[Federal Register Volume 79, Number 5 (Wednesday, January 8, 2014)]
[Proposed Rules]
[Pages 1430-1519]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2013-28668]
[[Page 1429]]
Vol. 79
Wednesday,
No. 5
January 8, 2014
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
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
[[Page 1430]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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 [email protected] 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: http://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 http://www.regulations.gov: Follow the instructions
for submitting comments.
At the Web site http://www.epa.gov/oar/docket.html: Follow the
instructions for submitting comments on the EPA Air and Radiation
Docket Web site.
Email: Send your comments by electronic mail (email) to [email protected], 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 http://www.regulations.gov, unless the comment includes information claimed to
be Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through http://
[[Page 1431]]
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 http://www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption and be free of any
defects or viruses.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available (e.g., CBI or other information
whose disclosure is restricted by statute). Certain other material,
such as copyrighted material, will be publicly available only in hard
copy. Publicly available docket materials are available either
electronically in http://www.regulations.gov or in hard copy at the EPA
Docket Center, 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 http://www.epa.gov/epahome/dockets.htm for additional information about the EPA's public
docket.
In addition to being available in the docket, an electronic copy of
this proposed rule will be available on the Worldwide Web (WWW) through
the Technology Transfer Network (TTN). Following signature, a copy of
the proposed rule will be posted on the TTN's policy and guidance page
for newly proposed or promulgated rules at the following address:
http://www.epa.gov/ttn/oarpg/.
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: [email protected] 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: [email protected].
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
[[Page 1432]]
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-
[[Page 1433]]
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.
---------------------------------------------------------------------------
\1\ In this rulemaking, all references to lb CO2/MWh
are on a gross output basis, unless specifically noted otherwise.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\2\ Conditions in the analysis year of 2022 are represented by a
model year of 2020.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 http://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, http://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,'' http://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), http://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\ http://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 http://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\ http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf; http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf; http://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\ http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
\51\ Energy Information Adminstration's Annual Energy Outlook
for 2013, Final Release available at http://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\ http://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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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 http://www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
\82\ The text of the SAB Peer Review Advisory is available at
http://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.
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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.''
---------------------------------------------------------------------------
\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, http://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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
[[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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
[[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\
---------------------------------------------------------------------------
\184\ http://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.
---------------------------------------------------------------------------
\185\ ``Cost and Performance of PC and IGCC Plants for a Range
of Carbon Dioxide Capture'', DOE/NETL-2011/1498, May 27, 2011.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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 (http://www.netl.doe.gov/technologies/coalpower/gasification/gasifipedia/4-gasifiers/4-3_syngas-table2.html).
---------------------------------------------------------------------------
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: http://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\
---------------------------------------------------------------------------
\191\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010).
---------------------------------------------------------------------------
In general, CO2 capture technologies applicable to coal-
fired power generation can be categorized into three approaches: \192\
---------------------------------------------------------------------------
\192\ Id at 29.
---------------------------------------------------------------------------
[[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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\199\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage. Retrieved from http://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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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: http://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 http://cdn.globalccsinstitute.com/sites/default/files/publications/39961/ccsinwareport-opt.pdf.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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 http://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., http://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.http://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 http://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 http://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\
---------------------------------------------------------------------------
\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
http://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.
---------------------------------------------------------------------------
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, http://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.
http://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 http://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\ http://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
http://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. http://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 http://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.
---------------------------------------------------------------------------
\251\ http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\252\ http://www.epa.gov/ghgreporting/reporters/subpart/d.html.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\253\ http://www.epa.gov/ghgreporting/reporters/subpart/pp.html.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\254\ 76 FR 48073 (Aug. 8, 2011).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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 http://www.epa.gov/region07/air/title5/t5memos/fees.pdf.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
[[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: http://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\ http://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