulfide (H2S) and CO2) but no WGS reactor. This 
unit was capable of CO2 capture ranging from zero up to 25 
percent. The no-CO2 capture case employed a one-stage 
Selexol\TM\ unit for H2S control and the 25 percent 
CO2 capture case utilized a two-stage Selexol\TM\ unit to 
maximize CO2 capture from the unshifted syngas (i.e., >90 
percent of the CO2 from the unshifted syngas was captured in 
the second stage Selexol\TM\ scrubber).

[[Page 1470]]

    To achieve moderate levels of partial CO2 capture--
approximately 25 to 75 percent--the IGCC was configured with a single-
stage WGS reactor with bypass and a two-stage Selexol\TM\ unit. Varying 
the extent of the WGS reaction by controlling the amount of syngas that 
was processed through the WGS reactor (by controlling the amount that 
bypassed the WGS reactor) manipulated the level of CO2 
capture. As more syngas is processed through the WGS reactor, the steam 
demand increases. The Selexol\TM\ removal efficiency was manipulated by 
varying the solvent circulation rate. Thus, a facility using this 
configuration could select or ``dial in'' a level of control of between 
25-75 percent.
    To achieve higher CO2 capture levels--levels greater 
than 75 percent--the IGCC was configured with a two-stage WGS with 
bypass and the two-stage acid gas (Selexol\TM\) scrubbing system. The 
facility could ``dial in'' a level of control of between 25 to greater 
than 90 percent by controlling the WGS bypass and the Selexol\TM\ 
scrubber recirculation rates.
    The water-gas shift involves the catalytic reaction of carbon 
monoxide and steam. Since the syngas initially contains primarily CO 
and H2, this shift reaction diminishes the concentration of 
CO and enriches the concentration of H2 in the pre-
combustion syngas stream via the following reaction:
[GRAPHIC] [TIFF OMITTED] TP08JA14.029

    An unshifted or partially shifted syngas can be combusted using a 
typical combustion turbine. However, as the level of H2 in 
the syngas increases, the more the syngas must be diluted with 
N2 or air. Very high levels of H2 in the syngas 
stream require use of a specialty hydrogen turbine.
4. Operational and Design Flexibility
    To this point, most of the studies involving research, development 
and demonstration of carbon capture technology, along with most of the 
studies that have modeled the costs and implementation of such 
technology have assumed capture requirements of 90 percent for fossil 
fuel-fired power plants (``full capture''). However, the EPA believes 
that partial capture provides significant benefits because an emission 
limit based on partial capture offers operators considerable 
operational flexibility. With such emission limits, project developers 
would have the option of designing and installing CO2 
capture technology at a size sufficient to treat the entire flue gas 
stream, with the capability to meet CO2 emission limits that 
are much lower than required. The operator of the plant could then 
choose to achieve those deeper capture rates during non-peak 
electricity demand periods and to achieve lesser capture rates (and 
thus generate more electricity) during peak electricity demand periods. 
This type of operational flexibility provides owners and operators the 
opportunity to optimize the operation and minimize the cost of CCS in 
new fossil fuel-fired projects.
    In addition, an emission standard that can be met with partial 
capture offers the opportunity for design flexibility. A project 
developer of a new conventional coal-fired plant (i.e., a new 
supercritical PC or CFB) could install post-combustion CO2 
scrubbers that have been designed and sized to treat only a portion of 
the flue gas stream.
    For a new IGCC unit, as noted, an emission standard that requires 
partial capture of CO2 offers operational flexibility 
because the standard could be met by adjusting the level of 
CO2 in the syngas stream by controlling the level of syngas 
``shift'' prior to treatment in the pre-combustion acid gas treatment 
system.

C. Determination of the Level of the Standard

    Once the EPA has determined that a technology has been adequately 
demonstrated based on cost and other factors, including the impact a 
standard will have on further technology development, and therefore 
represents BSER, the EPA must establish an emission standard. In this 
case, for new fossil fuel-fired boiler and IGCC EGUs, the EPA proposes 
to find that the level of partial capture of CO2 that 
qualifies as the BSER supports a standard of 1,100 lb CO2/
MWh on a gross basis. The level of the standard is based on the 
emission reductions that can be achieved by an IGCC with a single-stage 
WGS reactor and a two-stage acid gas removal system. According to the 
DOE/NETL partial capture study, an IGCC with this configuration would 
be expected to achieve a CO2 emission reduction of 25 to 75 
percent, which corresponds to emissions of approximately 1,060 and 380 
lb CO2/MWh-gross, respectively. The EPA is proposing a 
standard of performance of 1,100 lb CO2/MWh-gross, which is 
the high end of this range, for several reasons.
    First, both a new IGCC and a conventional coal-fired boiler (PC or 
CFB), can achieve this emission standard at a reasonable cost and the 
standard is based on technology that has been adequately demonstrated.
    The partial capture requirement and standard of performance will 
allow new IGCC project developers to minimize the need for multi-stage 
water-gas shift reactors (and the associated steam requirement) and 
will allow for the continued use of conventional syngas combustion 
turbines (rather than requiring the use of advanced hydrogen turbines). 
Second, this partial capture configuration will provide operators with 
operational flexibility. Third, this level of the standard best 
promotes further enhancement of the performance of existing technology 
and promotes continued development of new, better performing 
technology. Because the proposed emission standard would require only 
partial implementation of CCS, it will provide developers with the 
opportunity to investigate new emerging technologies that may achieve 
deeper reductions at lower or comparable cost. For instance, developers 
could build plants with the capacity to achieve deeper CO2 
reductions and choose to employ those greater capture rates during non-
peak periods, and then employ lower capture rates (and thus generate 
more electricity) during peak periods.
    While the EPA is proposing an emission rate of 1,100 lb 
CO2/MWh, we are also soliciting comment on whether the 
emission limit may be more appropriately set at a different level. 
Based on the rationale included in this proposal, we are considering a 
range of 1,000 to 1,200 lb CO2/MWh-gross for the final rule. 
An emission rate of 1,200 lb CO2/MWh-gross could potentially 
be met by an IGCC unit that does not include a WGS reactor (although an 
owner/operator might still use a WGS reactor or co-fire natural gas to 
maintain operational flexibility), thus further reducing the capital 
and operating costs. An emission limit of 1,000 lb CO2/MWh-
gross would provide greater emission reductions, could still be 
achieved with a single WGS reactor, and would also advance CCS 
technology but would offer less operational flexibility and increase 
costs.
    We are not currently considering a standard below 1,000 lb 
CO2/MWh. With a standard of 1,000 lb CO2/MWh, an 
owner/operator of an IGCC facility could burn natural gas during 
periods when the gasifier is unavailable while still maintaining an 
annual emissions rate that is below the NSPS. In addition, an owner/
operator could elect to co-fire natural gas as an option to reduce the 
amount of CCS required to comply with the NSPS. With a standard below 
1,000 lb CO2/MWh, those operational flexibilities may not be 
available. We request that commenters who suggest

[[Page 1471]]

emission rates below 1,000 lb CO2/MWh address potential 
concerns about operational flexibility.
    We are not currently considering a standard above 1,200 lb 
CO2/MWh because at that level, the NSPS would not 
necessarily promote the development of CO2 emissions control 
technology or provide significant CO2 reductions. At an 
emissions rate of 1,300 lb CO2/MWh, IGCC facilities would 
only be required to capture approximately 10 percent of the 
CO2, and many designs would have a sufficient compliance 
margin that they would not need to use a WGS reactor. Further, an 
owner/operator of an IGCC facility could comply with this standard 
without the use of any CCS. For example, a new IGCC facility designed 
to co-fire 20 percent natural gas or using fuel cells instead of 
combustion turbines could comply with an emissions rate of 1,300 lb 
CO2/MWh without the use of CCS. An emissions rate of 1,400 
lb CO2/MWh would provide even less technology development 
and emissions reductions. At an emissions rate of 1,400 lb 
CO2/MWh, an IGCC facility could comply with no WGS reactor 
and by (i) capturing less than 5 percent of the CO2, (ii) 
co-firing less ten percent natural gas with no CCS, or (iii) using 
integrated solar thermal for supplemental steam production without CCS. 
In addition, at an emissions rate of 1,400 lb CO2/MWh a PC 
or CFB could use integrated combustion turbines or fuel cells for 
boiler feedwater heating, supplemental steam production, or for 
preheated air for the boiler as an alternative to CCS. We request that 
commenters who suggest emission rates above 1,200 lb CO2/MWh 
address potential concerns about providing adequate reductions and 
technology development to be considered BSER.
    The next several sections review the factors for determining BSER 
and explain why partial capture at the level we are proposing meets 
those requirements, as well as why full capture does not meet some of 
them.

D. Extent of Reductions in CO2 Emissions

    The proposed standard of 1,100 lb CO2/MWh will provide 
meaningful reductions in emissions. As mentioned earlier, the DOE/NETL 
has estimated that a new SCPC boiler using bituminous coal would emit 
1,675 lb CO2/MWh. The DOE/NETL has also estimated that a new 
IGCC unit would emit 1,434 lb CO2/MWh. The emissions would 
be higher for units utilizing subbituminous coal or lignite and will 
vary when utilizing other fossil fuels such as petroleum coke or 
mixtures of fuels. We estimate that this standard will result in 
reduction in emissions of at least 40 percent when compared to the 
expected emissions of a new SCPC boiler.

E. Technical Feasibility

    The EPA proposes to find that partial CCS is feasible because each 
step in the process has been demonstrated to be feasible through an 
extensive literature record, fossil fuel-fired industrial plants 
currently in commercial operation and pilot-scale fossil fuel-fired 
EGUs currently in operation, the progress towards completion of 
construction of fossil fuel-fired EGUs implementing CCS at commercial 
scale. This literature record and experience demonstrate that partial 
CCS is achievable for all types of new boiler and IGCC configurations. 
Although much of this information also serves to demonstrate the 
technical feasibility of full capture, we note that several of the CCS 
projects that are the furthest along are partial capture projects, 
which further supports our view that partial capture is BSER.
1. Literature
    The current status of CCS technology was described and analyzed by 
the 2010 Interagency Task Force on CCS, 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 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 reducing GHG emissions.\187\
---------------------------------------------------------------------------

    \187\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010), page 7.
---------------------------------------------------------------------------

    The Pacific Northwest National Laboratory (PNNL) recently prepared 
a study that evaluated the development status of various CCS 
technologies for the DOE.\188\ The study addressed the availability of 
capture processes, transportation options (CO2 pipelines), 
injection technologies, and measurement, verification and monitoring 
technologies. The study concluded that, in general, CCS is technically 
viable today and that key component technologies of complete CCS 
systems have been deployed at scales large enough to meaningfully 
inform discussions about CCS deployment on large commercial fossil-
fired power plants.
---------------------------------------------------------------------------

    \188\ ``An Assessment of the Commercial Availability of Carbon 
Dioxide Capture and Storage Technologies as of June 2009'', PNNL-
18520, Pacific Northwest National Laboratory, Richland, WA, June 
2009. Available at: https://www.pnl.gov/main/publications/external/technical_reports/PNNL-18520.pdf.
---------------------------------------------------------------------------

    In addition, DOE/NETL has prepared other reports--in particular 
their ``Cost and Performance Baseline'' reports,\189\ including one on 
partial capture \190\--that further support our proposed determination 
of the technical feasibility of partial capture.
---------------------------------------------------------------------------

    \189\ The ``Cost and Performance Baseline'' reports are a series 
of reports by DOE/NETL that establish estimates for the cost and 
performance of combustion- and gasification-based power plants--all 
with and without CO2 capture and storage. Available at 
www.netl.doe.gov/energy-analyses/baseline_studies.html.
    \190\ ``Cost and Performance of PC and IGCC Plants for a Range 
of Carbon Dioxide Capture'', DOE/NETL-2011/1498, May 27, 2011.
---------------------------------------------------------------------------

2. Capture, Transportation and Storage Technologies
    Each of the core components of CCS--CO2 capture, 
compression, transportation and storage--has already been implemented 
and, in fact, in some instances, implemented on a commercial scale. The 
U.S. experience with large-scale CO2 injection, including 
injection at enhanced oil and gas recovery projects, combined with 
ongoing CCS research, development, and demonstration programs in the 
U.S. and throughout the world, provide confidence that the capture, 
transport, compression, and storage of large amounts of CO2 
can be achieved.
a. CO2 Capture Technology
    Capture of CO2 from industrial gas streams has occurred 
since the 1930s, through use of a variety of approaches to separate 
CO2 from other gases. These processes have been used in the 
natural gas industry and to produce food and chemical-grade 
CO2.
    Although current capture technologies are feasible, the costs of 
CO2 capture and compression represent the largest barriers 
to widespread commercialization of CCS. Currently available 
CO2 capture and compression processes are estimated to 
represent 70 to 90 percent of the overall CCS costs.\191\
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    \191\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010).
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    In general, CO2 capture technologies applicable to coal-
fired power generation can be categorized into three approaches: \192\
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    \192\ Id at 29.

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[[Page 1472]]

     Pre-combustion systems that are designed to separate 
CO2 and H2 in the high-pressure syngas produced 
at IGCC power plants.
     Post-combustion systems that are designed to separate 
CO2 from the flue gas produced by fossil-fuel combustion in 
air.
     Oxy-combustion that uses high-purity O2, rather 
than air, to combust coal and thereby produce a highly concentrated 
CO2 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 CO2 capture process uses some of the 
energy (e.g., electricity, steam, heat) produced from the plant.
b. CO2 Transportation
    Carbon dioxide has been transported via pipelines in the U.S. for 
nearly 40 years. Approximately 50 million metric tons of CO2 
are transported each year through 3,600 miles of pipelines. Moreover, a 
review of the 500 largest CO2 point sources in the U.S. 
shows that 95 percent are within 50 miles of a possible geologic 
sequestration site,\193\ which would lower transportation costs. There 
are multiple factors that contribute to the cost of CO2 
transportation via pipelines including but not limited to: availability 
and acquisition of rights-of-way for new pipelines, capital costs, 
operating costs, length and diameter of pipeline, terrain, flow rate of 
CO2, and the number of sources utilizing the pipeline. At 
the same time, studies and DOE quality guidelines have shown 
CO2 pipeline transport costs in the $1 to $4 dollar per ton 
of CO2 range.194 195 196 197 For these reasons, 
the transportation component of CCS is well-established as technically 
feasible and is not a significant component of the cost of CCS.
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    \193\ 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.
    \194\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010).
    \195\ McCollum, D., Ogden, J., 2006. Techno-Economic Models for 
Carbon Dioxide Compression, Transport, and Storage & Correlations 
for Estimating Carbon Dioxide Density and Viscosity. Institute of 
Transportation Studies, University of California, Davis, Davis, CA.
    \196\ McCoy, S., E.S. Rubin and M.B. Berkenpas, 2008. Technical 
Documentation: The Economics of CO2 Transport by Pipeline Storage in 
Saline Aquifers and Oil Reserves. Final Report, Prepared by Carnegie 
Mellon University, Pittsburgh, PA for U.S. Department of Energy, 
National Energy Technology Center, Pittsburgh, PA.
    \197\ DOE/NETL. (2013). Carbon Dioxide Transport and Storage 
Costs in NETL Studies, Quality Guidelines for energy system studies. 
March 2013. DOE/NETL-2013/1614.
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c. CO2 Storage
    (i) Current availability of geologic sequestration
    Existing project and regulatory experience (including EOR), 
research, and analogs (e.g. naturally existing CO2 sinks, 
natural gas storage, and acid gas injection), indicate that geologic 
sequestration is a viable long term CO2 storage option. 
While EPA has confidence that geologic sequestration is technically 
feasible and available, EPA recognizes the need to continue to advance 
the understanding of various aspects of the technology, including, but 
not limited to, site selection and characterization, CO2 
plume tracking, and monitoring. On-going Federal government efforts 
such as DOE/NETL's activities to enhance the commercial development of 
safe, affordable, and broadly deployable CCS technologies in the United 
States, including: Research, development, and demonstration of CCS 
technologies and the assessment of the country's geologic capacity to 
store carbon dioxide, are particularly important.\198\ Furthermore, 
this rule, including the information collected through the GHG 
Reporting Program, will facilitate further deployment of CCS and 
advancements in the technology. Information collected under the GHG 
Reporting Program will provide a transparent means for EPA and the 
public to continue to evaluate the effectiveness of CCS, including 
improvements needed in monitoring technologies.
---------------------------------------------------------------------------

    \198\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010).
---------------------------------------------------------------------------

    The viability of geologic sequestration of CO2 is based 
on a demonstrated understanding of the fate of CO2 in the 
subsurface. Geologic sequestration occurs through a combination of 
structural and stratigraphic trapping (trapping below a low 
permeability confining layer), residual CO2 trapping 
(retention as an immobile phase trapped in the pore spaces of the 
storage formation), solubility trapping (dissolution in the in situ 
formation fluids), mineral trapping (reaction with the minerals in the 
storage formation and confining layer to produce carbonate minerals), 
and preferential adsorption trapping (adsorption onto organic matter in 
coal and shale).199 200 These mechanisms are functions of 
the physical and chemical properties of CO2 and the geologic 
formations into which the CO2 is injected.
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    \199\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage. Retrieved from https://www.ipcc.ch/pdf/special-reports/srccs/srccs_chapter5.pdf.
    \200\ Benson, Sally M. and David R. Cole. (2008). CO2 
Sequestration in Deep Sedimentary Formations. Elements, Vol. 4, pp. 
325-331.
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    Project and research experience continues to add to the confidence 
in geologic sequestration as a viable CO2 reduction 
technology. In addition to the four existing commercial CCS facilities 
in other countries,\201\ multiple studies have been completed that have 
demonstrated geologic sequestration of CO2 as well as have 
improved technologies to monitor and verify that the CO2 
remains sequestered.\202\ For example, CO2 has been injected 
in the SACROC Unit in the Permian basin since 1972 for enhanced oil 
recovery purposes. A study evaluated this project, and estimated that 
about 93 million metric tons of CO2 were injected and about 
38 million metric tons were produced from 1972 to 2005, resulting in a 
geologic CO2 accumulation of 55 million metric tons of 
CO2.\203\ This study evaluated the ongoing and potential 
CO2 trapping occurring through various mechanisms using 
modeling and simulations, and collection and analysis of seismic 
surveys and well logging data. The monitoring at this site demonstrated 
that CO2 can indeed become trapped in geologic formations. 
Studies on the permanence of CO2 storage in geologic 
sequestration have been conducted internationally as well. For example, 
the Gorgon Carbon Dioxide Injection Project and Collie-South West 
CO2 Geosequestration Hub project in Australia have both 
demonstrated geologic CO2 trapping mechanisms.\204\
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    \201\ Sleipner in the North Sea, Sn[oslash]hvit in the Barents 
Sea, In Salah in Algeria, and Weyburn in Canada.
    \202\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010).
    \203\ Han, Weon Shik et al. (2010). Evaluation of trapping 
mechanisms in geologic CO2 sequestration: Case study of 
SACROC northern platform, a 35-year CO2 injection site. 
American Journal of Science Online April 2010 vol. 310 no. 4 282-
324. Retrieved from: https://www.ajsonline.org/content/310/4/282.abstract.
    \204\ Sewell, Margaret, Frank Smith and Dominique Van Gent. 
Western Australia Greenhouse Gas Capture and Storage: A tale of two 
projects. (2012) Australian Department of Resources, Energy and 
Tourism and Western Australia Government of Western Australia. 
Retrieved from https://cdn.globalccsinstitute.com/sites/default/files/publications/39961/ccsinwareport-opt.pdf.
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    Numerous other field studies, for example those conducted by the 
DOE/

[[Page 1473]]

NETL Regional Carbon Sequestration Partnerships, have been completed 
that demonstrate CO2 trapping mechanisms working in geologic 
formations in smaller scale projects. Examples of these DOE/NETL 
studies include: \205\
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    \205\ DOE/NETL. (2012). Best Practices for: Monitoring, 
Verification, and Accounting of CO2 Stored in Deep Geologic 
Formations--2012 Update. DOE/NETL-2012/1568. Retrieved from https://www.netl.doe.gov/technologies/carbon_seq/refshelf/BPM-MVA-2012.pdf.
---------------------------------------------------------------------------

     Midwest Regional Carbon Sequestration Partnership Michigan 
Basin Phase II Validation Test, which injected approximately 60,000 
metric tons of CO2 over two periods from February to March 
2008 (~10,000 metric tons) and from January to July 2009 (~50,000 
metric tons).
     Midwest Geologic Sequestration Consortium Loudon, Mumford 
Hills, and Sugar Creek Phase II Validation Test, which consisted of 
injecting over 14,000 tons of CO2 across three EOR-scale 
field tests.
     Southwest Regional Partnership on Carbon Sequestration 
(SWP) San Juan Basin Phase II Validation Test, which injected 16,700 
metric tons into the coal layers of the Fruitland Formation.
    Geologic storage potential for CO2 is widespread and 
available throughout the U.S. and Canada. Estimates based on DOE 
studies indicate that areas of the U.S. with appropriate geology have a 
storage potential of 2,300 billion to more than 20,000 billion metric 
tons of CO2 in deep saline formations, oil and gas 
reservoirs and un-mineable coal seams.\206\ Other types of geologic 
formations such as organic rich shale and basalt may also have the 
ability to store CO2; and the DOE is currently evaluating 
their potential storage capacity. While these are estimates, each 
potential geologic sequestration site must undergo appropriate site 
characterization to ensure that the site can safely and securely store 
CO2. Estimates of CO2 storage resources by state/
province are compiled by the DOE's National Carbon Sequestration 
Database and Geographic Information System (NATCARB).
---------------------------------------------------------------------------

    \206\ The United States 2012 Carbon Utilization and Storage 
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil 
Energy, National Energy Technology Laboratory (NETL).
---------------------------------------------------------------------------

    Further evidence of the widespread availability CO2 
storage reserves in the U.S. comes from the Department of Interior's 
U.S. Geological Survey (USGS) which has recently completed a 
comprehensive evaluation of the technically accessible storage resource 
for carbon storage for 36 sedimentary basins in the onshore areas and 
State waters of the United States.\207\ The USGS assessment estimates a 
mean of 3,000 billion metric tons of subsurface CO2 storage 
potential across the United States. For comparison, this amount is 500 
times the 2011 annual U.S. energy-related CO2 emissions of 
5.5 Gigatons (Gt).\208\
---------------------------------------------------------------------------

    \207\ U.S. Geological Survey Geologic Carbon Dioxide Storage 
Resources Assessment Team, 2013, National assessment of geologic 
carbon dioxide storage resources--Results: U.S. Geological Survey 
Circular 1386, 41 p., https://pubs.usgs.gov/fs/2013/1386/.
    \208\ U.S. Geological Survey Geologic Carbon Dioxide Storage 
Resources Assessment Team, 2013, National assessment of geologic 
carbon dioxide storage resources--Summary: U.S. Geological Survey 
Factsheet 2013-3020, 6p.https://pubs.usgs.gov/fs/2013/3020/.
---------------------------------------------------------------------------

    Nearly every state in the U.S. has or is in close proximity to 
formations with carbon storage potential including vast areas offshore.
    (ii) Current availability of enhanced oil and gas recovery
    Geologic storage options also include use of CO2 in EOR, 
which is the injection of fluids into a reservoir to increase oil 
production efficiency. EOR is typically conducted at a reservoir after 
production yields have decreased from primary production. Fluids 
commonly used for EOR include brine, fresh water, steam, nitrogen, 
alkali solutions, surfactant solutions, polymer solutions, and 
CO2. EOR using CO2, sometimes referred to as 
`CO2 flooding' or CO2-EOR, involves injecting 
CO2 into an oil reservoir to help mobilize the remaining oil 
and make it available for recovery. The crude oil and CO2 
mixture is produced, and sent to a separator where the crude oil is 
separated from the gaseous hydrocarbons and CO2. The gaseous 
CO2-rich stream then is typically dehydrated, purified to 
remove hydrocarbons, recompressed, and re-injected into the oil or 
natural gas reservoir to further enhance recovery.
    CO2-EOR has been successfully used at many production 
fields throughout the U.S. to increase oil recovery. The oil and 
natural gas industry in the United States has over 40 years of 
experience of injection and monitoring of CO2 in the deep 
subsurface for the purposes of enhancing oil and natural gas 
production. This experience provides a strong foundation for the 
injection and monitoring technologies that will be needed for 
successful deployment of CCS.
    Monitoring CO2 at EOR sites can be an important part of 
the petroleum reservoir management system to ensure the CO2 
is effectively sweeping the oil zone, and can be supplemented by 
techniques designed to detect CO2 leakage. Recently many 
studies have been conducted to better understand the fate of injected 
CO2 at well-established, operational EOR sites. A large 
number of methods are available to monitor surface and subsurface 
leakage at EOR sites. Some recent studies are presented below.
     At the SACROC field in the Permian Basin, the Texas Bureau 
of Economic Geology conducted an extensive groundwater sampling program 
to look for evidence of CO2 leakage in the shallow 
freshwater aquifers. At the time of the study (2011), the SACROC field 
had injected 175 million metric tons of CO2 over 37 years. 
No evidence of leakage was detected.\209\
---------------------------------------------------------------------------

    \209\ K.D. Romanak, R.C. Smyth, C. Yang, S.D. Hovorka, M. 
Rearick, J. Lu. (2011). Sensitivity of groundwater systems to CO2: 
Application of a site-specific analysis of carbonate monitoring 
parameters at the SACROC CO2-enhanced oil field. GCCC Digital 
Publication Series 12-01. Retrieved from https://www.beg.utexas.edu/gccc/forum/codexdownloadpdf.php?ID=190.
---------------------------------------------------------------------------

     An extensive CO2 leakage monitoring program was 
conducted by a third party (International Energy Agency Greenhouse Gas 
Programme) for 10 years at the Weyburn oil field in Saskatchewan, 
during which time over 16 million tonnes of CO2 have been 
stored. A comprehensive analysis of surface and subsurface monitoring 
methods was conducted and resulted in a best practices manual for 
CO2 monitoring at EOR sites.\210\
---------------------------------------------------------------------------

    \210\ Geoscience Publishing. (2012). Best Practices for 
Validating CO2 Geological Storage: Observations and 
Guidance from the IEAGHG Weyburn-Midale CO2 Monitoring 
and Storage Project. Brian Hitchon (Ed.).
---------------------------------------------------------------------------

     The Texas Bureau of Economic Geology has also been testing 
a wide range of surface and subsurface monitoring tools and approaches 
to document storage efficiency and storage permanence at a 
CO2 EOR site in Mississippi.\211\ The Cranfield Field, under 
CO2 flood by Denbury Onshore LLC, is a depleted oil and gas 
reservoir that injected greater than 1.2 million tons/year during the 
tests. The preliminary findings demonstrate the availability and 
effectiveness of many different monitoring techniques for tracking 
CO2 underground and detecting CO2 leakage.
---------------------------------------------------------------------------

    \211\ Hovorka, S.D., et al. (2011). Monitoring a large volume 
CO2 injection: Year two results from SECARB project at 
Denbury's Cranfield, Mississippi, USA: Energy Procedia, v. 4, 
Proceedings of the 10th International Conference on Greenhouse Gas 
Control Technologies GHGT10, September 19-23, 2010, Amsterdam, The 
Netherlands, p. 3478-3485. GCCC Digital Publication 11-16. 
Retrieved from https://www.sciencedirect.com/science/article/pii/S1876610211004711.
---------------------------------------------------------------------------

    The Department of Energy has conducted numerous evaluations of 
CO2

[[Page 1474]]

monitoring techniques at EOR pilot sites throughout the U.S. as part of 
the Regional Sequestration Partnership Phase II and III programs. For 
example, in the Illinois Basin surface and subsurface monitoring 
techniques were tested at three short duration CO2 
injections. At one of the Illinois Basin sites, a landowner became 
concerned when excessive odor in a water well was observed. The ongoing 
groundwater monitoring program results were used to verify the odor was 
from a different origin.\212\
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    \212\ DOE/NETL. (2012). Best Practices for: Monitoring, 
Verification, and Accounting of CO2 Stored in Deep 
Geologic Formations--2012 Update. DOE/NETL-2012/1568. Retrieved from 
https://www.netl.doe.gov/technologies/carbon_seq/refshelf/BPM-MVA-2012.pdf.
---------------------------------------------------------------------------

    The EPA anticipates that many early geologic sequestration projects 
may be sited in active or depleted oil and gas reservoirs because these 
formations have been previously well characterized for hydrocarbon 
recovery, likely already have suitable infrastructure (e.g., wells, 
pipelines, etc.), and have an associated economic benefit of oil 
production. EOR sites including those that inject CO2, are 
typically selected and operated with the intent of oil production; 
however, they may also be suitable for long term containment of 
CO2. Although deep saline formations provide the largest 
CO2 storage opportunity (2,102 to 20,043 billion metric 
tons), oil and gas reservoirs are currently estimated to have 226 
billion metric tons of CO2 storage resource.\213\
---------------------------------------------------------------------------

    \213\ U.S. Department of Energy National Energy Technology 
Laboratory (2012). United States Carbon Utilization and Storage 
Atlas, Fourth Edition.
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    CO2-EOR is the fastest-growing EOR technique in the 
U.S., providing approximately 281,000 barrels of oil per day in the 
U.S. which equals about 6 percent of U.S. crude oil production. The 
vast majority of CO2-EOR is conducted in oil reservoirs in 
the U.S. Permian Basin, which extends through southwest Texas and 
southeast New Mexico. Other U.S. states where CO2-EOR is 
utilized are Alabama, Colorado, Illinois, Kansas, Louisiana, Michigan, 
Mississippi, New Mexico, Oklahoma, Utah, and Wyoming. A well-
established and expanding network of pipeline infrastructure supports 
CO2-EOR in these areas. The CO2 supply for EOR 
operations currently is largely obtained from natural underground 
formations or domes that contain CO2. While natural sources 
of CO2 comprise the majority of CO2 supplied for 
EOR operations, recent developments targeting anthropogenic sources of 
CO2 (e.g., ethanol plants, gas processing plants, 
refineries, power plants) have expanded or led to planned expansions in 
existing infrastructure related to CO2-EOR. Several hundred 
miles of dedicated CO2 pipeline is under construction, 
planned, or proposed that would allow continued growth in 
CO2 supply for EOR.
    Potential sources of CO2 for EOR continue to increase as 
new projects are being planned or implemented. Based on an evaluation 
of publicly available sources, the EPA notes there are currently 
twenty-three industrial source CCS projects in twelve states that are 
either operational, under-construction, or actively being pursued which 
are or will supply captured CO2 for the purposes of 
EOR.\214\ This further demonstrates that CCS projects associated with 
large point sources are occurring due to a demand for CO2 by 
EOR operations. Nationally, approximately 60 million metric tons of 
CO2 were received for injection at EOR operations in 
2012.\215\ A recent study by DOE found that the market for captured 
CO2 emissions from power plants created by economically 
feasible CO2-EOR projects would be sufficient to permanently 
store the CO2 emissions from 93 large (1,000 MW) coal-fired 
power plants operated for 30 years.\216\ Based on all of these factors, 
the EPA anticipates opportunities to utilize CO2-EOR 
operations for geologic storage will continue to increase.
---------------------------------------------------------------------------

    \214\ See ``Documentation for the Summary of Carbon Dioxide 
Industrial Capture to Enhanced Oil Recovery Projects'' (Docket EPA-
HQ-OAR-2013-0495).
    \215\ ``Opportunities for Utilizing Anthropogenic CO2 
for Enhanced Oil Recovery and CO2 Storage'', Michael L. 
Godec, Advanced Resources International, June 11, 2013 presentation 
at the Introduction to CO2 EOR Workshop, https://na2050.org/introduction-to-carbon-dioxide-enhanced-oil-recovery-co2-eor.
    \216\ ``Improving Domestic Energy Security and Lowering 
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery (CO2-EOR)'', DOE/NETL-2011/1504 
(June 20, 2011).
---------------------------------------------------------------------------

    Based on a recent resource assessment by the DOE, the application 
of next generation CO2-EOR technologies would significantly 
increase oil production areas, further expanding the geographic extent 
and accessibility of CO2-EOR operations in the U.S.\217\ 
Additionally, oil and gas fields now considered to be `depleted' may 
resume operation because of increased availability and decreased cost 
of anthropogenic CO2, and developments in EOR technology, 
thereby increasing the demand for and accessibility of CO2 
utilization for EOR.
---------------------------------------------------------------------------

    \217\ Ibid.
---------------------------------------------------------------------------

    The use of CO2 for EOR can significantly lower the net 
cost of implementing CCS. The opportunity to sell the captured 
CO2 for EOR, rather than paying directly for its long-term 
storage, improves the overall economics of the new generating unit. 
According to the International Energy Agency (IEA), of the CCS projects 
under construction or at an advanced stage of planning, 70 percent 
intend to use captured CO2 to improve recovery of oil in 
mature fields.\218\
---------------------------------------------------------------------------

    \218\ Tracking Clean Energy Progress 2013, International Energy 
Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 2013.
---------------------------------------------------------------------------

d. Examples of CCS Demonstration Projects
    The following is a brief summary of some examples of currently 
operating or planned CO2 capture or storage systems, 
including, in some cases, components necessary for coal-fired 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 slip stream of each 
plant's flue gas. At Warrior Run, approximately 110,000 metric tons of 
CO2 per year are captured. At Shady Point 66,000 metric tons 
of CO2 per year are captured. The CO2 from both 
plants is used in the food processing industry.\219\
---------------------------------------------------------------------------

    \219\ 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.
---------------------------------------------------------------------------

    At the Searles Valley Minerals soda ash plant in Trona, CA, 
approximately 270,000 metric tons of CO2 per year are 
captured from the flue gas of a coal-fired power plant via amine 
scrubbing and used for the carbonation of brine in the process of 
producing soda ash.\220\
---------------------------------------------------------------------------

    \220\ IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
---------------------------------------------------------------------------

    A pre-combustion Rectisol[supreg] system is used for CO2 
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 metric tons of CO2 per year from 
the synthesis gas. The CO2 is purified and transported via a 
200-mile pipeline for use in EOR operations in the Weyburn oilfield in 
Saskatchewan, Canada.
    In September 2009, 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 CO2 capture technology on a 20 MWe slip stream of 
the plant's exhaust flue gas. In May 2011, Alstom Power announced the 
successful operation of the chilled-

[[Page 1475]]

ammonia CCS validation project. The demonstration achieved capture 
rates from 75 percent (design value) to as high as 90 percent, and 
produced CO2 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 slip 
stream 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 CO2 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 would terminate its cooperative agreement with the DOE and place its 
plans to advance CO2 capture and storage technology to 
commercial scale on hold, citing the uncertain status of U.S. climate 
policy as a contributor 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 metric tons of CO2 per year. A larger scale project--
the FutureGen 2.0 Project--is in advanced stages of planning in the 
U.S.\221\
---------------------------------------------------------------------------

    \221\ In cooperation with the U.S. Department of Energy (DOE), 
the FutureGen 2.0 project partners will upgrade a power plant in 
Meredosia, IL with oxy-combustion technology to capture 
approximately more than 90 percent of the plant's carbon emissions. 
https://www.futuregenalliance.org/.
---------------------------------------------------------------------------

    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 captures approximately 165,000 metric 
tons of CO2 annually at a CO2 capture rate of 
over 90 percent. The captured CO2 is being permanently 
stored underground in a deep saline geologic formation.
    Southern Company has begun construction of Mississippi Power Kemper 
County Energy Facility. This is a 582 MW IGCC plant that will utilize 
local Mississippi lignite and include pre-combustion carbon capture to 
reduce CO2 emissions by 65 percent. The captured 
CO2 will be used for EOR in the Heidelberg Oil Fields in 
Jasper County, MS. The project is now more than 75 percent complete 
with start-up and operation expected to begin in 2014.
    SaskPower's Boundary Dam CCS Project in Estevan, a city in 
Saskatchewan, Canada, is the world's largest commercial-scale CCS 
project of its kind. The project will fully integrate the rebuilt 110 
MW coal-fired Unit 3 with available CCS technology to capture 
90 percent of its CO2 emissions. The facility is currently 
under construction. Performance testing is expected to commence in late 
2013 and the facility is expected to be fully operational in 2014.
    The Texas Clean Energy Project, a 400 MW IGCC facility located near 
Odessa, Texas will capture 90 percent of its CO2, which is 
approximately 3 million metric tons annually. The captured 
CO2 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. The developer expects financing to be fully 
arranged in 2013.
    There are other CCS projects--domestic and worldwide--that are 
helping to further develop the CCS technology. They are noted in the 
DOE/NETL's Carbon Capture, Utilization, and Storage (CCUS) 
Database.\222\ The database includes active, proposed, canceled, and 
terminated CCUS projects worldwide.
---------------------------------------------------------------------------

    \222\ Available at https://www.netl.doe.gov/technologies/carbon_seq/global/database/.
    Information in the database regarding technologies being 
developed for capture, evaluation of sites for carbon dioxide 
(CO2) storage, estimation of project costs, and 
anticipated dates of completion is sourced from publically available 
information. The CCUS Database provides the public with information 
regarding efforts by various industries, public groups, and 
governments towards development and eventual deployment of CCUS 
technology.
---------------------------------------------------------------------------

F. Costs

    As noted, according to the D.C. Circuit case law, control costs are 
considered acceptable as long as they are reasonable, meaning that they 
can be accommodated by the industry.\223\ To determine reasonableness, 
the Court has looked to the amount of the control costs, whether they 
could be passed on to the consumer, and how much they would lead prices 
to increase. As we discuss below, where EOR opportunities are 
available, the sale of captured CO2 offers the opportunity 
to defray much of the costs. However, we recognize that there are 
places where opportunities to sell captured CO2 for 
utilization in EOR operations may not be presently available. 
Nevertheless, as discussed below, our analysis shows that this cost 
structure--with and without EOR--is consistent with the D.C. Circuit's 
criteria for determining that costs are reasonable.
---------------------------------------------------------------------------

    \223\ In addition, the EPA may consider costs through a national 
lens, as discussed below.
---------------------------------------------------------------------------

    At the outset, it should be noted that even though the costs of 
coal-fired electricity generation--even when not incorporating CCS 
technology--are high when compared to the current costs of new NGCC 
generation, some utilities and other project developers have indicated 
a willingness to proceed with new fossil fuel-fired boilers and IGCC 
units. They have indicated the need for energy and fuel diversity. They 
have also indicated a skepticism regarding long-term projections for 
low natural gas prices and high availability. And there may be other 
reasons why developers have indicated a willingness to build new coal-
fired plants, even if they currently do not appear to be the most 
economic choice.
1. Cost Estimates for Implementation of Partial CCS
    The EPA has examined costs of new fossil fueled power generation 
options. These options are shown in Table 6 below. The costs in Table 6 
are projected for new fossil generation with and without various carbon 
capture options. The costs for new NGCC technology are provided at two 
different natural gas prices: at $6.11/MMBtu, which is reasonably 
consistent with current and projected prices; and at $10/MMBtu, which 
would be well above current and projected natural gas prices. We also 
show projected costs for SCPC and IGCC units with no CCS (i.e., units 
that would not meet the proposed emission standard) and for those units 
with partial capture CCS installed such that their emissions would meet 
the proposed 1,100 lb CO2/MWh standard. We have also 
included costs for those same units when EOR opportunities are 
available. We have included a ``low EOR'' case assuming a low EOR price 
of $20 per ton of CO2, and a ``high EOR'' of $40/ton. These 
EOR prices are net of the costs of transportation, storage, and 
monitoring (TSM). We also show the projected costs for implementation 
of full capture CCS (i.e., 90 percent capture).

[[Page 1476]]



     Table 6--Levelized Cost of Electricity for Fossil Fuel Electric
    Generating Technologies, Excluding Transmission Costs \224\ \225\
------------------------------------------------------------------------
                                                      Levelized cost  of
                     Technology                           electricity
                                                          ($2011/MWh)
------------------------------------------------------------------------
NGCC @ $6.11/MMBtu..................................                  59
NGCC @ $10.0/MMBtu..................................                  86
SCPC w/o CCS \226\..................................                  92
SCPC (1,100 lb/MWh; no EOR).........................                 110
SCPC (1,100 lb/MWh; low EOR)........................                  96
SCPC (1,100 lb/MWh; high EOR).......................                  88
SCPC (full, 90 percent CCS).........................                 147
IGCC w/o CCS........................................                  97
IGCC (1,100 lb/MWh; no EOR).........................                 109
IGCC (1,100 lb/MWh; low EOR)........................                 101
IGCC (1,100 lb/MWh; high EOR).......................                  97
IGCC (full, 90 percent CCS).........................                 136
------------------------------------------------------------------------

    The DOE/NETL reports cite an accuracy range of -15% to +30% for the 
central point estimates shown in Table 6, which are based on a number 
of assumptions, including: an EPCM \227\ contracting methodology, ISO 
ambient conditions, Midwest merit-shop labor costs, and a level 
greenfield site in the United States Midwest with no unusual 
characteristics (e.g., flood plain, seismic zones, environmental 
remediation). For specific sites that differ from this generic 
description, plant costs could differ from the quoted range. We have 
presented that central estimate above. Also note that the 2010 DOE/NETL 
capital and operating costs and coal price were updated to 2011 dollars 
using the values from the 2012 DOE/NETL report. The value of the DOE/
NETL studies lies not in the absolute accuracy of the individual case 
results but in the fact that all cases were evaluated under the same 
set of technical and economic assumptions. This consistency of approach 
allows meaningful comparisons among the cases evaluated.
---------------------------------------------------------------------------

    \224\ These costs are derived from the following DOE/NETL 
studies: (1) Cost and Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev 2, 
DOE/NETL-2010/1397 (Nov 2010); (2) Updated Costs (June 2011 Basis) 
for Selected Bituminous Baseline Cases'' DOE/NETL-341/082312 (Aug 
2012); (3) Cost and Performance of PC and IGCC Plants for a Range of 
Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011). Capacity 
factor are assumed at 85 percent.
    \225\ These costs do not include the impact of subsidies that 
may potentially be available to developers of new projects that 
include CCS.
    \226\ SCPC LCOE includes a 3 percent increase to the weighted 
average cost of capital to reflect EIA's climate uncertainty adder 
(CUA).
    \227\ Engineering, Procurement, and Construction Management.
---------------------------------------------------------------------------

    For an emerging technology like CCS, costs can be estimated for a 
``first-of-a-kind'' (FOAK) plant or an ``nth-of-a-kind'' (NOAK) plant, 
the latter of which has lower costs due to the ``learning by doing'' 
and risk reduction benefits that result from serial deployments as well 
as from continuing research, development and demonstration 
projects.\228\ The estimates provided in Table 6 for a new NGCC unit 
and for a SCPC plant without CO2 capture are based on mature 
technologies and are thus NOAK costs. For plants that utilize 
technologies that are not yet fully mature and/or which have not yet 
been serially deployed in a commercial context, such as IGCC or any 
plant that includes CO2 capture, the cost estimates in Table 
6 represent a plant that is somewhere between FOAK and NOAK, sometimes 
referred to as ``next-of-a-kind'', or ``next commercial offering''. 
These cost estimates for next commercial offerings do not include the 
unique cost premiums associated with FOAK plants that must demonstrate 
emerging technologies and iteratively improve upon initial plant 
designs. However, these costs do utilize currently available cost bases 
for emerging technologies with associated process contingencies applied 
at the appropriate subsystem levels. It should also be noted that 
successful RD&D can lead to improved performance and lower costs.
---------------------------------------------------------------------------

    \228\ Elsewhere in this preamble, we describe the evidence that 
as technology matures, its costs decrease. Note also that EPA 
regulations of mobile source air emissions incorporate the 
decreasing costs of technology over time. See, e.g., ``2017 and 
Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and 
Corporate Average Fuel Economy Standards--Final Rule,'' 77 Fed. Reg. 
62624, 62984/1 to 62985/1 (October 15, 2012) (incorporating ``cost 
reductions, due to learning effects'').
---------------------------------------------------------------------------

    Because there are a number of projects currently under development, 
the EPA believes it is reasonable to focus on the next-of-a-kind costs 
provided in Table 6. The lessons learned from design, construction and 
operation of those projects, as well as for that of Duke Energy's 
Edwardsport IGCC (which does not include CCS) will help lower costs for 
future gasification facilities implementing CCS. The TCEP project and 
the HECA project are both in advanced stages of design and development. 
Summit Power, the developer of TCEP, is also pursuing a number of 
additional projects that would benefit from lessons learned from TCEP. 
These include the Captain Clean Energy Project in the United Kingdom 
(UK) and another poly-generation project in Texas.\229\ For a new 
conventional PC plant implementing post-combustion CCS, the Boundary 
Dam project will perhaps represent a FOAK project while the W.A. Parish 
project may represent a second-of-a-kind project--or perhaps even a 
next-of-a-kind project.
---------------------------------------------------------------------------

    \229\ https://ghgnews.com/index.cfm/summit-even-without-uk-demo-funding-project-will-move-forward/?mobileFormat=true.
---------------------------------------------------------------------------

    Further, as discussed elsewhere in this preamble, many of the 
individual components of a new generation project with CCS have been 
previously demonstrated. For example, capturing CO2 from a 
coal gasification syngas stream has been occurring for more than ten 
years at the Dakota Gasification facility. Experience gained at that 
facility can inform design and operational choices of a new IGCC 
implementing partial CCS.
    For all these reasons, the next IGCC and SCPC facilities with CCS 
can be expected to be less expensive than the current FOAK projects, 
but more expensive than the NOAK facilities with CCS that construct 
when CCS has become a fully mature technology. The costs in Table 6 
reflect those next-of-a-kind costs.
    The EPA has also examined costs of new non-fossil fueled power 
generation options. These options are shown in Table 7 below.

[[Page 1477]]



   Table 7--Range of Levelized Cost of Electricity for Non-Fossil Fuel
  Electric Generating Technologies, Excluding Transmission Costs \230\
                                  \231\
------------------------------------------------------------------------
                                                      Levelized cost of
                    Technology                      electricity  ($2011/
                                                            MWh)
------------------------------------------------------------------------
Nuclear...........................................               103-114
Biomass...........................................                97-130
Geothermal........................................                 80-99
Combustion Turbine................................                87-116
Onshore Wind......................................                 70-97
Offshore Wind.....................................               177-289
Solar PV \232\....................................               109-220
Solar Thermal.....................................               184-412
Nuclear...........................................               103-114
Biomass...........................................                97-130
Geothermal........................................                 80-99
------------------------------------------------------------------------

    It is important to note here that both the EIA and the EPA apply a 
climate uncertainty adder (CUA)--represented by a three percent 
increase to the weighted average cost of capital--to certain coal-fired 
capacity types. The EIA developed the CUA to address the disconnect 
between power sector modeling absent GHG regulation and the widespread 
use of a cost of CO2 emissions in power sector resource 
planning.
---------------------------------------------------------------------------

    \230\ Data for non-fossil fuel-fired generation comes from DOE 
Energy Information Administration (EIA) Annual Energy Outlook (AEO) 
2013. Levelized Cost of Electricity (LCOE) estimates come from 
https://www.eia.gov/forecasts/aeo/electricity_generation.cfm. To 
maintain consistency with DOE/NETL estimates in Table 6, the EIA 
estimates provided in this table do not include transmission 
investment.
    \231\ The LCOE estimates in Table 7 are presented as a range 
that reflects EIA's view on the regional variation in local labor 
markets, cost and availability of fuel, and renewable resources. The 
capacity factor ranges for renewable non-dispatchable technologies 
are as follows: Wind--30 to 39 percent, Wind Offshore--33 to 42 
percent, Solar PV--22 to 32 percent, and Solar Thermal--11 to 26 
percent. Capacity factors for dispatchable non-fossil fueled 
technologies are as follows: Nuclear--90 percent, Biomass--83 
percent, and Geothermal--92 percent. There is no capacity credit 
provided to dispatchable resources.
    \232\ Costs are expressed in terms of net AC power available to 
the grid for the installed capacity.
---------------------------------------------------------------------------

    The CUA reflects the additional planning cost typically assigned by 
project developers and utilities to GHG-intensive projects in a context 
of climate uncertainty. The EPA believes the CUA is consistent with the 
industry's planning and evaluation framework (demonstrable through IRPs 
and PUC orders) and is therefore necessary to adopt in evaluating the 
cost competitiveness of alternative generating technologies.
    EPA believes the CUA is relevant in considering the range of costs 
that power companies are willing to pay for generation alternatives to 
natural gas. To the extent that a handful of project developers are 
still considering coal without CCS, EPA believes, based both on the 
analysis the EIA undertook in developing the CUA approach and the EPA's 
review of IRPs,\233\ they must fall into one of two classes. The first, 
which is the minority, is not factoring in any form of a CUA. The 
second, which is the majority, assume that coal-fired power plants 
without CCS entail additional costs due to the risk of future 
regulation of CO2. Factoring in risk associated with 
CO2 suggests that these companies are, in fact, willing to 
pay the higher cost for coal without CCS (even if they are not actually 
incurring those costs today). For these reasons, EPA believes that it 
is appropriate to consider the cost of coal without CCS to include the 
CUA in the range of costs that utilities are willing to pay for 
alternatives to natural gas.
---------------------------------------------------------------------------

    \233\ See Technical Support Document: ``Review of Electric 
Utility Integrated Resource Plans'' (Docket EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------

    The EPA is requesting comment on all aspects of the CUA, including 
its magnitude and technology-specific application, to ensure that the 
EPA's supporting analysis best reflects the current standards and 
practices of the power sector's long-term planning process.
2. Comparison With the Costs of Other New Power Generation Options
    As Tables 6 and 7 above show, while new coal-fired generation that 
includes CCS is more expensive than either new coal-fired generation 
without CCS or new NGCC generation, it is competitive with new nuclear 
power, which, besides natural gas combustion turbines, is the principal 
other option often considered for providing new base load power. It is 
also competitive with biomass-fired generation, which is another 
generation technology often considered for base load power.\234\ A 
review of utility IRPs shows that a number of companies are considering 
new nuclear power as an option for new base load generation capacity in 
lieu of new coal-fired generation with or without CCS, because, 
according to the IRPs, nuclear power is a cost-effective way to 
generate base load electricity that addresses risks associated with 
potential future carbon liabilities. New fossil fuel-fired generation 
that includes CCS serves the same basic function as new nuclear power: 
providing base load power with a lower carbon footprint. New coal-fired 
generation that incorporates partial CCS that is sufficient to meet the 
CO2 emission limitation that we are proposing in today's 
action (1,100 lb CO2/MWh) would have a similar levelized 
cost of electricity (LCOE) as a new nuclear power plant (about $103/
MWh-$114/MWh). This indicates that, at the proposed emission limitation 
of 1,100 lb CO2/MWh, the cost of new coal-fired generation 
that includes CCS is reasonable today.
---------------------------------------------------------------------------

    \234\ Although geothermal energy is also generally considered 
for base load power, it is limited in availability. The other low-
GHG emitting generation listed in Table 4--solar and wind--are not 
used for base load.
---------------------------------------------------------------------------

3. Costs of ``Full Capture'' CCS
    As noted in Table 6, above, and discussed in the RIA \235\ for this 
rulemaking, implementation of CCS to achieve 90 percent CO2 
capture adds considerably to the LCOE from a new SCPC or IGCC unit. The 
LCOE for a new SCPC and a new IGCC, both without CCS, are estimated to 
be $92/MWh and $97/MWh, respectively. The corresponding costs with 
implementation of ``full capture'' CCS are $147/MWh for the new SCPC 
unit and $136/MWh for the new IGCC unit. These costs exceed what 
project developers have been willing to pay for other low GHG-emitting 
base load generating technologies (e.g., nuclear) that also provide 
energy diversity. For that reason alone, we do not believe that the 
costs of full implementation of CCS are reasonable at this time.
---------------------------------------------------------------------------

    \235\ Regulatory Impact Analysis for the Standards of 
Performance for Greenhouse Gas Emissions for New Fossil Fuel-Fired 
Electric Utility Steam Generating Units and Stationary Combustion 
Turbines (available in the rulemaking docket EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------

4. Reasonableness of Costs of Partial CCS
    As noted, the current costs of coal, natural gas, and construction 
of coal-fired or natural gas-fired EGUs have led to little currently 
announced or projected new coal-fired generating capacity. This very 
likely reflects the large price differential between the cost of a new 
NGCC (cost of electricity: $59/MWh at a natural gas price of $6.11/
MMBtu) and SCPC without CCS (cost of electricity: $92/MWh) and IGCC 
without CCS (cost of electricity: $97/MWh), coupled with a leveling of 
demand for electricity and the recent increase in renewable sources.
    We observe that most of the industry appears to take the view that 
the price of natural gas will remain sufficiently low for at least a 
long enough period into the future that new natural-gas fired 
electricity generation will be less expensive than new coal-fired 
generation. As a result, in most cases, customers or utilities that 
contract for

[[Page 1478]]

new generation are doing so for natural gas-fired generation. Long-term 
contracts for electricity supply are commonly for a 25-year period; 
thus, most of the industry appears to consider contracting for new 
natural gas-fired generation for a 25-year period to be the most 
economical of their choices.
    As shown in Table 6, we estimate that a new SCPC plant costs $92/
MWh, which is $33/MWh, or about 56 percent higher than the new NGCC 
cost of $59/MWh. Limiting the emission rate to 1,100 lb CO2/
MWh (which can be achieved by adding partial CCS), without sale of 
captured CO2 for EOR, would add another $18/MWh to the cost 
of electricity, for a total of $110/MWh. Thus, the total additional 
cost to meet the proposed standard by implementing partial capture CCS 
(without revenues from CO2 sales for EOR) is about half the 
additional cost of coal-fired generation, compared to natural-gas fired 
generation.
    We are aware of another segment of the industry, which includes 
electricity suppliers who have indicated a preference for new coal-
fired generation to establish or maintain fuel diversity in their 
generation portfolio because their customers have expressed a 
willingness to pay a premium for that diversity. It appears these 
utilities and project developers see lower risks to long-term reliance 
on coal-fired generation and greater risks to long-term reliance on 
natural gas-fired generation, compared to the rest of the industry.
    We consider the costs of CCS to be reasonable for this segment of 
the industry as well. The additional costs of CCS for new SCPC of $18/
MWh LCOE ($110/MWh for SCPC with partial CCS compared to $92/MWh for 
SCPC without CCS) are only about half as much as the additional costs 
that are already needed to be incurred to develop coal-fired 
electricity as compared to new NGCC generation ($92/MWh for SCPC 
without CCS compared to $59 MWh for NGCC at a natural gas price of 
$6.11/MMBtu). Moreover, it is possible that under these circumstances, 
the demand for the electricity would be inelastic with respect to the 
price because it may not depend on cost as much as on a demand for 
energy diversity. These circumstances would be similar to the Portland 
Cement (1975) case, discussed above, in which the D.C. Circuit upheld 
NSPS controls that increased capital and operating costs by a 
substantial percentage because the demand for the goods was inelastic 
with respect to price, so that the industry could pass along the 
costs.\236\
---------------------------------------------------------------------------

    \236\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
---------------------------------------------------------------------------

    In addition, we consider the costs of partial CCS to be reasonable 
because a segment of the industry is already accommodating them. As 
noted, a segment of the industry consists of the several coal-fired EGU 
projects that already incorporate at least partial CCS. These projects, 
which are each progressing, include Kemper, TCEP, and HECA. Each is an 
IGCC plant that expects to generate profits from the sale of products 
that result from coal gasification, in addition to the sale of 
electricity. It is true that each of these projects has received DOE 
grants to encourage the development of CCS technology, but we do not 
consider such government subsidies to mean that the costs of CCS would 
otherwise be unreasonable. As we noted in the original proposal for 
this rulemaking,\237\ many types of electricity generation receive 
government subsidies. For example, nuclear power is the beneficiary of 
the Price-Anderson Act, which partially indemnifies nuclear power 
plants against liability claims arising from nuclear incidents,\238\ 
and domestic oil and gas production,\239\ coal exploration and 
development,\240\ and renewable energy generation \241\ are each the 
beneficiary of Federal tax incentives.
---------------------------------------------------------------------------

    \237\ 77 FR 22418/3.
    \238\ See Duke Power Co. v. Carolina Environmental Study Group, 
438 U.S. 59 (1978).
    \239\ See Internal Revenue Code section 263.
    \240\ See ``General Explanations of the Administration's Fiscal 
Year 2013 Revenue Proposals,'' pp. 120-24. https://www.treasury.gov/resource-center/tax-policy/Documents/General-Explanations-FY2013.pdf.
    \241\ See Internal Revenue Code section 45.
---------------------------------------------------------------------------

5. Opportunities to Further Reduce the Costs of Partial CCS
a. Enhanced Oil Recovery
    While the reasons noted above are sufficient to justify the 
reasonableness of the costs of partial CCS, in most cases, we believe 
that the actual costs will be less. One reason is the availability of 
EOR. As noted, EOR is being actively used in various counties in the 
U.S., and CO2 pipelines extend into those counties from, in 
some cases, hundreds of miles away. We consider areas in close 
proximity to active EOR locations, including the pipelines that extend 
into those locations, to be places where EOR is available.
    We recognize that, at present, certain locations are far enough 
away from either oilfields with EOR availability or pipelines to those 
oil fields that any coal-fired power plants that build in those 
locations would incur costs to build pipeline extensions that may 
render EOR non-economical. Those locations are relatively limited when 
legal or practical limits on building coal-fired power plants are taken 
into account. For example, some states with locations that are not 
located near EOR availability are not expected to have new coal-fired 
builds without CCS in any event, for legal or practical reasons. A 
number of States, at least in the short term, already have high reserve 
margins and/or have large renewable targets which push new decisions 
towards renewables and quick starting natural gas to provide backup to 
renewables over coal-fired generation.
    In addition, it is important to note that coal-fired power plants 
that build in any particular location may serve demand in a wide area. 
There are many examples where coal-fired power generated in one state 
is used to supply electricity in other states. For instance, 
historically, nearly 40 percent of the power for the City of Los 
Angeles was provided from two coal-fired power plants located in 
Arizona and Utah. In another example, Idaho Power, which serves 
customers in Idaho and Eastern Oregon, meets its demand in part from 
coal-fired power plants located in Wyoming and Nevada.
    As a result, the geographic scope of areas in which EOR is 
available to defray the costs of CCS should be considered to be large. 
The costs provided in Table 6 show how the ability to sell 
CO2 for utilization in EOR can significantly affect the 
overall costs of the project.
    We also considered how the opportunity to sell captured 
CO2 for EOR may affect the costs for new units implementing 
full capture CCS. We previously indicated that the costs--$147/MWh for 
the new SCPC unit and $136/MWh for the new IGCC unit--are not 
reasonable and we rejected that option as BSER on that basis. We 
estimated that the SCPC with full capture LCOE could be reduced to 
between $93 and $115/MWh (depending on selling price of the 
CO2) and the IGCC with full capture could be reduced between 
$91 and $109/MWh (again, depending upon the selling price of the 
CO2). These costs are similar with the reasonable costs for 
partial capture similar units with no opportunity to sell captured 
CO2 for EOR. This indicates that in some cases (Summit's 
TCEP, for example), developers may determine that a new unit with full 
capture is economically viable. However, this factor alone does not 
lead us to conclude that full capture CCS should be BSER. When 
considered in

[[Page 1479]]

conjunction with other factors, such as the cost of full CCS where EOR 
is not available and the fact that more projects using partial CCS than 
full CCS are underway, the EPA believes that partial CCS should be 
considered BSER.
b. Government Subsidies
    In some instances, the costs of CCS can be defrayed by grants or 
other benefits provided by the DOE or the states. Although, for the 
reasons noted earlier, we consider the current costs of partial-capture 
CCS even without subsidization to be reasonable, the availability of 
these governmental subsidies supports the reasonableness of the costs.
    The 2010 Interagency Task Force Report on CCS report described the 
DOE program as follows:

    The DOE is currently pursuing multiple demonstration projects 
using $3.4 billion of available budgetary resources from the 
American Recovery and Reinvestment Act in addition to prior year 
appropriations. Up to ten integrated CCS demonstration projects 
supported by DOE are intended to begin operation by 2016 in the 
United States. These demonstrations will integrate current CCS 
technologies with commercial-scale power and industrial plants to 
prove that they can be permitted and operated safely and reliably. 
New power plant applications will focus on integrating pre-
combustion CO2 capture, transport, and storage with IGCC 
technology. Power plant retrofit and industrial applications will 
demonstrate integrated post-combustion capture.\242\
---------------------------------------------------------------------------

    \242\ Task Force Report on CCS, p. 76

    DOE allocated some $3.4 billion for 5-10 projects, and has 
committed $2.2 billion for 5 projects to date. In addition, various 
other federal and state incentives are also available to many projects. 
The 2010 Interagency Task Force on CCS, in surveying all of the federal 
and state benefits available, concluded that the DOE grants, ``plus . . 
. federal loan guarantees, tax incentives, and state-level drivers, 
cover a large group of potential CCS options.'' \243\
---------------------------------------------------------------------------

    \243\ Task Force Report on CCS, p. 76
---------------------------------------------------------------------------

    In addition, regulatory programs may serve to defray the costs of 
CCS, including, for example, Clean Energy Standards or guaranteed 
electricity purchase price agreements.\244\
---------------------------------------------------------------------------

    \244\ See Center for Climate and Energy Solutions, ``Financial 
Incentives for CCS''--available at https://www.c2es.org/.
---------------------------------------------------------------------------

    As noted above and in the April 2012 proposal, the need for 
subsidies to support emerging energy systems and new control 
technologies is not unusual. Each of the major types of energy used to 
generate electricity has been or is currently being 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 for fossil fuel-fired; as well as nuclear-, geothermal-, wind-, 
and solar-generated electricity.\245\
---------------------------------------------------------------------------

    \245\ 77 FR 22418/3.
---------------------------------------------------------------------------

c. Expected Reductions in the Costs of CCS
    The EPA reasonably projects that the costs of CCS will decrease 
over time as the technology becomes more widely used. Although, for the 
reasons noted earlier, we consider the current costs of CCS to be 
reasonable, the projected decrease in those costs further supports 
their reasonableness. The D.C. Circuit case law that authorizes 
determining the ``best'' available technology on the basis of 
reasonable future projections supports taking into account projected 
cost reductions as a way to support the reasonableness of the costs.
    As noted above, the D.C. Circuit, in the 1973 Portland Cement Ass'n 
v. Ruckelshaus case, stated that the EPA, in identifying the ``best 
system of emission reduction . . . adequately demonstrated,'' may 
``look[ ] toward what may fairly be projected for the regulated future, 
rather than the state of the art at present. . . .'' \246\ In the 1999 
Lignite Energy Council v. EPA case, the Court elaborated:
---------------------------------------------------------------------------

    \246\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973), quoted in Lignite Energy Council v. EPA, 198 F.3d 
930, 933-34 (D.C. Cir. 1999).

    Of course, where data are unavailable, EPA may not base its 
determination that a technology is adequately demonstrated or that a 
standard is achievable on mere speculation or conjecture . . . but 
EPA may compensate for a shortage of data through the use of other 
qualitative methods, including the reasonable extrapolation of a 
technology's performance in other industries.\247\
---------------------------------------------------------------------------

    \247\ Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. 
Cir. 1999). Based on this view that EPA may extrapolate from other 
industries, the Court in the Lignite Energy Council v. EPA case 
upheld a control technology as being ``adequately demonstrated'' for 
coal-fired industrial boilers because the technology was utilized by 
utility boilers.

It is logical to read these statements in the D.C. Circuit case law to 
apply as well to the cost component of the ``best system of emission 
---------------------------------------------------------------------------
reduction . . . adequately demonstrated.''

    We expect the costs of CCS technologies to decrease for several 
reasons. We expect that significant additional knowledge will be gained 
from deployment and operation of at least two new coal-fired generation 
projects that include CCS. These projects are the Southern Company's 
Kemper County Energy Facility IGCC with CCS and the Boundary Dam CCS 
project on a conventional coal-fired power plant in Canada. They are 
currently under construction and are expected to commence operation 
next year. In addition there are several other CCS projects in advanced 
stages of development in the U.S. (e.g., the Texas Clean Energy 
Project, the Hydrogen Energy California Project, and the Future Gen 
project in Illinois) that may also provide additional information. In 
addition, research is underway to reduce CO2 capture costs 
and to improve performance. The DOE/NETL sponsors an extensive 
research, development and demonstration program that is focused on 
developing advanced technology options designed to dramatically lower 
the cost of capturing CO2 from fossil-fuel energy plants 
compared to today's available capture technologies. The DOE/NETL 
estimates that using today's available CCS technologies would add 
significantly to the cost of electricity for a new pulverized coal 
plant, and the cost of electricity for a new advanced gasification-
based plant would be increased by approximately half of the increase at 
a comparable PC facility. (Note that these cost increases would be less 
for the partial capture standard being proposed in today's document.) 
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.\248\ The large-scale CO2 capture 
demonstrations that are currently planned and in some cases underway, 
under the DOE's initiatives, as well as other domestic and 
international projects, will generate operational knowledge and enable 
continued commercialization and deployment of these technologies.
---------------------------------------------------------------------------

    \248\ 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 CO2 from other gases have been in use since the 
1930s in the natural gas industry and to produce food and chemical 
grade CO2. The advancement of amine-based solvents is an 
example of technology development that has improved the cost and 
performance of CO2 capture. Most single component amine 
systems are not practical in a flue

[[Page 1480]]

gas environment as the amine will rapidly degrade in the presence of 
oxygen and other contaminants. The Fluor Econamine FG\SM\ process uses 
a monoethanolamine (MEA) formulation specially designed to recover 
CO2 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 CO2 capture performance and reduce costs.
    Significant reductions in the cost of CO2 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,\249\ 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, reductions in financial premiums related 
to risk, research and development investments, and other factors have 
been observed over the decades.
---------------------------------------------------------------------------

    \249\ These studies include: John M. Dutton and Annie Thomas, 
``Treating Progress Functions as a Managerial Opportunity,'' Academy 
of Management review, 1984, vol. 9, No. 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).
---------------------------------------------------------------------------

    In addition, we note that the 2010 Interagency Task Force on CCS 
report recognized that CCS would not become more widely available 
without a regulatory framework that promoted CCS or a strong price 
signal for CO2. Today's action is an important component in 
developing that framework.

G. Promotion of Technology

    It is clear that identifying partial CCS as the BSER promotes the 
utilization of CCS because any new fossil fuel-fired utility boiler or 
IGCC unit will need to install partial capture CCS in order to meet the 
emission standard. Particularly because the technology is relatively 
new, additional utilization is expected to result in improvements in 
the performance technology and in cost reductions. Moreover, 
identifying partial capture CCS as the BSER will encourage continued 
research and development efforts, such as those sponsored by the DOE/
NETL. In contrast, not identifying partial CCS as the BSER could 
potentially impede further utilization and development of CCS. It is 
important to promote deployment and further development of CCS 
technologies because they are the only technologies that are currently 
available or are expected to be available in the foreseeable future 
that can make meaningful reductions in CO2 emissions from 
fossil fuel-fired utility boilers and IGCC units.
    Identifying partial CCS as the BSER also promotes further use of 
EOR because, as a practical matter, we expect that new fossil fuel-
fired EGUs that install CCS will generally make the captured 
CO2 available for use in EOR operations. The use of EOR 
lowers costs for production of domestic oil, which promotes the 
important goal of energy independence.

H. Nationwide, Longer-Term Perspective

    As noted, the D.C. Circuit in Sierra Club held:

The language of [the definition of ``standard of performance'' in] 
section 111 . . . gives EPA authority when determining the best . . 
. system to weigh cost, energy, and environmental impacts in the 
broadest sense at the national and regional levels and over time as 
opposed to simply at the plant level in the immediate present.\250\
---------------------------------------------------------------------------

    \250\ Sierra Club v. Costle, 657 F.2d at 330.

    Considering on ``the national and regional levels and over time'' 
the criteria that go into determining the ``best system of emission 
reduction . . . adequately demonstrated'' also supports identifying 
partial CCS as that best system because doing so would not have adverse 
impacts on the power sector, national electricity prices, or the energy 
sector.
1. Structure of the Power Sector
    Identifying partial CCS as the BSER for new fossil fuel-fired 
utility boilers and IGCC units is consistent with the current and 
projected future structure of the power sector. As noted, we project 
that in light of the current and projected trends in coal and natural 
gas costs, virtually all new electric generating capacity will employ 
NGCC technology or renewable energy, and very little new capacity will 
be coal-fired.
    As noted above, the recent history of solid fossil fuel-fired 
projects suggest that these new coal-fired builds, if they occur, may 
(i) consist of an IGCC unit, including features such as sale of 
additional byproducts (e.g., plants such as the Texas Clean Energy 
Project, which intends to manufacture fertilizer products for sale and 
sell captured CO2 for EOR in addition to selling 
electricity), use of lower cost opportunity fuels (such as petcoke 
proposed to be used at the Hydrogen Energy California facility) and/or 
rely on additional local regulatory drivers (such as California's AB-32 
program which incentivizes lower CO2 generating 
technologies), all of which would be designed to offset enough of the 
additional coal-related costs to be able to compete with natural-gas 
fired electricity in the marketplace; and (ii) be designed to offer 
fuel diversity to a group of customers that are willing to pay a 
premium in electricity prices (such as the Power4Georgians project in 
Washington County, Georgia).
    Projects in the first category would by definition already include 
at least partial CCS and, as a result, would be affected by this rule 
to only a limited extent. Projects in the second category would be more 
affected, but developers of these projects would nevertheless have 
several options. They could pursue coal with CCS and possibly rely on 
cost savings from EOR or on their customers' willingness to pay a 
higher premium. Alternatively, they could choose a different generation 
technology (most likely natural gas). Even if they chose a different 
generation technology, the small number of these sources and the fact 
that the basic demand for electricity would still be met would limit 
the impact of this rule on the power sector.
2. Impacts on Nationwide Electricity Prices
    Identifying partial CCS as the BSER for fossil fuel-fired utility 
boilers and IGCC units will not have significant impacts on nationwide 
electricity prices. The reason is that the additional costs of partial 
CCS will, on a nationwide basis, be small because no more than a few 
new coal-fired projects are expected, and because, as noted, at least 
some of these can be expected to incorporate CCS technology in any 
event. It should be noted that the computerized model the EPA relies on 
to assess energy sector and nationwide impacts--the Integrated Planing 
Model (IPM)--does not forecast any new coal-fired EGUs through 2020. 
Based on these IPM analyses, the RIA for this

[[Page 1481]]

rulemaking concludes that the proposed standard of 1,100 lb of 
CO2/MWh for new fossil fuel-fired EGUs, which is based on 
partial CCS as the best demonstrated system, does not create any costs.
3. Energy Considerations
    Identifying partial CCS as the BSER for new fossil fuel-fired 
utility boilers and IGCC units is consistent with nationwide energy 
considerations because it will not have adverse effects on the 
structure of the power sector, will promote fuel diversity over the 
long term, and will not have adverse effects on the supply of 
electricity.
    Identifying partial CCS as the BSER will not have adverse impacts 
on the structure of the power sector because, as noted, for reasons 
related to the cost differential between natural gas-fired and coal-
fired electricity, very little, if any, new coal-fired EGUs are 
projected to be built, and at least some of those that may be built 
would be expected to include CCS technology in any event.
    In addition, identifying partial CCS as the BSER for coal will be 
beneficial to coal-fired electric generation, and therefore fuel 
diversity, over the long term. This is because identifying partial CCS 
as BSER eliminates uncertainty as to future control obligations for 
coal-fired capacity. Currently, any new coal-fired source that 
constructs without CCS faces the risk that future state or federal 
controls may require carbon capture, which would require the source to 
retrofit to CCS, which, in turn, is a more expensive proposition. This 
risk is heightened because power plants have expected lives of 30 to 40 
years and the likelihood of future carbon limitations can be expected 
to remain throughout that period. Any new coal-fired source that 
constructs with partial-capture CCS will achieve some level of 
CO2 emissions reductions, which lowers the risk of future 
liability, and may provide competitive advantages over higher emitting 
sources. Because at present, new electric generating construction is 
primarily natural gas-fired, benefiting new coal-fired capacity, at 
least over the long term, protects fuel diversity.
    Moreover, even if requiring CCS adds sufficient costs to prevent a 
new coal-fired plant from constructing in a particular part of the 
country due to lack of available EOR to defray the costs, or, in fact, 
from constructing at all, a new NGCC plant can be built to serve the 
electricity demand that the coal-fired plant would otherwise serve. 
Thus, the present rulemaking does not prevent basic electricity demand 
from being met, and thus does not have an adverse effect on the supply 
of electricity. As noted above, the EPA is authorized to promulgate 
standards of performance under CAA section 111 that may have the effect 
of precluding construction of sources in certain geographic locations.
4. Environmental Considerations
    Identifying partial CCS as the BSER for coal-fired power plants 
protects the environment by preventing large amounts of CO2 
emissions from new fossil fuel-fired utility boilers and IGCC units. As 
noted, CCS is the only technology available at present or within the 
foreseeable future that provides meaningful reductions in the amount of 
CO2 emissions in this sector.

I. Deference

    As noted above, the D.C. Circuit has held that it will grant a high 
degree of deference to the EPA in determining the appropriate standard 
of performance. Because determining the BSER for coal-fired power 
plants requires balancing several factors, including on a nationwide 
basis and over time, the EPA's determination that partial CCS is the 
BSER should be granted a high degree of deference.

J. CCS and BSER in Locations Where Costs Are Too High To Implement CCS

    As noted above, under CAA section 111, an emissions standard may 
meet the requirements of a ``standard of performance'' even if it 
cannot be met by every new source in the source category that would 
have constructed in the absence of that standard. As also noted above, 
the EPA's analysis for this proposal indicates that coal-fired power 
plants that would otherwise construct in the absence of the standards 
in this proposal may still do so.
    However, we recognize that there may be some geographic locations 
where EOR is not practicably available, so that in those locations, the 
higher costs of CCS may tilt the economics against new coal-fired 
construction. Even in this case, the standard would remain valid under 
CAA section 111, particularly because the basic demand for electricity 
could still be served by NGCC, which this rulemaking determines to be 
the ``best system'' for natural gas-fired power plants.

K. Compliance Period

1. 12-Operating-Month Period
    Under today's proposal, sources must meet the 1,100 lb 
CO2/MWh limit on a 12-operating-month rolling basis. This 
12-operating-month period is important due the inherent variability in 
power plant GHG emissions rates. Establishing a shorter averaging 
period would necessitate establishing a standard to account for the 
conditions that result in the lowest efficiency and therefore the 
highest GHG emissions rate.
    EGU efficiency has a significant impact on the source's GHG 
emission rate. By comparison, efficiency has a smaller impact on the 
emissions rate for criteria or hazardous air pollutants (HAPs). This is 
because control of criteria pollutants and HAPs often involves the use 
of a pollution control device that results in significant reductions, 
often greater than 90 percent. In this situation, the performance of 
the specific pollution control device impacts the emissions rate much 
more than the EGU efficiency.
    EGU efficiency can vary from month to month throughout the year. 
For example, high ambient temperature can negatively impact the 
efficiency of combustion turbine engines and steam generating units. As 
a result, an averaging period shorter than 12 operating-months would 
require us to set a standard that could be achieved under these 
conditions. This standard could potentially be high enough that it 
would not be a meaningful constraint during other parts of the year. In 
addition, operation at low load conditions can also negatively impact 
efficiency. It is likely that for some short period of time an EGU will 
operate at an unusually low load. A short averaging period that 
accounts for this operation would again not produce a meaningful 
constraint for typical loads.
    On the other hand, a 12-operating-month rolling average explicitly 
accounts for variable operating conditions, allows for a more 
protective standard and decreased compliance burden, allows EGUs to 
have and use a consistent basis for calculating compliance (i.e., 
ensuring that 12 operating months of data would be used to calculate 
compliance irrespective of the number of long-term outages), and 
simplifies compliance for state permitting authorities. Because the 12-
operating-month rolling average can be calculated each month, this form 
of the 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 CO2 
from these sources because the effect of GHGs on climate change depends 
on global atmospheric concentrations which are dependent on cumulative 
total emissions over time, rather than hourly or daily emissions 
fluctuations or local pollutant concentrations. Unlike for emissions of 
criteria and hazardous air pollutants, we do not believe that there are

[[Page 1482]]

measureable implications to health or environmental impacts from short-
term higher CO2 emission rates as long as the 12-month 
average emissions rate is maintained.
    We solicit comment on, in the alternative, basing compliance 
requirements on an annual (calendar year) average basis.
2. 84-Operating-Month Compliance Period
    Under today's proposal, new fossil fuel-fired boilers and IGCC 
units will have the option to alternatively meet an emission standard 
on an 84-operating-month rolling basis.
    The EPA has previously offered sources optional, longer-term 
emission standards that are stricter than the primary emissions 
standard in combination with a longer averaging period. We are 
proposing that this alternative emission limit should be between 1,000-
1,050 lb CO2/MWh and we are requesting comment on what the 
final numerical standard should be (within that range) such that the 
84-operating-month standard would be as stringent as or more stringent 
than the 12-operating-month standard.
    We are also requesting comment on an appropriate 12-operating-month 
standard that owners/operators electing to comply with the 84-
operating-month standard would have to comply with. This standard would 
be numerically between the alternate 12-operating-month standard and an 
emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb 
CO2/MWh). This shorter term standard would be more easily 
enforced and assure adequate emission reductions.
    This 84-operating-month period offers increased operational 
flexibility and will tend to compensate for short-term emission 
excursions, which may especially occur at the initial startup of the 
facility and the CCS system.

L. Geologic Sequestration

1. Overview
    We expect that for the immediate future, virtually all of the 
CO2 captured at EGUs will be injected underground for long-
term geologic sequestration at sites where enhanced oil recovery is 
also occurring. There is an existing regulatory framework for geologic 
sequestration and enhanced oil recovery activities. We intend to rely 
upon this existing framework to verify that the CO2 captured 
from an affected unit is injected underground for long-term 
containment. More specifically, as discussed in Section III, the EPA is 
proposing to build from the existing GHG Reporting Program 40 CFR part 
98 to track that the captured CO2 is geologically 
sequestered.
    In addition, we recognize that types of CO2 storage 
technologies other than geologic sequestration are under development 
(e.g. precipitated calcium carbonate, etc). EGUs may use another type 
of CO2 storage technology to meet the standard, once the EPA 
has approved its use, including methods for reporting, monitoring, and 
verifying long-term CO2 storage. We welcome comments on an 
appropriate mechanism for making this determination.
2. Existing Regulatory Framework for CCS
    As noted, the EPA expects that for the immediate future, captured 
CO2 from affected units will be injected underground for 
geologic sequestration at sites where EOR is occurring. Underground 
injection is currently the only technology available that can 
accommodate the large quantities of CO2 captured at EGUs, 
and EOR provides an associated economic incentive and benefit. Three 
solid-fuel fired EGU projects incorporating CCS--Kemper, TCEP, and 
HECA--all include utilization of captured CO2 for EOR.
    The EPA has promulgated, or recently proposed, several rules to 
protect underground sources of drinking water and track the total 
amount of CO2 that is supplied to the economy and injected 
underground for geologic sequestration. First, the EPA's 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.\251\ 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 CO2 and the associated area 
of elevated pressure using both direct and indirect methods, as 
appropriate. Projects are also required to conduct extended post-
injection monitoring and site care to track the location of the 
injected CO2 and monitor subsurface pressures until it can 
be demonstrated that there is no longer a risk of endangerment to 
underground sources of drinking water.
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    \251\ https://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.
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    UIC Class II wells inject fluids associated with oil and natural 
gas production and the storage of liquid hydrocarbons. Most of the 
injected fluid is salt water, which is brought to the surface in the 
process of producing (extracting) oil and gas and subsequently re-
injected. In addition, other fluids, including CO2, are 
injected to enhance oil and gas production. Class II regulations 
include site characterization, well construction, operating, 
monitoring, testing, reporting, financial responsibility, and closure 
requirements to prevent endangerment of underground sources of drinking 
water. Wells that inject CO2 underground for enhanced oil or 
gas recovery may be permitted as UIC Class II or Class VI wells. 
However, the designation of the appropriate well class depends, 
principally, on the risks posed or changes in the risks posed to 
underground sources of drinking water by a specific injection 
operation.
    Second, the GHG Reporting Program covers sources that generate 
electricity (40 CFR part 98, subpart D), sources that supply 
CO2 to the economy (40 CFR part 98, subpart PP) and sources 
that inject CO2 underground for geologic sequestration (40 
CFR part 98, subpart RR). Subpart D owners or operators of facilities 
that contain electricity-generating units must report emissions from 
electricity-generating units and all other source categories located at 
the facility for which methods are defined in part 98.\252\ Owners or 
operators are required to collect emission data; calculate GHG 
emissions; and follow the specified procedures for quality assurance, 
missing data, recordkeeping, and reporting.
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    \252\ https://www.epa.gov/ghgreporting/reporters/subpart/d.html.
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    Subpart PP provides requirements for quantifying CO2 
supplied to the economy.\253\ Affected units that capture 
CO2 to inject underground or supply offsite, are subject to 
all of the requirements under subpart PP of the GHG Reporting Program, 
which relates to suppliers of CO2. Specifically, subpart PP 
requires facilities with production process unit(s) that capture a 
CO2 stream for purposes of supplying CO2 for 
commercial applications or that capture and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground and which meet certain applicability requirements to report 
the mass of CO2 captured. CO2 suppliers are 
required to

[[Page 1483]]

report the annual quantity of CO2 transferred offsite and 
for what end use, including geologic sequestration.
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    \253\ https://www.epa.gov/ghgreporting/reporters/subpart/pp.html.
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    Subpart RR requires facilities meeting the source category 
definition (40 CFR 98.440) for any well or group of wells to report 
basic information on the amount of CO2 received for 
injection; develop and implement an EPA-approved monitoring, reporting, 
and verification (MRV) plan; and report the amount of CO2 
sequestered using a mass balance approach and annual monitoring 
activities. The MRV plan must be submitted and approved by the EPA and 
revised if necessary over time according to 40 CFR 98.448(d). The 
subpart RR MRV plan must include five major components:
     A delineation of the maximum monitoring area (MMA) and the 
active monitoring area (AMA).
     An identification and evaluation of the potential surface 
leakage pathways and an assessment of the likelihood, magnitude, and 
timing, of surface leakage of CO2 through these pathways in 
the MMA.
     A strategy for detecting and quantifying any surface 
leakage of CO2 in the event leakage occurs.
     An approach for establishing the expected baselines for 
monitoring CO2 surface leakage.
     A summary of considerations made to calculate site-
specific variables for the mass balance equation.
    More information on the MRV plan is available in the Technical 
Support Document for the subpart RR final rule (75 FR 75065).
    If an enhanced oil and gas recovery project holds a UIC Class VI 
permit, it is required to report under subpart RR. If the project holds 
a UIC Class II permit and is injecting a CO2 stream 
underground, it is not subject to subpart RR, but the owner or operator 
may choose to opt-in to subpart RR. Sources reporting under subpart RR, 
whether they are UIC Class VI or Class II well(s), must follow the same 
set of requirements.
    As stated in the preamble to the final subpart RR rule:

``while requirements under the UIC program are focused on 
demonstrating that USDWs are not endangered as a result of 
CO2 injection into the subsurface, requirements under the 
GHG Reporting Program through 40 CFR part 98, subpart RR will enable 
EPA to verify the quantity of CO2 that is geologically 
sequestered and to assess the efficacy of GS as a mitigation 
strategy. Subpart RR achieves this by requiring facilities 
conducting GS to develop and implement a MRV plan to detect and 
quantify leakage of injected CO2 to the surface in the 
event leakage occurs and to report the amount of CO2 
geologically sequestered using a mass balance approach, regardless 
of the class of UIC permit that a facility holds.'' (75 FR 75060)

    The Internal Revenue Service relies on the existing regulatory 
framework to verify geologic sequestration when determining eligibility 
of taxpayers claiming the 45Q tax credit. As stated in the preamble to 
the final subpart RR rule:

    ``EPA notes that the Internal Revenue Service (IRS) published 
IRS Notice 2009-83 7 to provide guidance regarding eligibility for 
the Internal Revenue Code section 45Q credit for CO2 
sequestration, computation of the section 45Q tax credit, reporting 
requirements for taxpayers claiming the section 45Q tax credit, and 
rules regarding adequate security measures for secure GS. As 
clarified in the IRS guidance, taxpayers claiming the section 45Q 
tax credit must follow the appropriate UIC requirements. The 
guidance also clarifies that taxpayers claiming section 45Q tax 
credit must follow the MRV procedures that are being finalized under 
40 CFR part 98, subpart RR in this final rule.'' (75 FR 75060)

    Third, the EPA proposed a rule that would conditionally exclude 
CO2 streams from the definition of hazardous waste under 
RCRA, where these streams are being injected for purposes of geologic 
sequestration, into a UIC Class VI well and meet other conditions.\254\ 
The rationale for the rule was that any CO2 stream that 
would otherwise be defined as hazardous waste, need not be managed as 
hazardous waste, provided it is managed under other regulatory programs 
that address the potential risks to human health and the environment 
that these materials may pose.
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    \254\ 76 FR 48073 (Aug. 8, 2011).
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3. Proposal
a. Geologic Sequestration
    To provide certainty and verify that CO2 captured at an 
affected unit is geologically sequestered, today's action relies upon 
the existing regulatory framework the EPA already has in place under 
the GHG Reporting Program 40 CFR part 98. As discussed in the previous 
section, there are key subparts (i.e., subpart D, PP and RR) under 40 
CFR part 98 that provide a transparent reporting and verification 
mechanism for EPA and the public. The EPA requires electric generating 
units to report CO2 emissions under subpart D. Facilities 
that capture CO2 are required to report quantities of 
CO2 captured and injected on site or transferred off-site 
under subpart PP. Facilities that inject CO2 underground for 
geologic sequestration report under subpart RR.
    First, the EPA is proposing that any affected unit that employs CCS 
technology which captures enough CO2 to meet the 1,100 lb/
MWh standard must report, under 40 CFR part 98, subpart RR, if the 
captured CO2 is injected onsite. If the captured 
CO2 is sent offsite, then the facility injecting the 
CO2 underground must report under 40 CFR part 98, subpart 
RR. As noted above, owners and operators of projects that inject 
CO2 underground and that are permitted under a UIC Class VI 
permit are required to comply with subpart RR. The practical impact of 
our proposal would be that owners and operators of projects injecting 
CO2 underground that are permitted under UIC Class II and 
that receive CO2 captured from EGUs to meet the proposed 
performance standard will also be required to submit and receive 
approval of a subpart RR MRV plan and report under subpart RR. This 
proposal does not change any of the requirements to obtain or comply 
with a UIC permit for facilities that are subject to EPA's UIC program 
under the Safe Drinking Water Act.
    In order to use the GHG Reporting Program to ensure that the 
affected unit is sending its captured CO2 to a site 
reporting under subpart RR, the EPA proposes minor modifications to 
subpart PP, CO2 supply. We propose that a facility capturing 
CO2 from an affected unit, and therefore subject to 40 CFR 
part 98, subpart PP, must provide additional information in its subpart 
PP annual report including (1) the electronic GHG Reporting Tool 
identification (e-GGRT ID) of the facility with the electric generating 
unit from which CO2 was captured, and (2) the e-GGRT ID(s) 
for, and mass of CO2 transferred to, each geologic 
sequestration site reporting under subpart RR. This proposed amendment 
to the GHG Reporting Program provides a transparent and consistent 
method to track CO2 capture and sequestration without 
significantly increasing burden on the affected sources. If the 
affected unit does not report under 40 CFR part 98, subpart PP and 
comply with these proposed requirements, it will be considered in 
noncompliance with today's proposal.
    The EPA notes that compliance with the standard of 1,100 lb 
CO2/MWh is determined exclusively by the tons of 
CO2 captured by the emitting EGU. The tons of CO2 
sequestered by the geologic sequestration site are not part of that 
calculation. However, to verify that the CO2 captured at the 
emitting EGU is sent to a geologic sequestration site, we are building 
on existing regulatory requirements under the GHG Reporting program.

[[Page 1484]]

    The EPA acknowledges that there can be downstream losses of 
CO2 after capture, for example during transportation, 
injection or storage. Though a well selected and operated site is 
expected to contain CO2 for the long-term, there is the 
potential for unanticipated leakage. The EPA expects these losses to be 
modest with incentives due to the market use of CO2 as a 
purchased product. There remains an issue of whether the standard 
itself should be adjusted to reflect these downstream losses. The EPA 
is not proposing to do so. Moreover, the EPA wishes to encourage rather 
than discourage EOR using captured CO2 since the practice 
makes CCS itself more economic and thus promotes use of the technology 
on which the proposed standard is based. See Sierra Club v. Costle, 657 
F. 2d at 347 (one purpose of section 111 standards is to promote 
expanded use and development of technology).
    We also emphasize that today's proposal does not involve regulation 
of any downstream recipients of captured CO2. That is, the 
regulatory standard applies exclusively to the emitting EGU, not to any 
downstream user or recipient of the captured CO2 (whether 
the captured CO2 is sold for EOR or otherwise sequestered 
underground). The requirement that the emitting EGU assure that 
captured CO2 is managed at an entity subject to the GHG 
reporting rules is thus exclusively an element of enforcement of the 
EGU standard. Similarly, the existing regulatory requirements 
applicable to geologic sequestration are not part of the proposed NSPS. 
The standard is a numeric value, applicable exclusively to the emitting 
EGU.
    The approach proposed today relies on the existing GHG Reporting 
framework to ensure that CO2 captured at an affected unit is 
transferred to a facility reporting geologic sequestration, and it does 
not impose any additional requirements for an affected unit to 
demonstrate how the captured CO2 is transferred to a 
facility that is compliant with 40 CFR part 98, subpart RR. We seek 
comment on whether there should be such requirements and suggestions 
for what those might include.
b. Alternatives to Geologic Sequestration
    In the development of this proposal, the EPA has identified some 
potential alternatives to geologic sequestration, including but not 
limited to CO2 stored in precipitated calcium carbonate and 
certain types of cement. The EPA solicits comment on whether these and 
other alternatives to geologic sequestration permanently store 
CO2 (so that the stack standard is assured of achieving its 
object--to capture CO2 and prevent its atmospheric release) 
and if they are technically available for EGUs to meet the performance 
standard. Consideration of how these alternatives could meet the 
performance standard involves understanding the ultimate fate of the 
captured CO2 and the degree to which the method permanently 
isolates the CO2 from the atmosphere, as well as existing 
methodologies to verify this permanent storage. The EPA proposes that 
alternatives to geologic sequestration could not be used until the EPA 
finalizes a mechanism to demonstrate that a non-CCS technology would 
result in permanent storage of CO2. The EPA believes that 
the number of cases where an EGU would seek to comply with the 
performance standard through an alternative to CCS will be very few. 
However, the EPA wishes to encourage development of alternatives to 
geologic sequestration that could help offset the cost of 
CO2 capture.
c. Drafting PSD Permits for Affected Sources Using Geologic 
Sequestration
    In most cases, sources that are subject to this NSPS will also be a 
major source or major modification under PSD and required to obtain a 
PSD permit prior to commencing construction. A permit is the legal tool 
used to establish all the source limitations deemed necessary by the 
reviewing agency during review of the permit application, and is the 
primary basis for enforcement of PSD requirements. A well written 
permit reflects the outcome of the permit review process and clearly 
defines what is expected of the source. The permit must be a ``stand-
alone'' document that: (1) Identifies the emissions units to be 
regulated; (2) establishes emissions standards or other operational 
limits to be met; (3) specifies methods for determining compliance and/
or excess emissions, including reporting and recordkeeping 
requirements; and (4) outlines the procedures necessary to maintain 
continuous compliance with the emission limits.
    One of the criteria that must be met to obtain a PSD permit is that 
the owner or operator of the facility must demonstrate that emissions 
from construction or operation of the facility will not cause or 
contribute to air pollution in excess of ``any other applicable 
emissions standard or standard of performance under this chapter.'' 42 
U.S.C. 7475(a)(3)(C); see also 42 U.S.C. 7410(j). Accordingly, PSD 
permits for EGU sources that are subject to this NSPS will need to 
reflect that, at a minimum, the source will meet the requirements of 
this NSPS. Compliance with the NSPS emissions standard is determined 
exclusively by evaluating emissions of CO2 at the EGU.\255\
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    \255\ We note that the PSD program regulates CO2 as 
part of the ``Greenhouse Gas'' pollutant, which includes the 
aggregate group of the following gases: CO2, 
CH4, N20, SF6, HFCs, and PFCs.
---------------------------------------------------------------------------

    As noted in the ``Implications for PSD and Title V programs'' 
section of this preamble, some states have authority to issue PSD 
permits. In other cases, the EPA issues the permit. States with EPA-
approved permitting programs have some discretion in making permit 
decisions and including the necessary conditions in the permit to 
ensure the enforceability of the requirements. Additionally, some 
states may have additional state-specific requirements (e.g., a 
renewable portfolio standard adopted by a state) that may affect the 
stringency of the emission limits for the permits issued in their 
states. Thus, permits for similar source types may vary from state to 
state depending on the permitting program of the state, and the case-
specific PSD evaluation of the source under review. However, the 
permits for similar sources should generally contain the same basic 
information.
    Thus, while EPA recognizes that permit conditions may vary from 
state to state, the EPA believes it is important to clarify the key 
components that should be included in a PSD permit for sources subject 
to the NSPS, as proposed here, and that intend to comply with the 
standard using geologic storage. We believe the following general 
condition areas of a PSD permit would adequately show that the source 
will not cause or contribute to air pollution in excess of this NSPS:
     A BACT emissions limit that applies to the EGU (or EGUs) 
at the stationary source (``EGU facility'') that does not exceed the 
NSPS emission limit standard using the 12-operating-month rolling 
average or the NSPS alternative compliance method.
     Procedures for how the EGU will demonstrate compliance 
with the permitted emissions limit, which, at a minimum, meet the 
monitoring and recordkeeping requirements defined in Sec.  60.5355.
     A requirement that CO2 produced by the EGU (or 
EGUs) is reported under Subpart PP by the permittee.
     A requirement that all CO2 that is geologically 
sequestered at the site of the EGU facility is reported under subpart 
RR by the permittee.
     A requirement that the captured CO2 that the 
permittee sends offsite of the EGU facility is transferred to an

[[Page 1485]]

entity that is subject to the requirements of Subpart RR.
    We specifically request comment on this basic framework for PSD 
permits that are issued for affected EGU sources that use geologic 
sequestration.

VIII. Rationale for Emission Standards for Natural Gas-Fired Stationary 
Combustion Turbines

A. Best System of Emission Reduction

    The EPA evaluated several different control technology 
configurations as potentially representing the ``best system of 
emissions reductions . . . adequately demonstrated'' (BSER) for new 
natural gas-fired stationary combustion turbines: (i) The use of full 
or partial capture CCS; and two types of efficient generation without 
any CCS, including (ii) high efficiency simple cycle aeroderivative 
turbines; and (iii) natural gas combined cycle (NGCC) technology. We do 
not consider full or partial capture CCS to be BSER because of 
insufficient information to determine technical feasibility and because 
of adverse impact on electricity prices and the structure of the 
electric power sector. In addition, we do not consider simple cycle 
turbines to be BSER because they have a higher emission rate and a 
higher cost than NGCC technology. We do find NGCC technology to be the 
BSER because it is technically feasible and relatively inexpensive, its 
emission profile is acceptably low, and it would not adversely affect 
the structure of the electric power sector.
    We note at the outset that currently, virtually all new sources in 
this category are using NGCC technology. That technology is considered 
to be the state of the art for this source category. Because, in this 
rulemaking, we are considering, and selecting, NGCC as the BSER for 
this category, as a matter of terminology, to avoid confusion, we 
generally refer to the affected sources as natural gas-fired combustion 
turbines, and not as NGCC sources.
1. Full and Partial CCS
    To determine the BSER for natural-gas-fired stationary source 
combustion turbines, we evaluated full and partial CCS against the 
criteria. We propose to reject CCS technology as the BSER because we 
cannot conclude that it meets several of the key criteria.
    First, it is not clear that full or partial capture CCS is 
technically feasible for this source category. There are significant 
differences between natural gas-fired combustion turbines and solid 
fossil fuel-fired EGUs that lead us to this conclusion. First, while 
some of these turbines are used to serve base load power demand, many 
cycle their operation much more frequently than coal-fired power 
plants. It is unclear how part-load operation and frequent startup and 
shutdown events would impact the efficiency and reliability of CCS. We 
are not aware that any of the pilot-scale CCS projects have operated in 
a cycling mode. Similarly, none of the larger CCS projects being 
constructed, or under development, are designed to operate in a cycling 
mode. Furthermore, the CO2 concentration in the flue gas of 
a natural gas combustion turbine is much lower (usually approximately 4 
volume percent) than the CO2 concentration in the flue gas 
stream of a typical coal-fired plant (which is approximately 16 volume 
percent for a SCPC or CFB unit) or the syngas of an IGCC unit (in which 
CO2 can be as high as 60 volume percent). Therefore, the 
overall amount of CO2 that can be captured in a CCS project 
is likely lower. Finally, unlike subpart Da affected facilities, where 
there are full-scale plants with CCS that are currently under 
construction or in advanced stages of development, the EPA is aware of 
only one demonstration project, which is an approximately 40 MW slip 
stream installation on a 320 MW NGCC unit.
    Additional factors that make CCS more challenging for a natural gas 
combustion turbine compared to coal-fired EGUs include the time it 
would take to complete the CCS project and the water use requirements. 
Requiring CCS at a natural gas combustion turbine facility would 
potentially delay the project more than at a coal-fired EGU. Natural 
gas combustion turbine facilities can be constructed in about half the 
time required to construct a coal-fired EGU. Therefore, the time 
necessary to construct the carbon capture equipment and any associated 
pipelines to transport the CO2 would have a relatively 
larger impact on a natural gas combustion turbine than a coal-fired 
EGU. Natural gas combustion turbines have relatively low cooling 
requirements for the steam condensing cooling cycle compared to coal-
fired EGUs and often use dry cooling technology. The imposition of CCS 
would have a larger impact on water requirements for a natural gas 
combustion turbine facility compared to a coal-fired EGU.
    Moreover, identifying partial or full CCS as the BSER for new 
stationary combustion turbines would have significant adverse effects 
on national electricity prices, electricity supply, and the structure 
of the power sector. Because virtually all new fossil fuel-fired power 
is projected to use NGCC technology, requiring CCS would have more of 
an impact on the price of electricity than the few projected coal 
plants with CCS and the number of projects would make it difficult to 
implement in the short term. In addition, requiring CCS could lead some 
operators and developers to forego retiring older coal-fired plants and 
replacing them with new NGCC projects, and instead keep the older 
plants on line longer, which could have adverse emission impacts. 
Identifying CCS and BSER for combustion turbines would likely result in 
higher nationwide electricity prices and could adversely affect the 
supply of electricity, since virtually all new fossil fuel-fired power 
is projected to use NGCC technology.
    We recognize that identifying full or partial CCS as the BSER for 
this source category would result in significant emissions reductions, 
but at present, we already consider natural gas to be a low-GHG-
emitting fuel and NGCC to be a low-emitting technology. Although 
identifying CCS as the BSER would promote the development and 
implementation of emission control technology, for the reasons 
described, the EPA does not believe that CCS represents BSER for 
natural gas combustion turbines at this time.
2. Energy Efficient Generation Technology
    To determine the BSER, the EPA also evaluated the use of energy 
efficient generation technology, including high efficiency simple cycle 
aeroderivative turbines.
    The use of high efficiency simple cycle aeroderivative turbines 
does not provide emission reductions from the current state-of-the-art 
technology, is more expensive than the current state-of-the-art 
technology, and does not develop emission control technology. For these 
reasons, we do not consider it BSER. According to the AEO 2013 
emissions rate information, advanced simple cycle combustion turbines 
have a base load rating CO2 emissions rate of 1,150 lb 
CO2/MWh, which is higher than the base load rating emission 
rates of 830 and 760 lb CO2/MWh for the conventional and 
advanced NGCC model facilities, respectively.
    In the April 2012 proposal, we identified NGCC as the BSER for this 
source category, and proposed a standard of 1,000 lb/MWh. We stated:

    [A] NGCC facility is the best system of emission reduction for 
new base load 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

[[Page 1486]]

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 different elevations and ambient temperatures), 
operational characteristics, and sizes.\256\
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    \256\ 77 FR 22414/1.

    The same information supports our current proposal. As described 
above, NGCC has a lower cost of electricity than simple cycle turbines 
at intermediate and high capacity factors. In addition, NGCC has an 
emissions rate that is approximately 25 percent lower than the most 
efficient simple cycle facilities. Therefore, the use of a heat 
recovery steam generator in combination with a steam turbine to 
generate additional electricity is a cost effective control for 
intermediate and high capacity factor stationary combustion turbines. 
Therefore, BSER for intermediate and high capacity factor stationary 
combustion turbines is the use of modern high efficiency NGCC 
technology.

B. Determination of the Standards of Performance

    Multiple commenters on the April 2012 proposal stated the proposed 
standard of 1,000 lb CO2/MWh for combined cycle facilities 
in the April 2012 proposal was too stringent and should be increased to 
a minimum of 1,100 lb CO2/MWh. Commenters explained that the 
increased use of renewable energy for electricity generation will 
require combined cycle facilities to startup, shutdown, cycle, and 
operate at part-load more frequently than they currently do, and that 
this more cyclical operation necessarily entails a higher emission 
rate. The commenters stated that the recent historical emissions data 
that the EPA relied on for the original proposal does not account for 
these likely operational changes. Additional reasons given justifying a 
higher standard include the deterioration of efficiencies over time, 
the need for flexibility to use distillate oil as a backup fuel, the 
operation of combined cycle facilities in simple cycle mode, the fact 
that combined cycle facilities located at high elevations and/or in 
locations with high ambient temperatures are less efficient, and the 
fact that smaller combined cycle facilities are inherently less 
efficient than larger facilities. On the other hand, other commenters 
stated that the final standard should be lower than proposed on grounds 
that the best performing facilities are operating below the original 
proposed standard. Multiple commenters also stated that the EPA should 
evaluate additional CEMS data to determine the appropriate standard.
    In light of these comments, we have reviewed the CO2 
emissions data from 2007 to 2011 for natural gas-fired (non-CHP) 
combined cycle units that commenced operation on or after January 1, 
2000, and that reported complete electric generation data, including 
output from the steam turbine, to the EPA. A more detailed description 
of this emissions data analysis is included in a technical support 
document in the docket for this rulemaking. These 307 NGCC units are 
diverse in location, age, capacity, and operating profile. Based on 
these data, we propose to subcategorize the turbines into the same two 
size-related subcategories currently in subpart KKKK for standards of 
performance for the combustion turbine criteria pollutants. These 
subcategories are based on whether the design heat input rate to the 
turbine engine is either less than or equal to 850 MMBtu/h or greater 
than 850 MMBtu/h. We further propose to establish different standards 
of performance for these two subcategories.
    This subcategorization has a basis in differences in several types 
of equipment used in the differently sized units, which affect the 
efficiency of the units. Large-size combustion turbines use industrial 
frame type combustion turbines and may use multiple pressure or steam 
reheat turbines in the heat recovery steam generator (HRSG) portion of 
a combined cycle facility. Multiple pressure HRSGs employ two or three 
steam drums that produce steam at multiple pressures. The availability 
of multiple pressure steam allows the use of a more efficient multiple 
pressure steam turbine, compared to a single pressure steam turbine. A 
steam reheat turbine is used to improve the overall efficiency of the 
generation of electricity. In a steam reheat turbine, steam is 
withdrawn after the high pressure section of the turbine and returned 
to the boiler for additional heating. The superheated steam is then 
returned to the intermediate section of the turbine, where it is 
further expanded to create electricity. Although HRSGs with steam 
reheat turbines are more expensive and complex than HRSGs without them, 
steam reheat turbines offer significant reductions in CO2 
emission rates. In contrast, small-size combustion turbines frequently 
use aeroderivative turbine engines instead of industrial frame design 
turbines. While there is not a strict definition for an aeroderivative 
turbine, at least parts of aeroderivative turbines are derived from 
aircraft engines. Aeroderivative and frame turbines use different 
combustor designs, lubrication oil systems, and bearing designs. While 
aeroderivative turbines are typically more expensive than industrial 
frame turbines, they are generally more compact, lighter, are able to 
start up and shut down more quickly, and handle rapid load changes more 
easily than industrial frame turbines. Due to their higher simple cycle 
efficiencies, they have traditionally been used more for peak and 
intermittent purposes rather than base power generation. However, 
combined cycle facilities based on aeroderivative combustion turbines 
are available. Due to the higher efficiency of the simple cycle portion 
of an aeroderivative turbine based combined cycle facility, the HRSG 
portion would contribute relatively less to the overall efficiency than 
a HRSG in a frame turbine based combined cycle facility. Therefore, 
adding a multiple steam pressure and/or a reheat steam turbine to the 
HRSG would be relatively more expensive to an aeroderivative turbine 
based combined cycle facility compared to a frame based combined cycle 
facility. Consequently, multiple pressure steam and reheat steam 
turbine HRSG are not widely available for aeroderivative turbine based 
combined cycle facilities. In addition, since aeroderivative turbine 
engines have faster start times and change load more quickly than frame 
turbines, aeroderivative turbine based combined cycle facilities are 
more likely to run at part load conditions and to potentially bypass 
the HRSG and run in simple cycle mode for short periods of time than 
industrial frame turbine based combined cycle facilities.
    Because of these differences in equipment and inherent efficiencies 
of scale, the smaller capacity NGCC units (850 MMBtu/h and smaller) 
available on the market today are less efficient than the larger units 
(larger than 850 MMBtu/h). According to the data in the EPA's Clean Air 
Markets Division database, which contains information on 307 NGCC 
facilities, there is a 7 percent difference in average CO2 
emission rate between the small- and large-size units. This relative 
difference is consistent with what would be predicted when comparing 
the efficiency values reported in Gas Turbine World of small and large 
combined cycle designs.\257\ Fourteen of the study NGCC facilities 
evaluated using the Clean Air Markets data have heat input rates of 
less than or equal to 850 MMBtu/h, and the

[[Page 1487]]

remaining 293 are above 850 MMBtu/MWh. Two of the small combined cycle 
facilities had a maximum 12-operating-month rolling average emissions 
rate equal to or greater than 1,000 lb CO2/MWh and one had a 
maximum 12-operating-month rolling average emissions rate equal to or 
greater than 1,100 lb CO2/MWh. Twenty three of the large 
turbines had at least one occurrence of a 12-operating-month rolling 
average emissions rate greater than or equal to 1,000 lb 
CO2/MWh and forty four had at least one occurrence of a 12-
operating-month rolling average emissions rate greater than or equal to 
950 lb CO2/MWh. Therefore, because over 90 percent of small 
and large existing NGCC facilities are currently operating below the 
emission rates of 1,100 lb CO2/MWh and 1,000 lb 
CO2/MWh, respectively, these rates are considered BSER for 
new NGCC facilities in those respective subcategories. These values 
represent the emission rates that a modern high efficiency NGCC 
facility located in the U.S. would be able to maintain over its life.
---------------------------------------------------------------------------

    \257\ Gas Turbine World--2012 GTW Handbook.
---------------------------------------------------------------------------

    To further evaluate the impact of the proposed rule we reviewed the 
GHG BACT permits for eight recently permitted NGCC facilities. Of these 
facilities, seven are larger than 850 MMBtu/h, and one is smaller. The 
seven larger facilities all have emission rates below 1,000 lb/MWh, and 
as low as 880 lb/MWh. The single smaller facility, which is 400 MMBtu/
h, has a permitted emissions rate of 1,100 lb CO2/MWh. The 
GHG BACT permit limits are higher than the base load rating emissions 
rates because they take into account actual operating conditions.
    We are requesting comment on a range of 950 to 1,100 lb 
CO2/MWh (430 to 500 kg CO2/MWh) for the large 
turbine subcategory and 1,000 to 1,200 lb CO2/MWh (450 to 
540 kg CO2/MWh) for the small turbine subcategory.

IX. 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. Commenters have raised questions regarding 
whether this rule will have implications for regulations and permits 
written under the CAA PSD preconstruction permit program and the CAA 
Title V operating permit program.
    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. Likewise, today's rulemaking does 
not have implications for the Tailoring Rule thresholds established 
with respect to sources subject to title V requirements. Furthermore, 
this proposal does not have any direct applicability on the 
determination of Best Available Control Technology (BACT) for existing 
EGUs that require PSD permits to authorize a major modification of the 
EGU. Finally, this proposal does have some implications for Title V 
fees, but EPA is proposing action to address those implications as 
discussed below.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    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.\258\ Commenters have queried whether under the EPA's 
PSD regulations, promulgation of a section 111 standard of performance 
for 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.
---------------------------------------------------------------------------

    \258\ ``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) if the 
State cannot do so promptly, the EPA will assess whether to 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 the 
final rule that the EPA is proposing today.
    In the alternative, if the Tailoring Rule thresholds would not 
continue to apply when the EPA promulgates requirements under CAA 
section 111, then the EPA would assess whether to 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 the final rule that EPA is proposing today.
    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 BACT. States 
that are authorized by the EPA to administer 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: 
CO2, CH4, N2O, HFCs, PFCs and 
SF6. On January 2, 2011, large industrial sources, including 
power plants, became subject to permitting requirements for their GHG 
emissions if they were already 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 undertakes construction 
and to a ``major modification.'' 40 CFR 51.166(a)(7)(i) and (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

[[Page 1488]]

applicability provisions is that PSD applies to a ``major stationary 
source.''
    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'' 40 CFR 51.166(b)(49) to include any pollutant that is 
subject to any standard promulgated under section 111 of the Act. 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 NSPS trigger provision in 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 of the final Tailoring Rule, 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'').\259\
---------------------------------------------------------------------------

    \259\ 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 create 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.''
    Even so, 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 add new 
provisions to the NSPS regulations, although not the PSD regulations, 
to make explicit that the NSPS trigger provision in the PSD regulations 
incorporates the Tailoring Rule thresholds.\260\ Under these new 
provisions, to the extent that promulgation of section 111 requirements 
for GHGs triggers PSD requirements for GHGs, it does so only for GHGs 
emitted at or above the Tailoring Rule thresholds.
---------------------------------------------------------------------------

    \260\ The Tailoring Rule thresholds themselves are not at issue 
in this rulemaking.
---------------------------------------------------------------------------

    The EPA requests that all States with approved SIP PSD programs 
that apply to GHGs indicate during the comment period on this rule 
whether, (i) in light of EPA's interpretation that the Tailoring Rule 
thresholds continue to apply even when the EPA promulgates the first 
NSPS for GHGs, and (ii) assuming that EPA finalizes the added 
provisions to the section 111 regulations proposed today, 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 
will assess whether to propose a rule shortly after the close of the 
comment period, 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 the final rule that the 
EPA is proposing today. Such a rule would be comparable to what we call 
the SIP PSD Narrowing Rule that EPA promulgated in December, 2010.\261\ 
The EPA may finalize such a narrowing rule at the same time that it 
finalizes this NSPS rule.
---------------------------------------------------------------------------

    \261\ ``Limitation of Approval of Prevention of Significant 
Deterioration Provisions Concerning Greenhouse Gas Emitting-Sources 
in State Implementation Plans; Final Rule,'' 75 FR 82536 (December 
30, 2010).
---------------------------------------------------------------------------

C. Implications for BACT Determinations Under PSD

    New major stationary sources and major modifications at existing 
major stationary sources are required by the CAA to, among other 
things, obtain a permit under the PSD program before commencing 
construction. A source is subject to PSD by way of its proposed 
construction and the effect of the construction and operation of the 
new equipment on emissions. The emission thresholds that define PSD 
applicability can be found in 40 CFR parts 51 and 52 and are discussed 
briefly in the above section.
    As mentioned above, sources that are subject to PSD must obtain a

[[Page 1489]]

preconstruction permit that contains emission limitations based on 
application of Best Available Control Technology for each regulated NSR 
pollutant. The BACT requirement is set forth in section 165(a)(4) of 
the CAA, and in EPA regulations under 40 CFR parts 51 and 52. These 
provisions require that BACT determinations be made on a case-by-case 
basis after consideration of the record in each case. CAA section 
169(3) defines BACT as an emissions limitation (including a visible 
emission standard) based on the maximum degree of reduction for each 
pollutant subject to regulation under the Clean Air Act which would be 
emitted from any proposed major stationary source or major modification 
which the Administrator, on a case-by-case basis, taking into account 
energy, environmental, and economic impacts and other costs, determines 
is achievable for such facility through application of production 
processes and available methods, systems, and techniques, including 
fuel cleaning, clean fuels, or treatment or innovative fuel combustion 
techniques for control of each such pollutant.
    Furthermore, this definition in the CAA specifies that ``[i]n no 
event shall application of [BACT] result in emissions of any pollutants 
which will exceed the emissions allowed by any applicable standard 
established pursuant to section 111 or 112 of the Act.'' This has 
historically been interpreted to mean that BACT cannot be less 
stringent than any applicable standard of performance under the NSPS. 
See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, 
p. 20-21 (March 2011). Thus, upon completion of an NSPS, EPA reads the 
CAA to mean that the NSPS establishes a ``BACT Floor'' for PSD permits 
issued to affected facilities covered by an NSPS. It is important to 
note that a proposed NSPS does not establish the BACT Floor for 
affected facilities seeking a PSD permit. This is explained on page 25 
of EPA's PSD and Title V Permitting Guidance for Greenhouse Gases 
(March 2011):

In cases where a NSPS is proposed, the NSPS will not be controlling 
for BACT purposes since it is not a final action and the proposed 
standard may change, but the record of the proposed standard 
(including any significant public comments on EPA's evaluation) 
should be weighed when considering available control strategies and 
achievable emission levels for BACT determinations made that are 
completed before a final standard is set by EPA. However, even 
though a proposed NSPS is not a controlling floor for BACT, the NSPS 
is an independent requirement that will apply to an NSPS source that 
commences construction after an NSPS is proposed and carries with it 
a strong presumption as to what level of control is achievable. This 
is not intended to limit available options to only those considered 
in the development of the NSPS. (p.25)

    However, once an NSPS is finalized, then the standard applies to 
any new source or modification that meets the applicability of the NSPS 
and has not commenced construction as of the date of the proposed NSPS.
    It is also important to keep in mind that BACT is a case-by-case 
review that considers a number of factors, and the fact that a minimum 
control requirement is established by EPA through an NSPS does not mean 
that a more stringent control cannot be chosen by the permitting 
agency. The EPA's PSD and Title V Permitting Guidance for Greenhouse 
Gases (March 2011) discusses considerations (e.g., technical 
feasibility, economic impacts and other costs, and environmental and 
energy impacts) when evaluating BACT for CO2, as well as 
other greenhouse gases.
    Under this proposed NSPS, an affected facility is a new EGU. In 
this rule we are not proposing standards for modified or reconstructed 
sources. However, since both a new and existing power plant can add new 
EGUs to increase generating capacity, this NSPS will apply to both a 
new, greenfield EGU facility or an existing facility that adds EGU 
capacity by adding a new EGU that is an affected facility under this 
NSPS. While this latter scenario can be considered the modification of 
existing sources under PSD, this proposed NSPS will not apply to 
modified or reconstructed sources as those terms are defined under part 
60. Thus, this NSPS would not establish a BACT floor for sources that 
are modifying an existing EGU, for example, by adding new steam tubes 
in an existing boiler or replacing blades in their existing combustion 
turbine with a more efficient design.
    Furthermore, our analysis for this proposed NSPS considers only the 
extent to which particular pollution control techniques are BSER for 
new units, and does not evaluate whether such techniques also qualify 
as BSER for modified or reconstructed sources under Part 60 or are 
otherwise achievable methods for reducing GHG emission from such 
sources considering economic, environmental, and energy impacts. 
Therefore, we do not believe that the content of this rule has any 
direct applicability on the determination of BACT for any part 60 
modified or reconstructed sources obtaining a PSD permit.

D. 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 the definition of 
``subject to regulation.'' The EPA 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. The 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 CO2e basis.

75 FR 31583.
    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

[[Page 1490]]

promulgation of CAA section 111 requirements has no further impact on 
title V applicability 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 applicable 
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.
    Note that we propose to move the definition of ``Greenhouse gases'' 
currently within the definitions of ``Subject to regulation'' in 40 CFR 
70.2 and 71.2 to a definition within 70.2 and 71.2 to promote clarity 
in the regulations.

E. Implications for Title V Fee Requirements for GHGs

    The issuance of the final EGU GHG NSPS will trigger certain 
requirements related to title V fees for GHG emissions under 40 CFR 
parts 70 and 71. States (and approved local and tribal permitting 
authorities) will be required to include GHG emissions in determining 
whether they collect adequate fees, if the state relies on the 
``presumptive minimum'' approach to demonstrating fee adequacy. In 
addition, sources subject to federal permitting under part 71 will be 
required to include GHG emissions in calculating their annual permit 
fee.\262\ The EPA is proposing changes to the title V rules to limit 
the impact of the requirements that would otherwise occur under the 
existing rules, provide flexibility to the states to ensure sufficient 
funding for their programs, and to ensure that the requirements are 
consistent with the Clean Air Act.
---------------------------------------------------------------------------

    \262\ Also, we understand several states may have fee 
requirements that are structured with similar definitions that would 
result in GHGs being added to the list of air pollutants that are 
subject to title V fees.
---------------------------------------------------------------------------

    These requirements would be triggered because the regulation of 
GHGs under section 111 for the first time through the issuance of the 
EGU GHG NSPS would make GHGs a ``regulated air pollutant,'' as defined 
under 40 CFR parts 70 and 71, a ``regulated pollutant (for presumptive 
fee calculation)'' as defined under part 70 and a ``regulated pollutant 
(for fee calculation)'' as defined under part 71.
    Under the current part 70, regulation of GHGs under section 111 
through the issuance of any NSPS would result in GHGs being added to 
the list of air pollutants used in ``presumptive minimum'' fee 
calculations. Also, in EPA's part 71 permit program, and possibly in 
certain state part 70 programs, issuance of a NSPS standard would 
result in GHGs being added to the list of air pollutants that are 
subject to fee payment by sources. This effect of adding GHGs to 
certain title V fee requirements was not discussed in the original 
proposal for the EGU GHG NSPS; however, several public comments were 
raised on this issue, and a number of related issues, during the public 
comment period on the original proposal for the EGU GHG NSPS.
    In this re-proposal of the EGU GHG NSPS, we discuss this issue for 
GHGs related to title V fees and propose rule amendments that will 
enable permitting authorities to collect fees as needed to support 
their programs, and to avoid excessive and unnecessary fees. We also 
respond to and clarify some related issues raised by commenters on the 
original proposal.
    In summary, we are proposing to exempt GHGs from the presumptive 
fee calculation, yet account for the costs of GHG permitting program 
costs through a cost adjustment to ensure that fees will be collected 
that are sufficient to cover the program costs. We are also proposing 
that permitting agencies that do not use the presumptive fee approach 
can continue to demonstrate that their fee structures are adequate to 
implement their title V programs.
    Prior to explaining our proposal in more detail, the following 
discussion provides background on the fee requirements of the title V 
rules, what those fees cover in terms of agencies' program 
implementation, what additional activities agencies might be expected 
to have to undertake as a result of GHGs becoming ``regulated 
pollutants'' under the NSPS, what the GHG Tailoring Rule said about 
title V fees, background on title V fees in the context of the original 
proposal for the EGU GHG NSPS, and existing limitations on the 
collection of GHG fees.
1. Background
a. The Title V Rules
    Title V is implemented through 40 CFR parts 70 and 71. Part 70 
defines the minimum requirements for state, local and tribal (state) 
agencies to develop, implement and enforce a title V operating permit 
program; these programs are developed by the state and the state 
submits a program to EPA for a review of consistency with part 70. 
There are about 112 approved part 70 programs in effect, with about 
15,000 part 70 permits currently in effect. (See Appendix A of 40 CFR 
part 70 for the approval status of each state program). Part 71 is a 
federal permit program run by the EPA, primarily where there is no part 
70 program in effect (e.g., in Indian country, the federal Outer 
Continental Shelf and for offshore Liquified Natural Gas 
terminals).\263\ There are about 100 part 71 permits currently in 
effect (most are in Indian country).
---------------------------------------------------------------------------

    \263\ In some circumstances, EPA may delegate authority for part 
71 permitting to another permitting agency, such as a tribal agency 
or a state. The EPA has entered into delegation agreements for 
certain part 71 permitting activities with at least one tribal 
agency. There are currently no states that do not have an approved 
part 70 program; thus, there is no need for EPA to delegate part 71 
permitting authority to any state at this time.
---------------------------------------------------------------------------

b. The Fee Requirements of Title V
    Section 502(b)(3)(A) of the Act requires owners or operators of all 
sources subject to permitting to ``pay an annual fee, or the equivalent 
over some other period, sufficient to cover all reasonable (direct and 
indirect) costs required to develop and administer the permit 
program.'' Section 502(b)(3)(B) of the Act generally sets forth the 
methods for determining whether a permitting authority is collecting 
sufficient fees in total to cover the costs of the program. First, 
under the ``presumptive minimum'' approach set forth in section 
502(b)(3)(B)(i), a state can satisfy the requirement by showing that 
``the program will result in the collection, in the aggregate, from all 
sources subject to [the program] of an amount not less than $25 per ton 
of each regulated pollutant, or such other amount as the Administrator 
may determine adequately reflects the reasonable costs of the permit 
program.'' The statute further provides that emissions in excess of 
4,000 tpy for any one pollutant need not be included in the 
calculation, and that the initial fee rate ($25 per ton) shall be 
adjusted for inflation.\264\ See section 502(b)(3)(B)(iii)-(v). Also, 
section 502(b)(3)(B)(ii) of the Act sets forth a definition of 
``regulated pollutant'' for purposes of the presumptive fee calculation 
that includes, in part, each pollutant regulated under section 111 of 
the Act, such as any pollutants regulated under any NSPS, which would 
make GHG a ``regulated pollutant'' based on our proposal for the EGU 
GHG NSPS. Each of the title V rules that implement title V contains a 
definition of ``regulated air

[[Page 1491]]

pollutant''\265\ (at 40 CFR 70.2 and 71.2) that tracks the Act 
definition of ``regulated pollutant.'' The ``regulated air pollutant'' 
definition is used in the regulatory text for application and other 
purposes and it is relevant for fee purposes because it is cross-
referenced as the starting point for two fee-related definitions: 
``regulated pollutant (for presumptive fee calculation) \266\'' in 40 
CFR 70.2 and ``regulated pollutant (for fee calculation) \267\'' in 40 
CFR 71.2.
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    \264\ The current corresponding part 70 fee rate, adjusted for 
inflation, is approximately $47 per ton.
    \265\ The definition includes any pollutant that is subject to 
any standard promulgated under section 111 of the Act.
    \266\ 40 CFR 70.2 defines regulated pollutant (for presumptive 
fee calculation) to include any regulated air pollutant except 
carbon monoxide, any pollutant that is a regulated air pollutant 
solely because it is a Class I or II substance subject to a standard 
promulgated under or established by title VI of the Act and any 
pollutant that is a regulated air pollutant solely because it is 
subject to a standard or regulation under section 112(r) of the Act.
    \267\ 40 CFR 71.2 defines regulated pollutant (for fee 
calculation) the same as reegulated pollutant (for presumptive fee 
calculation) in 40 CFR 70.2.
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    Alternatively, if a state does not wish to show it collects an 
amount of fees at least equal to the presumptive minimum amount, 
section 502(b)(3)(B)(iv) provides that a program may be approved if the 
state demonstrates that it collects sufficient fees to cover the costs 
of the program, even if that amount is below the presumptive minimum.
    The presumptive fee approach of the statute is reflected in the 
part 70 regulations for those states that wish to use it for fee 
adequacy purposes. In addition, for the federal part 71 permitting 
program, which the EPA implements directly, the EPA has adopted rules 
to ensure that it collects adequate fees, consistent with the statute. 
These statutory requirements for fees are reflected in 40 CFR 70.9 and 
71.9, respectively.
    Although the Clean Air Act and part 70 require that a title V 
permit program must collect sufficient fees to cover the costs of the 
program, neither the Act nor part 70 specifies the details of how those 
fees must be charged to particular sources in their fee schedules. The 
part 70 regulations specifically provide, at 40 CFR 70.9(b)(3), that a 
``state program's fee schedule may include emission fees, application 
fees, service fees or other types of fees, or any combination 
thereof.'' Many states use emission fees and other types of fees in 
combination in their fee schedules and we understand that some state 
fee schedules are structured such that they would result in GHG fees 
being required when GHGs are regulated under any NSPS. For example, 
states may have chosen for convenience sake to use the ``regulated 
pollutant (for presumptive fee calculation)'' definition of part 70, or 
a similar state definition, to identify the pollutants subject to fees 
as part of their fee schedule. For part 71, the EPA chose to promulgate 
an emissions-based fee schedule that uses the definition of ``regulated 
pollutants (for fee calculation)'' to identify the pollutants subject 
to fees, and thus, part 71 is structured such that GHG fees would be 
required when GHGs are regulated under any NSPS.
    State fee schedules charge emissions-based fees that range from 
about $15 to $100 or more per ton for each air pollutant for which they 
charge a fee, while part 71 charges about $48 per ton,\268\ effective 
for calendar year 2013, for each of the ``regulated pollutants (for fee 
calculation).'' See 40 CFR 71.9(c)(1). Most part 70 and part 71 
programs require sources to pay the fees on an annual basis, initially 
with the submittal of its permit application, and thereafter, on the 
anniversary of application submittal. See 40 CFR 70.9(a), 71.9(e).
---------------------------------------------------------------------------

    \268\ Note that the part 71 fee rate and the part 70 presumptive 
fee rate are slightly different because the part 71 rate was set 
based on an analysis that showed that the EPA needed slightly more 
than the presumptive minimum to collect sufficient revenue to fund 
the program.
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    Section 502(b)(3)(A) of the CAA broadly requires permit fees 
``sufficient to cover all reasonable (direct and indirect) costs 
required to develop and administer the permit program'' including the 
reasonable costs of: ``(i) reviewing and acting upon any application 
for such a permit, (ii) implementing and enforcing the terms and 
conditions of any such permit (not including any court costs or other 
costs associated with any enforcement action), (iii) emissions and 
ambient monitoring, (iv) preparing generally applicable regulations, or 
guidance, (v) modeling, analyses, and demonstrations, and (vi) 
preparing inventories and tracking emissions.'' These statutory 
requirements were incorporated into the regulations at 40 CFR 
70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on EPA's 
interpretation of this list of activities in several memoranda,\269\ 
and these activities have been considered in the context of the ICR 
development and renewal process for part 70 and 71.
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    \269\ For example, see ``Reissuance of Guidance on Agency Review 
of State Fee Schedules for Operating Permits Programs Under Title 
V''; from John S. Seitz, Director, Office of Air Quality Planning 
and standards, to Air Division Directors, Regions I-X; August 4, 
1993; available at https://www.epa.gov/region07/air/title5/t5memos/fees.pdf.
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c. How EPA Addressed Title V Fees in the Tailoring Rule
    The GHG Tailoring Rule concerned when sources are required to 
obtain permits under prevention of significant deterioration (PSD) and 
title V due to emissions of GHGs. (See Prevention of Significant 
Deterioration and Title V Greenhouse Tailoring Rule; Final Rule [the 
Tailoring Rule]; 75 FR 31514, June 3, 2010.) GHGs became subject to 
regulation as a result of the Light Duty Vehicle Rule (75 FR 25234, May 
7, 2010), and the Tailoring Rule established emissions thresholds for 
purposes of PSD and title V. Neither the Light Duty Vehicle Rule nor 
the Tailoring Rule made any changes that would cause GHGs to meet the 
definition of ``regulated air pollutant,'' or related fee definitions 
in the title V regulations. The EPA has promulgated no other standards 
that would trigger fee requirements for GHGs in title V programs.
    The GHG Tailoring Rule addressed the possible need for states and 
the EPA to charge fees for GHG emissions based on the burdens imposed 
under the Tailoring Rule for states to incorporate GHGs into permits or 
to issue permits to sources based on GHG emissions. We did not revise 
the part 70 rules to require fees for GHGs, although we did clarify 
that states have the option of charging fees to recover the costs of 
permitting related to GHGs. Also, we did not revise part 71 to require 
GHG fees, and we stated that we would review the need for additional 
fees to cover program costs for GHGs over time. (See 75 FR 31526 and 
31584.) We retained this approach in last year's Step 3 Tailoring Rule. 
(See Prevention of Significant Deterioration and Title V Greenhouse 
Tailoring Rule Step 3, GHG Plantwide Applicability Limitations and GHG 
Synthetic Minor Limitations, (Step 3 of the Tailoring Rule), 77 FR 
41051, July 12, 2012).
d. Title V Fees in the Previous EGU GHG NSPS Proposal
    The previous EGU GHG NSPS proposal did not discuss any title V fee 
issues related to regulating GHGs under a section 111 standard; 
however, several public commenters (two state agencies and one industry 
group) raised several concerns or asked for clarification on a number 
of issues related to title V fees during the public comment period. Two 
of these commenters requested clarification as to whether the issuance 
of the EGU GHG NSPS would make either GHGs or CO2 subject to 
regulation such that title V fee requirements would be triggered for 
either of these

[[Page 1492]]

pollutants. One commenter requested clarification on whether fees are 
required for ``regulated NSR pollutants,'' such as GHG. One commenter 
questioned whether the rationale of the Tailoring Rule for deferring 
fees for GHGs would also apply to the EGU GHG NSPS. Finally, one 
commenter asked us to clarify if a state could refrain from charging a 
fee for CO2 (based on the issuance of the EGU GHG NSPS) if 
the state otherwise generates a fee sufficient to meet the ``program 
support requirements'' of title V. Note that we address the substance 
of several of these comments related to title V fees in section B of 
this portion of the proposal.
e. Unique Characteristics of GHGs Relative to Fees
    There are a number of provisions in part 70 and part 71 and 
characteristics of GHGs that are relevant to any discussion related to 
charging fees for GHGs. First, it should be noted that GHG are emitted 
in extremely high quantities relative to other air pollutants, such as 
the criteria pollutants, which are typically emitted by combustion 
sources that also emit GHGs. A review of emission factors in EPA's AP-
42 shows that GHGs are typically emitted in quantities as much as one 
thousand or more times higher than CO or NOX and many other 
pollutants as a product of combustion for a given mass of fuel.\270\ 
Thus, we expect that charging fees for GHGs at the same rate (in 
dollars per ton) as other regulated air pollutants would lead to fee 
revenue that would be excessive, far beyond the reasonable costs of the 
program. Even though most part 70 and 71 programs cap total fees at 
4,000 tons per air pollutant per year \271\ we note that the total GHG 
fee for a particular source under the current part 71 rule could still 
be significant, up to about $194,000 per year for GHGs alone, if GHGs 
are charged at the same rate as for other ``regulated pollutants (for 
fee calculation).'' \272\
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    \270\ See AP-42, Compilation of Air Pollution Emission Factors, 
Volume I, Stationary and Area Sources, Fifth Edition. For example, 
for external combustion of bituminous and subbituminous coals, see 
table 1.1-3 for NOX and CO emission factors and table 
1.1-20 for CO2 emissions factors.
    \271\ Consistent with the option afforded states at 40 CFR 
70.9(b)(2)(ii)(B) and the EPA's fee schedule at 40 CFR 71.9(c)(5).
    \272\ Note that most sources that emit GHGs, particularly major 
sources of GHG, also emit other regulated air pollutants subject to 
fees; thus, they would pay significant title V fees even if a fee 
for GHGs is not charged.
---------------------------------------------------------------------------

    Second, unlike other pollutants, GHGs can be estimated in two ways: 
by mass or by CO2 equivalent (CO2e). While the 
title V permitting threshold for the Tailoring Rule was established at 
100,000 CO2e and 100 tpy mass, the fee provisions of part 70 
and 71, and we believe the fee provisions of the majority, if not all, 
state programs, charge fees on a mass (per ton), rather than on a 
CO2e,\273\ basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR 
71.9(c)(1).
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    \273\ The term ``tpy CO2 equivalent emissions'' (or 
``CO2e'') is defined within the definition of ``subject 
to regulation'' in 40 CFR 70.2 and 71.2. The definitions read, in 
relevant part, ``[CO2e] shall represent an amount of GHGs emitted, 
and shall be computed by multiplying the mass amount of emissions 
(tpy), for each of the six greenhouse gases in the pollutant GHGs, 
by the gas's associated global warming potential published at Table 
A-1 to subpart A of part 98 of this chapter--Global Warming 
Potentials, and summing the resultant value for each to compute a 
tpy CO2e.
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2. Response to Comments on Fees From the Previous EGU GHG NSPS Proposal
    In response to concerns raised by commenters, and because response 
to certain of these issues will help to provide a better proposal, we 
respond to several of these comments at this time. In response to the 
question as to whether CO2 or GHGs would be regulated by the 
EGU GHG NSPS, we clarify that GHG would be regulated under section 111 
of the Act and that this does not affect the applicability thresholds 
previously established for PSD and title V in the Tailoring Rule. 
First, the EPA considers the pollutant being regulated by the NSPS for 
the purposes of PSD and title V to be GHG, rather than CO2. 
Thus, under this interpretation, this NSPS has not caused 
CO2 to be treated as a ``regulated air pollutant'' under the 
third prong of the definition of ``regulated air pollutant'' contained 
in 40 CFR 70.2 and 71.2, which includes ``[a]ny pollutant that is 
subject to any standard promulgated under section 111 of the Act,'' 
because it causes GHG, rather than CO2, to be the 
``regulated air pollutant.'' Second, although EPA's PSD regulations 
provide that regulation of GHGs under CAA section 111 triggers PSD 
applicability, the Tailoring Rule thresholds for GHG continue to apply 
for major source applicability for both the PSD and Title V permitting 
programs.\274\ In addition, we are proposing regulatory text in section 
60.46Da(f) and section 60.4315(b) to make clear that for purposes of 
PSD and title V, greenhouse gases (not carbon dioxide) is the pollutant 
subject to a standard promulgated under section 111.
---------------------------------------------------------------------------

    \274\ We have clarified these points further in a memorandum 
added to the docket for this rulemaking (``PSD Threshold 
Memorandum,'' dated May 8, 2012). See document number EPA-HQ-OAR-
2011-0660-7602.
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    In response to the comment inquiring whether the rationale of the 
Tailoring Rule remains relevant for deferring action on fees, we are 
proposing several revisions to the part 70 and part 71 regulations in 
response to the proposed regulation of GHGs under section 111, while 
retaining the general approach that we described in the Tailoring Rule. 
At the time of the promulgation of the Tailoring Rule, there were no 
section 111 standards (or other standards) that had been promulgated 
that would have resulted in title V fee requirements being triggered 
for GHGs. Thus, the rationale we use now is necessarily different than 
the rationale we used for the Tailoring Rule fee discussion. If the 
commenter is referring to the requests of certain state agencies in 
their comments on the Tailoring Rule for the EPA to set a presumptive 
fee of GHGs, we are responding to that request in this proposal by 
proposing to set a presumptive fee cost adjustment. If the commenter is 
referring to the fee flexibility afforded by 40 CFR 70.9(b)(3), we 
respond that we are not proposing to revise that regulatory provision. 
A state commenter generally asked us if it could refrain from requiring 
a fee for CO2 (or GHG) if it could show that it can 
otherwise generate a fee sufficient to meet the ``program support 
requirements'' of title V. The response to this comment is yes, based 
on the following analysis. Title V requires permitting authorities to 
collect fees from sources that are ``sufficient to cover all reasonable 
(direct and indirect) costs required to develop and administer [title 
V] programs.'' \275\ States have adopted various fee schedules to meet 
this requirement. 40 CFR 70.9(b)(3) allows a State program's fee 
schedule to include emissions fees, application fees, service-based 
fees or other types of fees, or any combination thereof, to meet the 
requirements of the collection and retention of revenues sufficient to 
cover the permit program costs. Further, states are not required to 
calculate fees on any particular basis or in the same manner for all 
part 70 sources or for all regulated air pollutants, provided that they 
collect a total amount of fees sufficient to meet the program support 
requirements. This flexibility is also true for states that use the 
presumptive minimum approach to demonstrate they would collect 
sufficient fees to fund the program. In the final Tailoring Rule (75 FR 
31584, June 3, 2010), we did not change our fee regulations to require 
title V fees for GHGs or require new fee demonstrations from states 
related to permitting GHGs, and we have retained

[[Page 1493]]

the same policies for the purposes of the recent Step 3 rule (77 FR 
41051, July 12, 2012). In the final Tailoring Rule, we recommended that 
each state, local or tribal program review its resource needs for GHGs 
and determine if the existing fee approaches would be adequate. If 
those approaches were not adequate, we suggested that they should be 
proactive in raising fees to cover the direct and indirect costs of the 
program or develop other alternative approaches to meet the shortfall. 
Therefore, we agree with the commenter that consistent with 40 CFR 
70.9(b)(3), if a state generates fees ``sufficient to meet the program 
support requirements,'' without charging fees based on GHG emissions, 
then a fee does not have to be charged specifically for GHGs.\276\ 
Thus, this proposal does not seek to revise fee schedule flexibility 
for states and instead focuses on revising the presumptive minimum fee 
provisions under part 70 to more appropriately account for GHG program 
costs. This notice does not propose any new requirements for states 
that do not use the presumptive approach to establish adequacy of fees.
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    \275\ The fee provisions are set forth in CAA section 502(b)(3) 
and in our regulations at 40 CFR 70.9 and 71.9.
    \276\ Conversely, where a state cannot show that sufficient fees 
are being collected, the state would need to modify its fee schedule 
(which could, but need not, involve charging fees for GHG 
emissions).
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3. Today's Proposal To Address GHGs in Title V Fees
    In this part of the preamble we explain and solicit comment on 
options to address the title V fee issues raised by the proposed 
regulation of GHGs under this NSPS. In sum, we propose to exempt GHGs 
from the presumptive fee calculation, yet account for the costs of GHG 
permitting through a cost adjustment to ensure that fees will be 
collected that are sufficient to cover the program costs. We request 
comment on these proposals, particularly from state, local, and tribal 
permitting agencies, and particularly with respect to which approach 
would be most appropriate, feasible, and workable and result in fees 
that would be adequate to cover the direct and indirect costs of 
permitting GHGs. We also invite comments on ways to improve this 
proposal and/or address this issue in other ways consistent with the 
same principles, concerns, and statutory authority that we have 
described for this proposal.
a. Exemption of GHGs From Presumptive Fee Calculation
    For the reasons discussed earlier in this proposal, we propose to 
exempt GHGs from the definition of ``regulated pollutant (for 
presumptive fee calculation)'' in 40 CFR 70.2 in order to exclude GHGs 
from being subject to the statutory fee rate set for the presumptive 
minimum fee calculation of 40 CFR 70.9(b)(2)(i). Pursuant to the 
authority of section 502(b)(3)(B)(i), we are proposing to determine 
that utilizing the statutory fee rate for GHGs would be inappropriate 
because it would result in excessive fees, far above the reasonable 
costs of a program. We are proposing a significantly smaller cost 
adjustment for GHGs to reflect the program costs related to GHGs.
    We have estimated the cost of permitting GHGs associated with the 
Tailoring Rule thresholds in an economic analysis performed for the 
Tailoring Rule and in several documents related to Information 
Collection Request (ICR) requirements for part 70 and 71, and we 
believe these analyses provide a basis for estimating the costs related 
to GHG permitting for the typical permitting authority. Thus, we 
propose to revise 40 CFR 70.9(b)(2)(i) to add a GHG cost adjustment to 
account for the GHG permitting program costs.
b. Addition of a GHG Cost Adjustment to the Presumptive Minimum Fee 
Calculation
    We propose to revise the presumptive minimum fee provisions of part 
70 to add a GHG cost adjustment to account for the typical GHG 
permitting program costs that may not already be covered by the 
existing presumptive minimum fee provisions of parts 70 and 71. The 
current presumptive minimum fee provisions of the title V rules 
implements the statutory mandate to collect fees that are sufficient to 
cover the direct and indirect GHG program costs. Since we are not 
proposing to charge fees for GHGs at the statutory rate ($25 per ton, 
adjusted for inflation) due to concerns raised by permitting 
authorities and others about this resulting in excessive fees, we may 
need an alternative presumptive minimum fee to recover any costs 
related to GHGs that would not otherwise be covered by the presumptive 
minimum fee that is calculated based on emissions of regulated air 
pollutants, excluding GHGs. We estimated certain incremental GHG 
program costs that would not be covered under the context of the 
Tailoring Rule, but we did not revise our permit rule to reflect those 
costs at that time. We are aware that the EGU NSPS may further increase 
permitting authority costs above the levels that would be covered by 
presumptive minimum fee provisions that exclude GHGs, but we are also 
concerned that accounting for GHGs using the statutory rate would 
result in excessive calculation of costs. Thus, to address these 
concerns, we are proposing two alternative options to adjust the 
presumptive minimum fee provisions of the regulations, including a 
modest additional cost for each GHG-related activity of certain types 
that a permitting authority would process over the period covered by 
the presumptive minimum fee calculation, and a modest additional 
increase in the per ton rate used in the presumptive minimum 
calculation. We are also soliciting comment on an option that would 
calculate no additional costs for GHGs.
    When we promulgate step 4 of the Tailoring Rule, and depending on 
EPA's proposal(s) and final action(s) there, we may revisit the GHG 
cost adjustment and potentially revise it, taking into account any 
changes in permitting authority costs for GHGs related to the 
obligations for permitting authorities under that rulemaking.
    In addition, as a general matter, the presumptive minimum 
adjustments for part 70 we propose for GHGs are based, in part, on 
information concerning permitting authority burden (in hours) and cost 
(in dollars) contained in the Information Collection Request (ICR) 
renewal for part 70 \277\ approved by the Office of Management and 
Budget on October 3, 2012 for the 36 month period of October 31, 2012 
through September 30, 2015. Also, this information is consistent with, 
and updates, burden and cost information in the Regulatory Impact 
Assessment (RIA) for the Tailoring Rule \278\ and an ICR change request 
for the GHG Tailoring Rule (EPA ICR Number 1587.11), which was approved 
by OMB at the time of the promulgation of the Tailoring Rule\279\. 
These assumptions are relevant at least through step 3 of the 
implementation of the Tailoring Rule. The supporting statement for the 
ICR renewal for part 70 sets forth our estimate of the three-year and 
annual incremental burden related to certain activities performed by 
permitting authorities under the Tailoring Rule. (See Supporting 
Statement for the part 70 state Operating Permits Program, document 
number EPA-HQ-OAR-2004-0016-0023). The information in the supporting 
statement is designed to be a directionally correct assessment of 
costs, and thus, may serve as a starting point for considerations of

[[Page 1494]]

the possible range of costs to consider when proposing adjustments to 
the presumptive minimum fee provisions of part 70 to appropriately 
account for GHG permitting program costs.
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    \277\ The most recent part 70 ICR renewal is identified as EPA 
ICR number 1587.12 and the ICR for part 70 has been assigned OMB 
control number 2060-0243.
    \278\ Regulatory Impact Analysis for the Final Prevention of 
Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, 
Final Report, May 2010.
    \279\ The ICR change request form for the Tailoring Rule was 
based on the assumptions made in the RIA for the Tailoring Rule.
---------------------------------------------------------------------------

    First, we are proposing to adjust the presumptive minimum fee to 
account for GHG costs by adding a cost for each GHG-related activity of 
certain types that a permitting authority may perform over the period 
covered by a presumptive minimum fee calculation. Additional 
information supporting this approach may be found in part in Table 12 
of the supporting statement (in the ICR) summarizing the permitting 
authority burden for particular GHG-related permitting activities. 
Table 12 in the ICR shows certain incremental burden assumptions for 
certain activities related to GHG permitting program costs in the form 
of an hourly burden for each activity that a permitting authority may 
process. Based on observations regarding permitting activities since 
the Tailoring Rule, we have adapted these assumptions for the purposes 
of this option and included certain activities with a somewhat 
different description than we used in the table in the ICR in an 
attempt to more accurately reflect the types of permitting activities 
that have occurred in the GHG permit program. In addition, by making 
these clarifying changes, we are trying to more closely track the 
language in the CAA and parts 70 and 71 regarding the specific of the 
permit process. We are proposing to include three general activities in 
this proposed option: (1) ``GHG completeness determination (for initial 
permits or for updated applications)'' at 43 hours, (2) ``GHG 
evaluation for a modification or related permit action'' at 7 hours, 
and (3) ``GHG evaluation at permit renewal'' at 10 burden hours.\280\ 
The GHG cost adjustment for the presumptive fee would be calculated 
under this approach by multiplying the burden hours for each activity 
by the cost of staff time (in $ per hour), including wages, benefits, 
and overhead, as determined by the state for the particular activities 
undertaken. We also solicit comment on the specific burden hours we 
propose for these GHG-related activities. The proposed burden hours for 
the three activities above were not directly discussed in the ICR or 
directly subject to public comment in that context. We believe this 
proposal would benefit from state input on the burden hour assumptions 
for the activities identified and we solicit comment the burden hour 
assumptions and on additional GHG-related permitting activities that 
should be added to the list.
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    \280\ A completeness determination is the first step performed 
by the permitting authority once a permit application is received. 
This step is generally more time consuming for an initial permit 
application compared to other permit applications because this is 
the initial evaluation leading to the drafting and issuance of the 
permit for the first time. Because GHG permitting is in the early 
stages of implementation and EPA is in the early stages of issuing 
new applicable requirements for GHGs, we believe permitting 
authorities will experience additional burdens related to GHGs as 
part of this initial completeness determination. Thus, the first 
item, ``GHG completeness determination (for initial permit or update 
application)'' reflects these additional burdens for completeness 
determinations related to GHGs. This item would also cover 
subsequent application updates related to an initial application. 
See, e.g., 40 CFR 70.5(a)(2). The second item, ``GHG evaluation for 
a permit modification or related permitting action'' applies where a 
permitting authority undertakes an evaluation of whether a permit 
modification involves any GHG-related requirements. This might also 
occur, for example, where a synthetic or true minor application is 
submitted and the permitting authority needs to undertake a GHG 
related analysis to determine if it affects the existing title V 
permit. The third item, ``GHG evaluation at permit renewal'' applies 
where the permitting authority receives a renewal application that 
is not coupled with any facility modifications. The EPA suggests 
this language because it is more closely tied to the specific work 
to be performed by permitting authorities consistent with statutory 
and regulatory obligations.
---------------------------------------------------------------------------

    We are also co-proposing an alternative option under which we would 
increase the fee rate used in the presumptive minimum calculation for 
each regulated air pollutant, excluding GHGs. This option would rely 
primarily on data concerning the state burdens of permitting GHGs 
through step 3 of the tailoring rule found in the Information 
Collection Request (ICR) for part 70. This suggests that when looking 
at Tailoring Rule burden in isolation, that GHG permitting increases 
permitting authority burden by about 7 percent above the baseline 
burden,\281\ which would be multiplied by the presumptive minimum fee 
rate in effect to calculate the revise presumptive fee rate to account 
for GHG. Under this approach, the new presumptive minimum fee effective 
for the current period would be $50.00 per ton for each regulated 
pollutant (for presumptive fee calculation).\282\ Several states 
suggested an approach similar to this in comments on the Tailoring 
Rule, however, their comments assumed we would not be exempting GHGs 
from the definition of regulated pollutants (for presumptive fee 
calculation), as we are proposing today. We solicit comment on the 
appropriateness of the 7 percent fee increase for the presumptive 
minimum fee we propose to account for the GHG permitting costs for 
permitting authorities under this alternative option. We are 
particularly interested in state input on whether this level should be 
higher or lower than we propose.
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    \281\ The baseline costs in the supporting statement for the ICR 
were the costs of permitting looking at all activities except for 
those related to the GHG tailoring rule and certain other recent 
rule changes. Table 14 of the supporting statement shows a 
permitting authority burden of 102,122 hours for implementing the 
GHG tailoring rule and 1,414,293 hours of baseline permitting 
authority burden, and Table 15 shows a permitting authority cost of 
$5.5 million for implementing the GHG tailoring rule and $76.4 
million for the baseline permitting program.
    \282\ At the current rate for part 70 of $46.73, this would 
result in a GHG fee adjustment of about $3.27, or a new rate of 
$50.00 per ton for each regulated pollutant (for presumptive fee 
calculation).
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    The two options we co-propose for adjusting the presumptive minimum 
fee to account for the costs of GHG permitting are similar in that we 
believe they would both result in about the same amount of additional 
fee revenue being collected. For the first option, we took the 
assumptions approved into the ICR and adapted them somewhat so that 
they more accurately reflect the actual implementation experience of 
permitting authorities related to GHGs. On the second, alternative 
option, we used the ICR estimate to determine the relative contribution 
of GHG tailoring rule costs to the total costs of title V permitting 
and we assume these relative costs will hold true in any particular 
state that uses the presumptive minimum fee approach to demonstrating 
fee adequacy. The two options differ in that the first option 
calculates the GHG adjustment to the presumptive fee minimum by 
determining the number of actual GHG-related activities they have 
performed for a period, while the second option calculates the GHG 
adjustment by increasing the presumptive fee rate for non-GHG 
pollutants by a set ratio to reflect average expected costs. The first 
approach requires a state to track the number of activities of these 
types it is performing and is thus more burdensome to calculate, 
although it may more accurately reflect the actual costs. The second 
approach is simpler to calculate and predictable but is less directly 
tied to actual implementation experience in a particular state.
    We also solicit comment on whether we need to revise the 
presumptive minimum calculation provisions to account for GHGs costs if 
we exempt GHGs from the calculation of the presumptive minimum fee. The 
basis for this option would be that because most GHG sources that would 
be subject to title V permitting, whether due to GHGs or due for other 
reasons under the proposed NSPS and applicability provisions of the 
permitting rules (see 40 CFR 70.3 and 71.3) would have actual emissions 
of other regulated air

[[Page 1495]]

pollutants subject to fees, and thus the cost of permitting these 
sources may be adequately accounted for without charging any additional 
fees specifically based on emissions of GHGs. We also note that support 
for this approach can be found in the current OMB-approved ICR for part 
70, tables 14, 15 and 18, where the cost of permitting for permitting 
authorities is summarized, considering the effects of several recent 
EPA rulemakings that were conducted since the last ICR update.
    This proposal does not directly affect those states that do not 
rely on the presumptive minimum fee approach to show fee adequacy; 
however, non-presumptive fee states are still required to charge 
sufficient fees to recover all reasonable direct and indirect program 
costs. Part 70 allows the EPA to review state fee programs at any time 
to determine if they are collecting fees sufficient to cover their 
costs, whether or not states rely on the presumptively minimum fee 
approach. We are not requiring any additional detailed fee submittals 
from states at this time based on these proposed changes.
    Some states may conclude that they wish to revise their part 70 
programs in response to this proposal either to revise their state fee 
schedules to prevent any possible collection of excessive fees (e.g., 
if they require any regulated pollutant subject to a section 111 
standard to pay a fee) or to charge additional fees to sources because 
their presumptive minimum fee target has increased. We solicit comment 
on the most expeditious means for EPA to approve title V program 
revisions across the states once this proposal is finalized.
    There may be other viable options consistent with statutory and 
regulatory authority, principles, and concerns, in addition to those we 
have described in this proposal. For example, states have previously 
commented on establishing a separate, lower presumptive fee per ton of 
GHG emissions). The EPA invites states, local, and/or Tribal 
authorities to provide more refined data and/or information surrounding 
the unique costs associated with permitting GHG sources under this 
proposed rule, and other fee options such data supports. Notably, the 
regulatory text included today represents only one option on which 
comments are solicited. The EPA is providing full regulatory text only 
for this option because it represents the most novel approach. The EPA 
is also soliciting comment on other viable approaches described herein, 
but considers the discussion provided herein to provide an adequate 
basis for public comment. The EPA notes that the final rule may be 
based on any of the approaches described in the preamble.
c. Revisions to the Part 71 Fee Schedule
    As part of the promulgation of the final part 71 rule, the EPA 
performed a detailed analysis of the costs of developing and 
implementing the program and reviewed the inventory of emissions of 
regulated pollutants (for fee calculation) to determine the appropriate 
emission fee that would be sufficient to recover all direct and 
indirect programs costs--we set the fee at $32 per ton, adjusted for 
inflation, times the emissions of regulated pollutant (for fee 
calculation). (See Federal Operating Programs Fees, Revised Cost 
Analysis, February 1996; legacy docket A-93-51, document number II-A-
3.)
    For part 71, we also propose to exempt GHGs from the definition of 
regulated pollutant (for fee calculation), which is similar to the 
definition of regulated pollutants (for presumptive fee calculation) 
used in part 70, for the same reasons we have explained for part 70. In 
addition, for the same reasons we explained for part 70, we are 
proposing two options for revising the fee schedule of 40 CFR 71.9(c) 
to ensure that we continue to recover sufficient fees to fully fund the 
part 71 GHG permitting program. The bases for the options were 
described in more detail earlier in this proposal with respect to part 
70 proposals and those also apply here to part 71.
    First, the EPA (or delegate agency) burden hour assumptions we 
propose for each GHG-related permitting activity under part 71 are the 
same as we are proposing for states under the presumptive minimum fee 
provisions of part 70.\283\ This option would rely on the following 
information. The labor rate assumption we propose for the EPA (or 
delegate agency) staff time under part 71 is the average hourly rate we 
assumed in the supporting statement for the recent part 71 ICR renewal 
of $52 per hour in 2011 dollars, including wages, benefits and overhead 
costs. We propose to determine the GHG fee adjustment for each GHG 
permitting program activity by multiplying the burden hour assumption 
we propose by the EPA (or delegate agency) labor rate we propose. Thus, 
for example, we propose a set fee to be paid by sources for each 
``completeness determination (for new permit or updated application)'' 
of $364 (7 hours times $52 per hour for the current period). Also, we 
propose to charge, for simplicity sake, the same set fees for GHG 
activities, whether performed by the EPA, a delegate agency, or by the 
EPA with contractor assistance. The appropriate set fees for all GHG 
permitting program activities performed for the source would be added 
to the traditional fee that is determined based on emissions of each 
regulated pollutant (for fee calculation) to determine the total fee 
for the source.
---------------------------------------------------------------------------

    \283\ See the supporting statement for the ICR renewal for part 
71 approved by the Office of Management and Budget on June 13, 2012 
for the 36 month period of June 30, 2012 through May 31, 2015. The 
ICR renewal for part 71 is identified as EPA ICR number 1713.10 and 
the ICR for part 71 has been assigned OMB control number 2060-0336. 
The assumptions of this part 71 ICR renewal for GHG burden are 
identical to those used for the part 70 ICR. See Table 12 of the 
part 71 supporting statement.
---------------------------------------------------------------------------

    The second option we propose for part 71 is to increase the 
emission fee by a modest amount for each regulated air pollutant, 
excluding GHGs. For simplicity sake, we propose to charge the same 
adjustment under this option that we propose for part 70, or 7 percent, 
which would be multiplied by annual part 71 fee in effect to calculate 
the revise fee rate.\284\ The rationale for this approach is described 
in more detail earlier in this preamble during the part 70 discussion.
---------------------------------------------------------------------------

    \284\ At the current rate for part 71 of $48.33, this would 
result in a GHG fee adjustment of $3.38, or a new rate of $51.71 per 
ton for each regulated pollutant (for fee calculation).
---------------------------------------------------------------------------

    We also solicit comment on whether we could exclude GHG emissions 
from the calculation of the annual part 71 fee for reasons similar to 
those we explained for part 70 (e.g., because permitting costs can be 
covered by the existing part 71 permit fee).

X. Impacts of the Proposed Action \285\
---------------------------------------------------------------------------

    \285\ Note that EPA does not project any difference in the 
impacts between the alternative to regulate sources under subparts 
Da and KKKK versus regulating them under new subpart TTTT.
---------------------------------------------------------------------------

A. What are the air impacts?

    As explained in the Regulatory Impact Analysis (RIA) for this 
proposed rule, available data indicate that, even in the absence of 
this rule, existing and anticipated economic conditions will lead 
electricity generators to choose new generation technologies that would 
meet the proposed standard without installation of additional controls. 
Therefore, based on the analysis presented in Chapter 5 of the RIA, the 
EPA projects that this proposed rule will result in negligible 
CO2 emission changes, quantified benefits, and costs by 
2022.\286\
---------------------------------------------------------------------------

    \286\ Conditions in the analysis year of 2022 are represented by 
a model year of 2020.

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[[Page 1496]]

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, the 
EPA believes that electric power companies would choose to build new 
EGUs that comply with the regulatory requirements of this proposal even 
in its absence, because of existing and expected market conditions. In 
addition, the EPA does 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. 
However, because some companies may choose to construct coal or other 
fossil fuel-fired units, the RIA also analyzes project-level costs of a 
unit with and without CCS, to quantify the potential cost for a fossil 
fuel-fired unit with CCS.

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 CO2 emission changes, energy impacts, monetized 
benefits, costs, or economic impacts by 2022. The owners of newly built 
electric generating units will likely choose technologies that meet 
these standards even in the absence of this proposal due to existing 
economic conditions as normal business practice. Likewise, the EPA 
believes this rule will not have any impacts on the price of 
electricity, employment or labor markets, or the U.S. 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 CO2 emission changes 
resulting from the rule. Therefore, there are no direct monetized 
climate benefits in terms of CO2 emission reductions 
associated with this rulemaking. However, by clarifying that in the 
future, new coal-fired power plants will be required to meet a 
particular performance standard, this rulemaking reduces uncertainty 
and may enhance the prospects for new coal-fired generation and the 
deployment of CCS, and thereby promote energy diversity.

XI. 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.
    Measurement. We are requesting comment on requiring the use the 
following procedures that increase the precision of GHG measurements:
    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 (see: https://www.epa.gov/airmarkets/emissions/docs/square-ducts-wall-effects-test-method-ctm-041.pdf ) to account for wall 
effects 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 CO2 concentration 
measurement and for molecular weight determination during CEMS relative 
accuracy determinations or for performance testing.
    e. An ambient air argon concentration of 0.93 percent \287\ and a 
molecular weight of 39.9 lb/lb-mol in calculating the dry gas molecular 
weight.
---------------------------------------------------------------------------

    \287\ https://www.physicalgeography.net/fundamentals/7a.html.
---------------------------------------------------------------------------

    f. A value for pi of 3.14159 when calculating the effective area 
for circular stacks.
    g. A daily calibration drift cap no greater than 0.3 percent 
CO2 for CO2 CEMS.
    h. A maximum relative accuracy specification of 2.5 percent for 
both CO2 and flow rate measurement CEMS.
    i. Method 3B of 40 CFR part 60 in addition to Method 3A, for 
CO2 concentration measurement and for molecular weight 
determination during CEMS relative accuracy determinations or for 
performance testing.
    Coal refuse. In the original proposal, we requested comment on 
subcategorizing EGUs that burn over 75 percent coal refuse on an annual 
basis. Multiple commenters supported the exemption, citing numerous 
environmental benefits of remediating coal refuse piles. Other 
commenters disagreed with any exemption, specifically citing the 
N2O emissions from fluidized bed boilers (coal refuse-fired 
EGUs typically use fluidized bed technology). Due to the environmental 
benefits of remediating coal refuse piles cited by commenters, the 
limited amount of coal refuse, and that a new coal refuse-fired EGU 
would be located in close proximity to the coal refuse pile, we are 
continuing to consider establishing a subcategory for coal refuse-fired 
EGUs and are requesting additional comments. Specifically, we are 
requesting additional information on the net environmental benefits of 
coal refuse-fired EGUs, and in the event we do establish a coal refuse-
fired subcategory, what the emissions standard for that subcategory 
should be (i.e., should it be based on a lower amount of partial CCS or 
on highly efficient generation alone, without the use of CCS). One 
commenter on the original proposal stated that existing coal refuse 
piles are naturally combusting at a rate of 0.3 percent annually. We 
are requesting comment

[[Page 1497]]

on assuming this rate of natural combustion and the proper approach to 
accounting for naturally occurring emissions from coal refuse piles.
    Compressed Air Energy Storage (CAES) Facilities. CAES technology is 
an energy storage technology that involves two steps. Air is compressed 
by electric motor driven compressors during off-peak electricity demand 
hours and stored in a storage media (e.g., an underground cavern). 
Electricity is then generated during peak electricity demand periods by 
releasing the high-pressure air, heating the air with natural gas, and 
expanding it through sequential turbines (expanders), which drive an 
electrical generator. Since natural gas is combusted in the stationary 
combustion turbine, a new CAES would potentially have to comply with 
one of the proposed emissions standards. However, based on anticipated 
capacity factors for new CAES facilities, it is our understanding that 
the proposed one-third electric sales of potential electric output 
applicability criteria would exempt new CAES facilities from the 
proposed emission standards. The EPA is requesting comment on whether 
this assumption is accurate. In the event that this is not the case, 
the EPA is considering and requesting comment on if new source review 
is the appropriate mechanism to establish site specific GHG 
requirements for CAES facilities and, if so, whether the EPA should 
exempt stationary combustion turbines at CAES facilities from the 
proposed CO2 emission standards. We have concluded this 
could be appropriate since we expect only a limited number of new CAES 
facilities, and the use of stored energy complicates the determination 
of compliance with the proposed emission standards.
    District Energy. District energy systems produce steam, hot water 
or chilled water at a central facility. The steam, hot water or chilled 
water is then distributed through pipes to individual consumers for 
space heating, domestic hot water heating and air conditioning. As a 
result, individual consumers served by a district energy system do not 
need their own heating, water heating or air conditioning systems. Even 
though with the proposed definition of net-electric output it is 
unlikely that a district energy system would be subject to an emissions 
standard, we are considering and requesting comment on an appropriate 
method to recognize the environmental benefit of district energy 
systems. The steam or hot water distribution system of a district 
energy system located in urban areas, college and university campuses, 
hospitals, airports, and military installations eliminates the need for 
multiple, smaller boilers at individual buildings. A central facility 
typically has superior emission controls and consists of a few larger 
boilers facilitating more efficient operation than numerous separate 
smaller individual boilers. However, when the hot water or steam is 
distributed, approximately two to three percent of the thermal energy 
in the water and six to nine percent of the thermal energy in the steam 
is lost, reducing the net efficiency advantage. To recognize the net 
environmental benefit of district energy systems compared to multiple 
smaller heating and cooling systems, we are requesting comment on 
whether it is appropriate to adjust the measured thermal output from 
district energy systems when calculating the emissions rate used for 
compliance purposes. For example, if thermal energy from central 
district energy systems is approximately 5 percent more efficient than 
thermal energy supplied by multiple smaller heating and cooling 
systems, the measured thermal output would be divided by 0.95 (e.g., 
100 MMBtu/h of measured steam would be 105 MMBtu/h when determining the 
emissions rate). This approach would be similar to the proposed 
approach to how the electric output for CHP is considered when 
determining regulatory compliance and is consistent with the approach 
in the proposed amendments to the combustion turbine NSPS (77 FR 
52554). We request that comments include technical analysis of the net 
benefits in support of any conclusions on an appropriate adjustment 
factor.
    Emergency conditions. We are requesting comment on excluding 
electricity generated as a result of a grid emergency declared by the 
Regional Transmission Organizations (RTO), Independent System Operators 
(ISO) or control area Administrator from counting as net sales when 
determining applicability as an EGU. For example, under this approach, 
if grid voltage drops below acceptable levels and the affected facility 
is the only facility with available capacity, then electricity 
generated during this period would not count for applicability 
purposes. While the proposed 3 year average electric sales 
applicability provides significant flexibility for simple cycle 
turbines, we are considering including the emergency conditions 
exemption to allow facilities designed with the intent to sell less 
than one-third of their potential electric output to continue to 
generate electricity during a grid emergency without such generation 
counting towards the one-third sales applicability criterion. In the 
original 1979 electric utility NSPS rulemaking (44 FR 33580), the EPA 
recognized that emergency periods do occur from unplanned EGU outages, 
transmission outages or surging customer demand loads. Such occurrences 
may require that all available operable EGUs interconnected to the 
electrical grid supply power to the grid. Provisions were added to 40 
CFR part 60, subpart Da to address emergency conditions when continued 
operation of an EGU with a malfunctioning flue gas desulfurization 
(FGD) system is acceptable and not considered a violation of the 
SO2 emissions standard. These conditions require that all 
available capacity from the power company's other EGUs is being used 
and all available purchase power from interconnected power companies is 
being obtained. In this case, the EPA concluded that the broader 
benefits of operating the power plant with the malfunctioning FGD 
system to generate electrical power during emergency conditions in 
order to ensure uninterrupted electricity supply to the public outweigh 
any adverse impacts from a short-term increase in SO2 
emission to the atmosphere from the power plant. The definition for a 
system emergency we are considering is ``any abnormal system condition 
that the Regional Transmission Organizations (RTO), Independent System 
Operators (ISO) or control area Administrator determines requires 
immediate automatic or manual action to prevent or limit loss of 
transmission facilities or generators that could adversely affect the 
reliability of the power system and therefore call for maximum 
generation resources to operate in the affected area, or for the 
specific affected facility to operate to avert loss of load.''
    Initial Design Efficiency Test. We are considering and requesting 
comment on requiring an initial performance test for stationary 
combustion turbines in addition to the 12-operating-month rolling 
average standard. Requiring an initial compliance test that is 
numerically more stringent than the annual standard for new combined 
cycle facilities would insure that the most efficient stationary 
combustion turbines are installed. The less stringent 12-month rolling 
average standard would be set at a level that would take into account 
actual operating conditions.
    Integrated Equipment. The proposed affected facility definitions 
include the traditional generating unit ``plus any integrated equipment 
that provides electricity or useful thermal output.''

[[Page 1498]]

For example, the definition of a steam generating unit for GHG 
purposes, ``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 equipment that provides electricity or useful thermal output 
to either the boiler or to power auxiliary equipment'' (emphasis 
added). We are considering and requesting comment on also including in 
the definition of the affected facility co-located non-emitting energy 
generation equipment that is not integrated into the operation of the 
affected facility. This approach would provide additional flexibility, 
lower compliance costs, and recognize the environmental benefit of non-
emitting sources of electricity and not limit options to integrated 
solar thermal. The definition would include the additional language 
``or co-located non-emitting energy generation included in the facility 
operating permit.'' For example, the definition of a steam generating 
unit for GHG purposes would be expanded to read, ``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 equipment that provides electricity or useful 
thermal output to either the boiler or to power auxiliary equipment or 
co-located non-emitting energy generation included in the facility 
operating permit'' (emphasis added). This would permit the use of co-
located photovoltaic solar power, wind turbines, and other non-emitting 
energy generation as means for achieving compliance with the emission 
standards. Since integrated solar thermal is primarily a feasible 
option only for facilities that operate daily (e.g., thermal energy 
from the solar thermal is used in the steam cycle generated from the 
combustion of fossil fuels), this approach would expand options for 
more intermittent intermediate load generators to efficiently integrate 
non-emitting energy generation into their design.
    Other GHGs. Today's proposed rule would require continuous 
measurement of CO2 from fossil fuel-fired EGUs. Other GHGs, 
such as CH4 and N2O are not included in the 
proposed emission standards and are also not required to be measured 
and reported by affected EGUs as part of today's proposal, even though 
their 100-year global warming potential is 21 to 310 times greater than 
that of CO2, because their emissions from EGUs are believed 
to be negligible when compared to CO2 emissions. We request 
comment on the appropriateness, technique, and frequency (one-time or 
periodic, but not continuous) of measurement and reporting of 
CH4 and N2O emissions from fossil fuel-fired EGUs 
as part of the proposed emissions standard. Receipt of this data would 
enhance understanding of total GHG emissions from EGUs and could aid 
future policy decisions regarding whether these GHGs should be included 
in a revised emission standard, as part of 8-year NSPS review and 
potential revision cycle.
    Violations. We are proposing that the calculation of the number of 
daily violations within an averaging period be determined using the 
following methodology. If, for any 12- or 84-operating month period, 
the source's emission rate exceeds the standard, the number of daily 
violations in the 12- or 84-operating-month averaging period would be 
the number of operating days in that period. However, if a violation 
occurs directly following the previous 12-operating-month or 84-
operating-month averaging period, daily violations would not double 
count operating days that were determined as violations under the 
previous averaging period. For example, assume that a facility operates 
10 days out of each month for 12 months from January 1, Year 1 to 
December 31, Year 1, and exceeds the emissions standard during that 12-
month period. The violation for this January-December Year 1 period 
would constitute 120 daily violations. If the facility operated 20 days 
the following month, which would be January, Year 2, and was still in 
excess of the emissions standard over the period from February, Year 1 
to January, Year 2, then 20 additional daily violations would result, 
for a total of 140 daily violations. We are requesting comment on this 
determination of daily violations for owners/operators that exceeds 
either a 12-operating-month or 84-operating-month standard.

XII. 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 51735, October 4, 1993), 
this action is a ``significant regulatory action'' because it ``raises 
novel legal or policy issues arising out of legal mandates''. 
Accordingly, the EPA submitted this action to the 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 Fossil Fuel-Fired Electric Utility 
Steam Generating Units and Stationary Combustion Turbines.
    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). The 
EPA does not project any new coal-fired EGUs without CCS to be built in 
the absence of this proposal. However, because some companies may 
choose to construct coal or other fossil fuel-fired units, the RIA also 
analyzes project-level costs of a unit with and without CCS, to 
quantify the potential cost for a fossil fuel-fired unit with CCS.

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 the EPA ICR number 2465.02.
    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

[[Page 1499]]

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 emissions and downtime, every 3 months.
    When a malfunction occurs, sources must report them according to 
the applicable reporting requirements of 40 CFR part 60, subparts Da 
and KKKK or subpart TTTT 60.5530. 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 reasonably preventable, and not 
caused by poor maintenance 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 affirmative defense, 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.
    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 
this rule applies only to sources built in the future. Of the number of 
excess emissions events that may be reported by source operators, only 
a small number would be expected to result from a malfunction, and only 
a subset of excess emissions caused by malfunctions would result in the 
source choosing to assert an 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 Da and subpart KKKK or 
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 quarterly summary reports which 
include reporting of emissions and downtime. All burden estimates are 
in 2010 dollars. Average burden hours per response are estimated to be 
8 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-2013-0495. Submit any comments related to the ICR to the EPA and 
OMB. See ADDRESSES section at the beginning of this notice for where to 
submit comments to the EPA. Send comments to OMB at the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street, NW., Washington, DC 20503, Attention: Desk Officer for 
the EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after January 8, 2014, a comment to OMB is best 
assured of having its full effect if OMB receives it by February 7, 
2014. The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small 
entities, small entity is defined as:
    (1) A small business that is defined by the SBA's regulations at 13 
CFR 121.201 (for the electric power generation industry, the small 
business size standard is an ultimate parent entity 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 8 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.

[[Page 1500]]



       Table 8--Potentially Regulated Categories and Entities \a\
------------------------------------------------------------------------
                                                         Examples of
             Category                 NAICS Code         potentially
                                                     regulated entities
------------------------------------------------------------------------
Industry..........................          221112  Fossil fuel electric
                                                     power generating
                                                     units.
State/Local Government............      \b\ 221112  Fossil fuel electric
                                                     power generating
                                                     units owned by
                                                     municipalities.
------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate
  electric power generating units (includes boilers and stationary
  combined cycle combustion turbines).
\b\ 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). The EPA does not project any new coal-fired EGUs 
without CCS to be built. Accordingly, there are no anticipated 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, prior to the April 13, 2012 
proposal (77 FR 22392), the EPA determined to seek early input from 
representatives of small entities while formulating the provisions of 
the 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 CO2 
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.
    While formulating the provisions of this proposed regulation, the 
EPA also considered the input provided in the over 2.5 million public 
comments on the April 13, 2012 proposed rule (77 FR 22392). We invite 
comments on all aspects of the proposal and its impacts, including 
potential adverse impacts, on small entities.

D. Unfunded Mandates Reform Act

    This proposed rule does not contain a federal mandate that may 
result in expenditures of $100 million or more for State, local, and 
tribal governments, in the aggregate, or the private sector in any one 
year. 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). 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 prior to the 
April 13, 2012 proposal (77 FR 22392). 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

[[Page 1501]]

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 CO2 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 actions necessary to come into 
compliance.
    While formulating the provisions of this proposed regulation, the 
EPA also considered the input provided in the over 2.5 million public 
comments on the April 13, 2012 proposed rule (77 FR 22392).

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. Prior to the April 13, 2012 
proposal (77 FR 22392), 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. 
While formulating the provisions of this proposed regulation, the EPA 
also considered the input provided in the over 2.5 million public 
comments on the April 13, 2012 proposed rule (77 FR 22392). In the 
spirit of EO 13132, and consistent with the EPA policy to promote 
communications between the EPA and state and local governments, the EPA 
specifically solicits comment on this proposed action from state and 
local officials.

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

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It would neither 
impose substantial direct compliance costs on tribal governments, nor 
preempt Tribal law. This proposed rule would impose requirements on 
owners and operators of 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 CO2 emissions for new EGU 
sources only. Thus, Executive Order 13175 does not apply to this 
action.
    Although Executive Order 13175 does not apply to this action, EPA 
consulted with tribal officials in developing this action. Because the 
EPA is aware of Tribal interest in this proposed rule, prior to the 
April 13, 2012 proposal (77 FR 22392), the EPA offered consultation 
with tribal officials early in the process of developing the proposed 
regulation to permit them to have meaningful and timely input into its 
development. The EPA's consultation regarded planned actions for 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.
    While formulating the provisions of this proposed regulation, the 
EPA also considered the input provided in the over 2.5 million public 
comments on the April 13, 2012 proposed rule (77 FR 22392).
    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 action is not 
subject to EO 13045 because it is based solely on technology 
performance.

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

    This proposed action is not a ``significant energy action'' as 
defined in 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.

[[Page 1502]]

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 
proposes to use 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.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the U.S.
    This proposed rule limits GHG emissions from new fossil fuel-fired 
EGUs by establishing national emission standards for CO2. 
The EPA has determined that this proposed rule would not result in 
disproportionately high and adverse human health or environmental 
effects on minority, low-income, and indigenous populations because it 
increases the level of environmental protection for all affected 
populations without having any disproportionately high and adverse 
human health or environmental effects on any population, including any 
minority, low-income or indigenous populations.

XIII. Statutory Authority

    The statutory authority for this action is provided by sections 
111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 
7601, 7602, 7607(d)(1)(C)). This action is also subject to section 
307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects

40 CFR Part 60

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

40 CFR Part 70

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

40 CFR Part 71

    Environmental Protection, Administrative practice and procedure, 
Air pollution control, Reporting and recordkeeping requirements.

40 CFR Part 98

    Environmental protection, Greenhouse gases and monitoring, 
Reporting and recordkeeping requirements.

    Dated: September 20, 2013.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
60, 70, 71, and 98 of the Code of the Federal Regulations is proposed 
to be amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart Da--Standards of Performance for Electric Utility Steam 
Generating Units

0
2. Section 60.46Da is added to read as follows:


Sec.  60.46Da  Standards for carbon dioxide (CO2).

    (a) Your affected facility is subject to this section if 
construction commenced after [DATE OF PUBLICATION IN THE FEDERAL 
REGISTER], and the affected facility meets the conditions specified in 
paragraphs (a)(1) and (a)(2) of this section, except as specified in 
paragraph (b) of this section.
    (1) The affected facility combusts fossil fuel for more than 10.0 
percent of the heat input during any 3 consecutive calendar years.
    (2) The affected facility supplies more than one-third of its 
potential electric output and more than 219,000 MWh net-electric output 
to a utility power distribution system for sale on an annual basis.
    (b) The following EGUs are not subject to this section:
    (1) The proposed Wolverine EGU project described in Permit to 
Install No. 317-07 issued by the Michigan Department of Environmental 
Quality, Air Quality Division, effective June 29, 2011 (as revised July 
12, 2011).
    (2) The proposed Washington County EGU project described in Air 
Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia 
Department of Natural Resources, Environmental Protection Division, Air 
Protection Branch, effective April 8, 2010, provided that construction 
had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE 
FEDERAL REGISTER].
    (3) The proposed Holcomb EGU project described in Air Emission 
Source Construction Permit 0550023 issued by the Kansas Department of 
Health and Environment, Division of Environment, effective December 16, 
2010, provided that construction had not commenced for NSPS purposes as 
of [DATE OF PUBLICATION IN THE FEDERAL REGISTER].
    (c) As owner or operator of an affected facility subject to this 
section, you shall not cause to be discharged into the atmosphere from 
the affected facility any gases that contain CO2 in excess 
of the emissions limitation specified in either paragraphs (c)(1) or 
(c)(2) of this section.
    (1) 500 kilograms (kg) of CO2 per megawatt-hour (MWh) of 
gross energy output (1,100 lb CO2/MWh) on a 12-operating 
month rolling average basis; or
    (2) 480 kg of CO2 per MWh of gross energy output (1,050 
lb CO2/MWh) on an 84-operating month rolling average basis.
    (d) You must make compliance determinations at the end of each 
operating month, as provided in

[[Page 1503]]

paragraphs (d)(1) and (d)(2) of this section. For the purpose of this 
section, operating month means a calendar month during which any fossil 
fuel is combusted in the affected facility.
    (1) If you elect to comply with the CO2 emissions 
limitation in paragraph (c)(1) of this section, you must determine 
compliance monthly by calculating the average CO2 emissions 
rate for the affected facility at the end of each 12-operating month 
period that includes, as the last month, the month for which you are 
determining compliance.
    (2) If you elect to comply with the CO2 emissions 
limitation in paragraph (c)(2) of this section, you must determine 
compliance monthly by calculating the average CO2 emissions 
rate for the affected facility at the end of each 84-operating month 
period that includes, as the last month, the month for which you are 
determining compliance.
    (e) You must conduct an initial compliance determination with the 
CO2 emissions limitation for your affected facility within 
30 days after accumulating the required number of operating months for 
the compliance period with which you have elected to comply (i.e., 12-
operating months or 84-operating months). The first operating month 
included in this compliance period is the month in which emissions 
reporting is required to begin under Sec.  75.64(a) of this chapter.
    (f) You must monitor and collect data to demonstrate compliance 
with the CO2 emissions limitation according to the 
requirements in paragraphs (f)(1) through (4) of this section.
    (1) You must prepare a monitoring plan in accordance with the 
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (2) You must measure the hourly CO2 mass emissions from 
each affected facility using the procedures in paragraphs (f)(2)(i) 
through (vii) of this section, except as provided in paragraph (f)(3) 
of this section.
    (i) You must install, certify, operate, maintain, and calibrate a 
CO2 continuous emission monitoring system (CEMS) to directly 
measure and record CO2 concentrations in your affected 
facility's exhaust gases that are emitted to the atmosphere and an 
exhaust gas flow rate monitoring system according to Sec.  
75.10(a)(3)(i) of this chapter. If you measure CO2 
concentration on a dry basis, you must also install, certify, operate, 
maintain, and calibrate a continuous moisture monitoring system, 
according to Sec.  75.11(b) of this chapter.
    (ii) For each monitoring system used to determine the 
CO2 mass emissions, you must meet the applicable 
certification and quality assurance procedures in Sec.  75.20 of this 
chapter and Appendices B and D to part 75 of this chapter.
    (iii) You must use a laser device to measure the dimensions of each 
exhaust gas stack or duct at the flow monitor and the reference method 
sampling locations prior to the initial setup (characterization) of the 
flow monitor. For circular stacks, you must make measurements of the 
diameter at three or more distinct locations and average the results. 
For rectangular stacks or ducts, you must make measurements of each 
dimension (i.e., depth and width) at three or more distinct locations 
and average the results. If the flow rate monitor or reference method 
sampling site is relocated, you must repeat these measurements at the 
new location.
    (iv) You can only use unadjusted exhaust gas volumetric flow rates 
to determine the hourly CO2 mass emissions from the affected 
facility; you must not apply the bias adjustment factors described in 
section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust 
gas flow rate data.
    (v) If you choose to use Method 2 in Appendix A-1 to this part to 
perform the required relative accuracy test audits (RATAs) of the part 
75 flow rate monitoring system, you must use a calibrated Type-S pitot 
tube or pitot tube assembly. You must not use the default Type-S pitot 
tube coefficient.
    (vi) If two or more affected facilities share a common exhaust gas 
stack and are subject to the same CO2 emissions limitation 
in paragraph (c) of this section, you may monitor the hourly 
CO2 mass emissions at the common exhaust gas stack rather 
than monitoring each affected facility separately.
    (vii) If the exhaust gases from the affected facilities are emitted 
to the atmosphere through multiple stacks (or if the exhaust gases are 
routed to a common stack through multiple ducts and you choose to 
monitor in the ducts), you must monitor the hourly CO2 mass 
emissions and the ``stack operating time'' (as defined in Sec.  72.2 of 
this chapter) at each stack or duct separately.
    (3) As an alternative to complying with paragraph (f)(2) of this 
section, for affected facilities that do not combust any solid fuel, 
you may determine the hourly CO2 mass emissions by using 
Equation G-4 in Appendix G to part 75 of this chapter according to the 
requirements specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this 
section.
    (i) You must implement the applicable procedures in Appendix D to 
part 75 of this chapter to determine hourly unit heat input rates 
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic 
determinations of the gross calorific value (GCV) of each fuel 
combusted.
    (ii) You may determine site-specific carbon-based F-factors 
(Fc) using Equation F-7b in section 3.3.6 of Appendix F to 
part 75 of this chapter, and you may use these Fc values in 
the emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature.
    (4) You must install, calibrate, maintain, and operate a sufficient 
number of watt meters to continuously measure and record the gross 
electric output from the affected facility, and you must meet the 
requirements specified in paragraphs (f)(4)(i) and (ii) of this 
section, as applicable.
    (i) If your affected facility is a combined heat and power unit as 
defined in Sec.  60.42Da, you must also install, calibrate, maintain, 
and operate meters to continuously determine and record the total 
useful recovered thermal energy. For process steam applications, you 
must install, calibrate, maintain, and operate meters to continuously 
determine and record steam flow rate, temperature, and pressure. If 
your affected facility has a direct mechanical drive application, you 
must submit a plan to the Administrator or delegated authority for 
approval of how gross energy output will be determined. Your plan shall 
ensure that you install, calibrate, maintain, and operate meters to 
continuously determine and record each component of the determination.
    (ii) If two or more affected facilities have steam generating units 
that serve a common electric generator, you must apportion the combined 
hourly gross electric output to each individual affected facility using 
a plan approved by the Administrator (e.g., using steam load or heat 
input to each affected facility). Your plan shall ensure that you 
install, calibrate, maintain, and operate meters to continuously 
determine and record each component of the determination.
    (g) You must demonstrate compliance with the CO2 
emissions limitation using the procedures specified in paragraphs 
(g)(1) and (2) of this section.
    (1) You must calculate the CO2 mass emissions rate for 
your affected facility using the calculation procedures in paragraphs 
(g)(1)(i) through (v) of this section with the hourly CO2 
mass emissions and gross energy output data determined and recorded 
according to the procedures in paragraph (f) of this section for each 
operating hour in the applicable compliance period (i.e., 12-

[[Page 1504]]

operating months or 84-operating months).
    (i) You must only use operating hours in the compliance period for 
which you have valid data for all the parameters you use to determine 
the hourly CO2 mass emissions and gross output data. You 
must not use operating hours which use the substitute data provisions 
of part 75 of this chapter for any of the parameters in the 
calculation. For the compliance determination calculation, you must 
obtain valid hourly values for a minimum of 95 percent of the operating 
hours in the applicable compliance period.
    (ii) You must calculate the total CO2 mass emissions by 
summing all of the valid hourly CO2 mass emissions values 
for the applicable compliance period. If exhaust gases from the 
affected facility are emitted to the atmosphere through multiple stacks 
or ducts, you must calculate the total CO2 mass emissions 
for the affected facility by summing the total CO2 mass 
emissions from each of the individual stacks or ducts.
    (iii) For each operating hour of the compliance period used in 
paragraph (g)(1)(ii) of this section to calculate the total 
CO2 mass emissions, you must determine the affected 
facility's corresponding hourly gross energy output using the 
appropriate definitions in Sec.  60.42Da and paragraph (k) of this 
section and using the procedure specified in paragraphs (g)(3)(iii)(A) 
through (D) of this section.
    (A) Calculate Pgross for your affected facility using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.000

Where: a
Pgross = Gross energy output of your affected facility in 
megawatt-hours in MWh.
(Pe)ST = Electric energy output plus mechanical energy 
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy 
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy 
output (if any) of your affected facility's integrated equipment 
that provides electricity or mechanical energy to the affected 
facility or auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater 
pumps at steam generating units in MWh. This term is not applicable 
to IGCC facilities.
(Pt)PS = Useful thermal energy output of steam measured 
relative to ISO conditions that is used for applications that do not 
generate additional electricity, produce mechanical energy output, 
or enhance the performance of the affected facility. This term is 
calculated using the equation specified in paragraph (g)(3)(iii)(B) 
of this section in MWh.
(Pt)HR = Hourly useful thermal energy output measured 
relative to ISO conditions from heat recovery that is used for 
applications other than steam generation or performance enhancement 
of the affected facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO 
conditions from any integrated equipment that provides thermal 
energy to the affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a combined heat and power affected facility where 
at least on an annual basis 20.0 percent of the total gross energy 
output consists of electric or direct mechanical output and 20.0 
percent of the total gross energy output consists of useful thermal 
energy output on a rolling 3 year basis.
    T = 1.0 for all other affected facilities.

    (B) If applicable to your affected facility, calculate 
(Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.001

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds 
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure 
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (C) For an operating hour in which there is no gross electric load, 
but there is mechanical or useful thermal output, you must still 
determine the gross energy output for that hour. In addition, for an 
operating hour in which there is no useful output, you must still 
determine the hourly gross CO2 emissions for that hour.
    (D) If hourly CO2 mass emissions are determined for a 
common stack, you must determine the hourly gross energy output 
(electric, thermal, and/or mechanical, as applicable) by summing the 
hourly loads for the individual affected facility and you must express 
the operating time as ``stack operating hours'' (as defined in Sec.  
72.2 of this chapter).
    (iv) You must calculate the total gross energy output by summing 
the hourly gross energy output values for the affected facility 
determined from paragraph (g)(1)(iii) of this section for all of the 
operating hours in the applicable compliance period.
    (v) You must calculate the CO2 mass emissions rate for 
the applicable compliance period interval by dividing the total 
CO2 mass emissions value from paragraph (g)(1)(ii) of this 
section by the total gross energy output value from paragraph 
(g)(1)(iv) of this section.
    (2) You must determine compliance with the CO2 emissions 
limitation in paragraph (c) of this section is determined as specified 
in paragraphs (g)(2)(i) and (ii) of this section using the 
CO2 mass emissions rate for your affected facility that you 
determined in paragraph (g)(1) of this section.
    (i) If the CO2 mass emissions rate for your affected 
facility is less than or equal to the CO2 emissions 
limitation applicable to your affected facility, then your affected 
facility is in compliance with the CO2 emissions limitation. 
If you attain compliance with the CO2 emissions limitation 
at a common stack for two or more affected facilities subject to the 
same CO2 emissions limitation, each affected facility 
sharing the stack is in compliance with the CO2 emissions 
limitation.
    (ii) If the CO2 mass emissions rate for the affected 
facility is greater than the CO2 emissions limitation in 
paragraph (c) of this section applicable to the affected facility, then 
the affected facility has excess CO2 emissions.
    (h) You must prepare and submit notifications and reports according 
to paragraphs (h)(1) through (4) of this section.
    (1) You must prepare and submit the notifications in Sec. Sec.  
60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected 
facility.
    (2) You must prepare and submit notifications in Sec.  75.61 of 
this chapter, as applicable to your affected facility.
    (3) You must submit electronic quarterly reports according to the 
requirements specified in paragraphs (h)(3)(i) through (iii) of this 
section.
    (i) Initially, after you have accumulated the required number of 
operating months for the CO2 emission limitation compliance 
period that you have chosen to comply with (i.e., 12-operating months 
or 84-operating months), you must submit a report for

[[Page 1505]]

the calendar quarter that includes the final (12th- or 84th) operating 
month no later than 30 days after the end of that quarter. Thereafter, 
you must submit a report for each subsequent calendar quarter no later 
than 30 days after the end of the quarter.
    (ii) In each quarterly report you must include the information in 
paragraphs (h)(3)(ii)(A) through (E) of this section.
    (A) The CO2 emission limitation compliance period with 
which you have chosen to comply.
    (B) Any months in the calendar quarter that you are not counting as 
operating months.
    (C) For each operating month in the calendar quarter, the 
corresponding average CO2 mass emissions rate for the 
applicable compliance period interval that you determined according to 
paragraph (g) of this section.
    (D) The percentage of valid CO2 mass emission rates in 
each compliance period (i.e., the total number of valid CO2 
mass emission rates in that period divided by the total number of 
operating hours in that period, multiplied by 100 percent).
    (E) Any operating months in the calendar quarter with excess 
CO2 emissions.
    (iii) In the final quarterly report of each calendar year you must 
include the following:
    (A) Net electric output sold to an electric grid over the calendar 
year; and
    (B) The potential electric output of the facility.
    (iv) You must submit each electronic report using the Emissions 
Collection and Monitoring Plan System (ECMPS) Client Tool provided by 
the Clean Air Markets Division in the EPA Office of Atmospheric 
Programs.
    (4) You must meet all applicable reporting requirements and submit 
reports as required under subpart G of part 75 of this chapter.
    (5) If your affected unit uses geologic sequestration to meet the 
applicable emissions limit, you must report in accordance with the 
requirements of 40 CFR Part 98, subpart PP and either:
    (i) if injection occurs onsite, report in accordance with the 
requirements of 40 CFR Part 98, subpart RR, or
    (ii) if injection occurs offsite, transfer the captured 
CO2 to a facility or facilities that reports in accordance 
with the requirements of 40 CFR Part 98, subpart RR.
    (i) For each affected electric utility stream generating unit, you 
must maintain records according to paragraphs (i)(1) through (i)(8) of 
this section.
    (1) You must comply with the applicable recordkeeping requirements 
and maintain records as required under subpart F of part 75 of this 
chapter.
    (2) You must maintain records of the calculations you performed to 
determine the total CO2 mass emissions for each operating 
month, and the averages for each compliance period interval (i.e., 12-
operating months or 84-operating months, as applicable to the 
CO2 emissions limitations).
    (3) You must maintain records of the applicable data recorded and 
calculations performed that you used to determine the gross energy 
output for each operating month.
    (4) You must maintain records of the calculations you performed to 
determine the percentage of valid CO2 mass emission rates in 
each compliance period.
    (5) You must maintain records of the calculations you performed to 
assess compliance with each applicable CO2 emissions 
limitation in paragraph (c) of this section.
    (6) Your records must be in a form suitable and readily available 
for expeditious review.
    (7) You must maintain each record for 5 years after the date of 
each occurrence, measurement, maintenance, corrective action, report, 
or record except those records required to demonstrate compliance with 
an 84-operating month compliance period. You must maintain records 
required to demonstrate compliance with an 84-operating month 
compliance period for at least 10 years following the date of each 
occurrence, measurement, maintenance, corrective action, report, or 
record.
    (8) You must maintain 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.  60.7. You may maintain 
the records off site and electronically for the remaining year(s) as 
required by this subpart.
    (j) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG 
emissions from new affected facilities, the ``pollutant that is subject 
to the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP 
approved by the EPA that is interpreted to incorporate, or specifically 
incorporates, 40 CFR 51.166(b)(48).
    (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG 
emissions from new affected facilities, the ``pollutant that is subject 
to the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Act as defined in 40 CFR 52.21(b)(49).
    (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from new affected facilities, the ``pollutant that is subject 
to any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 70.2.
    (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from new affected facilities, the ``pollutant that is subject 
to any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 71.2.
    (k) For purposes of this section, the following definitions apply:
    Gross energy output means:
    (i) Except as provided under paragraph (ii) of this definition, for 
electric utility steam generating units, the gross electric or 
mechanical output from the affected facility (including, but not 
limited to, output from steam turbine(s), combustion turbine(s), and 
gas expanders) minus any electricity used to power the feedwater pumps 
plus 75 percent of the useful thermal output measured relative to ISO 
conditions that is not used to generate additional electric or 
mechanical output or to enhance the performance of the unit (e.g., 
steam delivered to an industrial process for a heating application);
    (ii) For electric utility steam generating unit combined heat and 
power facilities where at least 20.0 percent of the total gross energy 
output consists of electric or direct mechanical output and at least 
20.0 percent of the total gross energy output consists of thermal 
output on a rolling 3 year basis, the gross electric or mechanical 
output from the affected facility (including, but not limited to, 
output from steam turbine(s), combustion turbine(s), and gas expanders) 
minus any electricity used to power the feedwater pumps, that 
difference divided by 0.95, plus 75 percent of the useful thermal 
output measured relative to ISO conditions that is not used to generate 
additional electric or mechanical output or to enhance the performance 
of the unit (e.g., steam delivered to an industrial process for a 
heating application);
    (iii) Except as provided under paragraph (ii) of this definition, 
for a IGCC electric utility generating unit, the gross electric or 
mechanical output from the affected facility (including, but not 
limited to, output from steam turbine(s), combustion turbine(s), and 
gas expanders) plus 75 percent of the useful

[[Page 1506]]

thermal output measured relative to ISO conditions that is not used to 
generate additional electric or mechanical output or to enhance the 
performance of the unit (e.g., steam delivered to an industrial process 
for a heating application);
    (iv) For IGCC electric utility generating unit combined heat and 
power facilities where at least 20.0 percent of the total gross energy 
output consists of electric or direct mechanical output and at least 
20.0 percent of the total gross energy output consists of thermal 
output on a rolling 3 year basis, the gross electric or mechanical 
output from the affected facility (including, but not limited to, 
output from steam turbine(s), combustion turbine(s), and gas expanders) 
divided by 0.95, plus 75 percent of the useful thermal output measured 
relative to ISO conditions that is not used to generate additional 
electric or mechanical output or to enhance the performance of the unit 
(e.g., steam delivered to an industrial process for a heating 
application);
    IGCC facility is an integrated gasification combined cycle electric 
utility steam generating unit, which means an electric utility combined 
cycle facility that is designed to burn fuels containing 50 percent (by 
heat input) or more solid-derived fuel not meeting the definition of 
natural gas plus any integrated equipment that provides electricity or 
useful thermal output to either the affected facility or auxiliary 
equipment. The Administrator may waive the 50 percent solid-derived 
fuel requirement during periods of the gasification system 
construction, startup and commissioning, shutdown, or repair. No solid 
fuel is directly burned in the facility during operation.
    Net-electric output means:
    (i) Except as provided under paragraph (ii) of this definition, the 
gross electric sales to the utility power distribution system minus 
purchased power on a calendar year basis, or
    (ii) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and at least 20.0 percent of the total gross energy 
output consists of thermal output, the gross electric sales to the 
utility power distribution system minus purchased power of the thermal 
host facility or facilities on a calendar year basis.
    Potential electric output means:
    (i) Either 33 percent or the design net electric output efficiency, 
at the election of the owner/operator of the affected facility,
    (ii) Multiplied by the maximum design heat input capacity of the 
steam generating unit,
    (iii) Divided by 3,413 Btu/KWh,
    (iv) Divided by 1,000 kWh/MWh, and
    (v) Multiplied by 8,760 h/yr.
    (vi) For example, a 35 percent efficient steam generating unit with 
a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 
310,000 MWh 12 month potential electric output capacity.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel for the purpose of producing steam (nuclear 
steam generators are not included) plus any integrated equipment that 
provides electricity or useful thermal output to either the boiler or 
auxiliary equipment.

Subpart KKKK--Standards of Performance for Stationary Combustion 
Turbines

0
3. Section 60.4305 is amended by adding paragraph (c) to read as 
follows:


Sec.  60.4305  Does this subpart apply to my stationary combustion 
turbine?

* * * * *
    (c) For purposes of regulation of greenhouse gases, the applicable 
provisions of this subpart affect your stationary combustion turbine if 
it meets the applicability conditions in paragraphs (c)(1) through 
(c)(5) of this section.
    (1) Commenced construction after [DATE OF PUBLICATION IN THE 
FEDERAL REGISTER];
    (2) Has a design heat input to the turbine engine greater than 73 
MW (250 MMBtu/h);
    (3) Combusts fossil fuel for more than 10.0 percent of the heat 
input during any 3 consecutive calendar years.
    (4) Combusts over 90% natural gas on a heat input basis on a 3 year 
rolling average basis; and
    (5) Was constructed for the purpose of supplying, and supplies, 
one-third or more of its potential electric output and more than 
219,000 MWh net-electrical output to a utility distribution system on a 
3 year rolling average basis.

0
4. Section 60.4315 is revised to read as follows:


Sec.  60.4315  What pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are nitrogen oxides 
(NOX), sulfur dioxide (SO2), and greenhouse 
gases.
    (b)(1) The greenhouse gases regulated by this subpart consist of 
carbon dioxide (CO2).
    (2) PSD and Title V Thresholds for Greenhouse Gases.
    (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG 
emissions from affected stationary combustion turbine, the ``pollutant 
that is subject to the standard promulgated under section 111 of the 
Act'' shall be considered to be the pollutant that otherwise is subject 
to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in 
any SIP approved by the EPA that is interpreted to incorporate, or 
specifically incorporates, 40 CFR 51.166(b)(48).
    (ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG 
emissions from affected stationary combustion turbines, the ``pollutant 
that is subject to the standard promulgated under section 111 of the 
Act'' shall be considered to be the pollutant that otherwise is subject 
to regulation under the Act as defined in 40 CFR 52.21(b)(49).
    (iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from affected stationary combustion turbines, the ``pollutant 
that is subject to any standard promulgated under section 111 of the 
Act'' shall be considered to be the pollutant that otherwise is 
``subject to regulation'' as defined in 40 CFR 70.2.
    (iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from affected stationary combustion turbines, the ``pollutant 
that is subject to any standard promulgated under section 111 of the 
Act'' shall be considered to be the pollutant that otherwise is 
``subject to regulation'' as defined in 40 CFR 71.2.

0
5. Section 60.4326 is added to read as follows:


Sec.  60.4326  What CO2 emissions standard must I meet?

    You must not discharge from your affected stationary combustion 
turbine into the atmosphere any gases that contain CO2 in 
excess of the applicable CO2 emissions standard specified in 
Table 2 of this subpart.

0
6. Section 60.4333 is amended by adding paragraph (c) to read as 
follows:


Sec.  60.4333  What are my general requirements for complying with this 
subpart?

* * * * *
    (c) If you own or operate an affected stationary combustion turbine 
subject to a CO2 emissions standard in Sec.  60.4326, you 
must make compliance determinations on a 12-operating month rolling 
average basis, and you must determine compliance monthly by calculating 
the average CO2 emissions rate for the affected stationary

[[Page 1507]]

combustion turbine at the end of each 12-operating month period.

0
7. Section 60.4373 is added under undesignated center heading 
``Monitoring'' to read as follows:


Sec.  60.4373  How do I monitor and collect data to demonstrate 
compliance with my CO2 emissions standard using a 
CO2 CEMS?

    (a) You must prepare a monitoring plan in accordance with the 
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (b) You must measure the hourly CO2 mass emissions from 
each affected stationary combustion turbine using the procedures in 
paragraphs (b)(1) through (5) of this section, except as provided in 
paragraph (c) of this section.
    (1) You must install, certify, operate, maintain, and calibrate a 
CO2 continuous emission monitoring system (CEMS) to directly 
measure and record CO2 concentrations in the stationary 
combustion turbine exhaust gases emitted to the atmosphere and an 
exhaust gas flow rate monitoring system according to Sec.  
75.10(a)(3)(i) of this chapter. If you measure CO2 
concentration on a dry basis, you must also install, certify, operate, 
maintain, and calibrate a continuous moisture monitoring system, 
according to Sec.  75.11(b) of this chapter.
    (2) For each monitoring system that you use to determine the 
CO2 mass emissions, you must meet the applicable 
certification and quality assurance procedures in Sec.  75.20 of this 
chapter and Appendices B and D to part 75 of this chapter.
    (3) You must use a laser device to measure the dimensions of each 
exhaust gas stack or duct at the flow monitor and the reference method 
sampling locations prior to the initial setup (characterization) of the 
flow monitor. For circular stacks, you must make measure of the 
diameter at three or more distinct locations and average the results. 
For rectangular stacks or ducts, you must measure each dimension (i.e., 
depth and width) at three or more distinct locations and average the 
results. If the flow rate monitor or reference method sampling site is 
relocated, you must repeat these measurements at the new location.
    (4) You must use unadjusted exhaust gas volumetric flow rates only 
to determine the hourly CO2 mass emissions from the affected 
stationary combustion turbine; you must not apply the bias adjustment 
factors described in section 7.6.5 of Appendix A to part 75 of this 
chapter to the exhaust gas flow rate data.
    (5) If you chose to use Method 2 in Appendix A-1 to this part to 
perform the required relative accuracy test audits (RATAs) of the part 
75 flow rate monitoring system, you must use a calibrated Type-S pitot 
tube or pitot tube assembly. You must not use the default Type-S pitot 
tube coefficient.
    (c) As an alternative to complying with paragraph (b) of this 
section, you may determine the hourly CO2 mass emissions by 
using Equation G-4 in Appendix G to part 75 of this chapter according 
to the requirements specified in paragraphs (c)(1) and (2) of this 
section.
    (1) You must implement the applicable procedures in appendix D to 
part 75 of this chapter to determine hourly unit heat input rates 
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic 
determinations of the gross calorific value (GCV) of each fuel 
combusted.
    (2) You may determine site-specific carbon-based F-factors 
(Fc) using Equation F-7b in section 3.3.6 of Appendix F to 
part 75 of this chapter, and you may use these Fc values in 
the emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature.
    (d) You must install, calibrate, maintain, and operate a sufficient 
number of watt meters to continuously measure and record the gross 
electric output from the affected stationary combustion turbine. If the 
affected stationary combustion turbine is a CHP stationary combustion 
turbine, you must also install, calibrate, maintain, and operate meters 
to continuously determine and record the total useful recovered thermal 
energy. For process steam applications, you will need to install, 
calibrate, maintain, and operate meters to continuously determine and 
record steam flow rate, temperature, and pressure. If the affected 
stationary combustion turbine has a direct mechanical drive 
application, you must submit a plan to the Administrator or delegated 
authority for approval of how gross energy output will be determined. 
Your plan shall ensure that you install, calibrate, maintain, and 
operate meters to continuously determine and record each component of 
the determination.
    (e) If two or more affected stationary combustion turbines serve a 
common electric generator, you must apportion the combined hourly gross 
output to the individual stationary combustion turbines using a plan 
approved by the Administrator (e.g., using steam load or heat input to 
each affected stationary combustion turbine). Your plan shall ensure 
that you install, calibrate, maintain, and operate meters to 
continuously determine and record each component of the determination.
    (f) In accordance with Sec.  60.13(g), if two or more stationary 
combustion turbines that implement the continuous emission monitoring 
provisions in paragraph (b) of this section share a common exhaust gas 
stack and are subject to the same emissions standard under Sec.  
60.4326, you may monitor the hourly CO2 mass emissions at 
the common stack in lieu of monitoring each stationary combustion 
turbine separately. If you choose this option, the hourly gross load 
(electric, thermal, and/or mechanical, as applicable) must be the sum 
of the hourly loads for the individual stationary combustion turbines 
and you must express the operating time as ``stack operating hours'' 
(as defined in Sec.  72.2 of this chapter). If you attain compliance 
with the applicable emissions standard in Sec.  60.4326 at the common 
stack, each stationary combustion turbine sharing the stack is in 
compliance.
    (g) In accordance with Sec.  60.13(g), if the exhaust gases from a 
stationary combustion turbine that implements the continuous emission 
monitoring provisions in paragraph (b) of this section are emitted to 
the atmosphere through multiple stacks (or if the exhaust gases are 
routed to a common stack through multiple ducts and you chose to 
monitor in the ducts), you must monitor the hourly CO2 mass 
emissions and the ``stack operating time'' (as defined in Sec.  72.2 of 
this chapter) at each stack or duct separately. In this case, you 
determine compliance with the applicable emissions standard in Sec.  
60.4326 by summing the CO2 mass emissions measured at the 
individual stacks or ducts and dividing by the total gross output for 
the unit.
0
8. Section 60.4374 is added under undesignated center heading 
``Monitoring'' to read as follows:


Sec.  60.4374  How do I demonstrate compliance with my CO2 
emissions standard and determine excess emissions?

    (a) You must calculate the CO2 mass emissions rate for 
your affected stationary combustion turbine by using the hourly 
CO2 mass emissions and total gross output data determined 
and recorded according to the procedures in Sec.  60.4373 for the 
compliance period for the CO2 emissions standard applicable 
to the affected stationary combustion turbine, and the calculation 
procedures in paragraphs (a)(1) through (a)(5) of this section.
    (1) You must only use operating hours in the compliance period for 
the compliance determination calculation for which you obtained valid 
data for all

[[Page 1508]]

parameters you used to determine the hourly CO2 mass 
emissions and gross output data, are used for the compliance 
determination calculation. You must not include operating hours in 
which you used the substitute data provisions of part 75 of this 
chapter for any of the parameters in the calculation. For the 
compliance determination calculation, you must obtain valid hourly 
CO2 mass emission values for a minimum of 95 percent of the 
operating hours in the compliance period.
    (2) You must calculate the total CO2 mass emissions by 
summing the hourly CO2 mass emissions values for the 
affected stationary combustion turbine determined to be valid according 
to the conditions specified in paragraph (a)(1) of this section for all 
of the operating hours in the applicable compliance period.
    (3) For each operating hour of the compliance period used in 
paragraph (a)(2) of this section to calculate the total CO2 
mass emissions, you must determine the affected stationary combustion 
turbine's corresponding hourly gross output (Pgross) by 
applying the appropriate definitions in Sec. Sec.  60.4420 and 60.4421 
of this subpart and according to the procedures specified in paragraphs 
(a)(3)(i) and (iv) of this section.
    (i) Calculate Pgross for your affected stationary 
combustion turbine using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.002

    Where:
Pgross = Gross energy output of your affected stationary 
combustion turbine in megawatt-hours in MWh.
(Pe)CT = Electric energy output plus mechanical energy 
output (if any) of stationary combustion turbines in MWh.
(Pe)ST = Electric energy output plus mechanical energy 
output (if any) of steam turbines in MWh.
(Pe)IE = Electric energy output plus mechanical energy 
output (if any) of your affected stationary combustion turbine's 
integrated equipment that provides electricity to the affected 
facility or auxiliary equipment in MWh.
(Pt)PS = Useful thermal energy output of steam relative 
to ISO conditions that is used for applications that do not generate 
additional electricity, produce mechanical energy output, enhance 
the performance of the affected facility. Calculated using the 
equation specified in paragraph (a)(3)(ii) of this section in MWh.
(Pt)HR = Useful thermal energy output relative to ISO 
conditions from heat recovery that is used for applications other 
than steam generation or performance enhancement of the affected 
facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO 
conditions from any integrated equipment that provides input to the 
affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a CHP stationary combustion turbine where at least 
on an annual basis 20.0 percent of the total gross energy output 
consists of electric or direct mechanical output and 20.0 percent of 
the total gross energy output consists of useful thermal energy 
output on a rolling 3 year basis.
    T = 1.0 for all other affected stationary combustion turbines.

    (ii) If applicable to your affected stationary combustion turbine, 
calculate (Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.003

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds 
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure 
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (iii) You must determine the hourly gross energy output for each 
operating hour in which there is no electric output, but there is 
mechanical output or useful thermal output. In addition you must 
determine the hourly gross CO2 emissions for each operating 
hour in which there is no useful output.
    (iv) In the case for which compliance is demonstrated according to 
Sec.  60.4373(f) for affected stationary combustion turbines that vent 
to a common stack, then you must calculate the hourly gross energy 
output (electric, mechanical, and/or thermal, as applicable) by summing 
the hourly gross energy output you determined for each of your 
individual affected stationary combustion turbines that vent to the 
common stack; and you must express the operating time as ``stack 
operating hours'' (as defined in Sec.  72.2 of this chapter).
    (4) You must calculate the total gross output for the affected 
stationary combustion turbine's compliance period by summing the hourly 
gross output values for the affected stationary combustion turbine 
determined from paragraph (a)(2) of this section for all of the 
operating hours in the applicable compliance period.
    (5) You must calculate the CO2 mass emissions rate for 
the affected stationary combustion turbine by dividing the total 
CO2 mass emissions value as calculated according to the 
requirements of paragraph (a)(2) of this section by the total gross 
output value as calculated according to the requirements of paragraph 
(a)(4) of this section.
    (b) If the CO2 mass emissions rate for the affected 
stationary combustion turbine determined according to the procedures 
specified in paragraph (a) of this section is less than or equal to the 
CO2 emissions standard in Table 2 of this subpart applicable 
to the affected stationary combustion turbine, then your affected 
stationary combustion turbine is in compliance with the emissions 
standard. If the average CO2 mass emissions rate is greater 
than the CO2 emissions standard in Table 2 of this subpart 
applicable to the affected stationary combustion turbine, then your 
affected stationary combustion turbine has excess CO2 
emissions.
0
9. Section 60.4375 is amended by revising the section heading to read 
as follows:


Sec.  60.4375  What reports must I submit to comply with my 
NOX and SO2 emissions limits?

* * * * *
0
10. Section 60.4376 is added to read as follows:


Sec.  60.4376  What notifications and reports must I submit to comply 
with my CO2 emissions standard?

    (a)(1) You must prepare and submit the notifications specified in 
Sec. Sec.  60.7(a)(1) and (a)(3) and 60.19, as applicable to your 
affected stationary combustion turbine.
    (2) You must prepare and submit notifications specified in Sec.  
75.61 of this chapter, as applicable to your affected stationary 
combustion turbine.
    (b) You must prepare and submit reports according to paragraphs 
(b)(1) through (d) of this section, as applicable.
    (1) For stationary combustion turbines that are required, by Sec.  
60.4333(c), to conduct initial and on-going compliance determinations 
on a 12-operating month rolling average basis for the standard in Sec.  
60.4326, you must submit electronic quarterly reports as follows. After 
you

[[Page 1509]]

have accumulated the first 12-operating months for the affected 
stationary combustion turbine, you must submit a report for the 
calendar quarter that includes the 12th-operating month no later than 
30 days after the end of that quarter. Thereafter, you must submit a 
report for each subsequent calendar quarter, no later than 30 days 
after the end of the quarter.
    (2) In each quarterly report, you must include the following 
information, as applicable:
    (i) Each rolling average CO2 mass emissions rate for 
which the last (12th) operating month in a 12-operating month 
compliance period falls within the calendar quarter. You must calculate 
each average CO2 mass emissions rate according to the 
requirements of Sec.  60.4374. You must report the dates (month and 
year) of the 1st and 12th-operating months in each compliance period 
for which you performed a CO2 mass emissions rate 
calculation. If there are no compliance periods that end in the 
quarter, you must include a statement to that effect;
    (ii) If one or more compliance periods end in the quarter, you must 
identify each operating month in the calendar quarter with excess 
CO2 emissions;
    (iii) The percentage of valid CO2 mass emission rates 
(as defined in Sec.  60.4374) in each 12-operating month compliance 
period described in paragraph (b)(2)(i) of this section (i.e., the 
total number of valid CO2 mass emission rates in that period 
divided by the total number of operating hours in that period, 
multiplied by 100 percent); and
    (iv) The CO2 emissions standard (as identified in Table 
2 of this subpart) with which your affected stationary combustion 
turbine is complying.
    (3) The final quarterly report of each calendar year must contain 
the following:
    (i) Net electric output sold to an electric grid over the 4 
quarters of the calendar year; and
    (ii) The potential electric output of the stationary combustion 
turbine.
    (c) You must submit all electronic reports required under paragraph 
(b) of this section using the Emissions Collection and Monitoring Plan 
System (ECMPS) Client Tool provided by the Clean Air Markets Division 
in the Office of Atmospheric Programs of the EPA.
    (d) You must meet all applicable reporting requirements and submit 
reports as required under subpart G of part 75 of this chapter.
0
11. Section 60.4391 is added to read as follows:


Sec.  60.4391  What records must I maintain to comply with my 
CO2 emissions limits?

    (a) You must maintain records of the information you used to 
demonstrate compliance with this subpart as specified in Sec.  60.7(b) 
and (f).
    (b) You must follow the applicable recordkeeping requirements and 
maintain records as required under subpart F of part 75 of this 
chapter.
    (c) You must keep records of the calculations you performed to 
determine the total CO2 mass emissions for:
    (1) Each operating month (for all affected units);
    (2) Each compliance period, including, as applicable, each 12-
operating month compliance period.
    (d) You must keep records of the applicable data recorded and 
calculations performed that you used to determine your affected 
stationary combustion turbine's gross output for each operating month.
    (e) You must keep records of the calculations you performed to 
determine the percentage of valid CO2 mass emission rates in 
each compliance period.
    (f) You must keep records of the calculations you performed to 
assess compliance with each applicable CO2 mass emissions 
standard in Sec.  60.4326.
    (g) You must keep records of the calculations you performed to 
determine any site-specific carbon-based F-factors you used in the 
emissions calculations (if applicable).
    (h)(1) Your records must be in a form suitable and readily 
available for expeditious review.
    (2) You must keep each record for 5 years after the date of each 
occurrence, measurement, maintenance, corrective action, report, or 
record to demonstrate compliance with a 12-operating month emissions 
standard.
    (3) 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.  60.7. You may keep the 
records off site and electronically for the remaining year(s) as 
required by this subpart.
0
12. Section 60.4395 is revised to read as follows:


Sec.  60.4395  When must I submit my reports?

    All of your reports required under Sec.  60.7(c) must be postmarked 
by the 30th day after the end of each 6-month period, except as 
specified in Sec.  60.4376
0
13. Section 60.4421 is added to read as follows:


Sec.  60.4421  What definitions with respect to CO2 
emissions apply to this subpart?

    As used in this subpart:
    Base load rating means 100 percent of the manufacturer's design 
heat input capacity of the combustion turbine engine at ISO conditions 
using the higher heating value of the fuel (heat input from duct 
burners is not included).
    Excess emissions means a specified averaging period over which 
either:
    (1) The CO2 emissions rate of your affected stationary 
combustion turbine exceeds the applicable emissions standard in Table 2 
of this subpart or Sec.  60.4330; or
    (2) The recorded value of a particular monitored parameter is 
outside the acceptable range specified in the parameter monitoring plan 
for the affected unit.
    Gross energy output means:
    (1) The gross electric or direct mechanical output from both the 
combustion turbine engine and any associated steam turbine(s) or 
integrated equipment plus any useful thermal output measured relative 
to ISO conditions (except for GHG calculations in Sec.  60.4374 as only 
75 percent credit is given) that is not used to generate additional 
electric or mechanical output or to enhance the performance of the unit 
(e.g., steam delivered to an industrial process for a heating 
application).
    (2) For a CHP stationary combustion turbine where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and at least 20.0 percent of the total gross energy 
output consists of useful thermal output on a rolling 3-year basis, the 
sum of the gross electric or direct mechanical output from both the 
combustion turbine engine and any associated steam turbine(s) divided 
by 0.95 plus any useful thermal output measured relative to ISO 
conditions (except for GHG calculations in Sec.  60.4374 as only 75 
percent credit is given) that is not used to generate additional 
electric or mechanical output or to enhance the performance of the unit 
(e.g., steam delivered to an industrial process for a heating 
application).
    Net-electric output means:
    (1) The gross electric sales to the utility power distribution 
system minus purchased power on a 3 calendar year rolling average 
basis; or
    (2) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and at least 20.0 percent of the total gross energy 
output consists of useful thermal output on a 3 calendar year rolling 
average basis, the gross electric sales to the utility power 
distribution system minus purchased power of the thermal

[[Page 1510]]

host facility or facilities on a three calendar year rolling average 
basis.
    Operating month means a calendar month during which any fuel is 
combusted in the affected stationary combustion turbine.
    Potential electric output means 33 percent or the design electric 
output efficiency on a net output basis (at the election of the owner/
operator of the affected facility) multiplied by the base load rating 
(expressed in MMBtu/h) of the stationary combustion turbine, multiplied 
by 10\6\ Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, 
and multiplied by 8,760 h/yr (e.g., a 35 percent efficient stationary 
combustion turbine with a 100 MW (341 MMBtu/h) fossil-fuel heat input 
capacity would have a 310,000 MWh 12-month potential electric output 
capacity).
    Stationary combustion turbine means all equipment, including but 
not limited to the combustion turbine engine, the fuel, air, 
lubrication and exhaust gas systems, control systems, heat recovery 
system, steam turbine, fuel compressor, heater, and/or pump, post-
combustion emission control technology, and any ancillary components 
and sub-components plus any integrated equipment that provides 
electricity or useful thermal output to the combustion turbine engine, 
heat recovery system or auxiliary equipment. 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.
0
14. Table 2 to Subpart KKKK of Part 60 is added to read as follows:

 Table 2 to Subpart KKKK of Part 60--Carbon Dioxide Emission Limits for
                     Stationary Combustion Turbines
  [Note: all numerical values have a minimum of 2 significant figures]
------------------------------------------------------------------------
 Affected stationary combustion turbine       CO2 Emission standard
------------------------------------------------------------------------
Stationary combustion turbine that has   450 kilograms (kg) of CO2 per
 a design heat input to the turbine       megawatt-hour (MWh) of gross
 engine of greater than 250 MW            output (1,000 lb/MWh) on a 12-
 (850MMBtu/h).                            operating month rolling
                                          average.
Stationary combustion turbine that has   500 kg of CO2 per MWh of gross
 a design heat input to the turbine       output (1,100 lb CO2/MWh) on a
 engine greater than 73 MW (250 MMBtu/    12-operating month rolling
 h) and equal to or less than 250 MW      average.
 (850MMBtu/h).
------------------------------------------------------------------------

0
15. Table 3 to Subpart KKKK of Part 60 is added to read as follows:

   Table 3 to Subpart KKKK of Part 60--Applicability of Subpart a General Provisions to Stationary Combustion
                                 Turbine CO2 Emissions Standards in Subpart KKKK
----------------------------------------------------------------------------------------------------------------
                                                             Applies to
  General provisions citation      Subject of citation      subpart KKKK                 Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1....................  Applicability..........  Yes.              ....................................
Sec.   60.2....................  Definitions............  Yes.              ....................................
Sec.   60.3....................  Units and Abbreviations  Yes.              ....................................
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               Only the requirements to submit the
                                  Recordkeeping.                             notification in Sec.   60.7(a)(1)
                                                                             and (a)(3).
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 requirements  Yes.              ....................................
Sec.   60.14...................  Modification...........  No.               ....................................
Sec.   60.15...................  Reconstruction.........  No.               ....................................
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.
----------------------------------------------------------------------------------------------------------------

0
16. 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

Sec.

Applicability

60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?

Emission Standards

60.5515 What greenhouse gases are regulated by this subpart?
60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

60.5525 What are my general requirements for complying with this 
subpart?
60.5530 Affirmative defense for violation of emission standards 
during malfunction

Monitoring and Compliance Determination Procedures

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

[[Page 1511]]

60.5540 How do I demonstrate compliance with my CO2 
emissions standard and determine excess emissions?

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 maintain?
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 my affected 
facility?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?

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 a 
steam generating unit, IGCC, or a stationary combustion turbine that 
commences construction after [DATE OF PUBLICATION IN THE FEDERAL 
REGISTER].


Sec.  60.5509  Am I subject to this subpart?

    (a) Except as provided for in paragraph (b) of this section, the 
subpart applies to any steam generating unit, IGCC, or stationary 
combustion turbine that commences construction after [DATE OF 
PUBLICATION IN THE FEDERAL REGISTER] that meets the relevant 
applicability conditions in paragraphs (a)(1) and (a)(2) of this 
section.
    (1) A steam generating unit or IGCC that has a design heat input 
greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone 
or in combination with any other fuel), combusts fossil fuel for more 
than 10.0 percent of the average annual heat input during a 3 year 
rolling average basis, and was constructed for the purpose of 
supplying, and supplies, one-third or more of its potential electric 
output and more than 219,000 MWh net-electric output to a utility 
distribution system on an annual basis.
    (2) A stationary combustion turbine that has a design heat input to 
the turbine engine greater than 73 MW (250 MMBtu/h), combusts fossil 
fuel for more than 10.0 percent of the average annual heat input during 
a 3 year rolling average basis, combusts over 90% natural gas on a heat 
input basis on a 3 year rolling average basis, and was constructed for 
the purpose of supplying, and supplies, one-third or more of its 
potential electric output and more than 219,000 MWh net-electrical 
output to a utility distribution system on a 3 year rolling average 
basis.
    (b) You are not subject to the requirements of this subpart if your 
affected facility meets any one of the conditions specified in 
paragraphs (b)(1) through (b)(5) of this section.
    (1) The proposed Wolverine EGU project described in Permit to 
Install No. 317-07 issued by the Michigan Department of Environmental 
Quality, Air Quality Division, effective June 29, 2011 (as revised July 
12, 2011).
    (2) The proposed Washington County EGU project described in Air 
Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia 
Department of Natural Resources, Environmental Protection Division, Air 
Protection Branch, effective April 8, 2010, provided that construction 
had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE 
FEDERAL REGISTER].
    (3) The proposed Holcomb EGU project described in Air Emission 
Source Construction Permit 0550023 issued by the Kansas Department of 
Health and Environment, Division of Environment, effective December 16, 
2010, provided that construction had not commenced for NSPS purposes as 
of [DATE OF PUBLICATION IN THE FEDERAL REGISTER].
    (4) Your affected facility is a municipal waste combustor unit that 
is subject to subpart Eb of this part.
    (5) Your affected facility is a commercial or industrial solid 
waste incineration unit that is subject to subpart CCCC of this part.

Emission Standards


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

    (a) The greenhouse gas regulated by this subpart is carbon dioxide 
(CO2).
    (b) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG 
emissions from affected facilities, the ``pollutant that is subject to 
the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP 
approved by the EPA that is interpreted to incorporate, or specifically 
incorporates, 40 CFR 51.166(b)(48).
    (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG 
emissions from affected facilities, the ``pollutant that is subject to 
the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Act as defined in 40 CFR 52.21(b)(49).
    (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 70.2.
    (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 71.2.


Sec.  60.5520  What CO2 emissions standard must I meet?

    For each affected facility subject to this subpart, you must not 
discharge from the affected facility stack into the atmosphere any 
gases that contain CO2 in excess of the applicable 
CO2 emissions standard specified in Table 1 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 emission standards in this 
subpart that apply to your affected facility at all times. However, you 
must make a compliance determination only at the end of the applicable 
operating month, as provided in paragraphs (a)(1) and (2) of this 
section.
    (1) For each affected facility subject to a CO2 
emissions standard based on a 12-operating month rolling average, you 
must determine compliance monthly by calculating the average 
CO2 emissions rate for the affected facility at the end of 
each 12-operating month period.
    (2) For each affected facility subject to a CO2 
emissions standard based on an 84-operating month rolling average, you 
must determine compliance monthly by calculating the average 
CO2 emissions rate for the affected facility at the end of 
each 84-operating month period.
    (b) At all times you must operate and maintain each affected 
facility, including associated equipment and monitoring equipment, in a 
manner consistent with safety and good air pollution control practice. 
The Administrator will determine if you are using consistent operation 
and maintenance procedures based on information available to the 
Administrator that may include, but is not limited to, fuel use 
records, monitoring results, review of operation and maintenance 
procedures and

[[Page 1512]]

records, review of reports required by this subpart, and inspection of 
the facility.
    (c) You must conduct an initial compliance determination for your 
affected facility for the applicable emissions standard in Sec.  
60.5520, according to the requirements in this subpart, within 30 days 
after the end of the initial compliance period for the CO2 
emissions standards applicable to your affected facility (i.e., 12-
operating months or 84-operating months). The first operating month 
included in this compliance period is the month in which emissions 
reporting is required to begin under Sec.  75.64(a) of this chapter.


Sec.  60.5530  Affirmative defense for violation of emission standards 
during malfunction.

    In response to an action to enforce the standards set forth in 
Sec.  60.5520, you may assert an affirmative defense to a claim for 
civil penalties for violations of such standards that are caused by 
malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be 
assessed if you fail to meet your burden of proving all of the 
requirements in the affirmative defense. The affirmative defense shall 
not be available for claims for injunctive relief.
    (a) Assertion of affirmative defense. To establish the affirmative 
defense in any action to enforce such a standard, you must timely meet 
the reporting requirements in paragraph (b) of this section, and must 
prove by a preponderance of evidence that:
    (1) The violation:
    (i) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control equipment, process equipment, or a process to 
operate in a normal or usual manner; and
    (ii) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices;
    (iii) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for;
    (iv) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance;
    (2) Repairs were made as expeditiously as possible when the 
violation occurred;
    (3) The frequency, amount and duration of the violation (including 
any bypass) were minimized to the maximum extent practicable;
    (4) If the violation 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 possible steps were taken to minimize the impact of the 
violation on ambient air quality, the environment, and human health;
    (6) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices;
    (7) All of the actions in response to the violation were documented 
by properly signed, contemporaneous operating logs;
    (8) At all times, the affected source 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 violation resulting from the malfunction event at 
issue. The analysis shall also specify, using best monitoring methods 
and engineering judgment, the amount of any emissions that were the 
result of the malfunction.
    (b) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator to 
demonstrate, with all necessary supporting documentation, that it has 
met the requirements set forth in paragraph (a) of this section. This 
affirmative defense report is due after the initial occurrence of the 
exceedance of the standard in Sec.  60.5520, and on the same quarterly 
reporting schedule as in Sec.  60.5555 (which may be the end of any 
applicable averaging period). If such quarterly report is due less than 
45 days after the initial occurrence of the violation, the affirmative 
defense report may be included in the following quarterly report 
required in Sec.  60.5555(a).

Monitoring and Compliance Determination Procedures


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

    (a) You must prepare a monitoring plan in accordance with the 
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (b) You must measure the hourly CO2 mass emissions from 
each affected facility using the procedures in paragraphs (b)(1) 
through (5) of this section, except as provided in paragraph (c) of 
this section.
    (1) You must install, certify, operate, maintain, and calibrate a 
CO2 continuous emission monitoring system (CEMS) to directly 
measure and record CO2 concentrations in the affected 
facility exhaust gases emitted to the atmosphere and an exhaust gas 
flow rate monitoring system according to Sec.  75.10(a)(3)(i) of this 
chapter. If you measure CO2 concentration on a dry basis, 
you must also install, certify, operate, maintain, and calibrate a 
continuous moisture monitoring system, according to Sec.  75.11(b) of 
this chapter.
    (2) For each monitoring system you use to determine the 
CO2 mass emissions, you must meet the applicable 
certification and quality assurance procedures in Sec.  75.20 of this 
chapter and Appendices B and D to part 75 of this chapter.
    (3) You must use a laser device to measure the dimensions of each 
exhaust gas stack or duct at the flow monitor and the reference method 
sampling locations prior to the initial setup (characterization) of the 
flow monitor. For circular stacks, you must measure the diameter at 
three or more distinct locations and average the results. For 
rectangular stacks or ducts, you must measure each dimension (i.e., 
depth and width) at three or more distinct locations and average the 
results. If the flow rate monitor or reference method sampling site is 
relocated, you must repeat these measurements at the new location.
    (4) You must use only unadjusted exhaust gas volumetric flow rates 
to determine the hourly CO2 mass emissions from the affected 
facility; you must not apply the bias adjustment factors described in 
section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust 
gas flow rate data.
    (5) If you choose to use Method 2 in Appendix A-1 to this part to 
perform the required relative accuracy test audits (RATAs) of the part 
75 flow rate monitoring system, you must use a calibrated Type-S pitot 
tube or pitot tube assembly. You must not use the default Type-S pitot 
tube coefficient.
    (c) If your affected facility exclusively combusts liquid fuel and/
or gaseous fuel as an alternative to complying with paragraph (b) of 
this section, you may determine the hourly CO2 mass 
emissions by using Equation G-4 in Appendix G to part 75 of this 
chapter according to the requirements in paragraphs (c)(1) and (2) of 
this section.
    (1) You must implement the applicable procedures in appendix D to 
part 75 of this chapter to determine hourly unit heat input rates 
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic 
determinations of the gross calorific value (GCV) of each fuel 
combusted.
    (2) You may determine site-specific carbon-based F-factors 
(Fc) using Equation F-7b in section 3.3.6 of appendix F to 
part 75 of this chapter, and you may use these Fc values in 
the emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature.

[[Page 1513]]

    (d) You must install, calibrate, maintain, and operate a sufficient 
number of watt meters to continuously measure and record the gross 
electric output from the affected facility. If the affected facility is 
a CHP facility, you must also install, calibrate, maintain, and operate 
meters to continuously determine and record the total useful recovered 
thermal energy. For process steam applications, you will need to 
install, calibrate, maintain, and operate meters to continuously 
determine and record steam flow rate, temperature, and pressure. If the 
affected facility has a direct mechanical drive application, you must 
submit a plan to the Administrator or delegated authority for approval 
of how gross energy output will be determined. Your plan shall ensure 
that you install, calibrate, maintain, and operate meters to 
continuously determine and record each component of the determination.
    (e) If two or more affected facilities serve a common electric 
generator, you must apportion the combined hourly gross output to the 
individual affected facilities using a plan approved by the 
Administrator (e.g., using steam load or heat input to each affected 
EGU). Your plan shall ensure that you install, calibrate, maintain, and 
operate meters to continuously determine and record each component of 
the determination.
    (f) In accordance with Sec.  60.13(g), if two or more affected 
facilities that implement the continuous emission monitoring provisions 
in paragraph (b) of this section share a common exhaust gas stack and 
are subject to the same emissions standard under Sec.  60.5520, you may 
monitor the hourly CO2 mass emissions at the common stack in 
lieu of monitoring each EGU separately. If you choose this option, the 
hourly gross load (electric, thermal, and/or mechanical, as applicable) 
must be the sum of the hourly loads for the individual affected 
facility and you must express the operating time as ``stack operating 
hours'' (as defined in Sec.  72.2 of this chapter). If you attain 
compliance with the applicable emissions standard in Sec.  60.5520 at 
the common stack, each affected facility sharing the stack is in 
compliance.
    (g) In accordance with Sec.  60.13(g), if the exhaust gases from an 
affected facility that implements the continuous emission monitoring 
provisions in paragraph (b) of this section are emitted to the 
atmosphere through multiple stacks (or if the exhaust gases are routed 
to a common stack through multiple ducts and you elect to monitor in 
the ducts), you must monitor the hourly CO2 mass emissions 
and the ``stack operating time'' (as defined in Sec.  72.2 of this 
chapter) at each stack or duct separately. In this case, you must 
determine compliance with the applicable emissions standard in Sec.  
60.5520 by summing the CO2 mass emissions measured at the 
individual stacks or ducts and dividing by the total gross output for 
the affected facility.


Sec.  60.5540  How do I demonstrate compliance with my CO2 
emissions standard and determine excess emissions?

    (a) You must calculate the CO2 mass emissions rate for 
your affected facility by using the hourly CO2 mass 
emissions and total gross output data determined and recorded according 
to the procedures in Sec.  60.5535 for each operating hour in the 
compliance period for the CO2 emissions standard applicable 
to the affected facility (i.e., 12- or 84-operating month rolling 
average period), and the calculation procedures in paragraphs (a)(1) 
through (a)(5) of this section.
    (1) You can only use operating hours in the compliance period for 
the compliance determination calculation if valid data are obtained for 
all parameters you used to determine the hourly CO2 mass 
emissions and the gross output data are used for the compliance 
determination calculation. You must not include operating hours in 
which you used the substitute data provisions of part 75 of this 
chapter for any of those parameters in the calculation. For the 
compliance determination calculation, you must obtain valid hourly 
CO2 mass emission values for a minimum of 95 percent of the 
operating hours in the compliance period for the CO2 
emissions standard applicable to the affected facility.
    (2) You must calculate the total CO2 mass emissions by 
summing the valid hourly CO2 mass emissions values for all 
of the operating hours in the applicable compliance period.
    (3) For each operating hour of the compliance period that you used 
in paragraph (a)(2) of this section to calculate the total 
CO2 mass emissions, you must determine the affected 
facility's corresponding hourly gross output according to the 
procedures in paragraphs (a)(3)(i) and (ii) of this section, as 
appropriate for the type of affected facility. For an operating hour in 
which there is no gross electric load, but there is mechanical or 
useful thermal output, you must still determine the gross output for 
that hour. In addition, for operating hours in which there is no useful 
output, you still need to determine the CO2 emissions for 
that hour.
    (i) Calculate Pgross for your affected facility using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.004

Where: a
Pgross = Gross energy output of your affected facility in 
megawatt-hours in MWh.
(Pe)ST = Electric energy output plus mechanical energy 
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy 
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy 
output (if any) of your affected facility's integrated equipment 
that provides electricity or mechanical energy to the affected 
facility or auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater 
pumps at steam generating units in MWh. Not applicable to stationary 
combustion turbines or IGCC facilities.
(Pt)PS = Useful thermal energy output of steam measured 
relative to ISO conditions that is used for applications that do not 
generate additional electricity, produce mechanical energy output, 
or enhance the performance of the affected facility. Calculated 
using the equation specified in paragraph (g)(3)(iii)(B) of this 
section in MWh.
(Pt)HR = Hourly useful thermal energy output measured 
relative to ISO conditions from heat recovery that is used for 
applications other than steam generation or performance enhancement 
of the affected facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO 
conditions from any integrated equipment that provides thermal 
energy to the affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a combined heat and power affected facility where 
at least on an annual basis 20.0 percent of the total gross energy 
output consists of electric or direct mechanical output and 20.0 
percent of the total gross energy output consists of useful thermal 
energy output on a rolling 3 year basis.
    T = 1.0 for all other affected facilities.


[[Page 1514]]


    (ii) If applicable to your affected facility, you must calculate 
(Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.005

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds 
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure 
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (4) You must calculate the total gross output for the affected 
facility's compliance period by summing the hourly gross output values 
for the affected facility that you determined from paragraph (a)(2) of 
this section for all of the operating hours in the applicable 
compliance period.
    (5) You must calculate the CO2 mass emissions rate for 
the affected facility by dividing the total CO2 mass 
emissions value calculated according to the procedures in paragraph 
(a)(2) of this section by the total gross output value calculated 
according to the procedures in paragraph (a)(4) of this section.
    (b) If the CO2 mass emissions rate for your affected 
facility that you determined according to the procedures specified in 
paragraph (a) of this section is less than or equal to the 
CO2 emissions standard in Table 1 of this subpart applicable 
to the affected facility, then your affected facility is in compliance 
with the emissions standard. If the average CO2 mass 
emissions rate is greater than the CO2 emissions standard in 
Table 1 of this subpart applicable to the affected facility, then your 
affected facility has excess CO2 emissions.

Notification, Reports, and Records


Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit the notifications specified in 
Sec. Sec.  60.7(a)(1) and (a)(3) and 60.19, as applicable to your 
affected facility.
    (b) You must prepare and submit notifications specified in Sec.  
75.61 of this chapter, as applicable to your affected facility.


Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports according to paragraphs (a) 
through (d) of this section, as applicable.
    (1) For affected facilities that are required by Sec.  60.5525 to 
conduct initial and on-going compliance determinations on a 12- or 84-
operating month rolling average basis for the standard in Sec.  60.5520 
you must submit electronic quarterly reports as follows. After you have 
accumulated the first 12-operating months for the affected facility 
(or, the first 84-operating months for an affected facility electing to 
comply with the 84-operating month standard), you must submit a report 
for the calendar quarter that includes the twelfth (or eighty-fourth) 
operating month no later than 30 days after the end of that quarter. 
Thereafter, you must submit a report for each subsequent calendar 
quarter, no later than 30 days after the end of the quarter.
    (2) In each quarterly report you must include the following 
information, as applicable:
    (i) Each rolling average CO2 mass emissions rate for 
which the last (12th or eighty-fourth) operating month in a 12- or 84-
operating month compliance period falls within the calendar quarter. 
You must calculate each average CO2 mass emissions rate 
according to the procedures in Sec.  60.5540. You must report the dates 
(month and year) of the first and twelfth (or eighty-fourth) operating 
months in each compliance period for which you performed a 
CO2 mass emissions rate calculation. If there are no 
compliance periods that end in the quarter, you must include a 
statement to that effect;
    (ii) If one or more compliance periods end in the quarter you must 
identify each operating month in the calendar quarter with excess 
CO2 emissions;
    (iii) The percentage of valid CO2 mass emission rates 
(as defined in Sec.  60.5540) in each 12- or 84-operating month 
compliance period described in paragraph (a)(1)(i) of this section 
(i.e., the total number of valid CO2 mass emission rates in 
that period divided by the total number of operating hours in that 
period, multiplied by 100 percent); and
    (iv) The CO2 emissions standard (as identified in Table 
1 of this subpart) with which your affected facility is complying.
    (3) In the final quarterly report of each calendar year, you must 
include the following:
    (i) Gross electric output sold to an electric grid over the 4 
quarters of the calendar year; and
    (ii) The potential electric output of the facility.
    (b) You must submit all electronic reports required under paragraph 
(a) of this section using the Emissions Collection and Monitoring Plan 
System (ECMPS) Client Tool provided by the Clean Air Markets Division 
in the Office of Atmospheric Programs of EPA.
    (c) You must meet all applicable reporting requirements and submit 
reports as required under subpart G of part 75 of this chapter.
    (d) If your affected unit employs geologic sequestration to meet 
the applicable emission limit, you must report in accordance with the 
requirements of 40 CFR part 98, subpart PP and either:
    (1) if injection occurs onsite, report in accordance with the 
requirements of 40 CFR part 98, subpart RR, or
    (2) if injection occurs offsite, transfer the captured 
CO2 to a facility or facilities that reports in accordance 
with the requirements of 40 CFR part 98, subpart RR.


Sec.  60.5560  What records must I maintain?

    (a) You must maintain records of the information you used to 
demonstrate compliance with this subpart as specified in Sec.  60.7(b) 
and (f).
    (b) You must follow the applicable recordkeeping requirements and 
maintain records as required under subpart F of part 75 of this 
chapter.
    (c) You must keep records of the calculations you performed to 
determine the total CO2 mass emissions for:
    (1) Each operating month (for all affected units);
    (2) Each compliance period, including, as applicable, each 12-
operating month compliance period and the 84-operating month compliance 
period.
    (d) You must keep records of the applicable data recorded and 
calculations performed that you used to determine your affected 
facility's gross output for each operating month.
    (e) You must keep records of the calculations you performed to 
determine the percentage of valid CO2 mass emission rates in 
each compliance period.
    (f) You must keep records of the calculations you performed to 
assess compliance with each applicable CO2 mass emissions 
standard in Sec.  60.5520.
    (g) You must keep records of the calculations you performed to 
determine any site-specific carbon-based F-factors you used in the 
emissions calculations (if applicable).


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 maintain each record for 5 years after the date of 
each occurrence, measurement, maintenance, corrective action, report, 
or record except those records required to demonstrate

[[Page 1515]]

compliance with an 84-operating month compliance period. You must 
maintain records required to demonstrate compliance with an 84-
operating month compliance period for at least 10 years following the 
date of each occurrence, measurement, maintenance, corrective action, 
report, or record.
    (c) You must maintain 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.  60.7. You may maintain 
the records off site and electronically for the remaining year(s) as 
required by this subpart.

Other Requirements and Information


Sec.  60.5570  What parts of the General Provisions apply to my 
affected facility?

    Notwithstanding any other provision of this chapter, certain parts 
of the General Provisions in Sec. Sec.  60.1 through 60.19, listed in 
Table 2 of this subpart, do not apply to your affected facility.


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 Administrator retains 
the authorities listed in paragraphs (b)(1) through (5) of this section 
and does not transfer them to the state, local, or tribal agency. In 
addition, 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, 
baseload means 100 percent of the design heat input capacity of the 
simple cycle portion of the stationary combustion turbine at ISO 
conditions (heat input from duct burners is not included).
    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 facility means an electric generating unit that uses 
a stationary combustion turbine from which the heat from the turbine 
exhaust gases is recovered by a heat recovery steam generating unit to 
generate additional electricity.
    Combined heat and power facility or CHP facility, (also known as 
``cogeneration'') means an electric generating unit that that use a 
steam-generating unit or stationary combustion turbine to 
simultaneously produce both electric (or mechanical) and useful thermal 
energy from the same primary energy source.
    Distillate oil means fuel oils that contain no more than 0.05 
weight percent nitrogen 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).
    Excess emissions means a specified averaging period over which the 
CO2 emissions rate is higher than the applicable emissions 
standard located in Table 1 of this subpart.
    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 ISO 
conditions and includes, but is not limited to, natural gas, refinery 
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Gross energy output means:
    (1) For stationary combustion turbines and IGCC facilities, the 
gross electric or direct mechanical output from both the unit 
(including, but not limited to, output from steam turbine(s), 
combustion turbine(s), and gas expander(s)) plus 75 percent of the 
useful thermal output measured relative to ISO conditions that is not 
used to generate additional electric or mechanical output or to enhance 
the performance of the unit (e.g., steam delivered to an industrial 
process for a heating application).
    (2) For electric utility steam generating units, the gross electric 
or mechanical output from the affected facility (including, but not 
limited to, output from steam turbine(s), combustion turbine(s), and 
gas expander(s)) minus any electricity used to power the feedwater 
pumps plus 75 percent of the useful thermal output measured relative to 
ISO conditions that is not used to generate additional electric or 
mechanical output or to enhance the performance of the unit (e.g., 
steam delivered to an industrial process for a heating application);
    (3) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and 20.0 percent of the total gross energy output 
consists of thermal output on a rolling 3 year basis, the gross 
electric or mechanical output from the affected facility (including, 
but not limited to, output from steam turbine(s), combustion 
turbine(s), and gas expander(s)) minus any electricity used to power 
the feedwater pumps (the electric auxiliary load of boiler feedwater 
pumps is not applicable to

[[Page 1516]]

IGCC facilities), that difference divided by 0.95, plus 75 percent of 
the useful thermal output measured relative to ISO conditions that is 
not used to generate additional electric or mechanical output or to 
enhance the performance of the unit (e.g., steam delivered to an 
industrial process for a heating application).
    Heat recovery steam generating unit (HRSG) means a unit in which 
hot exhaust gases from the combustion turbine engine are routed in 
order to extract heat from the gases and generate useful output. Heat 
recovery steam generating units can be used with or without duct 
burners.
    Integrated gasification combined cycle facility or IGCC facility 
means a combined cycle stationary combustion 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, startup and 
commissioning, shutdown, 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.
    Liquid fuel means any fuel that is present as a liquid at ISO 
conditions and includes, but is not limited to, distillate oil and 
residual oil.
    Mechanical output means the useful mechanical energy that is not 
used to operate the affected facility, generate electricity and/or 
thermal energy, or to enhance the performance of the affected facility. 
Mechanical energy measured in horsepower hour should be converted into 
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    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:
    (1) The gross electric sales to the utility power distribution 
system minus purchased power on a three calendar year rolling average 
basis; or
    (2) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and at least 20.0 percent of the total gross energy 
output consists of useful thermal output on a 3 calendar year rolling 
average basis, the gross electric sales to the utility power 
distribution system minus purchased power of the thermal host facility 
or facilities on a three calendar year rolling average basis.
    Oil means crude oil or petroleum or a fuel derived from crude oil 
or petroleum, including distillate and residual oil, and gases derived 
from solid oil-derived fuels (not meeting the definition of natural 
gas).
    Operating month means a calendar month during which any fuel is 
combusted in the affected facility at any time.
    Potential electric output means 33 percent or the design electric 
output efficiency on a net output basis multiplied by the maximum 
design heat input capacity (expressed in MMBtu/h) of the steam 
generating unit, multiplied by 10\6\ Btu/MMBtu, divided by 3,413 Btu/
KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 
percent efficient affected facility with a 100 MW (341 MMBtu/h) fossil-
fuel heat input capacity would have a 310,000 MWh 12 month potential 
electric output capacity).
    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 engine, 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 plus any 
integrated equipment that provides electricity or useful thermal output 
to the combustion turbine engine, heat recovery system or auxiliary 
equipment. 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. If a stationary 
combustion turbine burns any solid fuel directly it is considered a 
steam generating unit.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel and producing steam (nuclear steam generators 
are not included) plus any integrated equipment that provides 
electricity or useful thermal output to the affected facility or 
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 electric generation, mechanical 
output at the affected facility, or to enhance the performance of the 
affected facility. 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--CO2 Emission Standards
  [Note: all numerical values have a minimum of 2 significant figures]
------------------------------------------------------------------------
           Affected facility                  CO2 Emission standard
------------------------------------------------------------------------
Stationary combustion turbine that has   450 kilograms (kg) of CO2 per
 a base load rating heat input to the     megawatt-hour (MWh) of gross
 turbine engine of greater than 250 MW    output (1,000 lb/MWh) on a 12-
 (850MMBtu/h).                            operating month rolling
                                          average.
Stationary combustion turbine that has   500 kg of CO2 per MWh of gross
 a design heat input to the turbine       output (1,100 lb CO2/MWh) on a
 engine greater than 73 MW (250 MMBtu/    12-operating month rolling
 h) and equal to or less than 250 MW      average.
 (850MMBtu/h).

[[Page 1517]]

 
Steam generating unit..................  500 kg of CO2 per MWh of gross
                                          energy output (1,100 lb CO2/
                                          MWh) on a 12-operating month
                                          rolling average basis;
                                         or
                                         480 kg of CO2 per MWh of gross
                                          energy output (1,050 lb CO2/
                                          MWh) on an 84-operating month
                                          rolling average basis.
Integrated gasification combined cycle   500 kg of CO2 per MWh of gross
 (IGCC) facility.                         energy output (1,100 lb CO2/
                                          MWh) on a 12-operating month
                                          rolling average basis;
                                         or
                                         480 kg of CO2 per MWh of gross
                                          energy output (1,050 lb CO2/
                                          MWh) on an 84-operating month
                                          rolling average basis.
------------------------------------------------------------------------


        Table 2 to Subpart TTTT of Part 60--Applicability of Subpart a General Provisions to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
                                                             Applies to
  General provisions citation      Subject of citation      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 Abbreviations  Yes.............
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.............  Only the requirements to submit the
                                  Recordkeeping.                             notification in Sec.   60.7(a)(1)
                                                                             and (a)(3).
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 requirements  Yes.............
Sec.   60.14...................  Modification...........  No..............
Sec.   60.15...................  Reconstruction.........  No..............
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.
----------------------------------------------------------------------------------------------------------------

PART 70--STATE OPERATING PERMIT PROGRAMS

0
17. The authority citation for part 70 continues to read as follows:

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

0
18. Section 70.2 is amended:
0
a. By adding in alphabetical order the definition of ``Greenhouse 
gases,''
0
b. By revising the introductory text, removing ``or'' from the end of 
paragraph (2), adding ``or'' to the end of paragraph (3), and adding 
paragraph (4) to the definition of ``Regulated pollutant (for 
presumptive fee calculation),'' and
0
c. By revising paragraph (1) to the definition of ``Subject to 
regulation.''
    The revision and additions read as follows:


Sec.  70.2  Definitions.

* * * * *
    Greenhouse gases (GHGs) means the air pollutant defined in Sec.  
86.1818-12(a) of this chapter as the aggregate group of six greenhouse 
gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, 
perfluorocarbons, and sulfur hexafluoride.
* * * * *
    Regulated pollutant (for presumptive fee calculation), which is 
used only for purposes of Sec.  70.9(b)(2), means any regulated air 
pollutant except the following:
* * * * *
    (4) Greenhouse gases.
* * * * *
    Subject to regulation * * *
    (1) Greenhouse gases shall not be subject to regulation unless, as 
of July 1, 2011, the GHG emissions are at a stationary source emitting 
or having the potential to emit 100,000 tpy CO2 equivalent 
emissions.
* * * * *
0
19. Section 70.9 is amended by revising paragraph (b)(2)(i), and by 
adding paragraph (b)(2)(v) to read as follows:


Sec.  70.9  Fee determination and certification.

* * * * *
    (b) * * *
    (2)(i) The Administrator will presume that the fee schedule meets 
the requirements of paragraph (b)(1) of this section if it would result 
in the collection and retention of an amount not less than $25 per year 
[as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) 
of this section] times the total tons of the actual emissions of each 
regulated pollutant (for presumptive fee calculation) emitted from part 
70 sources and any GHG cost adjustment required under paragraph 
(b)(2)(v) of this section.
* * * * *
    (v) GHG cost adjustment. The amount calculated in paragraph 
(b)(2)(i) of this section shall be increased by the GHG cost adjustment 
determined as follows:

[[Page 1518]]

For each activity identified in the following table, multiply the 
number of activities performed by the permitting authority by the 
burden hours per activity, and then calculate a total number of burden 
hours for all activities. Next, multiply the burden hours by the 
average cost of staff time, including wages, employee benefits and 
overhead.

 
------------------------------------------------------------------------
                                                                Burden
                          Activity                             hours per
                                                               activity
------------------------------------------------------------------------
GHG completeness determination (for initial permit or                 43
 updated application).......................................
GHG evaluation for a modification or related permit action..           7
GHG evaluation at permit renewal............................          10
------------------------------------------------------------------------

* * * * *

PART 71--FEDERAL OPERATING PERMIT PROGRAMS

0
20. The authority citation for part 71 continues to read as follows:

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

0
21. Section 71.2 is amended:
0
a. By adding in alphabetical order the definition of ``Greenhouse 
gases,''
0
b. By removing ``or'' from the end of paragraph (2), adding ``or'' to 
the end of paragraph (3), and adding paragraph (4) to the definition of 
``Regulated pollutant (for fee calculation),'' and
0
c. By revising paragraph (1) of the definition of ``Subject to 
regulation.''
    The revisions and additions read as follows:


Sec.  71.2  Definitions.

* * * * *
    Greenhouse gases (GHGs) means the air pollutant defined in Sec.  
86.1818-12(a) of this chapter as the aggregate group of six greenhouse 
gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, 
perfluorocarbons, and sulfur hexafluoride.
* * * * *
    Regulated pollutant (for fee calculation), which is used only for 
purposes of Sec.  71.9(c), means any ``regulated air pollutant'' except 
the following:
* * * * *
    (4) Greenhouse gases.
* * * * *
    Subject to regulation * * *
    (1) Greenhouse gases shall not be subject to regulation unless, as 
of July 1, 2011, the GHG emissions are at a stationary source emitting 
or having the potential to emit 100,000 tpy CO2 equivalent 
emissions.
* * * * *
0
22. Section 71.9 is amended by:
0
a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and
0
b. Adding paragraph (c)(8).
    The revisions and additions read as follows:


Sec.  71.9  Permit fees.

* * * * *
    (c) * * *
    (1) For part 71 programs that are administered by EPA, each part 71 
source shall pay an annual fee which is the sum of:
    (i) $32 per ton (as adjusted pursuant to the criteria set forth in 
paragraph (n)(1) of this section) times the total tons of the actual 
emissions of each regulated pollutant (for fee calculation) emitted 
from the source, including fugitive emissions; and
    (ii) Any GHG fee adjustment required under paragraph (c)(8) of this 
section.
    (2) * * *
    (i) Where the EPA has not suspended its part 71 fee collection 
pursuant to paragraph (c)(2)(ii) of this section, the annual fee for 
each part 71 source shall be the sum of:
    (A) $24 per ton (as adjusted pursuant to the criteria set forth in 
paragraph (n)(1) of this section) times the total tons of the actual 
emissions of each regulated pollutant (for fee calculation) emitted 
from the source, including fugitive emissions; and
    (B) Any GHG fee adjustment required under paragraph (c)(8) of this 
section.
* * * * *
    (3) For part 71 programs that are administered by EPA with 
contractor assistance, the per ton fee shall vary depending on the 
extent of contractor involvement and the cost to EPA of contractor 
assistance. The EPA shall establish a per ton fee that is based on the 
contractor costs for the specific part 71 program that is being 
administered, using the following formula: Cost per ton = (E x 32) + 
[(1- E) x $ C]
    Where E represents EPA's proportion of total effort (expressed as a 
percentage of total effort) needed to administer the part 71 program, 
1- E represents the contractor's effort, and C represents the 
contractor assistance cost on a per ton basis. C shall be computed by 
using the following formula: C = [ B + T + N] divided by 12,300,000
    Where B represents the base cost (contractor costs), where T 
represents travel costs, and where N represents nonpersonnel data 
management and tracking costs. In addition, each part 71 source shall 
pay a GHG fee adjustment for each activity as required under paragraph 
(c)(8) of this section.
    (4) For programs that are delegated in part, the fee shall be 
computed using the following formula: Cost per ton = (E x 32) + (D x 
24) + [(1- E - D) x $ C]
    Where E and D represent, respectively, the EPA and delegate agency 
proportions of total effort (expressed as a percentage of total effort) 
needed to administer the part 71 program, 1- E - D represents the 
contractor's effort, and C represents the contractor assistance cost on 
a per ton basis. C shall be computed using the formula for contractor 
assistance cost found in paragraph (c)(3) of this section and shall be 
zero if contractor assistance is not utilized. In addition, each part 
71 source shall pay a GHG fee adjustment for each activity as required 
under paragraph (c)(8) of this section.
* * * * *
    (8) GHG fee adjustment. The annual fee shall be increased by a GHG 
fee adjustment for any source that has initiated an activity listed in 
the following table since the fee was last paid. The GHG fee adjustment 
shall be equal to the set fee provided in the table for each activity 
that has been initiated since the fee was last paid:

------------------------------------------------------------------------
                           Activity                              Set fee
------------------------------------------------------------------------
GHG completeness determination (for initial permit or updated     $2,236
 application).................................................
GHG evaluation for a permit modification or related permit           364
 action.......................................................
GHG evaluation at permit renewal..............................       520
------------------------------------------------------------------------

* * * * *

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
23. The authority citation for part 98 is revised to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart PP--Suppliers of Carbon Dioxide

0
24. Section 98.426 is amended by adding paragraph (h) to read as 
follows:


Sec.  98.426   Data reporting requirements.

* * * * *
    (h) If you capture a CO2 stream from an electricity 
generating unit that is subject to subpart D of this part and transfer 
CO2 to any facilities that are subject to subpart RR of this 
part, you must:
    (1) Report the facility identification number associated with the 
annual GHG report for the facility that is subject to subpart D of this 
part,
    (2) Report each facility identification number associated with the 
annual GHG

[[Page 1519]]

reports for each facility that is subject to subpart RR of this part to 
which CO2 is transferred, and
    (3) Report the annual quantity of CO2 in metric tons 
that is transferred to each facility that is subject to subpart RR of 
this part.
0
25. Section 98.427 is amended by adding paragraph (d) to read as 
follows:


Sec.  98.427  Records that must be retained.

* * * * *
    (d) Facilities subject to Sec.  98.426(h) must retain records of 
CO2 in metric tons that is transferred to each facility that 
is subject to subpart RR of this part.
[FR Doc. 2013-28668 Filed 12-27-13; 8:45 am]
BILLING CODE 6560-50-P