[Federal Register Volume 80, Number 205 (Friday, October 23, 2015)]
[Rules and Regulations]
[Pages 64510-64660]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-22837]
[[Page 64509]]
Vol. 80
Friday,
No. 205
October 23, 2015
Part II
Environmental Protection Agency
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40 CFR Parts 60, 70, 71, et al.
Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Final Rule
Federal Register / Vol. 80 , No. 205 / Friday, October 23, 2015 /
Rules and Regulations
[[Page 64510]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 70, 71, and 98
[EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL-9930-66-OAR]
RIN 2060-AQ91
Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is finalizing new
source performance standards (NSPS) under Clean Air Act (CAA) section
111(b) that, for the first time, will establish standards for emissions
of carbon dioxide (CO2) for newly constructed, modified, and
reconstructed affected fossil fuel-fired electric utility generating
units (EGUs). This action establishes separate standards of performance
for fossil fuel-fired electric utility steam generating units and
fossil fuel-fired stationary combustion turbines. This action also
addresses related permitting and reporting issues. In a separate
action, under CAA section 111(d), the EPA is issuing final emission
guidelines for states to use in developing plans to limit
CO2 emissions from existing fossil fuel-fired EGUs.
DATES: This final rule is effective on October 23, 2015. The
incorporation by reference of certain publications listed in the rule
is approved by the Director of the Federal Register as of October 23,
2015.
ADDRESSES: The EPA has established dockets for this action under Docket
ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse
Gas Emissions from New Stationary Sources: Electric Utility Generating
Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution
Standards for Modified and Reconstructed Stationary Sources: Electric
Utility Generating Units). All documents in the dockets are listed on
the www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., Confidential Business
Information 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 www.regulations.gov or
in hard copy at the EPA Docket Center (EPA/DC), Room 3334, EPA WJC West
Building, 1301 Constitution Ave. NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Air
Docket is (202) 566-1742.
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: 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
AEO Annual Energy Outlook
AEP American Electric Power
ANSI American National Standards Institute
ASME American Society of Mechanical Engineers
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
GHGRP Greenhouse Gas Reporting Program
GPM Gallons per Minute
GS Geologic Sequestration
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
MRV Monitoring, Reporting, and Verification
MW Megawatt
MWe Megawatt Electrical
MWh Megawatt-hour
MWh-g Megawatt-hour gross
MWh-n Megawatt-hour net
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 n\th\-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
SCPC Supercritical Pulverized Coal
SDWA Safe Drinking Water Act
SF6 Sulfur Hexafluoride
SIP State Implementation Plan
[[Page 64511]]
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
USDW Underground Source of Drinking Water
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard
WGS Water Gas Shift
WWW World Wide Web
Organization of This Document. The information presented in this
preamble is organized as follows:
I. General Information
A. Executive Summary
B. Does this action apply to me?
C. Where can I get a copy of this document?
D. Judicial Review
E. How is this preamble organized?
II. Background
A. Climate Change Impacts From GHG Emissions
B. GHG Emissions From Fossil Fuel-Fired EGUs
C. The Utility Power Sector
D. Statutory Background
E. Regulatory Background
F. Development of Carbon Pollution Standards for Fossil Fuel-
Fired Electric Utility Generating Units
G. Stakeholder Engagement and Public Comments on the Proposals
III. Regulatory Authority, Affected EGUs and Their Standards, and
Legal Requirements
A. Authority To Regulate Carbon Dioxide From Fossil Fuel-Fired
EGUs
B. Treatment of Categories and Codification in the Code of
Federal Regulations
C. Affected Units
D. Units Not Covered by This Final Rule
E. Coal Refuse
F. Format of the Output-Based Standard
G. CO2 Emissions Only
H. Legal Requirements for Establishing Emission Standards
I. Severability
J. Certain Projects Under Development
IV. Summary of Final Standards for Newly Constructed, Modified, and
Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating
Units
A. Applicability Requirements and Rationale
B. Best System of Emission Reduction
C. Final Standards of Performance
V. Rationale for Final Standards for Newly Constructed Fossil Fuel-
Fired Electric Utility Steam Generating Units
A. Factors Considered in Determining the BSER
B. Highly Efficient SCPC EGU Implementing Partial CCS as the
BSER for Newly Constructed Steam Generating Units
C. Rationale for the Final Emission Standards
D. Post-Combustion Carbon Capture
E. Pre-Combustion Carbon Capture
F. Vendor Guarantees, Industry Statements, Academic Literature,
and Commercial Availability
G. Response to Key Comments on the Adequacy of the Technical
Feasibility Demonstration
H. Consideration of Costs
I. Key Comments Regarding the EPA's Consideration of Costs
J. Achievability of the Final Standards
K. Emission Reductions Utilizing Partial CCS
L. Further Development and Deployment of CCS Technology
M. Technical and Geographic Aspects of Disposition of Captured
CO2
N. Final Requirements for Disposition of Captured CO2
O. Non-Air Quality Impacts and Energy Requirements
P. Options That Were Considered by the EPA But Were Ultimately
Not Determined to Be the BSER
Q. Summary
VI. Rationale for Final Standards for Modified Fossil Fuel-Fired
Electric Utility Steam Generating Units
A. Rationale for Final Applicability Criteria for Modified Steam
Generating Units
B. Identification of the Best System of Emission Reduction
C. BSER Criteria
VII. Rationale for Final Standards for Reconstructed Fossil Fuel-
Fired Electric Utility Steam Generating Units
A. Rationale for Final Applicability Criteria for Reconstructed
Sources
B. Identification of the Best System of Emission Reduction
VIII. Summary of Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines
A. Applicability Requirements
B. Best System of Emission Reduction
C. Final Emission Standards
D. Significant Differences Between Proposed and Final Combustion
Turbine Provisions
IX. Rationale for Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines
A. Applicability
B. Subcategories
C. Identification of the Best System of Emission Reduction
D. Achievability of the Final Standards
X. Summary of Other Final Requirements for Newly Constructed,
Modified, and Reconstructed Fossil Fuel-Fired Electric Utility Steam
Generating Units and Stationary Combustion Turbines
A. Startup, Shutdown, and Malfunction Requirements
B. Continuous Monitoring Requirements
C. Emissions Performance Testing Requirements
D. Continuous Compliance Requirements
E. Notification, Recordkeeping, and Reporting Requirements
XI. Consistency Between BSER Determinations for This Rule and the
Rule for Existing EGUs
A. Newly Constructed Steam Generating Units
B. New Combustion Turbines
C. Modified and Reconstructed Steam and NGCC Units
XII. Interactions With Other EPA Programs and Rules
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
F. Interactions With Other EPA Rules
XIII. Impacts of This Action
A. What are the air impacts?
B. Endangered Species Act
C. What are the energy impacts?
D. What are the water and solid waste impacts?
E. What are the compliance costs?
F. What are the economic and employment impacts?
G. What are the benefits of the final standards?
XIV. 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 (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
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 (NTTAA) and
1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
XV. Withdrawal of Proposed Standards for Certain Modified Sources
XVI. Statutory Authority
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
In this final action the EPA is establishing standards that limit
greenhouse gas (GHG) emissions from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating units
and stationary combustion turbines, following the issuance of proposals
for such standards and an accompanying Notice of Data Availability.
On June 25, 2013, in conjunction with the announcement of his
Climate Action Plan (CAP), President Obama issued a
[[Page 64512]]
Presidential Memorandum directing the EPA to issue a proposal to
address carbon pollution from new power plants by September 30, 2013,
and to issue ``standards, regulations, or guidelines, as appropriate,
which address carbon pollution from modified, reconstructed, and
existing power plants.'' Pursuant to authority in section 111(b) of the
CAA, on September 20, 2013, the EPA issued proposed carbon pollution
standards for newly constructed fossil fuel-fired power plants. The
proposal was published in the Federal Register on January 8, 2014 (79
FR 1430; ``January 2014 proposal'').\1\ In that proposal, the EPA
proposed to limit emissions of CO2 from newly constructed
fossil fuel-fired electric utility steam generating units and newly
constructed natural gas-fired stationary combustion turbines.
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\1\ The EPA previously proposed performance standards for newly
reconstructed fossil fuel-fired EGUs in April 2012 (77 FR 22392). In
that action, the EPA proposed standards for steam generating units
and natural gas-fired combustion turbines based on a single Best
System of Emission Reduction determination. On January 8, 2014, the
EPA withdrew that proposal (79 FR 1352).
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The EPA subsequently issued a Notice of Data Availability (NODA) in
which the EPA solicited comment on its initial interpretation of
provisions in the Energy Policy Act of 2005 (EPAct05) and associated
provisions in the Internal Revenue Code (IRC) and also solicited
comment on a companion Technical Support Document (TSD) that addressed
these provisions' relationship to the factual record supporting the
proposed rule. 79 FR 10750 (February 26, 2014).
On June 2, 2014, the EPA proposed standards of performance, also
pursuant to CAA section 111(b), to limit emissions of CO2
from modified and reconstructed fossil fuel-fired electric utility
steam generating units and natural gas-fired stationary combustion
turbines. 79 FR 34960 (June 18, 2014) (``June 2014 proposal'').
Specifically, the EPA proposed standards of performance for: (1)
Modified fossil fuel-fired steam generating units, (2) modified natural
gas-fired stationary combustion turbines, (3) reconstructed fossil
fuel-fired steam generating units, and (4) reconstructed natural gas-
fired stationary combustion turbines.
In this action, the EPA is issuing final standards of performance
to limit emissions of GHG pollution manifested as CO2 from
newly constructed, modified, and reconstructed fossil fuel-fired
electric utility steam generating units (i.e., utility boilers and
integrated gasification combined cycle (IGCC) units) and from newly
constructed and reconstructed stationary combustion turbines.
Consistent with the requirements of CAA section 111(b), these standards
reflect the degree of emission limitation achievable through the
application of the best system of emission reduction (BSER) that the
EPA has determined has been adequately demonstrated for each type of
unit. These final standards are codified in 40 CFR part 60, subpart
TTTT, a new subpart specifically created for CAA 111(b) standards of
performance for GHG emissions from fossil fuel-fired EGUs.
In a separate action that affects the same source category, the EPA
is issuing final emission guidelines under CAA section 111(d) for
states to use in developing plans to limit CO2 emissions
from existing fossil fuel-fired EGUs. Pursuant to those guidelines,
states must submit plans to the EPA following a schedule set by the
guidelines.
The EPA received numerous comments and conducted extensive outreach
to stakeholders for this rulemaking. After careful consideration of
public comments and input from a variety of stakeholders, the final
standards of performance in this action reflect certain changes from
the proposals. Comments considered include written comments that were
submitted during the public comment period and oral testimony provided
during the public hearing for the proposed standards.
2. Summary of Major Provisions and Changes to the Proposed Standards
The BSER determinations and final standards of performance for
affected newly constructed, modified, and reconstructed EGUs are
summarized in Table 1 and discussed in more detail below. The final
standards for new, modified, and reconstructed EGUs apply to sources
that commenced construction--or modification or reconstruction, as
appropriate--on or after the date of publication of corresponding
proposed standards.\2\ The final standards for newly constructed fossil
fuel-fired EGUs apply to those sources that commenced construction on
or after the date of publication of the proposed standards, January 8,
2014. The final standards for modified and reconstructed fossil fuel-
fired EGUs apply to those sources that modify or reconstruct on or
after the date of publication of the proposed standards, June 18, 2014.
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\2\ See CAA section 111(a)(2).
Table 1--Summary of BSER and Final Standards for Affected EGUs
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Final standards of
Affected EGUs BSER performance
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Newly Constructed Fossil Fuel- Efficient new 1,400 lb CO2/MWh-
Fired Steam Generating Units. supercritical g.
pulverized coal
(SCPC) utility
boiler
implementing
partial carbon
capture and
storage (CCS).
Modified Fossil Fuel-Fired Steam Most efficient Sources making
Generating Units. generation at the modifications
affected EGU resulting in an
achievable increase in CO2
through a hourly emissions
combination of of more than 10
best operating percent are
practices and required to meet
equipment a unit-specific
upgrades. emission limit
determined by the
unit's best
historical annual
CO2 emission rate
(from 2002 to the
date of the
modification);
the emission
limit will be no
more stringent
than:
1. 1,800 lb CO2/
MWh-g for sources
with heat input
>2,000 MMBtu/h.
2. 2,000 lb CO2/
MWh-g for sources
with heat input
<=2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Most efficient 1. Sources with
Steam Generating Units. generating heat input >2,000
technology at the MMBtu/h are
affected source required to meet
(supercritical an emission limit
steam conditions of 1,800 lb CO2/
for the larger; MWh-g.
and subcritical 2. Sources with
conditions for heat input
the smaller). <=2,000 MMBtu/h
are required to
meet an emission
limit of 2,000 lb
CO2/MWh-g.
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Newly Constructed and Efficient NGCC 1. 1,000 lb CO2/
Reconstructed Fossil Fuel-Fired technology for MWh-g or 1,030 lb
Stationary Combustion Turbines. base load natural CO2/MWh-n for
gas-fired units base load natural
and clean fuels gas-fired units.
for non-base load 2. 120 lb CO2/
and multi-fuel- MMBtu for non-
fired units.\3\ base load natural
gas-fired units.
3. 120 to 160 lb
CO2/MMBtu for
multi-fuel-fired
units.\4\
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a. Fossil Fuel-Fired Electric Utility Steam Generating Units
This action establishes standards of performance for newly
constructed fossil fuel-fired steam generating units \5\ based on the
performance of a new highly efficient SCPC EGU implementing post-
combustion partial carbon capture and storage (CCS) technology, which
the EPA determines to be the BSER for these sources. After
consideration of a wide range of comments, technical input received on
the availability, technical feasibility, and cost of CCS
implementation, and publicly available information about projects that
are implementing or planning to implement CCS, the EPA confirms its
proposed determination that CCS technology is available and technically
feasible to implement at fossil fuel-fired steam generating units.
However, the EPA's final standard reflects the consideration of
legitimate concerns regarding the cost to implement available CCS
technology on a new steam generating unit. Accordingly, the EPA is
finalizing an emission standard for newly constructed fossil fuel-fired
steam generating units at 1,400 lb CO2/MWh-g, a level that
is less stringent than the proposed limitation of 1,100 lb
CO2/MWh-g. This final standard reflects our identification
of the BSER for such units to be a lower level of partial CCS than we
identified as the basis of the proposed standards--one that we conclude
better represents the requirement that the BSER be implementable at
reasonable cost.
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\3\ The term ``multi-fuel-fired'' refers to a stationary
combustion turbine that is physically connected to a natural gas
pipeline, but that burns a fuel other than natural gas for 10
percent or more of the unit's heat input capacity during the 12-
operating-month compliance period.
\4\ The emission standard for combustion turbines co-firing
natural gas with other fuels shall be determined at the end of each
operating month based on the amount of co-fired natural gas. Units
only burning natural gas with other fuels with a relatively
consistent chemical composition and an emission factor of 160 lb
CO2/MMBtu or less (e.g., natural gas, distillate oil,
etc.) only need to maintain records of the fuels burned at the unit
to demonstrate compliance. Units burning fuels with variable
chemical composition or with an emission factor greater than 160 lb
CO2/MMBtu (e.g., residual oil) must conduct periodic fuel
sampling and testing to determine the overall CO2
emission rate.
\5\ Also referred to as just ``steam generating units'' or as
``utility boilers and IGCC units''. These are units that are covered
under 40 CFR part 60, subpart Da for criteria pollutants.
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The EPA proposed that the BSER for newly constructed steam
generating EGUs was highly efficient new generating technology (i.e., a
supercritical utility boiler or IGCC unit) implementing partial CCS
technology to achieve CO2 emission reductions resulting in
an emission limit of 1,100 lb CO2/MWh-g.\6\
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\6\ Using the most recent data on partial capture rates to meet
an emission standard of 1,100 lb CO2/MWh-gross, about 35
percent capture would be required at an SCPC unit and about 22
percent capture would be required at an IGCC unit.
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The BSER for newly constructed steam generating EGUs in the final
rule is very similar to that in the January 2014 proposal. In this
final action, the EPA finds that a highly efficient new supercritical
pulverized coal (SCPC) utility boiler EGU implementing partial CCS to
the degree necessary to achieve an emission of 1,400 lb CO2/
MWh-g is the BSER. Contrary to the January 2014 proposal, the EPA finds
that IGCC technology--either with natural gas co-firing or implementing
partial CCS--is not part of the BSER, but recognizes that IGCC
technology can serve as an alternative method of compliance.
The EPA finds that a highly efficient SCPC implementing partial CCS
is the BSER because CCS technology has been demonstrated to be
technically feasible and is in use or under construction in various
industrial sectors, including the power generation sector. For example,
the Boundary Dam Unit #3 CCS project in Saskatchewan, Canada is a full-
scale, fully integrated CCS project that is currently operating and is
designed to capture more than 90 percent of the CO2 from the
lignite-fired boiler. A newly constructed, highly efficient SCPC
utility boiler burning bituminous coal will be able to meet this final
standard of performance by capturing and storing approximately 16
percent of the CO2 produced from the facility. A newly
constructed, highly efficient SCPC utility boiler burning subbituminous
coal or dried lignite \7\ will be able to meet this final standard of
performance by capturing and storing approximately 23 percent of the
CO2 produced from the facility. As an alternative compliance
option, utilities and project developers will also be able to construct
new steam generating units (both utility boilers and IGCC units) that
meet the final standard of performance by co-firing with natural gas.
This final standard of performance for newly constructed fossil fuel-
fired steam generating units provides a clear and achievable path
forward for the construction of such sources while addressing GHG
emissions and supporting technological innovation. The standard of
1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam
generating units for all fuel types, under a wide range of conditions,
and throughout the United States.
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\7\ For a summary of lignite drying technologies, see ``Techno-
economics of modern pre-drying technologies for lignite-fired power
plants'' available at www.iea-coal.org.uk/documents/83436/9095/
Techno-economics-of-modern-pre-drying-technologies-for-lignite-
fired-power-plants,-CCC/241; ``Drying the lignite prior to
combustion in the boiler is thus an effective way to increase the
thermal efficiencies and reduce the CO2 emissions from
lignite-fired power plants.''
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We note that identifying a highly efficient new SCPC EGU
implementing partial CCS as the BSER provides a path forward for new
fossil fuel-fired steam generation in the current market context.
Numerous studies have predicted that few new fossil fuel-fired steam
generating units will be constructed in the future. These analyses
identify a range of factors unrelated to this rulemaking, including low
electricity demand growth, highly competitive natural gas prices, and
increases in the supply of renewable energy. The EPA recognizes that,
in certain circumstances, there may be interest in building fossil
fuel-fired steam generating units despite these market conditions. In
particular, utilities and project developers may build new fossil fuel-
fired steam generating EGUs in order to achieve or maintain fuel
diversity within generating fleets, as a hedge against the possibility
of natural gas prices far exceeding projections, or to co-produce both
power and chemicals, including capturing CO2 for use in
enhanced oil
[[Page 64514]]
recovery (EOR) projects.\8\ As regulatory history has shown,
identifying a new highly efficient SCPC EGU implementing partial CCS as
the BSER in this rule is likely to further boost research and
development in CCS technologies, making the implementation even more
efficacious and cost-effective, while providing a competitive, low
emission future for fossil fuel-fired steam generation.
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\8\ As the EIA has stated: Policy-related factors, such as
environmental regulations and investment or production tax credits
for specified generation sources, can also impact investment
decisions. Finally, although levelized cost calculations are
generally made using an assumed set of capital and operating costs,
the inherent uncertainty about future fuel prices and future
policies may cause plant owners or investors who finance plants to
place a value on portfolio diversification. While EIA considers many
of these factors in its analysis of technology choice in the
electricity sector, these concepts are not included in LCOE or LACE
calculations. http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
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The EPA is also issuing final standards for steam generating units
that implement ``large modifications,'' (i.e., modifications resulting
in an increase in hourly CO2 emissions of more than 10
percent when compared to the source's highest hourly emissions in the
previous 5 years).\9\ The EPA is not issuing final standards, at this
time, for steam generating units that implement ``small modifications''
(i.e., modifications resulting in an increase in hourly CO2
emissions of less than or equal to 10 percent when compared to the
source's highest hourly emissions in the previous 5 years).
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\9\ 40 CFR 60.14(h) provides that no physical change, or change
in the method of operation, at an existing electric utility steam
generating unit will be treated as a modification provided that such
change does not increase the maximum hourly emissions above the
maximum hourly emissions achievable at that unit during the 5 years
prior to the change.
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The standards of performance for modified steam generating units
that make large modifications are based on each affected unit's own
best potential performance as the BSER. Specifically, such a modified
steam generating unit will be required to meet a unit-specific
CO2 emission limit determined by that unit's best
demonstrated historical performance (in the years from 2002 to the time
of the modification).\10\ The EPA has determined that this standard
based on each unit's own best potential performance can be met through
a combination of best operating practices and equipment upgrades and
that these steps can be implemented cost-effectively at the time when a
source is undertaking a large modification. To account for facilities
that have already implemented best practices and equipment upgrades,
the final rule also specifies that modified facilities will not have to
meet an emission standard more stringent than the corresponding
standard for reconstructed steam generating units (i.e., 1,800 lb
CO2/MWh-g for units with heat input greater than 2,000
MMBtu/h and 2,000 lb CO2/MWh-g for units with heat input
less than or equal to 2,000 MMBtu/h).
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\10\ For the 2002 reporting year the EPA introduced new
automated checks in the software that integrated automated quality
assurance (QA) checks on the hourly data. Thus, the EPA believes
that the data from 2002 and forward are of higher quality.
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The final standards for steam generating units implementing large
modifications are similar to the proposed standards for such units. In
the proposal, we suggested that the standard should be based on when
the modification is undertaken (i.e., before being subject to
requirements under a CAA section 111(d) state plan or after being
subject to such a plan). We also suggested that for units that
undertake modifications prior to becoming subject to an approved CAA
section 111(d) state plan, the standard should be its best historical
performance plus an additional two percent reduction. In response to
comments on the proposal, we are not finalizing separate standards that
are dependent upon when the modification takes place, nor are we
finalizing the proposed additional two percentage reduction.
The EPA is not promulgating final standards of performance for, and
is withdrawing the proposed standards for steam generating sources that
make modifications resulting in an increase of hourly CO2
emissions of less than or equal to 10 percent (see Section XV of this
preamble). As we indicated in the proposal, the EPA has been notified
of very few modifications for criteria pollutant emissions from the
power sector to which NSPS requirements have applied. As such, we
expect that there will be few NSPS modifications for GHG emissions as
well. Even so, we also recognize (and we discuss in this preamble) that
the power sector is undergoing significant change and realignment in
response to a variety of influences and incentives in the industry. We
do not have sufficient information at this time, however, to anticipate
the types of modifications, if any, that may result from these changes.
In particular, we do not have sufficient information about the types of
modifications, if any, that would result in increases in CO2
emissions of 10 percent or less, and what the appropriate standard for
such sources would be. Therefore, we conclude that it is prudent to
delay issuing standards for sources that undertake small modifications
(i.e., those resulting in an increase in CO2 emissions of
less than or equal to 10 percent).
For reconstructed steam generating units, the EPA is finalizing
standards based on the performance of the most efficient generating
technology for these types of units as the BSER (i.e., reconstructing
the boiler if necessary to use steam with higher temperature and
pressure, even if the boiler was not originally designed to do so).\11\
The emission standard for these sources is 1,800 lb CO2/MWh-
g for large sources, (i.e. those with a heat input rating of greater
than 2,000 MMBtu/h) or 2,000 lb CO2/MWh-g for small sources
(i.e., those with a heat input rating of 2,000 MMBtu/h or less). The
difference in the standards for larger and smaller units is based on
greater availability of higher pressure/temperature steam turbines
(e.g., supercritical steam turbines) for larger units. The standards
can also be met through other non-BSER options, such as natural gas co-
firing.
---------------------------------------------------------------------------
\11\ Steam with higher temperature and pressure has more thermal
energy that can be more efficiently converted to electrical energy.
---------------------------------------------------------------------------
b. Stationary Combustion Turbines
This action also finalizes standards of performance for newly
constructed and reconstructed stationary combustion turbines. In the
January 2014 proposal for newly constructed EGUs, the EPA proposed that
natural gas-fired stationary combustion turbines (i.e., turbines
combusting over 90 percent natural gas) would be subject to a standard
of performance for CO2 emissions if they are constructed for
the purpose of supplying and actually annually supply to the grid (1)
one-third or more of their potential electric output \12\ and (2) more
than 219,000 MWh,\13\ based on a three-year rolling average. We refer
to units that operate above the electric sales thresholds as ``base
load units,'' and we refer to units that operate below these thresholds
as ``non-base load units.''
---------------------------------------------------------------------------
\12\ We refer to thresholds related to an EGU's actual annual
electrical sales (as a fraction of potential annual output) as
``percentage electric sales criteria.''
\13\ We refer to thresholds related to an EGU's actual annual
electrical sales in megawatt-hours as ``total electric sales
criteria.''
---------------------------------------------------------------------------
In the January 2014 proposal for newly constructed combustion
turbines, the EPA proposed standards for two subcategories of base load
natural gas-fired stationary combustion turbines. The proposed standard
for small combustion turbines (units with base load ratings less than
or equal to 850 MMBtu/h) was 1,100 lb CO2/MWh-g. The
proposed standard for large combustion turbines (units with base
[[Page 64515]]
load ratings greater than 850 MMBtu/h) was 1,000 lb CO2/MWh-
g. The EPA did not propose standards for non-base load units.
In the June 2014 proposal for modified and reconstructed combustion
turbines, the EPA solicited comment on alternative approaches for
establishing applicability and subcategorization criteria, including
(1) eliminating the ``constructed for the purpose of supplying''
qualifier for the total electric sales and percentage electric sales
criteria, (2) eliminating the 219,000 MWh total electric sales
criterion altogether, (3) replacing the fixed percentage electric sales
criterion with a variable percentage electric sales criterion (i.e.,
the sliding-scale approach \14\), and (4) eliminating the proposed
small and large subcategories for base load natural gas-fired
combustion turbines. These proposed applicability requirements were
intended to exclude combustion turbines that are used for the purpose
of meeting peak power demand, as opposed to those that are used to meet
base load power demand.
---------------------------------------------------------------------------
\14\ The sliding-scale approach determines a unit-specific
percentage electric sales threshold equivalent to a unit's net
design efficiency (the maximum value is capped at 50 percent).
---------------------------------------------------------------------------
In both proposals, the EPA also solicited comment on a broad
applicability approach that would include non-base load natural gas-
fired units (primarily simple cycle combustion turbines) and multi-
fuel-fired units (primarily distillate oil-fired combustion turbines)
in the general applicability of subpart TTTT. As part of the broad
applicability approach, the EPA solicited comment on imposing ``no
emission standard'' or establishing separate numerical limits for these
two subcategories.
In this action, the EPA is finalizing a variation of the approaches
put forward in the January 2014 proposal for new sources and the June
2014 proposal for modified and reconstructed sources. Based on our
review of public comments related to the proposed subcategories for
small and large combustion turbines and our additional data analyses,
we have determined that there is no need to set two separate standards
for different sizes of combustion turbines for base load natural gas-
fired combustion turbines. The EPA has determined that all sizes of
affected newly constructed and reconstructed stationary combustion
turbines can achieve the final standards. For newly constructed and
reconstructed base load natural gas-fired stationary combustion
turbines, the EPA is finalizing a standard of 1,000 lb CO2/
MWh-g based on efficient natural gas combined cycled (NGCC) technology
as the BSER. Alternatively, owners and operators of base load natural
gas-fired combustion turbines may elect to comply with a standard based
on net output of 1,030 lb CO2/MWh-n.
The EPA is eliminating the 219,000 MWh total annual electric sales
criterion for non-CHP units. In addition, the EPA is finalizing the
sliding-scale approach for deriving the unit-specific, percentage
electric sales threshold above which a combustion turbine transitions
from the subcategory for non-base load units to the subcategory for
base load units. For newly constructed and reconstructed non-base load
natural gas-fired stationary combustion turbines, the EPA is finalizing
the combustion of clean fuels (natural gas with a small allowance for
distillate oil) as the BSER with a corresponding heat input-based
standard of 120 lb CO2/MMBtu. This standard of performance
will apply to the vast majority of simple cycle combustion turbines.
The EPA is finalizing a heat input-based clean fuels standard because
we have insufficient information at this time to set a uniform output-
based standard that can be achieved by all new and reconstructed non-
base load units.
In addition, for newly constructed and reconstructed multi-fuel-
fired stationary combustion turbines, the EPA is finalizing an input-
based standard of 120 to 160 lb CO2/MMBtu based on the
combustion of clean fuels as the BSER.\15\ The EPA has similarly
determined that it has insufficient information at this time to set a
uniform output-based standard for stationary combustion turbines that
operate with significant quantities of a fuel other than natural gas.
---------------------------------------------------------------------------
\15\ Combustion turbines co-firing natural gas with other fuels
shall determine fuel-based site-specific standards at the end of
each operating month. The site-specific standards depend on the
amount of co-fired natural gas.
---------------------------------------------------------------------------
We are not promulgating final standards of performance for
stationary combustion turbines that make modifications at this time. We
are simultaneously withdrawing the proposed standards for modifications
(see Section XV of this preamble). As we indicated in the proposal,
sources from the power sector have notified the EPA of very few NSPS
modifications, and we expect that there will be few NSPS modifications
for CO2 emissions as well. Moreover, our decision to
eliminate the subcategories for small and large EGUs and set a single
standard of 1,000 lb CO2/MWh-g has raised questions as to
whether smaller existing combustion turbines that undertake a
modification can meet this standard. As a result, we have concluded
that it is prudent to delay issuing standards for sources that
undertake modifications until we can gather more information.
A more detailed discussion of the final standards of performance
for stationary combustion turbines, the applicability criteria, and the
comments that influenced the final standards is provided in Sections
VIII and IX of this preamble.
3. Costs and Benefits
As explained in the regulatory impact analysis (RIA) for this final
rule, available data--including utility announcements and Energy
Information Administration (EIA) modeling--indicate that, even in the
absence of this rule, (i) existing and anticipated economic conditions
are such that few, if any, fossil fuel-fired steam-generating EGUs will
be built in the foreseeable future, and (ii) utilities and project
developers are expected to choose new generation technologies
(primarily NGCC) that would meet the final standards and renewable
generating sources that are not affected by these final standards.
These projections are consistent with utility announcements and EIA
modeling that indicate that new units are likely to be NGCC and that
any coal-fired steam generating units built between now and 2030 would
have CCS, even in the absence of this rule.\16\ Therefore, based on the
analysis presented in Chapter 4 of the RIA, the EPA projects that this
final rule will result in negligible CO2 emission changes,
quantified benefits, and costs by 2022 as a result of the performance
standards for newly constructed EGUs.\17\ However, as noted earlier,
for a variety of reasons, some companies may consider coal-fired steam
generating units that the modeling does not anticipate. Thus, in
Chapter 5 of the RIA, we also present an analysis of the project-level
costs of a newly constructed coal-fired steam generating unit with
partial CCS that meets the requirements of this final rule alongside
the project-level costs of a newly constructed coal-fired unit without
CCS. This analysis indicates that the
[[Page 64516]]
quantified benefits of the standards of performance would exceed their
costs under a range of assumptions.
---------------------------------------------------------------------------
\16\ The EPA's Integrated Planning Model (IPM) projects no new
non-compliant coal (i.e., newly constructed coal-fired plants that
do not meet the final standard of performance) throughout the model
horizon of 2030 (there is a small amount of new coal with CCS that
is hardwired into the modelling, consistent with EIA assumptions to
represent units already under construction or under development).
\17\ Conditions in the analysis year of 2022 are represented by
a model year of 2020.
---------------------------------------------------------------------------
As explained in the RIA and further below, the EPA has been
notified of few power sector NSPS modifications or reconstructions.
Based on that experience, the EPA expects that few EGUs will trigger
either the modification or the reconstruction provisions that we are
finalizing in this action. In Chapter 6 of the RIA, we discuss factors
that limit our ability to quantify the costs and benefits of the
standards for modified and reconstructed sources.
B. Does this action apply to me?
The entities potentially affected by the standards are shown in
Table 2 below.
Table 2--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
action. To determine whether your facility, company, business,
organization, etc., would be regulated by this action, refer to Section
III of this preamble for more information and examine the applicability
criteria in 40 CFR 60.1 (General Provisions) and Sec. 60.550840 of
subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for
Electric Utility Generating Units). 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).
C. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this final action will also be available on the Worldwide Web (WWW).
Following signature, a copy of this final action will be posted at the
following address: http://www2.epa.gov/carbon-pollution-standards.
D. Judicial Review
Under section 307(b)(1) of the CAA, judicial review of this final
rule is available only by filing a petition for review in the U.S.
Court of Appeals for the District of Columbia Circuit by December 22,
2015. Moreover, under section 307(b)(2) of the CAA, the requirements
established by this final rule may not be challenged separately in any
civil or criminal proceedings brought by the EPA to enforce these
requirements. Section 307(d)(7)(B) of the CAA further provides that
``[o]nly an objection to a rule or procedure which was raised with
reasonable specificity during the period for public comment (including
any public hearing) may be raised during judicial review.'' This
section also provides a mechanism mandating the EPA to convene a
proceeding for reconsideration if the person raising an objection can
demonstrate that it was impracticable to raise such objection within
the period for public comment or if the grounds for such objection
arose after the period for public comment (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule. Any person seeking to make such a
demonstration should submit a Petition for Reconsideration to the
Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building,
1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both
the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave. NW., Washington, DC 20460.
E. How is this preamble organized?
This action presents the EPA's final standards of performance for
newly constructed, modified, and reconstructed fossil fuel-fired
electric utility steam generating units and newly constructed and
reconstructed stationary combustion turbines. Section II provides
background information on climate change impacts from GHG emissions,
GHG emissions from fossil fuel-fired EGUs, the utility power sector,
the statutory and regulatory background relating to CAA section 111(b),
EPA actions prior to this final action, and public comments regarding
the proposed actions. Section III explains the EPA's authority to
regulate CO2 and EGUs, identifies affected EGUs, and
describes the source categories. Section IV provides a summary of the
final standards for newly constructed, modified, and reconstructed
fossil fuel-fired steam generating units. Sections V through VII
present the rationale for the final standards for newly constructed,
modified, and reconstructed steam generating units, respectively.
Sections VIII and IX provide a summary of the final standards for
stationary combustion turbines and present the rationale for the final
standards for newly constructed and reconstructed combustion turbines,
respectively. Section X provides a summary of other final requirements
for newly constructed, modified, and reconstructed fossil fuel-fired
steam generating units and stationary combustion turbines. Section XI
addresses the consistency of the respective BSER determinations in
these rules and under the emission guidelines issued separately under
CAA section 111(d). Interactions with other EPA programs and rules are
described in Section XII. Projected impacts of the final action are
then described in Section XIII, followed by a discussion of statutory
and executive order reviews in Section XIV. Section XV addresses the
withdrawal of the proposed standards for steam generating EGUs that
make modifications resulting in an increase of hourly CO2
emissions of less than or equal to 10 percent and the proposed
standards for modified stationary combustion turbines. The statutory
authority for this action is provided in Section XVI. We address major
comments throughout this preamble and in greater detail in an
accompanying response-to-comments document located in the docket.
[[Page 64517]]
II. Background
In this section, we discuss climate change impacts from GHG
emissions, both on public health and public welfare. We also present
information about GHG emissions from fossil fuel-fired EGUs and
describe the utility power sector and its changing structure. We then
summarize the statutory and regulatory background relevant to this
final rulemaking. In addition, we provide background information on the
EPA's January 8, 2014 proposed carbon pollution standards for newly
constructed fossil fuel-fired EGUs, the June 18, 2014 proposed carbon
pollution standards for modified and reconstructed EGUs, and other
actions associated with this final rulemaking. We close this section
with a general discussion of comments and stakeholder input that the
EPA received prior to issuing this final rulemaking.
A. Climate Change Impacts From GHG Emissions
According to the National Research Council, ``Emissions of
CO2 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 CO2 in the atmosphere is long
lived, it can effectively lock Earth and future generations into a
range of impacts, some of which could become very severe. Therefore,
emission reduction choices made today matter in determining impacts
experienced not just over the next few decades, but in the coming
centuries and millennia.'' \18\
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\18\ National Research Council, Climate Stabilization Targets,
p. 3.
---------------------------------------------------------------------------
In 2009, based on a large body of robust and compelling scientific
evidence, the EPA Administrator issued the Endangerment Finding under
CAA section 202(a)(1).\19\ In the Endangerment Finding, the
Administrator found that the current, elevated concentrations of GHGs
in the atmosphere--already at levels unprecedented in human history--
may reasonably be anticipated to endanger public health and welfare of
current and future generations in the United States. We summarize these
adverse effects on public health and welfare briefly here.
---------------------------------------------------------------------------
\19\ ``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
Climate change caused by human emissions of GHGs threatens the
health of Americans in multiple ways. By raising average temperatures,
climate change increases the likelihood of heat waves, which are
associated with increased deaths and illnesses. While climate change
also increases the likelihood of reductions in cold-related mortality,
evidence indicates that the increases in heat mortality will be larger
than the decreases in cold mortality in the United States. Compared to
a future without climate change, climate change is expected to increase
ozone pollution over broad areas of the U.S., especially on the highest
ozone days and in the largest metropolitan areas with the worst ozone
problems, and thereby increase the risk of morbidity and mortality.
Climate change is also expected to cause more intense hurricanes and
more frequent and intense storms and heavy precipitation, with impacts
on other areas of public health, such as the potential for increased
deaths, injuries, infectious and waterborne diseases, and stress-
related disorders. 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
Climate change impacts touch nearly every aspect of public welfare.
Among the multiple threats caused by human emissions of GHGs, 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 a multitude of increased risks,
particularly from rising sea level and increases in the severity of
storms. These communities face storm and flood damage to property, or
even loss of land due to inundation, erosion, wetland submergence and
habitat loss.
Impacts of climate change on public welfare also include threats to
social and ecosystem services. Climate change is expected to result in
an increase in peak electricity demand. Extreme weather from climate
change threatens energy, transportation, and water resource
infrastructure. Climate change may also exacerbate ongoing
environmental pressures in certain settlements, particularly in Alaskan
indigenous communities, and is very likely to fundamentally rearrange
U.S. ecosystems over the 21st century. Though some benefits may balance
adverse effects on agriculture and forestry in the next few decades,
the body of evidence points towards increasing risks of net adverse
impacts on U.S. food production, agriculture and forest productivity as
temperature continues to rise. These impacts are global and may
exacerbate problems outside the U.S. that raise humanitarian, trade,
and national security issues for the U.S.
3. New Scientific Assessments and Observations
Since the administrative record concerning the Endangerment Finding
closed following the EPA's 2010 Reconsideration Denial, the climate has
continued to change, with new records being set for a number of climate
indicators such as global average surface temperatures, Arctic sea ice
retreat, CO2 concentrations, and sea level rise.
Additionally, a number of major scientific assessments have been
released that improve understanding of the climate system and
strengthen the case that GHGs endanger public health and welfare both
for current and future generations. These assessments, from the
Intergovernmental Panel on Climate Change (IPCC), the U.S. Global
Change Research Program (USGCRP), and the National Research Council
(NRC), include: IPCC's 2012 Special Report on Managing the Risks of
Extreme Events and Disasters to Advance Climate Change Adaptation
(SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP's
2014 National Climate Assessment, Climate Change Impacts in the United
States (NCA3), and the NRC's 2010 Ocean Acidification: A National
Strategy to Meet the Challenges of a Changing Ocean (Ocean
Acidification), 2011 Report on Climate Stabilization Targets:
Emissions, Concentrations, and Impacts over Decades to Millennia
(Climate Stabilization Targets), 2011 National Security Implications
for U.S. Naval Forces (National Security Implications), 2011
Understanding Earth's Deep Past: Lessons for Our Climate Future
(Understanding Earth's Deep Past), 2012 Sea Level Rise for the Coasts
of California, Oregon, and Washington: Past, Present, and Future, 2012
Climate and Social Stress: Implications for Security Analysis (Climate
and Social Stress), and 2013 Abrupt Impacts of Climate Change (Abrupt
Impacts) assessments.
The EPA has carefully reviewed these recent assessments in keeping
with the same approach outlined in Section III.A of the 2009
Endangerment Finding, which was to rely primarily upon the major
assessments by the USGCRP, the IPCC, and the NRC of the National
Academies to provide the technical and scientific information to inform
the Administrator's judgment regarding the question of whether GHGs
endanger public health and welfare. These
[[Page 64518]]
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 findings of the recent scientific assessments confirm and
strengthen the conclusion that GHGs endanger public health, now and in
the future. The NCA3 indicates that human health in the United States
will be impacted by ``increased extreme weather events, wildfire,
decreased air quality, threats to mental health, and illnesses
transmitted by food, water, and disease-carriers such as mosquitoes and
ticks.'' The most recent assessments now have greater confidence that
climate change will influence production of pollen that exacerbates
asthma and other allergic respiratory diseases such as allergic
rhinitis, as well as effects on conjunctivitis and dermatitis. Both the
NCA3 and the IPCC AR5 found that increasing temperature has lengthened
the allergenic pollen season for ragweed, and that increased
CO2 by itself can elevate production of plant-based
allergens.
The NCA3 also finds that climate change, in addition to chronic
stresses such as extreme poverty, is negatively affecting indigenous
peoples' health in the United States through impacts such as reduced
access to traditional foods, decreased water quality, and increasing
exposure to health and safety hazards. The IPCC AR5 finds that climate
change-induced warming in the Arctic and resultant changes in
environment (e.g., permafrost thaw, effects on traditional food
sources) have significant impacts, observed now and projected, on the
health and well-being of Arctic residents, especially indigenous
peoples. Small, remote, predominantly-indigenous communities are
especially vulnerable given their ``strong dependence on the
environment for food, culture, and way of life; their political and
economic marginalization; existing social, health, and poverty
disparities; as well as their frequent close proximity to exposed
locations along ocean, lake, or river shorelines.'' \20\ In addition,
increasing temperatures and loss of Arctic sea ice increases the risk
of drowning for those engaged in traditional hunting and fishing.
---------------------------------------------------------------------------
\20\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part B: Regional Aspects. Contribution of Working
Group II to the Fifth Assessment Report of the Intergovernmental
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D.
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S.
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge
University Press, Cambridge, p. 1581.
---------------------------------------------------------------------------
The NCA3 concludes that children's unique physiology and developing
bodies contribute to making them particularly vulnerable to climate
change. Impacts on children are expected from heat waves, air
pollution, infectious and waterborne illnesses, and mental health
effects resulting from extreme weather events. The IPCC AR5 indicates
that children are among those especially susceptible to most allergic
diseases, as well as health effects associated with heat waves, storms,
and floods. The IPCC finds that additional health concerns may arise in
low-income households, especially those with children, if climate
change reduces food availability and increases prices, leading to food
insecurity within households.
Both the NCA3 and IPCC AR5 conclude that climate change will
increase health risks facing the elderly. Older people are at much
higher risk of mortality during extreme heat events. Pre-existing
health conditions also make older adults susceptible to cardiac and
respiratory impacts of air pollution and to more severe consequences
from infectious and waterborne diseases. Limited mobility among older
adults can also increase health risks associated with extreme weather
and floods.
The new assessments also confirm and strengthen the conclusion that
GHGs endanger public welfare, and emphasize the urgency of reducing GHG
emissions due to their projections that show GHG concentrations
climbing to ever-increasing levels in the absence of mitigation. The
NRC assessment, Understanding Earth's Deep Past, projected that,
without a reduction in emissions, CO2 concentrations by the
end of the century would increase to levels that the Earth has not
experienced for more than 30 million years.\21\ In fact, that
assessment stated that ``the magnitude and rate of the present
greenhouse gas increase place the climate system in what could be one
of the most severe increases in radiative forcing of the global climate
system in Earth history.'' \22\ Because of these unprecedented changes,
several assessments state that we may be approaching critical, poorly
understood thresholds. As stated in the assessment, ``As Earth
continues to warm, it may be approaching a critical climate threshold
beyond which rapid and potentially permanent--at least on a human
timescale--changes not anticipated by climate models tuned to modern
conditions may occur.'' The NRC Abrupt Impacts report analyzed abrupt
climate change in the physical climate system and abrupt impacts of
ongoing changes that, when thresholds are crossed, can cause abrupt
impacts for society and ecosystems. The report considered
destabilization of the West Antarctic Ice Sheet (which could cause 3-4
m of potential sea level rise) as an abrupt climate impact with unknown
but probably low probability of occurring this century. The report
categorized a decrease in ocean oxygen content (with attendant threats
to aerobic marine life); increase in intensity, frequency, and duration
of heat waves; and increase in frequency and intensity of extreme
precipitation events (droughts, floods, hurricanes, and major storms)
as climate impacts with moderate risk of an abrupt change within this
century. The NRC Abrupt Impacts report also analyzed the threat of
rapid state changes in ecosystems and species extinctions as examples
of irreversible impacts that are expected to be exacerbated by climate
change. Species at most risk include those whose migration potential is
limited, whether because they live on mountaintops or fragmented
habitats with barriers to movement, or because climatic conditions are
changing more rapidly than the species can move or adapt. While the NRC
determined that it is not presently possible to place exact
probabilities on the added contribution of climate change to
extinction, they did find that there was substantial risk that impacts
from climate change could, within a few decades, drop the populations
in many species below sustainable levels, thereby committing the
species to extinction. Species within tropical and subtropical
rainforests such as the Amazon and species living in coral reef
ecosystems were identified by the NRC as being particularly vulnerable
to extinction over the next 30 to 80 years, as were species in high
latitude and high elevation regions. Moreover, due to the time lags
inherent in the Earth's climate, the NRC Climate Stabilization Targets
assessment notes that the full warming from any given concentration of
CO2 reached will not be fully realized for several
centuries, underscoring that emission activities today carry with them
climate commitments far into the future.
---------------------------------------------------------------------------
\21\ National Research Council, Understanding Earth's Deep Past,
p. 1.
\22\ Id., p. 138.
---------------------------------------------------------------------------
Future temperature changes will depend on what emission path the
world follows. In its high emission scenario, the IPCC AR5 projects
that
[[Page 64519]]
average global temperatures by the end of the century will likely be
2.6 degrees Celsius ([deg]C) to 4.8 [deg]C (4.7 to 8.6 degrees
Fahrenheit ([deg]F)) warmer than today. Temperatures on land and in
northern latitudes will likely warm even faster than the global
average. However, according to the NCA3, significant reductions in
emissions would lead to noticeably less future warming beyond mid-
century, and therefore less impact to public health and welfare.
While rainfall may only see small globally and annually averaged
changes, there are expected to be substantial shifts in where and when
that precipitation falls. According to the NCA3, regions closer to the
poles will see more precipitation, while the dry subtropics are
expected to expand (colloquially, this has been summarized as wet areas
getting wetter and dry regions getting drier). In particular, the NCA3
notes that the western U.S., and especially the Southwest, is expected
to become drier. This projection is consistent with the recent observed
drought trend in the West. At the time of publication of the NCA, even
before the last 2 years of extreme drought in California, tree ring
data was already indicating that the region might be experiencing its
driest period in 800 years. Similarly, the NCA3 projects that heavy
downpours are expected to increase in many regions, with precipitation
events in general becoming less frequent but more intense. This trend
has already been observed in regions such as the Midwest, Northeast,
and upper Great Plains. Meanwhile, the NRC Climate Stabilization
Targets assessment found that the area burned by wildfire is expected
to grow by 2 to 4 times for 1 [deg]C (1.8 [deg]F) of warming. For 3
[deg]C of warming, the assessment found that 9 out of 10 summers would
be warmer than all but the 5 percent of warmest summers today, leading
to increased frequency, duration, and intensity of heat waves.
Extrapolations by the NCA also indicate that Arctic sea ice in summer
may essentially disappear by mid-century. Retreating snow and ice, and
emissions of CO2 and methane released from thawing
permafrost, will also amplify future warming.
Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple
NRC assessments have projected future rates of sea level rise that are
40 percent larger to more than twice as large as the previous estimates
from the 2007 IPCC 4th Assessment Report due in part to improved
understanding of the future rate of melt of the Antarctic and Greenland
Ice sheets. The NRC Sea Level Rise assessment projects a global sea
level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100, the NRC
National Security Implications assessment suggests that ``the
Department of the Navy should expect roughly 0.4 to 2 meters (1.3 to
6.6 feet) global average sea-level rise by 2100,'' \23\ and the NRC
Climate Stabilization Targets assessment states that an increase of 3
[deg]C will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3
feet) by 2100. These assessments continue to recognize that there is
uncertainty inherent in accounting for ice sheet processes.
Additionally, local sea level rise can differ from the global total
depending on various factors. The east coast of the U.S. in particular
is expected to see higher rates of sea level rise than the global
average. For comparison, the NCA3 states that ``five million Americans
and hundreds of billions of dollars of property are located in areas
that are less than four feet above the local high-tide level,'' and the
NCA3 finds that ``[c]oastal infrastructure, including roads, rail
lines, energy infrastructure, airports, port facilities, and military
bases, are increasingly at risk from sea level rise and damaging storm
surges.'' \24\ Also, because of the inertia of the oceans, sea level
rise will continue for centuries after GHG concentrations have
stabilized (though more slowly than it would have otherwise).
Additionally, there is a threshold temperature above which the
Greenland ice sheet will be committed to inevitable melting. According
to the NCA, some recent research has suggested that even present day
CO2 levels could be sufficient to exceed that threshold.
---------------------------------------------------------------------------
\23\ NRC, 2011: National Security Implications of Climate Change
for U.S. Naval Forces. The National Academies Press, p. 28.
\24\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W.
Yohe, Eds., 2014: Climate Change Impacts in the United States: The
Third National Climate Assessment. U.S. Global Change Research
Program, p. 9.
---------------------------------------------------------------------------
In general, climate change impacts are expected to be unevenly
distributed across different regions of the United States and have a
greater impact on certain populations, such as indigenous peoples and
the poor. The NCA3 finds that climate change impacts such as the rapid
pace of temperature rise, coastal erosion and inundation related to sea
level rise and storms, ice and snow melt, and permafrost thaw are
affecting indigenous people in the U.S. Particularly in Alaska,
critical infrastructure and traditional livelihoods are threatened by
climate change and, ``[i]n parts of Alaska, Louisiana, the Pacific
Islands, and other coastal locations, climate change impacts (through
erosion and inundation) are so severe that some communities are already
relocating from historical homelands to which their traditions and
cultural identities are tied.'' \25\ The IPCC AR5 notes, ``Climate-
related hazards exacerbate other stressors, often with negative
outcomes for livelihoods, especially for people living in poverty (high
confidence). Climate-related hazards affect poor people's lives
directly through impacts on livelihoods, reductions in crop yields, or
destruction of homes and indirectly through, for example, increased
food prices and food insecurity.'' \26\
---------------------------------------------------------------------------
\25\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W.
Yohe, Eds., 2014: Climate Change Impacts in the United States: The
Third National Climate Assessment. U.S. Global Change Research
Program, p. 17.
\26\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, p. 796.
---------------------------------------------------------------------------
CO2 in particular has unique impacts on ocean
ecosystems. The NRC Climate Stabilization Targets assessment found that
coral bleaching will increase due both to warming and ocean
acidification. Ocean surface waters have already become 30 percent more
acidic over the past 250 years due to absorption of CO2 from
the atmosphere. According to the NCA3, this acidification will reduce
the ability of organisms such as corals, krill, oysters, clams, and
crabs to survive, grow, and reproduce. The NRC Understanding Earth's
Deep Past assessment notes that four of the five major coral reef
crises of the past 500 million years were caused by acidification and
warming that followed GHG increases of similar magnitude to the
emissions increases expected over the next hundred years. The NRC
Abrupt Impacts assessment specifically highlighted similarities between
the projections for future acidification and warming and the extinction
at the end of the Permian which resulted in the loss of an estimated 90
percent of known species. Similarly, the NRC Ocean Acidification
assessment finds that ``[t]he chemistry of the ocean is changing at an
unprecedented rate and magnitude due to anthropogenic CO2
emissions; the rate of change exceeds any known to have occurred for at
least the past
[[Page 64520]]
hundreds of thousands of years.'' \27\ 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.'' \28\
---------------------------------------------------------------------------
\27\ NRC, 2010: Ocean Acidification: A National Strategy to Meet
the Challenges of a Changing Ocean. The National Academies Press, p.
5.
\28\ Id.
---------------------------------------------------------------------------
Events outside the United States, as also pointed out in the 2009
Endangerment Finding, will also have relevant consequences. The NRC
Climate and Social Stress assessment concluded that it is prudent to
expect that some climate events ``will produce consequences that exceed
the capacity of the affected societies or global systems to manage and
that have global security implications serious enough to compel
international response.'' The NRC National Security Implications
assessment 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.
In addition to future impacts, the NCA3 emphasizes that climate
change driven by human emissions of GHGs is already happening now and
it is happening in the United States. According to the IPCC AR5 and the
NCA3, there are a number of climate-related changes that have been
observed recently, and these changes are projected to accelerate in the
future. The planet warmed about 0.85 [deg]C (1.5 [deg]F) from 1880 to
2012. It is extremely likely (>95 percent probability) that human
influence was the dominant cause of the observed warming since the mid-
20th century, and likely (>66 percent probability) that human influence
has more than doubled the probability of occurrence of heat waves in
some locations. In the Northern Hemisphere, the last 30 years were
likely the warmest 30-year period of the last 1400 years. U.S. average
temperatures have similarly increased by 1.3 to 1.9 [deg]F since 1895,
with most of that increase occurring since 1970. Global sea levels rose
0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was
the warming of the oceans and melting of land ice. It is likely that
275 gigatons per year of ice have melted from land glaciers (not
including ice sheets) since 1993, and that the rate of loss of ice from
the Greenland and Antarctic ice sheets has increased substantially in
recent years, to 215 gigatons per year and 147 gigatons per year
respectively, since 2002. For context, 360 gigatons of ice melt is
sufficient to cause global sea levels to rise 1 mm. Annual mean Arctic
sea ice has been declining at 3.5 to 4.1 percent per decade, and
Northern Hemisphere snow cover extent has decreased at about 1.6
percent per decade for March and 11.7 percent per decade for June.
Permafrost temperatures have increased in most regions since the 1980s,
by up to 3 [deg]C (5.4 [deg]F) in parts of Northern Alaska. Winter
storm frequency and intensity have both increased in the Northern
Hemisphere. The NCA3 states that the increases in the severity or
frequency of some types of extreme weather and climate events in recent
decades can affect energy production and delivery, causing supply
disruptions, and compromise other essential infrastructure such as
water and transportation systems.
In addition to the changes documented in the assessment literature,
there have been other climate milestones of note. In 2009, the year of
the Endangerment Finding, the average concentration of CO2
as measured on top of Mauna Loa was 387 parts per million, far above
preindustrial concentrations of about 280 parts per million.\29\ The
average concentration in 2013, the last full year before this rule was
proposed, was 396 parts per million. The average concentration in 2014
was 399 parts per million. And the monthly concentration in April of
2014 was 401 parts per million, the first time a monthly average has
exceeded 400 parts per million since record keeping began at Mauna Loa
in 1958, and for at least the past 800,000 years based on ice core
records.\30\ Arctic sea ice has continued to decline, with September of
2012 marking a new record low in terms of Arctic sea ice extent, 40
percent below the 1979-2000 median. Sea level has continued to rise at
a rate of 3.2 mm per year (1.3 inches/decade) since satellite
observations started in 1993, more than twice the average rate of rise
in the 20th century prior to 1993.\31\ And 2014 was the warmest year
globally in the modern global surface temperature record, going back to
1880; this now means 19 of the 20 warmest years have occurred in the
past 20 years, and except for 1998, the ten warmest years on record
have occurred since 2002.\32\ The first months of 2015 have also been
some of the warmest on record.
---------------------------------------------------------------------------
\29\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
\30\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
\31\ Blunden, J., and D. S. Arndt, Eds., 2014: State of the
Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
\32\ http://www.ncdc.noaa.gov/sotc/global/2014/13.
---------------------------------------------------------------------------
These assessments and observed changes make it clear that reducing
emissions of GHGs across the globe is necessary in order to avoid the
worst impacts of climate change, and underscore the urgency of reducing
emissions now. The NRC Committee on America's Climate Choices listed a
number of reasons ``why it is imprudent to delay actions that at least
begin the process of substantially reducing emissions.'' \33\ For
example:
---------------------------------------------------------------------------
\33\ NRC, 2011: America's Climate Choices, The National
Academies Press.
---------------------------------------------------------------------------
The faster emissions are reduced, the lower the risks
posed by climate change. Delays in reducing emissions could commit the
planet to a wide range of adverse impacts, especially if the
sensitivity of the climate to greenhouse gases is on the higher end of
the estimated range.
Waiting for unacceptable impacts to occur before taking
action is imprudent because the effects of greenhouse gas emissions do
not fully manifest themselves for decades and, once manifest, many of
these changes will persist for hundreds or even thousands of years.
In the committee's judgment, the risks associated with
doing business as usual are a much greater concern than the risks
associated with engaging in strong response efforts.
4. Observed and Projected U.S. Regional Changes
The NCA3 assessed the climate impacts in eight regions of the
United States, noting that changes in physical climate parameters such
as temperatures, precipitation, and sea ice retreat were already having
impacts on forests, water supplies, ecosystems, flooding, heat waves,
and air quality. Moreover, the NCA3 found that future warming is
projected to be much larger than recent observed variations in
temperature, with precipitation likely to increase in the northern
states, decrease in the southern states, and with the heaviest
precipitation events projected to increase everywhere.
In the Northeast, temperatures increased almost 2 [deg]F from 1895
to 2011, precipitation increased by about 5 inches (10 percent), and
sea level rise of about a foot has led to an increase in coastal
flooding. The 70 percent increase in the amount of rainfall falling in
the 1 percent of the most intense events is a larger increase in
extreme precipitation than experienced in any other U.S. region.
In the future, if emissions continue increasing, the Northeast is
expected to experience 4.5 to 10 [deg]F of warming by
[[Page 64521]]
the 2080s. This will lead to more heat waves, coastal and river
flooding, and intense precipitation events. The southern portion of the
region is projected to see 60 additional days per year above 90 [deg]F
by mid-century. Sea levels in the Northeast are expected to increase
faster than the global average because of subsidence, and changing
ocean currents may further increase the rate of sea level rise.
Specific vulnerabilities highlighted by the NCA include large urban
populations particularly vulnerable to climate-related heat waves and
poor air quality episodes, prevalence of climate sensitive vector-borne
diseases like Lyme and West Nile Virus, usage of combined sewer systems
that may lead to untreated water being released into local water bodies
after climate-related heavy precipitation events, and 1.6 million
people living within the 100-year coastal flood zone who are expected
to experience more frequent floods due to sea level rise and tropical-
storm induced storm-surge. The NCA also highlighted infrastructure
vulnerable to inundation in coastal metropolitan areas, potential
agricultural impacts from increased rain in the spring delaying
planting or damaging crops or increased heat in the summer leading to
decreased yields and increased water demand, and shifts in ecosystems
leading to declines in iconic species in some regions, such as cod and
lobster south of Cape Cod.
In the Southeast, average annual temperature during the last
century cycled between warm and cool periods. A warm peak occurred
during the 1930s and 1940s, followed by a cool period, and temperatures
then increased again from 1970 to the present by an average of 2
[deg]F. There have been increasing numbers of days above 95 [deg]F and
nights above 75 [deg]F, and decreasing numbers of extremely cold days
since 1970. Daily and five-day rainfall intensities have also
increased, and summers have been either increasingly dry or extremely
wet. Louisiana has already lost 1,880 square miles of land in the last
80 years due to sea level rise and other contributing factors.
The Southeast is exceptionally vulnerable to sea level rise,
extreme heat events, hurricanes, and decreased water availability.
Major consequences of further warming include significant increases in
the number of hot days (95 [deg]F or above) and decreases in freezing
events, as well as exacerbated ground-level ozone in urban areas.
Although projected warming for some parts of the region by the year
2100 is generally smaller than for other regions of the United States,
projected warming for interior states of the region is larger than
coastal regions by 1 [deg]F to 2 [deg]F. Projections further suggest
that there will be fewer tropical storms globally, but that they will
be more intense, with more Category 4 and 5 storms. The NCA identified
New Orleans, Miami, Tampa, Charleston, and Virginia Beach as being
specific cities that are at risk due to sea level rise, with homes and
infrastructure increasingly prone to flooding. Additional impacts of
sea level rise are expected for coastal highways, wetlands, fresh water
supplies, and energy infrastructure.
In the Northwest, temperatures increased by about 1.3 [deg]F
between 1895 and 2011. A small average increase in precipitation was
observed over this time period. However, warming temperatures have
caused increased rainfall relative to snowfall, which has altered water
availability from snowpack across parts of the region. Snowpack in the
Northwest is an important freshwater source for the region. More
precipitation falling as rain instead of snow has reduced the snowpack,
and warmer springs have corresponded to earlier snowpack melting and
reduced streamflows during summer months. Drier conditions have
increased the extent of wildfires in the region.
Average annual temperatures are projected to increase by 3.3 [deg]F
to 9.7 [deg]F by the end of the century (depending on future global GHG
emissions), with the greatest warming expected during the summer.
Continued increases in global GHG emissions are projected to result in
up to a 30 percent decrease in summer precipitation. Earlier snowpack
melt and lower summer stream flows are expected by the end of the
century and will affect drinking water supplies, agriculture,
ecosystems, and hydropower production. Warmer waters are expected to
increase disease and mortality in important fish species, including
Chinook and sockeye salmon. Ocean acidification also threatens species
such as oysters, with the Northwest coastal waters already being some
of the most acidified worldwide due to coastal upwelling and other
local factors. Forest pests are expected to spread and wildfires to
burn larger areas. Other high-elevation ecosystems are projected to be
lost because they can no longer survive the climatic conditions. Low
lying coastal areas, including the cities of Seattle and Olympia, will
experience heightened risks of sea level rise, erosion, seawater
inundation and damage to infrastructure and coastal ecosystems.
In Alaska, temperatures have changed faster than anywhere else in
the United States. Annual temperatures increased by about
3[emsp14][deg]F in the past 60 years. Warming in the winter has been
even greater, rising by an average of 6[emsp14][deg]F. Arctic sea ice
is thinning and shrinking in area, with the summer minimum ice extent
now covering only half the area it did when satellite records began in
1979. Glaciers in Alaska are melting at some of the fastest rates on
Earth. Permafrost soils are also warming and beginning to thaw. Drier
conditions have contributed to more large wildfires in the last 10
years than in any previous decade since the 1940s, when recordkeeping
began. Climate change impacts are harming the health, safety, and
livelihoods of Native Alaskan communities.
By the end of this century, continued increases in GHG emissions
are expected to increase temperatures by 10 to 12[emsp14][deg]F in the
northernmost parts of Alaska, by 8 to 10[emsp14][deg]F in the interior,
and by 6 to 8[emsp14][deg]F across the rest of the state. These
increases will exacerbate ongoing arctic sea ice loss, glacial melt,
permafrost thaw and increased wildfire, and threaten humans,
ecosystems, and infrastructure. Precipitation is expected to increase
to varying degrees across the state. However, warmer air temperatures
and a longer growing season are expected to result in drier conditions.
Native Alaskans are expected to experience declines in economically,
nutritionally, and culturally important wildlife and plant species.
Health threats will also increase, including loss of clean water,
saltwater intrusion, sewage contamination from thawing permafrost, and
northward extension of diseases. Wildfires will increasingly pose
threats to human health as a result of smoke and direct contact. Areas
underlain by ice-rich permafrost across the state are likely to
experience ground subsidence and extensive damage to infrastructure as
the permafrost thaws. Important ecosystems will continue to be
affected. Surface waters and wetlands that are drying provide breeding
habitat for millions of waterfowl and shorebirds that winter in the
lower 48 states. Warmer ocean temperatures, acidification, and
declining sea ice will contribute to changes in the location and
availability of commercially and culturally important marine fish.
In the Southwest, temperatures are now about 2[emsp14][deg]F higher
than the past century, and are already the warmest that region has
experienced in at least 600 years. The NCA notes that there is evidence
that climate change-induced warming on top of recent drought has
influenced tree mortality, wildfire frequency and area, and forest
insect outbreaks. Sea levels have risen about 7
[[Page 64522]]
or 8 inches in this region, contributing to inundation of Highway 101
and back up of seawater into sewage systems in the San Francisco area.
Projections indicate that the Southwest will warm an additional 5.5
to 9.5[emsp14][deg]F over the next century if emissions continue to
increase. Winter snowpack in the Southwest is projected to decline
(consistent with the record lows from this past winter), reducing the
reliability of surface water supplies for cities, agriculture, cooling
for power plants, and ecosystems. Sea level rise along the California
coast will worsen coastal erosion, increase flooding risk for coastal
highways, bridges, and low-lying airports, pose a threat to groundwater
supplies in coastal cities such as Los Angeles, and increase
vulnerability to floods for hundreds of thousands of residents in
coastal areas. Climate change will also have impacts on the high-value
specialty crops grown in the region as a drier climate will increase
demands for irrigation, more frequent heat waves will reduce yields,
and decreased winter chills may impair fruit and nut production for
trees in California. Increased drought, higher temperatures, and bark
beetle outbreaks are likely to contribute to continued increases in
wildfires. The highly urbanized population of the Southwest is
vulnerable to heat waves and water supply disruptions, which can be
exacerbated in cases where high use of air conditioning triggers energy
system failures.
The rate of warming in the Midwest has markedly accelerated over
the past few decades. Temperatures rose by more than 1.5[emsp14][deg]F
from 1900 to 2010, but between 1980 and 2010, the rate of warming was
three times faster than from 1900 through 2010. Precipitation generally
increased over the last century, with much of the increase driven by
intensification of the heaviest rainfalls. Several types of extreme
weather events in the Midwest (e.g., heat waves and flooding) have
already increased in frequency and/or intensity due to climate change.
In the future, if emissions continue increasing, the Midwest is
expected to experience 5.6 to 8.5[emsp14][deg]F of warming by the
2080s, leading to more heat waves. Though projections of changes in
total precipitation vary across the regions, more precipitation is
expected to fall in the form of heavy downpours across the entire
region, leading to an increase in flooding. Specific vulnerabilities
highlighted by the NCA include long-term decreases in agricultural
productivity, changes in the composition of the region's forests,
increased public health threats from heat waves and degraded air and
water quality, negative impacts on transportation and other
infrastructure associated with extreme rainfall events and flooding,
and risks to the Great Lakes including shifts in invasive species,
increases in harmful algal blooms, and declining beach health.
High temperatures (more than 100[emsp14][deg]F in the Southern
Plains and more than 95[emsp14][deg]F in the Northern Plains) are
projected to occur much more frequently by mid-century. Increases in
extreme heat will increase heat stress for residents, energy demand for
air conditioning, and water losses. North Dakota's increase in annual
temperatures over the past 130 years is the fastest in the contiguous
U.S., mainly driven by warming winters. Specific vulnerabilities
highlighted by the NCA include increased demand for water and energy,
changes to crop-growth cycles and agricultural practices, and negative
impacts on local plant and animal species from habitat fragmentation,
wildfires, and changes in the timing of flowering or pest patterns.
Communities that are already the most vulnerable to weather and climate
extremes will be stressed even further by more frequent extreme events
occurring within an already highly variable climate system.
In Hawaii, other Pacific islands, and the Caribbean, rising air and
ocean temperatures, shifting rainfall patterns, changing frequencies
and intensities of storms and drought, decreasing baseflow in streams,
rising sea levels, and changing ocean chemistry will affect ecosystems
on land and in the oceans, as well as local communities, livelihoods,
and cultures. Low islands are particularly at risk.
Rising sea levels, coupled with high water levels caused by
tropical and extra-tropical storms, will incrementally increase coastal
flooding and erosion, damaging coastal ecosystems, infrastructure, and
agriculture, and negatively affecting tourism. Ocean temperatures in
the Pacific region exhibit strong year-to-year and decadal
fluctuations, but since the 1950s, they have exhibited a warming trend,
with temperatures from the surface to a depth of 660 feet rising by as
much as 3.6[emsp14][deg]F. As a result of current sea level rise, the
coastline of Puerto Rico around Rinc[oacute]n is being eroded at a rate
of 3.3 feet per year. Freshwater supplies are already constrained and
will become more limited on many islands. Saltwater intrusion
associated with sea level rise will reduce the quantity and quality of
freshwater in coastal aquifers, especially on low islands. In areas
where precipitation does not increase, freshwater supplies will be
adversely affected as air temperature rises.
Warmer oceans are leading to increased coral bleaching events and
disease outbreaks in coral reefs, as well as changed distribution
patterns of tuna fisheries. Ocean acidification will reduce coral
growth and health. Warming and acidification, combined with existing
stresses, will strongly affect coral-reef fish communities. For Hawaii
and the Pacific islands, future sea surface temperatures are projected
to increase 2.3[emsp14][deg]F by 2055 and 4.7[emsp14][deg]F by 2090
under a scenario that assumes continued increases in emissions. Ocean
acidification is also taking place in the region, which adds to
ecosystem stress from increasing temperatures. Ocean acidity has
increased by about 30 percent since the pre-industrial era and is
projected to further increase by 37 percent to 50 percent from present
levels by 2100.
The NCA also discussed impacts that occur along the coasts and in
the oceans adjacent to many regions, and noted that other impacts occur
across regions and landscapes in ways that do not follow political
boundaries.
B. GHG Emissions From Fossil Fuel-Fired EGUs
Fossil fuel-fired EGUs are by far the largest emitters of GHGs
among stationary sources in the U.S., primarily in the form of
CO2. Among fossil fuel-fired EGUs, coal-fired units are by
far the largest emitters. This section describes the amounts of these
emissions and places these amounts in the context of the U.S. Inventory
of Greenhouse Gas Emissions and Sinks \34\ (the U.S. GHG Inventory).
---------------------------------------------------------------------------
\34\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2013'', Report EPA 430-R-15-004, United States Environmental
Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
---------------------------------------------------------------------------
The EPA implements a separate program under 40 CFR part 98 called
the Greenhouse Gas Reporting Program \35\ (GHGRP) that requires
emitting facilities that emit over certain threshold amounts of GHGs to
report their emissions to the EPA annually. Using data from the GHGRP,
this section also places emissions from fossil fuel-fired EGUs in the
context of the total emissions reported to the GHGRP from facilities in
the other largest-emitting industries.
---------------------------------------------------------------------------
\35\ U.S. EPA Greenhouse Gas Reporting Program Dataset, see
http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
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The EPA prepares the official U.S. GHG Inventory to comply with
commitments under the United Nations Framework Convention on Climate
[[Page 64523]]
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sector. It provides the information in Table 3
below, which presents total U.S. anthropogenic emissions and sinks \36\
of GHGs, including CO2 emissions, for the years 1990, 2005
and 2013.
---------------------------------------------------------------------------
\36\ Sinks are physical units or processes that store GHGs, such
as forests or underground or deep sea reservoirs of CO2.
\37\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United
States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\38\ 1 metric ton (tonne) is equivalent to 1,000 kilograms (kg)
and is equivalent to 1.1023 short tons or 2,204.62 pounds (lb).
\39\ The energy sector includes all greenhouse gases resulting
from stationary and mobile energy activities including fuel
combustion and fugitive fuel emissions.
Table 3--U.S. GHG Emissions and Sinks by Sector (million metric tons carbon dioxide equivalent (MMT CO2e))\37\
\38\
----------------------------------------------------------------------------------------------------------------
Sector 1990 2005 2013
----------------------------------------------------------------------------------------------------------------
Energy\39\............................................. 5,290.5 6,273.6 5,636.6
Industrial Processes and Product Use................... 342.1 367.4 359.1
Agriculture............................................ 448.7 494.5 515.7
Land Use, Land-Use Change and Forestry................. 13.8 25.5 23.3
Waste.................................................. 206.0 189.2 138.3
--------------------------------------------------------
Total Emissions.................................... 6,301.1 7,350.2 6,673.0
Land Use, Land-Use Change and Forestry (Sinks)......... (775.8) (911.9) (881.7)
--------------------------------------------------------
Net Emissions (Sources and Sinks).................. 5,525.2 6,438.3 5,791.2
----------------------------------------------------------------------------------------------------------------
Total fossil energy-related CO2 emissions (including
both stationary and mobile sources) are the largest contributor to
total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG
emissions.\40\ In 2013, fossil fuel combustion by the utility power
sector--entities that burn fossil fuel and whose primary business is
the generation of electricity--accounted for 38.3 percent of all
energy-related CO2 emissions.\41\ Table 4 below presents
total CO2 emissions from fossil fuel-fired EGUs, for years
1990, 2005, and 2013.
---------------------------------------------------------------------------
\40\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United
States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\41\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
Table 4--U.S. GHG Emissions from Generation of Electricity from Combustion of Fossil Fuels (MMT CO2)\42\
----------------------------------------------------------------------------------------------------------------
GHG emissions 1990 2005 2013
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel-fired EGUs.................. 1,820.8 2,400.9 2,039.8
--from coal........................................ 1,547.6 1,983.8 1,575.0
--from natural gas................................. 175.3 318.8 441.9
--from petroleum................................... 97.5 97.9 22.4
----------------------------------------------------------------------------------------------------------------
In addition to preparing the official U.S. GHG Inventory to present
comprehensive total U.S. GHG emissions and comply with commitments
under the UNFCCC, the EPA collects detailed GHG emissions data from the
largest emitting facilities in the U.S. through its GHGRP. Data
collected by the GHGRP from large stationary sources in the industrial
sector show that the utility power sector emits far greater
CO2 emissions than any other industrial sector. Table 5
below presents total GHG emissions in 2013 for the largest emitting
industrial sectors as reported to the GHGRP. As shown in Table 4 and
Table 5, respectively, CO2 emissions from fossil fuel-fired
EGUs are nearly three times as large as the total reported GHG
emissions from the next ten largest emitting industrial sectors in the
GHGRP database combined.
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\42\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States
Environmental Protection Agency, April 15 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\43\ U.S. EPA Greenhouse Gas Reporting Program Dataset as of
August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.
Table 5--Direct GHG Emissions Reported to GHGRP by Largest Emitting
Industrial Sectors (MMT CO2e)\43\
------------------------------------------------------------------------
Industrial sector 2013
------------------------------------------------------------------------
Fossil Fuel-Fired EGUs............................... 2,039.8
Petroleum Refineries................................. 176.7
Onshore Oil & Gas Production......................... 94.8
Municipal Solid Waste Landfills...................... 93.0
Iron & Steel Production.............................. 84.2
Cement Production.................................... 62.8
Natural Gas Processing Plants........................ 59.0
Petrochemical Production............................. 52.7
Hydrogen Production.................................. 41.9
Underground Coal Mines............................... 39.8
Food Processing Facilities........................... 30.8
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[[Page 64524]]
It should be noted that the discussion above concerned all fossil
fuel-fired EGUs. Steam generators emitted 1,627 MMT CO2e and
combustion turbines emitted 401 MMT CO2e in 2013.\44\
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\44\ These figures are based on data for EGUs in the Acid Rain
Program plus additional ones that report to the EPA under the
Regional Greenhouse Gas Initiative.
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C. The Utility Power Sector
1. Modern Electric System Trends
The EPA includes a background discussion of the electricity system
in the Clean Power Plan (CPP) rulemaking, which is the companion
rulemaking to this rule that promulgates emission guidelines for states
to use in regulating emissions of CO2 from existing fossil
fuel-fired EGUs. Readers are referred to that rulemaking. The following
discussion of electricity sector trends is of particular relevance for
this rulemaking.
The electricity sector is undergoing a period of intense change.
Fossil fuels--such as coal, natural gas, and oil--have historically
provided a large percentage of electricity in the U.S., with smaller
amounts being provided by other types of generation, including nuclear
and renewables such as wind, solar, and hydroelectric power. Coal has
historically provided the largest percentage of fossil-fuel
generation.\45\ In recent years, the nation has seen a sizeable
increase in renewable generation such as wind and solar, as well as a
shift from coal to natural gas.\46\ In 2013, fossil fuels supplied 67
percent of U.S. electricity, but renewables made up 38 percent of the
new generation capacity (over 5 GW out of 13.5 GW).\47\ From 2007 to
2014, use of lower- and zero-carbon energy sources has grown, while
other major energy sources such as coal and oil have experienced
declines. Renewable electricity generation, including from large hydro-
electric projects, grew from 8 percent to 13 percent over that time
period.\48\ Between 2000 and 2013, approximately 90 percent of new
power generation capacity built in the U.S. has come in the form of
natural gas or renewable energy facilities.\49\ In 2015, the U.S.
Energy Information Administration (EIA) projected the need for 28.4 GW
of additional base load or intermediate load generation capacity
through 2020, with approximately 0.7 GW of new coal-fired capacity, 5.5
GW of new nuclear capacity, and 14.2 GW of new NGCC capacity already in
development.\50\
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\45\ U.S. Energy Information Administration, ``Table 7.2b
Electricity Net Generation: Electric Power Sector'' data from April
2014 Monthly Energy Review, release data April 25, 2014, available
at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
\46\ U.S. Energy Information Administration, ``Table 7.2b
Electricity Net Generation: Electric Power Sector'' data from April
2014 Monthly Energy Review, release data April 25, 2014, available
at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
\47\ Based on Table 6.3 (New Utility Scale Generating Units by
Operating Company, Plant, Month, and Year) of the U.S. Energy
Information Administration (EIA) Electric Power Monthly, data for
December 2013, for the following renewable energy sources: Solar,
wind, hydro, geothermal, landfill gas, and biomass. Available at:
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_03.
\48\ Bloomberg New Energy Finance and the Business Council for
Sustainable Energy, 2015 Factbook: Sustainable Energy in America, at
16 (2015), available at http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20America%20Factbook.pdf.
\49\ Energy Information Administration, Electricity: Form EIA-
860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/.
\50\ EIA, Annual Energy Outlook for 2015 with Projections to
2040, Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015). The AEO numbers include projects that are under
development and model-projected nuclear, coal, and NGCC projects.
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The change in the resource mix has accelerated in recent years, but
wind, solar, other renewables, and energy-efficiency resources have
been reliably participating in the electric sector for a number of
years. This rapid development of non-fossil fuel resources is occurring
as much of the existing power generation fleet in the U.S. is aging and
in need of modernization and replacement.\51\ For example, the average
age of U.S. coal steam units in 2015 is 45 years.\52\ In its 2013
Report Card for America's Infrastructure, the American Society for
Civil Engineers noted that ``America relies on an aging electrical grid
and pipeline distribution systems, some of which originated in the
1880s.'' \53\ While there has been an increased investment in electric
transmission infrastructure since 2005, the report also found that
``ongoing permitting issues, weather events, and limited maintenance
have contributed to an increasing number of failures and power
interruptions.''\54\ However, innovative technologies have increasingly
entered the electric energy space, helping to provide new answers to
how to meet the electricity needs of the nation. These new technologies
can enable the nation to answer not just questions as to how to
reliably meet electricity demand, but also how to meet electricity
demand reliably and cost-effectively\55\ with the lowest possible
emissions and the greatest efficiency.
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\51\ Quadrennial Energy Review, http://energy.gov/epsa/quadrennial-energy-review-qer.
\52\ We calculated the average age of coal steam units based on
the NEEDS inventory, and included units with planned retirements in
2015-2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx.
\53\ American Society for Civil Engineers, 2013 Report Card for
America's Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.
\54\ American Society for Civil Engineers, 2013 Report Card for
America's Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.
\55\ Business Council for Sustainable Energy Comments in Docket
Id. No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014).
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Natural gas has a long history of meeting electricity demand in the
U.S. with a rapidly growing role as domestic supplies of natural gas
have dramatically increased. Natural gas net generation increased by
approximately 36 percent between 2004 and 2014.\56\ In 2014, natural
gas accounted for approximately 27 percent of net generation.\57\ The
EIA projects that this demand growth will continue, with its Annual
Energy Outlook 2015 (AEO 2015) reference case forecasting that natural
gas will produce 31 percent of U.S. electric generation in 2040.\58\
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\56\ U.S. Energy Information Administration (EIA), Electric
Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All
Sectors), 2004-December 2014 (2015), available at http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_1_1.
\57\ Id.
\58\ The AEO 2015 Reference case projection is a business-as-
usual trend estimate, given known technology and technological and
demographic trends. EIA explores the impacts of alternative
assumptions in other cases with different macroeconomic growth
rates, world oil prices, and resource assumptions. U.S. Energy
Information Administration (EIA), Annual Energy Outlook 2015 with
Projections to 2040, at 24-25 (2015), available at http://
www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.
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Renewable sources of electric generation also have a history of
meeting electricity demand in the U.S. and are expected to have an
increasing role going forward. A series of energy crises provided the
impetus for renewable energy development in the early 1970s. The OPEC
oil embargo in 1973 and oil crisis of 1979 caused oil price spikes,
more frequent energy shortages, and significantly affected the national
and global economy. In 1978, partly in response to fuel security
concerns, Congress passed the Public Utilities Regulatory Policies Act
(PURPA) which required local electric utilities to buy power from
qualifying facilities (QFs).\59\ QFs were either cogeneration
facilities \60\ or small
[[Page 64525]]
generation resources that use renewables such as wind, solar, biomass,
geothermal, or hydroelectric power as their primary fuels.\61\ Through
PURPA, Congress supported the development of more renewable energy
generation in the U.S. States have taken a significant lead in
requiring the development of renewable resources. In particular, a
number of states have adopted renewable portfolio standards (RPS). As
of 2013, 29 states and the District of Columbia have enforceable RPS or
similar laws.\62\ In its AEO 2015 Reference case, the EIA found that
renewable energy will account for 38 percent of the overall growth in
electricity generation from 2013 to 2040.\63\ The AEO 2015 Reference
case forecasts that the renewables share of U.S. electricity generation
will grow from 13 percent in 2013 to 18 percent in 2040.\64\
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\59\ Casazza, J. and Delea, F., Understanding Electric Power
Systems, IEEE Press, at 220-221 (2d ed. 2010).
\60\ Cogeneration facilities utilize a single source of fuel to
produce both electricity and another form of energy such as heat or
steam. Casazza, J. and Delea, F., Understanding Electric Power
Systems, IEEE Press, at 220-221 (2d ed. 2010).
\61\ Casazza, J. and Delea, F., Understanding Electric Power
Systems, IEEE Press, at 220-221 (2d ed. 2010).
\62\ U.S. Energy Information Administration (EIA), Annual Energy
Outlook 2014 with Projections to 2040, at LR-5 (2014).
\63\ U.S. Energy Information Administration (EIA), Annual Energy
Outlook 2015 with Projections to 2040, at E-12 (2015).
\64\ U.S. Energy Information Administration (EIA), Annual Energy
Outlook 2015 with Projections to 2040, at 24-25(2015).
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Price pressures caused by oil embargoes in the 1970s also brought
the issues of conservation and energy efficiency to the forefront of
U.S. energy policy.\65\ This trend continued in the early 1990s. Some
state regulatory commissions and utilities supported energy efficiency
through least-cost planning, with the National Association of
Regulatory Utility Commissioners (NARUC) ``adopting a resolution that
called for the utility's least cost plan to be the utility's most
profitable plan.'' \66\ Energy efficiency has been utilized to meet
energy demand to varying levels since that time. As of April 2014, 25
states \67\ have ``enacted long-term (3+ years), binding energy savings
targets, or energy efficiency resource standards (EERS).'' \68\ Funding
for energy efficiency programs has grown rapidly in recent years, with
budgets for electric efficiency programs totaling $5.9 billion in
2012.\69\
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\65\ Edison Electric Institute, Making a Business of Energy
Efficiency: Sustainable Business Models for Utilities, at 1 (2007).
Congress passed legislation in the 1970s that jumpstarted energy
efficiency in the U.S. For example, President Ford signed the Energy
Policy and Conservation Act (EPCA) of 1975--the first law on the
issue. EPCA authorized the Federal Energy Administration (FEA) to
``develop energy conservation contingency plans, established vehicle
fuel economy standards, and authorized the creation of efficiency
standards for major household appliances.'' Alliance to Save Energy,
History of Energy Efficiency, at 6 (2013) (citing Anders, ``The
Federal Energy Administration,'' 5; Energy Policy and Conservation
Act, S. 622, 94th Cong. (1975-1976)), available at https://www.ase.org/sites/ase.org/files/resources/Media%20browser/ee_commission_history_report_2-1-13.pdf.
\66\ Edison Electric Institute, Making a Business of Energy
Efficiency: Sustainable Business Models for Utilities, at 1 (2007),
available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/Making_Business_Energy_Efficiency.pdf.
\67\ American Council for an Energy-Efficient Economy, State
Energy Efficiency Resource Standards (EERS) (2014), available at
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE did
not include Indiana (EERS eliminated), Delaware (EERS pending),
Florida (programs funded at levels far below what is necessary to
meet targets), Utah, or Virginia (voluntary standards) in its
calculation.
\68\ American Council for an Energy-Efficient Economy, State
Energy Efficiency Resource Standards (EERS) (2014), available at
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf.
\69\ American Council for an Energy-Efficient Economy, The 2013
State Energy Efficiency Scorecard, at 17 (Nov. 2013), available at
http://aceee.org/sites/default/files/publications/researchreports/e13k.pdf.
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Advancements and innovation in power sector technologies provide
the opportunity to address CO2 emission levels at affected
power plants while at the same time improving the overall power system
in the U.S. by lowering the carbon intensity of power generation, and
ensuring a reliable supply of power at a reasonable cost.
2. Fossil Fuel-Fired EGUs Regulated by this Action, Generally
Natural gas-fired EGUs typically use one of two technologies: NGCC
or simple cycle combustion turbines. NGCC units first generate power
from a combustion turbine (the combustion cycle). The unused heat from
the combustion turbine is then routed to a heat recovery steam
generator (HRSG) that generates steam, which is then used to produce
power using a steam turbine (the steam cycle). Combining these
generation cycles increases the overall efficiency of the system.
Simple cycle combustion turbines use a single combustion turbine to
produce electricity (i.e., there is no heat recovery or steam cycle).
The power output from these simple cycle combustion turbines can be
easily ramped up and down making them ideal for ``peaking'' operations.
Coal-fired utility boilers are primarily either pulverized coal
(PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is
crushed (pulverized) into a powder in order to increase its surface
area. The coal powder is then blown into a boiler and burned. In a
coal-fired boiler using FB combustion, the coal is burned in a layer of
heated particles suspended in flowing air.
Power can also be generated using gasification technology. An IGCC
unit gasifies coal or petroleum coke to form a synthetic gas (or
syngas) composed of carbon monoxide (CO) and hydrogen (H2),
which can be combusted in a combined cycle system to generate power.
3. Technological Developments and Costs
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.\70\
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\70\ Levelized Cost and Levelized Avoided Cost of New Generation
Resources in the Annual Energy Outlook 2015 http://www.eia.gov/forecasts/aeo/electricity_generation.html.
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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. As previously discussed, many states have
adopted RPS, which require a certain portion of electricity to come
from renewable energy sources such as solar or wind. The federal
government has also offered incentives to encourage further deployment
of other forms of electric generation including renewable energy
sources and new nuclear power plants.
Reflecting 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.\71\
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\71\ 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.
---------------------------------------------------------------------------
While EIA data shows that natural gas is likely to be the most
widely-used fossil fuel for new construction of electric generating
capacity through 2030, a few coal-fired units still remain as viable
projects at various advanced stages of construction and development.
One new coal facility that has essentially completed construction,
[[Page 64526]]
Southern Company's Kemper County Energy Facility, deploys IGCC with
partial CCS. Additionally, another project, Summit Power's Texas Clean
Energy Project (TCEP), which will deploy IGCC with CCS, continues as a
viable project.\72\ 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 will be built in this decade and that those that
are built will have CCS.\73\ 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 growth, and increases in the supply of renewable
energy. We recognize, however, that a variety of factors may come into
play in a decision to build new power generation, and we want to ensure
that there are standards in place to make sure that whatever fuel is
utilized is done so in a way that minimizes CO2 emissions,
as Congress intended with CAA section 111.\74\
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\72\ ``Odessa coal-to-gas power plant to break ground this
year'', Houston Chronicle (April 1, 2015).
\73\ This projection is for business as usual and does not
account for the proposed or final CO2 emission standard.
Even in its sensitivity analysis that assumes higher natural gas
prices and electricity demand, EIA does not project any additional
coal-fired power plants 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.
\74\ These sources received federal assistance under EPAct 2005.
See Section III.H.3.g below. However, none of the constraints in
that Act affect the discussion in the text above, since that
discussion does not relate to technology use or emissions reduction
by these sources.
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4. 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's annual
report, the AEO, forecasts the structure of and developments in the
power sector. These reports are based on economic modeling that
reflects existing policy and regulations, such as state RPS programs
and federal tax credits for renewables.\75\ The current report, AEO
2015: \76\ (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 \77\ that a very small amount of new
(``unplanned'') conventional coal-fired capacity, with CCS, will come
online after 2012 and through 2037 in response to federal and state
incentives. According to the AEO 2015, the vast majority of new
generating capacity during this period will be either natural gas-fired
or renewable sources. 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 2030.\78\
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\75\ http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
\76\ Energy Information Administration's Annual Energy Outlook
for 2015, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm.
\77\ EIA's reference case projections are the result of its
baseline assumptions for economic growth, fuel supply, technology,
and other key inputs.
\78\ Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and
2015.
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Specifically, the AEO 2015 projects 30.3 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 (20.4 GW) is
already under development (under construction or in advanced planning);
it includes about 0.7 GW of new coal-fired capacity, 5.5 GW of new
nuclear capacity, and 14.2 GW of new NGCC capacity. The EPA believes
that most current fossil fuel-fired projects are already designed to
meet limits consistent with this rule (or they have already commenced
construction and are thus not subject to these final standards). The
AEO 2015 also projects an additional 9.9 GW of new base load capacity
additions, which are model-projected (unplanned). This consists of 7.7
GW of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of
new hydroelectric capacity, and 0.3 GW of new coal equipped with CCS
(incentivized with some government funding). Therefore, the AEO 2015
projection suggests that the new power generation capacity added
through 2020 is expected to already meet the final emissions standards
without incurring further control costs. This is also true during the
period from 2020 through 2030, where new model-projected (unplanned)
intermediate and base load capacity is expected to be compliant with
the standards without incurring further control costs (i.e., an
additional 31.3 GW of NGCC and no additional coal, for a total, from
2015 through 2030, of 39 GW of NGCC and 0.3 GW of coal with CCS).
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 project that coal-fired generation will remain
the largest single source of electricity in the U.S. through 2040.
Specifically, in the EIA's AEO 2015, coal will supply approximately 40
percent of all electricity in the electric power sector 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.\79\ The EPA's projections from IPM
can be found in the RIA.
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\79\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
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5. Integrated Resource Plans
The trends in the power sector described above are also apparent in
publicly available long-term resource plans, known as integrated
resource plans (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.\80\ These IRPs indicate that companies are focused on
demand-side management programs to lower future electricity demand and
are 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.
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\80\ Technical Support Document--``Review of Electric Utility
Integrated Resource Plans'' (May 2015), available in the rulemaking
docket EPA-HQ-OAR-2013-0495.
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Notwithstanding this clear trend towards natural gas-fired
generation and renewables, many of the IRPs highlight the value of fuel
diversity 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 a
smaller number are considering new coal-fired generation capacity with
and without CCS technology. Based on public comments and on the
information contained in these IRPs, the EPA acknowledges that a small
number of
[[Page 64527]]
new coal-fired power plants may be built in the near future. While this
outcome would be 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. Further, it is
possible that some of this potential new coal-fired construction may
occur because developers are able to design projects with specific
business plans, such as the cogeneration of chemicals, which allow the
source to provide competitively priced electricity in specific
geographic regions.
D. Statutory Background
The U.S. Supreme Court ruled in Massachusetts v. EPA that GHGs \81\
meet the definition of ``air pollutant'' in the CAA,\82\ and premised
its decision in AEP v. Connecticut,\83\ that the CAA displaced any
federal common law right to compel reductions in CO2
emissions from fossil fuel-fired power plants, on its view that CAA
section 111 applies to GHG emissions.
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\81\ The EPA's 2009 endangerment finding defines the air
pollution which may endanger public health and welfare as the well-
mixed aggregate group of the following gases: CO2,
methane (CH4), nitrous oxide (N2O), sulfur
hexafluoride (SF6), hydrofluorocarbons (HFCs), and
perfluorocarbons (PFCs).
\82\ 549 U.S. 497, 520 (2007).
\83\ 131 S.Ct. 2527, 2537-38 (2011).
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CAA section 111 authorizes and directs the EPA to prescribe new
source performance standards (NSPS) applicable to certain new
stationary sources (including newly constructed, modified and
reconstructed sources).\84\ As a preliminary step to regulation, the
EPA must list categories of stationary sources that the Administrator,
in his or her judgment, finds ``cause[], or contribute[] significantly
to, air pollution which may reasonably be anticipated to endanger
public health or welfare.'' The EPA has listed and regulated more than
60 stationary source categories under CAA section 111.\85\ The EPA
listed the two source categories at issue here in the 1970s--listing
fossil fuel-fired electric steam generating units in 1971 \86\ and
listing combustion turbines in 1977.\87\
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\84\ CAA section 111(b)(1)(A).
\85\ See generally 40 CFR part 60, subparts D-MMMM.
\86\ 36 FR 5931 (March 31, 1971).
\87\ 42 FR 53657 (October 3, 1977).
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Once the EPA has listed a source category, the EPA proposes and
then promulgates ``standards of performance'' for ``new sources'' in
the category.\88\ A ``new source'' is ``any stationary source, the
construction or modification of which is commenced after,'' in general,
final standards applicable to that source are promulgated or, if
earlier, proposed.\89\ 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.'' \90\ The EPA,
through regulations, has determined that certain types of changes are
exempt from consideration as a modification.\91\
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\88\ CAA section 111(b)(1)(B).
\89\ CAA section 111(a)(2).
\90\ CAA section 111(a)(4); See also 40 CFR 60.14 concerning
what constitutes a modification, how to determine the emission rate,
how to determine an emission increase, and specific actions that are
not, by themselves, considered modifications.
\91\ 40 CFR 60.2, 60.14(e).
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The NSPS general provisions (40 CFR part 60, subpart A) provide
that an existing source is considered to be a new source if it
undertakes a ``reconstruction,'' which is the replacement of components
of an existing facility to an extent that (1) the fixed capital cost of
the new components exceeds 50 percent of the fixed capital cost that
would be required to construct a comparable entirely new facility, and
(2) it is technologically and economically feasible to meet the
applicable standards.\92\
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\92\ 40 CFR 60.15.
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CAA section 111(a)(1) defines a ``standard of performance'' as ``a
standard for emissions . . . achievable through the application of the
best system of emission reduction which [considering cost, non-air
quality health and environmental impact, and energy requirements] the
Administrator determines has been adequately demonstrated.'' This
definition makes clear that the standard of performance must be based
on ``the best system of emission reduction . . . adequately
demonstrated'' (BSER).
The standard that the EPA develops, reflecting the performance of
the BSER, is commonly a numeric emission limit, expressed as a numeric
performance level that can either be normalized to a rate of output or
input (e.g., tons of pollution per amount of product produced--a so-
called rate-based standard), or expressed as a numeric limit on mass of
pollutant that may be emitted (e.g., 100 ug/m\3\--parts per billion).
Generally, the EPA does not prescribe a particular technological system
that must be used to comply with a standard of performance.\93\ Rather,
sources generally may select any measure or combination of measures
that will achieve the emissions level of the standard.\94\ In
establishing standards of performance, the EPA has significant
discretion to create subcategories based on source type, class, or
size.\95\
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\93\ CAA section 111(b)(5) and (h).
\94\ CAA section 111(b)(5).
\95\ CAA section 111(b)(2); see also Lignite Energy Council v.
EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).
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The text and legislative history of CAA section 111, as well as
relevant court decisions, identify the factors that the EPA is to
consider in making a BSER determination. The system of emission
reduction must be technically feasible, the costs of the system must be
reasonable, and the emission standard that the EPA promulgates based on
the system of emission reduction must be achievable. In addition, in
identifying a BSER, the EPA must consider the amount of emissions
reductions attributable to the system, and must also consider non-air
quality health and environmental impacts and energy requirements. The
case law addressing CAA section 111 makes it clear that the EPA has
discretion in weighing costs, amount of emission reductions, energy
requirements, and impacts of non-air quality pollutants, and may weigh
them differently for different types of sources or air pollutants. We
note that under the case law of the D.C. Circuit, another factor is
relevant for the BSER determination: Whether the standard would
effectively promote further deployment or development of advanced
technologies. Within the constraints just described, the EPA has
discretion in identifying the BSER and the resulting emission standard.
See generally Section III.H below.
For more than four decades, the EPA has used its authority under
CAA section 111 to set cost-effective emission standards which ensure
that newly constructed, reconstructed, and modified stationary sources
use the best performing technologies to limit emissions of harmful air
pollutants. In this final action, the EPA is following the same well-
established interpretation and application of the law under CAA section
111 to address GHG emissions from newly constructed, reconstructed, and
modified fossil fuel-fired power plants. For each of the standards in
this final action, the EPA considered a number of alternatives and
evaluated them against the statutory factors. The BSER for each
category of affected EGUs and the standards of performance based on
these BSER are based on that evaluation.
[[Page 64528]]
E. Regulatory Background
In 1971, the EPA initially included fossil fuel-fired EGUs (which
includes natural gas, petroleum and coal) that use steam-generating
boilers in a category that it listed under CAA section
111(b)(1)(A),\96\ and promulgated the first set of standards of
performance for sources in that category, which it codified in subpart
D.\97\ In 1977, the EPA initially included fossil fuel-fired combustion
turbines in a category that the EPA listed under CAA section
111(b)(1)(A),\98\ and the EPA promulgated standards of performance for
that source category in 1979, which the EPA codified in subpart GG.\99\
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\96\ 36 FR 5931 (March 31, 1971).
\97\ ``Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17,
1971,'' 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40-46.
\98\ 42 FR 53657 (October 3, 1977).
\99\ ``Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After September
18, 1978,'' 44 FR 33580 (June 11, 1979).
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The EPA has revised those regulations, and in some instances, has
revised the codifications (that is, the 40 CFR part 60 subparts),
several times over the ensuing decades. In 1979, the EPA divided
subpart D into 3 subparts--Da (``Standards of Performance for Electric
Utility Steam Generating Units for Which Construction is Commenced
After September 18, 1978''), Db (``Standards of Performance for
Industrial-Commercial-Institutional Steam Generating Units'') and Dc
(``Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units'')--in order to codify separate
requirements that it established for these subcategories.\100\ 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.\101\ None of these subsequent
rulemakings, including the revised codifications, however, constituted
a new listing under CAA section 111(b)(1)(A).
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\100\ 44 FR 33580 (June 11, 1979).
\101\ 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861
(March 20, 2009).
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The EPA promulgated amendments to subpart Da in 2006, which
included new standards of performance for criteria pollutants for EGUs,
but did not include specific standards of performance for
CO2 emissions.\102\ Petitioners sought judicial review of
the rule, contending, among other issues, that the rule was required to
include standards of performance for GHG emissions from EGUs.\103\ The
January 8, 2014 preamble to the proposed CO2 standards for
new EGUs \104\ includes a discussion of the GHG-related litigation of
the 2006 Final Rule as well as other GHG-associated litigation.
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\102\ ``Standards of Performance for Electric Utility Steam
Generating Units, Industrial-Commercial-Institutional Steam
Generating Units, and Small Industrial-Commercial-Institutional
Steam Generating Units, Final Rule.'' 71 FR 9866 (February 27,
2006).
\103\ State of New York, et al. v. EPA, No. 06-1322.
\104\ 79 FR 1430, 1444.
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F. Development of Carbon Pollution Standards for Fossil Fuel-Fired
Electric Utility Generating Units
On April 13, 2012, the EPA initially proposed standards under CAA
section 111 for newly constructed fossil fuel-fired electric utility
steam generating units. 77 FR 22392 (``April 2012 proposal''). The EPA
withdrew that proposal (79 FR 1352 (January 8, 2014)), and, on the same
day, proposed the standards addressed in this final rule. 79 FR 1430
(``January 2014 proposal''). Specifically, the EPA proposed standards
under CAA section 111 to limit emissions of CO2 from newly
constructed fossil fuel-fired electric utility steam generating units
and newly constructed natural gas-fired stationary combustion turbines.
In support of the January 2014 proposal, on February 26, 2014, the
EPA published a notice of data availability (NODA) (79 FR 10750).
Through the NODA and an associated technical support document, Effect
of EPAct05 on Best System of Emission Reduction for New Power Plants,
the EPA solicited comment on its interpretation of the provisions in
the Energy Policy Act of 2005 (EPAct05),\105\ including how the
provisions may affect the rationale for the EPA's proposed
determination that partial CCS is the best system of emission reduction
adequately demonstrated for fossil fuel-fired electric utility steam
generating units.
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\105\ See Section III.H.3.g below. The Energy Policy Act of 2005
(EPAct05) was signed into law by President George W. Bush on August
8, 2005. EPAct05 was intended to address energy production in the
United States, including: (1) Energy efficiency; (2) renewable
energy; (3) oil and gas; (4) coal; (5) Tribal energy; (6) nuclear
matters and security; (7) vehicles and motor fuels, including
ethanol; (8) hydrogen; (9) electricity; (10) energy tax incentives;
(11) hydropower and geothermal energy; and (12) climate change
technology. www2.epa.gov/laws-regulations/summary-energy-policy-act.
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On June 18, 2014, the EPA proposed standards of performance to
limit emissions of CO2 from modified and reconstructed
fossil fuel-fired electric utility steam generating units and natural
gas-fired stationary combustion turbines (79 FR 34960; June 2014
proposal). Specifically, the EPA proposed standards of performance for:
(1) Modified fossil fuel-fired electric utility steam generating units,
(2) modified natural gas-fired stationary combustion turbines, (3)
reconstructed fossil fuel-fired electric utility steam generating
units, and (4) reconstructed natural gas-fired stationary combustion
turbines.
G. Stakeholder Engagement and Public Comments on the Proposals
1. Stakeholder Engagement
The EPA has engaged extensively with a broad range of stakeholders
and the general public regarding climate change, carbon pollution from
power plants, and carbon pollution reduction opportunities. These
stakeholders included industry and electric utility representatives,
state and local officials, tribal officials, labor unions, non-
governmental organizations and many others.
In February and March 2011, early in the process of developing
carbon pollution standards for new power plants, the EPA held five
listening sessions to obtain information and input from key
stakeholders and the public. Each of the five sessions had a particular
target audience: The electric power industry, environmental and
environmental justice organizations, states and tribes, coalition
groups, and the petroleum refinery industry.
The EPA conducted subsequent outreach prior to the June 2014
proposals of standards for modified and reconstructed EGUs and emission
guidelines for existing EGUs, as well as during the public comment
periods for the proposals. Although this stakeholder outreach was
primarily framed around the GHG emission guidelines for existing EGUs,
the outreach encompassed issues relevant to this rulemaking and
provided an opportunity for the EPA to better understand previous state
and stakeholder experience with reducing CO2 emissions in
the power sector. In addition to 11 public listening sessions, the EPA
held hundreds of meetings with individual stakeholder groups, and
meetings that brought together a variety of stakeholders to discuss a
wide range of issues related to the electricity sector and regulation
of GHGs under the CAA. The agency met with electric utility
associations and electricity grid operators. Agency officials engaged
with labor unions and with leaders representing large and small
industries. The agency also met with energy industries, such as coal
and natural gas interests, as well as with representatives of energy-
intensive industries, such as
[[Page 64529]]
the iron and steel, and aluminum industries, to better understand the
potential concerns of large industrial purchasers of electricity. In
addition, the agency met with companies that offer new technology to
prevent or reduce carbon pollution. The agency provided and encouraged
multiple opportunities for engagement with state, local, tribal, and
regional environmental and energy agencies. The EPA also met with
representatives of environmental justice organizations, environmental
groups, public health professionals, public health organizations,
religious organizations, and other community stakeholders.
The EPA received more than 2.5 million comments submitted in
response to the original April 2012 proposal for newly constructed
fossil fuel-fired EGUs. Because the original proposal was withdrawn,
the EPA instructed commenters that wanted their comments on the April
2012 proposal to be considered in connection with the January 2014
proposal to submit new comments to the EPA or to re-submit their
previous comments. We received more comments in response to the January
2014 proposal, as discussed in the section below.
The EPA has given stakeholder input provided prior to the
proposals, as well as during the public comment periods for each
proposal, careful consideration during the development of this
rulemaking and, as a result, it includes elements that are responsive
to many stakeholder concerns and that enhance the rule. This preamble
and the Response-to-Comments (RTC) document summarize and provide the
agency's responses to the comments received.
2. Comments on the January 2014 Proposal For Newly Constructed Fossil
Fuel-Fired EGUs
Upon publication of the January 8, 2014 proposal for newly
constructed fossil fuel-fired EGUs, the EPA provided a 60-day public
comment period. On March 6, 2014, in order to provide the public
additional time to submit comments and supporting information, the EPA
extended the comment period by 60 days, to May 9, 2014, giving
stakeholders over 120 days to review, and comment upon, the January
2014 proposal, as well as the NODA. A public hearing was held on
February 6, 2014, with 159 speakers presenting testimony.
The EPA received more than 2 million comments on the proposed
standards for newly constructed fossil fuel-fired EGUs from a range of
stakeholders that included industry and electric utility
representatives, trade groups, equipment manufacturers, state and local
government officials, academia, environmental organizations, and
various interest groups. The agency received comments on a range of
topics, including the determination that a new highly-efficient steam
generating EGU implementing partial CCS was the BSER for such sources,
the level of the CO2 standard based on implementation of
partial CCS, the criteria that define which newly constructed natural
gas-fired stationary combustion turbines will be subject to standards,
the establishment of subcategories based on combustion turbine size,
and the rule's potential effects on the Prevention of Significant
Deterioration (PSD) preconstruction permit program and Title V
operating permit program.
3. Comments on the June 2014 Proposal For Modified and Reconstructed
Fossil Fuel-Fired EGUs
Upon publication of the June 18, 2014 proposal for modified and
reconstructed fossil fuel-fired EGUs, the EPA offered a 120-day public
comment period--through October 16, 2014. The EPA held public hearings
in four locations during the week of July 28, 2014. These hearings also
addressed the EPA's June 18, 2014 proposed emission guidelines for
existing fossil fuel-fired EGUs (reflecting the connections between the
proposed standards for modified and reconstructed sources and the
proposed emission guidelines). A total of 1,322 speakers testified, and
a further 1,450 attended but did not speak. The speakers were provided
the opportunity to present data, views, or arguments concerning one or
both proposed actions.
The EPA received over 200 comments on the proposed standards for
modified and reconstructed fossil fuel-fired EGUs from a range of
stakeholders similar to those that submitted comments on the January
2014 proposal for newly constructed fossil fuel-fired EGUs (i.e.,
industry and electric utility representatives, trade groups, equipment
manufacturers, state and local government officials, academia,
environmental organizations, and various interest groups). The agency
received comments on a range of topics, including the methodology for
determining unit-specific CO2 standards for modified steam
generating units and the use of supercritical boiler conditions as the
basis for the CO2 standards for certain reconstructed steam
generating units. Many of the comments regarding modified and
reconstructed natural gas-fired stationary combustion turbines are
similar to the comments regarding newly constructed combustion turbines
described above (e.g., applicability criteria and subcategories based
on turbine size).
III. Regulatory Authority, Affected EGUs and Their Standards, and Legal
Requirements
In this section, we describe our authority to regulate
CO2 from fossil fuel-fired EGUs. We also describe our
decision to combine the two existing categories of affected EGUs--steam
generators and combustion turbines--into a single category of fossil
fuel-fired EGUs for purposes of promulgating standards of performance
for CO2 emissions. We also explain that we are codifying all
of the requirements in this rule for new, modified, and reconstructed
affected EGUs in new subpart TTTT of part 60 of Title 40 of the Code of
Federal Regulations. In addition, we explain which sources are and are
not affected by this rule, and the format of these standards. Finally,
we describe the legal requirements for establishing these emission
standards.
A. Authority To Regulate Carbon Dioxide From Fossil Fuel-Fired EGUs
The EPA's authority for this rule is CAA section 111(b)(1). CAA
section 111(b)(1)(A) requires the Administrator to establish a list of
source categories to be regulated under section 111. A category of
sources is to be included on the list ``if in [the Administrator's]
judgment it causes, or contributes significantly to, air pollution
which may reasonably be anticipated to endanger public health and
welfare.'' This determination is commonly referred to as an
``endangerment finding'' and that phrase encompasses both the ``causes
or contributes significantly'' component and the ``endanger public
health and welfare'' component of the determination. Then, for the
source categories listed under section 111(b)(1)(A), the Administrator
promulgates, under section 111(b)(1)(B), ``standards of performance for
new sources within such category.''
In this rule, the EPA is establishing standards under section
111(b)(1)(B) for source categories that it has previously listed and
regulated for other pollutants and which now are being regulated for an
additional pollutant. Because of this, there are two aspects of section
111(b)(1) that warrant particular discussion.
First, because the EPA is not listing a new source category in this
rule, the EPA is not required to make a new endangerment finding with
regard to affected EGUs in order to establish standards of performance
for the CO2 emissions from those sources. Under the plain
language of CAA section
[[Page 64530]]
111(b)(1)(A), an endangerment finding is required only to list a source
category. Further, though the endangerment finding is based on
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, the statute is clear
that the endangerment finding is made with respect to the source
category; section 111(b)(1)(A) does not provide that an endangerment
finding is made as to specific pollutants. This contrasts with other
CAA provisions that do require the EPA to make endangerment findings
for each particular pollutant that the EPA regulates under those
provisions. E.g., CAA sections 202(a)(1), 211(c)(1), and 231(a)(2)(A);
see also American Electric Power Co. Inc., v. Connecticut, 131 S. Ct.
2527, 2539 (2011) (``[T]he Clean Air Act directs the EPA to establish
emissions standards for categories of stationary sources that, `in [the
Administrator's] judgment,' `caus[e], or contribut[e] significantly to,
air pollution which may reasonably be anticipated to endanger public
health or welfare.' Sec. 7411(b)(1)(A).'') (emphasis added).
Second, once a source category is listed, the CAA does not specify
what pollutants should be the subject of standards from that source
category. The statute, in section 111(b)(1)(B), simply directs the EPA
to propose and then promulgate regulations ``establishing federal
standards of performance for new sources within such category.'' In the
absence of specific direction or enumerated criteria in the statute
concerning what pollutants from a given source category should be the
subject of standards, it is appropriate for the EPA to exercise its
authority to adopt a reasonable interpretation of this provision.
Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984).\106\
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\106\ In Chevron, the U.S. 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.
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The EPA has previously interpreted this provision as granting it
the discretion to determine which pollutants should be regulated. See
Standards of Performance for Petroleum Refineries, 73 FR 35838 (June
24, 2008) (concluding that the statute provides ``the Administrator
with significant flexibility in determining which pollutants are
appropriate for regulation under section 111(b)(1)(B)'' and citing
cases). Further, in directing the Administrator to propose and
promulgate regulations under section 111(b)(1)(B), Congress provided
that the Administrator should take comment and then finalize the
standards with such modifications ``as he deems appropriate.'' The D.C.
Circuit has considered similar statutory phrasing from CAA section
231(a)(3) and concluded that ``[t]his delegation of authority is both
explicit and extraordinarily broad.'' National Assoc. of Clean Air
Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
In exercising its discretion with respect to which pollutants are
appropriate for regulation under section 111(b)(1)(B), the EPA has in
the past provided a rational basis for its decisions. See National Lime
Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court
discussed, but did not review, the EPA's reasons for not promulgating
standards for oxides of nitrogen (NOX), sulfur dioxide
(SO2) and CO from lime plants); Standards of Performance for
Petroleum Refineries, 73 FR at 35859-60 (June 24, 2008) (providing
reasons why the EPA was not promulgating GHG standards for petroleum
refineries as part of that rule). Though these previous examples
involved the EPA providing a rational basis for not setting standards
for a given pollutant, a similar approach is appropriate where the EPA
determines that it should set a standard for an additional pollutant
for a source category that was previously listed and regulated for
other pollutants.
In this rulemaking, the EPA has a rational basis for concluding
that emissions of CO2 from fossil fuel-fired power plants,
which are the major U.S. source of GHG air pollution, merit regulation
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 the denial of petitions to reconsider.\107\ In addition,
assessments from the NRC, the IPCC, and other organizations published
after 2010 lend further credence to the validity of the Endangerment
Finding. No information that commenters have presented or that the EPA
has reviewed provides a basis for reaching a different conclusion.
Indeed, current and evolving science discussed in detail in Section
II.A of this preamble is confirming and enhancing our understanding of
the near- and longer-term impacts emissions of CO2 are
having on Earth's climate and the adverse public health, welfare, and
economic consequences that are occurring and are projected to occur as
a result.
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\107\ Coalition for Responsible Regulation v. EPA, 684 F.3d 102,
119-126 (D.C. Circuit 2012).
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Moreover, the high level of GHG emissions from fossil fuel-fired
EGUs makes clear that it is rational for the EPA to regulate GHG
emissions from this sector. EGUs emit almost one-third of all U.S. GHGs
and comprise by far the largest stationary source category of GHG
emissions; indeed, as noted above, the CO2 emissions from
fossil fuel-fired EGUs are almost three times as much as the emissions
from the next ten source categories combined. Further, the
CO2 emissions from even a single new coal-fired power plant
may amount to millions of tons each year. See, e.g., Section V.K below
(noting that even the difference in CO2 emissions between a
highly efficient SCPC and the same unit meeting today's standard of
performance can amount to hundreds of thousands of tons each year).
These facts provide a rational basis for regulating CO2
emissions from affected EGUs.
Some commenters have argued that the EPA is required to make a new
endangerment finding before it may regulate CO2 from EGUs.
We disagree, for the reasons discussed above. Moreover, as discussed in
the January 2014 proposal,\108\ even if CAA section 111 required the
EPA to make endangerment and cause-or-contribute significantly findings
as prerequisites for this rulemaking, then, so far as the
``CO2 endangers public health and welfare'' component of an
endangerment finding is concerned, the information and conclusions
described above should be considered to constitute the requisite
endangerment finding. Similarly, so far as a cause-or-contribute
significantly finding is concerned, the information and conclusions
described above should be considered to constitute the requisite
finding. The EPA's rational basis for regulating CO2 under
CAA section 111 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 subsequent assessments from
the IPCC and NRC that describe scientific developments since those EPA
actions. In addition, we have reviewed comments presenting other
scientific information to
[[Page 64531]]
determine whether that information has any meaningful impact on our
analysis and conclusions. For both the endangerment finding and the
rational basis, the EPA focused on public health and welfare impacts
within the United States, as it did in the 2009 Finding. The impacts in
other world regions strengthen the case because impacts in other world
regions can in turn adversely affect the United States or its citizens.
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\108\ 79 FR 1430, 1455-56 (January 8, 2014).
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More specifically, our approach here--reflected in the information
and conclusions described above--is substantially similar to that
reflected in the 2009 Endangerment Finding and the 2010 denial of
petitions to reconsider. The D.C. Circuit upheld that approach in
Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 117-123
(D.C. Cir. 2012) (noting, among other things, the ``substantial . . .
body of scientific evidence marshaled by EPA in support of the
Endangerment Finding'' (id. at 120); the ``substantial record evidence
that anthropogenic emissions of greenhouse gases `very likely' caused
warming of the climate over the last several decades'' (id. at 121);
``substantial scientific evidence . . . that anthropogenically induced
climate change threatens both public health and public welfare . . .
[through] extreme weather events, changes in air quality, increases in
food- and water-borne pathogens, and increases in temperatures'' (id.);
and ``substantial evidence . . . that the warming resulting from the
greenhouse gas emissions could be expected to create risks to water
resources and in general to coastal areas. . . .'' (id.)). The facts,
unfortunately, have only grown stronger and the potential adverse
consequences to public health and the environment more dire in the
interim. Accordingly, that approach would support an endangerment
finding for this rulemaking.\109\
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\109\ Nor does the EPA consider the cost of potential standards
of performance in making this Finding. Like the Endangerment Finding
under section 202(a) at issue in State of Massachusetts v. EPA, 549
U.S. 497 (2007) the pertinent issue is a scientific inquiry as to
whether an endangerment to public health or welfare from the
relevant air pollution may reasonably be anticipated. Where, as
here, the scientific inquiry conducted by the EPA indicates that
these statutory criteria are met, the Administrator does not have
discretion to decline to make a positive endangerment finding to
serve other policy grounds. Id. at 532-35. In this regard, an
endangerment finding is analogous to setting national ambient air
quality standards under section 109(b), which similarly call on the
Administrator to set standards that in her ``judgment'' are
``requisite to protect the public health''. The EPA is not permitted
to consider potential costs of implementation in setting these
standards. Whitman v. American Trucking Assn's, 531 U.S. 457, 466
(2001); see also Michigan v. EPA, U.S. (no. 14-46, June 29, 2015)
slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes
further that section 111(b)(1) contains no terms such as ``necessary
and appropriate'' which could suggest (or, in some contexts,
require) that costs may be considered as part of the finding.
Compare CAA section 111(n)(1)(A); see State of Michigan, slip op.
pp. 7-8. The EPA, of course, must consider costs in determining
whether a best system of emission reduction is adequately
demonstrated and so can form the basis for a section 111(b) standard
of performance, and the EPA has carefully considered costs here and
found them to be reasonable. See section V. H. and I. below. The EPA
also has found that the rule's quantifiable benefits exceed
regulatory costs under a range of assumptions were new capacity to
be built. RIA chapter 5 and section XIII.G below. Accordingly, this
endangerment finding would be justified if (against our view) it is
both required, and (again, against our view) costs are to be
considered as part of the finding.
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Likewise, 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. As shown in Tables 3 and 4
in this preamble, fossil fuel-fired EGUs are very large emitters of
CO2. All told, these fossil fuel-fired EGUs emit almost one-
third of all U.S. GHG emissions, and are responsible for almost three
times as much as the emissions from the next ten stationary source
categories combined. The CO2 emissions from even a single
new coal-fired power plant may amount to millions of tons each year,
and the CO2 emissions from even a single NGCC unit may
amount to one million or more tons per year. It is not necessary in
this rulemaking 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 combustion turbines and
steam generators are a significant contribution. Indeed, these
emissions far exceed in magnitude the emissions from motor vehicles,
which have already been held to contribute to the endangerment. See
Coalition for Responsible Regulation, 684 F. 3d at 121 (``substantial
evidence'' supports the EPA's determination ``that motor-vehicle
emissions of greenhouse gases contribute to climate change and thus to
the endangerment of public health and welfare'').\110\
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\110\ The ``air pollution'' defined in the Endangerment Finding
is the atmospheric mix of six long-lived and directly emitted
greenhouse gases: Carbon dioxide (CO2), methane
(CH4), nitrous oxide (N2O), hydrofluorocarbons
(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride
(SF6). See 74 FR 66496 at 66497. The standards of
performance adopted in the present rulemaking address only one
component of this air pollution: CO2. This is reasonable,
given that CO2 is the air pollutant emitted in the
largest volume by the source category, and which is (necessarily)
emitted by every affected EGU. There is, of course, no requirement
that standards of performance address each component of the air
pollution which endangers. Section 111(b)(1)(A) requires the EPA to
establish ``standards of performance'' for listed source categories,
and the definition of ``standard of performance'' in section
111(a)(1) does not specify which air pollutants must be controlled.
See also Section III.G below explaining that CH4 and
N2O emissions represent less than 1 percent of total
estimated GHG emissions (as CO2e) from fossil fuel-fired
electric power generating units.
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B. Treatment of Categories and Codification in the Code of Federal
Regulations
As discussed in the January 2014 proposal of carbon pollution
standards for newly constructed EGUs (79 FR 1430) and above, in 1971
the EPA listed fossil fuel-fired steam generating boilers as a new
category subject to CAA section 111 rulemaking, and in 1979 the EPA
listed fossil fuel-fired combustion turbines as a new category subject
to the CAA section 111 rulemaking. In the ensuing years, the EPA has
promulgated standards of performance for the two categories and
codified those standards, at various times, in 40 CFR part 60, subparts
D, Da, GG, and KKKK.
In the January 2014 proposal of carbon pollution standards for
newly constructed EGUs (79 FR 1430) and the June 2014 proposal of
carbon pollution standards for modified and reconstructed EGUs (79 FR
34960), the EPA proposed separate standards of performance for new,
modified, and reconstructed sources in the two categories. The EPA took
comment on combining the two categories into a single category solely
for purposes of the CO2 emissions from new, modified, and
reconstructed affected EGUs. In addition, the EPA proposed codifying
the standards of performance in the same Da and KKKK subparts that
currently contain the standards of performance for other pollutants
from those sources addressed in the NSPS program, but co-proposed
codifying all the standards of performance for CO2 emissions
in a new 40 CFR part 60, subpart TTTT.
In this rule, the EPA is combining the steam generator and
combustion turbine categories into a single category of fossil fuel-
fired electricity generating units for purposes of promulgating
standards of performance for GHG emissions. Combining the two
categories is reasonable because they both provide the same product:
Electricity services. Moreover, combining them in this rule is
consistent with our decision to combine them in the CAA section 111(d)
rule for existing sources that accompanies this rule. In addition,
[[Page 64532]]
many of the monitoring, reporting, and verification requirements are
the same for both source categories, and, as discussed next, we are
codifying all requirements in a single new subpart of the regulations;
as a result, combining the two categories into a single category will
reduce confusion. It should be noted that in this rule, we are not
combining the two categories for purposes of standards of performance
for other air pollutants.
Because these two source categories are pre-existing listed source
categories and the EPA will not be subjecting any additional sources in
the categories to CAA regulation for the first time, the combination of
these two categories is not considered a new source category subject to
the listing requirements of CAA section 111(b)(1)(A). As a result, this
final rule does not list a new category under CAA section 111(a)(1)(A),
nor does this final rule revise either of the two source categories.
Thus, the EPA is not required to make a new endangerment and
contribution finding for the combination of the two categories,\111\
although as discussed in the previous section, the evidence strongly
supports such findings. Thus, the EPA has found, in the alternative,
that this category of sources contributes significantly to air
pollution which may be reasonably anticipated to endanger public health
and welfare.
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\111\ See, e.g., American Trucking Assn's v. EPA, 175 F.3d 1027,
1055, rev'd on other grounds sub. nom. Whitman v. Am. Trucking
Assn's, 531.U.S. 457 (because fine particulate matter
(PM2.5) was already included as a sub-set of the listed
pollutant particulate matter, it was not a new pollutant
necessitating a new listing).
---------------------------------------------------------------------------
C. Affected Units
We generally refer to fossil fuel-fired electric generating units
that would be subject to a CAA section 111 emission standard as
``affected'' or ``covered'' sources, units, facilities or simply as
EGUs. An EGU is any boiler, IGCC unit, or combustion turbine (in either
simple cycle or combined cycle configuration) that meets the
applicability criteria. Affected EGUs include those that commenced
construction after January 8, 2014, and meet the specified
applicability criteria and, for modifications and reconstructions, EGUs
that commenced those activities after June 18, 2014, and meet the
specified applicability criteria.
To be considered an EGU, the unit must: (1) Be capable of
combusting more than 250 MMBtu/h (260 GJ/h) heat input of fossil fuel;
\112\ and (2) serve a generator capable of supplying more than 25 MW
net to a utility distribution system (i.e., for sale to the grid).\113\
However, we are not finalizing CO2 standards for certain
EGUs. The EGUs that are not covered by the standards we are finalizing
in this rule include: (1) Non-fossil fuel units subject to a federally
enforceable permit that limits the use of fossil fuels to 10 percent or
less of their heat input capacity on an annual basis; (2) combined heat
and power (CHP) units that are subject to a federally enforceable
permit limiting annual net-electric sales to no more than the unit's
design efficiency multiplied by its potential electric output, or
219,000 MWh or less, whichever is greater; (3) stationary combustion
turbines that are not physically capable of combusting natural gas
(e.g., not connected to a natural gas pipeline); (4) utility boilers
and IGCC units that have always been subject to a federally enforceable
permit limiting annual net-electric sales to one-third or less of their
potential electric output (e.g., limiting hours of operation to less
than 2,920 hours annually) or limiting annual electric sales to 219,000
MWh or less; (5) municipal waste combustors that are subject to subpart
Eb of this part; and (6) commercial or industrial solid waste
incineration units subject to subpart CCCC of this part.
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\112\ We refer to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
\113\ We refer to the capability to supply 25 MW net to the grid
as the ``total electric sales criterion.''
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D. Units Not Covered by This Final Rule
As described in the previous section, the EPA is not issuing
standards of performance for certain types of sources--specifically,
dedicated non-fossil fuel-fired (e.g., biomass) units and industrial
CHP units, as well as certain projects under development. This section
discusses these sources and our rationale for not issuing standards for
them. Because the rationale applies to both steam generating units and
combustion turbines, we are describing it here rather than in the
separate steam generating unit and combustion turbine discussions. We
discuss the proposed applicability criteria, the topics where the
agency solicited comment, a brief summary of the relevant comments, and
the rationale for the final applicability approach for these sources.
1. Dedicated Non-fossil Fuel Units
The proposed applicability for newly constructed EGUs included
those that primarily combust fossil fuels (e.g., coal, oil, and natural
gas). The proposed applicability criteria were that affected units must
burn fossil fuels for more than 10 percent of the unit's total heat
input, on average, over a 3-year period.\114\ Under the proposed
approach, applicability under the final NSPS for CO2
emissions could have changed on an annual basis depending on the
composition of fuel burned. We solicited comment on several aspects of
the proposed applicability criteria for non-fossil fuel units.
Specifically, we solicited comment on a broad applicability approach
that would include non-fossil fuel-fired units as affected units, but
that would impose an alternate standard when the unit fires fossil
fuels for 10 percent or less of the heat input during the 3-year
applicability-determination period. We solicited comment on whether, if
such a subcategory is warranted, the applicability-determination period
for the subcategory should be 1-year or a 3-year rolling period. We
also solicited comment on whether the standard for such a subcategory
should be an alternate numerical limit or ``no emission standard.''
---------------------------------------------------------------------------
\114\ We refer to the fraction of heat input derived from fossil
fuels as the ``fossil fuel-use criterion.''
---------------------------------------------------------------------------
While the proposed exemption applied to all non-fossil fuels, most
commenters focused on biomass-specific issues. Many commenters
supported an exclusion for biomass-fired units that fire no more than
10 percent fossil fuels. Some commenters suggested that the exclusion
for biomass-fired units should be raised to a 25 percent fossil fuel-
use threshold.
Many commenters supported the proposed 3-year averaging period for
the fossil fuel-use criterion because it provides greater flexibility
for operators to use fossil fuels when supply chains for the primary
non-fossil fuels are disrupted, during unexpected malfunctions of the
primary non-fossil fuel handling systems, or when the unit's maximum
generating capacity is required by system operators for reliability
reasons. Many commenters supported the 3-year averaging period because
it is consistent with the final requirements under the EPA's Mercury
and Air Toxics Standards (MATS) and would allow non-fossil fuel-fired
units to use some fossil fuels for flame stabilization without
triggering applicability. Some commenters requested that the EPA
clarify the method an operator should use during the first 3 years of
operations to determine if a particular unit will meet the 10 percent
fossil fuel-use threshold. Others asked whether or not an affected
facility has a compliance obligation during the first 3-year period
and, if an
[[Page 64533]]
affected facility does not meet the 10 percent fossil fuel-use
threshold during several 12-month periods during the first 3 years,
whether compliance calculations would be required for such 12-month
periods. Other commenters had concerns with the 3-year averaging
period, stating that a source would no longer be subject to the NSPS if
it fell below the threshold for any of the applicability metrics that
the EPA proposed to calculate on a 3-year (or, in some cases, annual)
basis. They argued that this would create a situation in which no one
would know whether a particular plant will be subject to the standards
until years after the emissions had already occurred. Some commenters
were concerned that plants operating near the threshold could move in
and out of the regulatory system, which would provide complications for
compliance, enforcement, and permitting.
After considering these comments, the EPA has concluded that the
proposed fossil fuel-use criterion based on the actual amount of fossil
fuel burned is not an ideal approach to determine applicability. As
commenters pointed out, facilities, permitting authorities, and the
public would not know when construction is commenced whether a facility
will be subject to the final NSPS, and after operation has commenced, a
unit could move in and out of applicability each year. The intent of
this rulemaking is to establish CO2 standards for fossil
fuel-fired EGUs, not for non-fossil fuel-fired EGUs. Therefore, to
simplify compliance and establish CO2 standards for only
those sources which we set out to regulate, we are finalizing a fossil
fuel-use criterion that will exempt dedicated non-fossil units.
Specifically, units that are capable of burning 50 percent or more non-
fossil fuel are exempt from the final standards so long as they are
subject to a federally enforceable permit that limits their use of
fossil fuels to 10 percent or less of their heat input capacity on an
annual basis. This approach establishes clear applicability criteria
and avoids the prospect of units moving in and out of applicability
based on their actual fuel use in a given year. Consistent with the
applicability approach in the steam generating unit criteria pollutant
NSPS, subpart Da, the final fossil fuel-use criterion does not include
``constructed for the purpose of'' language. Therefore, an owner or
operator could change a unit's applicability in the future by seeking a
modification of the unit's permit conditions. A unit with the
appropriate permit limitation will not be subject to the requirements
in this rulemaking. Similarly, an existing unit that takes a permit
limitation restricting fossil-fuel use would no longer be an affected
unit for the purposes of 111(d) state plans. This is consistent with
our intent to reduce GHG emissions from fossil fuel-fired EGUs.
We considered using either an annual or 3-year average for
calculating compliance with the final fossil fuel-use criterion.
Ultimately, we concluded that an annual average would provide
sufficient flexibility for dedicated non-fossil units to combust fossil
fuels for flame stabilization and other ancillary purposes, while
maintaining consistency with the 12-month compliance periods used for
most permit limitations. A 3-year average potentially would allow units
to combust a significant quantity of fuels in a given year, leading to
higher CO2 emissions, so long as they curtailed fossil-fuel
use in a later year. This would defeat the purpose of the criterion,
which is to exempt dedicated non-fossil units only. Finally, we are
finalizing the 10 percent fossil-fuel use threshold in relation to a
unit's heat input capacity rather than its actual heat input, which is
consistent with past approaches we have taken under the industrial
boiler criteria pollutant NSPS.
2. Industrial CHP Units
Another approach to generating electricity is the use of CHP units.
A CHP unit can use a boiler, combustion turbine, reciprocating engine,
or various other generating technologies to generate electricity and
useful thermal energy in a single, integrated system. CHP units are
generally more efficient than conventional power plants because the
heat that is normally wasted in a conventional power generation cooling
system (e.g., cooling towers) is instead recovered as useful thermal
output. While the EPA did propose some applicability provisions
specific to CHP units (e.g., subtract purchased power of adjacent
facilities when determining total electric sales), in general, the
proposed applicability criteria for electric-only units and CHP units
were similar. The intent of the proposed total and percentage electric
sales criteria was to cover only utility CHP units, not industrial CHP
units. To the extent that the proposal's applicability provisions would
have the effect of covering industrial CHP units, we solicited comment
on an appropriate applicability exemption, and the criteria for that
exemption, for highly efficient CHP facilities.
Many commenters supported the exclusion of CHP units as a means of
encouraging capital investments in highly efficient and reliable
distributed generation technologies. These commenters recommended that
the EPA adopt an explicit exemption for CHP units at facilities that
are classified as industrial (e.g., gas-fired CHPs within SIC codes
2911--petroleum refining, 13--oil and gas extraction, and other
industrial SIC codes as appropriate). They also stated that the EPA
should exclude CHP units that have an energy savings of 10 percent or
more compared to separate heat and power. One commenter suggested that
the final rule should cover only industrial-commercial-institutional
CHP units that supply, on a net basis, more than two-thirds of their
potential combined thermal and electric energy output and more than
450,000 MWh net-electric output to a utility power distribution system
on an annual basis for five consecutive calendar years. The commenter
also suggested that CHP units which have total thermal energy
production that approaches or exceeds their total electricity
production should be exempted.
Other commenters suggested exempting CHP units by fuel type or
based on the definition of potential electric output. For example, some
commenters suggested modifying the percentage electric sales threshold
to be based on net system efficiency (including useful thermal output)
rather than the rated net-electric-output efficiency. They also
suggested that the applicability criteria should use a default
efficiency of 50 percent for CHP units. Some commenters suggested that
a CHP unit should not be considered an affected EGU if 20 percent or
more of its total gross or net energy output consisted of useful
thermal output on a 3-year rolling average basis. Other commenters said
that highly efficient CHP units that achieve an overall efficiency
level of 60 to 70 percent or higher should be excluded from
applicability.
The intent of this rulemaking is to cover only utility CHP units,
because they serve essentially the same purpose as electric-only EGUs
(i.e., the sale of electricity to the grid). Industrial CHP units, on
the other hand, serve a different primary purpose (i.e., providing
useful thermal output with electric sales as a by-product). With these
facts in mind and after considering the comments, the EPA has concluded
that it is appropriate to consider two factors for the final CHP
exemption: (1) Whether the primary purpose of the CHP unit is to
provide useful thermal output rather than electricity and (2) whether
the CHP unit
[[Page 64534]]
is highly efficient and thus achieves environmental benefits.
We rejected many of the approaches suggested by the commenters
because they did not achieve one or both of the factors we identified.
Specifically, the EPA has concluded that SIC code classification is not
a sufficient indicator of the purpose (i.e., it does not correlate to
useful thermal output) or environmental benefits (i.e., efficiency) of
a unit. Further, an exemption based on SIC code could result in
circumvention of the intended applicability. For example, this approach
would allow a new EGU to locate near an industrial site, provide a
trivial amount of useful thermal output to that site, sell electricity
to the grid, and nonetheless avoid applicability. Similarly, increasing
the electric sales criteria to two-thirds of potential electric output
and 450,000 MWh would essentially amount to a blanket exemption that
tells us nothing about the primary purpose or efficiency of the unit.
On the other hand, exemptions based on useful thermal output being
greater than 20 percent of total output, thermal output being greater
than electric output, or overall design efficiency value would identify
whether the primary purpose of a unit is to generate thermal output,
but they would not recognize the environmental benefits of highly
efficient CHP units. While overall efficiency may appear to be a good
indicator of environmental benefits, this is not always the case with
CHP units. Overall efficiency is a function of both efficient design
and the power to heat ratio (the amount of electricity relative to the
amount of useful thermal output). For example, boiler-based CHP units
tend to produce large amounts of useful thermal output relative to
electric output and tend to have high overall efficiencies. For units
producing primarily useful thermal output, the equivalent separate heat
and power efficiency (i.e., the theoretical overall efficiency if the
electricity and useful thermal output were produced by a stand-alone
EGU and stand-alone boiler) would approach that of a stand-alone boiler
(e.g., 80 percent). However, combustion turbine-based CHP units tend to
produce relatively equal amounts of electricity and useful thermal
output. In this case, the equivalent separate heat and power efficiency
would be closer to 65 percent. Therefore, an exemption based on overall
efficiency is not an indication of the fuel savings a CHP unit will
achieve relative to separate heat and power. Further, this approach
would encourage the development of CHP units that just meet the
efficiency exemption criterion and would still cover many combustion
turbine-based industrial CHP units. Conversely, while an exemption
based on fuel savings relative to separate heat and power would
recognize the environmental benefit of highly efficient CHP units, it
would not consider the primary purpose of the CHP unit.
In the end, the EPA has concluded that maintaining the proposed
percentage electric sales criterion with two adjustments addresses both
factors with which we are concerned. First, we are changing the
definition of ``potential electric output'' to be based on overall net
efficiency at the maximum electric production rate, instead of just
electric-only efficiency. Second, we are changing the percentage
electric sales criterion to reflect the sliding scale, which is the
overall design efficiency, calculated at the maximum useful thermal
rating of the CHP unit (e.g., a CHP unit with a extraction condensing
steam turbine would determine the efficiency at the maximum extraction/
bypass rate), of the unit multiplied by the unit's potential electric
output instead of one-third of potential electric output as proposed.
This approach recognizes the primary purpose of industrial CHP units by
providing a more generous percentage electric sales exemption to CHP
units with high thermal output. As described previously, CHP units with
high thermal loads tend to be more efficient and will therefore have a
higher allowable percentage electric sales. By amending both the
definition of ``potential electric output'' and the electric sales
threshold, we assure that CHP units that primarily produce useful
thermal output are exempted as industrial CHP units even if they are
selling all of their electric output to the grid. As the relative
amount of electricity generated by the CHP unit increases, efficiency
will generally decrease, thus limiting allowable electric sales before
applicability is triggered. This approach also recognizes the
environmental benefits of increased efficiency by encouraging
industrial CHP units to be designed as efficiently as possible to take
advantage of the higher electric sales permitted by the sliding scale.
In conclusion, a CHP unit will be an affected source unless it is
subject to a federally enforceable permit that limits annual total
electric sales to less than or equal to the unit's design efficiency
multiplied by its potential electric output or 219,000 MWh,\115\
whichever is greater. This final applicability criterion will only
cover CHP units that condense a significant portion of steam generated
by the unit and use the electric power generated as a result of
condensing that steam to supply electric power to the grid. CHP
facilities that do not have a condensing steam turbine (e.g.,
combustion turbine-based CHP units without a steam turbine and boiler-
based systems with a backpressure steam turbine) would generally not be
physically capable of selling enough electricity to meet the
applicability criterion, even if they sold 100 percent of the
electricity generated and did not subtract out the electricity used by
the thermal host(s). The EPA has concluded that this is appropriate
because these sources are industrial by design and provide mostly
useful thermal output.
---------------------------------------------------------------------------
\115\ The EPA has concluded that it is appropriate to maintain
the 219,000 MWh total electric sales criterion for combustion
turbine based CHP units to avoid potentially covering smaller
industrial CHP units.
---------------------------------------------------------------------------
CHP facilities with a steam extraction condensing steam turbine
will determine their potential electric output based on their
efficiency on a net basis at the maximum electric production rate at
the base load heat input rating (e.g., the CHP is condensing as much
steam as possible to create electricity instead of using it for useful
thermal output). We have concluded that it is necessary for CHP units
with extraction condensing steam turbines to calculate their potential
electric output at the maximum condensing level to avoid circumvention
of the applicability criteria. For example, to avoid applicability a
CHP unit could locate next to an industrial host and have the
capability of selling significant quantities of useful thermal output
without ever actually intending to supply much, if any, useful thermal
output to the industrial host. If we calculated the potential electric
output at the maximum level of thermal output, this type of CHP unit
could operate at full condensing mode at base load conditions for the
entire year and still not exceed the electric sales threshold. During
the permitting process, the owner or operator will be able to determine
if the unit is subject to the final standards in this rule.
New EGUs with only limited useful thermal output will be subject to
the final standards, but the vast majority of new CHP units will be
classified as industrial CHP and will not be subject to the final
standards. The EPA has concluded that this approach is similar to
exempting CHP facilities that sell less than half of their total output
(electricity plus thermal), but has the benefit of accounting for
overall design efficiency.
[[Page 64535]]
This approach both limits applicability to the industrial CHP units and
encourages the installation of the most efficient CHP systems because
more efficient designs will be able to have higher permitted electric
sales while not being subject to the CO2 standards included
in this rulemaking.
3. Municipal Waste Combustors and Commercial and Industrial Solid Waste
Incinerators
The purpose of this rulemaking is to establish CO2
standards for fossil fuel-fired EGUs. Municipal waste combustors and
commercial and industrial solid waste incinerators typically have not
been included in this source category. Therefore, even if one of these
types of units meets the general heat input and electric sales
criteria, we are not finalizing CO2 emission standards for
municipal waste combustors subject to subpart Eb of this part and
commercial and industrial solid waste incinerators subject to subpart
CCCC of this part.
4. Certain Projects Under Development
The EPA proposed that a limited class of projects under development
should not be subject to the proposed standards. These were planned
sources that may be capable of commencing construction (within the
meaning of section 111(a)) shortly after the standard's proposal date,
and so would be classified as new sources, but which have a design
which would be incapable of meeting the proposed standard of
performance. See 79 FR 1461 and CAA section 111(a)(2). The EPA proposed
that these sources would not be subject to the generally-applicable
standard of performance, but rather would be subject to a unit-specific
permitting determination if and when construction actually commences.
The EPA indicated that there could be three sources to which this
approach could apply, and further indicated that the EPA could
ultimately adopt the generally-applicable standard of performance for
these sources (if actually constructed). 79 FR 1461.
As explained at Section III.J below, the EPA is finalizing this
approach in this final rule. We again note that these sources, if and
when constructed, could be ultimately subject to the 1,400 lb
CO2/MWh-g standard, especially if there is no engineering
basis, or demonstrated action in reliance, showing that the new source
could not meet that standard.
E. Coal Refuse
In the April 2012 proposal, we solicited comment on subcategorizing
and exempting 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. Observing that
coal refuse-fired EGUs typically use fluidized bed technologies, other
commenters disagreed with any exemption, specifically citing the
N2O emissions from fluidized bed boilers. In light of the
environmental benefits of remediating coal refuse piles cited by
commenters, the limited amount of coal refuse, and the fact that a new
coal refuse-fired EGU would be located in close proximity to the coal
refuse pile, we sought additional comments regarding a subcategory for
coal refuse-fired EGUs in the January 2014 proposal. Specifically, we
requested additional information on the net environmental benefits of
coal refuse-fired EGUs and information to support an appropriate
emissions standard for coal refuse-fired EGUs. One commenter on the
April 2012 proposal stated that existing coal refuse piles are
naturally combusting at a rate of 0.3 percent annually, and we
requested comment on this rate and the proper approach to account for
naturally occurring emissions from coal refuse piles in the January
2014 proposal.
Commenters said that a performance standard is not feasible for
coal refuse CFBs since there is no economically feasible way to capture
CO2 through a conveyance designed and constructed to capture
CO2. Commenters suggested that the EPA establish BSER for
GHGs at modified coal refuse CFBs as a boiler tune-up that must be
performed at least every 24 months. Commenters stated that the EPA
should exempt coal refuse CFB units relative to their CO2
emissions to the extent that these units offset the uncontrolled ground
level emissions from spontaneous combustion of legacy coal refuse
stockpiles and noted that the mining of coal waste not only produces
less emissions in the long term, but also helps to reclaim land that is
currently used to store coal waste. In contrast, one commenter saw no
legitimate basis for coal refuse to be subcategorized and stated that
it should be treated in the same manner as all other coal-fired EGUs.
The EPA has concluded that an explicit exemption or subcategory
specifically for coal refuse-fired EGUs is not appropriate. The costs
faced by coal refuse facilities to install CCS are similar to coal-
fired EGUs burning any of the primary coals, and the final applicable
requirements and standards in the rule do not preclude the development
of new coal refuse-fired units without CCS. Specifically, we are not
finalizing CO2 standards for industrial CHP units. Many
existing coal refuse-fired units are relatively small and designed as
CHP units. Due to the expense of transporting coal refuse long
distances, we anticipate that any new coal refuse-fired EGU would be
relatively small in size. Moreover, sites with sufficient thermal
demand exist such that the unit could be designed as an industrial CHP
facility and the requirements of this rule would not apply.
F. Format of the Output-Based Standard
1. Net and Gross Output-Based Standards
For all newly constructed units, the EPA proposed standards as
gross output emission rates consistent with current monitoring and
reporting requirements under 40 CFR part 75.\116\ For a non-CHP EGU,
gross output is the electricity generation measured at the generator
terminals. However, we solicited comment on finalizing equivalent net-
output-based standards either as a compliance alternative or in lieu of
the proposed gross-output-based standards. Net output is the gross
electrical output less the unit's total parasitic (i.e., auxiliary)
power requirements. A parasitic load for an EGU is a load or device
powered by electricity, steam, hot water, or directly by the gross
output of the EGU that does not contribute electrical, mechanical, or
useful thermal output. In general, parasitic energy demands include
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 NGCC power
output. The use of CCS increases both the electric and steam parasitic
loads used internal to the unit, and these outputs are not considered
when determining the emission rate. Net output is used to recognize the
environmental benefits of: (1) EGU designs and control equipment that
use less auxiliary power; (2) fuels that require less emissions control
equipment; and (3) higher efficiency motors, pumps, and fans. For
modified and reconstructed combustion turbines, the EPA also proposed
standards as gross output emission rates, but solicited comment on
finalizing net output standards. The rationale was that due to the low
auxiliary loads in non-CCS NGCC designs, the difference between a
gross-output standard and a net-output standard has a limited
[[Page 64536]]
impact on environmental performance. Auxiliary loads are more
significant for modified and reconstructed boilers and IGCC units, and
the EPA proposed standards on a net output basis for these units. The
rationale included that this would enable owners/operators of these
types of units to pursue projects that reduce auxiliary loads for
compliance purposes. However, the EPA solicited comment on finalizing
the standards on a gross-output basis. We also proposed to use either
gross-output or net-output bases for each respective subcategory of
EGUs (i.e., utility boilers, IGCC units, and combustion turbines)
consistently across all CAA section 111(b) standards for new, modified,
and reconstructed EGUs.
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\116\ 79 FR 1447-48.
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Many commenters supported gross-output-based standards, maintaining
that a net-output standard penalizes the operation of air pollution
control equipment. Several commenters disagreed with the agency's
proposed rationale that a net-output standard would provide incentive
to minimize auxiliary loads. The commenters believe utility commissions
and existing economic forces already provide utilities with appropriate
incentives to properly manage all of these factors. Some commenters
supported a gross-output-based standard because variations in site
conditions (e.g., available natural gas pressure, available cooling
water sources, and elevation) will likely penalize some owners and
benefit others simply through variations in their particular plant-site
conditions if a net basis is used. Several commenters stated that if
the final rule includes a net-output-based standard, it should be
included as an option in conjunction with a gross-output-based option.
Several commenters opposed net-output-based standards because they
believe it is difficult to accurately determine the net output of an
EGU. They pointed out that many facilities have transformers that
support multiple units at the facility, making unit-level reporting
difficult. These commenters also stated that station electric services
may come from outside sources to supply certain ancillary loads. One
commenter stated that the benefit of switching to net-output-based
standards would be small and would not justify the substantial
complexities in both defining and implementing such a standard.
Conversely, other commenters stated that net-metering is a well-
established technology that should be required, particularly for newly
constructed units.
Other commenters, however, maintained that the final rule should
strictly require compliance on a net output-basis. They believe that
this is the only way for the standards to minimize the carbon footprint
of the electricity delivered to consumers. These commenters believe
that, at a minimum, net-output-based standards should be included as an
option in the final rule.
We are only finalizing gross-output-based standards for utility
boilers and IGCC units. Providing an alternate net-output-based
standard that is based on gross-output-based emissions data and an
assumed auxiliary load is most appropriate when the auxiliary load can
be reasonably estimated and the choice between the net- and gross-
output-based standard will not impact the identified BSER. For example,
the auxiliary load for combustion turbines is relatively fixed and
small, approximately 2.5 percent, so the choice between a gross and
net-output-based standard will not substantially impact technology
choices. However, in the case of utility boilers, we have concluded
that we do not have sufficient information to establish an appropriate
net-output-based standard that would not impact the identified BSER for
these types of units. The BSER for newly constructed steam generating
units is based on the use of partial CCS. However, unlike the case for
combustion turbines, owners/operators of utility boilers have multiple
technology pathways available to comply with the actual emission
standard. The choice of both control technologies and fuel impact the
overall auxiliary load. For example, a coal-fired hybrid EGU (e.g., one
that includes integrated solar thermal equipment for feedwater heating
or steam augmentation) or a coal-fired EGU co-firing natural gas would
have lower non-CCS related auxiliary loads and, because the amount of
CCS needed to comply with the standard would also be smaller, the CCS
auxiliary loads would also be reduced. Therefore, we cannot identify an
appropriate assumed auxiliary load to establish an equivalent net-
output-based standard. In addition, many IGCC facilities (which could
be used as an alternative technology for complying with the standard of
performance; see Sections IV.B and V.P below) have been proposed or are
envisioned as co-production facilities (i.e., to produce useful by-
products and chemicals along with electricity). As noted in the
proposal, we have concluded that predicting the net electricity at
these co-production facilities would be more challenging to implement
under these circumstances.
In contrast, based on further evaluation and review of issues
raised by commenters, the EPA is finalizing the CO2 standard
for combustion turbine EGUs in a format that is similar to the current
NSPS format for criteria pollutants. The default final standards
establish a gross-output-based standard. This allows owners/operators
of new combustion turbines to comply with the CO2 emissions
standard under part 60 using the same data currently collected under
part 75.\117\ However, many permitting authorities commented
persuasively that the environmental benefits of using net-output-based
standards can outweigh any additional complexities for particular
units, and have indeed adopted net-output standards in recent GHG
operating permits for combustion turbines. We expect this trend to
continue and have concluded that it is appropriate to support the
expanded use of net-output-based standards, and therefore are allowing
certain sources to elect between gross output-based and net-output-
based standards. Only combustion turbines are eligible to make this
election.
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\117\ Additionally, having an NSPS standard that is measured
using the same monitoring equipment as required under the operating
permit minimizes compliance burden. If a combustion turbine were
subject to both a gross and net emission limit, more expensive
higher accuracy monitoring could be required for both measurements.
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The rule specifies an alternative net-output-based standard of
1,030 lb CO2/MWh-n for combustion turbines. This standard is
equivalent to the otherwise-applicable gross-output-based standard of
1,000 lb CO2/MWh-g.\118\
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\118\ Assuming a 3 percent auxiliary load for the NGCC system.
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The procedures for requesting this alternative net-output-based
standard require the owner or operator to petition the Administrator in
writing to comply with the alternate applicable net-output-based
standard. If the Administrator grants the petition, this election would
be binding and would be the unit's sole means of demonstrating
compliance. Owners or operators complying with the net-output-based
standard must similarly petition the Administrator to switch back to
complying with the gross-output-based standard.
2. Useful Thermal Output
For CHP units, useful thermal output is also used when determining
the emission rate. Previous rulemakings issued by the EPA have
prescribed various ``discount factors'' of the measured useful thermal
output to be used when determining the emission rate. We proposed that
75 percent credit is the appropriate discount factor for useful thermal
output, and we solicited
[[Page 64537]]
comment on a range from two-thirds to three-fourths credit for useful
thermal output in the proposal for newly constructed units and two-
thirds to one hundred percent credit in the proposal for modified and
reconstructed units. The 75 percent credit was based on matching the
emission rate, but not the overall emissions, of a hypothetical CHP
unit to the proposed emission rate.
Many commenters said that in order to fully account for the
environmental benefits of CHP and to reflect the environmental benefits
of CHP, the EPA should allow 100 percent of the useful thermal output
from CHP units. Commenters noted that providing 100 percent credit for
useful thermal output is consistent with the past practice of the EPA
in the stationary combustion turbine criteria pollutant NSPS and state
approaches for determining emission rates for CHP units.
Based on further consideration and review of the comments
submitted, we are finalizing 100 percent credit for useful thermal
output for all newly constructed, modified, and reconstructed CHP
sources. We have concluded that this is appropriate because, at the
same reported emission rate, a hypothetical CHP unit would have the
same overall GHG emissions as the combined emission rate of separate
heat and power facilities. Any discounting of useful thermal output
could distort the market and discourage the development of new CHP
units. Full credit for useful thermal output appropriately recognizes
the environmental benefit of CHP.
G. CO2 Emissions Only
The air pollutant regulated in this final action is greenhouse
gases. However, the standards in this rule are expressed in the form of
limits on only emissions of CO2, and not the other
constituent gases of the air pollutant GHGs.\119\ We are not
establishing a limit on aggregate GHGs or separate emission limits for
other GHGs (such as methane (CH4) or nitrous oxide
(N2O)) as other GHGs represent less than 1 percent of total
estimated GHG emissions (as CO2e) from fossil fuel-fired
electric power generating units.\120\ Notwithstanding this form of the
standard, consistent with other EPA regulations addressing GHGs, the
air pollutant regulated in this rule is GHGs.\121\
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\119\ As noted above, in the Endangerment Finding, the EPA
defined the relevant ``air pollution'' as the atmospheric mix of six
long-lived and directly-emitted greenhouse gases: carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SF6). 74 FR 66497.
\120\ EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting/.
\121\ See 77 FR 31257-30 (June 3, 2010).
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H. Legal Requirements for Establishing Emission Standards
1. Introduction
In the January 2014 proposal, we described the principal legal
requirement for standards of performance under CAA section 111(b),
which is that the standards of performance must consist of standards
for emissions that reflect the degree of emission limitation achievable
though the application of the ``best system of emission reduction . . .
adequately demonstrated,'' taking into account cost and any non-air
quality health and environment impact and energy requirements. We noted
that the D.C. Circuit has handed down numerous decisions that interpret
this CAA provision, including its component elements, and we reviewed
that case law in detail.\122\
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\122\ 79 FR 1430, 1462 (January 8, 2014).
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We received comments on our proposed interpretation, and in light
of those comments, in this rule, we are clarifying our interpretation
in certain respects. We discuss our interpretation below.\123\
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\123\ We also discuss our interpretation of the requirements for
standards of performance and the BSER under section 111(d), for
existing sources, in the section 111(d) rulemaking that the EPA is
finalizing with this rule. Our interpretations and applications of
these requirements in the two rulemakings are generally consistent
with each other except to the extent that they reflect distinctions
between new and existing sources. For example, the BSER for new
industrial facilities, which are expected to have lengthy useful
lives, should include, at a minimum, the most advanced pollution
controls available, but for existing sources, the additional costs
of retrofit may render those controls too expensive.
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2. CAA Requirements and Court Interpretation
As noted above, the CAA section 111 requirements that govern this
rule are as follows: 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.'' CAA 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. CAA 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.'' CAA section
111(b)(2). The term ``standard of performance'' is defined to ``mean[ ]
a standard for emissions . . . achievable through the application of
the best system of emission reduction which [considering cost, non-air
quality health and environmental impact, and energy requirements] the
Administrator determines has been adequately demonstrated.'' CAA
section 111(a)(1).
As noted in the January 2014 proposal, Congress first included the
definition of ``standard of performance'' when enacting CAA section 111
in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977
CAAA, and then amended it again in the 1990 CAAA to largely restore the
definition as it read in the 1970 CAAA. It is in the legislative
history for the 1970 and 1977 CAAAs that Congress primarily addressed
the definition as it read at those times, and that legislative history
provides guidance in interpreting this provision.\124\ In addition, the
D.C. Circuit has reviewed rulemakings under CAA section 111 on numerous
occasions during the past 40 years, handing down decisions dated from
1973 to 2011,\125\ through which the
[[Page 64538]]
Court has developed a body of case law that interprets the term
``standard of performance.''
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\124\ 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. 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 in
the case law remain relevant to the definition as it reads today.
\125\ 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). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1,
2015).
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3. Key Elements of Interpretation
By its terms, the definition of ``standard of performance'' under
CAA section 111(a)(1) provides that the emission limits that the EPA
promulgates must be ``achievable'' by application of a ``system of
emission reduction'' that the EPA determines to be the ``best'' 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'' \126\ reduced and the role of ``technological
innovation.'' \127\ The Court has emphasized that the EPA has
discretion in weighing those various factors.128 129
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\126\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
\127\ See Sierra Club v. Costle, 657 F.2d at 347.
\128\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C.
Cir. 1999).
\129\ Although section 111(a)(1) may be read to state that the
factors enumerated in the parenthetical are part of the ``adequately
demonstrated'' determination, the D.C. Circuit's case law appears to
treat them as part of the ``best'' determination. See Sierra Club v.
Costle, 657 F.2d at 325-26. It does not appear that those two
approaches would lead to different outcomes. In this rule, the EPA
is following the D.C. Circuit case law and treating the factors as
part of the ``best'' determination.
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Our overall approach to determining the BSER, which incorporates
the various elements, is as follows: First, the EPA identifies the
``system[s] of emission reduction'' that have been ``adequately
demonstrated'' for a particular source category. Second, the EPA
determines the ``best'' of these systems after evaluating extent of
emission reductions, costs, any non-air health and environmental
impacts, and energy requirements. And third, the EPA selects an
achievable standard for emissions--here, the emission rate--based on
the performance of the BSER. The remainder of this subsection discusses
the various elements in that analytical approach.
a. ``System[s] of Emission Reduction . . . Adequately Demonstrated''
The EPA's first step is to identify ``system[s] of emission
reduction . . . adequately demonstrated.'' For the reasons discussed
below, for the various types of newly constructed, modified, and
reconstructed sources in this rulemaking, the EPA focused on efficient
generation, add-on controls, efficiency improvements, and clean fuels
as the systems of emission reduction.
An ``adequately demonstrated'' system, according to the D.C.
Circuit, is ``one which has been shown to be reasonably reliable,
reasonably efficient, and which can reasonably be expected to serve the
interests of pollution control without becoming exorbitantly costly in
an economic or environmental way.'' \130\ It does not mean that the
system ``must be in actual routine use somewhere.'' \131\ Rather, the
Court has said, ``[t]he 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.'' \132\ Similarly, the EPA may ``hold the industry to a
standard of improved design and operational advances, so long as there
is substantial evidence that such improvements are feasible.'' \133\
Ultimately, the analysis ``is partially dependent on `lead time,' ''
that is, ``the time in which the technology will have to be
available.'' \134\ Per CAA section 111(e), standards of performance
under CAA section 111(b) are applicable immediately after the effective
date of their promulgation.
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\130\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\131\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and
House bills and reports from which the language in CAA section 111
grew).
\132\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
\133\ Sierra Club v. Costle, 657 F.2d 298, 364 (1981).
\134\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
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(1) Technical Feasibility of the Best System of Emission Reduction
As the January 2014 proposal indicates, the requirement that the
standard for emissions be ``achievable'' based on the ``best system of
emission reduction . . . adequately demonstrated'' indicates that one
of the requirements for the technology or other measures that the EPA
identifies as the BSER is that the measure must be technically
feasible. See 79 FR 1430, 1463 (January 8, 2014).
b. ``Best''
In determining which adequately demonstrated system of emission
reduction is the ``best,'' the EPA considers the following factors:
(1) Costs
Under CAA section 111(a)(1), the EPA is required to take into
account ``the cost of achieving'' the required emission reductions. As
described in the January 2014 proposal,\135\ in several cases the D.C.
Circuit has elaborated on this cost factor and formulated the cost
standard in various ways, stating that the EPA may not adopt a standard
the cost of which would be ``exorbitant,'' \136\ ``greater than the
industry could bear and survive,'' \137\ ``excessive,'' \138\ or
``unreasonable.'' \139\ For convenience, in this rulemaking, we use
`reasonableness' to describe costs well within the bounds established
by this jurisprudence.\140\
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\135\ 79 FR 1464 (January 8, 2014).
\136\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C.
Cir. 1999).
\137\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
\138\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\139\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\140\ These cost formulations are consistent with the
legislative history of section 111. 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. Some commenters asserted that
we do not have authority to revise the cost standard as established
in the case law, e.g., ``exorbitant,'' ``excessive,'' etc., to a
``reasonableness'' standard that may be considered less protective
of the environment. We agree that we do not have authority to revise
the cost standard as established in the case law, and we are not
attempting to do so here. Rather, our description of the cost
standard as ``reasonableness'' is intended to be a convenient term
for referring to the cost standard as established in the case law.
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The D.C. Circuit has indicated that the EPA has substantial
discretion in its consideration of cost under section 111(a). In
several cases, the Court upheld standards that entailed significant
costs, consistent with Congress's view 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.'' \141\ See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d
427, 440 (D.C. Cir. 1973); \142\ Portland Cement Association v.
Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club v.
Costle, 657 F.2d 298, 313 (D.C. Cir.
[[Page 64539]]
1981) (upholding standard imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . . .
is substantial'').\143\ Moreover, section 111(a) does not provide
specific direction regarding what metric or metrics to use in
considering costs, again affording the EPA considerable discretion in
choosing a means of cost consideration.\144\
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\141\ 1977 House Committee Report at 184.
\142\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769
(March 21, 1972).
\143\ Indeed, in upholding the EPA's consideration of costs
under the provisions of the Clean Water Act authorizing technology-
based standards based on performance of a best technology taking
costs into account, courts have also noted the substantial
discretion delegated to the EPA to weigh cost considerations with
other factors. Chemical Mfr's Ass'n v. EPA, 870 F.2d 177, 251 (5th
Cir. 1989); Association of Iron and Steel Inst. v. EPA, 526 F.2d
1027, 1054 (3d Cir. 1975); Ass'n of Pacific Fisheries v. EPA, 615
F.2d 794, 808 (9th Cir. 1980).
\144\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C.
Cir. 2001) (where CAA section 213 does not mandate a specific method
of cost analysis, the EPA may make a reasoned choice as to how to
analyze costs).
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As discussed below, the EPA may consider costs on both a source-
specific basis and a sector-wide, regional, or nationwide basis. The
EPA is finding here that whether costs are considered on a source-
specific basis, an industry/national basis, or both, they are
reasonable. See Sections V.H and I below.
(2) Non-Air Quality Health and Environmental Impacts
Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact'' in
determining the BSER. As the D.C. Circuit has explained, this
requirement makes explicit that a system cannot be ``best'' if it does
more harm than good due to cross-media environmental impacts.\145\ The
EPA has carefully considered such cross-media impacts here, in
particular potential impacts to underground sources of drinking water
posed by CO2 sequestration, and water use necessary to
operate carbon capture systems. See Sections V.N and O below.
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\145\ Portland Cement v. EPA, 486 F.2d at 384; Sierra Club v.
Costle, 657 F.2d at 331; see also Essex Chemical Corp. v.
Ruckelshaus, 486 F.2d at 439 (remanding standard to consider solid
waste disposal implications of the BSER determination).
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(3) Energy Considerations
Under CAA section 111(a)(1), the EPA is required to take into
account ``energy requirements.'' As discussed below, the EPA may
consider energy requirements on both a source-specific basis and a
sector-wide, region-wide, or nationwide basis. Considered on a source-
specific basis, ``energy requirements'' entail, for example, the
impact, if any, of the system of emission reduction on the source's own
energy needs. In this rulemaking, as discussed below in Section V.O.3,
the EPA considered the parasitic load requirements of partial CCS. The
EPA is finding here that whether energy requirements are considered on
a source-specific basis, an industry/national basis, or both, they are
reasonable. See Sections V.O.3 and XIII.C.
(4) Amount of Emissions Reductions
At proposal, we noted that although the definition of ``standard of
performance'' does not by its terms identify the amount of emissions
from the category of sources or 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 in fact 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'').\146\ The fact that the purpose of a ``system of emission
reduction'' is to reduce emissions, and that the term itself explicitly
incorporates the concept of reducing emissions, supports the Court's
view that in determining whether a ``system of emission reduction'' is
the ``best,'' the EPA must consider the amount of emission reductions
that the system would yield.\147\ Even if the EPA were not required to
consider the amount of emission reductions, the EPA has the discretion
to do so, on grounds that either the term ``system of emission
reduction'' or the term ``best'' may reasonably be read to allow that
discretion.
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\146\ 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.'' As noted above, the 1990 CAAA deleted
``technological,'' and thereby returned the phrase to how it read
under the 1970 CAAA. The court's interpretation of this phrase in
Sierra Club v. Costle to require consideration of the amount of air
emissions reductions remains valid for the phrase ``best system.''
\147\ See also NRDC v. EPA, 479 F.3d 875, 880 (D.C. Cir. 2006)
(``best performing'' source for purposes of CAA section 112 (d)(3)
is source with the lowest emission levels).
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(5) Sector or Nationwide Component of the BSER Factors
As discussed in the January 2014 proposal, another component of the
D.C. Circuit's interpretations of CAA section 111 is that the EPA may
consider the various factors it is required to consider on a national
or regional level and over time, and not only on a plant-specific level
at the time of the rulemaking.\148\ The D.C. Circuit based this
conclusion on a review of the legislative history, stating,
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\148\ 79 FR 1430, 1465 January 8, 2014) (citing Sierra Club v.
Costle, 657 F.2d at 351).
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.\149\
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\149\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted)
(citing legislative history).
The Court has upheld rules that the EPA ``justified . . . in terms
of the policies of the Act,'' including balancing long-term national
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and regional impacts:
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.\150\
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\150\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR
33583/3-33584/1). In the January 2014 proposal, we explained that
although the D.C. Circuit decided Sierra Club v. Costle before the
Chevron case was decided in 1984, the D.C. Circuit's decision could
be justified under either Chevron step 1 or 2. 79 FR 1430, 1466
(January 8, 2014).
Some commenters objected that this case law did not allow the EPA
to ignore source-specific impacts (particularly cost impacts) by basing
determinations solely on impacts at a regional or national level. In
fact, the EPA's consideration of cost, non-air quality impacts, and
energy requirements reflect source-specific impacts, as well as (for
some considerations) impacts that are sector-wide, regional, or
national. See Section V.H.6 below.
c. Achievability of the Standard for Emissions
In the January 2014 proposal, the EPA recognized that the first
element of the definition of ``standard of performance'' is that ``the
emission limit [i.e., the `standard for emissions'] that the EPA
promulgates must be `achievable' ''
[[Page 64540]]
based on performance of the BSER. 79 FR 1430, 1463 (January 8, 2014).
According to the D.C. Circuit, a standard for emissions 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.\151\ Moreover, according to the Court,
``[a]n achievable standard is one which is within the realm of the
adequately demonstrated system's efficiency and which, while not at a
level that is purely theoretical or experimental, need not necessarily
be routinely achieved within the industry prior to its adoption.''
\152\ To be achievable, a standard ``must be capable of being met under
most adverse conditions which can reasonably be expected to recur and
which are not or cannot be taken into account in determining the `cost
of compliance.' '' \153\ To show that a standard is achievable, the EPA
must ``(1) identify variable conditions that might contribute to the
amount of expected emissions, and (2) establish that the test data
relied on by the agency are representative of potential industry-wide
performance, given the range of variables that affect the achievability
of the standard.'' \154\
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\151\ Portland Cement, 486 F.2d at 391-92. Some commenters
stated that the EPA's analysis of the requirements for ``standard of
performance,'' including the BSER, attempted to eliminate the
requirement that the standard for emissions must be ``achievable.''
We disagree with this comment. As just quoted, the EPA's analysis
recognizes that the standard for emissions must be achievable
through the application of the BSER.
\152\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\153\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C.
Cir. 1980).
\154\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981)
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In
considering the representativeness of the source tested, the EPA may
consider such variables as the ```feedstock, operation, size and
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize
from a sample of one when one is the only available sample, or when
that one is shown to be representative of the regulated industry
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416,
434, n.52 (D.C. Cir. 1980).
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In Sections V.J and IX.D below, we show both that the BSER for new
steam generating units and combustion turbines is technically feasible
and adequately demonstrated, and that the standards of 1,400 lb
CO2/MWh-g and 1,000 lb CO2/MWh-g are achievable
considering the range of operating variables that affect achievability.
d. Expanded Use and Development of Technology
In the January 2014 proposal, we noted that the D.C. Circuit has
made clear that Congress intended for CAA section 111 to create
incentives for new technology and therefore that the EPA is required to
consider technological innovation as one of the factors in determining
the ``best system of emission reduction.'' \155\
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\155\ See 79 FR 1430, 1465 (January 8, 2014), Sierra Club v.
Costle, 657 F.2d at 346-47.
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The Court grounded its reading in the statutory text.\156\ In
addition, in the January 2014 proposal, we noted that the Court's
interpretation finds additional support in the legislative
history.\157\ We also explained that the legislative history identifies
three different ways that Congress designed CAA 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); (ii) the expanded use of the best demonstrated
technology; and (iii) the development of emerging technology.\158\ Even
if the EPA were not required to consider technological innovation as
part of its determination of the BSER, it would be reasonable for the
EPA to consider it, either because technological innovation may be
considered an element of the term ``best,'' or because the term ``best
system of emission reduction'' is ambiguous as to whether technological
innovation may be considered. The interpretation is likewise consistent
with the evident purpose of section 111(b) to require new sources to
maximize emission reductions using state-of-the-art means of control.
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\156\ Sierra Club v. Costle, 657 F.2d at 346 (``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 the EPA must weigh are broadly
defined and include within their ambit subfactors such as
technological innovation.'').
\157\ See 79 FR 1430, 1465 (January 8, 2014) (citing S.Rep. 91-
1196 at 16 (1970)) (``Standards of performance should provide an
incentive for industries to work toward constant improvement in
techniques for preventing and controlling emissions from stationary
sources''); S. Rep. 95-127 at 17 (1977) (cited in Sierra Club v.
Costle, 657 F.2d at 346 n. 174) (``The section 111 Standards of
Performance . . . sought to assure the use of available technology
and to stimulate the development of new technology'').
\158\ 79 FR 1465 (citing case law and legislative history).
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Commenters stated that the requirement to consider technological
innovation does not authorize the EPA to identify as the BSER a
technology that is not adequately demonstrated. The proposal did not,
and we do not in this final rule, claim to the contrary. In any event,
as discussed below, the EPA may justify the control technologies
identified in this rule as the BSER even without considering the factor
of incentivizing technological innovation or development.
e. Agency Discretion
As discussed in the January 2014 proposal, 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,'' \159\ and emphasized that ``[t]he text gives the
EPA broad discretion to weigh different factors in setting the
standard.'' \160\ In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C.
Cir. 1999), the Court reiterated:
---------------------------------------------------------------------------
\159\ Sierra Club v. Costle, 657 F.2d at 319.
\160\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F. 2d at 1150 (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).
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.\161\
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\161\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C.
Cir. 1999) (paragraphing revised for convenience). See also NRDC v.
EPA, 25 F.3d 1063, 1071 (D.C. Cir. 1994) (The EPA did not err in its
final balancing because ``neither RCRA nor EPA's regulations
purports to assign any particular weight to the factors listed in
subsection (a)(3). That being the case, the Administrator was free
to emphasize or deemphasize particular factors, constrained only by
the requirements of reasoned agency decision making.'').
f. Lack of Requirement That Standard Must Be Met by All Sources
In the January 2014 proposal, the EPA proposed that, 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 described in the January 2014 proposal,
the EPA based this view on (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.\162\
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\162\ 79 FR 1430, 1466 (January 8, 2014).
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[[Page 64541]]
Commenters contested this assertion, arguing that a 111(b) standard
must be achievable by all new sources. We continue to take the same
position as at proposal for the reasons described there. We note that
as a practical matter, in this rulemaking, the issue of whether all new
steam-generating sources can implement partial-capture CCS is largely
dependent on the geographic scope of geologic sequestration sites. As
discussed below in Section V.M, geologic sequestration sites are widely
available, and a steam-generating plant with partial CCS that is sited
near an area that is suitable for geologic sequestration can serve
demand in a large area that may not have sequestration sites available.
In any event, the standard of 1,400 lb CO2/MW-g that we
promulgate in this final rule can be achieved by new steam generating
EGUs--including new utility boilers and IGCC units--through co-firing
with natural gas in lieu of installing partial CCS, which moots the
issue of the geographic availability of geologic sequestration.
g. EPAct05
The Energy Policy Act of 2005 (``EPAct05'') authorizes assistance
in the form of grants, loan guarantees, as well as federal tax credits
for investment in ``clean coal technology.'' Sections 402(i), 421(a),
and 1307(b) (adding section 48A(g) to the Internal Revenue Code
(``IRC'')) address the extent to which information from clean coal
projects receiving assistance under the EPAct05 may be considered by
the EPA in determining what is the best system of emission reduction
adequately demonstrated. Section 402(i) of the EPAct05 limits the use
of information from facilities that receive assistance under EPAct05 in
CAA section 111 rulemakings:
``No technology, or level of emission reduction, solely by reason
of the use of the technology, or the achievement of the emission
reduction, by 1 or more facilities receiving assistance under this Act,
shall be considered to be adequately demonstrated [ ] for purposes of
section 111 of the Clean Air Act. . . .'' \163\
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\163\ Codified at 42 U.S.C. 15962(a). EPAct05 section 421(a)
similarly states: ``No technology, or level of emission reduction,
shall be treated as adequately demonstrated for purpose [sic] of
section 7411 of this title, . . . solely by reason of the use of
such technology, or the achievement of such emission reduction, by
one or more facilities receiving assistance under section
13572(a)(1) of this title''.
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IRC section 48A(g) contains a similar constraint concerning the use
of technology or level of emission reduction from EGU facilities for
which a tax credit is allowed:
``No use of technology (or level of emission reduction solely by
reason of the use of the technology), and no achievement of any
emission reduction by the demonstration of any technology or
performance level, by or at one or more facilities with respect to
which a credit is allowed under this section, shall be considered to
indicate that the technology or performance level is adequately
demonstrated [ ] for purposes of section 111 of the Clean Air Act. .
. .''
The EPA specifically solicited comment on its interpretation of
these provisions. 79 FR 10750 (Feb. 26, 2014) (Notice of Data
Availability). With respect to EPAct05 sections 402(i) and 421(a), the
EPA proposed that these provisions barred consideration where EPAct05-
assisted facilities were the sole support for the BSER determination,
but that these sources could support a BSER determination so long as
there is additional evidence supporting the determination.\164\ In
addition, the EPA viewed the two prohibitions as relating only to the
technology or emissions reduction for which assistance was given.\165\
The EPA likewise interpreted IRC section 48A(g)--based on the plain
language and the context provided by sections 402(i) and 421(a)--to
mean that use of technology, or emission performance, from a facility
for which the credit is allowed cannot, by itself, support a finding
that the technology or performance level is adequately demonstrated,
but the information can corroborate an otherwise supported
determination or otherwise provide part of the basis for such a
determination.\166\ The EPA also proposed to interpret the phrase
``with respect to which a credit is allowed under this section'' as
referring to the entire phrase ``use of technology (or level of
emission reduction . . .) and [] achievement of any emission reduction
. . . , by or at one or more facilities.'' Thus, if technology A
received a tax credit, but technology B at the same facility did not,
the constraint would not apply to technology B.\167\
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\164\ Technical Support Document, Effect of EPAct05 on Best
System of Emission Reduction for New Power Plants, p. 6 (Docket
entry: EPA-HQ-OAR-2013-0495-1873).
\165\ Id.
\166\ Id. p. 13.
\167\ Id. p. 14.
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Some commenters supported the EPA's proposed interpretation. Others
contended that the EPA's interpretation would allow it to support a
BSER determination even where EPAct05 facility information comprised 99
percent of the supporting information for a BSER determination because
that determination would not be based ``solely'' on EPAct05 sources.
These commenters urged the EPA to conclude that a determination
``solely'' on the basis of information from EPAct05-assisted facilities
is any determination where ``but for'' that information, the EPA could
not justify its chosen standard as the BSER.\168\ Other commenters
argued that the provisions bar the EPA from all consideration of
EPAct05 facilities when determining that a technology or level of
performance is adequately demonstrated.
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\168\ Comments of AFPM/API p. 46 (Docket entry: EPA-HQ-OAR-2013-
0495-10098).
---------------------------------------------------------------------------
In this final rule, the EPA is adopting the interpretations of all
three provisions that it proposed, largely for the reasons previously
advanced. The EPA thus interprets these provisions to preclude the EPA
from relying solely on the experience of facilities that received DOE
assistance, but not to preclude the EPA from relying on the experience
of such facilities in conjunction with other information. This reading
of sections 402(i) and 421(a) is consistent with the views of the only
court to date to consider the matter.\169\
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\169\ State of Nebraska v. EPA, 2014 U.S. Dist. LEXIS 141898 at
n. 1 (D. Nebr. 2014). (``But the Court notes that Sec. 402(i) only
forbids the EPA from considering a given technology or level of
emission reduction to be adequately demonstrated solely on the basis
of federally-funded facilities. 42 U.S.C. 15962(i). In other words,
such technology might be adequately demonstrated if that
determination is based at least in part on non-federally-funded
facilities'') (emphasis original).
---------------------------------------------------------------------------
The EPA notes that the extreme hypothetical posed in the comments
(where the EPA might avoid a limitation on its consideration of
EPAct05-assisted facilities by including a mere scintilla of evidence
from non-EPAct05 facilities) is not presented here, where the principal
evidence that partial post-combustion CCS is a demonstrated and
feasible technology comes from sources which received no assistance of
any type under EPAct05. The EPA also concludes that the ``but for''
test urged by these commenters is an inappropriate reading of the term
``solely'' in sections 402(i) and 421(a), as any piece of evidence may
be a necessary, or ``but for,'' cause without being a sufficient, or
``sole,'' cause.\170\ Nonetheless, if the ``but for'' test were
applicable here, the available evidence would satisfy it.
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\170\ For example, any vote of a Justice on the Supreme Court
may be a necessary but not sufficient cause. In a 5-4 decision, the
decision of the Court would have been different ``but for'' the
assent of Justice A or Justice B, who were in the majority. But it
would be incorrect to say that the assent of Justice A was the
``sole'' reason for the outcome, when the decision also required the
assent of Justice B.
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[[Page 64542]]
Other commenters took the extreme position that the EPAct05
provisions bar all consideration of a facility's existence if the
facility received EPAct05 assistance.\171\ The EPA does not accept this
argument because it is contrary to both the plain statutory language
\172\ (see Chapter 2 of the Response-to-Comment document) and to
Congress's intent that the EPAct05 programs advance the
commercialization of clean coal technology. For the same reason, the
EPA does not accept some commenters' suggestion that sections 402(i),
421(a), and 48A(g) preclude the EPA from considering NETL's cost
projections for CCS, which base cost estimates on up-to-date vendor
quotes reflecting costs for the CCS technology being utilized at the
Boundary Dam Unit #3 facility (a facility receiving no assistance under
EPAct05), but also considers that to-be-built plants will no longer be
first-of-a kind. See generally Section V.I.2 below. Commenters suggest
that the EPAct05 requires that the EPA treat future plants as ``first
of a kind'' when projecting costs, as if EPAct05 facilities simply did
not exist. This reading is contrary to the text of the provisions,
which as noted, relates specifically to a source's performance and
operation (whether a technology is demonstrated, and the level of
performance achieved by use of technology), not to sources' existence.
NETL's cost projections, on the other hand, merely acknowledge the
evident fact that CCS technologies exist, and reasonably project that
they will continue to develop. See Section V.I.2. The NETL cost
estimates, moreover, are based on vendor quotes for the CCS technology
in use at the Boundary Dam facility, a Canadian plant which obviously
is not a recipient of EPAct05 assistance. See sections V.D.2.a and V.
I.2 below.
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\171\ Supplemental Comments of Murray Energy p. 11 (Docket
entry: EPA-HQ-OAR-2013-0495-9498).
\172\ With respect to sections 402(i) and 421(a), commenters
fail to reconcile their reading of the statute with the Act's
grammatical structure, as explained in detail in chapter 2 of the
Response-to-Comment document. One commenter supported its reading by
adding suggested text to the statutory language, a highly disfavored
form of statutory construction. Comments of UARG, p.124 n.38 (Docket
entry: EPA-HQ-OAR-2013-0495-9666). With respect to section 48A(g),
commenters misread the phrase ``considered to indicate,'' and do not
explain how their reading of all three provisions together is
tenable.
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In any case, as shown in Section V below, the EPA finds that a new
highly-efficient SCPC EGU implementing partial post-combustion CCS is
the best system of emission reduction adequately demonstrated and is
doing so based in greater part on performance of facilities receiving
no assistance under EPAct05, and on other information likewise not
having any connection to EPAct05 assistance. The corroborative
information from EPAct05 facilities, though supportive, is not
necessary to the EPA's findings.
I. Severability
This rule has numerous components, and the EPA intends that they be
severable from each other to the extent that they function separately.
For example, the EPA intends that each set of BSER determinations and
standards of performance in this rulemaking be severable from each
other set. That is, the BSER determination and standard of performance
for newly constructed fossil fuel-fired electric utility steam
generating units are severable from all the other BSER determinations
and standards of performance, and the same is true for the BSER
determination and standard of performance for modified fossil fuel-
fired electric utility steam generating units, and so on. It is
reasonable to consider each set of BSER determination and standard of
performance to be severable from each other set of BSER determination
and standard of performance because each set is independently
justifiable and does not depend on any other set. Thus, in the event
that a court should strike down any set of BSER determination and
standard of performance, the remaining BSER determinations and
standards of performance should not be affected.
J. Certain Projects Under Development
In the January 2014 proposal, the EPA indicated that the proposed
Wolverine EGU project (Rogers City, Michigan) appeared to be the only
fossil fuel-fired steam generating unit that was currently under
development that may be capable of ``commencing construction'' for NSPS
purposes at the time of the proposal. See 79 FR 1461. The EPA also
acknowledged that the Wolverine EGU, as designed, would not meet the
proposed standard of 1,100 lb CO2/MWh for new utility steam
generating EGUs. The EPA proposed that, at the time of finalization of
the proposed standards, if the Wolverine project remains under
development and has not either commenced construction or been canceled,
we anticipated proposing a standard of performance specifically for
that facility. Additional discussion of the approach can be found in
the proposal or in the technical support document in the docket
entitled ``Fossil Fuel-Fired Boiler and IGCC EGU Projects under
Development: Status and Approach.''
In December 2013--after the proposed action was signed, but before
it was published--Wolverine Power Cooperative announced that it was
cancelling construction of the proposed coal-fired power plant in
Rogers City, MI.\173\ Therefore, we are not finalizing the proposed
exclusion for that project.
---------------------------------------------------------------------------
\173\ ``Wolverine ends plant speculation in Rogers City'', The
Alpena News, December 17, 2013. http://www.thealpenanews.com/page/content.detail/id/527862/Wolverine-ends-plant-speculation-in-Rogers-City.html?nav=5004.
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In the January 2014 proposal, the EPA also identified two other
fossil fuel-fired steam generating EGU projects that, as currently
designed, would not meet the proposed 1,100 lb CO2/MWh
emissions standard--the Plant Washington project in Georgia and the
Holcomb 2 project in Kansas. We indicated that, at the time of the
proposal, those projects appeared to remain under development but that
the project developers had represented that the projects have commenced
construction for NSPS purposes and, thus, would not be new sources
subject to the proposed or final NSPS. Based solely on the developers'
representations, the EPA indicated that those projects, if ultimately
fully constructed, would be existing sources, and would thus not be
subject to the standards of performance in this final action.
To date, neither developer has sought a formal EPA determination of
NSPS applicability. As we specified in the January 2014 proposal--and
we reiterate here--if such an applicability determination concludes
that either the Plant Washington (GA) project or the Holcomb 2 (KS)
project did not commence construction prior to January 8, 2014 (the
publication of the January 2014 proposal), then the project should be
situated similarly to the disposition the EPA proposed for the
Wolverine project. Accordingly, the EPA is finalizing in this action
that if it is determined that either of these projects has not
commenced construction as January 8, 2014, then that project will be
addressed in the same manner as was proposed for the Wolverine project.
In public comments submitted in response to the January 2014,
Power4Georgians (P4G), the Plant Washington developer, reiterated that
they had executed binding contracts for the purchase and erection of
the facility boiler prior to publication of the January 2014 proposal
and believe that the binding contracts are sufficient to constitute
commencement of construction for purposes of the NSPS program, so that
they are existing rather than new sources for purposes of this
[[Page 64543]]
rule.\174\ Public comments submitted by Tri-State Generation and
Transmission Association and Sunflower Electric Power Corporation, the
developers of the Holcomb 2 project, discussed the cost incurred in the
development of the project. They also indicated they had awarded
contracts for the turbine/generator purchase and had negotiated a rail-
supply agreement that provides for the delivery of fuel to the proposed
Holcomb 2 site. The developers did not, however, explicitly
characterize the construction status of the project.\175\ Other groups
submitted comments contending that neither project has actually
commenced construction.
---------------------------------------------------------------------------
\174\ Docket entry: EPA-HQ-OAR-2013-0495-9403.
\175\ Docket entry: EPA-HQ-OAR-2013-0495-9599.
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In October 2013, the Kansas Supreme Court invalidated the 2010 air
pollution permit granted to Sunflower Electric Power Corporation by the
Kansas Department of Health and Environment (KDHE).\176\ In May 2014,
the KDHE issued an air quality permit addendum for the proposed Holcomb
2 coal plant. The addendum addressed federal regulations that the
Kansas Supreme Court held had been overlooked in the initial permitting
determination. In June 2014, the Sierra Club filed an appeal with the
Kansas Appellate Court challenging the legality of the May 2014 permit.
Since the publication of the January 2014 proposal, the EPA is unaware
of any physical construction activity at the proposed Holcomb 2 site.
---------------------------------------------------------------------------
\176\ ``Kansas High Court Invalidates 895-MW Coal Project Air
Permit'', Power Magazine, 10/10/2013, available at:
www.powermag.com/kansas-high-court-invalidates-2010-895-mw-coal-project-air-permit/.
---------------------------------------------------------------------------
In October 2014, the Plant Washington project was given an 18-month
air permit extension by the Georgia Environmental Protection Division
(EPD). However, as with the Holcomb expansion project, the EPA is
unaware of any physical construction that has taken place at the
proposed Plant Washington site and a recent audit of the project
described it as ``dormant''.\177\
---------------------------------------------------------------------------
\177\ http://www.macon.com/2015/06/23/3811798/audit-sandersville-coal-plant.html.
---------------------------------------------------------------------------
Based on this information, it appears that these sources have not
commenced construction for purposes of section 111(b) and therefore
would likely be new sources should they actually be constructed. As
noted above, the EPA proposed that, if these projects are determined to
not have commenced construction for NSPS purposes prior to the
publication of the proposed rule, they will be addressed in the same
manner proposed for the Wolverine project. 79 FR 1461. We are
finalizing that proposal here. However, because these units may never
actually be fully built and operated, we are not promulgating a
standard of performance at this time because such action may prove to
be unnecessary.\178\
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\178\ In the proposed emission guidelines for existing EGUs, the
EPA did not include estimates of emissions for either Plant
Washington or the Holcomb 2 unit in baseline data used to calculate
proposed state goals for Georgia and Kansas. It appears that the
possibility of these plants actually being built and operating is
too remote. If either unit eventually seeks an applicability
determination and that unit is determined to be an existing source,
and there is reliable evidence that the source will operate, then
the source will be subject to the final 111(d) rule and the EPA will
allow the state to adjust its state goal to reflect adjustment of
the state's baseline data so as to include the unit. Guidance for
adjustment of state goals is provided in the record for the EPA's
final CAA section 111(d) rulemaking.
---------------------------------------------------------------------------
There is one possible additional new EGU, the Two Elk project in
Wyoming. In a supporting TSD accompanying the January 2014 proposal, we
discussed the Two Elk project and relied on developer statements and
state acquiescence that the unit had commenced construction for NSPS
purposes before January 8, 2014.\179\ We did not, therefore, propose
any special section 111(b) standard for the project. Some commenters
maintained that a continuous program of construction at the facility
has not been maintained and that if the plant is ultimately
constructed, it should be classified as a new source under CAA section
111(b). These comments were not specific enough to change the EPA's
view of the project for purposes of this rulemaking. We accordingly
continue to rely on developer statements that this facility has
commenced construction and would not be a new source for purposes of
this proceeding.
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\179\ ``Fossil Fuel-Fired Boiler and IGCC EGU Projects Under
Development: Status and Approach'', Technical Support Document at
pp. 10-1 (Docket Entry: EPA-HQ-OAR-2013-0495-0024).
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IV. Summary of Final Standards for Newly Constructed, Modified, and
Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating Units
This section sets forth the standards for newly constructed,
modified, and reconstructed steam generating units (i.e., utility
boilers and IGCCs). We explain the rationale for the final standards in
Sections V (newly constructed steam generating unit), VI (modified
steam generating units), and VII (reconstructed steam generating
units).
A. Applicability Requirements and Rationale
We generally refer to fossil fuel-fired electric utility generating
units that would be subject to an emission standard in this rulemaking
as ``affected'' or ``covered'' sources, units, facilities or simply as
EGUs. These units meet both the definition of ``affected'' and
``covered'' EGUs subject to an emission standard as provided by this
rule, and the criteria for being considered ``new,'' ``modified'' or
``reconstructed'' sources as defined under the provisions of CAA
section 111 and the EPA's regulations. This section discusses
applicability for newly constructed, modified, and reconstructed steam
generating units.
1. General Applicability Criteria
The EPA is finalizing applicability criteria for new, modified, and
reconstructed electric utility steam generating units (i.e., utility
boilers and IGCC units) in 40 CFR part 60, subpart TTTT that are
similar to the applicability criteria for those units in 40 CFR part
60, subpart Da (utility boiler and IGCC performance standards for
criteria pollutants), but with some differences. The proposed
applicability criteria, relevant comments, and final applicability
criteria specific to newly constructed, modified, and reconstructed
steam generating units are discussed below.
The applicability requirements in the proposal for newly
constructed EGUs included that a utility boiler or IGCC unit must: (1)
Be capable of combusting more than 250 MMBtu/h heat input of fossil
fuel; (2) be constructed for the purpose of supplying, and actually
supply, more than one-third of its potential net-electric output
capacity to any utility power distribution system (that is, to the
grid) for sale on an annual basis; (3) be constructed for the purpose
of supplying, and actually supply, more than 219,000 MWh net-electric
output to the grid on an annual basis; and (4) combust over 10 percent
fossil fuel on a heat input basis over a 3-year average. At proposal,
applicability was determined based on a combination of design and
actual operating conditions that could change annually depending on the
proportion and the amount of electricity actually sold and on the
proportion of fossil fuels combusted by the unit.
In the proposal for modified and reconstructed EGUs, we proposed a
broader applicability approach such that applicability would be based
solely on design criteria and would be identical to the applicability
requirements in
[[Page 64544]]
subpart Da. First, we proposed electric sales criteria that the source
be constructed for the purpose of selling more than one-third of their
potential electric output and more than 219,000 MWh to the grid on an
annual basis, regardless of the actual amount of electricity sold
(i.e., we did not include the applicability criterion that the unit
actually sell the specified amount of electricity on an annual basis).
In addition, we proposed a base load rating criterion that the source
be capable of combusting more than 250 MMBtu/h of fossil fuel,
regardless of the actual amount of fossil fuel burned (i.e., we did not
include the fossil fuel-use criterion that an EGU actually combust more
than 10 percent fossil fuel on a heat input basis on a 3-year average).
Under this approach, applicability would be known prior to the unit
actually commencing operation and would not change on an annual basis.
We also proposed that the final applicability criteria would be
consistent for newly constructed, reconstructed, and modified units.
The proposed broad applicability criteria would still not have included
boilers and IGCC units that were constructed for the purpose of selling
one-third or less of their potential output or 219,000 MWh or less to
the grid on an annual basis. These units are not covered under subpart
Da (the utility boiler and IGCC EGU criteria pollutant NSPS) but are
instead covered as industrial boilers under subpart Db (industrial,
institutional, and commercial boilers NSPS) or subpart KKKK (the
combustion turbine criteria pollutant NSPS).
We solicited comment on whether, to avoid implementation issues
related with different interpretations of ``constructed for the
purpose,'' the total and percentage electric sales criteria should be
recast to be based on permit conditions. The ``constructed for the
purpose'' language was included in the original subpart Da rulemaking.
At that time, the vast majority of new steam generating units were
clearly base load units. The ``constructed for the purpose'' language
was intended to exempt industrial CHP units. These units tend to be
relatively small and were not the focus of the rulemaking. In addition,
units not meeting the electric sales applicability criteria in subpart
Da would be covered by other NSPS so there is limited regulatory
incentive, or impact to the environment, for owners/operators to avoid
applicability with the utility NSPS. However, for new units, there is
no corresponding industrial unit CO2 NSPS and existing units
could debate their original intent (i.e., the purpose for which they
were constructed) in an attempt to avoid applicability under section
111(d) requirements. Consequently, there could be a regulatory
incentive for owners/operators to circumvent the CO2 NSPS
applicability. For units that avoid coverage, there would also be a
corresponding environmental impact. For example, an owner/operator of a
new unit could initially request a permit restriction to limit electric
sales to less than one-third of potential annual electric output, but
amend the operating permit shortly after operation has commenced to
circumvent the intended applicability. Many existing units were
initially built with excess capacity to account for projected load
growth and were intended to sell more than one-third of their potential
electric output. However, due to various factors (lower than expected
load growth, availability of other lower cost units, etc.), certain
units might have sold less than one-third of their potential electric
output, at least during their initial period of operation. Therefore,
the EPA has concluded that determining applicability based on whether a
unit is ``constructed for the purpose of supplying one-third or more of
its potential electric output and more than 219,000 MWh as net-electric
sales'' (emphasis added) could create applicability uncertainty for
both the regulated community and regulators. In addition, we have
concluded that applicability based on actual operating conditions
(i.e., actual electric sales) is not ideal because applicability would
not be known prior to determining compliance and could change annually.
This action finalizes applicability criteria based on design
characteristics and federally enforceable permit restrictions included
in each individual permit. Based on restrictions, if any, on annual
total electric sales in the operating permit, it will be clear from the
time of construction whether or not a new unit is subject to this rule.
The applicability includes all utility boilers and IGCC units unless
the electric sales restriction was in the original and remains in the
current operating permit without any lapses (this is to be consistent
with the `constructed for the purpose of' criteria in subpart Da). We
have concluded that this approach is equivalent to, but clearer than,
the existing language used in subpart Da. In addition, we have
concluded that it is important for both the 111(b) and 111(d)
requirements for electric-only steam generating units that the permit
restriction limiting annual electric sales be included in both the
original and current operating permit. Without this restriction,
existing units could avoid obligations under state plans developed as
part of the 111(d) program by amending their operating permit to limit
total annual electric sales to one-third of potential electric output.
These units would not be subject to any GHG NSPS requirements because
they would not meet the 111(b) or 111(d) applicability criteria and, at
this time, there is no NSPS that would cover these units. As described
in Section III, industrial CHP and dedicated non-fossil units also are
not affected EGUs under this final action.
In this rule, we are finalizing the definition of a steam
generating EGU as a utility boiler or IGCC unit that: (1) Has a base
load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either
alone or in combination with any other fuel) and (2) serves a generator
capable of supplying more than 25 MW-net to a utility distribution
system (i.e., for sale to the grid). However, we are not establishing
final CO2 standards for certain EGUs. These include: (1)
Steam generating units and IGCC units that are currently subject to--
and have been continuously subject to--a federally enforceable permit
limiting annual electric sales to one-third or less of their potential
electric output (e.g., limiting hours of operation to less than 2,920
hours annually) or limiting annual electric sales to 219,000 MWh or
less; (2) units subject to a federally enforceable permit that limits
the use of fossil fuels to 10 percent or less of the unit's heat input
capacity on an annual basis; and (3) CHP units that are subject to a
federally enforceable permit condition limiting annual total electric
sales to no more than their design efficiency times their potential
electric output, or to no more than 219,000 MWh, whichever is greater.
2. Applicability Specific to Newly Constructed Steam Generating Units
In CAA section 111(a)(2), a ``new source'' is defined as any
stationary source, the construction or modification of which is
commenced after the publication of regulations (or if earlier, proposed
regulations) prescribing a standard of performance under this section
which will be applicable to such source. Accordingly, for purposes of
this rule, a newly constructed steam generating EGU is a unit that fits
the definition and applicability criteria of a fossil fuel-fired steam
generating EGU and commences construction on or after January 8, 2014,
which is the date that the proposed standards were published for those
sources (see 79 FR 1430).
[[Page 64545]]
3. Applicability Specific to Modified Steam Generating Units
In CAA section 111(a)(4), a ``modification'' is defined as ``any
physical change in, or change in the method of operation of, a
stationary source'' that either ``increases the amount of any air
pollutant emitted by such source or . . . results in the emission of
any air pollutant not previously emitted.'' The EPA, through
regulations, has determined that certain types of changes are exempt
from consideration as a modification.\180\
---------------------------------------------------------------------------
\180\ 40 CFR 60.2, 60.14(e).
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For purposes of this rule, a modified steam generating EGU is a
unit that fits the definition and applicability criteria of a fossil
fuel-fired steam generating EGU and that modifies on or after June 18,
2014, which is the date that the proposed standards were published for
those sources (see 79 FR 34960).
4. Applicability Specific to Reconstructed Steam Generating Units
The NSPS general provisions (40 CFR part 60, subpart A) provide
that an existing source is considered a new source if it undertakes a
``reconstruction,'' which is the replacement of components of an
existing facility to an extent that: (1) The fixed capital cost of the
new components exceeds 50 percent of the fixed capital cost that would
be required to construct a comparable entirely new facility, and (2) it
is technologically and economically feasible to meet the applicable
standards.\181\
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\181\ 40 CFR 60.15.
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For purposes of this rule, a reconstructed steam generating EGU is
a unit that fits the definition and applicability criteria of a fossil
fuel-fired steam generating EGU and that reconstructs on or after June
18, 2014, which is the date that the proposed standards were published
for those sources (see 79 FR 34960).
B. Best System of Emission Reduction
1. BSER for Newly Constructed Steam Generating Units
In the January 2014 proposal, the EPA proposed that highly
efficient new generation technology implementing partial CCS is the
BSER for GHG emissions from new steam generating EGUs. (See generally
79 FR 1468-1469.) In this final action, the EPA has determined that the
BSER for newly constructed steam generating units is a new highly
efficient supercritical pulverized coal (SCPC) boiler implementing
partial CCS technology to the extent of removal efficiency that meets a
final emission limitation of 1,400 lb CO2/MWh-g. The final
standard of performance is less stringent than the proposed emission
limitation of 1,100 lb CO2/MWh-g. This change, as will be
discussed in greater detail later in this preamble, is in response to
public comments and reflects both a re-examination of the potential
BSER technologies and the most recent, reliable information regarding
technology costs. A newly constructed fossil fuel-fired supercritical
utility boiler will be able to meet the final standard by implementing
post-combustion carbon capture treating a slip-stream of the combustion
flue gas. Alternative potential compliance paths are to build a new
IGCC unit and co-fire with natural gas (or use pre-combustion carbon
capture on a slip-stream), or for a supercritical utility boiler to co-
fire with natural gas.
The EPA of course realizes that the final standard of performance
(1,400 lb CO2/MWh-g) differs from the proposed standard
(1,100 lb CO2/MWh-g). The EPA notes further, however, that
the methodology for determining the final standard of performance is
identical to that at proposal--determining that a new highly efficient
generating technology implementing some degree of partial CCS is the
BSER, with that degree of implementation being determined based on the
reasonableness of costs. A key means of assessing the reasonableness of
cost at proposal was comparison of the levelized cost of electricity
(LCOE) with that of other dispatchable, base load non-NGCC generating
options. We have maintained that approach in identifying BSER for the
final standard. Applying this methodology to the most recent cost
information has led the EPA to adopt the final standard of performance
of 1,400 lb CO2/MWh-g. See Section V.H at Table 8 below.
This final standard reflects the level of emission reduction achievable
by a highly efficient SCPC implementing the degree of partial CCS that
remains cost comparable to the other non-NGCC dispatchable base load
generating options.
The BSER for newly constructed steam generating EGUs in the final
rule is very similar to that in the proposal. In this final action, the
EPA finds that a highly efficient new SCPC EGU implementing partial CCS
to the degree necessary to achieve an emission of 1,400 lb
CO2/MWh-g is the BSER. Contrary to the January 2014
proposal, the EPA finds that IGCC technology--either alone or
implementing partial CCS--is not part of the BSER, but rather is a
viable alternative compliance option. As noted at proposal, a BSER
typically advances performance of a technology beyond current levels of
performance. 79 FR 1465, 1471. Similarly, promotion of technology
innovation can be a relevant factor in BSER determinations. Id. and
Section III.H.3.d above. For these reasons, the EPA at proposal voiced
concerns about adopting standards that would allow an IGCC to comply
without utilizing CCS for slip-stream control. Id. at 1471. The final
standard of 1,400 lb CO2/MWh-g, adopted as a means of
assuring reasonableness of costs, allows IGCC units to comply without
using partial CCS. Thus, although the standard can be met by a highly
efficient new IGCC unit using approximately 3 percent partial CCS (see
Sections V.E and V.H.7 below), the EPA does not believe that
implementation of partial CCS at such a low level, while technically
feasible, is the option that utilities and project developers will
choose. The EPA believes that IGCC project developers will either
choose to meet the final standard by co-firing with natural gas--which
would be a less costly and very straightforward process for a new IGCC
unit--or they will choose to install CCS equipment that will allow the
facility to achieve much deeper CO2 reductions than required
by this rule--likely to co-produce chemicals and/or to capture large
volumes of CO2 for use in EOR operations. Similarly, project
developers may also--as an alternative to utilizing partial CCS
technology--meet the final standard by co-firing approximately 40
percent natural gas in a new highly efficient SCPC EGU.
While the EPA does not find that IGCC technology--either alone or
with implementation of partial CCS--is part of the BSER for new steam
generating EGUs, we remain convinced that it is technically feasible
(see Section V.E below) and believe that it represents a viable
alternative compliance option that some project developers will
consider to meet the final standard issued in this action. The EPA
notes further that IGCC is available at reasonable cost (see Table 9
below), and involves use of an advanced technology. So, although the
final standard reflects performance of a BSER which includes partial
CCS, even in the instances that a compliance alternative might be
utilized, that alternative would both result in emission reductions
consistent with use of the BSER, and would reflect many of the
underlying principles and attributes of the BSER (costs are both
reasonable, not greatly dissimilar than BSER, no collateral adverse
impacts on health or the environment, and reflects
[[Page 64546]]
performance of an advanced technology).
In reaching the final standard of performance, the EPA is aware
that at proposal, the agency stated that it was not ``currently
considering'' a standard of performance as high as 1,400 lb
CO2/MWh-g. 79 FR 1471. However, in that same discussion, the
EPA noted the reasons for its reservations (chiefly reservations about
the extent of emission reductions, promotion of advanced CO2
control technologies, and whether the standard could be met by either
utility boilers or IGCC units co-firing with natural gas, or otherwise
complying without utilizing partial CCS), and we specifically solicited
comment on the issue: ``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.'' Id. The proposal thus both solicited comment on
higher emission standards (including 1,400 lb CO2/MWh-g
based on a less aggressive rate of partial CCS), and provided ample
notice of the methodology the EPA would use to determine the final BSER
and the corresponding final standard.\182\ For these reasons, the EPA
believes that it provided adequate notice of this potential outcome at
proposal, that the final standard of performance was reasonably
foreseeable, and that the final standard is a logical outgrowth of the
proposed rule. Allina Health Services v. Sebelius, 746 F. 3d 1102, 1107
(D.C. Cir. 2014).
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\182\ Although co-firing with natural gas is not part of BSER,
as noted above, it could be part of a compliance pathway for either
SCPC or IGCC units. In this regard, a number of commenters addressed
the issue of natural gas co-firing, indicating that there were
circumstances where it could be part of BSER. See e.g. Comments of
Exelon Corp. p. 12 (Docket entry: EPA-HQ-OAR-2013-0495-9406);
Comments of the Sierra Club p. 108 Docket entry: EPA-HQ-OAR-2013-
0495-9514). See Northeast Md. Waste Disposal Authority v. EPA, 358
F.3d 936, 952 (D.C. Cir. 2004); Appalachian Power v. EPA, 135 F.3d
791, 816 (D.C. Cir. 1998) (commenters understood a matter was under
consideration when they addressed it in comments).
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A more detailed discussion of the rationale for the final BSER
determination and of other systems that were also considered is
provided in Section V.P of this preamble.\183\
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\183\ Certain commenters maintained that the BSER determination
does not comply with (purportedly) binding legal requirements
created by regulations implementing the Information Quality Act.
These comments are mistaken as a matter of both law and fact. The
Information Quality Act does not create legal rights in third
parties (see, e.g. Mississippi Comm'n on Environmental Quality v.
EPA, no. 12-1309 at 84 (D.C. Cir. June 2, 2015)), and the OMB
Guidelines are not binding rules but rather, as their title
indicates, guidance to assist agencies. See State of Mississippi,
744 F.3d at 1347 (the Guidelines provide ``policy and procedural
guidance'', are meant to be ``flexible'' and are to be implemented
differently by different agencies accounting for circumstances).
There are also significant factual omissions and
mischaracterizations in these comments regarding peer review of the
proposed standard and underlying record information. The complete
response to these comments is in chapter 2 of the RTC. See also
Section V.I.2.a and N below describing findings of the SAB panel
that materials of the National Energy Technology Laboratory had been
fully and adequately peer reviewed, and that the EPA findings
related to sequestration of captured CO2 reflected the
best available science.
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2. BSER for Modified Steam Generating Units
The EPA has determined that, as proposed, the BSER for steam
generating units that trigger the modification provisions is the
modified unit's own best potential performance. However, as explained
below, the final BSER determination and the scope of modifications to
which the final standards apply differ in some important respects from
what the EPA proposed.
The EPA proposed that the modified unit's best potential
performance would be determined depending upon when the unit
implemented the modification (i.e., before or after being subject to an
approved CAA section 111(d) state plan). For units that commenced
modification prior to becoming subject to an approved CAA section
111(d) state plan, the EPA proposed unit-specific standards consistent
with each modified unit's best one-year historical performance (during
the years from 2002 to the time of the modification) plus an additional
two percent reduction. For sources that commenced modification after
becoming subject to an approved CAA section 111(d) plan, the EPA
proposed that the unit's best potential performance would be determined
from the results of an efficiency audit.
The final standards in this action do not depend upon when the
modification commences, as long as it commences after June 18, 2014. We
are establishing emission standards for large modifications in this
rule and deferring at this time the setting of standards for small
modifications.
In this final action, the EPA is issuing final emission standards
for affected steam generating units that implement larger modifications
that are consistent with the proposed BSER determination for those
units. The final standard for those sources that implement larger
modifications is a unit-specific emission limitation consistent with
each modified unit's best one-year historical performance (during the
years from 2002 to the time of the modification), but does not include
the additional two percent reduction that was proposed in the January
2014 proposal.
In this action, the EPA is not finalizing standards for those
sources that conduct smaller modifications and is withdrawing the
proposed standards for those sources. See Section XV below.
A more detailed discussion of the rationale for the BSER
determination and final standards is provided in Section VI of this
preamble.
3. BSER for Reconstructed Steam Generating Units
Consistent with our proposal, the EPA has determined that the BSER
for reconstructed steam generating units is the most efficient
demonstrated generating technology for these types of units (i.e.,
meeting a standard of performance consistent with a reconstructed
boiler using the most efficient steam conditions available, even if the
boiler was not originally designed to do so). A more detailed
discussion of the rationale for the BSER determination and the final
standards is provided in Section VII of this preamble.
C. Final Standards of Performance
The EPA is issuing final standards of performance for newly
constructed, modified, and reconstructed affected steam generating
units based on the degree of emission reduction achievable by
application of the best system of emission reduction for those
categories, as described above. The final standards are presented below
in Table 6.
Table 6--Final Standards of Performance for New, Modified, and
Reconstructed Steam Generating Units
------------------------------------------------------------------------
Final standard * lb
Source Description CO2/MWh-g
------------------------------------------------------------------------
New Sources................. All newly 1,400.
constructed steam
generating EGUs.
[[Page 64547]]
Modified Sources............ Sources that Best annual
implement larger performance (lb CO2/
modifications--thos MWh-g) during the
e resulting in an time period from
increase in hourly 2002 to the time of
CO2 emissions (lb the modification.
CO2/hr) of more
than 10 percent.
Reconstructed Sources....... Large **............ 1,800.
Reconstructed Sources....... Small **............ 2,000.
------------------------------------------------------------------------
* Standards are to be met over a 12-operating-month compliance period.
** Large units are those with heat input capacity of >2,000 mmBtu/hr;
small units are those with heat input capacity of <=2,000 mmBtu/hr.
For newly constructed and reconstructed steam generating units and
for modified steam generating sources that result in larger hourly
increases of CO2 emissions, the EPA is finalizing standards
in the form of a gross energy output-based CO2 emission
limit expressed in units of mass per useful energy output,
specifically, in pounds of CO2 per megawatt-hour (lb
CO2/MWh-g).\184\ The standard of performance will apply to
affected EGUs upon the effective date of the final action.
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\184\ Note that the standards for sources that conduct larger
modifications is a unit-specific numerical standard based on the
unit's best one-year historical performance during the period from
2002 to the time of the modification. The unit-specific standard
will also be in the form of a gross energy output-based
CO2 emission limit expressed in pounds of CO2
per megawatt-hour (lb CO2/MWh-g).
---------------------------------------------------------------------------
Compliance with the final standard will be demonstrated by summing
the emissions (in pounds of CO2) for all operating hours in
the 12-operating-month compliance period and then dividing that value
by the sum of the useful energy output (on a gross basis, i.e., gross
megawatt-hours) over the rolling 12-operating-month compliance period.
The final rule requires rounding of emission rates with numerical
values greater than or equal to 1,000 to three significant figures and
rounding of rates with numerical values less than 1,000 to two
significant figures.
For newly constructed steam generating units, we proposed two
options for the compliance period. We proposed that a newly constructed
source could choose to comply with a 12-operating-month standard or
with a more stringent standard over an 84-operating-month compliance
period, and we solicited comment on including an interim 12-operating-
month standard (based on use of supercritical boiler technology, see 79
FR at 1448). We are not finalizing the proposed 84-operating-month
compliance period option because the final standard of performance for
newly constructed sources is less stringent than the proposed standard
and because, as discussed in Section V below, we are identifying
alternative compliance pathways for new steam generating EGUs.
Specifically, we have concluded that there are unlikely to be
significant issues with short-term variability during initial
operation, in view of both the reduced numerical stringency of the
standard, and the availability of compliance alternatives. The EPA
notes that co-firing of natural gas can also serve as an interim means
to reduce emissions if a new source operator believes additional time
is needed to phase-in the operation of a CCS system. Therefore, the
applicable final standards of performance for all newly constructed,
modified, and reconstructed steam generating units must be met over a
rolling 12-operating-month compliance period.
In the Clean Power Plan, which is a separate rulemaking under CAA
section 111(d) published at the same time as the present rulemaking
under CAA section 111(b), the EPA is promulgating emission guidelines
for states to develop state plans regulating CO2 emissions
from existing fossil fuel-fired EGUs. Existing sources that are subject
to state plans under CAA section 111(d) may undertake modifications or
reconstructions and thereby become subject to the requirements under
section 111(b) in the present rulemaking. In the section 111(d) Clean
Power Plan rulemaking, the EPA discusses how undertaking a modification
or reconstruction affects an existing source's section 111(d)
requirements.
V. Rationale for Final Standards for Newly Constructed Fossil Fuel-
Fired Electric Utility Steam Generating Units
In the discussion below, the EPA describes the rationale and
justification of the BSER determination and the resulting final
standards of performance for newly constructed steam generating units.
We also explain why this determination is consistent with the
constraints imposed by the EPAct05.
A. Factors Considered in Determining the BSER
In evaluating the final determination of the BSER for newly
constructed steam generating units, the EPA considered the factors for
the BSER described above, looked widely at all relevant information and
considered all the data, information, and comments that were submitted
during the public comment period. We re-examined and updated the
information that was available to us and concluded, as described below,
that the final standard of 1,400 lb CO2/MWh-g is consistent
with the degree of emission reduction achievable through the
implementation of the BSER. This final standard of performance for
newly constructed fossil fuel-fired steam generating units provides a
clear and achievable path forward for the construction of new coal-
fired generating sources that addresses GHG emissions.
B. Highly Efficient SCPC EGU Implementing Partial CCS as the BSER for
Newly Constructed Steam Generating Units
In the sections that follow, we explain the technical
configurations that may be used to implement BSER to meet the final
standard, describe the operational flexibilities that partial CCS
offers, and then provide the rationale for the final standard of
performance. After that, we discuss, in greater detail, consideration
of the criteria for the determination of the BSER. We describe why a
highly efficient new SCPC EGU implementing partial CCS in the amount
that results in an emission limitation of 1,400 lb CO2/MWh-g
best meets those criteria, including, among others, that such a system
is technically feasible, provides meaningful emission reductions, can
be implemented at a reasonable cost, does not pose non-air quality
health and environmental concerns or impair energy reliability, and
consequently is adequately demonstrated. We also explain why the
emission standard of 1,400 lb CO2/MWh-g is achievable,
including under all circumstances
[[Page 64548]]
reasonably likely to occur when the system is properly designed and
operated. We also discuss alternative compliance options that new
source project developers can elect to use, instead of SCPC with
partial CCS, to meet the final standard of performance.
C. Rationale for the Final Emission Standards
1. The Proposed Standards
In the January 2014 proposal, the EPA proposed an emission
limitation of 1,100 lb CO2/MWh-g, which a new highly
efficient utility boiler burning bituminous coal could have met by
capturing roughly 40 percent of its CO2 emissions and a new
highly efficient IGCC unit could have met by capturing and storing
roughly 25 percent of its CO2 emissions. The captured
CO2 would then be securely stored in sequestration
repositories subject to either Class II or Class VI standards under the
Underground Injection Control program. The EPA arrived at the proposed
standard by examining the available CCS implementation configurations
and concluding that the proposed standard at the corresponding levels
of partial CCS best balanced the BSER criteria and resulted in an
achievable emission level. The EPA also proposed to find that highly
efficient new generation implementing ``full CCS'' (i.e., more than 90
percent capture and storage) was not the BSER because the costs of that
configuration--for both utility boilers and IGCC units--are projected
to substantially exceed the projected costs of other non-NGCC
dispatchable technologies that utilities and project developers are
considering (e.g., new nuclear and biomass). See generally 79 FR at
1477-78. Conversely, the EPA rejected highly efficient SCPC as the BSER
because it would not result in meaningful emission reductions from any
newly constructed PC unit. Id. at 1470. The EPA also declined to base
the BSER on IGCC operating alone due to the same concern--lack of
emission reductions from a new IGCC unit otherwise planned. Id.
2. Basis for the Final Standards
For this final action, the EPA reexamined the BSER options
available at proposal. Those options are: (1) Highly efficient
generation without CCS, (2) highly efficient generation implementing
partial CCS, and (3) highly efficient generation implementing full CCS.
Consistent with our determination in the January 2014 proposal, we
remain convinced that highly efficient generation (i.e., a new
supercritical utility boiler or a new IGCC unit) without CCS does not
represent the BSER because it does not achieve emission reductions
beyond the sector's business as usual, when options that do achieve
more emission reductions are available. 79 FR 1470; see also Section
V.P below. We also do not find that a highly efficient new steam
generating unit implementing full CCS is the BSER because, at this
time, the costs are predicted to be significantly more than the costs
for implementation of partial CCS and significantly more than the costs
for competing non-NGCC base load, dispatchable technologies--primarily
new nuclear generation--and are, therefore, potentially unreasonable.
See Section V.P.
As with the proposal, the EPA has determined the final BSER and
corresponding emission limitation by appropriately balancing the BSER
criteria and determining that the emission limitation is achievable.
The final standard of performance of 1,400 lb CO2/MWh-g is
less stringent than at proposal and reflects changes that are
responsive to comments received on, and the EPA's further evaluation
of, the costs to implement partial CCS. The EPA has determined that a
newly constructed highly efficient supercritical utility boiler burning
bituminous coal can meet this final emission limitation by capturing 16
percent of the CO2 produced from the facility (or 23 percent
if burning subbituminous or dried lignite), which would be either
stored in on-site or off-site geologic sequestration repositories
subject to control under either the Class VI (for geologic
sequestration) or Class II (for Enhanced Oil Recovery) standards under
the UIC program. This BSER is technically feasible, as shown by the
fact that post-combustion CCS technology--both the capture and storage
components--is demonstrated in full-scale operation within the
electricity generating industry. There are also numerous operating
results from smaller-scale projects that are reasonably predictive of
operation at full-scale. It is available at reasonable cost, does not
have collateral adverse non-air quality health or environmental
impacts, and does not have adverse energy implications.
The proposed BSER was a highly efficient newly constructed steam
generating EGU implementing partial CCS to an emission standard of
1,100 lb CO2/MWh-g. The final BSER is a highly efficient
SCPC EGU implementing partial CCS to achieve an emission standard of
1,400 lb CO2/MWh-g. In both cases, the EPA specified that
the BSER includes a ``highly efficient'' new EGU implementing partial
CCS. This assumes that a new project developer will construct the most
efficient generating technology available--i.e., a supercritical or
ultra-supercritical utility boiler--that will inherently generate lower
volumes of uncontrolled CO2 per MWh. See Section V.J below.
A well performing and highly efficient new SCPC EGU will need to
implement lower levels of partial CCS in order to meet the final
standard of 1,400 lb CO2/MWh-g than a less efficient new
steam generating EGU. The construction of highly efficient steam
generating EGUs--as opposed to less efficient units such as a
subcritical utility boiler--will result in lower overall costs from
decreased fuel consumption and the need for lower levels of required
partial CCS to meet the final standard.
3. Consideration of Projects Receiving Funding Under the EPAct05
As noted in Section III.H.3.g above, the EPA's determination of the
BSER here includes review of recently constructed facilities and those
planned or under construction to evaluate the control technologies
being used and considered. Some of the projects discussed in the
January 2014 proposal, and discussed here in this preamble, received or
are receiving financial assistance under the EPAct05 (P.L. 109-58).
This assistance may include financial assistance from the Department of
Energy (DOE), as well as receipt of the federal tax credit for
investment in clean coal technology under IRC Section 48A.
As noted above, the EPA interprets these provisions as allowing
consideration of EPAct05 facilities provided that such information is
not the sole basis for the BSER determination, and particularly so in
circumstances like those here, where the information is corroborative
but the essential information justifying the determinations comes from
facilities and other sources of information with no nexus with EPAct05
assistance. In the discussion below, the EPA explains its reliance on
other information in making the BSER determination for new fossil fuel-
fired steam generating units. The EPA notes that information from
facilities that did not receive any DOE assistance, and did not receive
the federal tax credit, is sufficient by itself to support its BSER
determination.
D. Post-Combustion Carbon Capture
In this section, we describe a variety of facts that support our
conclusion that the technical feasibility of post-combustion carbon
capture is adequately demonstrated. First, we describe the technology
of post-
[[Page 64549]]
combustion capture. We then describe EGUs that have previously utilized
or are currently utilizing post-combustion carbon capture technology.
This discussion is complemented by later sections that explain and
justify our conclusions that the technical feasibility of other aspects
of partial CCS are adequately demonstrated--namely, the transportation
and carbon storage (see Sections V.M. and N). Further, the conclusions
of this section are reinforced by the discussion in Section V.F. below,
in which we identify commercial vendors that offer carbon capture
technology and offer performance guarantees, and discuss industry and
technology developers' public pronouncements of their confidence in the
feasibility and availability of CCS technologies.
1. Post-Combustion Carbon Capture--How it Works
Post-combustion capture processes remove CO2 from the
exhaust gas of a combustion system--such as a utility boiler. It is
referred to as ``post-combustion capture'' because the CO2
is the product of the combustion of the primary fuel and the capture
takes place after the combustion of that fuel. The exhaust gases from
most combustion processes are at atmospheric pressure and are moved
through the flue gas system by fans. The concentration of
CO2 in most combustion flue gas streams is somewhat
dilute.\185\ Most post-combustion capture systems utilize liquid
solvents \186\ that separate the CO2 from the flue gas in
CO2 scrubber systems. Because the flue gas is at atmospheric
pressure and is somewhat dilute, the solvents used for post-combustion
capture are ones that separate the CO2 using chemical
absorption (or chemisorption). Amine-based solvents \187\ are the most
commonly used in post-combustion capture systems. In a chemisorption-
based separation process, the flue gas is processed through the
CO2 scrubber and the CO2 is absorbed by the
liquid solvent and then released by heating to form a high purity
CO2 stream. This heating step is referred to as ``solvent
regeneration'' and is responsible for much of the ``energy penalty'' of
the capture system. Steam from the boiler (or potentially from another
external source) that would otherwise be used to generate electricity
is instead used in the solvent regeneration process. The development of
advanced solvents--those that are chemically stable, have high
CO2 absorption capacities, and have low regeneration energy
requirements--is an active area of research. Many post-combustion
solvents will also selectively remove other acidic gases such as
SO2 and hydrochloric acid (HCl), which can result in
degradation of the solvent. For that reason, the CO2
scrubber systems are normally installed downstream of other pollutant
control devices (e.g., particulate matter and flue gas desulfurization
controls) and in some cases, the acidic gases will need to be scrubbed
to very low levels prior to the flue gas entering the CO2
capture system. See also RIA chapter 5 (quantifying SO2
reductions resulting from this scrubbing process).
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\185\ The typical concentration of CO2 in the flue
gas of a coal-fired utility boiler is roughly around 15 volume
percent.
\186\ A solvent is a substance (usually a liquid) that dissolves
a solute (a chemically different liquid, solid or gas), resulting in
a solution.
\187\ Amines are derivatives of ammonia (NH3) where
one or more hydrogen atoms have been replaced by hydrocarbon groups.
---------------------------------------------------------------------------
Additional information on post-combustion carbon capture--including
process diagrams--can be found in a summary technical support
document.\188\
---------------------------------------------------------------------------
\188\ Technical Support Document--``Literature Survey of Carbon
Capture Technology'', available in the rulemaking docket (Docket ID:
EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------
2. Post-Combustion Carbon Capture Projects That Have Not Received DOE
Assistance Through the EPAct05 or Tax Credits Under IRC Section 48A
a. Boundary Dam Unit #3
SaskPower's Boundary Dam CCS Project in Estevan, a city in
Saskatchewan, Canada, is the world's first commercial-scale fully
integrated post-combustion CCS project at a coal-fired power plant. The
project fully integrates the rebuilt 110 MW coal-fired Unit #3 with a
CO2 capture system using Shell Cansolv amine-based solvent
to capture 90 percent of its CO2 emissions. The facility,
which utilizes local Saskatchewan lignite, began operations in October
2014 and accounts of the system's performance describe it as working
even ``better than expected.'' 189 190 The plant
started by capturing roughly 75 percent of CO2 from the
plant emissions and its operators plan to increase the capture
percentage as they optimize the equipment to reach full capacity.
Initial indications are that the facility is producing more power than
predicted and that the energy penalty (parasitic load--the energy
needed to regenerate the CO2 capture solvent) is much lower
than initially predicted.\191\ Water use at the facility is consistent
with levels that were predicted.\192\ The total project costs--for the
power plant and the carbon capture plant--was $1.467B (CAD).\193\ The
CO2 from the capture system is more than 99.999 percent pure
with only trace levels of N2 in the product stream.\194\
This purity is food-grade quality CO2 and is a clear
indication that the system is working well. The captured CO2
is transported by pipeline to nearby oil fields in southern
Saskatchewan where it is being used for EOR operations. Any captured
CO2 that is not used for EOR operations will be stored in
nearby deep brine-filled sandstone formations. Thus, the Boundary Dam
Unit #3 project is demonstrating CO2 post-combustion
capture, CO2 compression and transport, and CO2
injection for both EOR and geologic storage. The CCS system is fully
integrated with the electricity production of the plant.
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\189\ ``[W]e are achieving better than expected'' operation out
of the plant, SaskPower's Mike Marsh said April 8, 2015 in
Washington, DC, summarizing the status of the first-of-a-kind plant
in Saskatchewan, Canada, known as Boundary Dam Unit 3. Marsh spoke
at a meeting of the National Coal Council, which advises the Energy
Department on coal-related topics. From ``Bolstering EPA's NSPS,
Canadian CCS Plant Working `Better Than Expected' '', Climate Daily
News, Inside EPA/climate (April 08, 2015); www.insideepa.com
(subscription required).
\190\ ``CCS performance data exceeding expectations at world-
first Boundary Dam Power Station Unit #3'', http://www.saskpowerccs.com/newsandmedia/latest-news/ccs-performance-data-exceeding-expectations/.
\191\ Correspondence between Mike Monea (SaskPower) and Nick
Hutson (EPA), February 20, 2015.
\192\ 30 percent of the water used for cooling comes from the
recycled or reclaimed water from the process itself; namely, water
in the coal is reclaimed.
\193\ About $1.2B USD; roughly $700M (USD) for the carbon
capture system, which was on budget.
\194\ ``Boundary Dam--The Future is Here'', plenary presentation
by Mike Monea at the 12th International Conference on Greenhouse Gas
Technologies (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------
Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is
a relatively small coal-fired utility boiler and thus, in the
commenters' view, does not demonstrate that such a system could be
utilized at a much larger utility coal-fired boiler. However, there is
nothing to indicate that the post-combustion system used at Boundary
Dam could not be scaled-up for use at a larger utility boiler. In fact,
the carbon capture system at Boundary Dam #3 is designed and
constructed to implement ``full CCS''--that is to capture more than 90
percent of the CO2 produced from the subcritical unit. A
similarly-sized capture system--with no need for further scale-up--
could be used to treat a slip-stream of a much larger
[[Page 64550]]
supercritical utility boiler (a new unit of approximately 500 to 600
MW) in order to meet the final standard of performance of 1,400 lb
CO2/MWh-g, which would only require partial CCS on the order
of approximately 16 to 23 percent (depending on the coal used).
A ``slip-stream'' is a portion of the flue gas stream that can be
treated separately from the bulk exhaust gas. It is not an uncommon
configuration for the flue gas from a coal-fired boiler to be separated
into two or more streams and treated separately in different control
equipment before being recombined to exit from a common stack.\195\ A
slip-stream configuration is often used to treat a smaller portion of
the bulk flue gas stream as a way of testing or demonstrating a control
device or measurement technology. For implementation of post-combustion
partial carbon capture, a portion of the bulk flue gas stream would be
treated separately to capture approximately 90 percent of the
CO2 from that smaller slip-stream of the flue gas. For
example, in order to capture 20 percent of the CO2 produced
by a coal-fired utility boiler, an operator would treat approximately
25 percent of the bulk flue gas stream (rather than treating the entire
stream). Approximately 90 percent of the CO2 would be
captured from the slip-stream gas, resulting in an overall capture of
about 20 percent.
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\195\ See Figure 1A from Atmospheric Environment, 43, 3974
(2009), for an example of this type of configuration.
---------------------------------------------------------------------------
In its study on the cost and performance of a range of carbon
capture rates, the DOE/NETL determined that the slip-stream approach
was the most economical for carbon capture of less than 90 percent of
the total CO2.\196\ The advantage of the slip-stream
approach is that the capture system will be sized to treat a lower
volume of flue gas flow, which reduces the size of the CO2
absorption columns, induced draft fans, and other equipment, leading to
lower capital and operating costs.
---------------------------------------------------------------------------
\196\ ``Cost and Performance of PC and IGCC for a Range of
Carbon Capture'', Rev 1 (2013), DOE/NETL-2011/1498 p. 2 (``A
literature search was conducted to verify that <90 percent
CO2 capture is most economical using a `slip-stream' (or
bypass) approach. Indeed, the slip-stream approach is more cost-
effective for <90 percent CO2 capture than removing
reduced CO2 fractions from the entire flue gas stream,
according to multiple peer-reviewed studies.'' See also id. at 19,
21, 77, and 478 (documenting further that treating a slip-stream is
the most economical approach).
---------------------------------------------------------------------------
The carbon capture system at Boundary Dam does not utilize the
slip-stream configuration because it was designed to achieve more than
90 percent capture rates from the 110 MW facility. However, the same
carbon capture equipment could be used to treat approximately 50
percent of the flue gas from a 220 MW facility--or 20 percent of the
flue gas from a 550 MW facility. Thus, the equipment that is currently
working very well (in fact, ``better than expected'') at the Boundary
Dam plant can be utilized for partial carbon capture at a much larger
coal-fired unit without the need for further scale-up.
The experience at Boundary Dam is directly transferrable to other
types of post-combustion sources, including those using different
boiler types and those burning different coal types. There is nothing
to suggest that the Shell CanSolv process would not work with other
coal types and indeed, the latest NETL cost estimates assume that the
capture technology would be used in a new unit using bituminous
coal.\197\ The EPA is unaware of any reasons why the Boundary Dam
technology would not be transferrable to another utility boiler at a
different location at a different elevation or climate because the
control technology is not climate or elevation-dependent.
---------------------------------------------------------------------------
\197\ In fact, in ``Cost and Performance Baseline for Fossil
Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to
Electricity Revision 3'', DOE/NETL-2015/1723 (July 2015), Exh.2-3
the Shell Cansolv process is used as the capture process for a new
SCPC unit using bituminous coal rather than the subcritical PC unit
at Boundary Dam that uses Canadian lignite. The study evidently
assumes that the CanSolv process can be used effectively for
bituminous coal since this type of coal is assumed for cost
estimation purposes.
---------------------------------------------------------------------------
Commenters also noted that the Boundary Dam Unit #3 project
received financial assistance from both the Canadian federal government
and from the Saskatchewan provincial government. But the availability
of--or the lack of--external financial assistance does not affect the
technical feasibility of the technology. Commenters further
characterized Boundary Dam as a ``demonstration project''. These
descriptors are beside the point. Regardless of what the project is
called or how it was financed, the project clearly shows the technical
feasibility of full-scale, fully integrated implementation of available
post-combustion CCS technology, which in this case also appears to be
commercially viable.
The EPA notes that, although there is ample additional information
corroborating that post-combustion CCS is technically feasible, which
we describe below, the performance at Boundary Dam Unit #3 alone would
be sufficient to support that conclusion. Essex Chemical Corp., 486 F.
2d at 436 (test results from single facility demonstrates achievability
of standard of performance). As mentioned above, the post-combustion
capture technology used at Boundary Dam is transferrable to all other
types of utility boilers.
b. AES Warrior Run and Shady Point
AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point
(Panama, OK) plants are both circulating fluidized bed (CFB) coal-fired
power plants with carbon capture amine scrubbers developed by ABB/
Lummus. The scrubbers were designed to process a slip-stream of each
plant's flue gas. At the 180 MW Warrior Run Plant, a plant that burns
bituminous coal, approximately 10 percent of the plant's CO2
emissions (about 110,000 metric tons of CO2 per year) has
been captured since 2000 and sold to the food and beverage industry. At
the 320 MW Shady Point Plant, a plant that burns a blend of bituminous
and subbituminous coals, CO2 from an approximate 5 percent
slip-stream (about 66,000 metric tons of CO2 per year) has
been captured since 2001. The captured CO2 from the Shady
Point Plant is also sold for use in the food processing industry.\198\
While these projects do not demonstrate the CO2 storage
component of CCS, they clearly demonstrate the technical viability of
partial CO2 capture. The capture of CO2 from a
slip-stream of the bulk flue gas, as described earlier, is the most
economical method for capturing less than 90 percent of the
CO2. The amounts of partial capture that these sources have
demonstrated--up to 10 percent--is reasonably similar to the level, at
16 to 23 percent, that the EPA predicts would be needed by a new highly
efficient steam utility boiler to meet the final standard of
performance. These facilities, which have been operating for multiple
years, clearly show the technical feasibility of post-combustion carbon
capture.
---------------------------------------------------------------------------
\198\ 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.
---------------------------------------------------------------------------
c. Searles Valley Minerals
Since 1978, the Searles Valley Minerals soda ash plant in Trona, CA
has used post-combustion amine scrubbing to capture approximately
270,000 metric tons of CO2 per year from the flue gas of a
coal-fired power plant that generates steam and power for on-site use.
The captured CO2 is used for the carbonation of brine in the
process of producing soda ash.\199\ Again, while the captured
CO2 is not
[[Page 64551]]
sequestered, this project clearly demonstrates the technical
feasibility of the amine scrubbing system for CO2 capture
from a coal-fired power plant.\200\ The fact that this system is an
industrial coal-fired power plant rather than a utility coal-fired
power plant is irrelevant as they both serve a similar purpose--the
production of electricity.
---------------------------------------------------------------------------
\199\ IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
\200\ Moreover, the final rule allows alternative means of
storage of captured CO2 based on a case-by-case
demonstration of efficacy. See Section V.M.4 below.
---------------------------------------------------------------------------
Each of these processes indicate a willingness of industry to
utilize available post-combustion technology for capture of
CO2 for commercial purposes. Not one of the CO2
capture systems at Warrior Run, Shady Point, or Searles Valley was
installed for regulatory purposes or as government-funded demonstration
projects. They were installed to capture CO2 for commercial
use. The fact that the captured CO2 was utilized rather than
being stored is of no consequence in the consideration of the technical
feasibility of post-combustion CO2 capture technology. These
commercial operations have helped to improve the performance of
scrubbing systems that are available today. For example, the heat duty
(i.e., the energy needed to remove the CO2) has been reduced
by about 5 times from the amine process originally used at the Searles
Valley facility. The amine scrubbing process used at Boundary Dam is
equally efficient, and the amine scrubbing system to be used at the
Petra Nova WA Parish project (Thompsons, TX) is projected to be as
well.\201\
---------------------------------------------------------------------------
\201\ The heat duty for the amine scrubbing process used at
Searles Valley in the mid-70's was about 12 MJ/mt CO2
removed as compared to a heat duty of about 2.5 MJ/mt CO2
removed for the amine processes used at Boundary Dam and to be used
at WA Parish. ``From Lubbock, TX to Thompsons, TX--Amine Scrubbing
for Commercial CO2 Capture from Power Plants'', plenary
address by Prof. Gary Rochelle at the 12th International Conference
on Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------
3. Post-Combustion Carbon Capture Projects That Received DOE Assistance
Through the EPAct05, but Did Not Receive Tax Credits Under IRC Section
48A
The EPA considers the experiences from the CCS projects described
above, coupled with evidence that the design of CCS is well accepted
(also described above) and the strong support that CCS has received
from vendors and others (described below) to adequately demonstrate
that post-combustion partial CCS is technically feasible. The EPA finds
that additional projects, described next, provide more support for that
conclusion. These projects received funding under EPAct05 from the
Department of Energy, but that does not disqualify them from being
considered. See Section III.H.3 above.
a. Petra Nova WA Parish Project
Petra Nova, a joint venture between NRG Energy Inc. and JX Nippon
Oil & Gas Exploration, is constructing a commercial-scale post-
combustion carbon capture project at Unit #8 of NRG's WA Parish
generating station southwest of Houston, Texas. The project is designed
to utilize partial CCS by capturing approximately 90 percent of the
CO2 from a 240 MW slip-stream of the 610 MW WA Parish
facility. The project is expected to be operational in 2016 and thus
does not yet directly demonstrate the technical feasibility or
performance of the MHI amine scrubbing system. However, this project is
a clear indication that the developers have confidence in the technical
feasibility of the post-combustion carbon capture system.
The project was originally envisioned as a 60 MW slip-stream
demonstration and received DOE Clean Coal Power Initiative (CCPI)
funding (as provided in EPAct05) on that basis. The developers later
expanded the project to the larger 240 MW slip-stream because of the
need to capture greater volumes of CO2 for EOR operations.
No additional DOE or other federal funding was obtained for the
expansion from a 60 MW slip-stream to a 240 MW slip-stream.\202\
---------------------------------------------------------------------------
\202\ Thus, even if the project received DOE assistance for the
initial 60 MW design, the expansion of the project from 60 MW to 240
MW should not be considered a DOE-assisted project. In any case, as
described above, even without consideration of this facility at all,
other information adequately demonstrates the technical feasibility
of post-combustion CCS.
---------------------------------------------------------------------------
At 240 MW, the Petra Nova project will be the largest post-
combustion carbon capture system installed on an existing coal-fueled
power plant. The project will use for EOR or will sequester 1.6 million
tons of captured CO2 each year. The project is expected to
be operational in 2016.
In 2014 project materials,\203\ the project developer NRG
recognized the importance of CCS technology by noting:
---------------------------------------------------------------------------
\203\ WA Parish CO2 Capture Project Fact Sheet;
available at www.nrg.com/documents/business/pla-2014-petranova-waparish-factsheet.pdf (2014).
The technology has the potential to enhance the long-term
viability and sustainability of coal-fueled power plants across the
U.S. and around the world. . . . Post-combustion carbon capture is
essential so that we can use coal to sustain our energy ecosystem
---------------------------------------------------------------------------
while we begin reducing our carbon footprint.
According to NRG, the Petra Nova Carbon Capture Project will
utilize ``a proven carbon capture process,'' jointly developed by
Mitsubishi Heavy Industries, Ltd. (MHI) and the Kansai Electric Power
Co., that uses a high-performance solvent for CO2 absorption
and desorption.\204\ In using the MHI high-performance solvent, the
Petra Nova project will benefit from pilot-scale testing of this
solvent at Alabama Power's Plant Barry and at other installations. WA
Parish Unit #8 came on-line in 1982 and is thus an existing source that
will not be subject to final standards of performance issued in this
action. However, because it will be capturing roughly 35 percent of the
CO2 generated by the facility, its emissions will be below
the final new source emission limitation of 1,400 lb CO2/
MWh-g.\205\
---------------------------------------------------------------------------
\204\ The WA Parish project (described earlier) will utilize the
KM-CDR Process[supreg], which was jointly developed by MHI and the
Kansai Electric Power Co., Inc. and uses the proprietary KS-
1TM high-performance solvent for the CO2
absorption and desorption.
\205\ Using emissions data reported to the Acid Rain Program,
the EPA estimates that the CO2 emissions from the WA
Parish Unit #8 will be 1,250-1,300 lb CO2/MWh-g during
operations with the post-combustion capture system.
---------------------------------------------------------------------------
The captured CO2 from the WA Parish CO2
Capture Project will be used in EOR operations at mature oil fields in
the Gulf Coast region. Using EOR at Hilcorp's West Ranch Oil Field, the
production is expected to be boosted from around 500 barrels per day to
approximately 15,000 barrels per day. Thus the project will utilize all
aspects of CCS by capturing CO2 at the large coal-fired
power plant, compressing the CO2, transporting it by
pipeline to the EOR operations, and injecting it for EOR and eventual
geologic storage.
The carbon capture system at WA Parish will utilize a slip-stream
configuration. However, as noted, the system is designed to capture
roughly 35 percent of the CO2 from WA Parish Unit #8 (90
percent of the CO2 from the 240 MW slip-stream from the 610
MW unit). A carbon capture system of the same size as that used at WA
Parish could be used to treat a 240 MW slip-stream from a 1,000 MW unit
in order to meet the final standard of performance of 1,400 lb
CO2/MWh-g.
Again, the experience at the WA Parish Unit #8 project will be
directly transferable to post-combustion capture at a new utility
boiler, even though WA Parish Unit #8 is an existing source that has
been in operation for over 30 years. In fact, retrofit of such
technology at an existing unit can be more challenging than
incorporating the technology into the design of a new facility. The
[[Page 64552]]
experience will be directly transferrable to other types of post-
combustion sources including those using different boiler types and
those burning different coals. The amine scrubbing and associated
systems are not boiler type- or coal-specific. The EPA is unaware of
any reasons that the technology utilized at the WA Parish plant would
not be transferrable to another utility boiler at a different location
at a different elevation or climate, given that the technology is not
dependent on either climate or topography.
b. AEP/Alstom Mountaineer Project
In September 2009, AEP began a pilot-scale CCS demonstration at its
Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a very
large (1,300 MW) 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 ammonia CCS
validation project. The demonstration achieved capture rates from 75
percent (design value) to as high as 90 percent, and produced
CO2 at a 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.\206\
---------------------------------------------------------------------------
\206\ http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carbon-capture-and-sequestration-ccs-project/.
---------------------------------------------------------------------------
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. AEP cited the uncertain status of U.S.
climate policy as a contributor to its decision, but did not express
doubts about the feasibility of the technology. See Section V.L below.
AEP also prepared a Front End Engineering & Design (FEED)
Report,\207\ explaining in detail how its pilot-scale work could be
scaled up to successful full-scale operation, and to accommodate the
operating needs of a full-scale EGU, including reliable generating
capacity capable of cycling up and down to accommodate consumer demand.
Recommended design changes to accomplish the desired scaling included
detailed flue gas specifications, ranges for temperature, moisture and
SO2 content; careful scrutiny of makeup water composition
and temperature; quality and quantity of available steam to accommodate
heat cycle based on unit load changes; and detailed scrutiny of
material and energy balances.\208\ See Section V.G.3 below, addressing
in more detail the record support for how CCS technology can be scaled
up to commercial size in both pre- and post-combustion applications.
---------------------------------------------------------------------------
\207\ ``CCS front end engineering & design report: American
Electric Power Mountaineer CCS II Project. Phase 1'', pp 10-11;
available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
\208\ Id. at 11. The EPA does not view this information as being
affected by the constraints in EPAct05. The information does not
relate to use of technology, level of emission reduction by reason
of use of technology, achievement of emission reduction by
demonstration of technology, or demonstration of a level of
performance. The FEED study rather explains engineering challenges
which would remain at full scale and how those challenges can be
addressed.
---------------------------------------------------------------------------
c. Southern Company/MHI Plant Barry
In June 2011, Southern Company and Mitsubishi Heavy Industries
(MHI) launched operations at a 25 MW coal-fired carbon capture facility
at Alabama Power's Plant Barry. The facility, which completed the
initial demonstration phase, captured approximately 165,000 metric tons
of CO2 annually at a CO2 capture rate of over 90
percent. The facility employed the KM CDR Process, which uses a
proprietary high performing solvent \209\ for CO2 absorption
and desorption that was jointly developed by MHI and Japanese utility
Kansai Electric Power Co. The captured CO2 has been
transported via pipeline approximately 12 miles to the Citronelle oil
field where it is injected into the Paluxy formation, a saline
reservoir, for storage.\210\
---------------------------------------------------------------------------
\209\ This is the same carbon capture system that is being
utilized at the Petra Nova project at the NRG WA Parish plant.
\210\ Ivie, M.A. et al.; ``Project Status and Research Plans of
500 TPD CO2 Capture and Sequestration Demonstration at
Alabama Power's Plant Barry'', Energy Procedia 37, 6335 (2013).
---------------------------------------------------------------------------
Project participants have reported that ``[t]he plant performance
was stable at the full load condition with CO2 capture rate
of 500 TPD at 90 percent CO2 removal and lower steam
consumption than conventional capture processes.'' \211\
---------------------------------------------------------------------------
\211\ Id.
---------------------------------------------------------------------------
E. Pre-Combustion Carbon Capture
As described earlier, the EPA does not find that IGCC technology--
either alone or implementing partial CCS--is part of the BSER for newly
constructed steam generating EGUs. However, as noted, there may be
specific circumstances and business plans--such as co-production of
chemicals or fertilizers, or capture of CO2 for use in EOR
operations--that encourage greater CO2 emission reductions
than are required by this standard. In this section, we describe and
justify our conclusion that the technical feasibility of pre-combustion
carbon capture is adequately demonstrated, indicating that this could
be a viable alternative compliance pathway. First, we explain the
technology of pre-combustion capture. We then describe EGUs that have
previously utilized or are currently utilizing pre-combustion carbon
capture technology. This discussion is complemented by other sections
that conclude the technical feasibility of other aspects of partial CCS
are adequately demonstrated--namely, post-combustion carbon capture
(Section V.D) and sequestration (Sections V.M and V.N). Further, this
section's conclusions are reinforced by Section V.F, in which we
identify commercial vendors that offer CCS performance guarantees as
well as developers that have publicly stated their confidence in CCS
technologies.
1. Pre-Combustion Carbon Capture--How It Works
Pre-combustion capture systems are typically used with IGCC
processes. In a gasification system, the fuel (usually coal or
petroleum coke) is heated with water and oxygen in an oxygen-lean
environment. The coal (carbon), water and oxygen react to form
primarily a mixture of hydrogen (H2) and carbon monoxide
(CO) known as synthesis gas or syngas according to the following high
temperature reaction:
3C + H2O + O2 [rarr] H2 + 3CO
In an IGCC system, the resulting syngas, after removal of the
impurities, can be combusted using a conventional combustion turbine in
a combined cycle configuration (i.e., a combustion turbine combined
with a HRSG and steam turbine). The gasification process also typically
produces some amount of CO2 \212\ as a by-product along with
other
[[Page 64553]]
gases (e.g., H2S) and inorganic materials originating from
the coal (e.g., minerals, ash). The amount of CO2 in the
syngas 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 according to the following catalytic
reaction:
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\212\ The amount of CO2 in 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/research/coal/energy-systems/gasification/gasifipedia/syngas-composition).
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CO + H2O [rarr] CO2 + H2
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. If a high level of CO2 capture is required, then
multi-stage WGS reactors will be needed and an advanced hydrogen
turbine will likely be needed to combust the resulting hydrogen-rich
syngas.
Most syngas streams are at higher pressure and can contain higher
concentrations of CO2 (especially if shifted to enrich the
concentration). As such, the pre-combustion capture systems can utilize
physical absorption (physisorption) solvents rather than the chemical
absorptions solvents described earlier. Physical absorption has the
benefit of relying on weak intermolecular interactions and, as a
result, the absorbed CO2 can often be released (desorbed) by
reducing the pressure rather than by adding heat. Pre-combustion
capture systems have been used widely in industrial processes such as
natural gas processing.
Additional information on pre-combustion carbon capture can be
found in a summary technical support document.\213\
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\213\ Technical Support Document--``Literature Survey of Carbon
Capture Technology'', available in the rulemaking docket (Docket ID:
EPA-HQ-OAR-2013-0495).
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2. Pre-Combustion Carbon Capture Projects That Have Not Received DOE
Assistance Through EPAct05 or Tax Credits Under IRC Section 48A
a. Dakota Gasification Great Plains Synfuels Plant
Each day, the Dakota Gasification Great Plains Synfuels Plant uses
approximately 18,000 tons of North Dakota lignite in a coal
gasification process that produces syngas (a mixture of CO,
CO2, and H2), which is then converted to methane
gas (synthetic natural gas) using a methanation process. Each day, the
process produces an average of 145 million cubic feet of synthetic
natural gas that is ultimately transported for use in home heating and
electricity generation.\214\
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\214\ http://www.dakotagas.com/Gasification/.
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Capture of CO2 from the facility began in 2000. The
Synfuels Plant, using a pre-combustion Rectisol[supreg] process,
captures about 3 million tons of CO2 per year--more
CO2 from coal conversion than any facility in the world, and
is a participant in the world's largest carbon sequestration project.
On average about 8,000 metric tons per day of captured CO2
from the facility is sent through a 205-mile pipeline to oil fields in
Saskatchewan, Canada, where it is used for EOR operations that result
in permanent CO2 geologic storage. The geologic
sequestration of CO2 in the oil reservoir is monitored by
the International Energy Agency (IEA) Weyburn CO2 Monitoring
and Storage Project.
Several commenters to the January 2014 proposal argued that the
Great Plains Synfuels facility is not an EGU, that it operates as a
chemical plant, and that its experience is not translatable to an IGCC
using pre-combustion carbon capture technology. The commenters noted
that the Dakota facility can be operated nearly continuously without
the need to adjust operations to meet cyclic electricity generation
demands. In the January 2014 proposal, the EPA had noted that, while
the facility is not an EGU, it has significant similarities to an IGCC
and the implementation of the pre-combustion capture technology would
be similar enough for comparison. See 79 FR at 1435-36 and n. 11. We
continue to hold this view.
As explained above, in an IGCC gasification system, coal (or
petroleum coke) is gasified to produce a synthesis gas comprised of
primarily CO, H2, and some amount of CO2
(depending on the gasifier and the specific operating conditions). A
water-gas-shift reaction using water (H2O, steam) is then
used to shift the syngas to CO2 and H2. The more
the syngas is ``shifted,'' the more enriched it becomes in
H2. In an IGCC, power can be generated by directly
combusting the un-shifted syngas in a conventional combustion turbine.
If the syngas is shifted such that the resulting syngas is highly
enriched in H2, then a special, advanced hydrogen turbine is
needed. If CO2 is to be captured, then the syngas would need
to be shifted either fully or partially, depending upon the level of
capture required.\215\
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\215\ ``Cost and Performance of PC and IGCC for a Range of
Carbon Capture'', Rev 1 (2013), DOE/NETL-2011/1498.
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The Dakota Gasification process bears essential similarities to the
just-described IGCC gasification system. As with the IGCC gasification
system, the Dakota Gasification facility gasifies coal (lignite) to
produce a syngas which is then shifted to increase the concentration of
CO2 and to produce the desired ratio of CO and
H2. As with the IGCC gasification system, the CO2
is then removed in a pre-combustion capture system, and the syngas that
results is made further use of. For present purposes, only the manner
in which the syngas is used distinguishes the IGCC gasification system
from the Dakota Gasification facility. In the IGCC process, the syngas
is combusted. In the Dakota Gasification facility, the syngas is
processed through a catalytic methanation process where the CO and
H2 react to produce CH4 (methane, synthetic
natural gas) and water. Importantly, the CO2 capture system
that is used in the Dakota Gasification facility can readily be used in
an IGCC EGU. There is no indication that the RECTISOL[supreg] process
(or other similar physical gas removal systems) is not feasible for an
IGCC EGU. In confirmation, according to product literature,
RECTISOL[supreg], which was independently developed by Linde and Lurgi,
is frequently used to purify shifted, partially shifted or un-shifted
gas from the gasification of coal, lignite, and residual oil.\216\
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\216\ www.linde-engineering.com/en/process_plants/hydrogen_and_synthesis_gas_plants/gas_processing/rectisol_wash/index.html.
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b. International Projects
There are some international projects that are in various stages of
development that indicate confidence by developers in the technical
feasibility of pre-combustion carbon capture. Summit Carbon Capture,
LLC is developing the Caledonia Clean Energy Project, a proposed 570-
megawatt IGCC plant with 90 percent CO2 capture that would
be built in Scotland, U.K. Captured CO2 from the plant will
be transported via on-shore and sub-sea pipeline for sequestration in a
saline formation in the North Sea. The U.K. Department of Energy &
Climate Change (DECC) recently announced funding to allow for
feasibility studies for this plant.\217\ Commercial operation is
expected in 2017.\218\
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\217\ http://www.downstreambusiness.com/item/Summit-Power-Wins-Funding-Studies-Proposed-IGCC-CCS-Project_140878.
\218\ http://www.summitpower.com/projects/carbon-capture/.
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The China Huaneng Group--with multiple collaborators, including
Peabody Energy, the world's largest private sector coal company--is
building the 400 MW GreenGen IGCC
[[Page 64554]]
facility in Tianjin City, China. The goal is to complete the power
plant before 2020. Over 80 percent of the CO2 will be
separated using pre-combustion capture technology. The captured
CO2 will be used for EOR operations.\219\
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\219\ http://sequestration.mit.edu/tools/projects/greengen.html.
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Vattenfall and Nuon's pilot project in Bugennum, The Netherlands
involves carbon capture from coal- and biomass-fired IGCC plants. It
has operated since 2011.\220\
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\220\ Buggenum Fact Sheet: Carbon Dioxide Capture and Storage
Project, Carbon Capture & Sequestration Technologies @MIT, http://sequestration.mit.edu/tools/projects/buggenum.html.
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Approximately 100 tons of CO2 per day are captured from
a coal- and petcoke-fired IGCC plant in Puertollano, Spain. The
facility began operating in 2010.\221\
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\221\ Puertollano Fact Sheet: Carbon Dioxide Capture and Storage
Project, Carbon Capture & Sequestration Technologies @MIT, https://sequestration.mit.edu/tools/projects/puertollanto.html.
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Emirates Steel Industries is expected to capture approximately
0.8Mt of CO2 per year from a steel-production facility in
the United Arab Emirates. Full-scale operations are scheduled to begin
by 2016.\222\
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\222\ ESI CCS Project Fact Sheet: Carbon Dioxide and Storage
Project, Carbon Capture & Sequestration Technologies @MIT, https://sequestration.mit.edu/tools/projects/esi_ccs.html and https://www.globalccsinstitute.com/projects/large-scale-ccs-projects.
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The Uthmaniyah CO2 EOR Demonstration Project in Saudi
Arabia will capture 0.8 Mt of CO2 from a natural gas
processing plant over three years. It is expected to begin operating in
2015.\223\
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\223\ Uthmaniyah CO2 EOR Demonstration Project,
Global CCS Institute, https://www.globalccsinstitute.com/projects/large-scale-ccs-projects.
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The experience of the Dakota Gasification facility, coupled with
the descriptions of the technology in the literature, the statements
from vendors, and the experience of facilities internationally, are
sufficient to support our determination that the technical feasibility
of CCS for an IGCC facility is adequately demonstrated. The experience
of additional facilities, described next, provides additional support.
3. Pre-Combustion Carbon Capture Projects That Have Received DOE
Assistance Through EPAct05, but Did Not Receive Tax Credits Under IRC
Section 48A
a. Coffeyville Fertilizer
Coffeyville Resources Nitrogen Fertilizers, LLC, owns and operates
a nitrogen fertilizer facility in Coffeyville, Kansas. The plant began
operation in 2000 and is the only one in North America using a
petroleum coke-based fertilizer production process. The petroleum coke
is generated at an oil refinery adjacent to the plant. The petroleum
coke is gasified to produce a hydrogen rich synthetic gas, from which
ammonia and urea ammonium nitrate fertilizers are subsequently
synthesized.
As a by-product of manufacturing fertilizers, the plant also
produces significant amounts of CO2. In March 2011,
Chaparral Energy announced a long-term agreement for the purchase of
captured CO2 which is transported 68 miles via
CO2 pipeline for use in EOR operations in Osage County, OK.
Injection at the site started in 2013.
At least one commenter suggested that the cost and complexity of
carbon capture from these and other industrial projects was
significantly decreased because the sources already separate
CO2 as part of their normal operations. The EPA finds this
argument unconvincing. The Coffeyville process involves gasification of
a solid fossil fuel (pet coke), shifting the resulting syngas stream,
and separation of the resulting CO2 using a pre-combustion
carbon capture system. These are the same, or very similar, processes
that are used in an IGCC EGU. The argument is even less convincing when
considering that the Coffeyville Fertilizer process uses the
SelexolTM pre-combustion capture process--the same process
that Mississippi Power described as having been ``in commercial use in
the chemical industry for decades'' and is expected by Mississippi
Power to ``pose little technology risk'' when used at the Kemper IGCC
EGU.
4. Pre-Combustion Carbon Capture Projects That Have Received DOE
Assistance Through EPAct05 and Tax Credits Under IRC Section 48A
a. Kemper County Energy Facility
Southern Company's subsidiary Mississippi Power has constructed the
Kemper County Energy Facility in Kemper County, MS. This is a 582 MW
IGCC plant that will utilize local Mississippi lignite and includes a
pre-combustion carbon capture system to reduce CO2 emissions
by approximately 65 percent. The pre-combustion solvent,
SelexolTM has also been used extensively for acid gas
removal (including for CO2 removal) in various processes. In
filings with the Mississippi Public Service Commission for the Kemper
project, Mississippi described the carbon capture system:
The Kemper County IGCC Project will capture and compress
approximately 65% of the Plant's CO2 [. . .] a process
referred to as SelexolTM is applied to remove the
CO2 such that it is suitable for compression and delivery
to the sequestration and EOR process. [. . .] The carbon capture
equipment and processes proposed in this project have been in
commercial use in the chemical industry for decades and pose little
technology risk. (emphasis added) \224\
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\224\ Mississippi Power Company, Kemper County IGCC Certificate
Filing, Updated Design, Description and Cost of Kemper IGCC Project,
Mississippi Public Service Commission (MPSC) DOCKET NO. 2009-UA-
0014, filed December 7, 2009.
Thus, Mississippi Power believes that, because the
SelexolTM process has been in commercial use in the chemical
industry for decades, it is well proven, and will pose little technical
risk when used in the Kemper IGCC EGU.
b. Texas Clean Energy Project and Hydrogen Energy California Project
The Texas Clean Energy Project (TCEP), 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. Summit has announced that they
expect to commence construction on the project in 2015.\225\ The
facility will utilize the Linde Rectisol[supreg] gas cleanup process to
capture carbon dioxide \226\--the same process that has been deployed
for decades, including at the Dakota Gasification facility, a clear
indication of the developer's confidence in that technology and further
evidence that the Dakota Gasification carbon capture technology is
transferable to EGUs.
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\225\ ``Odessa coal-to-gas power plant to break ground this
year'', Houston Chronicle (April 1, 2015).
\226\ http://www.texascleanenergyproject.com/project/.
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F. Vendor Guarantees, Industry Statements, Academic Literature, and
Commercial Availability
In this section, we describe additional information that supports
our determination that CCS is adequately demonstrated to be technically
feasible. This includes performance guarantees from vendors, public
statements from industry officials, and review of the literature.
1. Performance Guarantees
The D.C. Circuit made clear in its first cases concerning CAA
section 111 standards, and has affirmed since then,
[[Page 64555]]
that performance guarantees from vendors are an important basis for
supporting a determination that pollution technology is adequately
demonstrated to be technically feasible. In 1973, in Essex Chem. Corp.
v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973), the Court upheld
standards of performance for coal-fired steam generators based on
``prototype testing data and full-scale control systems, considerations
of available fuel supplies, literature sources, and documentation of
manufacturer guarantees and expectations'' (emphasis supplied)).\227\
Subsequently, in Sierra Club v. Costle, the Court noted, in upholding
the standard: ``we find it informative that the vendors of FGD
equipment corroborate the achievability of the standard.'' \228\
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\227\ See also Portland Cement Ass'n v. Ruckelshaus, 486 F.2d
375, 401-02 (D.C. Cir. 1973) (``It would have been entirely
appropriate if the Administrator had justified the standards . . .
on testimony from experts and vendors made part of the record.'').
\228\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
See also National Petrochem & Refiners Assn v. EPA, 287 F. 3d 1130,
1137 (D.C. Cir. 2002) (noting that vendor guarantees are an indicia
of availability and achievability of a technology-based standard
since, notwithstanding a desire to promote sales, ``a manufacturer
would risk a considerable loss of reputation if its technology could
not fulfill a mandate that it had persuaded EPA to adopt'').
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Linde and BASF offer performance guarantees for carbon capture
technology. The two companies are jointly marketing new, advanced
technology for capturing CO2 from low pressure gas streams
in power or chemical plants. In product literature,\229\ they note that
Linde will provide a turn-key carbon capture plant using a scrubbing
process and solvents developed by BASF, one of the world's leading
technical suppliers for gas treatment. They further note that:
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\229\ www.intermediates.basf.com/chemicals/web/gas-treatment/en/function/conversions:/publish/content/products-and-industries/gas-treatment/images/Linde_and_BASF-Flue_Gas_Carbon_Capture_Plants.pdf.
The captured carbon dioxide can be used commercially for example
for EOR (enhanced oil recovery) or as a building block for the
production of urea. Alternatively it can be stored underground as a
carbon abatement measure. [. . .] The PCC (Post-Combustion Capture)
technology is now commercially available for lignite and hard coal
fired power plant [. . .] applications.
The alliance between Linde, a world-leading gases and
engineering company and BASF, the chemical company, offers great
benefits [. . .] Complete capture plants including CO2
compression and drying . . . Proven and tested processes including
guarantee . . . Synergies between process, engineering, construction
and operation . . . Optimized total and operational costs for the
owner. (emphasis added)
In addition, other well-established companies that either offer
technologies that are actively marketed for CO2 capture from
fossil fuel-fired power plants or that develop those power plants, have
publicly expressed confidence in the technical feasibility of carbon
capture. For example, Fluor has developed patented CO2
recovery technologies to help its clients reduce GHG emissions. The
Fluor product literature \230\ specifically points to the Econamine FG
Plus\SM\ (EFG+) process, which uses an amine solvent to capture and
produce food grade CO2 from post-combustion sources. The
literature further notes that EFG+ is also used for carbon capture and
sequestration projects, that the proprietary technology provides a
proven, cost-effective process for the removal of CO2 from
power plant flue gas streams, and that the process can be customized to
meet a power plant's unique site requirements, flue gas conditions, and
operating parameters.
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\230\ www.fluor.com/client-markets/energy-chemicals/Pages/carbon-capture.aspx.
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Fluor has also published an article titled ``Commercially Available
CO2 Capture Technology'' in which it describes the EFG+
technology.\231\ The article notes, ``Technology for the removal of
carbon dioxide (CO2) from flue gas streams has been around
for quite some time. The technology was developed not to address the
GHG effect but to provide an economic source of CO2 for use
in enhanced oil recovery and industrial purposes, such as in the
beverage industry.''
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\231\ http://www.powermag.com/commercially-available-co2-capture-technology/.
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Mitshubishi Heavy Industries (MHI) offers a CO2 capture
system that uses a proprietary energy-efficient CO2
absorbent called KS-1TM. Compared with the conventional
monoethanolamine (MEA)-based absorbent, KS-1TM solvent
requires less solvent circulation to capture the CO2 and
less energy to recover the captured CO2.
In addition, Shell has developed the CANSOLV CO2 Capture
System, which Shell describes in its product literature \232\ as a
world leading amine based CO2 capture technology that is
ideal for use in fossil fuel-fired power plants where enormous amounts
of CO2 are generated. The company also notes that the
technology can help refiners, utilities, and other industries lower
their carbon intensity and meet stringent GHG abatement regulations by
removing CO2 from their exhaust streams, with the added
benefit of simultaneously lowering SO2 and NO2
emissions.
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\232\ http://www.shell.com/global/products-services/solutions-for-businesses/globalsolutions/shell-cansolv/shell-cansolv-solutions/co2-capture.html.
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At least one commenter suggested that it is unlikely that any
vendor is willing or able to provide guarantees of the performance of
the system as a whole, arguing that this shows the system isn't
adequately demonstrated.\233\ However, this suggestion is inconsistent
with the performance guarantees offered for other air pollution control
equipment. Particulate matter (PM) is controlled in the flue gas stream
of a coal-fired power plant using fabric filters or electrostatic
precipitators (ESP). The captured PM is then moved using PM/ash
handling systems and is then transported for storage or re-use. It is
unlikely that a fabric filter or ESP vendor would provide a performance
guarantee for ``the system as a whole.'' Similarly, a wet-FGD scrubber
vendor would not be expected to provide a performance guarantee for
handling, transportation, and re-use of scrubber solids for gypsum
wallboard manufacturing. CO2 capture, transportation, and
storage should, similarly, not be viewed as a single technology.
Rather, these should be viewed as components of an overall system of
emission reduction. Different companies will have expertise in each of
these components, but it is unlikely that a single technology vendor
would provide a guarantee for ``the system as a whole.''
---------------------------------------------------------------------------
\233\ Comments of Murray Energy, p. 73, (Docket entry: EPA-HQ-
OAR-2013-0495-10046).
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2. Academic and Other Literature
Climate change mitigation options--including CCS--are the subject
of great academic interest, and there is a large body of academic
literature on these options and their technical feasibility. In
addition, other research organizations (e.g., U.S. national
laboratories and others) have also published studies on these subjects
that demonstrate the availability of these technologies. A compendium
of relevant literature is provided in a Technical Support Document
available in the rulemaking docket.\234\
---------------------------------------------------------------------------
\234\ Technical Support Document--``Literature Survey of Carbon
Capture Technology'', available in the rulemaking docket (Docket ID:
EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------
3. Additional Statements by Technology Developers
The discussion above of vendor guarantees, positive statements by
industry officials, and the academic literature supports the EPA's
determination that partial CCS is adequately demonstrated to be
[[Page 64556]]
technically feasible. Industry officials have made additional positive
statements in conjunction with facilities that received DOE assistance
under EPAct05 or the IRC Section 48A tax credit. These statements
provide further, although not necessary, support.
For example, Southern Company's Mississippi Power has stated that,
because the SelexolTM process has been used in industry for
decades, the technical risk of its use at the Kemper IGCC facility is
minimized. For example:
The carbon capture process being utilized for the Kemper County
IGCC is a commercial technology referred to as SelexolTM.
The SelexolTM process is a commercial technology that
uses proprietary solvents, but is based on a technology and
principles that have been in commercial use in the chemical industry
for over 40 years. Thus, the risk associated with the design and
operation of the carbon capture equipment incorporated into the
Plant's design is manageable.\235\
---------------------------------------------------------------------------
\235\ Testimony of Thomas O. Anderson, Vice President,
Generation Development for Mississippi Power, MS Public Service
Commission Docket 2009-UA-14 at 22 (Dec. 7, 2009).
---------------------------------------------------------------------------
And . . .
The carbon capture equipment and processes proposed in this
project have been in commercial use in the chemical industry for
decades and pose little technology risk.\236\
---------------------------------------------------------------------------
\236\ Mississippi Power Company, Kemper County IGCC Certificate
Filing, Updated Design, Description and Cost of Kemper IGCC Project,
Mississippi Public Service Commission (MPSC) DOCKET NO. 2009-UA-
0014, filed December 7, 2009.
Similarly, in an AEP Second Quarter 2011 Earnings Conference Call,
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Chairman and CEO Mike Morris said of the Mountaineer CCS project:
We are encouraged by what we saw, we're clearly impressed with
what we learned, and we feel that we have demonstrated to a
certainty that the carbon capture and storage is in fact viable
technology for the United States and quite honestly for the rest of
the world going forward.\237\
---------------------------------------------------------------------------
\237\ American Electric Power Co Inc AEP Q2 2011 Earnings Call
Transcript, Morningstar, http://www.morningstar.com/earnings/28688913-american-electric-power-co-incaep-q2-2011-earnings-call-transcript.aspx.
Some commenters have claimed that CCS technology is not technically
feasible, and some further assert that vendors do not offer performance
---------------------------------------------------------------------------
guarantees. For example, Alstom commented:
The EPA referenced projects fail to meet the `technically
feasible' criteria. These technologies are not operating at
significant scale at any site as of the rule publication. We do not
support mandating technology based on proposed projects (many of
which may never be built).\238\
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\238\ Alstom Comments, p. 3 (Docket entry: EPA-HQ-OAR-2013-0495-
9033).
As discussed above, vendors do in fact offer performance
guarantees. We further note that, as noted above, Boundary Dam Unit #3
is a full-scale project that is successfully implementing full CCS with
post-combustion capture, and Dakota Gasification is likewise a full-
scale commercial operation that is successfully implementing pre-
combustion CCS technology. Moreover, as we explain above, this
technology and performance is transferable to the steam electric
generating sector. In addition, as noted above, technology providers
and technology end users have expressed confidence in the availability
and performance of CCS technology.\239\
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\239\ We note that before filing comments for this rule
asserting that CCS is not technically feasible, Alstom issued public
statements that, like the other industry officials quoted above,
affirmed that CCS is technically feasible. According to an Alstom
Power press release, Alstom President Phillipe Joubert, referencing
results from an internal Alstom study, stated at an industry
meeting: ``We can now be confident that carbon capture technology
(CCS) works and that it is cost-effective''. http://www.alstom.com/press-centre/2011/6/2011-06-16-CCS-cost-competiveness/.
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G. Response to Key Comments on the Adequacy of the Technical
Feasibility Demonstration
1. Commercial Availability
Some commenters asserted that CCS cannot be considered the BSER
because it is not commercially available. There is no requirement, as
part of the BSER determination, that the EPA finds that the technology
in question is ``commercially available.'' As we described in the
January 2014 proposal, the D.C. Circuit has explained that a standard
of performance is ``achievable'' if a technology or other system of
emission reduction can reasonably be projected to be available to new
sources at the time they are constructed that will allow them to meet
the standard, and that there is no requirement that the technology
``must be in routine use somewhere.'' See Portland Cement v.
Ruckelshaus, 486 F. 2d at 391; 79 FR 1463. In any case, as discussed
above, CCS technology is available through vendors who provide
performance guarantees, which indicates that in fact, CCS is
commercially available, which adds to the evidence that the technology
is adequately demonstrated to be technically feasible. In sum, ``[t]he
capture and CO2 compression technologies have commercial
operating experience with demonstrated ability for high reliability.''
\240\
---------------------------------------------------------------------------
\240\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity
Revision 3'', DOE/NETL-2015/1723 (July 2015) at p. 36.
---------------------------------------------------------------------------
2. Must a technology or system of emission reduction be in full-scale
use to be considered demonstrated?
Commenters maintained that the EPA can only show that a BSER is
``adequately demonstrated'' using operating data from the technology or
system of emission reduction itself. This is mistaken. Since the very
inception of the CAA section 111 program, courts have noted that ``[i]t
would have been entirely appropriate if the Administrator had justified
the standard, not on the basis of tests on existing sources or old test
data in the literature, but on extrapolations from this data, on a
reasoned basis responsive to comments, and on testimony from experts
and vendors . . . .'' Portland Cement v. Ruckelshaus, 486 F. 2d at 401-
02.\241\
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\241\ More recently, the D.C. Circuit stated:
Our prior decisions relating to technology-forcing standards are
no bar to this conclusion. We recognize here, as we have recognized
in the past, that an agency may base a standard or mandate on future
technology when there exists a rational connection between the
regulatory target and the presumed innovation.
API v. EPA, 706 F. 3d at 480 (D.C. Cir. 2013) (citing the
section 111 case Sierra Club v. Costle, 657 F. 2d at 364). The
Senate Report to the original section 111 likewise makes clear that
it was not intended that the technology ``must be in actual routine
use somewhere.'' Rather, the question was whether the technology
would be available for installation in new plants. S. Rep. No. 91-
1196, 91st Cong., 2d Sess. 16 (1970).
---------------------------------------------------------------------------
In a related argument, other commenters stated that a system cannot
be adequately demonstrated unless all of its component parts are
operating together.\242\ Courts have, in fact, accepted that the EPA
can legitimately infer that a technology is demonstrated as a whole
based on operation of component parts which have not, as yet, been
fully integrated. Sur Contra la Contaminacion v. EPA, 202 F. 3d 443,
448 (1st Cir. 2000); Native Village of Point Hope v Salazar 680 F. 3d
1123, 1133 (9th Cir. 2012). Moreover, all components of CCS are fully
integrated at Boundary Dam: Post-combustion full CCS is being utilized
at a steam electric fossil fuel-fired plant, with captured carbon being
transported via dedicated pipeline to both sequestration and EOR sites.
All components are likewise demonstrated for pre-combustion CCS at the
Dakota Gasification facility, except that the facility does not
generate electricity, a distinction without a difference for this
purpose (see Section V.E.2.a above).
---------------------------------------------------------------------------
\242\ See, e.g., Comments of UARG p. 5 (Docket entry: EPA-HQ-
OAR-2013-0495-9666).
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The short of it is that the ``EPA does have authority to hold the
industry to a standard of improved design and
[[Page 64557]]
operational advances, so long as there is substantial evidence that
such improvements are feasible and will produce the improved
performance necessary to meet the standard.'' Sierra Club, 657 F. 2d at
364. The EPA's task is to ``identify the major steps necessary for
development of the device, and give plausible reasons for its belief
that the industry will be able to solve those problems in the time
remaining''. API v. EPA, 706 F. 3d at 480 (quoting NRDC v. EPA, 655 F.
2d 318, 333 (D.C. Cir. 1981), and citing Sierra Club for this
proposition).
3. Scalability of Pilot and Demonstration Projects
Commenters maintained that the EPA had no basis for maintaining
that pilot and demonstration plant operations showed that CCS was
adequately demonstrated. This is mistaken. In a 1981 decision, Sierra
Club v. Costle, the D.C. Circuit explained that data from pilot-scale,
or less than full-scale operation, can be shown to reasonably
demonstrate performance at full-scale operation, although it is
incumbent on the EPA to explain the necessary steps involved in scaling
up a technology and how any obstacles may reasonably be surmounted when
doing so.\243\ The EPA has done so here.
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\243\ Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 and 380-84
(D.C. Cir. 1981). See also Essex Chemical Corp. v. EPA, 486 F. 2d at
440 (upholding achievability of standard of performance for coal-
burning steam generating plants which hadn't been achieved in full-
scale performance based in part on ``prototype testing data'' which,
along with vendor guarantees, indicated that the promulgated
standard was achievable); Weyerhaeuser v. Costle, 590 F. 2d 1054 n.
170 (D.C. Cir. 1978) (use of pilot plant information to justify
technology-based standard for Best Available Technology Economically
Achievable under section 304 of the Clean Water Act); FMC Corp. v.
Train, 539 F. 2d 973, 983-84 (4th Cir. 1976)(same).
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Most obviously, the final standard reflects experience of full-
scale operation of post-combustion carbon capture. Pre-combustion
carbon capture is likewise demonstrated at full-scale. Second, the
record explains in detail how CCS can be implemented at full-scale. The
NETL cost and performance reports, indeed, contain hundreds of pages of
detailed, documented explanation of how CCS can be implemented at full-
scale for both utility boiler and IGCC facilities. See, for example,
the detailed description of the following systems projected to be
needed for a new supercritical PC boiler to capture CO2:
Coal and sorbent receiving and storage, steam generator and
ancillaries, NOX control system, particulate control, flue
gas desulfurization, flue gas system, CO2 recovery facility,
steam turbine generator system, balance of plant, and accessory
electric plant, and instrumentation and control systems.\244\
---------------------------------------------------------------------------
\244\ Cost and Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity; Revision
2a, pp. 57-74.
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It is important to note that, while some commenters challenged the
EPA's use of costs in the DOE/NETL cost and performance reports,
commenters did not challenge the technical methodology in the work.
In addition, the AEP FEED study indicates how the development scale
post-combustion CCS could be successfully scaled up to full-scale
operation. See Section V.D.3.b above.
Tenaska Trailblazer Partners, LLC also prepared a FEED study \245\
for the carbon capture portion of the previously proposed Trailblazer
Energy Center, a 760 MW SCPC EGU that was proposed to include 85 to 90
percent CO2 post-combustion capture. Tenaska selected the
Fluor Econamine FG Plus\SM\ technology and contracted Fluor to conduct
the FEED study. One of the goals of the FEED study was to ``[c]onfirm
that scale up to a large commercial size is achievable.'' Tenaska
ultimately concluded that the study had achieved its objectives
resulting in ``[c]onfirmation that the technology can be scaled up to
constructable design at commercial size through (1) process and
discipline engineering design and CFD (computational fluid dynamics)
analysis, (2) 3D model development, and (3) receipt of firm price
quotes for large equipment.''
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\245\ Final front-end engineering design (FEED) study report'',
available at: www.globalccsinstitute.com/publications/tenaska-trailblazer-front-end-engineering-design-feed-study.
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Much has been written about the complexities of adding CCS systems
to fossil fuel-fired power plants. Some of these statements come from
high government officials. Some commenters argued that the EPA
minimized--or even ignored--these publically voiced concerns in the
discussion presented in the January 2014 proposal. On the contrary, the
EPA has not minimized or ignored these complexities, but it is
important to realize that most of these statements come in a different
context: Namely, implementing full CCS, or retrofitting CCS onto
existing power plants. For example, in the Final Report of the
President's CCS Task Force, it was noted that ``integration of CCS
technologies with the power cycle at generating plants can present
significant cost and operating issues that will need to be addressed to
facilitate widespread, cost-effective deployment of CO2
capture.'' \246\ This statement--and most of the statements in this
vein--are in reference to implementation of full CCS systems that
capture more than 90 percent of the CO2 and many reference
widespread implementation of such technology. The EPA has addressed the
concerns regarding ``significant cost'' by finalizing a standard that
relies on partial CCS which we show, in this preamble and in the
supporting record, can be implemented at a reasonable, non-exorbitant
cost. The Boundary Dam facility, in particular, demonstrates that the
complexities of implementing CCS--even full CCS--can be overcome.
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\246\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010), page 28. See also DOE Carbon Capture Web
site: ``First generation CO2 capture technologies are
currently being used in various industrial applications. However, in
their current state of development, these technologies are not ready
for implementation on coal-based power plants because they have not
been demonstrated at appropriate scale, requisite approximately one-
third of the plant's steam power to operate, and are cost
prohibitive.'' (Dec 2010); and Testimony of Dr. S. Julio Friedmann,
Deputy Asst. Secretary of Energy for Clean Coal, U.S. Dept. of
Energy, before the Subcommittee on Oversight and Investigations
Committee on Energy and Commerce (Feb. 11, 2014): CCS technologies
at new coal-fired plants would result in ``something like a 70 to 80
percent increase on the wholesale price of electricity.''
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Concerns regarding ``operating issues'' are also often associated
with implementation of full CCS--and often with implementation of full
CCS as a retrofit to an existing source. Implementation of CCS at some
existing sources may be challenging because of space limitations. That
should not be an issue for a new facility because the developer will
need to ensure that adequate space is available during the design of
the facility. Constructing CCS technology at an existing facility can
be challenging even if there is adequate space because the positioning
of the equipment may be awkward when it must be constructed to fit with
the existing equipment at the plant. Some commenters noted the
challenges of diverting steam from the plant's steam cycle. Again, that
is primarily an issue with full CCS implementation as a retrofit to an
existing source. Consideration of steam requirements for solvent
regeneration can be factored into the design of a new facility. We also
note that issues of integration with the plant's steam cycle are less
challenging when implementing partial CCS.
Some commenters noted conclusions and statements from the CCS Task
Force report as contradictory to the EPA's determination of that
partial CCS is technically feasible and adequately demonstrated.
However, the EPA mentioned in the January 2014
[[Page 64558]]
proposal, and we emphasize again here, that the Task Force was charged
with proposing a plan to overcome the barriers to the widespread, cost-
effective deployment of CCS by 2020. Implicit in all of the
conclusions, recommendations, and statements of that final report is a
goal of widespread implementation of full CCS--including retrofits of
existing sources. This final action does not require--nor does it
envision--the near term widespread implementation of full CCS. On the
contrary, as we have noted several times in this preamble, the EPA and
others predict that very few, if any, new coal-fired steam generating
EGUs will be built in the near term.
Thus, the EPA has provided an ample record supporting its finding
that partial CCS is feasible at full-scale. As in Sierra Club, the EPA
has presented evidence from full-scale operation, smaller scale
installations, and reasonable, corroborated technical explanations of
how the BSER can be successfully operated at full scale. See 657 F. 2d
at 380, 382. Indeed, the EPA has more evidence here, as the baghouse
standard in Sierra Club was justified based largely on less-than-full-
scale operation. See 657 F.2d at 380 (there was only ``limited data
from one full scale commercial sized operation''), 376 (``the baghouses
surveyed were installed at small plants''), and 341 n.157; see also
Section V.L, explaining why CCS is a more developed technology than FGD
scrubbers were at the inception of the 1971 NSPS for this industry.
H. Consideration of Costs
CAA section 111(a) defines ``standard of performance'' as an
emission standard that reflects the best system of emission reduction
that is adequately demonstrated, ``taking into account [among other
things] the cost of achieving such reduction.'' Based on consideration
of relevant cost metrics in the context of current market conditions,
the EPA concludes that the costs associated with the final standard are
reasonable.
In reaching this determination, the EPA considered a host of
different cost metrics, each of which illuminated a particular aspect
of cost consideration, and each of which demonstrated that the costs of
the final standard are reasonable. The EPA evaluated capital costs on a
per-plant basis, responding to public comment that noted the particular
significance of capital costs for coal-fired EGUs. As in the proposal,
the EPA also considered how the standard would affect the LCOE for
individual affected EGUs as well as national, overall cost impacts of
the standard. The EPA found that the anticipated cost impacts are
similar to those in other promulgated NSPS--including for this
industry--that have been upheld by the D.C. Circuit. The costs are also
comparable to those of other base load technologies that might be
selected on comparable energy portfolio diversity grounds. Finally, the
EPA does not anticipate any significant overall nationwide costs or
cost impacts on consumers because projected new generating capacity is
expected to meet the standards even in the baseline. Accordingly, after
considering costs from a range of different perspectives, the EPA
concludes that the costs of the final standard are reasonable.
1. Rationale at Proposal
At proposal, the EPA evaluated the costs of new coal-fired EGUs
implementing full (90 percent) and partial CCS. The EPA compared the
predicted LCOE of those units against the LCOE of other new
dispatchable technologies often considered for new base load power with
fuel diversity, primarily including a new nuclear plant, as well as a
new biomass-fired EGU. See 79 FR at 1475-78. The levelized cost for a
new steam EGU implementing full CCS was higher than that of the other
non-NGCC dispatchable technologies, and we did not propose to identify
a new steam EGU implementing full CCS as BSER on that basis. Id. at
1477. The EPA proposed that a standard of performance of 1,100 lb
CO2/MWh-g, reflecting a new steam EGU implementing partial
CCS, could be achieved at reasonable cost based on a comparison of the
projected LCOE associated with achieving this standard with the
alternative dispatchable technologies just mentioned. In the January
2014 proposal, the EPA used LCOE projections for new fossil fuel-fired
EGUs from a series of studies conducted by the DOE NETL. These
studies--the ``cost and performance studies''--detail expected costs
and performance for a range of technology options both with and without
CCS.\247\ The EPA used LCOE projections for non-fossil dispatchable
generation--specifically nuclear and biomass--from the EIA AEO 2013.
See 79 FR 1435.
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\247\ For the cost estimates in the January 2014 proposal, the
EPA 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/research/energy-analysis/energy-baseline-studies.
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In addition, the EPA proposed that the costs to implement partial
CCS were reasonable because a segment of the industry was already
accommodating them. Id. at 1478. The EPA also considered anticipated
decreases in the cost of CCS technologies, the availability of
government tax benefits, loan guarantees, and direct expenditures, and
the opportunity to generate income from sale of captured CO2
for EOR. Id. at 1478-80. The EPA noted that the proposed standard was
not expected to lead to any significant overall costs or effects on
electricity prices. Id. at 1480-81. The EPA also acknowledged the
overall market context, noting that fossil steam EGUs, even without any
type of CCS, are significantly more expensive than new natural gas-
fired electricity generation, but that some electricity suppliers might
include new coal-fired generating sources in their generation
portfolio, and would pay a premium to do so. Id. at 1478.
2. Brief Summary of Cost Considerations Under CAA Section 111
As explained above, CAA section 111(a) directs the EPA to ``tak[e]
into account the cost'' of achieving reductions in determining if a
particular system of emission reduction is the best that is adequately
demonstrated. The statute does not provide further guidance on how
costs should be considered, thus affording the EPA considerable
discretion in choosing a means of cost consideration. In addition, it
should be noted that in evaluating the reasonableness of costs, the
D.C. Circuit has upheld application of a variety of metrics, such as
the amount of control costs or product price increases. See Section
III.H.3.(b).(1) above.
Following the directive of CAA section 111(a) and applicable
precedent, the EPA evaluated relevant metrics and context in
considering the reasonableness of the regulation's costs. The EPA's
findings demonstrate that the costs of the selected final standard are
reasonable.
3. Current Context
The EIA projects that few new coal-fired EGUs will be constructed
over the coming decade and that those that are built will apply CCS,
reflecting the broad consensus of government, academic, and industry
forecasters.\248\
[[Page 64559]]
The primary reasons for this projected trend include low electricity
demand growth, highly competitive natural gas prices, and increases in
the supply of renewable energy. In particular, U.S. electricity demand
growth has followed a downward sloping trend for decades with future
growth expected to remain very low.\249\ Furthermore, the EPA projects
that, for any new fossil fuel-fired electricity generating capacity
that is constructed through 2030, natural gas will be the overwhelming
fuel of choice.\250\ See RIA chapter 4.
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\248\ 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. EIA, ``Annual Energy Outlook 2015,'' DOE/EIA-
0383(2015), April 2015, ``[v]ery little unplanned coal-fired
capacity is added across all the AEO 2015 cases'', p. 26.
\249\ EIA, ``Annual Energy Outlook 2015,'' DOE/EIA-0383(2015),
April 2015, p. 8.
\250\ Integrated Planning Model (IPM) run by the EPA (v. 5.15)
Base Case, available at www.epa.gov/airmarkets/powersectormodeling.html.
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The EIA's projection is confirmed by an examination of Integrated
Resource Plans (IRPs) contained in a TSD in the docket for this
rulemaking. IRPs are used by utilities to plan operations and
investments in both owned generation and power purchase agreements over
long time horizons. Though IRPs do not demonstrate a utility's intent
to pursue a particular generation technology, they do indicate the
types of new generating technologies that a utility would consider for
new generating capacity. The EPA's survey of recent IRPs demonstrates
that across the nation, utilities are not actively considering
constructing new coal-fired generation without CCS in the near term.
Accordingly, construction of new uncontrolled coal-fired generating
capacity is not anticipated in the near term, even in the absence of
the standards of performance we are finalizing in this rule, except
perhaps in certain limited circumstances.
In particular, commenters suggested that some developers might
choose to build a new coal-fired EGU, despite its not being cost
competitive, in order to achieve or maintain ``fuel diversity.'' Fuel
diversity could provide important value by serving as a hedge against
the possibility that future natural gas prices will far exceed
projected levels.
Public announcements, including IRPs, confirm that utilities are
interested in technologies that could provide or preserve fuel
diversity within generating fleets. The Integrated Resource Plan TSD
\251\ notes examples where the goal of fuel diversity was considered in
IRPs; in many cases, these plans considered new generation that would
not rely on natural gas. In particular, several utilities that
considered fuel diversity in developing their IRPs included new nuclear
generation as a potential future generation strategy.
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\251\ Technical Support Document--``Review of Electric Utility
Integrated Resource Plans'' (May 2015), available in the rulemaking
docket EPA-HQ-OAR-2013-0495.
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In addition, the EPA recognizes that there may be interest in
constructing a new combined-purpose coal-fired facility that would
generate power as well as produce chemicals or CO2 for use
in EOR projects. These facilities would similarly provide additional
value due to the revenue streams from saleable chemical products or
CO2.\252\
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\252\ The EPA may, of course, consider revenues generated as a
result of application of pollution control measures in assessing the
costs of a best system of emission reduction. See New York v.
Reilly, 969 F.2d 1147, 1150-52 (D.C. Cir. 1992).
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As demonstrated below, the agency carefully considered the
reasonableness of costs in identifying a standard that allows a path
forward for such projects and rejects more stringent options that would
impose potentially excessive costs. In fact, based on this careful
consideration of costs, the EPA is finalizing a substantially lower
cost standard than the one we proposed. At the same time, we note the
unusual circumstances presented here, where the record, and indeed
simple consideration of electricity market economics, demonstrates that
non-economic factors such as fuel diversity are likely to drive any
construction of new coal-fired generation. See also RIA chapter 4
(documenting that electric power companies will choose to build new
EGUs that comply with the regulatory requirements of this rule even in
its absence, primarily NGCC units, because of existing and expected
market conditions). Under these circumstances, the EPA's consideration
of costs takes into account that higher costs can be viewed as
reasonable when costs are not a paramount factor in new coal capacity
decisions. At the same time, the EPA acknowledges and agrees with the
public comments that such an argument, left unconstrained, could
justify any standard and obviate all cost considerations.\253\ The EPA
has reasonably cabined its consideration of costs by examining costs
for comparable non-NGCC base load dispatchable technologies, as well as
by considering capital costs and other cost metrics.\254\ This cost-
reasonable standard will preserve the opportunity for such projects
while driving new technology deployment.\255\
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\253\ See, e.g., Comments of Murray Energy, pp. 79-80 (Docket
entry: EPA-HQ-OAR-2013-0495-10046).
\254\ Indeed, the EPA is not only adopting a standard predicated
on a lower rate of carbon capture than proposed, but also rejecting
full CCS for reasons of cost. See Section V.P below. Thus, although
the EPA has reasonably taken into account the current economic
posture of the industry whereby new capacity is not cost-competitive
and so would be added for non-economic reasons, it is not using that
fact to negate consideration of cost here. See also Section V.I.4
below responding to comments that the incremental cost of partial
CCS could prove the difference between constructing and not
constructing new coal capacity.
\255\ In this rulemaking, our determination that the costs are
reasonable means that the costs meet the cost standard in the case
law no matter how that standard is articulated, that is, whether the
cost standard is articulated through the terms that the case law
uses, e.g., ``exorbitant,'' ``excessive,'' etc., or through the term
we use for convenience, ``reasonableness.''
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4. Consideration of Capital Costs
As noted above, CAA section 111 does not mandate any particular
method for evaluating costs, leaving the EPA with significant
discretion as to how to do so. One method is to consider the
incremental capital costs required for a unit to achieve the standard
of performance.
The EPA included information on capital cost at proposal and, as
discussed further below, the LCOE metric relied upon at proposal and in
this final rulemaking incorporates and fully reflects capital
costs.\256\ Nonetheless, extensive comment from industry
representatives and others noted persuasively that fossil-steam units
are very capital-intensive projects and recommended that a separate
metric, solely of capital costs, be considered by the EPA in evaluating
the final standard's costs. Accordingly, the EPA has considered the
final standard's impact on the capital costs of new fossil-steam
generation. The EPA has determined that the incremental capital costs
of the final standard are reasonable because they are comparable to
those in prior regulations and to industry experience, and because the
fossil steam electric power industry has been shown to be able to
successfully absorb capital costs of this magnitude in the past.
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\256\ See RIA chapter 4.5.4 and Fig. 4-3; see also ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (July 2015) p. 17.
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Prior new source performance standards for new fossil steam
generation units have had significant--yet manageable--impacts on the
capital costs of construction. The EPA estimated that the costs for the
1971 NSPS for coal-fired EGUs were $19M for a 600 MW plant, consisting
of $3.6M for particulate matter controls, $14.4M for sulfur dioxide
controls, and $1M for nitrogen oxides controls, representing a 15.8
percent increase in capital costs
[[Page 64560]]
above the $120M cost of the plant. See 1972 Supplemental Statement, 37
FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld the EPA's
determination that the costs associated with the final 1971 standard
were reasonable, concluding that the EPA had properly taken costs into
consideration. Essex Cement v. EPA, 486 F. 2d at 440.
In reviewing the 1978 NSPS for coal-fired EGUs, the D.C. Circuit
recognized that ``EPA estimates that utilities will have to spend tens
of billions of dollars by 1995 on pollution control under the new
NSPS'' and that ``[c]onsumers will ultimately bear these costs.''
Sierra Club, 657 F.2d at 314. The court nonetheless upheld the EPA's
determination that the standard was reasonable. Id. at 410.
The cost and investment impacts of the 1978 NSPS on electric
utilities were subsequently evaluated in a 1982 Congressional Budget
Office (CBO) retrospective study.\257\ The CBO study highlighted that
installation of scrubbers--capital intensive pollution control
equipment that had ``in effect'' been mandated by the 1978 NSPS--
increased capital costs for new EGUs by 10 to as much as 20
percent.\258\ The study further noted that air pollution control
requirements in general had led to an estimated 37.5 to 45 percent
increase in capital costs for coal-fired power plant installation
between 1971 and 1980.\259\
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\257\ Congressional Budget Office report, ``The Clean Air Act,
the Electric Utilities, and the Coal Market'', April 1982, p. 10-11,
23.
\258\ Id. at 10-11.
\259\ Id. at 22.
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The study retrospectively confirmed the EPA's conclusion that
imposition of these costs was reasonable, finding that ``utilities with
commitments to pollution control tend to fare no better and no worse
than all electric utilities in general.'' \260\ In assessing the
capital cost impacts of the suite of 1970s EPA air pollution standards,
the report concluded that ``though controlling emissions is indeed
costly, it has not played a major role in impairing the utilities'
financial position, and is not likely to do so in the future.'' \261\
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\260\ Id. at xvi.
\261\ Id.
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In NSPS standards for other sectors, the EPA's determination that
capital cost increases were reasonable has similarly been upheld. In
Portland Cement Association, the D.C. Circuit upheld the EPA's
consideration of costs for a standard of performance that would
increase capital costs by about 12 percent, although the rule was
remanded due to an unrelated procedural issue. 486 F.2d at 387-88.
Reviewing the EPA's final rule after remand, the court again upheld the
standards and the EPA's consideration of costs, noting that ``[t]he
industry has not shown inability to adjust itself in a healthy economic
fashion to the end sought by the Act as represented by the standards
prescribed.'' Portland Cement v. Ruckelshaus, 513 F. 2d 506, 508 (D.C.
Cir. 1975).
The capital cost impacts incurred under these prior standards are
comparable in magnitude on an individual unit basis to those projected
for the present standard. We predict that the incremental costs of
control for a new highly efficient SCPC unit to meet the final emission
limitation of 1,400 lb CO2/MWh-g would be an increase of 21-
22 percent for capital costs. See Table 7 below.262 263
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\262\ We explain at Section V.I.2 and 3 below the reasonableness
of the EPA's cost projections here.
\263\ We estimate that a new SCPC EGU using low rank coal
(subbituminous coal or dried lignite) would incur a capital cost
increase of 23 percent to meet the final standard. See
``Achievability of the Standard for Newly Constructed Steam
Generating EGUs'' technical support document available in the
rulemaking docket.
\264\ Exhibit A-3 (p. 18); ``Cost and Performance Baseline for
Fossil Energy Plants Supplement: Sensitivity to CO2
Capture Rate in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June
2015).
Table 7--Comparison of Estimated Capital Costs for a New SCPC and a New
SCPC Meeting the Final Standard of Performance \264\
------------------------------------------------------------------------
Total Total as-spent
overnight cost capital (2011$/
(2011$/kW) kW)
------------------------------------------------------------------------
SCPC--no CCS............................ 2,507 2,842
SCPC--partial CCS (1,400 lb CO2/MWh-g).. 3,042 3,458
Incremental cost increase............... 21.3% 21.7%
------------------------------------------------------------------------
By comparison, a SCPC that co-fires with natural gas to meet the
final standard of 1,400 lb CO2/MWh-g would not result in an
increase in capital cost over the uncontrolled SCPC. A compliant IGCC
unit co-firing natural gas is predicted to have Total Overnight Cost of
$3,036/kW--an approximately 21.1 percent increase in capital over the
uncontrolled SCPC unit.
5. Consideration of Costs Based on Levelized Cost of Electricity
As in the proposal, the EPA also considered the reasonableness of
costs by evaluating the LCOE associated with the final standard. The
LCOE is a commonly used economic metric that takes into account all
costs to construct and operate a new power plant over an assumed time
period and an assumed capacity factor. The LCOE is a summary metric,
which expresses the full cost of generating electricity on a per unit
basis (i.e., megawatt-hours). Levelized costs are often used to compare
the cost of different potential generating sources. While capital cost
is a useful and relevant metric for capital-intensive fossil-steam
units, the LCOE can serve as a useful complement because it takes into
account all specified costs (operation and maintenance, fuel--as well
as capital costs), over the whole lifetime of the project.
As previously mentioned, at proposal the EPA relied on LCOE
projections for fossil fuel-fired EGUs (with and without CCS) from DOE/
NETL reports detailing the results of studies evaluating the costs and
performance of such units. For non-fossil dispatchable generating
sources, the EPA relied on LCOE projections from EIA AEO 2013. For this
final action, the EPA is relying on updated costs from the same
sources. The NETL has provided updated cost and performance information
in recently published revisions of reports used in the January 2014
proposal.\265\ The updated SCPC cases in the reports include up-to-date
cost and performance information from recent vendor quotes
[[Page 64561]]
and implementation of the Shell Cansolv post-combustion capture
process--the process that is currently being utilized at the Boundary
Dam #3 facility. The IGCC cost and performance results in the updated
reports utilize vendor quotes from the previous report; the costs are
adjusted from $2007 to $2011. Important also to note is that DOE/NETL
utilized conventional financing for cases without CCS and utilized
high-risk financial assumptions for cases that include CCS.\266\
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\265\ ``Cost and Performance Baseline for Fossil Energy Plants:
Volume 1a'' Bituminous Coal (PC) and Natural Gas to Electricity,
Revision 3, U.S. DOE NETL report (2015) and ``Cost and Performance
Baseline for Fossil Energy Plants: Volume 1b: Bituminous Coal (IGCC)
to Electricity, Revision 2--Year Dollar Update, U.S. DOE NETL report
(2015). Both reports are available at www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
\266\ Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015) p. 18.
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Using information from those reports, the DOE/NETL prepared a
separate report summarizing a study that evaluated the cost and
performance of various plants designed to meet a range of
CO2 emissions by varying the CO2 capture rate
(i.e., the level of partial capture).\267\ The EIA also updated LCOE
projections from AEO 2013 to AEO 2014 and again in AEO 2015. Those are
discussed in more detail in Section V.I.2.b and d. In evaluating costs
for the final standards in this action, the EPA relied primarily on the
updated NETL LCOE projections for new fossil fuel-fired EGUs provided
in the reports described above and on the LCOE projections for non-
fossil, dispatchable generating options from the EIA's AEO 2015.\268\
Here, the EPA compared the LCOE of the final standard to the LCOE of
analogous potential sources of intermediate and base load power. This
comparison demonstrated that the LCOE for a fossil steam unit with
partial CCS is within the range of the LCOE of comparable alternative
non-NGCC generation sources. In particular, nuclear and biomass
generation, which similarly provide both base load power and fuel
diversity, have comparable LCOE. The EPA concludes that an evaluation
of the LCOE also demonstrates that the costs of the final standard are
reasonable.
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\267\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015). Available at http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
\268\ http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
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a. Calculation of the LCOE
The LCOE of a power plant source is calculated with the expected
lifetime and average capacity factor, and represents the average cost
of producing a megawatt-hour (MWh) of electricity over the expected
lifetime of the asset.
The LCOE incorporates all specified costs, and therefore is
dependent on the project's capital costs, the fixed and variable
operating and maintenance (O&M) costs, the fuel costs, the costs to
finance the project, and finally on the assumed capacity factor.\269\
The relative contribution of each of these inputs to LCOE will vary
among the generating technologies. For example, the LCOE for a new
supercritical PC plant or a new IGCC plant is influenced more by the
capital costs (and thus the financing assumptions) and less on fuel
costs than a comparably sized new NGCC facility which would require
less capital investment but would be more influenced by assumed fuel
costs.
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\269\ See, e.g. ``Cost and Performance Baseline for Fossil
Energy Plants Supplement: Sensitivity to CO2 Capture Rate
in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June 2015) at p.
17.
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b. Use of the LCOE
The utility industry and electricity sector regulators often use
levelized costs as a summary measure for comparing the cost of
different potential generating sources. Use of the LCOE as a comparison
measure is appropriate where the facilities being compared would serve
load in a similar manner.
The value of generation, as reflected in the wholesale electricity
price, can vary seasonally and over the course of a day. In addition,
electricity generation technologies differ on dimensions other than
just cost, such as ramping efficiency, intermittency, or uncertainty in
future fuel costs. These other factors are also important in
determining the value of a particular generation technology to a firm,
and accordingly cost comparisons between two different technologies are
most appropriate and insightful when the technologies align along these
other dimensions. Isolating a comparison of technologies based on their
LCOE is appropriate when they can be assumed to provide similar
services and similar values of electricity generated.
As we indicated in the proposal, we evaluated publicly available
IRPs and other available information (such as public announcements) to
determine the types of technologies that utilities are considering as
options for new generating capacity.\270\ In the near future, the
largest sources of new fossil fuel-fired power generation are expected
to be new NGCC units. But the IRPs also suggested that utilities are
interested in a range of technologies that can be used to provide or
preserve fuel diversity within the utilities' respective generating
fleets.271 272 The options for
[[Page 64562]]
dispatchable generation that can provide intermediate or base-load
power and fuel diversity would include new fossil steam units, new
nuclear power, and biomass-fired generation.
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\270\ See also discussion at V.C.3 above. The IRPs do not
provide an indication of the utility's intention to pursue a
particular generation technology. However, the IRPs do provide an
indication of the types of new generating technologies that the
utility would consider for new generating capacity.
\271\ See, e.g. the 2014 IRP of Dominion Virginia Power:
With those factors in mind, the 2014 Plan presents two paths
forward for resource expansion: a Base Plan, designed using least-
cost planning methods and consistent with the requirements of Rule
R8-60 for utility plans to provide ``reliable electric utility
service at least cost over the planning period;'' and a Fuel
Diversity Plan, which includes a broader array of low or zero-
emissions options. While the Fuel 2 Diversity Plan currently
represents a higher cost option at today's current and projected
commodity prices, its resource mix provides the important benefits
of greater fuel diversity and lower carbon intensity. Therefore, the
Company will continue reasonable development of the more diverse and
lower carbon intensive options in the Fuel Diversity Plan and will
be ready to implement them as conditions warrant. . . . The Fuel
Diversity Plan places a greater reliance on generation sources with
little or no carbon emissions and is less reliant on natural gas.
While following the resource expansion scenario in the least-cost
Base Plan, the Company will continue evaluation and reasonable
development efforts for the following projects identified in the
Fuel Diversity Plan. These include:
Continued development of a third nuclear reactor at North Anna
Power Station, using reactor technology supplied by GE-Hitachi
Nuclear Energy Americas LLC. While the Company has made no final
commitment to building this unit, it recognizes the many operational
and environmental benefits of nuclear power and continues to
actively develop the project. Our customers have benefitted from the
existing nuclear fleet for many years now, and they will continue to
benefit from the existing fleet for many years in the future. A
final decision on construction of North Anna Unit 3 will not be made
until after the Company receives a Combined Operating License or COL
from the U.S. Nuclear Regulatory Commission, now expected in 2016.
The Fuel Diversity Plan includes the addition of North Anna Unit 3's
1,453 megawatts of zero-emissions generation by 2028. If
constructed, the project would provide a dramatic boost to the
regional economy.
Additional reliance on renewable energy, including 247 megawatts
of onshore wind capacity at sites in western Virginia and a 12
megawatt offshore wind demonstration project by 2018.
An additional 559 megawatts of nameplate solar capacity,
including several new Company-owned photovoltaic CPV) installations.
Solar PV costs have declined significantly in recent years, making
utility-scale solar much more cost-effective than distributed solar,
and continuing technological development, in which the Company is
participating, may allow it to become a more cost-effective source
of intermittent generation in the future.cover letter for 2014 IRP--
https://www.dom.com/library/domcom/pdfs/corporate/integrated-resource-planning/va-irp-2014.pdf.
\272\ Another example are the recent statements of officials of
Tri-State Generation and Transmission, available at http://www.wyofile.com/coal-power/, including:
``We are considering nuclear, coal and natural gas,'' said Ken
Anderson, general manager of Tri-State at a conference in October
[2010], a position that Tri-State representatives say remains. ``We
will pick our technology once policy certainty comes about,'' he
added. . . . Longer-term forecasts are based on assumptions that may
or may not prove well-founded. Because of this uncertainty, Tri-
State believes it must retain options for all fuels and
technologies.
``We will not take anything off the table,'' [Tri-State
spokesman Lee] Boughey said. That includes coal. ``Coal is an
affordable and plentiful resource, but it does come with
challenges--and we are looking to different technology that can
address some of those challenges while continuing to provide a
reliable and affordable power supply,'' Boughey said. ``Some critics
believe we shouldn't be looking at resource options that include
coal, and even nuclear technology,'' Boughey added. ``We believe it
would be irresponsible not to consider these fuels or technologies
as part of an affordable, reliable and responsible resource
portfolio.''
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Thus, in both the proposal and in this final rule, the EPA is
comparing the LCOE of technologies that would be reasonably anticipated
to be designed, constructed, and operated for a similar purpose--that
is, to provide dispatchable base load power that provides fuel
diversity by relying on a fuel source other than natural gas. In
contrast, it may not be appropriate to compare the LCOE for a base load
coal-fired plant with that of a peaking natural gas-fired simple cycle
turbine. Similarly, it may not be appropriate to compare LCOE for
dispatchable technologies (i.e., generating sources that can be ramped
up or down as needed, e.g., coal-fired units, NGCC units, nuclear) with
that of non-dispatchable technologies (i.e., generating sources that
cannot be reliably ramped up or down to meet demand, e.g., wind,
solar.)
c. Reasonableness of Costs Based on LCOE
An examination of the LCOE of analogous sources of base load,
dispatchable power shows that the final standard's LCOE is comparable
to that of other sources, as shown in Table 8 below. As mentioned
earlier and discussed in further detail below, these estimates rely
most heavily on DOE/NETL cost projections for fossil fuel generating
technologies and on the updated EIA AEO 2015 for non-fossil generation
technologies. Recent estimates from Lazard 273 274 are also
provided for nuclear and biomass generation options.
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\273\ Lazard's Levelized Cost of Energy Analysis--Version 8.0;
September 2014; available at: http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in the rulemaking
docket.
\274\ Lazard is one of the world's preeminent financial advisory
and asset management firms. Lazard's Global Power, Energy &
Infrastructure Group serves private and public sector clients with
advisory services regarding M&A, financing, and other strategic
matters. The group is active in all areas of the traditional and
alternative energy industries, including regulated utilities,
independent power producers, advanced transportation technologies,
renewable energy technologies, meters, smart grid and energy
efficiency technologies, and infrastructure. http://www.marketwatch.com/story/lazard-releases-new-levelized-cost-of-energy-analysis-2014-09-18.
\275\ LCOE cost estimates for SCPC and IGCC cases come from
``Cost and Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'' DOE/NETL-2015/1720 (June 22, 2015). Cost and performance
for low rank SCPC is adapted from ``Cost and Performance Baseline
for Fossil Energy Plants Volume 3 Executive Summary: Low Rank Coal
and Natural Gas to Electricity'', DOE/NETL-2010/1399 (September
2011). LCOE cost estimates for nuclear and biomass are derived from
``Levelized Cost and Levelized Avoided Cost of New Generation
Resources in the Annual Energy Outlook 2015'', June 2015,
www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf. LCOE cost
estimates for NGCC technology are EPA estimates based on a range of
potential natural gas prices.
\276\ Table 8 includes LCOE figures for biomass-fired
generation, a potential sources of dispatchable base load power that
is not fueled by natural gas. The EPA includes this information for
completeness, while noting that biomass-fired units in operation in
the U.S. are smaller scale and thus are not as robust analogues as
nuclear power. CO2 emissions are not provided for biomass
units because different biomass feedstocks have different net
CO2 emissions; therefore a single emission rate is not
appropriate to show in Table 8.
\277\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015) at p. 18.
Table 8--Predicted Cost and CO2 Emission Levels for a Range of Potential
New Generation Technologies \275\
------------------------------------------------------------------------
Emission lb CO2/
New generation technology MWh-g LCOE* $/MWh
------------------------------------------------------------------------
SCPC--no CCS (bit)................ 1,620 76-95
SCPC--no CCS (low rank)........... 1,740 75-94
SCPC + ~16% partial CCS (bit)..... 1,400 92-117
SCPC + ~23% partial CCS (low rank) 1,400 95-121
Nuclear (EIA)..................... 0 87-115
Nuclear (Lazard).................. 0 92-132
Biomass (EIA) \276\............... -- 94-113
Biomass (Lazard).................. -- 87-116
IGCC.............................. 1,430 94-120
NGCC.............................. 1,000 ** 52-86
------------------------------------------------------------------------
* The LCOE ranges presented in Table 8 include an uncertainty of -15%/
+30% on capital costs for SCPC and IGCC cases and an uncertainty of -
10%/+30% on capital costs for nuclear and biomass cases from EIA. This
reflects information provided by EIA. Nuclear staff experts expect
that nuclear plants currently under construction would not have
capital costs under estimates and that one could expect to see a 30%
``upside'' variation in capital cost. There is also insufficient
market data to get a good statistical range of potential capital cost
variation (i.e. only 2 plants under construction, neither complete).
The nuclear cost estimates from Lazard likewise reflect the range of
expected nuclear costs. LCOE estimates displayed in this table for
SCPC units with partial CCS as well as for IGCC units use a higher
financing cost rate in comparison to the SCPC unit without
capture.\277\
** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.
As shown in Table 8, we project that the LCOE for new fossil steam
capacity meeting the final 1,400 lb CO2/MWh-g standard to be
substantially similar to that for a new nuclear unit, the principal
other alternative to natural gas to provide new base load power. This
is the case for new units firing bituminous and subbituminous coals and
dried lignite. This is another demonstration that the costs of the
final standard are reasonable because nuclear and fossil steam
generation each would serve an analogous role in adding dispatchable
base load generation diversity--or at least non-NGCC alternatives--to a
power provider's portfolio; hence, they are reasonably viewed as
comparable alternatives.\278\
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\278\ LCOE comparisons of reasonably available compliance
alternatives--IGCC with natural gas co-firing, and SCPC with natural
gas co-firing--are found below in Table 9. As shown there, these
alternatives are either lower cost than SCPC with partial CCS, or of
comparable cost.
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As previously mentioned, the DOE/NETL assumed conventional
financing
[[Page 64563]]
for cases without CCS and assumed high-risk financing for cases with
some level of CCS. Specifically a high-risk financial structure
resulting in a capital charge factor (CCF) of 0.124 is used in the
study to evaluate the costs of all cases with CO2 capture
(non-capture case uses a conventional financial structure with a CCF of
0.116).\279\ As a comparison of how this affects the resulting DOE/NETL
costs, a new SCPC utilizing 16 percent partial CCS is projected to have
an LCOE of $99/MWh (including transportation and storage costs; does
not include the range for uncertainty). That projected LCOE includes
the ``high risk financial assumptions''. If the LCOE for that unit were
to be calculated using the ``conventional financing assumptions'', the
resulting LCOE would be $94/MWh.
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\279\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015) at p. 7.
---------------------------------------------------------------------------
This approach is in contrast to that taken by the EIA which applies
a 3-percentage-point cost of capital premium (the `climate uncertainty
adder') to non-capture coal plants to reflect the market reaction to
potential future GHG regulation.
Under current and anticipated market conditions, power providers
that are considering costs alone in choosing a fuel source for new
intermediate or base load generation will choose natural gas because of
its competitive current and projected price. However, as noted in
Section V.H.3, public IRPs indicate that utilities are considering and
selecting technologies that could provide or preserve fuel diversity
within generating fleets. For example, utilities have been willing to
pay a premium for nuclear power in certain circumstances, as indicated
by the recent new constructions of nuclear facilities and by IRPs that
include new nuclear generation in their plans. In general, fossil steam
and nuclear generation each can provide dispatchable, base load power
while also maintaining or increasing fuel diversity.\280\ Utilities may
be willing to pay a premium for these generation sources because they
could serve as a hedge against the possibility that future natural gas
prices will far exceed projected levels. Accordingly, the LCOE analysis
demonstrates that the final standard's costs are in line with power
sources that provide analogous services--dispatchable base load power
and fuel diversity.
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\280\ As another example, San Antonio customers will benefit
from low-carbon power from the Texas Clean Energy Project. CPS
Energy CEO Doyle Deneby said in a news release: ``Adding clean coal
to our portfolio dovetails with our strategy to diversify and reduce
the carbon intensity of the power we supply to our customers.''
www.bizjournals.com/sanantonio/news/2014/10/06/cps-energy-strikes-new-deal-to-buy-power-from.html.
---------------------------------------------------------------------------
We further note a number of conservative elements of the costs we
used in making this comparison. In particular, these estimates include
the highest value in the projected range of potential costs for partial
CCS. They do not reflect revenues which can be generated by selling
captured CO2 for enhanced oil recovery, and reflect the
costs of partial CCS rather than potentially less expensive alternative
compliance paths such as a utility boiler co-firing with natural gas.
See also V.H.7 and 8 below.
6. Overall Costs and Economic Impacts
As noted above, an assessment of national costs is also an
appropriate means of evaluating the reasonableness of costs under CAA
section 111. See Sierra Club, 657 F.2d at 330.
The EPA considered the regulation's overall costs and economic
impacts as part of its RIA. The RIA demonstrates that these costs would
be negligible and that the effects on electricity rates and other
market indicators would similarly be minimal.
These results are driven by the existing market context for fossil-
steam generation. Even in the absence of the standards of performance
for newly constructed EGUs, substantial new construction of
uncontrolled fossil steam units is not anticipated under existing
prevailing and anticipated future economic conditions. Modeling
projections from government, industry, and academia anticipate that few
new fossil steam EGUs will be constructed over the coming decade and
that those that are built would have CCS.\281\ Instead, EIA data shows
that natural gas is likely to be the most widely-used fossil fuel for
new construction of electric generating capacity in the near
future.\282\ Of the coal-fired units moving forward at various advanced
stages of construction and development--Southern Company's Kemper
County Energy Facility and Summit Power's Texas Clean Energy Project
(TCEP)--each will deploy IGCC with some level of CCS. 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.
---------------------------------------------------------------------------
\281\ RIA chapter 4. For example, even in the EIA's sensitivity
analysis that assumes higher natural gas prices and electricity
demand, the 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. AEO 2015.
\282\ Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and
2015.
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In its RIA, the EPA considered the overall costs of this regulation
in the context of these prevailing market trends. Because of the
expectation of no new fossil steam generation, the RIA projects that
this final rule will result in negligible costs overall on owners and
operators of newly constructed EGUs by 2022.\283\ More broadly, this
regulation is not expected to have significant effects on fuel markets,
electricity prices, or the economy as a whole, as described in detail
in Chapter 4 of the RIA.
---------------------------------------------------------------------------
\283\ Conditions in the analysis year of 2022 are represented by
a model year of 2020.
---------------------------------------------------------------------------
In comparison, courts have upheld past regulations that imposed
substantial overall costs in order to protect against uncontrolled
emissions. As noted above, in Sierra Club v. Costle, the D.C. Circuit
upheld a standard of performance that imposed costly controls on
SO2 emissions from new coal-fired power plants. 657 F.2d at
410. These standards had implications for the economy ``at the local
and national levels,'' as ``EPA estimates that utilities will have to
spend tens of billions of dollars by 1995 on pollution control under
the new NSPS.'' Id. at 314. Further, the court acknowledged that
``[c]onsumers 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,'' before concluding that
the costs were reasonable. Id.
The projected total incremental capital costs associated with the
standard we are finalizing in this rule are dramatically lower than was
the case for this prior standard, as well as other prior standards
summarized previously. For example, when the standard at issue in
Sierra Club was upheld, the industry was expected to build, and did
build, dozens of plants ultimately meeting the standards--at a
projected incremental cost of tens of billions of dollars.\284\ Here,
by contrast, few if any fossil steam EGUs are projected to be built in
the foreseeable future, indicating that the total incremental costs are
likely to be considerably more modest.
---------------------------------------------------------------------------
\284\ Sierra Club, 657 F.2d at 314.
---------------------------------------------------------------------------
Commenters stated that the cost provision in CAA section 111(a)(1)
does not authorize the EPA to consider the nationwide costs of a system
of emission reduction in lieu of considering the cost impacts for
individual new plants. In this rule, we
[[Page 64564]]
are considering both sets of costs and, in fact, we are not identifying
full CCS as the BSER primarily for reasons of its cost to individual
sources. At the same time, total projected costs are relevant in
assessing the overall reasonableness of costs associated with a
standard. Our analysis demonstrates that the impacts on the industry as
a whole are negligible, and are certainly not greater than ``what the
industry could bear and survive.'' \285\ These facts support the EPA's
overall conclusion that the costs of the standard are reasonable.
---------------------------------------------------------------------------
\285\ Portland Cement Ass'n, 513 F.2d at 508.
---------------------------------------------------------------------------
However, as noted earlier, for a variety of reasons, some companies
may consider coal-fired steam generating units that the modeling does
not anticipate. Thus, in Chapter 5 of the RIA, we also present an
analysis of the project-level costs of a newly constructed coal-fired
steam generating unit with partial CCS that meets the requirements of
this final rule alongside the project-level costs of a newly
constructed coal-fired unit without CCS. This analysis in RIA chapter 5
indicates that the quantified benefits of the standards of performance
would exceed their costs under a range of assumptions.
As required under Executive Order 12866, the EPA conducts benefit-
cost analyses for major Clean Air Act rules, and has done so here.
While such analysis can help to inform policy decisions, as permissible
and appropriate under governing statutory provisions, the EPA does not
use a benefit-cost test (i.e., a determination of whether monetized
benefits exceed costs) as the sole or primary decision tool when
required to consider costs or to determine whether to issue regulations
under the Clean Air Act, and is not doing so here.\286\ Nonetheless, as
just noted, the RIA analysis shows that the standard of performance has
net quantified benefits under a range of assumptions.
---------------------------------------------------------------------------
\286\ See Memorandum ``Consideration of Costs and Benefits under
the Clean Air Act'' available in the rulemaking dockets, EPA-HQ-OAR-
2013-0495 (new sources) and EPA-OAR-HQ-2013-0603 (modified and
reconstructed sources).
---------------------------------------------------------------------------
7. Opportunities to Further Reduce Compliance Costs
While the EPA believes, as detailed above, that there is sufficient
evidence to show that the final standards of performance for new steam
generating units can be met at a reasonable cost, we also note that
there are potential opportunities to further reduce compliance costs.
We believe that, in most cases, the actual costs will be less than
those presented earlier.
As explained in more detail in the following subsection, a new
utility boiler can meet the final standard of performance by co-firing
with natural gas. Some project developers may choose to utilize natural
gas co-firing as a means of delaying, rather than avoiding,
implementation of partial CCS. Developers can also choose to install
IGCC with a small amount of natural gas co-firing at costs within the
range of SCPC with partial CCS, although slightly higher.
The EPA also notes that new units that capture CO2 will
likely be built in areas where there are opportunities to sell the
captured CO2 for some useful purpose prior to (or
concomitant with) permanent storage. The DOE refers to this as ``carbon
capture, utilization and storage'' or CCUS. In particular, the ability
to sell captured CO2 for use in enhanced oil recovery
operations offers the most opportunity to reduce costs. In this regard,
the newly-operating Boundary Dam facility is selling captured
CO2 for EOR. The Kemper facility likewise plans to do
so.\287\
---------------------------------------------------------------------------
\287\ The EPA is referring to the Kemper facility here as an
example of how costs can be defrayed, not for use of technology or
level of emission reduction achieved. The EPA therefore does not
believe that the EPAct05 prevents reference to the fact that Kemper
plans to sell captured carbon.
---------------------------------------------------------------------------
In some instances, the costs of CCS may be defrayed by grants or
other benefits provided by federal or state governments. 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. As stated earlier, the EPA considers
the costs of partial CCS at a level to meet the final standard of
performance to be reasonable even without considering these
opportunities to further reduce implementation and compliance costs. We
did not in the proposal--and we do not here in this final action--rely
on any cost reduction opportunities to justify the costs of meeting the
standard as reasonable, but again note the conservative assumptions
embodied in our assessment of compliance costs.
a. Cost and Feasibility of Natural Gas Co-firing as an Alternative
Compliance Pathway
Although the EPA has determined that implementation of partial CCS
at an emission limitation of 1,400 lb CO2/MWh-g is the BSER
for newly constructed fossil fuel-fired steam generating EGUs, we also
note that operators can consider the use of natural gas co-firing to
achieve the final emission limitation, likely at a lower cost.
At the final emissions limitation of 1,400 lb CO2/MWh-g
a new supercritical PC or supercritical CFB can meet the standard by
co-firing with natural gas at levels up to approximately 40 percent
(heat input basis) and could potentially avoid (or delay) installation
and use of partial CCS altogether.
Natural gas co-firing has long been recognized as an option for
coal-fired boilers to reduce emissions of criteria and hazardous air
pollutants. EPRI sponsored a study to assess both technical and
economic issues associated with natural gas co-firing in coal-fired
boilers.\288\ They determined that the largest number of applications
and the longest experience time is with natural gas reburning and with
supplemental gas firing. Natural gas reburning has been used primarily
as a NOX control technology. It is implemented by
introducing natural gas (up to 20 percent total fuel heat input) in a
secondary combustion zone (called the ``reburn zone'') downstream of
the primary combustion zone in the boiler. Injecting the natural gas
creates a fuel-rich zone where NOX formed in the main
combustion zone is reduced to nitrogen and water vapor.
---------------------------------------------------------------------------
\288\ Gas Cofiring Assessment for Coal Fired Utility Boilers;
Final Report, August 2000; EPRI Technical Report available at
www.epri.com.
---------------------------------------------------------------------------
Higher levels of natural gas co-firing can be met by utilizing
supplemental gas co-firing (either alone or along with natural gas
reburning). This involves the simultaneous firing of natural gas and
pulverized coal in a boiler's primary combustion zone. Others have also
evaluated configurations that would allow coal-fired units to utilize
natural gas.289 290
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\289\ Many of the studies evaluated opportunities to use natural
gas reburn, natural gas co-firing and other configurations in
existing coal-fired boilers. Those conclusions would also be
applicable for new coal-fired boilers.
\290\ ``Dual Fuel Firing--The New Future for the Aging U.S.
Based Coal-Fired Boilers'', presented by Riley Power, Inc. at 37th
International Technical Conference on Clean Coal and Fuel Systems
June 2012 Clearwater, FL, available at http://www.babcockpower.com/pdf/RPI-TP-0228.pdf.
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[[Page 64565]]
A 2013 article entitled ``Utility Options for Leveraging Natural
Gas'' \291\ noted that:
---------------------------------------------------------------------------
\291\ Utility Options for Leveraging Natural Gas, 10/01/2013
article in Power. Available at http://www.powermag.com/utility-options-for-leveraging-natural-gas/.
Utility owners of coal-fired power stations that wish to balance
their exposure to coal-fired generation with additional natural gas-
fired generation have several options to consider. The four most
practical options are co-firing coal and gas in the same boiler,
converting the coal-fired boiler to gas-only operation, repowering
the coal plant with natural gas-fired combustion turbines, or
replacing the coal plant with a combined cycle plant. [. . .] Co-
---------------------------------------------------------------------------
firing is the lowest-risk option for substituting gas use for coal.
The EPA examined compliance costs for a new steam generating unit
to meet the final standard of performance using natural gas co-firing
and compared those costs to the estimated costs of meeting the final
standards using partial CCS. Those costs are provided below in Table 9.
---------------------------------------------------------------------------
\292\ Costs and emissions for cases that do not utilize natural
gas co-firing are from ``Cost and Performance Baseline for Fossil
Energy Plants Supplement: Sensitivity to CO2 Capture Rate
in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June 2015). Costs
and emissions for natural gas co-fired cases are EPA estimates.
Table 9--Predicted Costs to Meet the Final Standard Using Natural Gas Co-
firing \292\
------------------------------------------------------------------------
Emission lb LCOE $/
New generation technology CO2/MWh-g MWh
------------------------------------------------------------------------
SCPC--no CCS................................. 1,620 82
SCPC + ~16% partial CCS...................... 1,400 99
SCPC + ~34% NG co-fire....................... 1,400 92
IGCC--no CCS................................. 1,434 103
IGCC + ~6% NG co-fire........................ 1,400 105
NGCC*........................................ 1,000 60
------------------------------------------------------------------------
* The generation cost using NG co-fire and NGCC assume a natural gas
price of $6.19/mmBtu.
The EPA thus again notes that the cost assumptions it is making in
its BSER determination are conservative. That is, by costing partial
CCS as BSER, the EPA may be overestimating actual compliance costs
since there exist other less expensive means of meeting the promulgated
standard.\293\
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\293\ Certain commenters argued that the proposed standard
essentially mandated a sole method of compliance, and hence
constituted a work practice for purposes of section 111(h) of the
Act. These commenters argued further that the EPA had failed to
justify the proposal under the section 111(h) criteria. The EPA
disagrees with the premise of these comments, but, in any case,
there are clearly multiple compliance paths available for achieving
the final standard.
---------------------------------------------------------------------------
Notwithstanding that costs for a SCPC to meet the standard would be
lower if it co-fired with natural gas, we have not identified that
compliance alternative as BSER because we believe that new coal-fired
steam electric generating capacity would be built to provide fuel
diversity, and burning substantial amounts of natural gas would be
contrary to that objective. In addition, this choice would not promote
use of advanced pollution control technology. New IGCC has costs which
are comparable to SCPC, as does IGCC with natural gas co-firing,\294\
but we are choosing not to identify it as BSER for reasons stated at
Sections V.C.2 and V.P: use of IGCC does not advance emission control
beyond current levels of performance for sources which may choose to
utilize IGCC technology. Nonetheless, use of IGCC remains a viable,
demonstrated compliance option to meet the 1,400 lb CO2/MWh-
g standard of performance, and is available at reasonable cost and (as
shown at Section V.P below) without significant adverse non-air quality
impacts or energy implications.
---------------------------------------------------------------------------
\294\ IGCC units already have combined cycle capacity, and so
can be readily operated in whole or in part using natural gas as a
fuel. Indeed, both the Edwardsport and Kemper IGCC facilities have
operated at times by firing exclusively natural gas.
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Costs are Reasonably Expected To Decrease Over Time
The EPA reasonably expects that the costs of CCS will decrease over
time as the technology becomes more widely deployed. Although, for the
reasons that have been noted, 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.
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 the new coal-fired generation
facilities that are either operating or are nearing completion. These
would include the Boundary Dam Unit #3 facility, the Petra Nova WA
Parish project, and the Kemper County IGCC facility. The operators of
the Boundary Dam Unit #3 are considering construction of additional CCS
units and have projected that the next units could be constructed at a
cost of at least 30 percent less than that at Unit #3.\295\ These
savings primarily come from application of lessons learned from the
Unit #3 design and construction.
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\295\ ``Boundary Dam--The Future is Here'', plenary presentation
by Mike Monea at the 12th International Conference on Greenhouse Gas
Technologies (GHGT-12), Austin, TX (October 2014).
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To facilitate the transfer of the technology and to accelerate
development of carbon capture technology, SaskPower has created the CCS
Global Consortium.\296\ This consortium provides SaskPower the
opportunity to share the knowledge and experience from the Boundary Dam
Unit #3 facility with global energy leaders, technology developers, and
project developers. SaskPower, in partnership with Mitsubishi and
Hitachi, is also helping to advance CCS knowledge and technology
development through the creation of the Shand Carbon Capture Test
Facility (CCTF).\297\ The test facility will provide technology
developers with an opportunity to test new and emerging carbon capture
systems for controlling carbon emissions from coal-fired power plants.
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\296\ http://www.saskpowerccs.com/consortium/.
\297\ www.saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
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The DOE also sponsors testing at the National Carbon Capture Center
(NCCC). The NCCC--located at Southern Company's Plant Gaston in
Wilsonville, AL--provides first-class facilities to test new capture
technologies for extended periods under commercially representative
conditions with coal-derived flue gas and syngas.\298\
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\298\ www.nationalcarboncapturecenter.com/index.html.
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[[Page 64566]]
We expect continued additional cost reductions to come from
knowledge gained from continued operation of non-power sector
industrial projects which, as we have discussed, are informative in
transferring the technology to power sector applications. We expect the
on-going research and development efforts--such as those sponsored by
the DOE/NETL.
Significant reductions in the cost of CO2 capture would
be consistent with overall experience with the cost of pollution
control technology. 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.
c. Opportunities To Reduce Cost Through Sales of Captured
CO2
Geologic storage options include use of CO2 in EOR
operations, which is the injection of fluids into a reservoir after
production yields have decreased from primary production in order to
increase oil production efficiency. CO2-EOR has been
successfully used for decades at many production fields throughout the
U.S. to increase oil recovery. 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.\299\ See also Section V.M.3
below.
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\299\ Tracking Clean Energy Progress 2013, International Energy
Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 2013.
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I. Key Comments Regarding the EPA's Consideration of Costs
In its consideration of the costs associated with the final
standard, the EPA considered a range of different cost metrics, each
with its individual strengths and weaknesses. As discussed above, each
metric supports the EPA's conclusion that the costs of the final
standard are reasonable.
In this section, we review the comments received on assessing cost
reasonableness and specific cost metrics. We explain how these comments
informed our consideration of different metrics and cost reasonableness
in general.
1. Use of LCOE as a Cost Metric
As noted, CAA section 111(a) directs the EPA to consider ``cost''
in determining if the BSER is adequately demonstrated. It does not
provide further guidance as to how costs are to be considered, thus
affording the EPA considerable discretion to choose a reasonable means
of cost consideration. See, e.g. Lignite Energy Council v. EPA, 198 F.
3d at 933. Certain commenters nonetheless argued that LCOE was an
impermissible metric because it does not measure the cost of achieving
the emission reduction, but rather measures the impact on the product
produced by the entity subject to the standard.\300\ The EPA does not
agree that its authority is so limited. Indeed, in the first decided
case under section 111, the D.C. Circuit, in holding that the EPA's
consideration of costs was reasonable, specifically noted the EPA's
examination of the impact of the standards on the regulated source
category's product in comparison to competitive products. Portland
Cement Ass'n v. EPA, 486 F. 2d at 388 (``costs of control equipment
could be passed on without substantially affecting competition with
construction substitutes such as steel, asphalt, and aluminum'').
---------------------------------------------------------------------------
\300\ Comments of EEI, pp 94-5 (Docket entry: EPA-HQ-OAR-2013-
0495-9780).
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Commenters also argued that the choice of LCOE as a cost metric
masked consideration of the considerable capital costs associated with
CCS. The EPA disagrees with this contention. The LCOE does not mask
consideration of capital costs. Rather, as explained at V.H.5 above,
LCOE is a summary metric that expresses the full cost (e.g., capital,
O&M, fuel) of generating electricity and therefore provides a useful
summary metric of costs per unit of production (i.e., megawatt-hours).
Provided that those megawatt-hours provide similar electricity services
and align on dimensions other than just cost, then the LCOE provides a
useful comparison of which technologies are least cost.
The EPA certainly does not minimize that project developers must
take capital costs into consideration, and as discussed in Section
V.H.4 above, the EPA accordingly has considered direct capital costs
here as part of its assessment and found those costs to be reasonable.
In addition, the EPA notes that its comparison of the marginal impacts
from an individual illustrative facility's compliance with the
standard, discussed in detail above and in the RIA Chapter 5, took into
account the marginal capital costs that would be incurred by an
individual facility.
According to EIA,\301\ capital costs represent approximately 63
percent of the LCOE for a new coal-fired SCPC plant; approximately 66
percent of the LCOE for a new IGCC plant; approximately 74 percent of
the LCOE for a new nuclear plant; and only about 22 percent of the LCOE
for a new NGCC unit. The LCOE of a new NGCC unit is much more strongly
affected by fuel costs (natural gas). As we have discussed in detail in
this preamble, in the preamble for the January 2014 proposal, and in
associated technical support documents, the power sector has moved
toward increased use of natural gas for a variety of reasons. If
capital was the only cost that utilities and project developers
considered, then they would almost certainly always choose to build a
new NGCC unit. However, a variety of factors can be involved in
selecting a generation source beyond capital costs. Accordingly, in
considering cost reasonableness the EPA considered metrics that
encompassed other costs as well as the value of fuel and fleet
diversity.
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\301\ http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
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Some commenters maintained that even if LCOE was a proper cost
metric, the comparison with the costs of a new nuclear power plant is
improper because nuclear itself is a highly expensive technology. The
EPA disagrees. The comparison is appropriate and valid because, as
discussed at V.H.3 above, under current and foreseeable economic
conditions affecting the cost of new fossil steam generation and new
nuclear generation relative to the cost of new natural gas generation,
neither new nuclear power nor fossil steam generation are competitive
with new natural gas if evaluated on the basis of LCOE alone.
Nonetheless, both are important potential alternatives to natural gas
power for those interested in dispatchable base load power that
maintains or increases fuel diversity. As shown in a survey of recent
IRP filings in the docket \302\ and Section II.C.5 above, several
utilities are considering new nuclear power as a potential generation
option. Because both fossil steam and nuclear generation serve a
comparable role of offering a diverse source of base load power
generation, the EPA concludes that the comparison of their LCOE is a
valid approach to evaluating cost reasonableness.
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\302\ Technical Support Document--``Review of Electric Utility
Integrated Resource Plans'' (May 2015), available in the rulemaking
docket EPA-HQ-OAR-2013-0495.
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[[Page 64567]]
2. Use of Cost Estimates From DOE/NETL and DOE/EIA
In the January 2014 proposal, the EPA relied mostly on the cost
projections for new fossil fuel-fired generating sources that were
informed by cost studies conducted by DOE/NETL. The EPA relied on the
EIA's AEO 2013 projections for non-fossil based generating sources
(i.e., nuclear, renewables, etc.). For this final rule, the EPA
continues to rely most heavily on DOE/NETL cost projections for fossil
fuel generating technologies and on the updated DOE/EIA AEO 2014 for
nuclear and other base load non-fossil generation technologies.
a. DOE/NETL Cost and Performance Studies
The DOE/NETL ``Cost and Performance Baselines for Fossil Energy
Plants'' are a series of studies conducted by NETL to establish
estimates for the cost and performance of combustion and gasification
based power plants with and without CO2 capture and
storage.\303\ The studies evaluate numerous technology configurations
utilizing different coal ranks and natural gas.
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\303\ http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
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The EPA relied on those sources because the NETL studies are the
most comprehensive and transparent of the available cost studies and
NETL has a reputation in the power sector industry for producing high
quality, reliable work.\304\ The NETL studies were extensively peer
reviewed.\305\ The EPA Science Advisory Board Work Group considering
the adequacy of the peer review noted the EPA staff's statement that
``the NETL studies were all peer reviewed under DOE peer review
protocols'', further noted the EPA staff's statement that ``the
different levels of review of these DOE documents met the requirements
to support the analyses as defined by the EPA Peer Review Handbook,''
and concluded that ``peer review on the DOE documents'' was conducted
``at a level required by agency guidance.'' \306\
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\304\ The NETL costs and studies are often cited in academic and
other publications.
\305\ The initial NETL study ``Cost and Performance Baseline for
Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to
Electricity'' (2006) was subject to peer review by industry experts,
academia, and government research and regulatory agencies.
Subsequent iterations of the study were not further peer reviewed
because the modeling procedures used in the cost estimation were not
revised.
\306\ Letter from James Mihelcic, Chair, SAB Work Group on EPA
Planned Actions for SAB Consideration of the Underlying Science to
Members of the Chartered SAB and SAB Liaisons (page 3, Jan. 24,
2014). http://yosemite.epa.gov/sab/sabproduct.nsf/
F43D89070E89893485257C5A007AF573/$File/
SAB+work+grp+memo+w+attach+20140107.pdf. The SAB's statement that
these guidance documents ``require'' any specific peer review is an
overstatement, since guidance documents, by definition, do not
mandate any specific course of action.
---------------------------------------------------------------------------
The cost estimates were indicated by DOE/NETL to carry an accuracy
of -15 percent to +30 percent on the capital costs, consistent with a
AACE Class 4 cost estimate--i.e., a ``feasibility study'' level of
design engineering.\307\ The DOE/NETL further notes that ``The value of
the study 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.'' \308\
---------------------------------------------------------------------------
\307\ Recommended Practice 18R-97 of the Association for the
Advancement of Cost Engineering International (AACE) describes a
Cost Estimate Classification System as applied in Engineering,
Procurement and Construction for the process industries.
\308\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity'' Rev 2a
(Sept 2013); DOE/NETL-2010/1397, page 9.
---------------------------------------------------------------------------
For the final standard, the EPA made particular use of the most
recent NETL cost estimates for post-combustion CCS, which reflect up-
to-date vendor quotes and incorporate the post-combustion capture
technology--the Shell Cansolv amine-based process--that is being
utilized at the Boundary Dam Unit #3 facility.\309\ The EPA used this
latest version of the NETL studies not only to assure that it considers
the most up-to-date information but also to address public comments
criticizing the proposal for relying on out-of-date cost information.
---------------------------------------------------------------------------
\309\ Cost and Performance Baseline for Fossil Energy Plants
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity,
Revision 3, July 6, 2015, DOE/NETL-2015/1723.
---------------------------------------------------------------------------
b. Other Studies That Corroborate NETL Cost Estimates
A variety of government, industry and academic groups routinely
conduct studies to estimate costs of new generating technologies. These
studies use techno-economic models to predict the cost to build a new
generating facility at some point in the future. These studies often
use levelized cost of electricity (LCOE) to summarize costs and to
compare the competiveness of the different generating technologies.
A variety of groups have recently published LCOE estimates for new
dispatchable generating technologies. Those are shown below in Table
10. The table shows LCOE projections from the EPA's January 2014
proposal, from studies conducted by the Electric Power Research
Institute (EPRI),\310\ by the DOE's Energy Information Administration
(EIA) in their 2015 Annual Energy Outlook (AEO 2015), by the DOE's
National Energy Technology Laboratory (NETL), and by researchers from
the Department of Engineering and Public Policy at the Carnegie Mellon
University (CMU) in Pittsburgh, PA.
---------------------------------------------------------------------------
\310\ EPRI is a non-profit organization, headquartered in Palo
Alto, CA, that conducts research on issues related to the U.S.
electric power industry (www.epri.com).
---------------------------------------------------------------------------
The Global CCS Institute \311\ has recently published a report that
examines costs of major low and zero emissions technologies currently
available for power generation and compares the predicted LCOEs of
those technologies. Importantly, the analysis presented in the report
uses cost and performance data from several recent studies, and applies
a common methodology and economic parameters to derive comparable
lifetime costs. Analysis and findings in the paper reflect costs
specific to the U.S.
---------------------------------------------------------------------------
\311\ www.globalccsinstitute.com.
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The fact that these various groups have conducted independent
studies and that the results of those independent studies are
reasonably consistent with the estimates of DOE/NETL are further
indications that the DOE/NETL cost estimates are reasonable.
[[Page 64568]]
Table 10--Selection of Levelized Cost of Electricity (LCOE) Projections
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lazard \312\ EPRI \313\ AEO2015 \314\ DOE/NETL \315\ CMU \316\ GCCSI \317\**
New generation technology $2014/MWh $2011/MWh $2013/MWh* $2011/MWh* $2010/MWh $2014/MWh
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCPC--no CCS............................................ 66 62-77 95 76-95 59 78
SCPC--full CCS.......................................... 151 102-137 -- 140-176 -- 115-160
SCPC--16% CCS........................................... -- -- -- 92-117 -- --
Nuclear***.............................................. 92-132 85-97 87-115 -- -- 86-102
Biomass................................................. 87-116 90-155 94-113 -- -- 123-137
IGCC.................................................... 102 82-96 116 94-120 -- --
IGCC--full CCS.......................................... 171 105-136 144 142-178 -- --
NGCC.................................................... 61--87 33--65 73 58 63 60
--------------------------------------------------------------------------------------------------------------------------------------------------------
* EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertainty adder (CUA), which is a 3-percentage point increase in the cost
of capital. In contrast, DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk financial assumptions for cases that
include CCS.
** The Global CCS Institute provided range for coal with full CCS (shown as ``CCS(coal)'' in Figure 5.2 of the referenced report) reflects a combination
of costs for both PC and IGCC coal plants.
*** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider range of technology options.
The LCOE values from the Lazard, EPRI, and NETL studies are
presented as a range. The EPRI costs incorporate uncertainty reflecting
the range of inputs (i.e., capital costs, fuel costs, fixed and
variable O&M, etc.). The NETL costs are indicated to carry an accuracy
of -15 percent to + 30 percent, consistent with a ``feasibility study''
level of design. The range in Table 10 is the NETL projected costs with
the -15 percent to +30 percent uncertainty on the capital costs.
Overall, as can be seen from the results in Table 10, the range of LCOE
estimates from the different groups are in reasonable agreement with
the DOE/NETL estimates most often representing the most conservative of
the estimates shown.
---------------------------------------------------------------------------
\312\ Lazard's Levelized Cost of Energy Analysis--Version 8.0
(Sept 2014); available at http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in the rulemaking
docket.
\313\ ``Program on Technology Innovation: Integrated Generation
Technology Options 2012; Report 1026656; Available at: www.epri.com.
\314\ ``Levelized Cost and Levelized Avoided Cost of New
Generation Resources in the Annual Energy Outlook 2015'', Available
at: www.eia.gov/forecasts/aeo/electricity_generation.cfm; the LCOE
values displayed incorporate -10%/+30% for uncertainty for biomass
and nuclear.
\315\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'' DOE/NETL-2015/1720 (June 22, 2015).
\316\ CMU is Carnegie Mellon University; Zhai, H., Rubin, E.;
``Comparative Performance and Cost Assessments of Coal- and Natural
Gas-Fired Power Plants under a CO2 Emission Performance
Standard Regulation'', Energy & Fuels, 2013, 27, 4290, Table 1.
\317\ ``The Costs of CCS and other Low-Carbon Technologies--2015
update'' July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccs-other-low-carbon-technologies-2015-update.pdf.
---------------------------------------------------------------------------
The EIA cost estimates include 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 inconsistencies between power sector modeling absent GHG
regulation and the widespread use of a cost of CO2 emissions
in power sector resource planning. 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 pertinent when evaluating the cost competitiveness of
alternative generating technologies. The 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.
c. Industry Information That Corroborates NETL Cost Estimates
Information from vendors of CCS technology also supports the
reliability of the cost estimates the EPA is using here.\318\
Specifically, the EPA had conversations with representatives from
Summit Carbon Capture, LLC regarding available cost information. Cost
estimates provided by another leading provider of CCS technology
likewise are consistent (indeed, somewhat less than) the estimates the
EPA is using for purposes of cost analysis in the rule.
---------------------------------------------------------------------------
\318\ See Section V.F above, explaining that the D.C. Circuit
has repeatedly stated that vendor statements are probative in
demonstrating that a technology is adequately demonstrated under
section 111.
---------------------------------------------------------------------------
Summit Carbon Capture's primary business is large-scale carbon
capture from power and other industrial projects and use of the
captured CO2 for EOR.\319\ Summit is actively working with
several different technology companies offering CO2 capture
systems, including the leading equipment manufacturers for fossil fuel
power production equipment. Their current projects include the 400 MW
IGCC Texas Clean Energy Project and the Caledonia Clean Energy
Project--a new project underway in the United Kingdom--and a variety of
other projects under development which are not yet public.
---------------------------------------------------------------------------
\319\ http://www.summitpower.com/projects/carbon-capture/.
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Summit is also interested in potentially retrofitting CCS onto
existing coal-fired plants for the purpose of capturing CO2
for sale to EOR markets. Summit provided the EPA with copies of slides
from a presentation that it has used in different public forums.\320\
The presentation focused on costs to retrofit available carbon capture
equipment at an existing PC power plant that is ideally located to take
advantage of opportunities to sell captured CO2 for use in
EOR operations. Summit received proprietary costing information from
numerous technology providers and that information, along with other
publically available information, was used to develop their cost
predictions.\321\ Though the primary focus of their effort was to
examine costs associated with retrofitting CCS to an existing coal
fired power plant, Summit Power also calculated costs for several new
generation scenarios--including the cost of a new NGCC, a new SCPC, a
new SCPC with full CCS, and a new SCPC with partial CCS at 50 percent.
The costs are reasonably consistent with costs predicted by NETL, EIA,
EPRI and others. The company ultimately concluded that ``in a world of
uncertain gas prices, falling CO2 capture
[[Page 64569]]
equipment prices, improving CCS process efficiency, and possible
compliance costs . . . existing coal plants retrofitted with available
CCS equipment can be cost competitive with development of new NGCC
generation.'' \322\
---------------------------------------------------------------------------
\320\ ``Coal's Role in a Low Carbon Energy Environment'',
presented at 2015 Euromoney Power & Renewables Conference, remarks
by Jeffrey Brown (amended to address EPA questions on the original).
Available in the rulemaking docket.
\321\ No proprietary or business confidential information was
shared with the EPA. No specific vendors were mentioned by name
during discussions with Summit Power. Summit also used available
DOE/NETL and EIA cost information.
\322\ Others have come to similar conclusions--that retrofit of
CCS technology at existing coal-fired power plants can be feasible--
e.g., ``The results indicate that for about 60 gigawatts of the
existing coal-fired capacity, the implementation of partial
CO2 capture appears feasible, though its cost is highly
dependent on the unit characteristics and fuel prices.'' (Zhai, H.;
Ou, Y.; Rubin, E.S.; ``Opportunities for Decarbonizing Existing U.S.
Coal-fired Plants via CO2 Capture, Utilization, and
Storage'', accepted for publication in Env. Sci & Tech. (2015).
---------------------------------------------------------------------------
In June 2012, Alstom Power released a report entitled ``Cost
assessment of fossil power plants equipped with CCS under typical
scenarios''.\323\ The study examined costs for a new coal-fired power
plant implementing post-combustion CCS (full CCS) in Europe, in North
America, and in Asia. The results for the North American case--along
with similar cost estimates from Summit--are shown in Table 11 below.
The DOE/NETL estimated costs are also included for comparison. The
results show predicted costs for a new SCPC ranging from $53/MWh to
$82/MWh and costs to implement full CCS ranging from $97/MWh to $143/
MWh. Costs to implement varying levels of partial CCS are also provided
for comparison. The industry cost estimates are on the lower end of the
range of costs predicted from other techno-economic studies (see Table
11 below) and, like those economic studies, are affected by the
specific assumptions. As with the techo-economic studies presented
earlier in Table 10, there is relatively good agreement among these
projected costs and the DOE/NETL costs. There is relatively good
agreement in the incremental levelized cost to implement full CCS on
the new SCPC units (ranging from 74 to 85 percent) and to implement 50
percent CCS on the new SCPC unit (from 41 to 45 percent increase).
These industry estimates are also lower than the DOE/NETL estimates for
both full and 50 percent partial CCS (with the incremental cost
percentage for full CCS being almost identical), providing further
support for the reasonableness of the EPA using the NETL cost estimates
here.
---------------------------------------------------------------------------
\323\ Leandri, J., Skea, A., Bohtz, C., Heinz, G.; ``Cost
assessment of fossil power plants equipped with CCS under typical
scenarios'', Alstom Power, June 2012. Available in the rulemaking
docket: EPA-HQ-OAR-2013-0495.
\324\ Note that in other tables in this preamble, the EPA has
presented LCOE values from the DOE/NETL work as a range in order to
incorporate the uncertainty on the capital costs. The range is not
present here for easy comparison with the industry costs which were
not provided as a range. The full range of DOE/NETL costs for each
of the cases presented can be found in Exhibit A-3 in ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (June 2015), p. 18.
Table 11--Industry LCOE Estimates for Implementation of Post-Combustion CCS \324\
----------------------------------------------------------------------------------------------------------------
DOE/NETL $/
Summit $/MWh Alstom $/MWh* MWh
----------------------------------------------------------------------------------------------------------------
SCPC............................................................ 64.5 52.6 82.3
SCPC + full CCS................................................. 117.6 97.4 152.4
Full CCS incremental cost, %.................................... 82.3% 85.0% 85.2%
SCPC + 50% CCS.................................................. 91.1 -- 123.6
50% CCS incremental cost, %..................................... 41.2% -- 50.1%
SCPC + 35% CCS.................................................. -- -- 114.7
SCPC + 16% CCS.................................................. -- -- 100.5
NGCC**.......................................................... 47.7 35.0 **52.0
----------------------------------------------------------------------------------------------------------------
* Costs are from Figure 2 in the referenced Alstom report (North American case); costs are presented as [euro]/
MWh in the report. The costs were converted to $/MWh assuming a conversion rate of 1 USD = 0.76 [euro] (in
2012).
** NGCC cost is estimated by the EPA using NETL information. Assumed natural gas prices = Summit ($4/mmBtu);
Astom ($3.9/mmBtu); EPA ($5.00/mmBtu).
The EPA notes that in its public comments, Alstom maintained that
``no CCS projects that would [sic] be considered cost competitive in
today's energy economy.'' \325\ As explained above, no steam electric
EGU would be cost competitive even without CCS--and that is
substantiated in the projected costs presented above in Table 11 where
NGCC is consistently the most economic new generation option when
compared to the other listed technologies. Alstom does not explain (or
address) why the cost premium for partial CCS would be a decisive
deterrent for capacity that would otherwise be constructed. More
important, Alstom does not challenge the specific cost estimates used
by the EPA at proposal, nor disavow its own estimates of CCS costs
(which are even less) which it is publically disseminating in the
marketplace. See also Section V.F.3 above, quoting Alstom's press
release stating unequivocally that ``CCS works and is cost-effective''.
The EPA reasonably is relying on the specific Alstom estimates which it
is using for its own commercial purposes, and not on the generalized
concerns presented in its public comments.
---------------------------------------------------------------------------
\325\ Alstom Comment p. 3 (Docket entry: EPA-HQ-OAR-2013-0495-
9033). The comment also urged the EPA to evaluate costs without
considering EOR opportunities (which in fact is our methodology,
albeit a conservative one), and without considering possible
subsidies. Id. The LCOE and capital cost estimates above are direct
cost comparisons, again consistent with the commenter's position.
---------------------------------------------------------------------------
d. Use of Cost Information From EIA Annual Energy Outlook (AEO)
For the January 2014 proposal the EPA chose to rely on the EIA AEO
2013 cost projections for non-fossil based generation. The AEO presents
long-term annual projections of energy supply, demand, and prices
focused on U.S. energy markets. The predictions are based on results
from EIA's National Energy Modeling System (NEMS). The AEO costs are
updated annually, they are highly scrutinized, and they are widely used
by those involved in the energy sector.
In the January 2014 proposal, the EPA presented LCOE costs for new
non-fossil dispatchable generation (see 77 FR 1477, Table 7) from the
AEO 2013. Those costs were updated as part of the AEO 2015 release. The
estimated cost for all of these technologies decreased from AEO 2013 to
AEO 2014 and AEO 2015. This was due to changes in the interest rates
that resulted in lower financing costs relative to those used the AEO
2013.\326\ The EIA commissioned a comprehensive update of its capital
cost assumptions for all generation technologies in 2013. Fuel cost and
[[Page 64570]]
financial assumptions are updated for each edition of the Annual Energy
Outlook.
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\326\ www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf.
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e. Accounting for Uncertainty of Projected Costs
As previously mentioned, the projected costs are dependent upon a
range of assumptions including the projected capital costs, the cost of
financing the project, the fixed and variable O&M costs, the projected
fuel costs, and incorporation of any incentives such as tax credits or
favorable financing that may be available to the project developer.
There are also regional or geographic differences that affect the final
cost of a project. The LCOE projections in this final action are not
intended to provide an absolute cost for a new project using any of
these respective technologies. Large construction projects--as these
would be--would be subjected to detailed cost analyses that would take
into consideration site-specific information and specific design
details in order to determine the project costs.
The DOE/NETL noted that the cost estimates from their studies carry
an accuracy in the range of -15 percent to +30 percent, which is
consistent with a ``feasibility study'' level of design. They also
noted that the value of the 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.''
The EIA AEO 2015 presented LCOE costs as a single point estimate
representing average nationwide costs and separately as a range to
represent the regional variation in costs. In order to compare the
fossil fuel generation technologies from the NETL studies with the cost
projections for non-fossil dispatchable technologies from EIA AEO 2015,
we assume that the EIA studies would carry a similar level of
uncertainty (i.e., +30 percent) and we present the AEO 2015 projected
costs as the average nationwide LCOE with a range of -10 percent to +30
percent to account for uncertainty.\327\ The EIA does not provide
uncertainty estimates in the AEO cost projections. However, nuclear
experts from EIA staff have indicated to the EPA that a range of
uncertainty of -10 percent to +30 percent on the capital component of
the LCOE can be expected based on market uncertainties. Specifically,
these staff experts expect that nuclear plants currently under
construction would not have capital costs under estimates and that one
could expect to see a 30 percent ``upside'' variation in capital cost.
There is also insufficient market data to get a good statistical range
of potential capital cost variation (i.e., only two plants under
construction, neither complete). This is reasonably consistent with
estimates for nuclear costs estimated by Lazard (see Table 8 above)
which likewise reflect a similar level of cost uncertainty. The Lazard
nuclear costs show a range of projected levelized capital cost from
$73/MWh to $110/MWh--a range of 50 percent, very similar to the 40
percent range (i.e., -10 percent to +30 percent) suggested by EIA
nuclear experts. The Global CCS Institute, in its most recent cost
update, also provides nuclear costs as a range from $86/MWh to $102/
MWh.\328\
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\327\ EIA does not provided uncertainty estimates in the AEO
cost projections. However, EIA staff have indicated to the EPA that
a range of uncertainty of -10%/+30% on the capital component of the
LCOE can be expected based on market uncertainties. See memorandum
``Range of uncertainty for AEO nuclear costs'' available in the
rulemaking docket, EPA-HQ-OAR-2013-0495.
\328\ ``The Costs of CCS and other Low-Carbon Technologies--2015
update'' July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccs-other-low-carbon-technologies-2015-update.pdf.
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3. Use of Costs From Current Projects
Although we are relying on cost estimates drawn from techno-
economic models, we recognize that there are a few steam electric
plants that include CCS that have been built, or are being constructed.
Some information about the costs (or cost-to-date) for these projects
is known. We discuss in this section the costs at facilities which have
installed or are installing CCS, why the EPA does not consider those
costs to be reasonably predictive of the costs of the next new plants
to be built, and why the EPA considers that the next new plants will
have lower costs along the lines predicted by NETL.\329\
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\329\ The EPA notes that two of these facilities, Kemper and
TCEP, received both assistance from DOE under EPAct05 and the IRC
section 48A tax credit; and that the AEP Mountaineer pilot project
received assistance from DOE under EPAct05. Under the most extreme
interpretations of those provisions offered by commenters, the EPA
would be precluded from any consideration of any information from
those sources, including cost information, in showing whether a
system of emission reduction is adequately demonstrated. We note,
however, that many of these same commenters urged consideration of
the cost information from these sources. In fact, the EPA is not
relying on information about the costs of these sources to determine
the BSER or the standards of performance in this rulemaking, and the
EPA is discussing the cost information here to explain why not.
Accordingly, this discussion of cost information from these sources
is not precluded by the EPAct05 and IRC section 48A provisions and,
even if it is precluded, that would have no impact on the EPA's
determination of the BSER and the standards of performance in this
rule.
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The Boundary Dam Unit #3 facility utilizing post-combustion capture
from Shell Cansolv is now operational. Petra Nova, a joint venture
between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is
currently constructing a post-combustion capture system at NRG's WA
Parish generating station near Houston, TX. The post-combustion capture
system will utilize MHI amine-based solvents and is currently being
constructed with plans to initiate operation in 2016.\330\
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\330\ http://www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccs-project/.
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Construction on Mississippi Power's Kemper County Energy Center
IGCC facility is now nearly complete. The combined cycle portion of the
facility has been generating power using natural gas. The gasification
portion of the facility and the carbon capture system are undergoing
system checks and training to enable commercial operations using a UOP
SelexolTM pre-combustion capture system in early 2016.\331\
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\331\ http://www.mississippipower.com/about-energy/plants/kemper-county-energy-facility/facts.
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Another full-scale project, the Summit Power Texas Clean Energy
Project has not commenced construction but remains a viable project.
Several other full-scale projects have been proposed and have
progressed through the early stages of design, but have been cancelled
or postponed for a variety of reasons.
Some cost information is also available for small demonstration
projects--including those that have been supported by USDOE research
programs. These projects would include Alabama Power's demonstration
project at Plant Barry and the AEP/Alstom demonstration at Plant
Mountaineer.
Many commenters felt that the EPA should rely on those high costs
when considering whether the costs are reasonable. The costs from these
large-scale projects appear to be consistently higher than those
projected by techno-economic models. However, the costs from these
full-scale projects represent first-of-a-kind (FOAK) costs and, it is
reasonable to expect these costs to come down to the level projected in
the NETL and other techno-economic studies for the next new projects
that are built--which are the sources that would be subject to this
standard.
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
[[Page 64571]]
that the per-unit cost of producing or using a given technology
declines as experience with that technology increases over time, and
this has certainly been the case with air pollution control
technologies. Reductions in the cost of air pollution control
technologies as a result of learning-by-doing, research and development
investments, and other factors have been observed over the decades. We
expect that the costs of capture technology will follow this pattern.
The NETL cost estimates reasonably account for this documented
phenomenon. Specifically, ``[I]n all cases, the report intends to
represent the next commercial offering, and relies on vendor cost
estimates for component technologies. It also applies process
contingencies at the appropriate subsystem levels in an attempt to
account for expected but undefined costs (a challenge for emerging
technologies).'' \332\
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\332\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity
Revision 3'', DOE/NETL-2015/1723 (July 2015) at p. 38.
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Commenters argued that the next plants to be built would still
reflect first-of-a-kind costs, pointing to the newness of the
technology and the lack of operating experience, i.e. the alleged
absence of learning by doing. The EPA disagrees. In addition to
operating experience from operating and partially constructed CCS
projects, substantial research efforts are underway providing a further
knowledge base 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 that will dramatically lower the cost of capturing
CO2 from fossil fuel energy plants compared to currently
available capture technologies. The large-scale CO2 capture
demonstrations that are currently planned and in some cases underway,
under DOE's initiatives, as well as other domestic and international
projects, will generate operational knowledge and enable continued
commercialization and deployment of these technologies. 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 gas environment as the amine will rapidly degrade
in the presence of oxygen and other contaminants. The Fluor Econamine
FG process, the process modeled in the NETL cost study for the SCPC
cases, 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.
As noted in Section V.H.7.d above, SaskPower has created the CCS
Global Consortium to facilitate further knowledge regarding, and use
of, carbon capture technology.\333\ This consortium provides SaskPower
the opportunity to share its knowledge and experience with global
energy leaders, technology developers, and project developers.
SaskPower, in partnership with Mitsubishi and Hitachi, is also helping
to advance CCS knowledge and technology through the creation of the
Shand Carbon Capture Test Facility (CCTF).\334\ The test facility will
provide technology developers with an opportunity to test new and
emerging carbon capture systems for controlling carbon emissions from
coal-fired power plants.
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\333\ http://www.saskpowerccs.com/consortium/.
\334\ http://www.saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
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We also note certain features of the commercial plants already
built that suggest that their costs are uniquely high, and otherwise
not fairly comparable to the costs of plants meeting the NSPS using the
BSER. Most obviously, many of these projects involve deeper capture
than the partial CCS that the EPA assumes in this final action. In
addition, cost overruns at the Kemper facility, mentioned repeatedly in
the public comments, resulted in major part from highly idiosyncratic
circumstances, and are related to the cost of the IGCC system, not to
the cost of CCS.\335\ The EPA does not believe that these unusual
circumstances are a reasonable basis for assessing costs of either CCS
or IGCC here.
---------------------------------------------------------------------------
\335\ See Independent Monitor's Prudency Evaluation Report for
the Kemper County IGCC Project (prepared for Mississippi Public
Utilities Staff), available at www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=328417
(``Report''). As documented in this Report, costs escalated
significantly because the developers adopted a ``compressed
schedule'' in an attempt to obtain the IRC 48A tax credit, resulting
in ``engineering and design changes which are a normal result of
detailed engineering and design . . . occurring at the same time as,
rather than ahead of, construction activities'', which did not allow
for proper sequencing during construction. This `` 'just-in-time'
approach to engineering and procurement (meaning that the
engineering was often completed shortly before material procurement
and construction activities) resulted in a greater number of
construction work-arounds, congestion of construction craft labor in
the field, inefficiencies and additional steps that became necessary
during construction to cope with this just-in-time engineering,
procurement and construction approach.'' Report, p. 6. Ironically,
work was still completed too late to obtain the tax credit. Id. p.
15.
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4. Cost Competitiveness of New Coal Units
As the EPA noted, all indications suggest that very few new coal-
fired power plants will be constructed in the foreseeable future.
Although a small number of new coal-fired power plants have been built
recently, the industry generally is not building these kinds of power
plants at present and is not expected to do so for the foreseeable
future. The reasons include the current economic environment and
improved energy efficiency, which has led to lower electricity demand,
and competitive current and projected natural gas prices. On average,
the cost of generation from a new NGCC power plant is expected to be
lower than the cost of generation from a new coal-fired power plant,
and the EPA has concluded that, even in the absence of the requirements
of this final rule, very few new coal-fired power plants will be built
in the near term.
Some commenters, however, disagreed with this conclusion. They
contended instead that it is the CCS-based NSPS that would preclude
such new generation. However, as the EPA has discussed, there is
considerable evidence that utilities and project developers are moving
away--or have already moved away--from a long term dependence on coal-
fired generating sources. A review of publicly available integrated
resource plans show that many utilities are not considering
construction of new coal-fired sources without CCS. See Section V. H.3
above. Few new coal-fired generating sources have commenced
construction in the past 5 years and, of the projects that are
currently in the development phase, the EPA is only aware of projects
that will include CCS in the design. As we have noted in this preamble,
the bulk of new
[[Page 64572]]
generation that has been added recently has been either natural gas-
fired or renewable sources. Overall, the EPA remains convinced that the
energy sector modeling is reflecting the realities of the market in
predicting very few new coal-fired power plants in the near future--
even in the absence of these final standards.
In addition, we note that the Administration's CCS Task Force
report recognized that CCS would not become more widely available
without the advent of a regulatory framework that promoted CCS or
provided a strong price signal for CO2. In this regard, we
note American Electric Power's statements regarding the need for
federal requirement for GHG control to aid in cost recovery for CCS
projects, to attract other investment partners, and thereby promote
advancement and deployment of CCS technology: ``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''.\336\ Indeed, AEP has stated that CCS is
important for the very future of the industry: ``AEP still believes the
advancement of CCS is critical for the sustainability of coal-fired
generation.'' \337\ This final rule's action is an important component
in developing that needed regulatory framework.
---------------------------------------------------------------------------
\336\ www.aep.com/newsroom/newsreleases/?id=1704.
\337\ ``CCS LESSONS LEARNED REPORT American Electric Power
Mountaineer CCS II Project Phase 1'', prepared for The Global CCS
Institute Project # PRO 004, January 23, 2012, page 2. Available at:
www.globalccsinstitute.com/publications/ccs-lessons-learned-report-american-electric-power-mountaineer-ccs-ii-project-phase-1; See also
AEP FEED Study at pp. 4, 63, Available at:
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------
5. Accuracy of Cost Estimates for Transportation and Geologic
Sequestration
The EPA's estimates of costs take into account the transport of
CO2 and sequestration of captured CO2. Estimates
of transport and sequestration costs--approximately $5-$15 per ton of
CO2--are based on DOE NETL studies and are also consistent
with other published studies.\338\ For transport, costs reflect
pipeline capital costs, related capital expenditures, and O&M costs.
Sequestration cost estimates reflect the cost of site screening and
evaluation, the cost of injection wells, the cost of injection
equipment, operation and maintenance costs, pore volume acquisition
expense, and long term liability protection. These sequestration costs
reflect the regulatory requirements of the Underground Injection
Control Class VI program and GHGRP subpart RR for geologic
sequestration of CO2 in deep saline formations, which are
discussed further in Sections V. M. and N below.\339\
---------------------------------------------------------------------------
\338\ Updated Costs (June 2011 Basis) for Selected Bituminous
Baseline Cases (DOE/NETL-341/082312); Cost and Performance of PC and
IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL-2011/
1498); Cost and Performance Baseline for Fossil Energy Plants (DOE/
NETL-2010/1397); Economic Evaluation of CO2 Storage and
Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI,
December 2002; Carbon Dioxide and Transport and Storage Costs in
NETL Studies (DOE/NETL-2013/1614), March 2013; Carbon Dioxide and
Transport and Storage Costs in NETL Studies (DOE/NETL-2014/1653),
May 2014; Cost and Performance Baseline for Fossil Energy Power
Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to
Electricity (DOE-NETL-2015/1723), July 2015.
\339\ Carbon Dioxide and Transport and Storage Costs in NETL
Studies. DOE/NETL-2013/1614. March 2013. P. 13.
---------------------------------------------------------------------------
Based on DOE/NETL studies, the EPA estimated that the total
CO2 transportation, storage, and monitoring (TSM) cost
associated with EGU CCS would comprise less than 5.5 percent of the
total cost of electricity in all capture cases modeled--approximately
$5-$15 per ton of CO2.\340\ The range of TSM costs the EPA
relied on are broadly consistent with estimates provided by the Global
Carbon Capture and Storage Institute as well.\341\ Some commenters
suggested that the EPA underestimated the costs associated with
transporting captured CO2 from an EGU to a sequestration
site.\342\ Specifically, commenters suggested that the EPA's estimated
costs for constructing pipelines were lower than costs based on actual
industry experience. Commenters also opined that the EPA's assumed
length of pipeline needed between the EGU and the sequestration site is
not reasonable and that the DOE/NETL study upon which the EPA relied
does not account for CO2 transport costs when EOR is not
available.
---------------------------------------------------------------------------
\340\ RIA at section 5.5; proposed rule RIA at 5-30.
\341\ http://hub.globalccsinstitute.com/sites/default/files/publications/12786/economic-assessment-carbon-capture-and-storage-technologies-2011-update.pdf.
\342\ See, for example, comments from American Electric Power,
pp 97-8 (Docket entry: EPA-HQ-OAR-2013-0495-10618), Southern
Company, pp. 47-48 (Docket entry: EPA-HQ-OAR-2013-0495-10095), and
Duke Energy p. 28 (Docket entry: EPA-HQ-OAR-2013-0495-9426).
---------------------------------------------------------------------------
The EPA believes its estimates of transportation and sequestration
costs are reasonable. First, the EPA in fact includes cost estimates
for CO2 transport when EOR opportunities are not available--
consistent with its overall conservative cost methodology of assuming
no revenues from sale of captured CO2. Specifically, the EPA
estimates transport, storage and monitoring (TSM) costs of $5-$15 per
ton of CO2 for non-EOR applications.\343\ This estimate is
reflected in the LCOE comparative costs.\344\
---------------------------------------------------------------------------
\343\ See RIA at section 5.5 and proposed RIA at 5-30.
\344\ See RIA at section 5.5.
---------------------------------------------------------------------------
The EPA also carefully reviewed the assumptions on which the
transport cost estimates are based and continues to find them
reasonable. The NETL studies referenced in Section V.I.2 above based
transport costs on a generic 100 km (62 mi) pipeline and a generic 80
kilometer pipeline.\345\ At least one study estimated that of the 500
largest point sources of CO2 in the United States, 95
percent are within 50 miles of a potential storage reservoir.\346\ As a
point of reference, the longest CO2 pipeline in the United
States is 502 miles.\347\ For new sources, pipeline distance and costs
can be factored into siting and, as discussed in Section V.M, there is
widespread availability of geologic formations for geologic
sequestration (GS). Moreover, data from the Pipeline and Hazardous
Materials Safety Administration show that in 2013 there were 5,195
miles of CO2 pipelines operating in the United States. This
represents a seven percent increase in CO2 pipeline miles
over the previous year and a 38 percent increase in CO2
pipeline miles since 2004. For the reasons outlined above, the EPA
believes its estimates have a reasoned basis. See also Section V.M
below further discussing the current availability of CO2
pipelines.
---------------------------------------------------------------------------
\345\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
\346\ 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.
\347\ A Review of the CO2 Pipeline Infrastructure in
the U.S., April 21, 2015, DOE/NETL-2014/1681, Office of Fossil
Energy, National Energy Technology Laboratory.
---------------------------------------------------------------------------
With respect to sequestration, certain commenters argued that the
EPA's cost analysis failed to account for many contingencies and
uncertainties (surface and sub-surface property rights in particular),
ignored the costs of GHGRP subpart RR, and also was not representative
of the costs associated with specific GS site characterization,
development, and operation/injection of monitoring wells. Commenter
American Electric Power (AEP) referred to its own
[[Page 64573]]
experience with the Mountaineer demonstration project. AEP noted that
although this project was not full scale, finding a suitable
repository, notwithstanding a generally favorable geologic area, proved
difficult. The company referred to its estimated cost of expanding the
existing Mountaineer plant to a larger scale project, particularly the
cost of site characterization and well construction.\348\
---------------------------------------------------------------------------
\348\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
---------------------------------------------------------------------------
The EPA's cost estimates account for the requirements of the
Underground Injection Control Class VI program, and GHGRP subpart RR,
among them site screening and evaluation costs, costs for injection
wells and equipment, O&M costs, and monitoring costs. The estimated
sequestration costs include operational and post-injection site care
monitoring, which are components of the UIC Class VI requirements, and
also reflect costs for sub-surface pore volume property rights
acquisition.\349\ These estimates are consistent with the costs
presented in the study CO2 Storage and Sink Enhancements:
Developing Comparable Economics, which incorporates the costs
associated with site evaluation, well drilling, and the capital
equipment required for transporting and injecting
CO2.350 351 Monitoring costs were evaluated based
on the methodology set forth in the International Energy Agency
Greenhouse Gas R&D Programme's Overview of Monitoring Projects for
Geologic Storage Projects report.\352\
---------------------------------------------------------------------------
\349\ ``Cost and Performance of PC and IGCC Plants for a Range
of Carbon Dioxide Capture.'' DOE/NETL-2011/1498 (September 2013) p.
49. Specifically, the report estimates the costs associated with
acquiring rights to use the pore space in the geologic formation.
Costs are estimated based on studies of subsurface rights
acquisition for natural gas storage. The report also estimates costs
for land acquisition for surface property rights. Id. p. 48.
\350\ Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G.
De La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of
CO2 Storage and Sink Enhancement Options, Final Technical
Report Prepared by Tennessee Valley Authority for DOE.
\351\ As noted above, other sequestration-related costs are also
estimated, including injection wells and equipment, pore volume
acquisition, and long-term-liability. ``Cost and Performance
Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and
Natural Gas to Electricity Revision 2a, September 2013 DOE/NETL-
2010/1397, p. 55.
\352\ ``Overview of Monitoring Requirements for Geologic Storage
Projects'', IEA Greenhouse Gas R&D Programme, Report Number PH4/29,
November 2004.
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The EPA's cost estimates for sequestration thus cover all aspects
commenters claimed the EPA disregarded. The EPA believes that the use
of costs and scenarios presented in the studies referenced are
representative for purposes of the cost analysis. The NETL cost
estimates upon which the EPA's costs draw directly from the UIC Class
VI economic impact analysis.\353\ That analysis is based on estimated
characteristics for a representative group of projects over a 50-year
period of analysis, as well as industry averages for several cost
components and sub-components. The EPA also made reasonable assumptions
regarding the assumed injection site: A deep saline formation with
typical characteristics (e.g., representative depth and pressure).\354\
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\353\ Cost Analysis for the Federal Requirements Under the
Underground Injection Control Program for Carbon Dioxide Geologic
Sequestration Wells, U.S. Environmental Protection Agency Office of
Water, EPA 816-R10-013, November 2010, pages 3-1, 5-42.
\354\ Economic Evaluation of CO2 Storage and Sink
Enhancement Options, Tennessee Valley Authority, NETL and EPRI,
December 2002.
---------------------------------------------------------------------------
With respect to AEP's experience with the Mountaineer demonstration
project, sequestration siting issues are of course site-specific, and
raise individual issues. For this reason, it is inappropriate to
generalize from a particular individual experience. In this regard, as
explained in Section V.N below, the construction permits issued by the
EPA to-date under the Underground Injection Control Class VI
regulations required far fewer wells for site characterization and
monitoring than AEP found to be necessary at its Mountaineer site.
Moreover, notwithstanding difficulties, the company was able to
successfully drill and complete wells, and safely inject captured
CO2. The company also indicated it fully expected to be able
to do so at full scale and explained how.\355\ For discussion of 40 CFR
part 98, subpart RR (the GHGRP requirements for geologic
sequestration), including costs associated with compliance with those
requirements, see Section V.N below.
---------------------------------------------------------------------------
\355\ See ``CCS front end engineering & design report: American
Electric Power Mountaineer CCS II Project. Phase 1'' at pp. 36-43.
The company likewise explained the monitoring regime it would
utilize to verify containment, and the well construction it would
utilize to guarantee secure sequestration. Id. at pp. 44-54.
Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
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J. Achievability of the Final Standards
The EPA finds the final standard of 1,400 lb CO2/MWh-g
to be achievable over a wide range of variable conditions that are
reasonably likely to occur when the system is properly designed and
operated. As discussed elsewhere, the final standard reflects the
degree of emission limitation achievable through the application of the
BSER which we have determined to be a highly efficient SCPC
implementing partial CCS at a level sufficient to achieve the final
standard--for such a unit utilizing bituminous coal that would be
approximately 16 percent. In determining the predicted cost and
performance of such a system, the EPA utilized information contained in
updated DOE/NETL studies that assumed use of bituminous coal and an 85
percent capacity factor. Here we examine the effects of deviating from
those assumed operational parameters on the achievability of the final
standard of performance.\356\ This is in keeping with the requirement
that a standard of performance must be achievable accounting for all
normal operating variability when a control system is properly
designed, maintained, and operated. See Section III.H.1.c above.
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\356\ Additional information can be found in a Technical Support
Document (TSD)--``Achievability of the Standard for Newly
Constructed Steam Generating EGUs'' available in the rulemaking
docket.
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1. Operational Fluctuations, Start-Ups, Shutdowns, and Malfunctions
Importantly, compliance with the standard must be demonstrated over
a 12-operating-month average. The total CO2 emissions
(pounds of CO2) over 12 operational months are summed and
divided by the total gross output (in megawatt-hours) over the same 12
operational months. Such a compliance averaging period is very
forgiving of short-term excursions that can be associated with non-
routine events such as start-ups, shutdowns, and malfunctions. A new
fossil fuel-fired steam generating EGU--if constructed--would, most
likely, be built to serve base load power demand and would not be
expected to routinely start-up or shutdown or ramp its capacity factor
in order to follow load demand. Thus, planned start-up and shutdown
events would only be expected to occur a few times during the course of
a 12-operating-month compliance period. Malfunctions are unplanned and
unpredictable events and emission excursions can happen at or around
the time of the equipment malfunction. But a malfunctioning EGU that
cannot be operated properly should be shut down until the
malfunctioning equipment can be addressed and the EGU can be restarted
to operate properly.
The post-combustion capture systems that have been utilized have
proven to be reliable. The Boundary Dam facility has been operating
full CCS successfully at commercial scale since October 2014. As
described earlier, in evaluating results from the Mountaineer slip-
[[Page 64574]]
stream demonstration, AEP and Alstom 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.\357\
---------------------------------------------------------------------------
\357\ http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carbon-capture-and-sequestration-ccs-project/. The Boundary Dam facility likewise is
operating reliably (see Section V.D.3.a above). See also ``Cost and
Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous
Coal (PC) and Natural Gas to Electricity, Revision 3'', DOE/NETL-
2015/1723 (July 2015) at p. 36 (``[t]he capture and CO2
compression technologies have commercial operating experience with
demonstrated ability for high reliability'').
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2. Variations in Coal Type
The use of specific coal types can affect the amount of
CO2 that is emitted from a new coal-fired power plant. As
previously discussed, the EPA utilized studies by the DOE/NETL to
predict the cost and performance of new steam generating units. Based
on those reports, the EPA predicts that a new SCPC burning low rank
coal (subbituminous coal or dried lignite) would have an uncontrolled
emission rate about 7 percent higher than a similar unit firing typical
bituminous coal.\358\ The EPA predicts that such a highly efficient new
SCPC utilizing subbituminous coal or dried lignite would need to
capture approximately 23 percent of the CO2. The EPA also
believes that it is technically feasible to do so, although additional
cost would be entailed. The EPA has evaluated those costs and finds
them to remain reasonable.\359\ As shown in Table 8 above, the
predicted cost remains within the estimated range for the other
principal base load, dispatchable non-NGCC alternative technologies.
Estimated capital cost using these coal types would also be somewhat
higher, an estimated 23 percent increase.\360\ The EPA finds these
increases to be reasonable because, as discussed earlier, the costs are
reasonably consistent with capital cost increases in previous NSPS. See
Section V.H.4 above.
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\358\ For additional detail, see the Technical Support Document
(TSD)--``Achievability of the Standard for Newly Constructed Steam
Generating EGUs''--available in the rulemaking docket.
\359\ The cost of the lignite drying equipment is assumed to be
low compared to the cost of the carbon capture equipment. Further,
pre-drying of the lignite reduces fuel, auxiliary power consumption
and other O&M costs. www.iea-coal.org.uk/documents/83436/9095/
Techno-economics-of-modern-pre-drying-technologies-for-lignite-
fired-power-plants,-CCC/241.
\360\ Note that the 23 percent increase in expected capital
costs and the 23 percent CO2 capture needed to meet the
final standard are coincidental and are not correlated.
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K. Emission Reductions Utilizing Partial CCS
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 at 326 (``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'').\361\ This is consistent with the Court's statements in
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 that it is
necessary to ``[k]eep[] in mind Congress' intent that new plants be
controlled to the `maximum practicable degree' ''.
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\361\ 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.''
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The final standard of performance will result in meaningful and
significant emission reductions of GHG emissions from a new coal-fired
steam generating unit. The EPA estimates that a new highly efficient
500 MW coal-fired SCPC meeting the final standard of 1,400 lb
CO2/MWh-g will emit about 354,000 fewer metric tons of
CO2 each year than that new highly efficient unit would have
emitted otherwise. That is equivalent to taking about 75,000 vehicles
off the road each year \362\ and will result in over 14,000,000 fewer
metric tons of CO2 in a 40-year operating life. To emphasize
the importance of constructing a highly efficient SCPC unit that
includes partial CCS--the highly efficient 500 MW coal-fired SCPC with
partial CCS would emit about 675,000 fewer metric tons of
CO2 each year than that from a new, less efficient coal-
fired utility boiler with an assumed emission of 1,800 lb
CO2/MWh-g.
---------------------------------------------------------------------------
\362\ Using U.S. EPA Office of Transportation and Air Quality
(OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year.
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For comparison, see Table 12 below which provides the amount of
CO2 emissions captured each year by other CCS projects.
These result show that, even though the emission reductions are
significant, they are reasonably within the range of emission
reductions that are currently being achieved now in existing
facilities. For comparison, approximately 60,000,000 metric tons of
CO2 were supplied to U.S. EOR operations in 2013.\363\
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\363\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
Table 12--Annual Metric Tons of CO2 Captured (or Predicted to Capture)
From CCS Projects and From a Model 500 MW Plant Meeting the Final
Standard.
------------------------------------------------------------------------
CO2 captured
Project tonnes/year
------------------------------------------------------------------------
AES Shady Point......................................... 66,000
AES Warrior Run......................................... 110,000
Southern Company Plant Barry............................ 165,000
Searles Valley Minerals................................. 270,000
New 500 MW SCPC EGU (1,400 lb CO2/MWh-g)................ 354,000
Coffeyville Fertilizer.................................. 700,000
Boundary Dam #3......................................... 1,000,000
Petra Nova/NRG WA Parish................................ 1,400,000
Dakota Gasification..................................... 3,000,000
------------------------------------------------------------------------
[[Page 64575]]
L. Further Development and Deployment of CCS Technology
Researchers at Carnegie Mellon University (CMU) have studied the
history and the technological response to environmental
regulations.\364\ By examining U.S. research funding and patenting
activity over the past century, the CMU researchers found that
promulgation of national policy requiring large reductions in power-
plant emissions resulted in a significant upswing in inventive activity
to develop technologies to reduce those emissions. The researchers
found that, following the 1970 Clean Air Act, there was a 10-fold
increase in patenting activity directed at improving the SO2
scrubbers that were needed to comply with stringent federal and state-
level standards.
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\364\ See Technical Support Document/Memorandum ``History Of
Flue Gas Desulfurization in the United States'' (July 11, 2015)
summarizing the doctoral dissertation of Margaret R. Taylor, ``The
Influence of Government Actions on Innovative Activities in the
Development of Environmental Technologies to Control Sulfur Dioxide
Emissions from Stationary Sources,'' MA dissertation submitted to
the Carnegie Institute of Technology, Carnegie Mellon University in
partial fulfillment of the requirements for the degree of Doctor of
Philosophy in Engineering and Public Policy, Pittsburgh, PA, January
2001.
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Much like carbon capture scrubbers today, the technology to capture
and remove SO2 from power plant flue gases was new to the
industry and was not yet widely deployed at large coal-burning plants
when the EPA first promulgated the 1971 standards.
Many of the early Flue Gas Desulfurization (FGD) units did not
perform well, as the technology at that time was poorly understood and
there was little or no prior experience on coal-fired power plants. In
contrast, amine-based capture systems have a much longer history of
reliable use at coal-fired plants and other industrial sources. There
is also a better understanding of the amine process chemistry and
overall process design--and project developers have much sophisticated
analytical tools available today than in the 1970s during the
development of FGD scrubber technologies.
While R&D efforts were essential to achieving improvements in FGD
scrubber technology--and are also very important to improving carbon
capture technologies, the influence of regulatory actions that
establish commercial markets for advanced technologies cannot be
minimized. The existence of national government regulation for
SO2 emissions control stimulated innovation, as shown by the
patent analysis following initial SO2 regulatory
requirements for EGU emissions. The study author further found that
regulatory stringency appears to be particularly important as a driver
of innovation, both in terms of inventive activity and in terms of the
communication processes involved in knowledge transfer and diffusion.
Further, as electric power generation doubled, the operating and
maintenance costs of FGD systems decline to 83 percent of their
original level. This finding, which is very much in line with progress
ratios determined in other industries, shows that quantifiable
technological improvements can be shown to occur solely on the basis of
the experience of operating an environmental control technology forced
into being by government actions.
M. Technical and Geographic Aspects of Disposition of Captured
CO2
In the following sections of the preamble, we discuss issues
associated with the disposition of captured CO2: the ``S''--
sequestration--in CCS. In this section, we review the existing
processes, technologies, and geologic conditions that enable successful
geologic sequestration (GS). In Section V.N., we discuss in detail the
comprehensive, in-place regulatory structure that is currently
available to oversee GS projects and assure their safety and
effectiveness. Together, these discussions demonstrate that the
technical feasibility of GS, another key component of a partial CCS
unit, is adequately demonstrated. Sequestration is already well proven.
CO2 has been retained underground for eons in geologic
(natural) repositories and the mechanisms by which CO2 is
trapped underground are well understood. The physical and chemical
trapping mechanisms, along with the regulatory requirements and
safeguards of the Underground Injection Control Program and
complementary monitoring and reporting requirements of the GHGRP,
together ensure that sequestered CO2 will remain secure and
provide the monitoring to identify and address potential leakage using
Safe Drinking Water Act (SDWA) and CAA authorities (see Section V.N of
this preamble).\365\
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\365\ See also Carbon Sequestration Council and Southern Company
Services v. EPA, No. 14-1406 (D.C. Cir. June 2, 2015) at *10
(``[c]arbon capture and storage is an emerging climate change
mitigation program that involves capturing carbon dioxide from
industrial sources, compressing it into a `supercritical fluid,' and
injecting that fluid underground for the purposes of geologic
sequestration, with the goal of preventing the carbon from
reentering the atmosphere. Because the last of these steps--geologic
sequestration of the supercritical carbon dioxide--involves that
injection of fluid into underground wells, it is subject to
regulation under the Safe Drinking Water Act'').
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1. Geologic and Geographic Considerations for GS
Geologic sequestration (i.e., long-term containment of a
CO2 stream in subsurface geologic formations) is technically
feasible and available throughout most of the United States. GS is
based on a demonstrated understanding of the processes that affect
CO2 fate in the subsurface; these processes can vary
regionally as the subsurface geology changes. GS occurs through a
combination of mechanisms including: (1) Structural and stratigraphic
trapping (generally trapping below a low permeability confining layer);
(2) residual CO2 trapping (retention as an immobile phase
trapped in the pore spaces of the geologic formation); (3) solubility
trapping (dissolution in the in situ formation fluids); (4) mineral
trapping (reaction with the minerals in the geologic formation and
confining layer to produce carbonate minerals); and (5) preferential
adsorption trapping (adsorption onto organic matter in coal and
shale).\366\ These mechanisms are functions of the physical and
chemical properties of CO2 and the geologic formations into
which the CO2 stream is injected. Subsurface formations
suitable for GS of CO2 captured from affected EGUs are
geographically widespread throughout most parts of the United States.
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\366\ See, e.g., USEPA. 2008. Vulnerability Evaluation Framework
for Geologic Sequestration of Carbon Dioxide.
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Storage security is expected to increase over time through post-
closure, resulting in a decrease in potential risks.\367\ This
expectation is based in part on a technical understanding of the
variety of trapping mechanisms that work to reduce CO2
mobility over time.\368\ In addition, site characterization, site
operations, and monitoring strategies can work in combination to
promote storage security.
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\367\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010), page 47.
\368\ See, e.g., Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture and Storage.
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[[Page 64576]]
The effectiveness of long-term trapping of CO2 has been
demonstrated by natural analogs in a range of geologic settings where
CO2 has remained trapped for millions of years.\369\ For
example, CO2 has been trapped for more than 65 million years
in the Jackson Dome, located near Jackson, Mississippi.\370\ Other
examples of natural CO2 sources include Bravo Dome and
McElmo Dome in Colorado and New Mexico, respectively. These natural
storage sites are themselves capable of holding volumes of
CO2 that are larger than the volume of CO2
expected to be captured from a fossil fuel-fired EGU. In 2010, the
Department of Energy (DOE) estimated current CO2 reserves of
594 million metric tons at Jackson Dome, 424 million metric tons at
Bravo Dome, and 530 million metric tons at McElmo Dome.\371\
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\369\ Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale.
2007. Natural Emissions of CO2 from the Geosphere and
their Bearing on the Geological Storage of Carbon Dioxide. Energy
32: 1194-1201.
\370\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\371\ DiPietro, P., Balash, P. & M. Wallace. A Note on Sources
of CO2 Supply for Enhanced-Oil Recovery Operations. SPE
Economics & Management. April 2012.
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GS is feasible in different types of geologic formations including
deep saline formations (formations with high salinity formation fluids)
or in oil and gas formations, such as where injected CO2
increases oil production efficiency through a process referred to as
enhanced oil recovery (EOR). Both deep saline and oil and gas formation
types are widely available in the United States. The geographic
availability of deep saline formations and EOR is shown in Figure 1
below.\372\ As shown in the figure, there are 39 states for which
onshore and offshore deep saline formation storage capacity has been
identified.\373\ EOR operations are currently being conducted in 12
states. An additional 17 states have geology that is amenable to EOR
operations. Figure 1 also shows areas that are within 100 kilometers
(62 miles) of where storage capacity has been identified.\374\ There
are 10 states with operating CO2 pipelines and 18 states
that are within 100 kilometers (62 miles) of an active EOR location.
---------------------------------------------------------------------------
\372\ A color version of the figure, which readers may find
easier to view, can be found in the technical support document on
geographic availability in the rulemaking docket.
\373\ Alaska is not shown in Figure 1; it has deep saline
formation storage capacity, geology amenable to EOR operations, and
potential GS capacity in unmineable coal seams.
\374\ The distance of 100 kilometers reflects assumptions in
DOE-NETL cost estimates which the EPA used for cost estimation
purposes. See ``Carbon Dioxide and Transport and Storage Costs in
NETL Studies'', DOE/NETL-2014/1653 (May 2014).
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CO2 may also be used for other types of enhanced
recovery, such as for natural gas production. Reservoirs such as
unmineable coal seams also offer the potential for geologic
storage.\375\ Enhanced coalbed methane recovery is the process of
injecting and storing CO2 in unmineable coal seams to
enhance methane recovery. These operations take advantage of the
preferential chemical affinity of coal for CO2 relative to
the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane that can then be captured and produced. This process
effectively ``locks'' the CO2 to the coal, where it remains
stored. DOE has identified over 54 billion metric tons of potential
CO2 storage capacity in unmineable coal across 21
states.\376\ The availability of unmineable coal seams is shown in
Figure 1 below.
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\375\ Other types of opportunities include organic shales and
basalt.
\376\ 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).
---------------------------------------------------------------------------
As discussed below in Section M.7, a few states do not have
geologic conditions suitable for GS, or may not be located in proximity
to these areas. However, in some cases, demand in those states can be
served by coal-fired power plants located in areas suitable for GS, and
in other cases, coal-fired power plants are unlikely to be built in
those areas for other reasons, such as the lack of available coal or
state law prohibitions and restrictions against coal-fired power
plants.\377\
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\377\ Similarly, as discussed below, the U.S. territories lack
available coal, do not currently have coal-fired power plants, and,
as a result, are not expected to see new coal-fired power plants.
Hawaii is not expected to constructed new coal plants as it intends
to utilize 100 percent renewable energy sources by 2050.
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[[Page 64577]]
[GRAPHIC] [TIFF OMITTED] TR23OC15.000
[[Page 64578]]
[GRAPHIC] [TIFF OMITTED] TR23OC15.001
2. Availability of Geologic Sequestration in Deep Saline Formations
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\378\ Ventyx Velocity Suite Online. April 2015.
---------------------------------------------------------------------------
The DOE and the United States Geological Survey (USGS) have
independently conducted preliminary analyses of the availability and
potential CO2 sequestration capacity of deep saline
formations in the United States. DOE estimates are compiled by the
DOE's National Carbon Sequestration Database and Geographic Information
System (NATCARB) using volumetric models and published in a Carbon
Utilization and Storage Atlas.\379\ DOE estimates that areas of the
United States
[[Page 64579]]
with appropriate geology have a sequestration potential of at least
2,035 billion metric tons of CO2 in deep saline formations.
According to DOE and as noted above, at least 39 states have geologic
characteristics that are amenable to deep saline GS in either onshore
or offshore locations. In 2013, the USGS completed its evaluation of
the technically accessible GS resources for CO2 in U.S.
onshore areas and state waters using probabilistic assessment.\380\ The
USGS estimates a mean of 3,000 billion metric tons of subsurface
CO2 sequestration potential, including saline and oil and
gas reservoirs, across the basins studied in the United States.
---------------------------------------------------------------------------
\379\ 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).
\380\ 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, p. 41, http://pubs.usgs.gov/circ/1386/ 1386/.
---------------------------------------------------------------------------
The DOE has created a network of seven Regional Carbon
Sequestration Partnerships (RCSPs) to deploy large-scale field projects
in different geologic settings across the country to demonstrate that
GS can be achieved safely, permanently, and economically at large
scales. Collectively, the seven RCSPs represent regions encompassing 97
percent of coal-fired CO2 emissions, 97 percent of
industrial CO2 emissions, 96 percent of the total land mass,
and essentially all the geologic sequestration sites in the United
States potentially available for GS.\381\ The seven partnerships
include more than 400 organizations spanning 43 states (and four
Canadian provinces).\382\ RCSP project objectives are to inject at
least one million metric tons of CO2. In April 2015, DOE
announced that CCS projects supported by the department have safely and
permanently stored 10 million metric tons of CO2.\383\
---------------------------------------------------------------------------
\381\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
\382\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
\383\ http://energy.gov/articles/milestone-energy-department-projects-safely-and-permanently-store-10-million-metric-tons.
---------------------------------------------------------------------------
Eight RCSP ``Development Phase'' projects have been initiated and
five of the eight projects are injecting or have completed
CO2 injection into deep saline formations. Three of these
projects have already injected more than one million metric tons each,
and one, the Cranfield Site, injected over eight million metric tons of
CO2 between 2009 and 2013.\384\ Various types of
technologies for monitoring CO2 in the subsurface and air
have been employed at these projects, such as seismic methods
(crosswell seismic, 3-D and 4-D seismic, and vertical seismic
profiling), atmospheric CO2 monitoring, soil gas sampling,
well and formation pressure monitoring, and surface and ground water
monitoring.\385\ No CO2 leakage has been reported from these
sites, which further supports the availability of effective GS.
---------------------------------------------------------------------------
\384\ U.S. Department of Energy, National Energy Technology
Laboratory, Project Facts, Southeast Regional Carbon Sequestration
Partnership--Development Phase, Cranfield Site and Citronelle Site
Projects, NT42590, October 2013. Available at: http://www.netl.doe.gov/publications/factsheets/project/NT42590.pdf.
\385\ A description of the types of monitoring technologies
employed at RCSP projects can be found here: http://www.netl.doe.gov/research/coal/carbon-storage/carbon-storage-infrastructure/regional-partnership-development-phase-iii.
---------------------------------------------------------------------------
3. Availability of CO2 Storage via EOR
Although the determination that the BSER is adequately demonstrated
and the regulatory impact analysis for this rule relies on GS in deep
saline formations, the EPA also recognizes the potential for securely
sequestering CO2 via EOR.
EOR is a technique that is used to increase the production of oil.
Approaches used for EOR include steam injection, injection of specific
fluids such as surfactants and polymers, and gas injection including
nitrogen 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 to make it more amenable for recovery. The
crude oil and CO2 mixture is then recovered and sent to a
separator where the crude oil is separated from the gaseous
hydrocarbons, native formation fluids, and CO2. The gaseous
CO2-rich stream then is typically dehydrated, purified to
remove hydrocarbons, re-compressed, and re-injected into the reservoir
to further enhance oil recovery. Not all of the CO2 injected
into the oil reservoir is recovered and re-injected. As the
CO2 moves from the injection point to the production well,
some of the CO2 becomes trapped in the small pores of the
rock, or is dissolved in the oil and water that is not recovered. The
CO2 that remains in the reservoir is not mobile and becomes
sequestered.
The amount of CO2 used in an EOR project depends on the
volume and injectivity of the reservoir that is being flooded and the
length of time the EOR project has been in operation. Initially, all of
the injected CO2 is newly received. As discussed above, as
the project matures, some CO2 is recovered with the oil and
the recovered CO2 is separated from the oil and recycled so
that it can be re-injected into the reservoir in addition to new
CO2 that is received. If an EOR operator will not require
the full volume of CO2 available from an EGU, the EGU has
other options such as sending the CO2 to other EOR
operators, or sending it to deep saline formation GS facilities.
CO2 used for EOR may come from anthropogenic or natural
sources. The source of the CO2 does not impact the
effectiveness of the EOR operation. CO2 capture, treatment
and processing steps provide a concentrated stream of CO2 in
order to meet the needs of the intended end use. CO2
pipeline specifications of the U.S. Department of Transportation
Pipeline Hazardous Materials Safety Administration found at 49 CFR part
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless
of the source of the CO2 and take into account
CO2 composition, impurities, and phase behavior.
Additionally, EOR operators and transport companies have specifications
related to the composition of the CO2 stream. The regulatory
requirements and company specifications ensure EOR operators receive a
known and consistent CO2 stream.
EOR has been successfully used at numerous production fields
throughout the United States to increase oil recovery. The oil industry
in the United States has over 40 years of experience with EOR. An oil
industry study in 2014 identified more than 125 EOR projects in 98
fields in the United States.\386\ More than half of the projects
evaluated in the study have been in operation for more than 10 years,
and many have been in operation for more than 30 years. This experience
provides a strong foundation for demonstrating successful
CO2 injection and monitoring technologies, which are needed
for safe and secure GS (see Section N below) that can be used for
deployment of CCS across geographically diverse areas.
---------------------------------------------------------------------------
\386\ Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil &
Gas Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables
appear in Volume 112, Issue 5, May 5, 2014).
---------------------------------------------------------------------------
Currently, 12 states have active EOR operations and most have
developed an extensive CO2 infrastructure, including
pipelines, to support the continued operation and growth of EOR. An
additional 18 states are within 100 kilometers (62 miles) of current
EOR operations. See Figure 1 above. The vast majority of EOR is
conducted in oil reservoirs in the Permian Basin, which extends through
southwest Texas and southeast New Mexico. States where EOR is utilized
include Alabama, Colorado, Louisiana, Michigan,
[[Page 64580]]
Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. Several
commenters raised concerns about the volume of CO2 used in
EOR projects relative to the scale of EGU emissions and the demand for
CO2 for EOR projects. At the project level, the volume of
CO2 already injected for EOR and the duration of operations
are of similar magnitude to the duration and volume of CO2
expected to be captured from fossil fuel-fired EGUs. The volume of
CO2 used in EOR operations can be large (e.g., 55 million
tons of CO2 were stored in the SACROC unit in the Permian
Basin over 35 years), and operations at a single oil field may last for
decades, injecting into multiple parts of the field.\387\ According to
data reported to the EPA's GHGRP, approximately 60 million metric tons
of CO2 were supplied to EOR in the United States in
2013.\388\ Approximately 70 percent of this total CO2
supplied was produced from natural (geologic) CO2 sources
and approximately 30 percent was captured from anthropogenic
sources.\389\
---------------------------------------------------------------------------
\387\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F
P. ``Evaluation of CO2 trapping mechanisms at the SACROC
northern platform, Permian basin, Texas, site of 35 years of
CO2 injection.'' American Journal of Science 310. (2010):
282-324.
\388\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
\389\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
---------------------------------------------------------------------------
A DOE-sponsored study has analyzed the geographic availability of
applying EOR in 11 major oil producing regions of the United States and
found that there is an opportunity to significantly increase the
application of EOR to areas outside of current operations.\390\ DOE-
sponsored geologic and engineering analyses show that expanding EOR
operations into areas additional to the capacity already identified and
applying new methods and techniques over the next 20 years could
utilize 18 billion metric tons of anthropogenic CO2 and
increase total oil production by 67 billion barrels. The study found
that one of the limitations to expanding CO2 use in EOR is
the lack of availability of CO2 in areas where reservoirs
are most amenable to CO2 flooding.\391\ DOE's Carbon
Utilization and Storage Atlas identifies 29 states with oil reservoirs
amenable to EOR, 12 of which currently have active EOR operations. A
comparison of the current states with EOR operations and the states
with potential for EOR shows that an opportunity exists to expand the
use of EOR to regions outside of current areas. The availability of
anthropogenic CO2 in areas outside of current sources could
drive new EOR projects by making more CO2 locally available.
---------------------------------------------------------------------------
\390\ ``Improving Domestic Energy Security and Lowering
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc.
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
\391\ ``Improving Domestic Energy Security and Lowering
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc.
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
---------------------------------------------------------------------------
Some commenters raised concerns that data are extremely limited on
the extent to which EOR operations permanently sequester
CO2, and the efficacy of long term storage, or that the EOR
industry does not have the requisite experience with and technical
knowledge of long-term CO2 sequestration. The EPA disagrees
with these commenters. Several EOR sites, which have been operated for
years to decades, have been studied to evaluate the viability of safe
and secure long-term sequestration of injected CO2. Examples
are identified below.
CO2 has been injected in the SACROC Unit in the Permian
basin since 1972 for EOR purposes. One study evaluated a portion of
this project, and estimated that the injection operations resulted in
final sequestration of about 55 million tons of CO2.\392\
This study used modeling and simulations, along with collection and
analysis of seismic surveys, and well logging data, to evaluate the
ongoing and potential CO2 trapping occurring through various
mechanisms. The monitoring at this site demonstrated that
CO2 can become trapped in geologic formations. In a separate
study in the SACROC Unit, the Texas Bureau of Economic Geology
conducted an extensive groundwater sampling program to look for
evidence of CO2 leakage in the shallow freshwater aquifers.
No evidence of leakage was detected.\393\
---------------------------------------------------------------------------
\392\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F
P. ``Evaluation of CO2 trapping mechanisms at the SACROC
northern platform, Permian basin, Texas, site of 35 years of
CO2 injection.'' American Journal of Science 310. (2010):
282-324.
\393\ Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S.,
Detection of anthropogenic CO2 in dilute groundwater:
field observations and geochemical modeling of the Dockum aquifer at
the SACROC oilfield, West Texas, USA: presented at the 9th Annual
Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May
10-13, 2010. GCCC Digital Publication Series #10-06.
---------------------------------------------------------------------------
The International Energy Agency Greenhouse Gas Programme conducted
an extensive monitoring program at the Weyburn oil field in
Saskatchewan between 2000 and 2010 (the site receiving CO2
captured by the Dakota Gasification synfuel plant discussed in Section
V.E.2.a above). During that time over 16 million metric tons of
CO2 were safely sequestered as evidenced by soil gas
surveys, shallow groundwater monitoring, seismic surveys and wellbore
integrity testing. An extensive shallow groundwater monitoring program
revealed no significant changes in water chemistry that could be
attributed to CO2 storage operations.\394\ The International
Energy Agency Greenhouse Gas Programme developed a best practices
manual for CO2 monitoring at EOR sites based on the
comprehensive analysis of surface and subsurface monitoring methods
applied over the 10 years.\395\
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\394\ Roston, B., and S. Whittaker (2010), 10+ years of the IEA-
GHG Weyburn-Midale CO2 monitoring and storage project;
success and lessons learned from multiple hydrogeological
investigations, to be published in Energy Procedia, Elsevier,
Proceedings of 10th International Conference on Greenhouse Gas
Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The
Netherlands.
\395\ Hitchon, B. (Editor), 2012, Best Practices for Validating
CO2 Geological Storage: Geoscience Publishing, p. 353.
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The Texas Bureau of Economic Geology also has been testing a wide
range of surface and subsurface monitoring tools and approaches to
document sequestration efficiency and sequestration permanence at the
Cranfield oilfield in Mississippi (see Section L.1 above).\396\ As part
of a DOE Southeast Regional Carbon Sequestration Partnership study,
Denbury Resources injected CO2 into a depleted oil and gas
reservoir at a rate greater than 1.2 million tons/year. Texas Bureau of
Economic Geology is currently evaluating the results of several
monitoring techniques employed at the Cranfield project and preliminary
findings indicate no impact to groundwater.\397\ The project also
demonstrates the availability and effectiveness of many different
monitoring techniques for tracking CO2 underground and
detecting CO2 leakage to ensure CO2 remains
safely sequestered.
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\396\ http://www.beg.utexas.edu/gccc/cranfield.php.
\397\ http://www.beg.utexas.edu/gccc/cranfield.php.
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As discussed in Section M.1 above and as shown in Figure 1, the
United States has widespread potential for storage, including in deep
saline formations and oil and gas formations. However, some commenters
maintained that the EPA's information regarding availability of GS
sites is overly general and ignores important individual
considerations. A number of commenters, for example, maintained that
site conditions often make monitoring difficult or impossible, so
[[Page 64581]]
that sites are not available as a practical matter.\398\ Commenter
American Electric Power pointed to its own experience in siting
monitoring wells for its pilot plant Mountaineer CCS project, which
involved protracted time and expense to eventually site monitoring
wells.\399\ Other commenters noted significant geographic disparity in
GS site availability, claiming absence of sites in southeastern areas
of the country.\400\
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\398\ Comments of Southern Co., p. 38 (Docket entry: EPA-HQ-OAR-
2013-0495-10095).
\399\ Comments of AEP pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
\400\ Comments of Duke Energy, pp. 24-5 Docket entry: EPA-HQ-
OAR-2013-0495-9426); UARG, pp. 53, 57 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) citing Cichanowicz (2012).
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Project- and site-specific factors do influence where
CO2 can be safely sequestered. However, as outlined above,
there is widespread potential for GS in the United States. If an area
does not have a suitable GS site, EGUs can either transport
CO2 to GS sites via CO2 pipelines (see Section
M.5 below), or they may choose to locate their units closer to GS sites
and provide electric power to customers through transmission lines (see
Figure 2 and Section M.7). In addition, there are alternative means of
complying with the final standards of performance that do not
necessitate use of partial CCS, so any siting difficulties based on
lack of a CO2 repository would be obviated. See Portland
Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that
the EPA could adopt section 111 standards of performance based on the
performance of a kiln type that kilns of older design would have great
difficulty satisfying, since, among other things, there were
alternative methods of compliance available should a new kiln of this
older design be built.
4. Alternatives to Geologic Sequestration
Potential alternatives to sequestering CO2 in geologic
formations are emerging. These relatively new potential alternatives
may offer the opportunity to offset the cost of CO2 capture.
For example, captured anthropogenic CO2 may be stored in
solid carbonate materials such as precipitated calcium carbonate (PCC)
or magnesium or calcium carbonate, bauxite residue carbonation, and
certain types of cement through mineralization. PCC is produced through
a chemical reaction process that utilizes calcium oxide (quicklime),
water, and CO2. Likewise, the combination of magnesium oxide
and CO2 results in a precipitation reaction where the
CO2 becomes mineralized. The carbonate materials produced
can be tailored to optimize performance in specific industrial and
commercial applications. These carbonate materials have been used in
the construction industry and, more recently and innovatively, in
cement production processes to replace Portland cement.
The Skyonics Skymine project, which opened its demonstration
project in October 2014, is an example of captured CO2 being
used in the production of carbonate products. This plant converts
CO2 into commercial products. It captures over 75,000 tons
of CO2 annually from a San Antonio, Texas, cement plant and
converts the CO2 into other products, including sodium
carbonate, sodium bicarbonate, hydrochloric acid and bleach.\401\
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\401\ http://skyonic.com/technologies/skymine.
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A few commenters suggested that CO2 utilization
technologies alternative to GS are being commercialized, and that these
should be included as compliance options for this rule. The rule
generally requires that captured CO2 be either injected on-
site for geologic sequestration or transferred offsite to a facility
reporting under 40 CFR subpart RR. The EPA does not believe that the
emerging technologies just discussed are sufficiently advanced to
unqualifiedly structure this final rule to allow for their use. Nor are
there plenary systems of regulatory control and GHG reporting for these
approaches, as there are for geologic sequestration. Nonetheless, as
stated above, these technologies not only show promise, but could
potentially be demonstrated to show permanent storage of
CO2.
In the January 2014 proposal, the EPA noted that it would need to
adopt a mechanism to evaluate these alternative technologies before any
could be used in lieu of geologic sequestration. 79 FR at 1484. The EPA
is establishing such a mechanism in this final rule. See Sec.
60.5555(g). The rule provides for a case-by-case adjudication by the
EPA of applications seeking to demonstrate to the EPA that a non-
geologic sequestration technology would result in permanent confinement
of captured CO2 from an affected EGU. The criteria to be
addressed in the application, and evaluated by the EPA, are drawn from
CAA section 111(j), which provides an analogous mechanism for case-by-
case approval of innovative technological systems of continuous
emission reduction which have not been adequately demonstrated.
Applicants would need to demonstrate that the proposed technology would
operate effectively, and that captured CO2 would be
permanently stored. Applicants must also demonstrate that the proposed
technology will not cause or contribute to an unreasonable risk to
public health, welfare or safety. In evaluating applications, the EPA
may conduct tests itself or require the applicant to conduct testing in
support of its application. Any application would be publicly noticed,
and the EPA would solicit comment on the application and on intended
action the EPA might take. The EPA could also provide a conditional
approval of an application on operating results from a proscribed
period. The EPA could also terminate an approval, including a
termination based on operating results calling into question a
technology's effectiveness.
As noted at proposal, given the unlikelihood of new coal-fired EGUs
being constructed, the EPA does not expect there to be many (if any)
applications for use of non-geologic sequestration technology. 79 FR at
1484.
5. Availability of Existing or Planned CO2 Pipelines
CO2 pipelines are the most economical and efficient
method of transporting large quantities of CO2.\402\
CO2 has been transported via pipelines in the United States
for nearly 40 years. Over this time, the design, construction,
operation, and safety requirements for CO2 pipelines have
been proven, and the U.S. CO2 pipeline network has been
safely used and expanded. The Pipeline and Hazardous Materials Safety
Administration (PHMSA) reported that in 2013 there were 5,195 miles of
CO2 pipelines operating in the United States. This
represents a seven percent increase in CO2 pipeline miles
over the previous year and a 38 percent increase in CO2
pipeline miles since 2004.\403\
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\402\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010), page 36.
\403\ ``Annual Report Mileage for Hazardous Liquid or Carbon
Dioxide Systems'', U.S. Pipeline and Hazardous Materials Safety
Administration, March 2, 2015. Available at: http://www.phmsa.dot.gov/pipeline/library/data-stats.
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Some commenters argued that the existing CO2 pipeline
capacity is not adequate and that CO2 pipelines are not
available in a majority of the United States.
The EPA does not agree. The CO2 pipeline network in the
United States has almost doubled in the past ten years in order to meet
growing demands for CO2 for EOR. CO2 transport
companies have recently proposed initiatives to expand the
CO2 pipeline network. Several hundred miles of dedicated
CO2 pipeline are under construction, planned, or proposed,
including
[[Page 64582]]
projects in Colorado, Louisiana, Montana, New Mexico, Texas, and
Wyoming.
Examples are identified below.
Kinder Morgan has reported several proposed pipeline projects
including the proposed expansion of the existing Cortez CO2
pipeline, crossing Colorado, New Mexico, and Texas, to increase the
CO2 transport capacity from 1.35 billion cubic feet per day
(Bcf/d) to 1.7 Bcf/d, to support the expansion of CO2
production capacity at the McElmo Dome production facility in Colorado.
The Cortez pipeline expansion is expected to be placed into service in
2015.\404\
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\404\ ``Form 10-K: Annual Report Pursuant to Section 13 or 15(d)
of the Security and Exchange Act of 1934, For the Fiscal Year Ended
December 31, 2014'', Kinder Morgan, February 2015. Available at:
http://ir.kindermorgan.com/sites/kindermorgan.investorhq.businesswire.com/files/report/additional/KMI-2014-10K_Final.pdf.
---------------------------------------------------------------------------
Denbury reported that the company utilized approximately 70 million
cubic feet per day of anthropogenic CO2 in 2013 and that an
additional approximately 115 million cubic feet per day of
anthropogenic CO2 may be utilized in the future from
currently planned or future construction of facilities and associated
pipelines in the Gulf Coast region.\405\ Denbury also initiated
transport of CO2 from a Wyoming natural gas processing plant
in 2013 and reported transporting approximately 22 million cubic feet
per day of CO2 in 2013 from that plant alone.\406\
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\405\ ``2013 Annual Report'', Denbury, April 2014. Available at
http://www.denbury.com/files/doc_financials/2013/Denbury_Final_040814.pdf.
\406\ ``CO2 Sources'', Denbury, 2015. Available at:
http://www.denbury.com/operations/rocky-mountain-region/co2-sources-and-pipelines/default.aspx.
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Denbury completed the final section of the 325-mile Green Pipeline
for transporting CO2 from Donaldsonville, Louisiana, to EOR
oil fields in Texas.\407\ Denbury completed construction and commenced
operation of the 232-mile Greencore Pipeline in 2013; the Greencore
pipeline transports CO2 to EOR fields in Wyoming and
Montana.\408\
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\407\ http://www.denbury.com/operations/gulf-coast-region/Pipelines/default.aspx.
\408\ ``CO2 Pipelines'', Denbury, 2014. Available at:
http://www.denbury.com/operations/rocky-mountain-region/COsub2-sub-Pipelines/default.aspx.
---------------------------------------------------------------------------
A project being constructed by NRG and JX Nippon Oil & Gas
Exploration (Petra Nova) would capture CO2 from a power
plant in Fort Bend County, Texas for transport to EOR sites in Jackson
County, Texas through an 82-mile CO2 pipeline.\409\ The
project is anticipated to commence operation in 2016.\410\
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\409\ ``The West Ranch CO2-EOR Project, NRG Fact
Sheet'', NRG, 2014. Available at: www.nrg.com/documents/business/pla-2014-west-ranch-fact-sheet.pdf.
\410\ ``WA Parish Carbon Capture Project'', NRG, 2015. Available
at: www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccs-project/.
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Some commenters suggested that there may be challenges associated
with the safety of transporting supercritical CO2 over long
distances, or that the EPA did not adequately consider the potential
non-air environmental impacts of the construction of CO2
pipelines.
The EPA has carefully evaluated the safety of pipelines used to
transport captured CO2 and determined that pipelines can
indeed convey captured CO2 to sequestration sites with
certainty and provide full protection of human health and the
environment. 76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 354 (Jan. 3,
2014). Existing and new CO2 pipelines are comprehensively
regulated by the Department of Transportation's Pipeline Hazardous
Material Safety Administration. The regulations govern pipeline design,
construction, operation and maintenance, and emergency response
planning. See generally 49 CFR 195.2. Additional regulations address
pipeline integrity management by requiring heightened scrutiny to
assure the quality of pipeline integrity in areas with a higher
potential for adverse consequences. See 49 CFR 195.450 and 195.452. On-
site pipelines are not subject to the Department of Transportation
standards, but rather adhere to the Pressure Piping standards of the
American Society of Mechanical Engineers (ASME B31), which the EPA has
found would ensure that piping and associated equipment meet certain
quality and safety criteria sufficient to prevent releases of
CO2, such that certain additional requirements were not
necessary (See 79 FR 358-59 (Jan. 3, 2014)).\411\ These existing
controls over CO2 pipelines assure protective management,
guard against releases, and assure that captured CO2 will be
securely conveyed to a sequestration site.
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\411\ See the B31 Code for pressure piping, developed by the
American Society of Mechanical Engineers, Pipeline Transportation
Systems for liquid hydrocarbons and other liquids.
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6. States With Emission Standards That Would Require CCS
Several states have established emission performance standards or
other measures to limit emissions of GHGs from new EGUs that are
comparable to or more stringent than the final standard in this
rulemaking. For example, in September 2006, California Governor
Schwarzenegger signed into law Senate Bill 1368. The law limits long-
term investments in base load generation by the state's utilities to
power plants that meet an emissions performance standard jointly
established by the California Energy Commission and the California
Public Utilities Commission. The Energy Commission has designed
regulations that establish a standard for new and existing base load
generation owned by, or under long-term contract to publicly owned
utilities, of 1,100 lb CO2/MWh.
In May 2007, Washington Governor Gregoire signed Substitute Senate
Bill 6001, which established statewide GHG emissions reduction goals,
and imposed an emission standard that applies to any base load electric
generation that commenced operation after June 1, 2008 and is located
in Washington, whether or not that generation serves load located
within the state. Base load generation facilities must initially comply
with an emission limit of 1,100 lb CO2/MWh.
In July 2009, Oregon Governor Kulongoski signed Senate Bill 101,
which mandated that facilities generating base load electricity,
whether gas- or coal-fired, must have emissions equal to or less than
1,100 lb CO2/MWh, and prohibited utilities from entering
into long-term purchase agreements for base load electricity with out-
of-state facilities that do not meet that standard.
In 2012 New York established emission standards of CO2
at 925 lb CO2/MWh for new and expanded base load fossil
fuel-fired plants.
In May 2007, Montana Governor Schweitzer signed House Bill 25,
adopting a CO2 emissions performance standard for EGUs in
the state. House Bill 25 prohibits the state Public Utility Commission
from approving new EGUs primarily fueled by coal unless a minimum of 50
percent of the CO2 produced by the facility is captured and
sequestered.
On January 12, 2009, Illinois Governor Blagojevich signed Senate
Bill 1987, the Clean Coal Portfolio Standard Law. The legislation
establishes emission standards for new power plants that use coal as
their primary feedstock. From 2009-2015, new coal-fueled power plants
must capture and store 50 percent of the carbon emissions that the
facility would otherwise emit; from 2016-2017, 70 percent must be
captured and stored; and after 2017, 90 percent must be captured and
stored.
7. Coal-by-Wire
In addition, as discussed in the proposal, electricity demand in
states
[[Page 64583]]
that may not have geologic sequestration sites may be served by coal-
fired electricity generation built in nearby areas with geologic
sequestration, and this electricity can be delivered through
transmission lines. This method, known as ``coal-by-wire,'' has long
been used in the electricity sector because siting a coal-fired power
plant near the coal mine and transmitting the generation long distances
to the load area is generally less expensive than siting the plant near
the load area and shipping the coal long distances.
For example, we noted in the proposal that there are many examples
where coal-fired power generated in one state is used to supply
electricity in other states. In the proposal we specifically noted that
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 and 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. 79 FR at 1478.
In the Technical Support Document on Geographic Availability
(Geographic Availability TSD), we explore in greater detail the issue
of coal-by-wire and the ability of demand in areas without geologic
sequestration to be served by coal generation located in areas that
have access to geologic sequestration. Figure 1 of this preamble (a
color version of which is provided as Figure 1 of the Geographic
Availability TSD) depicts areas of the country with: (1) existing
CO2 pipeline; (2) probable, planned, or under study
CO2 pipeline; (3) counties with active CO2-EOR
operations; (4) oil and natural gas reservoirs; (5) deep saline
formations; (6) unmineable coal seams; and (7) areas 100 kilometers
from geologic sequestration. As demonstrated by Figure 1, the vast
majority of the country has existing or planned CO2
pipeline, active CO2-EOR operations, the necessary geology
for CO2 storage, or is within 100 kilometers of areas with
geologic sequestration.\412\ A review of Figure 1 indicates limited
areas that do not fall into these categories.
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\412\ The NETL cost estimates for CO2 transport
assume a pipeline of 100 kilometers. NETL (2015) at p. 44.
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As an initial matter, we note that the data included in Figure 1 is
a conservative outlook of potential areas available for the development
of CO2 storage in that we include only areas that have been
assessed to date. Portions of the United States--such as the State of
Minnesota--have not yet been assessed and thus are depicted as not
having geological formations suitable for CO2 storage, even
though assessment could in fact reveal additional formations.\413\
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\413\ The data in Figure 1 is based on estimates compiled by the
DOE's National Carbon Sequestration Database and Geographic
Information System (NATCARB) and published in the United States 2012
Carbon Utilization and Storage Atlas, Fourth Edition. As discussed
in the TSD, deep saline formation potential was not assessed for
Alaska, Connecticut, Hawaii, Massachusetts, Nevada, Rhode Island,
and Vermont. Oil and gas storage potential was not assessed for
Alaska, Washington, Nevada, and Oregon. Unmineable coal seams were
not assessed for Nevada, Oregon, California, Idaho, and New York. We
are assuming for purposes of our analysis here that they do not have
storage potential in those formations.
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As one considers the areas on the map depicted in Figure 1 that
fall outside of the above enumerated categories, in many instances, we
find areas with low population density, areas that are already served
by transmission lines that could deliver coal-by-wire, and/or areas
that have made policy or other decisions not to pursue a resource mix
that includes coal. In many of these areas, utilities, electric
cooperatives, and municipalities have a history of joint ownership of
coal-fired generation outside the region or contracting with coal and
other generation in outside areas to meet their demand. Some of the
relevant areas are in RTOs \414\ which engage in planning across the
RTO, balancing supply and demand in real time throughout the RTO.
Accordingly, generating resources in one part of the RTO such as a coal
generator can serve load in other parts of the RTO, as well as load
outside of the RTO. As we consider each of these geographic areas in
the Geographic Availability TSD, we make key points as to why this
final rule does not negatively impact the ability of these regions to
access new coal generation to the extent that coal is needed to supply
demand and/or those regions want to include new coal-fired generation
in their resource mix.
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\414\ In this discussion, we use the term RTO to indicate both
ISOs and RTOs.
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N. Final Requirements for Disposition of Captured CO2
This section discusses the different regulatory components, already
in place, that assure the safety and effectiveness of GS. This section,
by demonstrating that GS is already covered by an effective regulatory
structure, complements the analysis of the technical feasibility of GS
contained in Sec. V.M. Together, these sections affirm that the
technical feasibility of GS is adequately demonstrated.
In 2010, the EPA finalized an effective and coherent regulatory
framework to ensure the long-term, secure and safe storage of large
volumes of CO2. The EPA developed these Underground
Injection Control (UIC) Class VI well regulations under authority of
the Safe Drinking Water Act (SDWA) to facilitate injection of
CO2 for GS, while protecting human health and the
environment by ensuring the protection of underground sources of
drinking water (USDWs). The Class VI regulations are built upon 35
years of federal experience regulating underground injection wells, and
many additional years of state UIC program expertise. The EPA and
states have decades of UIC experience with the Class II program, which
provides a regulatory framework for the protection of USDWs for
CO2 injected for purposes of EOR.
In addition, to complement both the Class VI and Class II rules,
the EPA used CAA authority to develop air-side monitoring and reporting
requirements for CO2 capture, underground injection, and
geologic sequestration through the GHGRP. Information collected under
the GHGRP provides a transparent means for the EPA and the public to
continue to evaluate the effectiveness of GS.
As explained below, these requirements help ensure that sequestered
CO2 will remain in place, and, using SDWA and CAA
authorities, provide the monitoring mechanisms to identify and address
potential leakage. We note the near consensus in the public responses
to the Class VI rulemaking that saline and oil and gas reservoirs
provide ready means for secure GS of CO2.\415\
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\415\ In that rulemaking, we stated that ``most commenters
encouraged the EPA not to automatically exclude any potential
injection formations for GS at this stage of deployment.'' We added
that commenters suggested, in particular, ``that there is sufficient
technical basis and scientific evidence to allow GS in depleted oil
and gas reservoirs and in saline formations, noting that there is
consensus on how to inject into these formation types.'' 75 FR at
77252 (Dec. 10, 2010).
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1. Requirements for UIC Class VI and Class II Wells
Under SDWA, the EPA developed the UIC Program to regulate the
underground injection of fluids in a manner that ensures protection of
USDWs. UIC regulations establish six different well classes that manage
a range of injectates (e.g., industrial and municipal wastes; fluids
associated with oil and gas activities; solution mining fluids; and
CO2 for geologic sequestration) and which accommodate
varying geologic, hydrogeological, and other conditions. The standards
apply to injection into any type of formation that meets the rule's
rigorous criteria, and so apply not only to injection into deep
[[Page 64584]]
saline formations, but also can apply to injection into unmineable coal
seams and other formations. See 75 FR 77256 (Dec. 10, 2010).
The EPA's UIC regulations define the term USDWs to include current
and future sources of drinking water and aquifers that contain a
sufficient quantity of ground water to supply a public water system,
where formation fluids either are currently being used for human
consumption or that contain less than 10,000 ppm total dissolved
solids.\416\ UIC requirements have been in place for over three decades
and have been used by the EPA and states to manage hundreds of
thousands of injection wells nationwide.
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\416\ 40 CFR 144.3.
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a. Class VI Requirements
In 2010, the EPA established a new class of well, Class VI. Class
VI wells are used to inject CO2 into the subsurface for the
purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010).
This rule accounts for the unique nature of CO2 injection
for large-scale GS. Specifically, the EPA addressed the unique
characteristics of CO2 injection for GS including the large
CO2 injection volumes anticipated at GS projects, relative
buoyancy of CO2, its mobility within subsurface geologic
formations, and its corrosivity in the presence of water. The UIC Class
VI rule was developed to facilitate GS and ensure protection of USDWs
from the particular risks that may be posed by large scale
CO2 injection for purposes of long-term GS. The Class VI
rule establishes technical requirements for the permitting, geologic
site characterization, area of review (i.e., the project area) and
corrective action, well construction, operation, mechanical integrity
testing, monitoring, well plugging, post-injection site care, site
closure, and financial responsibility for the purpose of protecting
USDWs.\417\ Notably:
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\417\ The Class VI rule rests on a robust technical and
scientific foundation, reflecting scientific oversight and peer
review. In developing these Class VI rules, the EPA engaged with the
SAB, providing detailed information on key issues relating to
geologic sequestration--including monitoring schemes; methods to
predict and verify capacity, injectivity, and effectiveness of
subsurface CO2 storage; and characterization and
management of risks associated with plume migration and pressure
increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B42B75D9E36D85257704004882CF?OpenDocument. In
addition, the EPA developed a peer reviewed Vulnerability Evaluation
Framework, which served as a technical support document for both the
Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF-Technical_Document_072408.pdf. In the section 111(b) rulemaking
here, the SAB Work Group, in a letter endorsed by the full SAB
Committee, found that ``while the scientific and technical basis for
carbon storage provisions is new and emerging science, the agency is
using the best available science and has conducted peer review at a
level required by agency guidance.'' Memorandum of Jan. 7, 2014,
from SAB Work Group Chair to Members of the Chartered SAB and SAB
Liaisons, p. 3. The letter was subsequently endorsed by the full
SAB. Work Group Letter of Jan. 24, 2014, as edited by the full
Committee.
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Site characterization includes assessment of the geologic,
hydrogeologic, geochemical, and geomechanical properties of a proposed
GS site to ensure that Class VI wells are sited in appropriate
locations and CO2 streams are injected into suitable
formations with a confining zone or zones free of transmissive faults
or fractures to ensure USDW protection.418 419 Site
characterization is designed to eliminate unacceptable sites that may
pose risks to USDWs. Generally, injection of CO2 for GS
should occur beneath the lowermost formation containing a USDW.\420\ To
increase the availability of Class VI sites in geographic areas with
very deep USDWs, waivers from the injection depth requirements may be
sought where owners or operators can demonstrate USDW protection.\421\
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\418\ 75 FR 77240 and 75 FR 77247 (December 10, 2010).
\419\ 40 CFR 146.82 and 146.83. Comments indicating that EPA
rules have not considered issues of exposure pathways such as
abandoned wells or formation fissures are mistaken. (See, e.g.,
Comments of UARG, p. 52 (Docket entry: EPA-HQ-OAR-2013-0495-9666).)
\420\ 40 CFR 146.81(d).
\421\ 40 CFR 146.95.
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Owners or operators of Class VI wells must delineate the project
area of review using computational modeling that accounts for the
physical and chemical properties of the injected CO2 and
displaced fluids and is based on an iterative process of available site
characterization, monitoring, and operational data.\422\ Within the
area of review, owners or operators must identify and evaluate all
artificial penetrations to identify those that need corrective action
to prevent the movement of CO2 or other fluids into or
between USDWs.423 424 Due to the potentially large size of
the area of review for Class VI wells, corrective actions may be
conducted on a phased basis during the lifetime of the project.\425\
Periodic reevaluation of the area of review is required and enables
owners or operators to incorporate previously collected monitoring and
operational data to verify that the CO2 plume and the
associated area of elevated pressure are moving as predicted within the
subsurface.\426\
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\422\ 40 CFR 146.84(a).
\423\ 40 CFR 146.84(c)(1)(3) and 146.90(d)(1).
\424\ 40 CFR 146.81(d) and 146.84.
\425\ 40 CFR 146.84(b)(2)(iv).
\426\ 40 CFR 146.84(e)(1).
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Well construction must use materials that can withstand contact
with CO2 over the operational and post-injection life of the
project.\427\ These requirements address the unique physical
characteristics of CO2, including its buoyancy relative to
other fluids in the subsurface and its potential corrosivity in the
presence of water.
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\427\ 40 CFR 146.86(b).
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Requirements for operation of Class VI injection wells account for
the unique conditions that will occur during large-scale GS including
buoyancy, corrosivity, and high sustained pressures over long periods
of operation.428 429
---------------------------------------------------------------------------
\428\ 75 FR 77250-52 (December 10, 2010); see also id. at 77234-
35. Commenters were mistaken in asserting (without reference to
Class VI provisions) that the EPA had ignored issues relating to
CO2 properties when injected in large volumes in
supercritical state into geologic formations.
\429\ 40 CFR 146.88.
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Owners or operators of Class VI wells must develop and implement a
comprehensive testing and monitoring plan for their projects that
includes injectate analysis, mechanical integrity testing, corrosion
monitoring, ground water and geochemical monitoring, pressure fall-off
testing, CO2 plume and pressure front monitoring and
tracking, and, at the discretion of the Class VI director, surface air
and/or soil gas monitoring.\430\ Owners and operators must periodically
review the testing and monitoring plan to incorporate operational and
monitoring data and the most recent area of review reevaluation.\431\
Robust monitoring of the CO2 stream, injection pressures,
integrity of the injection well, ground water quality and geochemistry,
and monitoring of the CO2 plume and position of the pressure
front throughout injection will ensure protection of USDWs from
endangerment, preserve water quality, and allow for timely detection of
any leakage of CO2 or displaced formation fluids.
---------------------------------------------------------------------------
\430\ 40 CFR 146.90.
\431\ 40 CFR 146.90(j).
---------------------------------------------------------------------------
Although subsurface monitoring is the primary and effective means
of determining if there are any risks to a USDW, the Class VI rule also
authorizes the UIC Program Director to require surface air and/or soil
gas monitoring on a site-specific basis. For example, the Class VI
Director may require surface air/soil gas monitoring of the flux of
CO2 out of the subsurface, with elevation of CO2
levels above background serving as
[[Page 64585]]
an indicator of potential leakage and USDW endangerment.\432\
---------------------------------------------------------------------------
\432\ 40 CFR 146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010).
---------------------------------------------------------------------------
Class VI well owners or operators must develop and update a site-
specific, comprehensive emergency and remedial response plan that
describes actions to be taken (e.g., cease injection) to address
potential events that may cause endangerment to a USDW during the
construction, operation, and post-injection site care periods of the
project.\433\
---------------------------------------------------------------------------
\433\ 40 CFR 146.94.
---------------------------------------------------------------------------
Financial responsibility demonstrations are required to ensure that
funds will be available for all area of review corrective action,
injection well plugging, post-injection site care, site closure, and
emergency and remedial response.\434\
---------------------------------------------------------------------------
\434\ 40 CFR 146.85.
---------------------------------------------------------------------------
Following cessation of injection, the operator must conduct
comprehensive post-injection site care activities to show the position
of the CO2 plume and the associated area of elevated
pressure to demonstrate that neither poses an endangerment to
USDWs.\435\ The injection well also must be plugged, and following a
demonstration of non-endangerment of USDWs by the Class VI owner or
operator, the site must be closed.436 437 The default
duration for the post-injection site care period is 50 years, with
flexibility for demonstrating that an alternative period is appropriate
if it ensures non-endangerment of USDWs.\438\ Following successful
closure, the facility property deed must record that the underlying
land is used for GS.\439\
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\435\ 40 CFR 146.93.
\436\ 40 CFR 146.92.
\437\ 40 CFR 146.93.
\438\ 40 CFR 146.93(b).
\439\ 40 CFR 146.93(c).
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The EPA has completed technical guidance documents on Class VI well
site characterization, area of review and corrective action, well
testing and monitoring, project plan development, well construction,
and financial responsibility.440 441 442 443 444 445 The EPA
has also issued guidance documents on transitioning Class II wells to
Class VI wells; well plugging, post-injection site care, and site
closure; and recordkeeping, reporting, and data
management.446 447 448 449
---------------------------------------------------------------------------
\440\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13004.pdf.
\441\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13005.pdf.
\442\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13001.pdf.
\443\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11017.pdf.
\444\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11020.pdf.
\445\ http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinancialresponsibilityguidancefinal072011v.pdf.
\446\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13004.pdf. See also 40 CFR 144.19 and ``Key Principles in
EPA's Underground Injection Control Program Class VI Rule Related to
Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells
to Class VI'', April 23, 2015, Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
\447\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13005.pdf.
\448\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13001.pdf.
\449\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13002.pdf.
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To inform the development of the UIC Class VI rule, the EPA
solicited stakeholder input and reviewed ongoing domestic and
international GS research, demonstration, and deployment projects. The
EPA also leveraged injection experience of the UIC Program, such as
injection via Class II wells for EOR. A description of the work
conducted by the EPA in support of the UIC Class VI rule can be found
in the preamble for the final rule (see 75 FR 77230 and 77237-
240(December 10, 2010)).
The EPA has issued Class VI permits for six wells under two
projects. In September 2014, a UIC Class VI injection well permit (to
construct) was issued by the EPA to Archer Daniels Midland for an
ethanol facility in Decatur, Illinois. The goal of the project is to
demonstrate the ability of the Mount Simon geologic formation, a deep
saline formation, to accept and retain industrial scale volumes of
CO2 for permanent GS. The permitted well has a projected
operational period of five years, during which time 5.5 million metric
tons of CO2 will be injected into an area of review with a
radius of approximately 2 miles.\450\ Following the operational period,
Archer Daniels Midland plans a post-injection site care period of ten
years.\451\ In September 2014, the EPA also issued four Class VI
injection well permits (to construct) to the FutureGen Industrial
Alliance project in Jacksonville, Illinois, which proposed to capture
CO2 emissions from a coal-fired power plant in Meredosia,
Illinois and transport the CO2 by pipeline approximately 30
miles to the deep saline GS site.\452\ The Alliance proposed to inject
a total of 22 million metric tons of CO2 into an area of
review with a radius of approximately 24 miles over the 20-year life of
the project, with a post-injection site care period of fifty
years.\453\
---------------------------------------------------------------------------
\450\ http://www.epa.gov/region5/water/uic/adm/. In addition,
Archer Daniels Midland received a UIC Class VI injection well permit
for a second well in December 2014. Archer Daniels Midland had been
injecting CO2 at this well since 2011 under a UIC Class I
permit issued by the Illinois EPA.
\451\ http://www.epa.gov/region5/water/uic/adm/.
\452\ After permit issuance, and for reasons unrelated to the
permitting proceeding, DOE initiated a structured closeout of
federal support for the FutureGen project in February 2015. However,
these are still active Class VI permits.
\453\ http://www.epa.gov/r5water/uic/futuregen/.
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Both permit applicants addressed siting and operational aspects of
GS (including issues relating to volumes of the CO2 and
nature of the CO2 injectate), and included monitoring that
helps provide assurance that CO2 will not migrate to
shallower formations. The permits were based on findings that regional
and local features at the site allow the site to receive injected
CO2 in specified amounts without buildup of pressure which
would create faults or fractures, and further, that monitoring provides
early warning of any changes to groundwater or CO2
leakage.\454\
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\454\ http://www.epa.gov/r5water/uic/futuregen/; http://www.epa.gov/region5/water/uic/adm/.
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The permitting of these projects illustrates that permit applicants
were able to address perceived challenges to issuance of Class VI
permits. These permits demonstrate that these projects are capable of
safely and securely sequestering large volumes of CO2--
including from steam generating units--for long-term storage since the
EPA would not otherwise have issued the permits.
b. Class II Requirements
As explained in Section M.3 above, CO2 has been injected
into the subsurface via injection wells for EOR, boosting production
efficiency by re-pressurizing oil and gas reservoirs and increasing the
mobility of oil. There are decades of industry experience in operating
EOR projects. The CO2 injection wells used for EOR are
regulated through the UIC Class II program.\455\ CO2 storage
associated with Class II wells is a common occurrence and
CO2 can be safely stored where injected through Class II-
permitted wells for the purpose of enhanced oil or gas-related
recovery.
---------------------------------------------------------------------------
\455\ 40 CFR 144.6(b).
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UIC Class II regulations issued under section 1421 of SDWA provide
minimum federal requirements for site characterization, area of review,
well construction (e.g., casing and cementing), well operation (e.g.,
injection pressure), injectate sampling, mechanical integrity testing,
plugging and abandonment, financial responsibility, and reporting.
Class II wells must undergo periodic mechanical integrity testing which
will detect well construction and operational
[[Page 64586]]
conditions that could lead to loss of injectate and migration into
USDWs.
Section 1425 of SDWA allows states to demonstrate that their
program is effective in preventing endangerment of USDWs. These
programs must include permitting, inspection, monitoring, record-
keeping, and reporting components.
2. Relevant Requirements of the GHGRP
The GHGRP requires reporting of facility-level GHG data and other
relevant information from large sources and suppliers in the United
States. The final rules under 40 CFR part 60 specifically require that
if an affected EGU captures CO2 to meet the applicable
emissions limit, the EGU must report in accordance with 40 CFR part 98,
subpart PP (Suppliers of Carbon Dioxide) and the captured
CO2 must be injected at a facility or facilities that
reports in accordance with 40 CFR part 98, subpart RR (Geologic
Sequestration of Carbon Dioxide). See Sec. 60.5555(f). Taken together,
these requirements ensure that the amount of captured and sequestered
CO2 will be tracked as appropriate at project- and national-
levels, and that the status of the CO2 in its sequestration
site will be monitored, including air-side monitoring and reporting.
Specifically, subpart PP provides requirements to account for
CO2 supplied to the economy. This subpart requires affected
facilities with production process units 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 to
report the mass of CO2 captured and supplied to the
economy.\456\ CO2 suppliers are required to report the
annual quantity of CO2 transferred offsite and its end use,
including GS.\457\
---------------------------------------------------------------------------
\456\ 40 CFR 98.420(a)(1).
\457\ 40 CFR 98.426.
---------------------------------------------------------------------------
This rule finalizes amendments to subpart PP reporting
requirements, specifically requiring that the following pieces of
information be reported: (1) the electronic GHG Reporting Tool
identification (e-GGRT ID) of the EGU facility from which
CO2 was captured, and (2) the e-GGRT ID(s) for, and mass of
CO2 transferred to, each GS site reporting under subpart
RR.\458\
---------------------------------------------------------------------------
\458\ 40 CFR 98.426(h).
---------------------------------------------------------------------------
As noted, this final rule also requires that any affected EGU unit
that captures CO2 to meet the applicable emissions limit
must transfer the captured CO2 to a facility that reports
under GHGRP subpart RR. In order to provide clarity on this
requirement, the EPA reworded the proposed language under Sec.
60.5555(f) to use the phrase ``If your affected unit captures
CO2'' in place of the phrase ``If your affected unit employs
geologic sequestration''. This revision is not a change from the EPA's
initial intent.
Reporting under subpart RR is required for all facilities that have
received a Class VI UIC permit for injection of CO2.\459\
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 mass of CO2 received for injection;
develop and implement an EPA-approved monitoring, reporting, and
verification (MRV) plan; report the mass of CO2 sequestered
using a mass balance approach; and report annual monitoring
activities.460 461 462 463 Although deep subsurface
monitoring is the primary and effective means of determining if there
are any leaks to a USDW, the monitoring employed under a subpart RR MRV
Plan can be utilized, if required by the UIC Program Director, to
further ensure protection of USDWs.\464\ The subpart RR MRV plan
includes five major components:
---------------------------------------------------------------------------
\459\ 40 CFR 98.440.
\460\ 40 CFR 98.446.
\461\ 40 CFR 98.448.
\462\ 40 CFR 98.446(f)(9) and (10).
\463\ 40 CFR 98.446(f)(12).
\464\ See 75 FR at 77263 (Dec. 10, 2010).
---------------------------------------------------------------------------
A delineation of monitoring areas based on the CO2 plume
location. Monitoring may be phased in over time.\465\
---------------------------------------------------------------------------
\465\ 40 CFR 98.448(a)(1).
---------------------------------------------------------------------------
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. The
monitoring program will be designed to address the risks
identified.\466\
---------------------------------------------------------------------------
\466\ 40 CFR 98.448(a)(2).
---------------------------------------------------------------------------
A strategy for detecting and quantifying any surface leakage of
CO2 in the event leakage occurs. Multiple monitoring methods
and accounting techniques can be used to address changes in plume size
and risks over time.\467\
---------------------------------------------------------------------------
\467\ 40 CFR 98.448(a)(3).
---------------------------------------------------------------------------
An approach for establishing the expected baselines for monitoring
CO2 surface leakage. Baseline data represent pre-injection
site conditions and are used to identify potential anomalies in
monitoring data.\468\
---------------------------------------------------------------------------
\468\ 40 CFR 98.448(a)(4).
---------------------------------------------------------------------------
A summary of considerations made to calculate site-specific
variables for the mass balance equation. Site-specific variables may
include calculating CO2 emissions from equipment leaks and
vented emissions of CO2 from surface equipment, and
considerations for calculating CO2 from produced
fluids.\469\
---------------------------------------------------------------------------
\469\ 40 CFR 98.448(a)(5).
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Subpart RR provides a nationally consistent mass balance framework
for reporting the mass of CO2 that is sequestered. Certain
monitoring and operational data for a GS site is required to be
reported to the EPA annually. More information on the MRV plan and
annual reporting is available in the subpart RR final rule (75 FR
75065; December 1, 2010) and its associated technical support
document.\470\
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\470\ Technical Support Document: ``General Technical Support
Document for Injection and Geologic Sequestration of Carbon Dioxide:
Subparts RR and UU'' (Docket EPA-HQ-OAR-2009-0926), November 2010.
---------------------------------------------------------------------------
Under this final rule, any well receiving CO2 captured
from an affected EGU, be it a Class VI or Class II well, must report
under subpart RR.\471\ As explained below in Section V.N.5.a, a Class
II well's UIC regulatory status does not change because it receives
such CO2. Nor does it change by virtue of reporting under
subpart RR.
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\471\ See Sec. 60.5555(f).
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3. UIC and GHGRP Rules Provide Assurance To Prevent, Monitor, and
Address Releases of Sequestered CO2 to Air
Together the requirements of the UIC and GHGRP programs help ensure
that sequestered CO2 will remain secure, and provide the
monitoring mechanisms to identify and address potential leakage using
SDWA and CAA authorities. The EPA designed the GHGRP subpart RR
requirements for GS with consideration of UIC requirements. The
monitoring required by GHGRP subpart RR is complementary to and builds
on UIC monitoring and testing requirements. 75 FR 77263. Although the
regulations for Class VI and Class II injection wells are designed to
ensure protection of USDWs from endangerment the practical effect of
these complementary technical requirements, as explained below, is that
they also prevent releases of CO2 to the atmosphere.
The UIC and GHGRP programs are built upon an understanding of the
mechanisms by which CO2 is retained in geologic formations,
which are well understood and proven.
Structural and stratigraphic trapping is a physical trapping
mechanism that occurs when the CO2 reaches a stratigraphic
zone with low permeability (i.e., geologic confining
[[Page 64587]]
system) that prevents further upward migration.
Residual trapping is a physical trapping mechanism that occurs as
residual CO2 is immobilized in formation pore spaces as
disconnected droplets or bubbles at the trailing edge of the plume due
to capillary forces.
Adsorption trapping is another physical trapping mechanism that
occurs when CO2 molecules attach to the surfaces of coal and
certain organic rich shales, displacing other molecules such as
methane.
Solubility trapping is a geochemical trapping mechanism where a
portion of the CO2 from the pure fluid phase dissolves into
native ground water and hydrocarbons.
Mineral trapping is a geochemical trapping mechanism that occurs
when chemical reactions between the dissolved CO2 and
minerals in the formation lead to the precipitation of solid carbonate
minerals.
a. Class VI Wells
As just discussed in Section V.N.1, the UIC Class VI rule provides
a framework to ensure the safety of underground injection of
CO2 such that USDWs are not endangered. As explained below,
protection against releases to USDWs likewise assures against releases
to ambient air. Through the injection well permit application process,
the Class VI permit applicant (i.e., a prospective Class VI well owner
or operator) must demonstrate that the injected CO2 will be
trapped and retained in the geologic formation, and not migrate out of
the injection zone or the approved project area (i.e., the area of
review). To assure that CO2 is confined within the injection
zone, major components to be considered and included in Class VI
permits are site characterization, area of review delineation and
corrective action, well construction and operation, testing and
monitoring, financial responsibility, post-injection site care, well
plugging, emergency and remedial response, and site closure as
described in Section V.N.1.
Site characterization provides the foundation for successful GS
projects. It includes evaluation of the chemical and physical
mechanisms that will occur in the subsurface to immobilize and securely
store the CO2 within the injection zone over the long-term
(see above). Site characterization requires a detailed assessment of
the geologic, hydrogeologic, geochemical, and geomechanical properties
of the proposed GS site to ensure that wells are sited in suitable
locations.\472\ Data and information collected during site
characterization are used in the development of injection well
construction and operating plans; provide inputs for modeling the
extent of the injected CO2 plume and related pressure front;
and establish baseline information to which geochemical, geophysical,
and hydrogeologic site monitoring data collected over the life of the
injection project can be compared.
---------------------------------------------------------------------------
\472\ 40 CFR 146.82(a) and (c).
---------------------------------------------------------------------------
The Class VI rules contain rigorous subsurface monitoring
requirements to assure that the chosen site is functioning as
characterized. This subsurface monitoring should detect leakage of
CO2 before CO2 would reach the atmosphere. For
example, when USDWs are present, they are generally located above the
injection zone. If CO2 were to reach a USDW prior to being
released to the atmosphere, the presence of CO2 or
geochemical changes that would be caused by CO2 migration
into unauthorized zones would be detected by a UIC Class VI monitoring
program that is approved and periodically evaluated/adjusted based on
permit conditions.
Likewise, UIC Class VI mechanical integrity testing requirements
are designed to confirm that a well maintains internal and external
mechanical integrity. Continuous monitoring of the internal mechanical
integrity of Class VI wells ensures that injection wells maintain
integrity and serves as a way to detect problems with the well system.
Mechanical integrity testing provides an early indication of potential
issues that could lead to CO2 leakage from the confining
zone, providing assurance and verification that CO2 will not
reach the atmosphere.
Further assurance is provided by the regulatory requirement that
injection must cease if there is evidence that the injected
CO2 and/or associated pressure front may cause endangerment
to a USDW.\473\ Once the anomalous operating conditions are verified,
the cessation of injection, as required by UIC permits, will minimize
any risk of release to air.
---------------------------------------------------------------------------
\473\ 40 CFR 146.94(b).
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Following cessation of injection, the operator must conduct
comprehensive post-injection site care to show the position of the
CO2 plume and the associated area of elevated pressure to
demonstrate that neither poses an endangerment to USDWs--also having
the practical effect of preventing releases of CO2 to the
atmosphere. Post-injection site care includes appropriate monitoring
and other needed actions (including corrective action). The default
duration for the post-injection site care period is 50 years, with
flexibility for demonstrating that an alternative period is appropriate
if it ensures non-endangerment of USDWs.
As the EPA has found, the UIC Class VI injection well requirements
protect against releases from all exposure pathways. Specifically, the
EPA stated that the Class VI rules ``[are] specifically designed to
ensure that the CO2 (and any incidental associated
substances derived from the source materials and the capture process)
will be isolated within the injection zone.'' The EPA further stated
that ``[t]he EPA concluded that the elimination of exposure routes
through these requirements, which are implemented through a SDWA UIC
permit, will ensure protection of human health and the environment. .
.''.\474\
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\474\ 79 FR at 353 (January 3, 2014) (Final Hazardous Waste
Management System: Conditional Exclusion for Carbon Dioxide
(CO2) Streams in Geologic Sequestration Activities under
subtitle C of RCRA). See Section N.5.c below.
---------------------------------------------------------------------------
GHGRP subpart RR complements these UIC Class VI requirements.
Requirements under the UIC program are focused on demonstrating that
USDWs are not endangered as a result of CO2 injection into
the subsurface, while requirements under the GHGRP through subpart RR
enable accounting for CO2 that is geologically sequestered.
A methodology to account for potential leakage is developed as part of
the subpart RR MRV plan (see Section V.N.2). The MRV plan submitted for
subpart RR may describe (or provide by reference to the UIC permit) the
relevant elements of the UIC permit (e.g. assessment of leakage
pathways in the monitoring area) and how those elements satisfy the
subpart RR requirements. The MRV plan required under subpart RR may
rely upon the knowledge of the subsurface location of CO2
and site characteristics that are developed in the permit application
process, and operational monitoring results for UIC Class VI permitted
wells.
In summary, there are well-recognized physical mechanisms for
storing CO2 securely. The comprehensive and rigorous site
characterization requirements of the Class VI rules assure that sites
with these properties are selected. Subsurface monitoring serves to
assure that the sequestration site operates as intended, and this
monitoring continues through a post-closure period. Although release of
CO2 to air is unlikely and should be detected prior to
release by subsurface monitoring, the subpart RR air-side monitoring
and reporting regime
[[Page 64588]]
provides back up assurance that sequestered CO2 has not been
released to the atmosphere.
b. Class II Wells
The Class II rules likewise are designed to protect USDWs during
EOR operation, including the injection of CO2 for EOR. For
example, UIC Class II minimum federal requirements promulgated under
SDWA address site characterization, area of review, well construction
(e.g., casing and cementing), well operation (e.g., injection
pressure), injectate sampling, mechanical integrity testing, plugging
and abandonment, financial responsibility, and reporting. Class II
wells must undergo periodic mechanical integrity testing which will
detect well construction and operational conditions that could lead to
loss of injectate and migration into USDWs. The establishment of
maximum injection pressures, designed to ensure that the pressure in
the injection zone during injection does not initiate new fractures or
propagate existing fractures in the confining zone, prevents injection
from causing the movement of fluids into an underground source of
drinking water. The safeguards that protect USDWs also serve as an
early warning mechanism for releases of CO2 to the
atmosphere.
CO2 injected via Class II wells becomes sequestered by
the trapping mechanisms described above in this Section V.N.3. As with
Class VI wells, for Class II wells that report under subpart RR, there
is monitoring to evaluate whether CO2 used for EOR will
remain safely in place both during and after the injection period.
Subpart RR provides a CO2 accounting framework that will
enable the EPA to assess both the project-level and national efficacy
of geologic sequestration to determine whether additional requirements
are necessary and, if so, inform the design of such regulations.
c. Response to Comments
Commenters maintained that GS was not demonstrated for
CO2 captured from EGUs. In addition, commenters noted that
the volumes of captured CO2 would be considerably larger
than from existing GS sites, and could quadruple amounts injected into
Class II EOR wells. In addition to volumes of CO2 to be
injected, commenters opined on the possibility of sporadic
CO2 supply due to the nature of EGU operation.\475\
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\475\ See, e.g. Comments of Southern Company, p. 41 (Docket
entry: EPA-HQ-OAR-2013-0495-10095).
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The EPA does not agree. CO2 capture from EGUs is
demonstrated as discussed in Sections V.D and V.E. As discussed below,
the volumes of CO2 are comparable to the amounts that have
been injected at large scale commercial operations. The EPA also
disagrees that the volume of CO2 would quadruple amounts
injected into Class II EOR wells because CO2 may be
sequestered in deep saline formations, which have widespread geographic
availability (see Section M.1). The BSER determination and regulatory
impact analysis for this rule relies on GS in deep saline
formations.\476\ However, the EPA also recognizes the potential for
sequestering CO2 via EOR and allows the use of EOR as a
compliance option. According to data reported to the GHGRP,
approximately 60 million metric tons of CO2 were supplied to
EOR in the United States in 2013.\477\ Approximately 70 percent of
total CO2 supplied in the United States was produced from
geologic (natural) CO2 sources and approximately 30 percent
was captured from anthropogenic sources. CO2 pipeline
systems, such as those serving the Permian Basin, have multiple sources
of CO2 that serve to levelize the pipeline supply, thus
minimizing the effect of supply on the EOR operator.
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\476\ The EPA anticipates EOR projects may be early GS projects
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.
\477\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
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GS of anthropogenic CO2 in deep saline formations is
demonstrated. First, as explained above, the EPA has issued
construction permits under the Class VI program. It would not have done
so, and under the regulations cannot have done so, without
demonstrations that CO2 would be securely confined. One of
these projects was for a steam generating EGU.
Second, international experience with large scale commercial GS
projects has demonstrated through extensive monitoring programs that
large volumes of CO2 can be safely injected and securely
sequestered for long periods of time at volumes and rates consistent
with those expected under this rule. This experience has also
demonstrated the value and efficacy of monitoring programs to determine
the location of CO2 in the subsurface and detect potential
leakage through the presence of CO2 in the shallow
subsurface, near surface and air.
The Sleipner CO2 Storage Project is located at an
offshore gas field in the North Sea where CO2 must be
removed from the natural gas in order to meet customer requirements and
reduce costs. The project began injecting CO2 into the deep
subsurface in 1996. The single offshore injection well injects
approximately 1 million metric tons per year into a thick, permeable
sandstone above the gas producing zone. Approximately 15 million metric
tons of CO2 have been injected since inception. Many US and
international organizations have conducted monitoring at Sleipner. The
location and dimensions of the CO2 plume have been measured
numerous times using 3-dimensional seismic monitoring since the 1994
pre-injection survey. The monitoring data have demonstrated that
although the plume is behaving differently than initially modeled due
to thin layers of impermeable shale that were not initially identified
in the reservoir model, the CO2 remains trapped in the
injection zone. Numerous other techniques have been successfully used
to monitor CO2 storage at Sleipner. The research and
monitoring at Sleipner demonstrates the value of a comprehensive
approach to site characterization, computational modeling and
monitoring, as is required under UIC Class VI rules. The experience at
Sleipner demonstrates that large volumes of CO2, of the same
order of magnitude expected for an EGU, can be safely injected and
stored in saline reservoirs over an extended period.
Sn[oslash]hvit is another large offshore CO2 storage
project, located at a gas field in the Barents Sea. Like Sleipner the
natural gas must be treated to reduce high levels of CO2 to
meet processing standards and reduce costs. Gas is transported via
pipeline 95 miles to a gas processing and liquefied natural gas plant
and the CO2 is piped back offshore for injection.
Approximately 0.7 million metric tons per year CO2 are
injected into permeable sandstone below the gas reservoir. Between 2008
and 2011, the operator observed pressure increases in the injection
formation (Tubaen Formation) greater than expected and conducted time
lapse seismic surveys and studies of the injection zone and concluded
that the pressure increase was mainly caused by a limited storage
capacity in the formation.\478\ In 2011,
[[Page 64589]]
the injection well was modified and injection was initiated in a second
interval (St[oslash] Formation) in the field to increase the storage
capacity. Approximately 3 million metric tons of CO2 have
been injected since 2008. Monitoring demonstrates that no leakage has
occurred, again demonstrating that large volumes of CO2, of
the same order of magnitude expected for an EGU, can be safely injected
and stored in deep saline formations over an extended period.
---------------------------------------------------------------------------
\478\ Grude, S. M. Landr[oslash]a, and J. Dvorkinb, 2014,
Pressure effects caused by CO2 injection in the
Tub[aring]en Fm., the Sn[oslash]hvit field. International Journal of
Greenhouse Gas Control 27 (2014) 178-187. Commenters argued that the
project had failed to sequester CO2, referring to the
initial cessation of injection. See, e.g. Comments of UARG p. 56
(Docket entry: EPA-HQ-OAR-2013-0495-9666). In fact, injection
resumed successfully, as described in the text above.
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As discussed above in Sections V.E.2.a and M, CO2 from
the Great Plains Synfuels plant in North Dakota has been injected into
the Weyburn oil field in Saskatchewan Canada since 2000. Over that time
period the project has injected more than 16 million metric tons of
CO2. It is anticipated that approximately 40 million metric
tons of CO2 will be permanently sequestered over the
lifespan of the project. Extensive monitoring by U.S. and international
partners has demonstrated that no leakage has occurred. The sources of
CO2 for EOR may vary (e.g., industrial processes, power
generation); however, this does not impact the effectiveness of EOR
operations (see Section V.M.3).
CO2 used for EOR may come from anthropogenic or natural
sources. The source of the CO2 does not impact the
effectiveness of the EOR operation. CO2 capture, treatment
and processing steps provide a concentrated stream of CO2 in
order to meet the needs of the intended end use. CO2
pipeline specifications of the U.S. Department of Transportation
Pipeline Hazardous Materials Safety Administration found at 49 CFR part
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless
of the source of the CO2 and take into account
CO2 composition, impurities, and phase behavior.
Additionally, EOR operators and transport companies have specifications
to ensure related to the composition of CO2. These
requirements and specifications ensure EOR operators receive a known
and consistent CO2 stream.
At the In Salah CO2 storage project in Algeria,
CO2 is removed from natural gas produced at three nearby gas
fields in order to meet export quality specification. The
CO2 is transported by pipeline approximately 3 miles to the
injection site. Three horizontal wells are used to inject the
CO2 into the down-dip aquifer leg of the gas reservoir
approximately 6,200 feet deep. Between 2004 and 2011 over 3.8 million
metric tons of CO2 were stored. Injection rates in 2010 and
2011 were approximately 1 million metric tons per year. Storage
integrity has been monitored by several U.S. and international
organizations and the monitoring program has employed a wide range of
geophysical and geochemical methods, including time lapse seismic,
microseismic, wellhead sampling, tracers, down-hole logging, core
analysis, surface gas monitoring, groundwater aquifer monitoring and
satellite data. The data have been used to support periodic risk
assessments during the operational phase of the project. In 2010 new
data from seismic, satellite and geomechanical models were used to
inform the risk assessment and led to the decision to reduce
CO2 injection pressures due to risk of vertical leakage into
the lower caprock, and risk of loss of well integrity. The caprock at
the site consisted of main caprock units, providing the primary seal,
and lower caprock units, providing additional buffers. There was no
leakage from the well or through the caprock, but the risk analysis
identified an increased risk of leakage, therefore, the aforementioned
precautions were taken. Additional analysis of the reservoir, seismic
and geomechanical data led to the decision to suspend CO2
injection in June 2011. No leakage has occurred and the injected
CO2 remains safely stored in the subsurface. The decision to
proceed with safe shutdown of injection resulted from the analysis of
seismic and geomechanical data to identify and respond to storage site
risk. The In Salah project demonstrates the value of developing an
integrated and comprehensive set of baseline site data prior to the
start of injection, and the importance of regular review of monitoring
data. Commenters also noted that the data collection and analysis had
proven effective at preventing any release of sequestered
CO2 to either underground drinking water sources or to the
atmosphere.\479\
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\479\ ``It is important to note that although the In Salah
project is no longer injecting CO2, the CCS community
still views this early saline project as a success because the
monitoring program served its intended purpose. That is, the
monitoring methods deployed at this site informed the operator of a
potential problem, leading to a shutdown of CO2 injection
before the Caprock was breached.'' Comment of EPRI, p. 14 Docket
entry: EPA-HQ-OAR-2013-0495-8925).
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These projects demonstrate that sequestration of CO2
captured from industrial operations has been successfully conducted on
a large scale and over relatively long periods of time. The volumes of
captured CO2 are within the same order of magnitude as that
expected from EGUs. Even though potentially adverse conditions were
identified at some projects (In Salah and Sn[oslash]hvit), there were
no releases to air and the monitoring systems were effective in
identifying the issues in a timely manner, and these issues were
addressed effectively. In each case, the site-specific characteristics
were evaluated on a case-by-case basis to select a site where the
geologic conditions are suitable to ensure long-term, safe storage of
CO2. Each project was designed to address the site-specific
characteristics and operated to successfully inject CO2 for
safe storage.
4. Must the standard of performance for CO2 include CAA
requirements on the sequestration site?
One commenter maintained as a matter of law that a standard
predicated on use of CCS is not a ``system of emission reduction'', and
therefore is not a ``standard of performance'' within the meaning of
section 111 (a)(1) of the Act. The commenter argued that the standard
does not require sequestration of captured CO2 but only
capture, so that no emission reductions are associated with the
standard. A gloss on this argument is that there are no enforceable
requirements for the captured CO2 (``[t]he fate of that
[captured] CO2 is something that the proposed standard does
not proscribe with enforceable requirements''). The commenter further
argues that a ``system of emission reduction'' under section 111 must
be ``designed into the new source itself'' so that off-site underground
sequestration of captured CO2 emissions ``could never
satisfy the statutory requirements governing a `standard of
performance''' (emphasis original).\480\
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\480\ Comments of UARG, pp. 37-38 (Docket entry: EPA-HQ-OAR-
2013-0495-9666).
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The EPA disagrees with both the legal and factual assertions in
this comment. As to the legal point, the commenter fails to distinguish
capture and sequestration of carbon from every other section 111
standard which is predicated on capture of a pollutant. Indeed, all
emission standards not predicated on outright pollutant destruction
involve capture of the pollutant and its subsequent disposition in the
capturing medium. Thus, metals are captured in devices like baghouses
or scrubbers, leaving a solid waste or wastewater to be managed. Gases
can be captured with activated carbon or under pressure, again
requiring further management of the captured pollutant(s). The EPA is
required to consider these potential implications in promulgating an
NSPS. See section 111(a)(1) (in promulgating a standard of performance
under section 111, the EPA must ``tak[e] into account . . . any nonair
quality health and environmental
[[Page 64590]]
impact''). The EPA thus considers such issues as solid waste and
wastewater generation as part of determining if a system of emission
reduction is ``best'' and ``adequately demonstrated'' under section
111. See Section V.O below (discussion of this rule's potential cross-
media impacts).
The further comment that the standard is arbitrary because it fails
to impose any requirements on the captured CO2 is misplaced.
The commenter mischaracterizes the standard as requiring capture only.
The BSER is not just capturing a certain amount of CO2, but
sequestering it. Sequestration can occur either on-site or off-site.
Sequestration sites receiving and injecting the captured CO2
are required to obtain UIC permits and report under subpart RR of the
GHGRP. They must conduct comprehensive monitoring as part of these
obligations. Although the NSPS does not impose regulatory requirements
on the transportation pipeline or the sequestration site, such
requirements already exist under other regulatory programs of the
Department of Transportation and the EPA. In particular, the EPA is
reasonably relying on the already-adopted, and very rigorous, Class VI
well requirements in combination with the subpart RR requirements to
provide secure sequestration of captured CO2. The EPA has
also considered carefully the requirements and operating history of the
Class II requirements for EOR wells, which, in combination with the
subpart RR requirements, ensure protection of USDWs from endangerment,
provide the monitoring mechanisms to identify and address potential
leakage using SDWA and CAA authorities, and have the practical effect
of preventing releases of CO2 to the atmosphere. This is
analogous to the many section 111 standards of performance for metals
which result in a captured air pollution control residue to be disposed
of pursuant to waste management requirements of the rules implementing
the Resource Conservation and Recovery Act. It is also analogous to the
many section 111 standards of performance for metals or organics
captured in wet air pollution control systems resulting in wastewater
discharged to a navigable water where pollutant loadings are controlled
under rules implementing the Clean Water Act. Again, these are non-air
environmental impacts for which the EPA must account in establishing a
section 111(a) standard. The EPA has reasonably done so here based on
the regulatory regimes of the Class VI and Class II UIC requirements in
combination with the monitoring regime of the subpart RR reporting
rules, as well as the CO2 pipeline standards of the
Department of Transportation.
In this regard, the EPA notes that at proposal it acknowledged the
possibility ``that there can be downstream losses of CO2
after capture, for example during transportation, injection or
storage.'' 79 FR at 1484. Given the rigorous substantive requirements
and the monitoring required by the Class VI rules, the complementary
monitoring regime of the subpart RR MRV plan and reporting rules, as
well as the regulatory requirements for Class II wells, any such losses
would be de minimis. Indeed, the same commenter maintained that the
monitoring requirements of the Class VI rule are overly stringent and
that a 50-year post-injection site care period is unnecessarily
long.\481\ As it happens, as noted above, the Class VI rules allow for
an alternative post-injection site care period based on a site-specific
demonstration. See 40 CFR 146.93(b).
---------------------------------------------------------------------------
\481\ Comments of UARG, p. 63 (Docket entry: EPA-HQ-OAR-2013-
0495-9666).
---------------------------------------------------------------------------
The EPA addresses this comment in more detail in Chapter 2 of the
Response-to-Comment Document.
5. Other Perceived Obstacles to Geologic Sequestration
a. Class II to Class VI transition
A number of commenters maintained that the Class VI rules could
effectively force all Class II wells to transition to Class VI wells if
they inject anthropogenic CO2, and further maintained that,
as a practical matter, this would render EOR unavailable for such
CO2. The EPA disagrees with these comments. Injection of
anthropogenic CO2 into Class II wells does not force
transition of these wells to Class VI wells--not during the well's
active operation and not when EOR operations cease. We recognize the
widespread use of EOR and the expectation that injected CO2
can remain underground. The EPA issued a memorandum to its regional
offices on April 23, 2015 reflecting these principles: \482\
---------------------------------------------------------------------------
\482\ ``Key Principles in EPA's Underground Injection Control
Program Class VI Rule Related to Transition of Class II Enhanced Oil
Recovery or Gas Recovery Wells to Class VI'', April 23, 2015.
Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
---------------------------------------------------------------------------
Geologic storage of CO2 can continue to be permitted
under the UIC Class II program.
Use of anthropogenic CO2 in EOR operations does not
necessitate a Class VI permit.
Class VI site closure requirements are not required for Class II
CO2 injection operations.
EOR operations that are focused on oil or gas production will be
managed under the Class II program. If oil or gas recovery is no longer
a significant aspect of a Class II permitted EOR operation, the key
factor in determining the potential need to transition an EOR operation
from Class II to Class VI is increased risk to USDWs related to
significant storage of CO2 in the reservoir, where the
regulatory tools of the Class II program cannot successfully manage the
risk.\483\
---------------------------------------------------------------------------
\483\ In this regard, the Class VI rules provide that, owners or
operators that are injecting carbon dioxide for the primary purpose
of long-term storage into an oil and gas reservoir must apply for
and obtain a Class VI geologic sequestration permit when there is an
increased risk to USDWs compared to Class II operations. 40 CFR
144.19.
---------------------------------------------------------------------------
b. GHGRP Subpart RR
A number of commenters maintained that no EOR operator would accept
captured carbon from an EGU due to the reporting and other regulatory
burdens imposed by the monitoring requirements of GHGRP subpart
RR.\484\ They noted that preparing a subpart RR MRV plan could cost
upwards of $100,000 which would be cost prohibitive given other
available sources of CO2.
---------------------------------------------------------------------------
\484\ See e.g., comments of UARG, p, 63 (Docket entry: EPA-HQ-
OAR-2013-0495-9666); Southern Co., p. 37 (Docket entry: EPA-HQ-OAR-
2013-0495-10095); American Petroleum Institute pp. 40-50 Docket
entry: EPA-HQ-OAR-2013-0495-10098).
---------------------------------------------------------------------------
The EPA disagrees with this comment in several respects. First, the
BSER determination and regulatory impact analysis for this rule relies
on GS in deep saline formations, not on EOR. However, the EPA also
recognizes the potential for sequestering CO2 via EOR, but
disagrees that subpart RR requirements effectively preclude or
substantially inhibit the use of EOR.
The cost of compliance with subpart RR is not significant enough to
offset the potential revenue for the EOR operator from the sale of
produced oil for CCS projects that are reliant on EOR. First, the costs
associated with subpart RR are relatively modest, especially in
comparison with revenues from an EOR field. In the economic impact
analysis for subpart RR, the EPA estimated that an EOR project with a
Class II permit would incur a first year cost of up to $147,030 to
develop an MRV plan, and an annual cost of $27,787 to maintain the
plan; the EPA estimated annual reporting and recordkeeping costs at
$13,262 per year.\485\ Monitoring costs
[[Page 64591]]
are estimated to range from $0.02 per metric ton (base case scenario)
to approximately $2 per metric ton of CO2 (high scenario).
Using a range of scenarios (that included high end estimates), these
subpart RR costs are approximately three to four percent of estimated
revenues for an average EOR field, indicating that the costs can
readily be absorbed. 75 FR 75073.
---------------------------------------------------------------------------
\485\ Subpart RR costs are presented in 2008 US dollars.
---------------------------------------------------------------------------
Furthermore, there is a demand for new CO2 by EOR
operators, even beyond current natural sources of CO2. For
example, in an April 2014 study, DOE concluded that future development
of EOR will need to rely on captured CO2.\486\ Thus, the
argument that EOR operators will obtain CO2 from other
sources without triggering subpart RR responsibilities, which assumes
adequate supplies of CO2 from other sources, lacks
foundation. In addition, the Internal Revenue Code section 45Q provides
a tax credit for CO2 sequestration which is far greater than
subpart RR costs.\487\ In sum, the cost of complying with subpart RR
requirements, including the cost of MRV, is not significant enough to
deter EOR operators from purchasing EGU captured CO2.
---------------------------------------------------------------------------
\486\ ``Near Term Projections of CO2 Utilization for
Enhanced Oil Recovery''. DOE/NETL-2014/1648. April 2014.
\487\ http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section
45Q tax credit for calendar year 2015 is $10.92 per metric ton of
qualified CO2 that is captured and used in a qualified
EOR project and $21.85 per metric ton of qualified CO2
that is captured and used in a qualified non-EOR GS project. http://www.irs.gov/irb/2015-26_IRB/ar14.html.
---------------------------------------------------------------------------
The EPA addresses these comments in more detail in the Response to
Comment Document.
c. Conditional exclusion for geologic sequestration of CO2 streams
under the Resource Conservation and Recovery Act (RCRA)
Certain commenters voiced concerns that regulatory requirements for
hazardous wastes might apply to captured CO2 and these
requirements might be inconsistent with, or otherwise impede, GS of
captured CO2 from EGUs. The EPA has acted to remove any such
(highly conjectural) uncertainty. The Resource Conservation and
Recovery Act (RCRA) authorizes the EPA to regulate the management of
hazardous wastes. In particular, RCRA Subtitle C authorizes a cradle to
grave regulatory program for wastes identified as hazardous, whether
specifically listed as hazardous or whether the waste fails certain
tests of hazardous characteristics. The EPA currently has little
information to conclude that CO2 streams (defined in the
RCRA exclusion rule as including incidental associated substances
derived from the source materials and the capture process, and any
substances added to the stream to enable or improve the injection
process) might be identified as ``hazardous wastes'' subject to RCRA
Subtitle C regulation.\488\ Nevertheless, to reduce potential
uncertainty regarding the regulatory status of CO2 streams
under RCRA Subtitle C, and in order to facilitate the deployment of
geologic sequestration, the EPA recently concluded a rulemaking to
exclude certain CO2 streams from the RCRA definition of
hazardous waste.\489\ In that rulemaking, the EPA determined that if
any such CO2 streams would be hazardous wastes, further RCRA
regulation is unnecessary to protect human health and the environment
provided certain conditions are met. Specifically, the rule
conditionally excludes from Subtitle C regulations CO2
streams if they are (1) transported in compliance with U.S. Department
of Transportation or state requirements; (2) injected in compliance
with UIC Class VI requirements (summarized above); (3) no other
hazardous wastes are mixed with or co-injected with the CO2
stream; and (4) generators (e.g., emission sources) and Class VI well
owners or operators sign certification statements. See 40 CFR
261.4(h)).\490\ The D.C. Circuit recently dismissed all challenges to
this rule in Carbon Sequestration Council and Southern Company Services
v. EPA, No. 787 F. 3d 1129 (D.C. Cir. 2015).
---------------------------------------------------------------------------
\488\ No hazardous waste listings apply to CO2
streams. Therefore, a CO2 stream could be identified
(i.e. defined) as a hazardous waste only if it exhibits one or more
of the hazardous characteristics. 79 FR 355 (Jan 3. 2014).
\489\ 79 FR 350 (Jan. 3, 2014).
\490\ The EPA made clear in the final conditional exclusion that
that rule does not address, and is not intended to affect the RCRA
regulatory status of CO2 streams that are injected into
wells other than Class VI. However, the EPA noted in the preamble to
the final rule that (based on the limited information provided in
public comments) should CO2 be used for its intended
purpose as it is injected into UIC Class II wells for the purpose of
EOR/EGR (enhanced oil recovery/enhanced gas recovery), it is the
EPA's expectation that such an injection process would not generally
be a waste management activity. 79 FR 355. The EPA encouraged
persons to consult with the appropriate regulatory authority to
address any fact-specific questions that they may have regarding the
status of CO2 in situations that are beyond the scope of
that rule. Id. Moreover, use of anthropogenic CO2 for EOR
is long-standing and has flourished in all of the years that EPA's
subtitle C regulations (which among other things, define what a
solid waste is for purposes of those regulations) have been in
place. The RCRA subtitle C regulatory program consequently has not
been an impediment to use of anthropogenic CO2 for EOR.
---------------------------------------------------------------------------
d. Other perceived uncertainties
Other commenters claimed that various legal uncertainties preclude
a finding that geologic sequestration of CO2 from EGUs can
be considered to be adequately demonstrated. Many of the issues
referred to in comments relate to property rights: issues of ownership
of pore space, relationship of sequestration to ownership of mineral
rights, issues of dealing with multiple landowners, lack of state law
frameworks, or competing, inconsistent state laws.\491\ Other
commenters noted the lack of long-term liability insurance, and noted
uncertainties regarding long-term liability generally.\492\
---------------------------------------------------------------------------
\491\ See e.g. Comments of Duke Energy, p. 28 Docket entry: EPA-
HQ-OAR-2013-0495-9426); UARG, p. 62 (Docket entry: EPA-HQ-OAR-2013-
0495-9666); AEP, p. 91 (Docket entry: EPA-HQ-OAR-2013-0495-10618).
\492\ See e.g. Comments of UARG, pp. 26 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), 62; EEI, p. 92 Docket entry: EPA-HQ-OAR-2013-
0495-9780); Duke Energy, pp. 27, 28 Docket entry: EPA-HQ-OAR-2013-
0495-9426).
---------------------------------------------------------------------------
An IPCC special report on CCS found that with an appropriate site
selection, a monitoring program, a regulatory system, and the
appropriate use of remediation methods, the risks of GS would be
comparable to risks of current activities, such as EOR, acid gas
injection and underground natural gas storage.\493\ Furthermore, an
interagency CCS task force examined GS-related legal issues thoroughly
and concluded that early CCS projects can proceed under the existing
legal framework with respect to issues such as property rights and
liability.\494\ As noted earlier, both the Archer Daniels Midland (ADM)
and FutureGen projects addressed siting and operational aspects of GS
(including issues relating to volumes of the CO2 and the
nature of the CO2 injectate) in their permit applications.
The fact that these applicants pursued permits indicates that they
regarded any potential property rights issues as resolvable.
---------------------------------------------------------------------------
\493\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\494\ http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-2010.pdf.
---------------------------------------------------------------------------
Commenter American Electric Power (AEP) referred to its own
experience with the Mountaineer demonstration project. AEP noted that
although this project was not full scale, finding a suitable
repository, notwithstanding a generally favorable geologic area, proved
difficult. The company referred to years spent in site characterization
and digging multiple wells.\495\ Other commenters noted more generally
that site characterization issues can be time-consuming and difficult,
and quoted
[[Page 64592]]
studies suggesting that it could take 5 years to obtain a Class VI
permit.\496\
---------------------------------------------------------------------------
\495\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
\496\ See e.g. Comments of UARG, p. 55 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), citing to Cichanowitz CCS Report (2012).
---------------------------------------------------------------------------
The EPA agrees that robust site characterization and selection is
important to ensuring capacity needs are met and that the sequestered
CO2 is safely stored. Efforts to characterize geologic
formations suitable for GS have been underway at DOE through the RCSPs
since 2003 (see Section V.M). Additionally, since 2007, the USGS has
been assessing U.S. geologic storage resources for CO2. As
noted earlier, DOE, in partnership with researchers, universities, and
organizations across the country, is demonstrating that GS can be
achieved safely, permanently, and economically at large scales, and
projects supported by the department have safely and permanently stored
10 million metric tons of CO2.
In the time since the commenter submitted comments several Class VI
permits have been issued by the EPA. These projects demonstrate that a
GS site permit applicant could potentially prepare and obtain a UIC
permit concurrent with permits required for an EGU. With respect to
AEP's experience with the Mountaineer demonstration project,
notwithstanding difficulties, the company was able to successfully dig
wells, and safely inject captured CO2. Moreover, the company
indicated it fully expected to be able to do so at full scale and
explained how.\497\ The EPA notes further that a monitoring program and
its associated infrastructure (e.g., monitoring wells) and costs will
be dependent on site-specific characteristics, such as CO2
injection rate and volume, geology, the presence of artificial
penetrations, among other factors. It is thus not appropriate to
generalize from AEP's experience, and assume that other sites will
require the same number of wells for site characterization or
injection. In this regard, we note that the ADM and FutureGen
construction permits for Class VI wells involved far fewer injection
wells than AEP references.\498\ See also discussion of this issue in
Section V.I.5 above.
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\497\ See AEP FEED Study at pp. 36-43. The company likewise
explained the monitoring regime it would utilize to verify
containment, and the well construction it would utilize to guarantee
secure sequestration. Id. at pp. 44-54. Available at:
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
\498\ The FutureGen UIC Class VI injection well permits (four in
total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/. The Archer Daniels Midland UIC Class VI injection
well permit issued in September 2014 (CCS2) requires five monitoring
wells and the Archer Daniels Midland UIC Class VI injection well
permit issued in December 2014 (CCS1) was permitted with two
monitoring wells. http://www.epa.gov/region5/water/uic/adm/.
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O. Non-air Quality Impacts and Energy Requirements
As part of the determination that SCPC with partial CCS is the best
system of emission reduction adequately demonstrated, the EPA has given
careful consideration to non-air quality health and environmental
impacts and energy requirements, as required by CAA section 111 (a). We
have also considered those factors for alternative potential compliance
paths to assure that the standard does not have unintended adverse
health, environmental or energy-related consequences. The EPA finds
that neither the BSER, nor the possible alternative compliance
pathways, would have adverse consequences from either a non-air quality
impact or energy requirement perspective.
1. Transport and Sequestration of Captured CO2
As just discussed in detail, the EPA finds that the Class VI and II
rules, as complemented by the subpart RR GHGRP reporting and monitoring
requirements, amply safeguard against potential of injected
CO2 to degrade underground sources of drinking water and
amply protect against any releases of sequestered CO2 to the
atmosphere. The EPA likewise finds that the plenary regulatory controls
on CO2 pipelines assure that CO2 can be safely
conveyed without environmental release, and that these rules, plus the
complementary tracking and reporting rules in subpart RR, assure that
captured CO2 will be properly tracked and conveyed to a
sequestration site.
2. Water Use Impacts
Commenters claimed that the EPA ignored the negative environmental
impacts of the use of CCS for the mitigation of CO2
emissions from fossil fuel-fired steam generating EGUs. In particular,
commenters noted that the use of CCS will increase the water usage at
units that implement CCS to meet the proposed standard of performance.
At least one commenter claimed that addition of an amine-based CCS
system would double the consumptive water use of a power plant, which
would be unacceptable, especially in drought-ridden states and in the
arid west and referenced a study in the scientific literature as
support.\499\ The commenter also references a DOE/NETL report that
likewise notes significant increases in the amount of cooling and
process water required with the use of carbon capture technology.\500\
However, those studies discuss increased water use for cases where full
CCS (90 percent or greater capture) is implemented. As we discussed in
both the proposal and in this preamble, the EPA does not find that
highly efficient new generation technology implementing full CCS is the
BSER for new steam generating EGUs.
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\499\ See comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) referencing Haibo Zhai, et al., Water Use at
Pulverized Coal Power Plants with Post-combustion Carbon Capture and
Storage, 45 Environ. Sci. Technol., 2479-85 (2011).
\500\ Id at p. 84 referencing DOE/NETL-402/080108, ``Water
Requirements for Existing and Emerging Thermoelectric Plant
Technologies'' at 13 (Aug. 2008, Apr. 2009 revision).
---------------------------------------------------------------------------
The EPA examined water use predicted from the updated DOE/NETL
studies in order to determine the magnitude of increased water usage
for a new SCPC implementing partial CCS to meet the final standard of
1,400 lb CO2/MWh-g. The predicted water consumption for
varying levels of partial and full CCS are provided in Table 13. The
results show that a new SCPC unit that implements 16 percent partial
CCS to meet the final standard would see an increase in water
consumption (the difference between the predicted water withdraw and
discharge) of about 6.4 percent compared to an SCPC with no CCS and the
same net power output. By comparison, a unit implementing 35 percent
CCS to meet the proposed emission limitation of 1,100 lb
CO2/MWh-g would see an increase in water consumption of 16.0
percent and a new unit implementing full (90 percent) CCS would see an
increase of almost 50 percent.
Table 13--Predicted Water Consumption With Implementation of Various
Levels of Partial CCS \501\
------------------------------------------------------------------------
Raw water Increase
Technology consumption, compared to
gpm SCPC, %
------------------------------------------------------------------------
SCPC.................................... 4,095 --
[[Page 64593]]
SCPC + 16% CCS.......................... 4,359 6.4
SCPC + 35% CCS.......................... 4,751 16.0
SCPC + 90% CCS.......................... 6,069 48.2
IGCC*................................... 3,334 -18.6
IGCC + 90% CCS*......................... 4,815 17.6
------------------------------------------------------------------------
* The IGCC results presented in the DOE/NETL report are for an IGCC with
net output of 622 MWe and an IGCC with full CCS with net output of 543
MWe. The water consumption for each was normalized to 550 MWe to be
consistent with the SPCP cases.
Similar to other air pollution controls--such as a wet flue gas
desulfurization scrubber--utilization of post-combustion amine-based
capture systems results in increased consumption of water. However, by
finalizing a standard that is less stringent than the proposed
limitation and by rejecting full CCS as the BSER, the EPA has reduced
the increased amount of water needed as compared to a similar unit
without CCS. Further, the EPA notes that there are additional
opportunities to minimize the water usage at such a facility. For
example, the SaskPower Boundary Dam Unit #3 post-combustion capture
project captures water from the coal and from the combustion process
and recycles the captured water in the process, resulting in decreased
need for withdrawal of fresh water.
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\501\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (June 22, 2015).
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The EPA also examined the predicted water usage for a new IGCC and
for a new IGCC implementing 90 percent CCS. The predicted water
consumption for the new IGCC unit is nearly 20 percent less than that
predicted for the new SCPC unit without CCS (and almost 25 percent less
than the SCPC unit meeting the final standard). The EPA rejected new
IGCC implementing full CCS as BSER because the predicted costs were
significantly more than alternative technologies. The EPA also does not
find that a new IGCC EGU is part of the final BSER (for reasons
discussed in Section V.P). However, the EPA does note that IGCC is a
viable alternative compliance option and, as shown here, would result
in less water consumption than a compliant SCPC EGU. The EPA also notes
that predicted water consumption at a new NGCC unit would be less than
half that for a new SCPC EGU with the same net output.\502\
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\502\ The EPA also finds that the standards would not result in
any significant impact on solid waste generation or management. See
Section XIII.D below.
---------------------------------------------------------------------------
3. Energy Requirements
The EPA also examined the expected impacts on energy requirements
for a new unit meeting the final promulgated standard and finds impacts
to be minimal. Specifically, the EPA examined the increased auxiliary
load or parasitic energy requirements of a system implementing CCS. The
EPA examined the predicted auxiliary power demand from the updated DOE/
NETL studies in order to determine the increased energy requirement for
a new SCPC implementing partial CCS to meet the final standard of 1,400
lb CO2/MWh-g. The predicted gross power output, the
auxiliary power demand, and the parasitic power demand (percent of
gross output) are provided in Table 14 for varying levels of partial
and full CCS.
Table 14--Predicted Parasitic Power Demand With Implementation of Various Levels of Partial CCS \503\
----------------------------------------------------------------------------------------------------------------
Gross power Auxiliary Parasitic
Generation technology output, MWe power, MWe demand (%)
----------------------------------------------------------------------------------------------------------------
SCPC........................................................ 580 30 5.2
SCPC + 16% CCS.............................................. 599 38 6.3
SCPC + 35% CCS.................................................. 603 53 8.8
SCPC + 90% CCS.............................................. 642 91 14.2
IGCC........................................................ 748 126 16.8
IGCC + 90% CCS.............................................. 734 191 26.0
CCS............................................................. 734 191 26.0
----------------------------------------------------------------------------------------------------------------
The auxiliary power demand is the amount of the gross power output
that is utilized within the facility rather than used to produce
electricity for sale to the grid. The parasitic power demand (or
parasitic load) is the percentage of the gross power output that is
needed to meet the auxiliary power demand.\504\ In an SCPC EGU without
CCS, the auxiliary power is used to primarily to operate fans, motors,
pumps, etc. associated with operation of the facility and the
associated pollution control equipment. When carbon capture equipment
is incorporated, additional power is needed to operate associated
equipment, and steam is need to regenerate the capture solvents (i.e.,
the solvents are heated to release the captured CO2).
---------------------------------------------------------------------------
\503\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (June 2015).
\504\ Note that this auxiliary power demand is not necessarily
met from power or steam generated from the EGU. External sources can
also be utilized for this purpose.
---------------------------------------------------------------------------
The results in Table 14 show that a new SCPC unit without CCS can
expect a parasitic power demand of about 5.2 percent. A new SCPC unit
meeting the
[[Page 64594]]
final standard of performance by implementing 16 percent partial CCS
will see a parasitic power demand of about 6.3 percent, which is not a
significant increase in energy requirement. Of course, new SCPC EGUs
that implement higher levels of CCS will expect higher amounts of
parasitic power demand. As shown in Table 14, a new SCPC EGU
implementing full CCS would expect to utilize over 14 percent of its
gross power output to operate the facility and the carbon capture
system. But, the EPA does not find that a new SCPC implementing full
CCS is the BSER for new fossil-fired steam generating units. See
Section V.P.2 below.
The EPA also notes that there is on-going research sponsored by
DOE/NETL and others to further reduce the energy requirements of the
carbon capture systems. Progress is being made. As was mentioned
previously, the heat duty (the energy required to regenerate the
capture solvent) for the amine scrubbing process used at the Searles
Valley facility in the mid-70's was about 12 MJ/mt CO2
removed as compared to a heat duty of about 2.5 MJ/mt CO2
removed for the amine processes used at Boundary Dam and for the amine
system that will be used at the WA Parish facility.\505\
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\505\ ``From Lubbock, TX to Thompsons, TX--Amine Scrubbing for
Commercial CO2 Capture from Power Plants'', plenary
address by Prof. Gary Rochelle at the 12th International Conference
on Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------
The EPA also examined the predicted parasitic power demand for a
new IGCC and for a new IGCC implementing 90 percent CCS. As we have
noted elsewhere, the auxiliary power demand for a new IGCC unit is more
than that for that of a new SCPC. As one can see in Table 14, a new
IGCC unit can expect to see a nearly 17 percent parasitic power demand;
and a new IGCC unit implementing full CCS would expect a parasitic
power demand of nearly 30 percent. Of course, the EPA rejected new IGCC
implementing full CCS as BSER because of the potentially unreasonable
costs. The EPA also does not find that a new IGCC EGU is part of the
final BSER (for reasons discussed elsewhere in Section V.P.1 below).
However, as we have noted, the EPA does find IGCC to be a viable
alternative compliance option. Utilities and project developers should
consider the increased auxiliary power demand for an IGCC when
considering their options for new power generation. The EPA also notes
that the predicted parasitic load for a new NGCC unit would be about 2
percent--less than half that for a new SCPC EGU with the same net
output.\506\
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\506\ The EPA also finds that the standards would not result in
any significant impact on solid waste generation or management. See
Section XII.D below.
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With respect to potential nationwide impacts on energy
requirements, as described above in Section V.H.3 and more extensively
in the RIA chapter 4, the EPA reasonably projects that no new non-
compliant fossil-fuel fired steam electric capacity will be constructed
through 2022 (the end of the 8 year review cycle for NSPS). It is
possible, as described earlier, that some new sources could be built to
preserve fuel diversity, but even so, the number of such sources would
be small and therefore would not significantly impact national energy
requirements (assuming that such sources would not already be reflected
in the baseline conditions just noted).
P. Options That Were Considered by the EPA but Were Ultimately Not
Determined To Be the BSER
In light of the comments received, the EPA re-examined several
alternative systems of emission reduction and reaffirms in this
rulemaking our proposed determination that those alternatives do not
represent the ``best'' system of emission reduction when compared
against the other available emission reduction options. These are
described below. See also Section IV.B.1 above.
1. Highly Efficient Generation Technology (e.g., Supercritical or
Ultra-supercritical Boilers)
In the January 2014 proposal, we considered whether `Highly
Efficient New Generation without CCS Technology' should constitute the
BSER for new steam generating units. 79 FR at 1468-69. The discussion
focused on the performance of highly efficient generation technology
(that does not include any implementation of CCS), such as a
supercritical \507\ pulverized coal (SCPC) or a supercritical CFB
boiler, or a modern, well-performing IGCC unit.
---------------------------------------------------------------------------
\507\ 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.
---------------------------------------------------------------------------
All these options are technically feasible--there are numerous
examples of each operating in the U.S. and worldwide. However, we do
not find them to qualify as the best system for reduction of
CO2 emissions for the following reasons:
a. Lack of Significant CO2 Reductions When Compared to
Business as Usual
At the outset, we reviewed the emission rates of efficient PC and
CFB units. According to the DOE/NETL estimates, a newly constructed
subcritical PC unit firing bituminous coal would emit approximately
1,800 lb CO2/MWh-g,\508\ a new highly efficient SCPC unit
using bituminous coal would emit nearly 1,720 lb CO2/MWh-g,
and a new IGCC unit would emit about 1,430 lb CO2/MWh-
g.509 510 Emissions from comparable sources utilizing sub-
bituminous coal or lignite will have somewhat higher CO2
emissions.\511\
---------------------------------------------------------------------------
\508\ 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).
\509\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015); SCPC rates come from
Exhibit A-2 and IGCC rates come from Exhibit A-4.
\510\ The comparable emissions on a net basis are: subcritical
PC--1,890 lb CO2/MWh-n; SCPC-1,705 lb CO2/MWh-
n; and IGCC--1,724 lb CO2/MWh-n. (See same references as
for gross emissions provided in the text).
\511\ Exhibit ES-2 from ``Cost and Performance Baseline for
Fossil Energy Plants Volume 3b: Low Rank Coal to Electricity:
Combustion Cases'', Report DOE/NETL-2010/1463 (March 2011).
---------------------------------------------------------------------------
Some commenters noted that new coal-fired plants utilizing
supercritical boiler design or IGCC would provide substantial emission
reductions compared to the emissions from the existing subcritical coal
plants that are currently in wide use in the power sector. However,
most of the recent new power sector projects using solid fossil fuel
(coal or petroleum coke) as the primary fuel--both those that have been
constructed and those that have been proposed--are supercritical
boilers and IGCC units. About 60 percent of new coal-fired utility
boiler capacity that has come on-line since 2005 was supercritical and
of the new capacity that came on-line since 2010, about 70 percent was
supercritical. No new coal-fired utility boilers began operation in
either 2013 or 2014. Coal-fired power plants that have come on-line
most recently include AEP's John W. Turk, Jr. Power Plant, which is a
600 MW ultra-supercritical \512\ PC (USCPC) facility located in the
southwest corner of Arkansas, and Duke Energy's Edwardsport plant,
which is a 618 MW
[[Page 64595]]
``CCS ready'' \513\ IGCC unit located in Knox County, Indiana. Both of
those facilities came on-line in 2012. It is likely that the units that
initiated operation in 2010 or later were conceived of, planned,
designed, and permitted well before 2010--likely in the early 2000s.
Thus, it seems clear that the power sector had already, at that point,
transitioned to the selection of supercritical boiler technology as
``business as usual'' for new coal-fired power plants. Since that time,
there have been other coal-fired power plants that have been proposed
and almost all of them have been either supercritical boiler designs or
IGCC units. In Table 1 of the Technical Support Document Fossil Fuel-
Fired Boiler and IGCC EGU Projects Under Development: Status and
Approach \514\ for the January 2014 proposal, the EPA listed the
development status of ``potential transitional sources'' (i.e.,
projects that had been proposed and had received Prevention of
Significant Deterioration (PSD) preconstruction permits as of April 13,
2012). Of the 16 proposed EGU projects in Table 1--most of which have
been cancelled or converted to or replaced with NGCC projects--the
majority (nine) are either supercritical PC or IGCC designs. Five of
the proposed projects were CFB designs with only one being a
subcritical PC design.
---------------------------------------------------------------------------
\512\ Ultra-supercritical (U.S.C.) and advanced ultra-
supercritical (A-U.S.C.) are terms often used to designate a coal-
fired power plant design with steam conditions well above the
critical point.
\513\ A ``CCS ready'' facility is one that is designed such that
the CCS equipment can be more easily added at a later time.
\514\ Available in the rulemaking docket (entry: EPA-HQ-OAR-
2013-0495-0024).
---------------------------------------------------------------------------
The EPA is aware of only one new coal-fired power plant that is
actively in the construction phase. That plant is Mississippi Power's
Kemper County Energy Facility in Kemper County, MS--an IGCC unit that
plans to begin operations in 2016 and will implement partial CCS to
capture approximately 65 percent of the available CO2, which
will be sold for use in EOR operations.
Considering the direction that the power sector has been taking and
the changes that it is undergoing, identifying a new supercritical unit
as the BSER and requiring an emission limitation based on the
performance of such units thus would provide few, if any, additional
CO2 emission reductions beyond the sector's ``business as
usual''. As noted, for the most part, new sources are already designed
to achieve at least that emission limitation. This criterion does not
itself eliminate supercritical technology from consideration as BSER.
However, existing technologies must be considered in the context of the
range of technically feasible technologies and, as we discuss elsewhere
in this final preamble, partial CCS can achieve emission limitations
beyond business as usual and do so at a reasonable cost.
The EPA also considered IGCC technology and whether it represents
the BSER for new power plants utilizing coal or other solid fossil
fuels. IGCC units, on a gross-output basis, have inherently lower
CO2 emission rates when compared to similarly-sized SCPC
units. However, the net emission rates and overall emissions to the
atmosphere (i.e., tons of CO2 per year) tend to be more
similar (though still somewhat lower) for new IGCC units when compared
to new SCPC units with the same electrical output. Therefore an
emission limitation based on the expected performance of a new IGCC
unit would result in 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. A gross-output-based emission limitation consistent
with the expected performance of a new IGCC unit would still require
some additional control, such as partial CCS, on a new supercritical
boiler.
As is shown in Section V.J and H, additional emission reductions
beyond those that would result from an emission standard based on a new
SCPC boiler or even a new IGCC unit as the BSER can be achieved at a
reasonable cost. Because practicable emission controls are available
that are of reasonable cost at the source level and that will have
little cost and energy impact at the national level, the EPA is
according significant weight to the factor of amount of emissions
reductions in determining the BSER. As discussed above, the D.C.
Circuit has emphasized this factor in describing the purpose of CAA
section 111 as to achieve ``as much [emission reduction] as
practicable.'' \515\
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\515\ Sierra Club, 657 F.2d at 327 & n. 83.
---------------------------------------------------------------------------
b. Lack of Incentive for Technological Innovation
As discussed above, the EPA is justifying its identification of the
BSER based on its weighing of the factors explicitly identified in CAA
section 111(a)(1), including the amount of the emission reduction.
Under the D.C. Circuit case law, encouraging the development and
implementation of advanced control technology must also be considered
(and, in any case, may reasonably be considered; see Section V.H.3.d
above). Consideration of this factor confirms the EPA's decision not to
identify highly efficient generation technology (without CCS) as the
BSER. At present, CCS technologies are the most promising options to
achieve significant reductions in CO2 emissions from newly
constructed fossil fuel-fired steam generating units. CCS technology is
also now a viable retrofit option for some modified, reconstructed and
existing sources--depending upon the configuration, location and age of
those sources. As CCS technologies are deployed and used more there is
an expectation that, based on previous experience with advanced
technologies, the performance will improve and the implementation costs
will decline. The improved performance and lower costs will provide
additional incentive for further implementation in the future.
The Intergovernmental Panel on Climate Change (IPCC) recently
released its Fifth Assessment report, \516\ which recognizes that
widespread deployment of CCS is crucial to reach the long term climate
goals. The authors of the report used models to predict the likelihood
of stabilizing the atmospheric concentration of CO2 at 450
ppm by 2050 with or without carbon capture and storage (CCS). They
found that several of the models were not able to reach this goal
without CCS, which underlines the importance of deploying and further
developing CCS on a large scale.
---------------------------------------------------------------------------
\516\ IPCC, Working Group III, Climate Change 2014: Mitigation
of Climate Change, http://mitigation2014.org/report/publication/.
---------------------------------------------------------------------------
American Electric Power (AEP), in an evaluation of lessons learned
from the Phase 1 of its Mountaineer CCS project, wrote: ``AEP still
believes the advancement of CCS is critical for the sustainability of
coal-fired generation.'' \517\
---------------------------------------------------------------------------
\517\ CCS LESSONS LEARNED REPORT American Electric Power
Mountaineer CCS II Project Phase 1, Prepared for The Global CCS
Institute Project # PRO 004, January 23, 2012, page 2. See also AEP
FEED Study at pp. 4, 63 (same). Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------
Some commenters felt that the proposed standard of performance for
new steam generating units, based on implementation of partial CCS at
an emission rate of 1,100 lb/MWh-g, would not serve to promote the
increased deployment and implementation of CCS. The commenters argued
that such a standard could instead have the unintended result of
discouraging the further development of advanced coal generating
technologies such as ultra-supercritical boilers and improved IGCC
designs.
Commenters further argued that such a standard will stifle further
[[Page 64596]]
development of CCS technologies. Commenters felt that the standard
would effectively deter the construction of new coal-fired generation--
and, if there is no new coal-fired generation, then there will be no
implementation of CCS technology and, therefore, no need for continued
research and development of CCS technologies. They argued, in fact,
that the best way to promote the development of CCS was to set a
standard that did not rely on it.
The EPA does not agree with these arguments and, in particular,
does not see how a standard that is not predicated on performance of an
advanced control technology would serve to promote development and
deployment of that advanced control technology. On the contrary, the
history of regulatory actions has shown that emission standards that
are based on performance of advanced control equipment lead to
increased use of that control equipment, and that the absence of a
requirement stifles technology development.
There is a dramatic instance of this paradigm presented in the
present record. In 2011, AEP deferred construction of a large-scale CCS
retrofit demonstration project on one of its coal-fired power plants
because the state's utility regulators would not approve 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.\518\
---------------------------------------------------------------------------
\518\ http://www.aep.com/newsroom/newsreleases/?id=1704.
---------------------------------------------------------------------------
Some commenters also argued that the incremental cost associated
with including CCS at the proposed level would prevent new coal-fired
units from being built. Instead, they advocated for a standard based on
most efficient technology (supercritical) coupled with government
subsidies to advance and promote CCS technology. The final standard is
less stringent than that proposed, and can be met at a lower cost than
the proposed standard, and as explained above in Section V.H, the EPA
has carefully evaluated those costs and finds them to be reasonable.
Further, the record and current economic conditions (fuel costs,
renewables, demand growth, etc.) show that non-economic factors such as
a desire for fuel diversity will likely drive future development of any
new coal-fired EGUs. For this reason, the EPA does not find the
commenters' bare assertions that the incremental cost of CCS
(particularly as reasonably modulated for this final standard) would
make the difference between constructing and not constructing new coal
capacity to be persuasive. Rather, a cost-reasonable standard
reflecting use of the new technology is what will drive new technology
deployment.
The EPA expects that it is unlikely that a new IGCC unit would
install partial CCS to meet the final standard unless the facility is
built to take advantage of EOR opportunities or to operate as a poly-
generation facility (i.e., to co-produce power along with chemicals or
other products). For new IGCC units, the final standard of performance
can be met by co-firing a small amount of natural gas. Some commenters
argued that IGCC is an advanced technology that, like CCS, should be
promoted. The EPA agrees. IGCC is a low-emitting, versatile technology
that can be used for purposes beyond just power production (as
mentioned just above). Commenters further argued that a requirement to
include partial CCS (at a level to meet the proposed standard of
performance) would serve to deter--rather than promote--more
installation of IGCC technology. We disagree with a similar argument
that commenters make with respect to partial CCS for post-combustion
facilities, but our final standard moots that argument for IGCC
facilities because the final emission limitation of 1,400 lb
CO2/MWh-g will not itself deter installation of IGCC
technology, by the terms of the commenters' own argument.
2. ``Full'' Carbon Capture and Storage (i.e., 90 Percent Capture)
We also reconsidered whether the emission limitation for new coal-
fired EGUs should be based on the performance of full implementation of
CCS technology. For a newly constructed utility boiler, this would mean
that a post-combustion capture system would be used to treat the entire
flue gas stream to achieve an approximately 90 percent reduction in
CO2 emissions. For a newly constructed IGCC unit, a pre-
combustion capture system would be used to capture CO2 from
a fully shifted gasification syngas stream to achieve an approximately
90 percent reduction in CO2 emissions.
In the proposal for newly constructed sources, we found that ``full
CCS'' would certainly result in significant CO2 reductions
from any new source implementing the technology. However, we also found
that the costs associated with implementation, on either a new utility
boiler system or a new IGCC unit, are predicted to substantially exceed
the costs for other dispatchable non-NGCC generating options that are
being considered by utilities and project developers (e.g., new nuclear
plants and new biomass-fired units). See 79 FR at 1477. This remains
the case, and indeed, the difference between cost of full capture and
new nuclear technology is estimated to be even greater than at
proposal. The EPA thus is not selecting full capture CCS as BSER.
Q. Summary
The EPA finds that the best system of emission reduction adequately
demonstrated is a highly efficient supercritical pulverized coal boiler
using post-combustion partial CCS so that CO2 is captured,
compressed and safely stored over the long-term. Properly designed,
operated, and maintained, this best system can achieve a standard of
performance of 1,400 lb CO2/MWh-g, an emission limitation
that is achievable over the 12-operating-month compliance period
considering usual operating variability (including use of different
coal types, periods of startup and shutdown, and malfunction
conditions). This standard of performance is technically feasible,
given that the BSER technology is already operating reliably in full-
scale commercial application. The technology adds cost to a new
facility which the EPA has evaluated and finds to be reasonable because
the costs are in the same range as those for new nuclear generating
capacity--a competing non-NGCC, dispatchable technology that utilities
and project developers are also considering for base load application.
The EPA has also considered capital cost increases associated with use
of post-combustion partial CCS at the level needed to meet the final
standard and found them to be reasonable, and within the range of
capital cost increases for this industry in prior NSPS which have been
adjudicated as reasonable. The EPA's consideration of costs is also
informed by its judgment that new coal-
[[Page 64597]]
fired capacity would be constructed not as the most economic option,
but for such purposes as preserving fuel diversity in an energy
portfolio, and so would not be cost competitive with natural gas-fired
capacity, so that some additional cost premium may therefore be
reasonable. The EPA has carefully evaluated the non-air quality health
and environmental impacts of the final standard and found them to be
reasonable: CO2 pipelines and CO2 sequestration
via deep well injection are subject already to rigorous control under
established regulatory programs which assure prevention of
environmental release during transport and storage. In addition, water
use associated with use of partial CCS at the level to meet the final
standard is acceptable, and use of the technology does not impose
significant burdens on energy requirements at either the plant or
national level. The 1,400 lb CO2/MWh-g standard reflecting
performance of the BSER may be achieved without geographic constraint,
both because geologic sequestration and EOR capacity are widely
available and accessible, and also because alternative compliance
pathways are available in the unusual circumstance where a new coal-
fired plant is sited in an area without such access, that area has not
already limited construction of new coal-fired capacity in some way,
and the area cannot be serviced by coal-by-wire. Accordingly, the EPA
finds that the promulgated standard of performance for new fossil fuel-
fired steam electric generating units satisfies the requirements of CAA
section 111(a).
VI. Rationale for Final Standards for Modified Fossil Fuel-Fired
Electric Utility Steam Generating Units
The EPA has determined that, as proposed, the BSER for steam
generating units that trigger the modification provisions is each
affected unit's own best potential performance as determined by that
unit's historical performance. The final standards of performance are
similar to those proposed in the June 2014 proposal. Differences
between the proposed standards and the final standards issued in this
action reflect responses to comments received on the proposal. Those
changes are described below.
As noted previously, the EPA is issuing final emission standards
only for affected modified steam generating units that conduct
modifications resulting in a hourly increase in CO2
emissions (mass per hour) of more than 10 percent (``large''
modifications). The EPA is continuing to review the appropriate
standards for modified sources that conduct modifications resulting in
a hourly increase in CO2 emissions (mass per hour) of less
than or equal to 10 percent (``small'' modifications), is not issuing
final standards for those sources in this action, and is withdrawing
the proposed standards for those sources. See Section XV below.
A. Rationale for Final Applicability Criteria for Modified Steam
Generating Units
Final applicability criteria for modified steam generating EGUs
include those discussed earlier in Section III.A.1 (General
Applicability) and Section III.A.3 (Applicability Specific to Modified
Sources).
CAA section 111(a)(4) defines a ``modification'' as ``any physical
change in, or change in the method of operation of, a stationary
source'' that either ``increases the amount of any air pollutant
emitted by such source or . . . results in the emission of any air
pollutant not previously emitted.'' Certain types of physical or
operational changes are exempt from consideration as a modification.
Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action
in this final rule, and the discussion below, does not change anything
concerning what constitutes or does not constitute a modification under
the CAA or the EPA's regulations.\519\
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\519\ CAA section 111(a)(4); See also 40 CFR 60.14 concerning
what constitutes a modification, how to determine the emission rate,
how to determine an emission increase, and specific actions that are
not, by themselves, considered modifications.
---------------------------------------------------------------------------
A modified steam generating unit is a source that fits the
definition and applicability criteria of a fossil fuel-fired steam
generating unit and that commences a qualifying modification on or
after June 18, 2014 (the publication date of the proposed modification
standards). 79 FR 34960.
For the reasons discussed below, the EPA in this final action is
finalizing requirements only for steam generating units that conduct
modifications resulting in an increase in hourly CO2
emissions (mass per hour) of more than 10 percent as compared to the
source's highest hourly emission during the previous five years. With
respect to modifications with smaller increases in CO2
emissions (specifically, steam generating units that conduct
modifications resulting in an increase in hourly CO2
emissions (mass per hour) of 10 percent or less compared to the
source's highest hourly emission during the previous 5 years), the EPA
is not finalizing any standard or other requirements, and is
withdrawing the June 2014 proposal with respect to these sources (see
Section XV below).
The effect of the EPA's deferral on setting standards for sources
undertaking modifications resulting in smaller increases in
CO2 emissions and the withdrawal of the June 2014 proposal
with respect to such sources is that such sources will continue to be
existing sources and subject to requirements under section 111(d). This
is because an existing source does not always become a new source when
it modifies. Under the definition of ``new source'' in section
111(a)(2), an existing source only becomes a new source if it modifies
after the publication of proposed or final regulations that will be
applicable to it. Thus, if an existing source modifies at a time that
there is no promulgated final standard or pending proposed standard
that will be applicable to it as a modified ``new'' source, that source
is not a new source and continues to be an existing source. Here,
because the EPA is not finalizing standards for sources undertaking
modifications resulting in smaller increases in CO2
emissions and is withdrawing the proposal with respect to such sources,
these sources do not fall within the definition of ``new source'' in
section 111(a)(2) and continue to be an ``existing source'' as defined
in section 111(a)(6). See Section XV below.
As we discussed in the June 2014 proposal, the EPA has historically
been notified of only a limited number of NSPS modifications \520\
involving fossil steam generating units and therefore predicted that
very few of these units would trigger the modification provisions and
be subject to the proposed standards. Given the limited information
that we have about past modifications, the agency has concluded that it
lacks sufficient information to establish standards of performance for
all types of modifications at steam generating units at this time.
Instead, the EPA has determined that it is appropriate to establish
standards of performance at this time for larger modifications, such as
major facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that result
in substantial increases in a unit's hourly CO2 emissions
rate. The agency has determined, based on its review of public comments
and other publicly available information, that it has adequate
information regarding the types of modifications that could result in
large increases in hourly CO2 emissions, as well as on the
types of
[[Page 64598]]
measures available to control emissions from sources that undergo such
modifications, and on the costs and effectiveness of such control
measures, upon which to establish standards of performance for
modifications with large emissions increases at this time.
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\520\ NSPS modifications resulting in increases in hourly
emissions of criteria pollutants.
---------------------------------------------------------------------------
In establishing standards of performance at this time for
modifications with large emissions increases, but not for those with
small increases, the EPA is exercising its policy discretion to
promulgate regulatory requirements in a sequential fashion for classes
of modifications within a source category, accounting for the
information available to the agency, while also focusing initially on
those modifications with the greatest potential environmental impact.
This approach is consistent with the case law that authorizes agencies
to establish a regulatory framework in an incremental fashion, that is,
a step at a time.\521\
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\521\ As the U.S. Supreme Court recently stated in Massachusetts
v. EPA, 549 U.S. 497, 524 (2007): `` `Agencies, like legislatures,
do not generally resolve massive problems in one fell regulatory
swoop;' '' and instead they may permissibly implement such
regulatory programs over time, `` `refining their preferred approach
as circumstances change and as they develop a more nuanced
understanding of how best to proceed.' '' See Grand Canyon Air Tour
Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), City of Las
Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), National
Association of Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (D.C.
Cir. 1984). See also, Hazardous Waste Treatment Council v. U.S.
E.P.A., 861 F.2d 277, 287 (D.C. Cir. 1988) (``[A]n agency's failure
to regulate more comprehensively is not ordinarily a basis for
concluding that the regulations already promulgated are invalid.
`The agency might properly take one step at a time.' United States
Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the
agency's first step takes it down a path that forecloses more
comprehensive regulation, the first step is not assailable merely
because the agency failed to take a second. The steps may be too
plodding, but that raises an entirely different issue . . . .'').
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To be clear, the EPA is not reaching a final decision as to whether
it will regulate modifications with smaller increases, or even that
such modifications should be subject to different requirements than we
are finalizing in this rule for the modifications with larger
increases. We have made no decisions and this matter is not concluded.
We plan to continue to gather information, consider the options for
modifications with smaller increases, and, in the future, develop a
proposal for these modifications or otherwise take appropriate steps.
As a means of determining the proper threshold between the larger
and smaller increases in CO2 emissions, the EPA examined
changes in CO2 emissions that may result from large,
capital-intensive projects, such as major facility upgrades involving
the refurbishing or replacement of steam turbines and other equipment
upgrades that would significantly increase a unit's capacity to burn
more fossil fuel, thereby resulting in large emissions increases. Major
upgrades such as these could increase a steam generating unit's hourly
CO2 emissions by well over 10 percent.\522\
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\522\ See e.g., Power Engineering, Steam Turbine Upgrades Boost
Plant Reliability, Efficiency, available at www.power-eng.com/articles/print/volume-116/issue-11/features/steam-turbine-upgrades-boost-plant-reliability-efficiency.html.
---------------------------------------------------------------------------
An example of such major upgrade would be work performed at
AmerenUE's Labadie Plant, a facility with four 600-MW (nominal) coal-
fired units located 35 miles west of St. Louis. In the early 2000s,
plant staff conducted process improvements that raised maximum unit
capacity by nearly 10 percent (from 580 MW to 630 MW).\523\ Those
changes included boiler improvements necessitated by its switch from
bituminous to subbituminous coal,\524\ installation of low-
NOX burners, an overfire air system, and advanced computer
controls. One of the performance gains came from upgrading all four
steam turbines, which AmerenUE chose to replace as modules allowing
engineers more freedom to maximize performance unconstrained by the
units' existing outer casing.
---------------------------------------------------------------------------
\523\ ``Steam turbine upgrading: Low-hanging fruit'', Power (04/
15/2006), www.powermag.com/steam-turbine-upgrading-low-hanging-fruit.
\524\ Note that a change in coal-type or change in the use of
other raw material does not necessarily constitute an ``operational
change''. See 40 CFR 60.14(e)(4).
---------------------------------------------------------------------------
Another example is the refurbishment of the 2,100 MW Eskom Arnot
coal-fired power plant in South Africa with a resulting increase in its
power output by 300 MW to 2,400 MW--an increase in capacity of 14
percent.\525\ For each of the plant's six steam generating units, the
company conducted a complete retrofit of the high pressure and
intermediate pressure steam turbines, a capacity upgrade of the low
pressure steam turbine, and the replacement and upgrade of associated
turbine side pumps and auxiliaries. In addition, major upgrades to the
boiler plant were conducted, including supply of new pressure part
components, new burners, and modification to other equipment such as
the coal mills and classifiers, fans, and heaters. Other examples are
provided in a technical memo available in the rulemaking docket.\526\
---------------------------------------------------------------------------
\525\ www.alstom.com/press-centre/2006/10/alstom-signs-power-plant-upgrade-and-retrofit-contract-with-eskom-in-south-africa/.
\526\ See ``U.S. DOE Information Relevant to Technical Basis for
``Large Modification'' Threshold'' available in the rulemaking
docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------
The EPA does not intend to imply that these specific projects would
have resulted in an increase in hourly CO2 emissions of
greater than 10 percent. Capacity increases are often the result of
efficient improvements or are accompanied by other facility
improvements that can offset emissions increases due to increased fuel
input capacity. However, these examples are intended to show the types
of large, more capital intensive projects that can potentially result
in increases in hourly emissions of CO2 of at least 10
percent.
The EPA believes that it is reasonable to set the threshold between
``large'' modifications and ``small'' modifications at 10 percent, a
level commensurate with the magnitude of the emissions increases that
could result from the types of projects described above, and we are
issuing a final standard of performance for those sources that conduct
modifications resulting in hourly CO2 emission increases
that exceed that threshold. We are not issuing standards of performance
for those sources that conduct modifications resulting in an hourly
increase of CO2 emissions of less than or equal to 10
percent.
Therefore, the EPA is withdrawing the proposed standards for those
sources that conduct modifications resulting in a hourly increase in
CO2 emissions (mass per hour) of less than or equal to ten
percent and is not issuing final standards for those sources at this
time. See Section XV below. Utilities, states and others should be
aware that the differentiation between modifications with larger and
smaller increases in CO2 emissions only applies to sources
covered under 40 CFR part 60, subpart TTTT, i.e., it is only applicable
to CO2 emissions from fossil fuel-fired steam generating
units. There is no similar provision for criteria pollutants or for
other source categories. Utilities, states and others should also be
aware that the distinction between large and small modifications only
applies to NSPS modifications. Sources undertaking modifications may
still be subject to requirements of New Source Review under CAA Title I
part C or D (which have different standards for modifications than the
NSPS and require a case-by-case analysis) or other CAA requirements.
The EPA notes that some commenters expressed concern that a number
of existing fossil steam generating units, in order to fulfill
requirements of an approved CAA section 111(d) plan, may pursue actions
that involve physical or operational changes that result in some
increase in their CO2 emissions on an hourly basis, and thus
constitute
[[Page 64599]]
modifications. Some commenters suggested that the EPA should exempt
projects undertaken specifically for the purpose of complying with CAA
section 111(d).
The EPA does not have sufficient information at this time to
predict the full array of actions that existing steam generating units
may undertake in response to applicable requirements under an approved
CAA section 111(d) plan, or which, if any, of these actions may result
in increases in CO2 hourly emissions. Nevertheless, the EPA
expects that, to the extent actions undertaken by existing steam
generating units in response to 111(d) requirements trigger
modifications, the magnitude of the increases in hourly CO2
emissions associated with such modifications would generally be smaller
and would therefore generally not subject such modifications to the
standards of performance that the EPA is finalizing in this rule for
modified steam generating units with larger increases in hourly
CO2 emissions.
B. Identification of the Best System of Emission Reduction
The EPA has determined that, as was proposed, the BSER for steam
generating units that trigger the modification provisions is the
affected EGU's own best potential performance as determined by that
source's historical performance.
The EPA proposed that the BSER for modified steam generating EGUs
is each unit's own best potential performance based on a combination of
best operating practices and equipment upgrades. Specifically, the EPA
co-proposed two alternative standards for modified utility steam
generating units. In the first co-proposed alternative, modified steam
generating EGUs would be subject to a single emission standard
determined by the affected EGU's best demonstrated historical
performance (in the years from 2002 to the time of the modification)
with an additional 2 percent emission reduction. The EPA proposed that
the standard could be met through a combination of best operating
practices and equipment upgrades. To account for facilities that have
already implemented best practices and equipment upgrades, the proposal
also specified that modified facilities would not have to meet an
emission standard more stringent than the corresponding standard for
reconstructed EGUs.
The EPA also co-proposed that the specific standard for modified
sources would be dependent on the timing of the modification. We
proposed that sources that modify prior to becoming subject to a CAA
section 111(d) plan would be required to meet the same standard
described in the first co-proposal--that is, the modified source would
be required to meet a unit-specific emission limit determined by the
affected EGU's best demonstrated historical performance (in the years
from 2002 to the time of the modification) with an additional 2 percent
emission reduction (based on equipment upgrades). We also proposed that
sources that modify after becoming subject to a CAA section 111(d) plan
would be required to meet a unit-specific emission limit that would be
determined by the CAA section 111(d) implementing authority and would
be based on the source's expected performance after implementation of
identified unit-specific energy efficiency improvement opportunities.
The final standards in this action do not depend upon when the
modification commences (as long as it commences after June 8, 2014).
The EPA received comments on the June 2014 proposal that called into
question the need to differentiate the standard based on when the
modification was undertaken. Further, commenters noted that the
proposed requirements for sources modifying after becoming subject to a
CAA section 111(d) plan, which were based on energy efficiency
improvement opportunities were vague and that standard setting under
CAA section 111(b) is a federal duty and would require notice-and-
comment rulemaking. The EPA considered those comments and has
determined that we agree that there is no need for subcategories based
on the timing of the modification.
C. BSER Criteria
1. Technical Feasibility
The EPA based technical feasibility of the unit-specific efficiency
improvement on analyses done to support heat rate improvement for the
proposed CAA section 111(d) emission guidelines (Clean Power Plan).
That work was summarized in Chapter 2 of the TSD, ``GHG Abatement
Measures''.\527\ In response to comments on the proposed Clean Power
Plan, the approach was adjusted, as described in the final CAA section
111(d) emission guidelines. As with proposed actions, the EPA is basing
technical feasibility for final standards for modified source
efficiency improvements on the analyses for heat rate improvements for
the CAA 111(d) final rule.
---------------------------------------------------------------------------
\527\ Technical Support Documents ``GHG Abatement Measures''
(proposal) and ``GHG Mitigation Measures'' (final) available in the
rulemaking docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------
2. Cost
Any efficiency improvement made by EGUs for the purpose of reducing
CO2 emissions will also reduce the amount of fuel that EGUs
consume to produce the same electricity output. The cost attributable
to CO2 emission reductions, therefore, is the net cost of
achieving heat rate improvements after any savings from reduced fuel
expenses. As summarized below, we estimate that, on average, the
savings in fuel cost associated with a 4 percent heat rate improvement
would be sufficient to cover much of the associated costs, and thus
that the net costs of heat rate improvements associated with reducing
CO2 emissions from affected EGUs are relatively low.
We recognize that our cost analysis just described will represent
the costs for some EGUs better than others because of differences in
EGUs' individual circumstances. We further recognize that reduced
generation from coal-fired EGUs will tend to reduce the fuel savings
associated with heat rate improvements, thereby raising the effective
cost of achieving the CO2 emission reductions from the heat
rate improvements. Nevertheless, we still expect that the majority of
the investment required to capture the technical potential for
CO2 emission reductions from heat rate improvements would be
offset by fuel savings, and that the net costs of implementing heat
rate improvements as an approach to reducing CO2 emissions
from modified fossil fuel-fired EGUs are reasonable. The EPA further
notes that the types of large, more capital intensive projects that may
trigger the ``larger modifications'' threshold (i.e., result in an
hourly increase in CO2 emissions of more than 10 percent)
often are undertaken in order to increase the capacity of the source
but also to improve the heat rate or efficiency of the unit.
3. Emission Reductions
This approach would achieve reasonable reductions in CO2
emissions from the affected modified units as those units will be
required to meet an emission standard that is consistent with more
efficient operation. In light of the limited opportunities for emission
reductions from retrofits, these reductions are adequate.
4. Promotion of Technology and Other Systems of Emission Reduction
As noted previously, the case law makes clear that the EPA is to
consider
[[Page 64600]]
the effect of its selection of the BSER on technological innovation or
development, but that the EPA also has the authority to weigh this
factor, along with the various other factors. With the selection of
emissions controls, modified sources face inherent constraints that
newly constructed greenfield and even reconstructed sources do not; as
a result, modified sources present different, and in some ways more
limited, opportunities for technological innovation or development. In
this case, the standards promote technological development by promoting
further development and market penetration of equipment upgrades and
process changes that improve plant efficiency.
VII. Rationale for Final Standards for Reconstructed Fossil Fuel-Fired
Electric Utility Steam Generating Units
A. Rationale for Final Applicability Criteria for Reconstructed Sources
The applicability rationale for reconstructed utility steam
generating units is the same as for newly constructed utility steam
generating units. We are finalizing the same general criteria and not
amending the reconstruction provisions included in the general
provisions.
B. Identification of the Best System of Emission Reduction
In the proposal, the EPA evaluated seven different control
technology configurations to determine the BSER for reconstructed
fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2)
conversion to (or co-firing with) natural gas, (3) the use of CHP, (4)
hybrid power plants, (5) reductions in generation associated with
dispatch changes, renewable generation, and demand side energy
efficiency, (6) efficiency improvements achieved through the use of the
most efficient generation technology, and (7) efficiency improvements
achieved through a combination of best operating practices and
equipment upgrades.
Although the EPA concluded that the first 4 technologies met most
of the evaluation criteria, namely they are adequately demonstrated,
have reasonable costs and provide GHG emissions reductions, they were
inappropriate for BSER due to site specific constraints for existing
EGUs on a nationwide basis. We rejected best operating practices and
equipment upgrades because we concluded the GHG reductions are not
sufficient to qualify as BSER. The majority of commenters agree with
the EPA's decision that these technologies are not BSER. In contrast,
as described in more detail later in this section a few commenters did
support partial CCS as BSER.
The fifth option, reductions in generation associated with dispatch
changes, renewable generation, and demand side energy efficiency, is
comparable to application of measures identified in building blocks
two, three and four in the emissions guidelines that we proposed under
CAA section 111(d). We solicited comment on any additional
considerations that the EPA should take into account in the
applicability of building blocks two, three and four in the BSER
determination. Most commenters stated that building blocks two, three
and four should not be considered for reconstructed sources.
The proposed BSER was based on the performance of the most
efficient generation technology available, which we concluded was the
use of the best available subcritical steam conditions for small units
and the use of supercritical steam conditions for large units. We
concluded this technology to be technically feasible, to have
sufficient emission reductions, to have reasonable costs, and some
opportunity for technological innovation. The proposed emission
standard for these sources was 1,900 lb CO2/MWh-n for units
with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb
CO2/MWh-n for units with a heat input rating of 2,000 MMBtu/
h or less. The difference in the proposed standards for larger and
smaller units was based on greater availability of higher pressure/
temperature steam turbines (e.g. supercritical steam turbines) for
larger units. As explained in Section III of this preamble, we are
finalizing the standard on a gross output basis for utility steam
generating units. The equivalent gross-output-based standards are 1,800
lb CO2/MWh and 2,000 lb CO2/MWh respectively.
We solicited comment on multiple aspects of the proposed standards.
First, we solicited comment on a range of 1,600 to 2,000 lb
CO2/MWh-g for large units and 1,800 to 2,200 lb
CO2/MWh-g for small units. We also solicited comment on
whether the standards for utility boilers and IGCC units should be
subcategorized by primary fuel type. In addition, we solicited comment
on if there are sufficient alternate compliance technologies (e.g., co-
firing natural gas) that the small unit subcategory is unnecessary and
should be eliminated. Those small sources would be required to meet the
same emission standard as large utility boilers and IGCC units.
Many commenters supported the upper limits of the suggested ranges,
saying the standard will be consistently met. Some commenters raised
concerns about the achievability of these limits for the many boiler
and fuel types. A few commenters suggested that there should be
separate subcategories for coal-fired utility boilers and IGCC units,
since IGCC units have demonstrated limits closer to 1,500 lb
CO2/MWh-n and the units' designs are so fundamentally
different. Some commenters said that CFB (due to lower maximum steam
temperatures), IGCC, and traditional boilers each need their own
subcategory. Some commenters suggested that due to high moisture
content and high relative CO2 emissions of lignite, lignite-
fired units should have its own subcategory. Other commenters opposed
the proposed standards for reconstructed units because they thought the
BSER determination for reconstructed subpart Da units was inconsistent
with the BSER determination for newly constructed units. These
commenters stated that the EPA did not provide sufficient justification
for eliminating partial carbon capture and sequestration (CCS). These
commenters also stated that the reason the EPA gave for dismissing CCS
in the proposal was a lack of ``sufficient information about costs.''
These commenters hold that the cost rationale does not apply for
reconstructed coal-fired power plants. The fact that reconstructed
units may face greater costs to comply with a CAA section 111(b)
standard than new sources does not relieve them of their compliance
obligation.
Based on a review of the comments, we have concluded that both the
proposed BSER and emission standards are appropriate, and we are
finalizing the standards as proposed. Nothing in the comments changed
our view that the BSER for reconstructed steam generating units should
be based on the performance of a well operated and maintained EGU using
the most efficient generation technology available, which we have
concluded is a supercritical pulverized coal (SCPC) or supercritical
circulating fluidized bed (CFB) boiler for large units, and subcritical
for small units. As described at proposal, we have concluded that these
standards are achievable by all the primary coal types. The final
standards for reconstructed utility boilers and IGCC units is 1,800 lb
CO2/MWh-g for sources with a heat input rating of greater
than 2,000 MMBtu/h and 2,000 lb CO2/MWh-g for sources with a
heat input rating of 2,000 MMBtu/h or less.
[[Page 64601]]
While the final emission standards are based on the identified
BSER, a reconstructed EGU would not necessarily have to rebuild the
boiler to use steam temperatures and pressures that are higher than the
original design. As commenters noted, a reconstructed unit is not
required to meet the standards if doing so is deemed to be
``technologically and economically'' infeasible. 40 CFR 60.15(b). This
provision inherently requires case-by-case reconstruction
determinations in the light of considerations of economic and
technological feasibility. However, this case-by-case determination
would consider the identified BSER (the use of the best available steam
conditions), as well as--at a minimum--the first four technologies the
EPA considered, but rejected, as BSER for a nationwide rule. One or
more of these technologies could be technically feasible and reasonable
cost, depending on site specific considerations and, if so, would
likely result in sufficient GHG reductions to comply with the
applicable reconstructed standards. Finally, in some cases, equipment
upgrades and best operating practices would result in sufficient
reductions to achieve the reconstructed standards.
VIII. Summary of Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines
This section summarizes the final applicability requirements, BSER
determinations, and emission standards for newly constructed and
reconstructed stationary combustion turbines. In addition, it also
summarizes significant differences between the proposed and final
provisions.
A. Applicability Requirements
We are finalizing BSER determinations and emission standards for
newly constructed and reconstructed stationary combustion turbines that
(1) have a base load rating for fossil fuels greater than 260 GJ/h (250
MMBtu/h) and (2) serve a generator capable of selling more than 25 MW-
net of electricity to the grid. We also are finalizing applicability
requirements that will exempt from the final standards (1) all
stationary combustion turbines that are dedicated non-fossil fuel-fired
units (i.e., combustion turbines capable of combusting 50 percent or
more non-fossil fuel) and subject to a federally enforceable permit
condition restricting annual fossil fuel use to 10 percent or less of a
unit's annual heat input capacity; (2) the large majority of industrial
CHP units (i.e., CHP combustion turbines that are subject to a
federally enforceable permit condition limiting annual net-electric
sales to the product of the unit's net design efficiency multiplied by
the unit's potential output, or 219,000 MWh, whichever is greater); (3)
combustion turbines that are physically incapable of burning natural
gas (i.e., not connected to a natural gas pipeline); and (4) municipal
waste combustors and commercial or industrial solid waste incinerators
(units subject to subparts Eb or CCCC of this part).
For combustion turbines subject to an emission standard, we are
finalizing three subcategories: base load natural gas-fired units, non-
base load natural gas-fired units, and multi-fuel-fired units. We use
the term base load natural gas-fired units to refer to stationary
combustion turbines that (1) burn over 90 percent natural gas and (2)
sell electricity in excess of their design efficiency (not to exceed 50
percent) multiplied by their potential electric output. To be in this
subcategory, a stationary combustion turbine must exceed the ``natural
gas-use criterion'' on a 12-operating-month rolling average and the
``percentage electric sales'' criterion on both a 12-operating-month
and 3-year rolling average basis. We use the term non-base load natural
gas-fired units to refer to stationary combustion turbines that (1)
burn over 90 percent natural gas and (2) have net-electric sales equal
to or below their design efficiency (not to exceed 50 percent)
multiplied by their potential electric output. These criteria are
calculated on the same rolling average bases as for the base load
subcategory. Finally, we use the term multi-fuel-fired units to refer
to stationary combustion turbines that burn 10 percent or more non-
natural gas on a 12-operating-month rolling average basis. We are not
finalizing the proposed emission standards for modified sources and are
withdrawing those standards. We explain our rationale for these final
decisions in Sections IX and XV of this preamble.
B. Best System of Emission Reduction
We are finalizing BSER determinations for the three subcategories
of stationary combustion turbines referred to above: base load natural
gas-fired units, non-base load natural gas-fired units, and multi-fuel-
fired units. For newly constructed and reconstructed base load natural
gas-fired stationary combustion turbines, the BSER is the use of
efficient NGCC technology. For newly constructed and reconstructed non-
base load natural gas-fired stationary combustion turbines, the BSER is
the use of clean fuels (i.e., natural gas with an allowance for a small
amount of distillate oil). For multi-fuel-fired stationary combustion
turbines, the BSER is also the use of clean fuels (e.g., natural gas,
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2,
biodiesel, and landfill gas).
C. Final Emission Standards
For all newly constructed and reconstructed base load natural gas-
fired combustion turbines, we are finalizing an emission standard of
1,000 lb CO2/MWh-g, calculated on a 12-operating-month
rolling average basis. We are also finalizing an optional emission
standard of 1,030 lb CO2/MWh-n, calculated on a 12-
operating-month rolling average basis, for stationary combustion
turbines in this subcategory. For newly constructed and reconstructed
non-base load natural gas-fired combustion turbines, we are finalizing
a standard of 120 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. For newly constructed and
reconstructed multi-fuel-fired combustion turbines, we are finalizing a
standard of 120 to 160 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. The emission standard for multi-
fuel-fired combustion turbines co-firing natural gas with other fuels
shall be determined at the end of each operating month based on the
percentage of co-fired natural gas. Table 15 summarizes the
subcategories, BSER determinations, and emission standards for
combustion turbines.
[[Page 64602]]
Table 15--Combustion Turbine Subcategories and BSER
------------------------------------------------------------------------
Subcategory BSER Emission standard
------------------------------------------------------------------------
Base load natural gas-fired Efficient NGCC.... 1,000 lb CO2/MWh-g
combusiton turbines. or 1,030 lb CO2/
MWh-n
Non-base load natural gas-fired Clean fuels....... 120 lb CO2/MMBtu
combustion turbines.
Multi-fuel-fired combustion Clean fuels....... 120 to 160 lb CO2/
turbines. MMBtu \528\
------------------------------------------------------------------------
D. Significant Differences Between Proposed and Final Combustion
Turbine Provisions
As shown in Tables 16 and 17 below, the proposed rule included
several general applicability criteria and two subcategorization
criteria for combustion turbines. In addition to the proposed
applicability and subcategorization framework, we solicited comment on
a ``broad applicability approach'' that included most combustion
turbines irrespective of the actual amount of electricity sold to the
grid or the actual amount of natural gas burned (i.e., non-base load
units and multi-fuel-fired units, respectively). The broad
applicability approach changed the proposed ``percentage electric
sales'' and ``natural gas-use'' criteria to distinguish among
subcategory-specific emissions standards. Specifically, in the broad
applicability approach, we solicited comment on subjecting non-base
load units and multi-fuel-fired units to ``no emissions standard,''
while still including them in the general applicability. We also
solicited comment on establishing a separate numerical standard for
non-base load units. The final rule retains all of the proposed
applicability criteria in some form, but most closely tracks the broad
applicability approach by finalizing the percentage electric sales and
natural gas-use criteria as thresholds that distinguish among three
subcategories of combustion turbines with separate emissions standards.
---------------------------------------------------------------------------
\528\ The emission standard for combustion turbines co-firing
natural gas with other fuels shall be determined based on the amount
of co-fired natural gas at the end of each operating month.
---------------------------------------------------------------------------
The final rule also includes exceptions to the broad applicability
approach that we solicited comment on, with some changes that are
responsive to public comments. Categorical exceptions to the broad
applicability criteria are the exclusions for CHP units, non-fossil
fuel units, and combustion turbines not able to combust natural gas.
First, the proposed applicability criteria did not include CHP units
that were constructed for the purpose of or that actually sell one-
third or less of their potential electric output or 219,000 MWh,
whichever is greater, to the grid. The final rule eliminates the
``constructed for the purpose of'' and actual sales aspects of the
proposal and replaces them with an exemption for CHP units that take
federally enforceable permit conditions restricting net-electric sales
to a percentage of potential electric sales based on the unit's design
efficiency or 219,000 MWh, whichever is greater. Second, the proposed
applicability criteria did not include non-fossil fuel units that burn
10 percent or less fossil fuel on a 3-year rolling average. The final
rule similarly replaces the actual fuel-use aspect of the proposal with
an exemption for non-fossil fuel units that take federally enforceable
permit conditions limiting fossil-fuel use to 10 percent or less of
annual heat input capacity. Finally, the proposed applicability
criteria did not include combustion turbines that burn 90 percent or
less natural gas on a 3-year rolling average basis. In contrast, the
final rule includes most fossil fuel-fired combustion turbines
regardless of the amount of natural gas burned, with an exception for
combustion turbines that are not connected to natural gas pipelines.
Finally, in response to public comments, we are not finalizing the
subcategories for large and small combustion turbines that were
contained in the proposal. Instead, all base load natural gas-fired
combustion turbines must meet an emission standard of 1,000 lb
CO2/MWh-g.
Table 16--Proposed Applicability Criteria versus Final Applicability
Criteria
------------------------------------------------------------------------
Proposed Final
Applicability Criteria Applicability Applicability
------------------------------------------------------------------------
Base load rating criterion...... Base load rating > Base load rating >
73 MW (250 MMBtu/ 260 GJ/h \529\
h). (250 MMBtu/h)
Total electric sales criterion.. Constructed for Ability to sell >
purpose of and 25 MW-n to the
actually selling grid
> 219,000 MWh-n
to the grid.
Percentage electric sales Constructed for Changed to
criterion. purpose of and subcategorization
having actual net- criterion per
sales to the grid broad
> one-third of applicability
potential approach
electric output.
Natural gas-use criterion....... Actually burns > Changed
90 percent to
natural gas. subcategorization
criterion per
broad
applicability
approach
Exemption
for combustion
turbines that are
not connected to
a natural gas
supply
Fossil fuel-use criterion....... Actually burns > Exemption based on
10 percent fossil permit condition
fuel. limiting amount
of fossil fuel
burned to <= 10
percent of annual
heat input
capacity
Combined Heat and Power (CHP) NA................ Exemption based on
exemption. permit condition
limiting net-
electric sales to
<= design
efficiency
multiplied by
potential
electric output,
or 219,000 MWh-n,
whichever is
greater
Non-EGU exemption............... Exemption for Same as proposal
municipal solid
waste combustors
and commercial or
industrial solid
waste
incinerators.
------------------------------------------------------------------------
[[Page 64603]]
Table 17--Proposed Subcategories versus Final Subcategories
------------------------------------------------------------------------
Subcategory Proposed Criteria Final Criteria
------------------------------------------------------------------------
Small combustion turbine Base load rating NA
subcategory. <= 850 MMBtu/h.
Large combustion turbine Base load rating > NA
subcategory. 850 MMBtu/h.
Base load natural gas-fired base NA................ Actually
load combustion turbine burns > 90
subcategory. percent natural
gas
Net-
electric sales >
design efficiency
(not to exceed 50
percent)
multiplied by
potential
electric output
Non-base load natural gas-fired NA................ Actually
combustion turbine subcategory. burns > 90
percent natural
gas
Net-
electric sales <=
design efficiency
(not to exceed 50
percent)
multiplied by
potential
electric output
Multi-fuel-fired combustion NA................ Actually burns <=
turbine subcategory. 90 percent
natural gas
------------------------------------------------------------------------
IX. Rationale for Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines
This section discusses the EPA's rationale for the final
applicability criteria, BSER determinations, and standards of
performance for newly constructed and reconstructed stationary
combustion turbines. In this section, we present a summary of what we
proposed, a selection of the significant comments we received, and our
rationale for the final determinations, including how the comments
influenced our decision-making.
---------------------------------------------------------------------------
\529\ 73 MW is equivalent to 260 GJ/h. We changed units to avoid
potential confusion of MW referring to electric output rather than
heat input.
---------------------------------------------------------------------------
A. Applicability
This section describes the proposed applicability criteria,
applicability issues we specifically solicited comment on, the relevant
significant comments, and the final applicability criteria. We also
provide our rationale for finalizing applicability criteria based
strictly on design and permit restrictions rather than actual operating
characteristics. Finally, we explain why the proposed percentage
electric sales and natural gas-use applicability criteria are being
finalized instead as criteria to distinguish between separate
subcategories of stationary combustion turbines.
1. Proposed Applicability Criteria
In the January 2014 proposal, we proposed several applicability
criteria for stationary combustion turbines. Specifically, to be
subject to the proposed emission standards, we proposed that a unit
must (1) be capable of combusting more than 73 MW (250 MMBtu/h) heat
input of fossil fuel; (2) be constructed for the purpose of supplying
and actually supply more than one-third of its potential electric
output capacity to a utility power distribution system for sale (that
is, to the grid) on a 3-year rolling average; (3) be constructed for
the purpose of supplying and actually supply more than 219,000 MWh net-
electric output to the grid on a 3-year rolling average; (4) combust
over 10 percent fossil fuel on a 3-year rolling average; and (5)
combust over 90 percent natural gas on a 3-year rolling average. We
proposed exempting municipal solid waste combustors and commercial and
industrial solid waste incinerators.
Under these proposed applicability criteria, two types of
stationary combustion turbines that are currently subject to criteria
pollutant standards under subpart KKKK would not have been subject to
CO2 standards. The first type was stationary combustion
turbines that are constructed for the purpose of selling and that
actually sell one-third or less of their potential output or 219,000
MWh or less to the grid on a 3-year rolling average basis (i.e., non-
base load units). The second type was combustion turbines that actually
combust 90 percent or less natural gas on a 3-year rolling average
basis (i.e., multi-fuel-fired units).
We proposed the electric sales criteria in part because they
already exist in other regulatory contexts (e.g., the coal-fired EGU
criteria pollutant NSPS) and would promote consistency between
regulations. Our understanding at proposal was that the percentage
electric sales criterion would distinguish between non-base load units
(e.g., low capital cost, flexible, but relatively inefficient simple
cycle units) and base load units (i.e., higher capital cost, less
flexible, but relatively efficient combined cycle units).
While the proposed applicability criteria did not explicitly exempt
simple cycle combustion turbines from the emission standards, we
concluded that, as a practical matter, the vast majority of simple
cycle turbines would be excluded because they historically have
operated as peaking units and, on average, have sold less than five
percent of their potential electric output on an annual basis, well
below the proposed one-third electric sales threshold.
a. Solicitation of comment on applicability, generally
We solicited comment on a range of issues related to applicability.
In conjunction with the proposed one-third (i.e., 33.3 percent)
electric sales threshold, we solicited comment on a threshold between
20 to 40 percent of potential electric output. We also solicited
comment on a variable percentage electric sales criterion, which would
allow more efficient, lower emitting turbines to run for longer periods
of operation before becoming subject to the standards of performance.
Under this ``sliding scale'' approach, the percentage electric sales
criterion would be based on the net design efficiency of the combustion
turbine being installed. In this way, more efficient combustion
turbines would be able to sell a greater portion of their potential
electric output compared with less efficient combustion turbines before
becoming subject to an emission standard. This approach had the benefit
of incentivizing the development and installation of more efficient
simple cycle combustion turbines to serve peak load.
We also solicited comment on whether the percentage electric sales
criterion for stationary combustion turbines should be defined on a
single calendar year basis. In addition, we solicited comment on
eliminating the 219,000 MWh aspect of the total electric sales
criterion to eliminate any incentive for generators to install
multiple, small, less-efficient stationary combustion turbines that
would be exempt due to their lower output. We further solicited comment
on whether to provide an explicit exemption for all simple cycle
combustion turbines regardless of the amount of electricity sold. We
additionally solicited comment on how to implement the proposed
electric sales, fossil fuel-use, and natural
[[Page 64604]]
gas-use criteria given that they were to be evaluated as 3-year rolling
averages during the first three years of operation, and we requested
comment on appropriate monitoring, recordkeeping, and reporting
requirements. We specifically solicited comment on whether these
proposed requirements raised implementation issues because they were
based on source operation after construction has occurred.
We also solicited comment on excluding electricity sold during
system emergencies from the calculation of percentage electric sales.
The rationale for this exclusion was that simple cycle combustion
turbines intended only for peaking applications might be required to
operate above the proposed percentage electric sales threshold if a
major power plant or transmission line became unexpectedly unavailable
for an extended period of time. The EPA proposed that this flexibility
would be appropriate if the unit were called upon to run after all
other available generating assets were already running at full load.
b. Solicitation of comment on broad applicability approach
In both the January 2014 proposal for newly constructed EGUs and
the June 2014 proposal for modified and reconstructed EGUs, the EPA
solicited comment on finalizing a broad applicability approach instead
of the proposed approach. Under the proposed approach, a stationary
combustion turbine could be an affected EGU one year, but not the next,
depending on the unit's actual electric sales and the composition of
fuel burned. The broad applicability approach is consistent with
historical NSPS applicability approaches that are based on design
criteria and include different emission standards for subcategories
that are distinguished by operating characteristics. Specifically, we
solicited comment on whether we should completely remove the electric
sales and natural gas-use criteria from the general applicability
framework. Instead, the percentage electric sales and natural gas-use
thresholds would serve as subcategorization criteria for distinguishing
among classes of EGUs and subcategory-specific emissions standards.
Under this broad applicability approach, the ``constructed for the
purpose of'' component of the percentage electric sales criterion would
be completely eliminated so that applicability for combustion turbines
would be determined only by a unit's base load rating (i.e., greater
than 260 GJ/h (250 MMBtu/h)) and its capability to sell power to a
utility distribution system (i.e., serving a generator capable of
selling more than 25 MW). In contrast to the proposed applicability
criteria, under the broad applicability approach, non-base load (e.g.,
simple cycle) and multi-fuel-fired (e.g., oil-fired) combustion
turbines would remain subject to the rule regardless of their electric
sales or fuel use. We solicited comment on all aspects of this ``broad
applicability approach,'' including the extent to which it would
achieve our policy objective of assuring that owners and operators
install NGCC combustion turbines if they plan to sell more than the
specified electric sales threshold to the grid.
2. Comments on Applicability
This section summarizes the comments we received specific to each
of the proposed applicability criteria. We also received more general
comments on the scope of the proposed framework as compared to the
scope of the broad applicability approach. Comments on applicability
for dedicated non-fossil and CHP units are discussed in Section III.
a. Base load rating criterion
Many commenters supported a base load rating of 260 GJ/h (250
MMBtu/h) because it is generally consistent with the threshold used in
states participating in the Regional Greenhouse Gas Initiative (RGGI)
and under Title IV programs. Other commenters opposed the proposed
applicability thresholds and stated that all new, modified, and
reconstructed units that sell electricity to the grid, including small
EGUs and simple cycle combustion turbines, should be affected EGUs
because they would otherwise have a competitive advantage in energy
markets as they would not be required to internalize the costs of
compliance.
b. Total electric sales criterion
Commenters noted that the 219,000 MWh total electric sales
threshold put larger combustion turbines at a competitive disadvantage
by distorting the market and could have the perverse impact of
increasing CO2 emissions. These commenters noted that the
219,000 MWh total electric sales threshold would allow combustion
turbines smaller than approximately 80 MW to sell more than one-third
of their potential electric output, but larger, more efficient
combustion turbines would still be restricted to selling one-third of
their potential electric output to avoid triggering the NSPS. They
argued that this would result in a regulatory incentive for generators
to install multiple, less-efficient combustion turbines instead of
fewer, more-efficient combustion turbines and could have the unintended
consequence of increasing CO2 emissions.
c. Percentage electric sales criterion
Commenters from the power sector generally supported a complete
exemption for simple cycle turbines. These commenters stated that
simple cycle turbines are uniquely capable of achieving the ramp rates
(the rate at which a power plant can increase or decrease output)
necessary to respond to emergency conditions and hourly variations in
output from intermittent renewables. Commenters noted that simple cycle
combustion turbines serve a different purpose than NGCC power blocks.
In addition, commenters noted that electricity generation dispatch is
based on the incremental cost to generate electricity and that because
NGCC units have a lower incremental generation cost than simple cycle
units, economics will drive the use of NGCC technologies over simple
cycle units. However, commenters also stated that historic simple cycle
operating data may not be representative of future system requirements
as coal units retire, generation from intermittent renewable generation
increases, and numerous market and regulatory drivers impact plant
operations. In the absence of a complete exemption, these commenters
supported a percentage electric sales threshold between 40 to 60
percent of a unit's potential electric output.
Some commenters said that because the proposed percentage electric
sales criterion applied over a three-year period, it would adversely
affect grid reliability because operators conservatively would hedge
short-term operating decisions to ensure that they have sufficient
capacity to respond to unexpected scenarios during future compliance
periods when the demand for electricity is higher. These commenters
were concerned that such compliance decisions would drive up the cost
of electricity as the most efficient new units are taken out of service
to avoid triggering the NSPS and older, less efficient units with no
capacity factor limitations are ramped up instead.
Some commenters supported the sliding-scale approach (i.e., a
percentage electric sales threshold based on the design efficiency of
the combustion turbine) and stated that incentives for manufacturers to
develop (and end users to purchase) higher efficiency combustion
turbines could help mitigate concerns about a monolithic national
constraint on simple cycle capacity factors.
[[Page 64605]]
In contrast, others commented that fast-start NGCC units intended
for peaking and intermediate load applications can achieve comparable
ramp rates to simple cycle combustion turbines, but with lower
CO2 emission rates. These commenters said that simple cycle
turbines should be restricted to their historical role as true peaking
units and that the proposed one-third electric sales threshold provided
sufficient flexibility. Some commenters suggested that the one-third
electric sales threshold could be reduced to 20 percent or lower
without adverse impacts on grid reliability.
Commenters noted that a complete exclusion for simple cycle
turbines would create a regulatory incentive for generators to install
and operate less efficient unaffected units instead of more efficient
affected units, thereby increasing CO2 emissions. According
to these commenters, any applicability distinctions should be based on
utilization and function rather than purpose or technology.
Commenters in general supported the use of 3-year rolling averages
instead of a single-year average for the percentage and total electric
sales criteria because, in their view, the 3-year rolling averages
would provide a better overall picture of normal operations. Some
commenters stated that a rolling 12-month or calendar-year average
could be severely skewed in a given year because of unforeseen or
unpredicted events. They said that using a 3-year averaging methodology
would provide system operators with needed flexibility to dispatch
simple cycle units at higher than normal capacity factors. In contrast,
some commenters stated that, because capacity is forward-looking (e.g.,
payments for capacity are often made several years in advance), the 3-
year averaging period provides limited benefit because owner/operators
need to reserve the ability to respond to unforeseen events.
Commenters noted that potential compliance issues could result from
the inconsistent time frame between the 3-calendar-year applicability
period and the 12-operating-month compliance period. For example, a
facility could sell more than one-third of its potential electric
output over a 3-year period, but sell less than one-third of its
potential electric output during any given 12-operating-month
compliance period within that 3-year period. During a 12-operating-
month period with electric sales of less than one-third of potential
electric output, a unit could be operating for long periods at part
load and have multiple starts and stops. These operating conditions
have the potential to increase CO2 emissions, regardless of
the deign efficiency of the turbine. Therefore, a unit could have an
emission rate in excess of the proposed standard.
Regarding the relationship between the percentage electric sales
criterion and system emergencies, multiple commenters supported
exclusion of electricity generated as a result of a system emergency
from counting towards net sales. These commenters stated that the
exclusion was appropriate because the benefits of operating these units
to generate electrical power during emergency conditions would outweigh
any adverse impacts from short-term increases in CO2
emissions. One commenter stated that, in addition to declared grid
emergencies, other circumstances might warrant emergency exemption
under the rule, including extreme market conditions, limitations on
fuel supply, and reliability responses.
Multiple commenters opposed the exclusion of system emergencies
when calculating a source's percentage electric sales for applicability
purposes because NSPS must apply continuously, even during system
emergencies. These commenters stated that the EPA does not have the
authority under the CAA to suspend the applicability of a standard
during periods of system emergency. Some commenters stated that an
exclusion would be unnecessary because the EPA Assistant Administrator
for Enforcement has the authority to advise a source that the
government will not sue the source for taking certain actions during an
emergency. Commenters said that this enforcement discretion approach
has provided prompt, flexible relief that is tailored to the needs of
the particular emergency and the communities being served and is only
utilized where the relief will address the particular emergency at
hand.
Commenters added that this enforcement discretion approach is
consistent with the CAA's mandate that emission limits apply
continuously and provide safeguards against abuse. One commenter stated
that emergencies happen rarely and typically last for short periods,
that the proposed percentage electric sales threshold would allow a
source to operate at its full rated capacity for up to 2,920 hours per
year without triggering applicability, and that the potential
occurrence of grid emergencies would represent a tiny fraction of this
time. Another commenter stated that no emergency short of large scale
destruction of power generating capacity by terrorism, war, accident,
or natural disaster could justify operating a peaking unit above a 10-
percent capacity factor on a 3-year rolling average.
d. Broad applicability approach
In response to the EPA's request for comments on whether the
proposed applicability requirements that retrospectively look back at
actual events (i.e., the electric sales and fuel use criteria) would
create implementation issues, several permitting authorities opposed
the provisions because units could be subject to coverage one year but
not the next, resulting in compliance issues and difficulties in
determining proper pre-construction and operating permit conditions.
These permitting authorities suggested that in order for a source to
avoid applicability, the source should be subject to a federally
enforceable permit condition with associated monitoring, recordkeeping,
and reporting conditions for assessing applicability on an ongoing
basis. Other commenters stated that an applicability test that
concludes after construction and operation have commenced is
inconsistent with the general purpose of an applicability test--to
provide clear and predictable standards of performance for new sources
that would apply when they begin operations.
Some commenters opposed the proposed retrospective applicability
criteria related to actual output supplied during a preceding
compliance period because EGUs must know what performance standards
will apply to them during the licensing process, and such criteria do
not allow the permitting authority and the public to know in advance
whether an emission standard applies to a proposed new unit. Other
commenters said that EGUs undergoing permitting should be allowed to
request limits in their operating permit conditions in order to remain
below the applicability thresholds, as this methodology is consistent
with the pre-construction permitting requirements in many federally
approved SIPs and the current approach under the Title V permitting
program.
Many commenters stated a preference for the ``proposed
applicability approach'' over the ``broad applicability approach.''
These commenters did not think it was necessary to require non-base
load or multi-fuel-fired combustion turbines to be subject to emission
standards. They stated that there is no justification for imposing
burdensome monitoring, reporting, and recordkeeping requirements that
would have no environmental benefit (i.e., would not reduce
CO2 emissions) because these units would be subject to
[[Page 64606]]
``no emissions standards.'' Other commenters supported the broad
applicability approach and stated that all new, modified, and
reconstructed units that sell electricity to the grid, including small
EGUs, oil-fired combustion turbines, and simple cycle combustion
turbines should be affected EGUs because they would otherwise have a
competitive advantage in energy markets as they would not be required
to internalize the costs of compliance.
In contrast, to preserve the discretion of state planners under
section 111(d), many other commenters supported the broad applicability
approach and the inclusion of new simple cycle units within the scope
of the section 111(b) emission standards so that similar, existing
simple cycle units could be subject to the 111(d) standards. Numerous
other commenters stated that all units that sell electricity to the
grid should be subject to a standard, including simple cycle units,
because they view the utility grid as a single integrated system and
that doing so may simplify development of future frameworks for cost-
effective carbon reductions from existing units, such as frameworks
based on system-wide approaches.
3. Final Applicability Criteria and Rationale
Based on our consideration of the comments received related to the
proposed applicability criteria and practical implementation issues, we
are revising how those criteria will be implemented. The final
applicability criteria for combustion turbines are generally consistent
with the broad applicability approach on which we solicited comment.
Section VIII of this preamble presents each proposed applicability
criterion together with the form of the criterion in the final rule.
The final general applicability framework includes the proposed
criteria based on the combustion turbine's base load rating and the
combustion turbine's total electric sales capacity. The final general
applicability framework also includes multiple exemptions that are
relevant to combustion turbines: combustion turbines that are not
connected to natural gas pipelines; CHP facilities with federally
enforceable limits on total electric sales; dedicated non-fossil units
with federally enforceable limits on the use of fossil fuels; and
municipal waste combustors and incineration units.
The final applicability framework reflects multiple variations from
the proposal that are responsive to public comments. First, consistent
with the broad applicability approach, we are finalizing the percentage
electric sales and natural gas-use thresholds as subcategorization
criteria instead of as applicability criteria. In addition, for non-CHP
combustion turbines, we are eliminating the proposed 219,000 MWh total
electric sales criterion. Finally, we are eliminating the proposed
``constructed for the purpose of'' qualifier for the total and
percentage electric sales criteria. We are also not finalizing
CO2 standards for dedicated non-fossil fuel-fired or
industrial CHP combustion turbines. The rationale for not finalizing
CO2 standards for dedicated non-fossil and industrial CHP
units is discussed in more detail in Section III.
The EPA agrees with commenters that the NSPS applicability
framework should be structured so that permitting authorities, the
regulated community, and the public can determine what standards apply
prior to a unit having commenced construction. With this in mind, the
EPA has concluded that the proposed fossil fuel-use, natural gas-use,
percentage electric sales, and total electric sales applicability
criteria for combustion turbines are not ideal approaches. Because
applicability determinations based on these criteria could change from
year to year (i.e., units could move in and out of coverage each year
depending on actual operating parameters), some operators would not
know the extent of their compliance obligations until after the
compliance period.
Further, from a practical implementation standpoint, existing
permitting rules generally require pre-construction permitting
authorities to include enforceable conditions limiting operations such
that unaffected units will not trigger applicability thresholds. Such
conditions are often called ``avoidance'' or ``synthetic minor''
conditions, and these conditions typically include ongoing monitoring,
recordkeeping, and reporting requirements to ensure that operations
remain below a particular regulatory threshold.
The following sections provide further discussion of the final
general applicability criteria and the rationale for changing certain
proposed applicability criteria to subcategorization criteria.
a. Base load rating criterion
We are retaining the applicability criterion that a combustion
turbine must be capable of combusting more than 260 GJ/h (250 MMBtu/h)
heat input of fossil fuel. We revised the proposed 73 MW form of the
base load rating criterion to 260 GJ/h because some commenters
misinterpreted the 73 MW form (which is mathematically equivalent to
250 MMBtu/h) as the electrical output rating of the generator. This
change is a non-substantive unit conversion intended to limit
misinterpretation. While some commenters suggested that we expand this
applicability criterion to cover smaller EGUs as well, we did not
propose to cover smaller units. Because smaller units emit relatively
few CO2 emissions compared to larger units and because we
currently do not have enough information to identify an appropriate
BSER for these units, we are not finalizing CO2 standards
for smaller units.
b. Total electric sales criterion
The proposed 219,000 MWh total sales criterion was based on a 25 MW
unit operating at base load the entire year (i.e., 25 MW * 8,760 h/y =
219,000 MWh/y). This criterion was included in the original subpart Da
coal-fired EGU criteria pollutant NSPS. Coal-fired EGUs tend to be much
larger than 25 MW, and the criterion's primary purpose was to exempt
industrial CHP facilities from the criteria pollutant NSPS. In the
context of combustion turbines, however, commenters expressed concerns
that the 219,000 MWh electric sales threshold would actually encourage
owners and operators to install multiple, smaller, less-efficient
simple cycle combustion turbines instead of a single, larger, more-
efficient simple cycle turbine. The reason for this is that the 219,000
MWh threshold would allow smaller simple cycle combustion turbines of
less than 80 MW to sell significantly more electricity relative to
their potential electric output than larger turbines. Many commenters
also indicated that having the flexibility to operate a simple cycle
turbine at a higher capacity factor is important because it allows for
capacity payments from the transmission authority. In light of these
comments, we are not finalizing the 219,000 MWh total electric sales
criterion for non-CHP combustion turbines. Instead, we are finalizing a
criterion that will exempt combustion turbines that do not have the
ability to sell at least 25 MW to the grid. This approach will maintain
our goal of exempting smaller EGUs, while avoiding the perverse
environmental incentives mentioned by the commenters. As explained in
Section III, however, industrial CHP units are sized based on demand
for useful thermal output, so there is less of an incentive for owners
and operators to install multiple smaller units. Therefore, we are
maintaining the 219,000 MWh
[[Page 64607]]
total electric sales criterion for CHP units.
c. Percentage electric sales criterion
Commenters generally opposed the proposed percentage electric sales
criterion approach because it was based in part on actual electric
sales, meaning applicability could change periodically (i.e., a unit's
electric sales may change over time, rising above and falling below the
electric sales threshold). The EPA agrees this situation is not ideal.
To avoid situations in which applicability changes from year to year,
we first considered two approaches using permit restrictions. Under the
first approach, a standard would apply to all sources with permit
restrictions mandating electric sales above a threshold (i.e., an
approach that closely mirrors the proposed percentage electric sales
criterion). Under the second approach, a standard would apply to all
sources without permit restrictions limiting electric sales to a level
below that threshold (i.e., effectively identifying non-base load units
and excluding them from applicability). As stated in the proposal, we
did not think it was critical to include peaking and cycling units
because peaking turbines operate less and because it would be much more
expensive to lower their emission profile to that of a combined cycle
power plant or a coal-fired plant with CCS.
The first approach is not practical, however, because new
combustion turbines could avoid applicability by simply not having a
permit restriction at all. Moreover, even if a combustion turbine were
subject to the restriction, it could violate its permit if it did not
operate enough to sell the requisite amount of electricity. This would
be nonsensical, especially because system demand would not always be
sufficient to allow all permitted units to operate above the threshold.
Therefore, we rejected the first permitting approach.
In contrast, the second approach would be a viable method for
identifying and exempting peaking units from applicability. However,
there are multiple drawbacks to such an applicability approach. First,
this approach would subject those turbines without a permit restricting
electric sales to the final emission standards, which raises concerns
as to whether turbines with lower actual sales could achieve the
standards. For example, new NGCC units tend to dispatch prior to older
existing units and will generally operate for extended periods of time
near full load and sell electricity above the percentage electric sales
threshold. However, as NGCC units age, they tend to start and stop more
frequently and operate at part load. Yet, even if these units sell
below the percentage electric sales threshold, they would still be
affected units if they did not take a permit restriction. As commenters
noted, part-load operation and frequent starts and stops can reduce the
efficiency of a combustion turbine. While we are confident that our
final standards for base load natural gas-fired combustion turbines can
be achieved by units serving either base or intermediate load, we are
not as confident that affected NGCC units that might someday be
operated as non-base load units (e.g., as NSPS units age, their
incremental generating costs will tend to be higher than newer units
and they will dispatch less) could achieve the standards.
More importantly, however, we are concerned that using a permitting
approach for the percentage electric sales criterion would create
problems due to the interaction between 111(b) and 111(d). Under the
second permitting approach we considered, units with low electric sales
would be excluded from applicability, while units with high electric
sales would be included. While these low-electric sales units would
generally be simple cycle combustion turbines and the high-electric
sales units would generally be NGCC combustion turbines, this would not
always be the case. In contrast, we are finalizing an applicability
approach in the 111(d) emission guidelines that is based on a
combustion turbine's design characteristics rather than electric sales.
Simple cycle combustion turbines are excluded from applicability, while
NGCC units are included. As a result, the universe of sources covered
by the 111(b) standards would not necessarily be the same universe of
sources covered by the 111(d) standards.
To resolve this issue, we considered whether we could change the
111(d) applicability criteria to be based on historical operation
rather than design characteristics. For example, if an existing
combustion turbine had historically sold less than one-third of its
potential output to the grid, then it would be exempt from the emission
guidelines. However, many existing NGCC units have historically sold
less than this amount of electricity, meaning that they would not be
subject to the rule. We ran into similar issues when considering other
thresholds. For example, a percentage electric sales threshold of 10
percent would still exempt roughly 5 percent of existing NGCC units
from 111(d), while simultaneously raising achievability concerns with
the 111(b) standard. Moreover, even if we had finalized 111(d)
applicability criteria based on historical operations, existing NGCC
units could have decided to take a permit restriction limiting their
electric sales going forward to avoid applicability. Under any of these
scenarios, our goals with respect to 111(d) would not be accomplished.
To avoid this result, the EPA has concluded that it is appropriate
to finalize the broad applicability approach and set standards for
combustion turbines regardless of what percentage of their potential
electric output they sell to the grid. To accommodate the continued use
of simple cycle and fast-start NGCC combustion turbines for peaking and
cycling applications, however, the EPA has subcategorized natural gas-
fired combustion turbines based on a variation of the proposed
percentage electric sales criterion. Specifically, and as explained in
more detail in Section IX.B.2, we are finalizing the sliding-scale
approach on which we solicited comment.
d. Natural gas-use criterion
Similar to the proposed electric sales criteria, commenters
generally opposed the proposed natural gas-use criterion being based on
actual operating parameters. As with the electric sales criteria, the
EPA agrees that applicability that can switch periodically due to
operating parameters is not ideal. The EPA evaluated two approaches for
implementing the intent of the proposed natural gas-use criterion
(i.e., to exclude non-natural gas-fired combustion turbines) through
operating permit restrictions. Under the first approach, an emission
standard would apply to all combustion turbines with a permit
restriction mandating that natural gas contribute over 90 percent of
total heat input.\530\ Under the second approach, an emission standard
would apply to all combustion turbines without a permit restriction
limiting natural gas use to 90 percent or less of total heat
input.\531\ As with the percentage electric sales criterion, the first
approach is not practical because combustion turbines could avoid
[[Page 64608]]
applicability by simply not having a permit that requires the use of
more than 90 percent natural gas, even if they intend to only burn
natural gas. We disregarded this approach because it would essentially
provide a pathway for all NGCC units to avoid applicability under both
111(b) and 111(d). The second approach is problematic because operating
permit restrictions to improve air quality are typically written to
limit high emission activities (e.g., limiting the use of distillate
oil to 500 hours annually), not to limit lower emitting activities.
This approach could lead to perverse environmental impacts by
incentivizing the use of non-natural gas fuels, which would typically
result in higher CO2 emissions. Furthermore, the second
approach would not limit the fuels that can be burned by affected units
(i.e., combustion turbines not required to use non-natural gas fuels)
and would continue to cover combustion turbines even when they burn
over 10 percent non-natural gas fuels. Because all non-natural gas
fuels except H2 have CO2 emission rates higher
than natural gas, this approach would exacerbate the concerns raised by
commenters about the achievability of the 111(b) requirements when
burning back up fuels.
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\530\ This approach could also be written as ``an emission
standard would apply to all combustion turbines with a permit
restriction limiting the use of non-natural gas fuels to 10 percent
or less of the total heat input.'' Applicability could then be
avoided by simply being permitted to burn non-natural gas fuels for
more than 876 hours per year even if they actually intended to
seldom, if ever, combust the alternate fuels.
\531\ This approach could also be written as ``an emission
standard would apply to all combustion turbines without permit
restrictions mandating that non-natural gas use contribute over 10
percent or more of total heat input.''
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In light of these issues, the EPA has concluded that permit
restrictions are not an ideal approach to distinguishing between
natural gas-fired and multi-fuel-fired combustion turbines and are
finalizing a variation of the broad applicability approach. The EPA has
concluded that the only practical approach to implement the natural
gas-use criterion is to look at the turbine's physical ability to burn
natural gas. Therefore, we are not finalizing CO2 standards
for combustion turbines that are not capable of firing any natural gas
(i.e., not connected to a natural gas pipeline). From a practical
standpoint, the burners of most combustion turbines can be modified to
burn natural gas, so this exemption is essentially limited to
combustion turbines that are built in remote or offshore locations
without access to natural gas. Consistent with the broad applicability
approach, we are finalizing standards for all other combustion
turbines, but are subcategorizing between natural gas-fired turbines
and multi-fuel-fired turbines. Specifically, and as explained in more
detail in Section IX.B.3, we are distinguishing between these classes
of turbines based on whether they burn greater than 90 percent natural
gas or not.
B. Subcategories
We are finalizing a variation of the broad applicability approach
for combustion turbines where the percentage electric sales and natural
gas-use criteria serve as thresholds that distinguish between three
subcategories. These subcategories are base load natural gas-fired
units, non-base load natural gas-fired units, and multi-fuel-fired
units. Under the final subcategorization approach, multi-fuel-fired
combustion turbines are distinguished from natural gas-fired turbines
if fuels other than natural gas (e.g., distillate oil) supply 10
percent or more of heat input. Natural gas-fired turbines are further
subcategorized as base load or non-base load units based on the
percentage electric sales criterion. The percentage electric sales
threshold that distinguishes base load and non-base load units is based
on the specific turbine's design efficiency (i.e., the sliding-scale
approach). The percentage electric sales threshold is capped at 50
percent.
This section describes comments we received regarding the proposed
size-based subcategories and our rationale for not finalizing them. In
addition, it describes comments we received regarding sales-based
subcategories and our rationale for adopting the sliding scale to
distinguish between subcategories. Finally, it describes comments we
received regarding fuel-based subcategories and our rationale for
adopting fuel-based subcategories.
1. Size-Based Subcategories
At proposal, the EPA identified two size-based subcategories: (1)
large natural gas-fired stationary combustion turbines with a base load
rating greater than 850 MMBtu/h and (2) small natural gas-fired
stationary combustion turbines with a base load rating of 850 MMBtu/h
or less. The EPA received numerous comments regarding our proposal to
subcategorize combustion turbines by size. Some commenters agreed with
the 850 MMBtu/h cut-point between large and small units, some suggested
increasing it to 1,500 MMBtu/h, and others suggested eliminating size-
based subcategorization altogether. For example, some commenters stated
that the 850 MMBtu/h cut-point was inappropriate because it was
originally calculated based on NOX performance, not
CO2 performance. These commenters stated that 850 MMBtu/h
was not a logical demarcation between more efficient and less efficient
combustion turbines, but rather would divide the units into arbitrary
size classifications. These commenters suggested that 1,500 MMBtu/h
would be a better cut-point because data reported to Gas Turbine World
(GTW) showed that new combustion turbines are not currently offered
with a heat input rating between 1,300 MMBtu/h and 1,800 MMBtu/h, so
the higher cut-point would more accurately reflect when more efficient
technologies are available.
In contrast, other commenters said that differentiation between
small and large combustion turbines was not justified at all because
many of the same efficiency technologies that reduce the emission rates
of larger units could be incorporated into smaller units (e.g.,
upgrades that increase the turbine engine operating temperature,
increase the turbine engine pressure ratio, or add multi-pressure steam
and a steam reheat cycle). These commenters also said that separate
standards for small and large turbines would undermine the incentive
for technology innovation, which they described as a key purpose of the
NSPS program, and that relaxing standards for smaller units would
discourage investment in more efficient technologies, resulting in
increased CO2 emissions. These commenters recommended that
the limit for both large and small units be no higher than 1,000 lb
CO2/MWh-g.
After evaluating these comments, the EPA has decided not to
subcategorize combustion turbines based on size for several reasons.
First, the heat input values listed in Gas Turbine World do not include
potential heat input from duct burners.\532\ Because the heat input
from duct burners is necessary to accurately determine potential
electric output, our definition of ``base load rating'' includes the
heat input from any installed duct burners. The EPA reviewed the heat
input data for existing NGCC units that has been submitted to CAMD.
These data include the heat input from duct burners and show that
multiple NGCC power blocks have been built in the past with heat input
capacities that fall within the range that commenters suggested new
turbines are not offered. Therefore, the EPA has concluded that the
regulated community uses various sizes of NGCC turbines and when the
heat input from duct burners is included, there is no clear break
between the NGCC unit sizes that could distinguish between small and
large units. In fact, subcategorizing
[[Page 64609]]
by size could unduly influence the development of future NGCC offerings
because manufacturers could be incentivized to design new products at
the top end of the small subcategory to take advantage of the less
stringent emission standard.
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\532\ Duct burners are optional supplemental burners located in
the HRSG that are used to generate additional steam. Heat input to
duct burners could in theory be twice that of the combustion turbine
engine, but are more commonly sized at 10 to 30 percent of the heat
input to the combustion turbine engine.
---------------------------------------------------------------------------
Second, commenters suggested that a cut-point of 1,500 MMBtu/h
reflects when more efficient technologies become available. However,
when we reviewed actual operating data and design data, we only found a
relatively weak correlation between turbine size and CO2
emission rates and did not see a dramatic drop in CO2
emission rates at 1,500 MMBtu/h. The variability of emission rates
among similar size units far exceeds any difference that could be
attributed to a difference in size. In addition, the most efficient
one-to-one configuration NGCC power block with a base load rating of
1,500 MMBtu/h or less has a design emission rate of the 767 lb
CO2/MWh-n (984 MMBtu/h). The most efficient one-to-one
configuration NGCC power block with a base load rating just greater
than 1,500 MMBtu/h has a design emission rate of 772 lb CO2/
MWh-n (1,825 MMBtu/h). Because the smaller unit has a lower design
emission rate than the larger unit, increasing the cut-point does not
make sense.
Finally, the EPA has concluded that, while certain smaller NGCC
designs may be less efficient than larger NGCC designs, most existing
small units have demonstrated emission rates below the range of
emission rates on which we solicited comment. We have concluded that
the lower design efficiencies of some small NGCC units are primarily
related to model-specific design choices in both the turbine engine and
HRSG, not an inherent limitation in the ability of small NGCC units to
have comparable efficiencies to large NGCC units. Specifically,
manufacturers could improve the efficiency of the turbine engine by
using turbine engines with higher firing temperatures and high
compression ratios and could improve the efficiency of the steam cycle
by switching from single or double-pressure steam to triple-pressure
steam and adding a reheat cycle. For all of these reasons, we have
decided against subcategorizing combustion turbines based on size. Our
rationale for setting a single standard for small and large combustion
turbines is explained in more detail in Section IX.D.3.a below.
2. Sales-Based Subcategories
As described above in Section IX.A.3.c, the final applicability
criteria do not include an exemption for non-CHP units based on actual
electric sales or permit restrictions limiting the amount of
electricity that can be sold. Instead, we are finalizing the percentage
electric sales criterion as a threshold to distinguish between two
natural gas-fired combustion turbine subcategories. The industry uses a
number of terms to describe combustion turbines with different
operating characteristics based on electric sales (e.g., capacity
factors). Combustion turbines that operate at near-steady, high loads
are generally referred to as ``base load'' or ``intermediate load''
units, depending on how many hours the units operate annually.
Combustion turbines that operate continuously with variable loads that
correspond to variable demand are referred to as ``load following'' or
``cycling'' units. Combustion turbines that only operate during periods
with the highest electricity demand are referred to as ``peaking''
units. However, it is difficult to characterize a particular unit using
just one of these terms. For example, a particular unit may serve as a
load following unit during winter, but serve as a base load unit during
summer. In addition, none of these terms has a precise universal
definition. In this preamble, we refer to the subcategory of combustion
turbines that sell a significant portion of their potential electric
output as ``base load units.'' This subcategory includes units that
would colloquially be referred to as base load units, as well as some
intermediate load and load following units. We refer to all other units
as ``non-base load units.'' This subcategory includes peaking units, as
well as some load following and intermediate load units. The threshold
that distinguishes between these two subcategories is determined by a
unit's design efficiency and varies from 33 to 50 percent, hence the
term ``slide scale'' approach.
Numerous commenters supported three sales-based subcategories for
peaking, intermediate load, and base load units. These commenters said
that each subcategory should be distinguished by annual hours of
operation and that each should have a different BSER and emission
standard. Other commenters opposed the tiered approach. These
commenters said that separate standards for different operating
conditions would be complicated to implement and enforce, while
providing few benefits. These commenters said that a tiered approach
could also have the unintended consequence of encouraging less
efficient technologies because it would create a regulatory incentive
to install lower-capital-cost, less-efficient units that would operate
under the percentage electric sales threshold instead of higher-
capital-cost, more-efficient units that would operate above the
threshold.
After evaluating these comments, the EPA has concluded that it is
appropriate to adopt a two-tiered subcategorization approach based on a
percentage electric sales threshold to distinguish between non-base
load and base load units. While we agree with commenters that separate
standards for peaking, intermediate, and base load units is attractive
on the surface, we ultimately concluded that a three-tiered approach is
not appropriate for several reasons. First, the increased generation
from renewable sources that is anticipated in the coming years makes it
very difficult to determine appropriate thresholds to distinguish among
peaking, intermediate, and base load subcategories. Indeed, the
boundaries between these demand-serving functions may blur or shift in
the years to come. The task is further complicated because each
transmission region has a different mix of generation technologies and
load profiles with different peaking, intermediate, and base load
requirements.
Second, there are only two distinct combustion turbine
technologies--simple cycle units and NGCC units. In theory, the BSER
for the intermediate load subcategory could be based on high-efficiency
simple cycle units or fast-start NGCC units, but these are variations
on traditional technologies and not necessarily distinct. Moreover, we
do not have specific cost information on either high-efficiency simple
cycle turbines or fast-start NGCC units, so our ability to make cost
comparisons to conventional designs is limited.
Finally, even if we could identify appropriate sales thresholds to
distinguish between peaking, intermediate load, and base load
subcategories, we do not have sufficient information to establish a
meaningful output-based standard for an intermediate load subcategory
at this time. In the transition zone from peaking to base load
operation (i.e., cycling and intermediate load), combustion turbines
may have similar electric sales, but very different operating
characteristics. For example, despite having similar sales, one unit
might have relatively steady operation for a short period of time,
while another could have variable operation throughout the entire year.
The latter unit would likely have a higher CO2 emission
rate. For all of these reasons, the EPA has concluded that we do not
have sufficient information at this time
[[Page 64610]]
to establish three sales-based subcategories.
Instead, as we explained above, we are finalizing two sales-based
subcategories. To determine an appropriate threshold to distinguish
between base load and non-base load units, the EPA considered the
important characteristics of the combustion turbines that serve each
type of demand. For non-base load units, low capital costs and the
ability to start, stop, and change load quickly are key. Simple cycle
combustion turbines meet these criteria and thus serve the bulk of peak
demand. In contrast, for base load units, efficiency is the key
consideration, while capital costs and the ability to start and stop
quickly are less important. While NGCC units have relatively high
capital costs and are less flexible operationally, they are more
efficient than simple cycle units. NGCC units recover the exhaust heat
from the combustion turbine with a HRSG to power a steam turbine, which
reduces fuel use and CO2 emissions by approximately one-
third compared to a simple cycle design. Consequently, base load units
use NGCC technology. Because simple cycle turbines have historically
been non-base load units, we have concluded that it is appropriate to
distinguish between the non-base load and base load subcategories in a
way that recognizes the distinct roles of the different turbine designs
on the market.
The challenge, however, is setting a threshold that will not
distort the market. The future distinction between non-base load and
base load units is unclear. For example, some commenters indicated that
increased generation from intermittent renewable sources has created a
perceived need for additional cycling and load following generation
that will operate between the traditional roles of peaking and base
load units. To fulfill this perceived need, some manufacturers have
developed high-efficiency simple cycle turbines. These high-efficiency
turbines have higher capital costs than traditional simple cycle
turbine designs, but maintain similar flexibilities, such as the
ability to start, stop, and change load rapidly. Other manufacturers
have developed fast-start NGCC turbines to fill the same role. These
newer NGCC designs have lower design efficiencies than NGCC designs
intended to only operate as base load units, but are able to startup
more quickly to respond to rapid changes in electricity demand. As a
result of these new technological developments, both high-efficiency
simple cycle and fast-start NGCC units can be used for traditional
peaking applications, as well as for higher capacity applications, such
as supporting the growth of intermittent renewable generation.
With the changing electric sector in mind, we set out to identify
an appropriate percentage electric sales threshold to distinguish
between non-base load and base load natural gas-fired units. Two
factors were of primary importance to our decision. First, the
threshold needed to be high enough to address commenters' concerns
about the need to maintain flexibility for simple cycle units to
support the growth of intermittent renewable generation. Second, the
threshold needed to be low enough to avoid creating a perverse
incentive for owners and operators to avoid the base load subcategory
by installing multiple, less efficient turbines instead of fewer, more
efficient turbines.
To determine the potential impact of intermittent renewable
generation on the operation of simple cycle units, we examined the
average electric sales of simple cycle turbines in the lower 48 states
between 2005 and 2014 using information submitted to CAMD. We combined
this data with information reported to the EIA on total in-state
electricity generation, including wind and solar, from 2008 through
2014. We focused on data from the Southwest Power Pool (data
approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and
California. All of these regions have relatively large amounts of
generation from wind and solar and experienced increases in the portion
of total electric generation provided by wind and solar during the
2008-2014 period.
a. Southwest Power Pool
The portion of in-state generation from wind and solar in the
Southwest Power Pool increased from 3 to 16 percent between 2008 and
2014. The average growth rate of wind and solar was 28 percent, while
overall electricity demand grew 1 percent annually on average. Based on
statements in some of the comments, we expected to see a large change
in the operation of simple cycle turbines in this region. However, the
average electric sales from simple cycle turbines only increased at an
annual rate of 1.7 percent, and remained essentially unchanged at 3
percent of potential electric output between 2008 and 2014. Total
generation from simple cycle turbines in the Southwest Power Pool
increased slightly more, at an annual rate of 2.5 percent, which was
the result of additional simple cycle capacity being added to address
increased electricity demand.
This lack of a significant change in the operation of simple cycle
turbines could be explained by the Southwest Power Pool's relatively
large amount of exported power. If most of the region's renewable
generation was being exported, the intermittent nature of this power
would primarily impact other transmission regions. An alternate
explanation, however, is that other generating assets are flexible
enough to respond to the intermittent nature of wind and solar
generation and that simple cycle turbines are not necessary to back up
these assets to the degree some commenters suggested. If this is the
case, then new simple cycle turbines may primarily continue to fill
their historical role as peaking units going forward, while other
technologies, such as fast-start NGCC units, may provide the primary
back up capacity for new wind and solar.
b. Texas
The portion of in-state generation from wind and solar in Texas
increased from 4 to 9 percent between 2008 and 2014. The average growth
rate of wind and solar was 13 percent, while overall demand grew at an
average rate of 2 percent annually. Similar to the Southwest Power
Pool, the average electric sales of simple cycle turbines has remained
relatively unchanged. In fact, the average electric sales of these
turbines decreased at an annual rate of 1.1 percent. Total generation
from simple cycle turbines increased at an annual rate of 6.6 percent,
however, due to simple cycle capacity additions that occurred at
approximately four times the rate one would expect from the growth in
overall demand.
The most likely technologies to back up intermittent renewable
generation have low incremental generating costs and can start up and
stop quickly. Highly efficient simple cycle units meet these criteria.
As such, the EPA has concluded that the most efficient simple cycle
turbines in a given region are the most likely to support intermittent
renewable generation. Focusing on these simple cycle turbines will
address concerns raised by commenters about the future percentage
electric sales of highly efficient simple cycle turbines and give an
indication of the impact of increased renewable generation on non-base
load units intended to back up wind and solar. There are two highly
efficient intercooled simple cycle turbines installed in Texas. These
two combustion turbines sell an average of 10 percent of their
potential electric output annually, compared to an average of 3 percent
for the remaining simple cycle turbines. No simple cycle
[[Page 64611]]
turbine in Texas sold more than 25 percent of its potential electric
output annually. The rapid growth in simple cycle capacity, but not
overall capacity factors, could indicate that the additional generation
assets are providing firm capacity for intermittent generation sources
such as wind and solar, but that capacity is infrequently required.
Based on the data, even highly efficient simple cycle turbines are
expected to continue to sell less than one-third of their potential
electric output.
c. California
The portion of in-state generation from wind and solar in
California increased from 3 to 11 percent between 2008 and 2014. The
average growth rate of wind and solar was 25 percent, while overall
demand has remained stable. The operation of simple cycle turbines in
California has changed more significantly than in the other evaluated
regions. The average electric sales from simple cycle turbines
increased from 5.1 to 5.9 percent, an annual rate increase of 4.5
percent. As in Texas, considerable additional simple cycle capacity has
been added in recent years. The total capacity of simple cycle turbines
is increasing at 15 percent annually even though overall demand has
remained relatively steady. In addition, the newest simple cycle
turbines are operating at higher capacity factors than the existing
fleet of simple cycle turbines, resulting in an average increase in
generation from simple cycle turbines of 21 percent. Many of the new
additions are intercooled simple cycle turbines that may have been
installed with the specific intent to back up wind and solar
generation.
The average electric sales for the intercooled turbines ranged from
3 to 25 percent, with a 7 percent average. No simple cycle turbines in
California have sold more than one-third of their potential electric
output on an annual basis. The operation of simple cycle turbines that
existed prior to 2008 has not changed significantly. Average electric
sales for these turbines increased at an annual rate of 0.1 percent.
This indicates that support for new renewable generation is being
provided by new units and not by the installed base of simple cycle
units. These units are still serving their historical role of providing
power during peak periods of demand.
Based on our data analysis, the proposed one-third electric sales
threshold would appear to offer sufficient operational flexibility for
new simple cycle turbines. Existing NGCC units, other generation
assets, and demand-response programs are currently providing adequate
back up to intermittent renewable generation. In the future, however,
existing NGCC units will likely operate at higher capacity factors.
They will therefore be less available to provide back up power for
intermittent generation. In addition, the amount of power generated by
intermittent sources is expected to increase in the future. Both of
these factors could require additional flexibility from the remaining
generation sources to maintain grid reliability.
Even though fast-start NGCC units, reciprocating internal
combustion engines, energy storage technologies, and demand-response
programs are promising technologies for providing back up power for
renewable generation, none of them historically have been deployed in
sufficient capacity to provide the potential capacity needed in the
future to facilitate the continued growth of renewable generation.
While we anticipate that state and federally issued permits for new
electric generating sources will consider the CO2 benefits
of these technologies compared to simple cycle turbines, the EPA has
concluded at this time that it is appropriate to finalize a percentage
electric sales threshold that provides additional flexibility for
simple cycle turbines.
Specifically, we have concluded that a percentage electric sales
threshold based on a unit's design net efficiency at standard
conditions is appropriate. This is the sliding-scale approach on which
we solicited comment. Several commenters supported this approach
because it provides sufficient operational flexibility for new simple
cycle and fast-start NGCC combustion turbines and simultaneously
promotes the installation of the most efficient generating
technologies. By allowing more efficient turbines to sell more
electricity before becoming subject to the standard for the base load
subcategory, the sliding scale should reduce the perverse incentive for
owners and operators to install more lower-capital-cost, less-efficient
units instead of fewer higher-capital-cost, more-efficient units. At
the same time, the sliding scale should incentivize turbine
manufacturers to design higher efficiency simple cycle turbines that
owners and operators can run more frequently.
The net design efficiencies for aeroderivative simple cycle
combustion turbines range from approximately 32 percent for smaller
designs to 39 percent for the largest intercooled designs. The net
design efficiencies of industrial frame units range from 30 percent for
smaller designs to 36 percent for the largest designs. These efficiency
values follow the methodology the EPA has historically used and are
based on the higher heating value (HHV) of the fuel. In contrast,
combustion turbine vendors in the U.S. often quote efficiencies based
on the lower heating value (LHV) of the fuel. The LHV of a fuel is
determined by subtracting the heat of vaporization of water vapor
generated during combustion of fuel from the HHV. For natural gas, the
LHV is approximately 10 percent lower than the HHV. Therefore, the
corresponding LHV efficiency ranges would be 35 to 44 percent for
aeroderivative designs and 33 to 40 percent for frame designs. We
considered basing the percentage electric sales threshold on both the
HHV and LHV. The EPA typically uses the HHV, but in light of
commenters' concerns regarding uncertainty in the operation of non-base
load units in the future, we opted to be conservative and use the LHV
efficiency.
We anticipate that high-efficiency simple cycle and fast-start NGCC
turbines will make up the majority of new capacity intended for non-
base load applications. Based on the sliding-scale approach, owners and
operators of new simple cycle combustion turbines will be able to sell
between 33 to 44 percent of the turbine's potential electric output.
Our analysis showed that 99.5 percent of existing simple cycle turbines
have not sold more than one-third of their potential electric output on
an annual basis. In addition, 99.9 percent of existing simple cycle
turbines have not sold more than 36 percent of their potential electric
output on an annual basis. The two simple cycle turbines that exceeded
the 36 percent threshold had annual electric sales of 39 and 45 percent
and are located in Montana and New York, respectively. As noted
earlier, the most efficient simple cycle turbine currently available is
44 percent efficient and would accommodate the operations at the
Montana facility. The only existing simple cycle turbine that exceeded
the maximum allowable percentage electric sales threshold of 44
percent, which is based on current simple cycle designs, sold an
abnormally high amount of electricity in 2014. It is possible that this
unit was operating under emergency conditions. As explained below, the
incremental generation due to the emergency would not have counted
against the percentage electric sales threshold.
We are capping the percentage electric sales threshold at 50
percent of potential electric output for multiple reasons. First, NGCC
emission rates are
[[Page 64612]]
relatively steady above 50 percent electric sales, so there is no
reason that a NGCC unit with sales greater than this amount should not
have to comply with the output-based standard for the base load
subcategory. Second, the net design efficiency of the fast-start NGCC
units intended for peaking and intermediate load applications is 49
percent. As described earlier, this technology can serve the same
purpose as high-efficiency simple cycle turbines. If we were to set a
cap any lower than 50 percent, it could create a disincentive for
owners and operators to choose this promising new technology.
Finally, the EPA solicited comment on excluding electricity sold
during system emergencies from counting towards the percentage electric
sales threshold. After considering the comments, we have concluded that
this exclusion is necessary to provide flexibility, maintain system
reliability, and minimize overall costs to the sector. We disagree with
commenters that suggested that the EPA's existing enforcement
discretion would be a viable alternative. An enforcement discretion-
based approach would not provide certainty to the regulated community,
public, and regulatory authorities on the applicability of the emission
standards, which is a primary reason why we are finalizing the broad
applicability approach. Moreover, system emergencies are defined
events, so commenters' fears that the exclusion will be subject to
abuse are overstated. Therefore, electricity sold during hours of
operation when a unit is called upon to operate due to a system
emergency will not be counted toward the percentage electric sales
threshold. However, electricity sold by units that are not called upon
to operate due to a system emergency (e.g., units already operating
when the system emergency is declared) will be counted toward the
percentage electric sales threshold.
In summary, the EPA is finalizing the percentage electric sales
criterion as a threshold to distinguish between two natural gas-fired
combustion turbine subcategories. Specifically, all units that have
electric sales greater than their net LHV design efficiencies (as a
percentage of potential electric output) are base load units. All units
that have electric sales less than or equal to their net LHV design
efficiencies are non-base load units. We are capping the percentage
electric sales threshold at 50 percent of potential electric output.
This sliding-scale approach will limit the operation of the least
efficient units, provide flexibility for renewable energy growth, and
incentivize the development of more efficient simple cycle units.
3. Fuel-Based Subcategories
As described in Section IX.A.3.d, we are finalizing a version of
the broad applicability approach. Under the broad applicability
approach, the EPA solicited comment on a subcategorization approach
based in part on natural gas-use. We received few comments on this
issue. One of the comments we did receive was that combustion turbines
that burn fuels other than natural gas have higher CO2
emissions due to the higher relative carbon content of alternate fuels.
Besides hydrogen,\533\ natural gas has the lowest CO2
emission rate on a lb/MMBtu basis of any fossil fuel. Therefore,
burning fuels other than natural gas will result in a higher
CO2 emission rate. We interpret this comment to mean that,
if we were to subcategorize based on fuel use, turbines that burn non-
natural gas fuels should receive a less stringent emission standard.
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\533\ Hydrogen would only be considered a fossil fuel if it were
derived for the purpose of creating useful heat from coal, oil, or
natural gas.
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For the reasons described in the applicability section, we have
decided to set emission standards for all combustion turbines capable
of burning natural gas, regardless of the actual fuel burned, to avoid
the practical problems that would have arisen under the proposed
approach. However, as commenters explained, multi-fuel-fired combustion
turbines cannot achieve the emission standards achieved by natural-gas
fired turbines. For this reason, it would not be reasonable to require
affected EGUs to comply with a standard based on the use of natural gas
during periods when significant quantities of non-natural gas fuels are
being burned. If we did not subcategorize, owners and operators would
not be able to combust other fuels in their turbines, including process
gas, blast furnace gas, and petroleum-based liquid wastes, which might
otherwise be wasted. In addition, without the ability to burn back up
fuels during natural gas curtailments, grid reliability could be
jeopardized. Therefore, we are finalizing a separate fuel-based
subcategory for multi-fuel-fired combustion turbines. To distinguish
between this subcategory and the natural gas-fired subcategories, we
are using the same threshold as proposed. Specifically, combustion
turbines that burn ninety percent or less natural gas on a 12-
operating-month rolling average basis will be included in this
subcategory and subject to a separate emission standard, which is
discussed in Section IX.D.3.d.
C. Identification of the Best System of Emission Reduction
This section summarizes the EPA's proposed BSER determinations for
stationary combustion turbines, provides a summary of the comments we
received, and explains our final BSER determinations for each of the
three subcategories we are now finalizing. For natural gas-fired
stationary combustion turbines operating as base load units, we
proposed and are finalizing the use of NGCC technology as the BSER. For
the other two subcategories of affected combustion turbines--non-base
load natural gas-fired combustion turbines and multi-fuel-fired
combustion turbines--we are finalizing the use of clean fuels as the
BSER.
1. Proposed BSER
We considered three alternatives in evaluating the BSER for base
load natural gas-fired combustion turbines: (1) Partial CCS, (2) high-
efficiency simple cycle aeroderivative turbines, and (3) modern,
efficient NGCC turbines. We rejected partial CCS as the BSER because we
concluded that we did not have sufficient information to determine
whether implementing CCS for combustion turbines was technically
feasible. We rejected high-efficiency simple cycle aeroderivative
turbines as the BSER because this standalone technology does not
provide emission reductions and generally is more expensive than NGCC
technology for base load applications. In contrast, NGCC is the most
common type of new fossil fuel-fired EGU currently being planned and
built for generating base load power. NGCC is technically feasible, and
NGCC units are currently the lowest-cost, most efficient option for new
base load fossil fuel-fired power generation. After considering the
options, the EPA proposed to find that modern, efficient NGCC
technology is the BSER for base load natural gas-fired combustion
turbines.
For non-base load natural gas-fired units and multi-fuel-fired
units, we did not propose a specific BSER or associated numeric
emission standards, but instead solicited comment on these issues.
2. Comments on the Proposed BSER for Base Load Natural Gas-Fired
Combustion Turbines
This section summarizes the differing comments submitted on the
proposed BSER for base load natural gas-fired combustion turbines. Some
commenters supported partial CCS as the BSER, others supported advanced
NGCC
[[Page 64613]]
designs as the BSER, and others supported the proposed BSER.
a. Partial CCS
Some commenters stated that our proposed BSER analysis for
stationary combustion turbines was inconsistent with our proposed BSER
analysis for coal-fired units. They stated that the EPA had determined
that the use of CCS was feasible for coal-fired generation based on
current CCS projects under development at coal-fired generating
stations, but did not come to the same conclusion for combustion
turbines. These commenters stated that CO2 removal is just
as technologically feasible and economically reasonable for a natural
gas-fired EGU as for a coal-fired EGU. While some of these commenters
wanted the EPA to reconsider CCS as the BSER for NGCC, many of these
commenters were attempting to prove that if the agency did not choose
CCS as the BSER for NGCC units, then the agency should not for coal-
fired units either.
Some commenters referenced the Northeast Energy Association NGCC
plant in Bellingham, MA, which operated from 1991-2005 with 85-95
percent carbon capture on a 320 MW unit for use in the food and
beverage industry, that was referred to in the proposal. This plant
captured 330 tons of CO2 per day from a 40 MW slip stream
and was decommissioned as a result of financial difficulties, including
rising gas prices and discontinuation of tax credits. According to
these commenters, this plant provided sufficient proof that CCS
technology is adequately demonstrated for NGCC units. Additionally,
these commenters referred to other NGCC plants that are planned or in
development that will incorporate CCS. The plants mentioned were the
Sumitomo Chemical Plant in Japan, the Peterhead CCS project in
Scotland, and the GE-Sargas Plant in Texas. The Sumitomo Chemical Plant
has a base load NGCC unit with CCS operating on an 8 MW slip-stream
that captures about 150 tons of CO2 per day for commercial
use in the food and beverage industry. This carbon capture system has
been operating since 1994. The Peterhead CCS project in Scotland is in
the planning stages. It is a collaboration between Shell and SSE to
provide 320 MW of electricity to its customers from a base load NGCC
unit with 90 percent carbon capture. The CO2 will be
transported to the depleted Goldeneye reservoir in the ocean where it
will be stored and continuously monitored. The GE-Sargas Plant in Texas
is a planned joint venture that does not currently have a location
selected, but is intended to be a base load NGCC unit with CCS used for
EOR.
These commenters also referenced reports authored by DOE, NETL, the
Clean Air Task Force (CATF), CCS Task Force, ICF Inc., and Global CCS
Institute, suggesting that, because CCS technology for NGCC is included
in these reports, it is adequately demonstrated. Some commenters
referred to a DOE/NETL study that suggested that the cost of CCS for
NGCC units would be more cost-effective than for coal-fired EGUs. One
non-industry commenter emphasized that a technology does not have to be
in use to be considered adequately demonstrated.
In addition, some commenters disagreed with the EPA's decision to
treat combustion turbines differently than coal-fired units with
respect to CCS on the basis that combustion turbines startup, shutdown,
and cycle load more frequently than coal-fired units. According to
these commenters, the operating characteristics of combustion turbines
do fluctuate, but so do those of coal-fired units. Another commenter
said that even if NGCC operations vary more than they do for coal-fired
units, it is not an impediment to using CCS because combustion turbine
operators could bypass the carbon capture system during startup and
shutdown modes (which are typically shorter and less intensive efforts
compared to the startup or shutdown of a coal facility) and then employ
the carbon capture system when operating normally. One commenter stated
that most future base load fossil fuel-fired generation will be NGCC
and that not making CCS the BSER for NGCC would result in significant
CO2 emissions.
Other commenters supported the EPA's determination that CCS is not
the BSER for combustion turbines. These commenters said that CCS is not
adequately demonstrated for combustion turbines because none are
currently operating, under construction, or in the advanced stages of
development. They also noted that CCS would have to be demonstrated for
the range of facilities included in the regulated source category,
which they alleged includes both simple cycle and NGCC units. They
specifically noted that the Bellingham, MA demonstration facility was
not a full-scale commercial NGCC power plant operating with CCS.
These commenters agreed with the EPA that CCS does not match well
with the operating flexibilities of NGCC and simple cycle units. They
agreed with the EPA that frequent cycling restricts the efficacy of CCS
on these units, a problem which would only get worse as more renewable
energy sources are integrated into the grid. These commenters added
that NGCC units operate differently than coal-fired units because the
former start, stop, and cycle frequently, whereas the latter tend to
operate at relatively steady loads and do not start and stop
frequently. They stated that even if technical barriers could be
overcome, the application of CCS to combustion turbines would be more
costly (compared to the application of CCS to coal-fired units) on a
dollars-per-ton basis. In addition, these commenters said that other
industries' experience with CCS could not be transferred to NGCC units
due to differences in flue gas CO2 concentration.
Some commenters stated that CAA section 111(a) requires the EPA to
account not only for the cost of achieving emission reductions, but
also for impacts on energy requirements and the environment. The
commenters cited to Sierra Club v. Costle, where the D.C. Circuit
observed that the EPA ``must exercise its discretion to choose an
achievable emission level which represents the best balance of
economic, environmental, and energy considerations.'' \534\ The
commenters stated that requiring CCS on combustion turbines would
adversely affect the nation's energy needs and the environment because
imposing CCS on combustion turbines would invariably delay the emission
reductions that can be obtained from new NGCC projects that displace
load from older, less efficient generating technologies. In addition,
the commenters stated that, because combustion turbines are projected
to provide a significant share of new power generation, the EPA should
recognize that requiring CCS on these units would have a
disproportionally higher impact on electricity prices when compared to
the projected number of new coal-fired projects. These commenters
concluded that the EPA could not determine that CCS is the BSER for
combustion turbines without producing severe and unacceptable
consequences for the availability of affordable electricity in the U.S.
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\534\ Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
---------------------------------------------------------------------------
b. NGCC Turbines
Some commenters stated that the proposed BSER analysis should have
reflected the emission rates achieved by the latest designs deployed at
advanced, state-of-the-art NGCC installations. These commenters stated
that advanced NGCC technologies are the best system
[[Page 64614]]
for reducing CO2 emissions with no negative environmental
impacts and no negative economic impacts on rate payers. They stated
that advanced NGCC technologies are capable of achieving emission rates
that are 8 percent lower than conventional NGCC facilities. They also
said that the majority of existing sources that do not deploy these
advanced technologies are currently able to meet the standard and that
the proposal failed to explain why these lower-emitting advanced
technologies that are more than adequately demonstrated were not
selected as the BSER.
c. Simple Cycle Turbines
Many commenters opposed the EPA's proposal to set emission
standards for combustion turbines based on their function rather than
based on their design. These commenters stated that the EPA's
determination that NGCC technology is the BSER for base load natural
gas-fired combustion turbines would apply equally to simple cycle
turbines if they sell electricity in excess of the percentage electric
sales threshold. They pointed to the word ``achievable'' in CAA section
111(a)(1) and stated that applying an emission standard based on NGCC
technology to simple cycle units was legally indefensible because
simple cycle units cannot achieve emission rates as low as NGCC units.
In contrast, many other commenters agreed with the EPA's basic approach
and stated that NGCC technology should be the BSER for base-load
functions, while simple cycle technology should be the BSER for peak-
load functions.
3. Comments on Non-Base Load and Multi-Fuel-Fired Combustion Turbines
Multiple commenters suggested that high efficiency simple cycle or
fast-start NGCC technologies should be the BSER for non-base natural
gas-fired load units. They explained that high efficiency simple cycle
units and fast-start NGCC units are actually more efficient when
serving non-base load demand than NGCC units that are designed strictly
for base load operation. Some commenters also suggested that we should
subcategorize multi-fuel-fired combustion turbines, but did not provide
any specific technologies that should be considered in the BSER
analysis.
4. Identification of the BSER
After our evaluation of the comments and additional analysis, we
identified the BSER for each subcategory of combustion turbine that we
are finalizing: base load natural gas-fired units, non-base load
natural gas-fired units, and multi-fuel-fired units.
a. Base Load Natural Gas-Fired Units
As described in the proposal, we evaluated CCS, NGCC, and high-
efficiency simple cycle combustion turbines as the potential BSER for
this subcategory. We selected NGCC as the BSER because it met all the
BSER criteria. This section describes our response to issues raised by
commenters and our rationale for maintaining that NGCC is the BSER for
base load natural gas-fried combustion turbines.
(1) Partial CCS
Some commenters stated that CCS could be applied equally to both
coal-fired and natural gas-fired EGUs. To support this conclusion, the
commenters pointed to a retired NGCC-with-CCS demonstration project, as
well as a few overseas projects and projects in the early stages of
development. While we have concluded that these commenters made strong
arguments that the technical issues we raised at proposal could in many
instances be overcome, we have concluded that there is not sufficient
information at this time for us to determine that CCS is adequately
demonstrated for all base load natural-gas fired combustion turbines.
While the commenters make a strong case that the existing and
planned NGCC-with-CCS projects demonstrate the feasibility of CCS for
NGCC units operating at steady state conditions, many NGCC units do not
operate this way. For example, the Bellingham, MA and Sumitomo NGCC
units cited by the commenters operated at steady load conditions with a
limited number of starts and stops, similar to the operation of coal-
fired boilers.\535\ In contrast, our base load natural gas-fired
combustion turbine subcategory includes not only true base load units,
but also some intermediate units that cycle more frequently, including
fast-start NGCC units that sell more than 50 percent of their potential
output to the grid. Fast-start NGCC units are designed to be able to
start and stop multiple times in a single day and can ramp to full load
in less than an hour. In contrast, coal-fired EGUs take multiple hours
to start and ramp relatively slowly. These differences are important
because we are not aware of any pilot-scale CCS projects that have
demonstrated how fast and frequent starts, stops, and cycling will
impact the efficiency and reliability of CCS. Furthermore, for those
periods in which a NGCC unit is operating infrequently, the CCS system
might not have sufficient time to startup. During these periods, no
CO2 control would occur. Thus, if the NGCC unit is intended
to operate for relatively short intervals for at least a portion of the
year, the owner or operator could have to oversize the CCS to increase
control during periods of steady-state operation to make up for those
periods when no control is achieved by the CCS, leading to increased
costs and energy penalties. While we are optimistic that these hurdles
are surmountable, it is simply premature at this point to make a
finding that CCS is technically feasible for the universe of combustion
turbines that are covered by this rule.
---------------------------------------------------------------------------
\535\ As explained in Section V.J above, a new fossil fuel-fired
steam generating EGU would, most likely, be built to serve base load
power demand exclusively and would not be expected to routinely
startup, shut down, or ramp its capacity factor in order to follow
load demand. Thus, planned start-up and shutdown events would only
be expected to occur a few times during the course of a 12-
operating-month compliance period.
---------------------------------------------------------------------------
Notably, the Department of Energy has not yet funded a CCS
demonstration project for a NGCC unit, and no NGCC-with-CCS
demonstration projects are currently operational or being constructed
in the U.S. In contrast, multiple CCS demonstration projects for coal-
fired units are in various stages of development throughout the U.S.,
and a full-capture system is in operation at the Boundary Dam facility
in Canada. See Sections V.E and D above.
One commenter suggested that not having CCS as the BSER for
combustion turbines would ultimately halt the development of CCS in the
U.S. We disagree. A number of coal-fired power plants are currently
being built with CSS, while some existing plants are considering CCS
retrofits. Moreover, the NSPS sets the minimum level of control for new
sources. We expect that state air agencies and other air permitting
authorities will evaluate CCS when permitting new NGCC power plants,
taking into consideration case-specific parameters, like operating
characteristics, to determine whether CCS could be BACT or LAER in
specific instances. While the NGCC-with-CCS units that currently are in
the planning stages do not provide us with enough assurance to
determine that CCS is adequately demonstrated for combustion turbines,
it is our expectation that these units and others to come will provide
additional information for both permitting reviews and the next NSPS
review in eight years.
(2) NGCC Turbines
Regarding the advanced NGCC technologies advocated by several
commenters, the EPA has concluded
[[Page 64615]]
that the term ``advanced'' simply refers to incremental improvements to
traditional NGCC designs, not a new and unique technology. These
incremental improvements include higher firing temperatures in the
turbine engine, increasing the number of steam pressures, and adding a
reheat cycle to the steam cycle. The emission rates achieved by these
so-called ``advanced'' technologies were included within the data set
of newer NGCC designs that we used to establish the final emission
standards. In addition, our review of the operating data for NGCC power
blocks installed since 2000 indicates that a unit's mode of operation
in response to system demand (e.g., capacity factor) affects
efficiencies achieved to the extent that we cannot evaluate the impact
of particular subcomponents used within the power block. As a result, a
conventional NGCC power block located in a region of the country where
system demand requires the power block to run continuously at a steady
high load can achieve higher efficiencies than an ``advanced'' NGCC
power block located in a region where system demand requires the power
block to cycle on and off to match system demand. For this reason, our
data set included a large population of technologies and load
conditions to ensure that new NGCC power blocks can achieve the final
emission standards in all regions of the country.
As we explained in the proposal, NGCC technology meets all of the
BSER criteria. For base load functions, NGCC units are technically
feasible, cost-effective (indeed, less expensive than simple cycle
combustion turbines), and have no adverse energy or environmental
impacts. Moreover, NGCC units reduce emissions because they have a
lower CO2 emission rate than simple cycle units. Finally,
selecting NGCC as the BSER will promote the development of new
technology, such as the incremental improvements advocated by the
commenters, which will further reduce emissions in the future.
Some commenters suggested that the costs and efficiency impacts of
startup and shutdown events are higher for NGCC units than for simple
cycle units. Consequently, we refined the LCOE costing approach used at
proposal by adding these additional costs and efficiency impacts to our
cost comparison. Even accounting for these new costs and impacts, we
found that NGCC technology results in a lower cost of electricity than
simple cycle technology when a unit's electric sales exceed
approximately one-third of its potential electric output. The final
percentage electric sales criterion for the base load natural gas-fired
combustion turbine subcategory is based on the sliding scale. This
means that the dividing line between the base load subcategory and the
non-base load subcategory will change depending on a unit's nameplate
design efficiency. For a conventional simple cycle turbine, the base
load subcategory will begin at around 33 percent electric sales, while
for a newer fast-start NGCC turbine, the base load subcategory will
begin at approximately 50 percent electric sales. Anywhere within this
range, our cost calculations have shown that NGCC technology is more
cost-effective than simple cycle technology. Therefore, we are
finalizing our determination that modern, efficient NGCC technology is
the BSER for base load natural-gas fired combustion turbines.
(3) Simple Cycle Turbines
Many commenters mistakenly thought that the EPA proposed to require
some simple cycle combustion turbines to meet an emission standard of
1,000 lb CO2/MWh-g, a level that they assert is
unachievable. On the contrary, the EPA is not finding that NGCC
technology and a corresponding emission standard of 1,000 lb
CO2/MWh-g is the BSER for simple cycle turbines. Instead,
the EPA is finding that NGCC technology is the BSER for base load
turbine applications. This means that if an owner or operator wants to
sell more electricity to the grid than the amount derived from a unit's
nameplate design efficiency calculated as a percentage of potential
electric output, then the owner or operator should install a NGCC unit.
If the owner or operator elects to install a simple cycle turbine
instead, then the practical effect of our final standards will be to
limit the electric sales of that unit so that it serves primarily peak
demand, not to subject it to an unachievable emission standard.
b. Non-base Load Natural Gas-Fired Load Units
To identify the BSER for non-base load natural gas-fired units, we
evaluated a range of technologies, including partial CCS, high-
efficiency NGCC technology designed for base load applications, fast-
start NGCC, high-efficiency simple cycle units (i.e., aeroderivative
turbines), and clean fuels. For each of these technologies, we
considered technical feasibility, costs, energy and non-air quality
impacts, potential for emission reductions, and ability to promote
technology.
While CCS would result in emission reductions and promote the
development of new technology, we concluded that CCS does not meet the
BSER criteria because the low capacity factors and irregular operating
patterns (e.g., frequent starting and stopping and operating at part
load) of non-base load units make the technical challenges associated
with CCS even greater than those associated with base load units. In
addition, because the CCS system would remain idle for much of the time
while these units are not running, CCS would be less cost-effective for
these units than for base load units.
We have also concluded that the high-efficiency NGCC units designed
for base load applications do not meet any of the BSER criteria for
non-base load units. First, non-base load units need to be able to
start and stop quickly, and NGCC units designed for base load
applications require relatively long startup and shutdown periods.
Therefore, conventional NGCC designs are not technically feasible for
the non-base load subcategory. Also, non-base load units operate less
than 10 percent of the time on average. As a result, conventional NGCC
units designed for base load applications, which have relatively high
capital costs, will not be cost-effective if operated as non-base load
units. In addition, it is not clear that a conventional NGCC unit will
lead to emission reductions if used for non-base load applications. As
some commenters noted, conventional NGCC units have relatively high
startup and shutdown emissions and poor part-load efficiency, so
emissions may actually be higher compared with simple cycle
technologies that have lower overall design efficiencies but better
cycling efficiencies. Finally, requiring conventional NGCC units as the
BSER for non-base load combustion turbines would not promote technology
because these units would not be fulfilling their intended role. In
fact, it could hamper the development of technologies with lower design
efficiencies that are specifically designed to operate efficiently as
non-base load units (i.e., high-efficiency simple cycle and fast-start
NGCC units). For all these reasons, we have concluded that conventional
NGCC units designed for base load applications are not the BSER for
non-base load natural gas-fired units.
Compared to conventional NGCC technology, fast-start NGCC units
have lower design efficiencies, but are able to start and ramp to full
load more quickly. Therefore, it is possible that requiring fast-start
NGCC as the BSER for non-base load units would result in emission
reductions and further promote the development of fast-start NGCC
technology, which is relatively new and advanced. However, because the
[[Page 64616]]
majority of non-base load combustion turbines operate less than 10
percent of the time, it would be cost-prohibitive to require fast-start
NGCC, which have relatively high capital costs compared to simple cycle
turbines, as the BSER for all non-base load applications. Also, as we
explained above in Section IX.B.2, we do not have sufficient emissions
data for fast-start NGCC units operating over the full range of non-
base load conditions (e.g., peaking, cycling, etc.), so we would not be
able to establish a reasonable emission standard.
High-efficiency simple cycle turbines are primarily used for
peaking applications. High-efficiency simple cycle turbines often
employ aeroderivative designs because they are more efficient at a
given size and are able to startup and ramp to full load more quickly
than industrial frame designs. Requiring high-efficiency simple cycle
turbines as the BSER could result in some emission reductions compared
with conventional simple cycle turbines. It would also promote
technology development by incentivizing manufacturers to increase the
efficiency of their simple cycle turbine models. However,
aeroderivative designs have higher initial costs that must be weighed
against the specific peak-load profiles anticipated for a particular
new non-base load unit. Many utility companies have elected to install
the heavier industrial frame turbines because the ramping capabilities
of aeroderivative turbines are not required for their system demand
profiles (i.e., the speed and durations of daily changes in electricity
demand), and the fuel savings do not justify the higher initial costs.
We currently do not have precise enough costing information to compare
the cost-effectiveness of aeroderivative turbines and industrial frame
turbines for all non-base load applications. Determining cost-
effectiveness is further complicated because the efficiencies of the
available aeroderivative and industrial frame technologies
significantly overlap. For example, the efficiencies of aeroderivative
turbines range from 32 to 39 percent, while the efficiencies of
industrial frame turbines range from 30 to 36 percent. Based on these
cost uncertainties, we cannot conclude that high-efficiency simple
cycle turbines are the BSER for natural gas-fired non-base load
applications at this time.
The final option that we considered for the BSER was clean fuels,
specifically natural gas with a small allowance for distillate oil. The
use of clean fuels is technically feasible for non-base load units.
Based on available EIA data,\536\ natural gas comprises more than 96
percent of total heat input for simple cycle combustion turbines. In
addition, natural gas is frequently the lowest cost fossil fuel used in
combustion turbines, so it is cost-effective. Clean fuels will also
result in some emission reductions by limiting the use of fuels with
higher carbon content, such as residual oil. Finally, the use of clean
fuels will not have any significant energy or non-air quality impacts.
Based on these factors, the EPA has determined that the BSER for non-
base load natural gas-fired units is the use of clean fuels,
specifically natural gas with a small allowance for distillate oil.
Natural gas has approximately thirty percent lower CO2
emissions per million Btu than other fossil fuels commonly used by
utility sector non-base load units.
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\536\ http://www.eia.gov/electricity/data/eia923/.
---------------------------------------------------------------------------
c. Multi-Fuel-Fired Units
To identify the BSER for multi-fuel-fired units, we again evaluated
CCS, NGCC technology, high-efficiency simple cycle units (i.e.,
aeroderivative turbines), and clean fuels. For each of these
technologies we considered technical feasibility, costs, energy and
non-air quality impacts, emission reductions, and technology promotion.
For many of the same reasons we provided above in our discussion of the
BSER for non-base load natural gas-fired combustion turbines, only
clean fuels meets the BSER criteria for multi-fuel-fired units.
While CCS would result in emission reductions and the promotion of
technology, we concluded that CCS does not meet the BSER criteria
because multi-fuel-fired units tend to start, stop, and operate at part
load frequently. Also, there are impurities and contaminants in some
alternate fuels which make the technical challenges of applying CCS to
multi-fuel-fired units greater than for natural gas-fired units.
In regards to NGCC technology, we have concluded that it is
technically feasible, would result in emission reductions, is cost-
effective, and would promote the development of technology. However, a
BSER determination based on the use of NGCC technology could pose
challenges for facilities operating in remote locations and certain
industrial facilities. In remote locations, the construction of a NGCC
facility is often not practical because it requires larger capital
investments and significant staffing for construction and operation. In
contrast, simple cycle turbines are cheaper and can be operated with
minimal staffing. Also, many industrial facilities do not have the
space available to build a HRSG and the associated cooling tower.
Therefore, requiring NGCC as the BSER could have unforeseen energy
impacts at these types of facilities. Moreover, these same kinds of
facilities also burn by-product fuels. Faced with a decision to install
an NGCC unit, these facilities might seek alternative energy options,
which could lead to increased flaring or venting of by-product fuels
because they are no longer being burned onsite for energy recovery.
Therefore, in light of these potential energy and non-air quality
impacts, we have concluded that NGCC technology is not the BSER for
multi-fuel-fired combustion turbines.
Similarly, while high-efficiency simple cycle turbines would result
in emission reductions and promote the advancement of this technology,
we are not confident that high-efficiency simple cycle units are
technically feasible or cost-effective for this subcategory.
Aeroderivative turbines are not as flexible with regards to what fuels
that can be burned. Because by-product fuels vary in composition, it is
not clear that all by-products fuels could be burned in a high-
efficiency simple cycle turbine. In addition, even if a by-product fuel
could be burned in an aeroderivative turbine, we do not have
information on the potential for increased maintenance costs, so we
cannot determine whether using high-efficiency simple cycle turbines
would be cost-effective.
The final option that we considered for the BSER was clean fuels.
The use of clean fuels is technically feasible and cost-effective. The
use of clean fuels also provides an environmentally beneficial
alternative to the flaring or venting of by-product fuels and limits
the use of dirtier fuels with higher CO2 emission rates,
such as residual oils. Clean fuels also promote technology development
by allowing manufacturers to develop new combustion turbine designs
that are capable of burning by-product fuels that currently cannot be
burned in combustion turbines. Finally, the use of clean fuels does not
have any significant energy or non-air quality impacts. Based on these
factors, the EPA has determined that the BSER for multi-fuel-fired
combustion turbines is the use of clean fuels.
D. Achievability of the Final Standards
We are finalizing emission standards for three subcategories of
combustion turbines. Specifically, units that sell electricity in
excess of a threshold based on their design efficiency and that burn
more than 90 percent natural gas (i.e., base load natural gas-fired
units) will be
[[Page 64617]]
subject to an output- based standard. The output-based standard is
based on the performance of existing NGCC units and takes into account
a range of operating conditions, future degradation, etc. Units not
meeting either the percentage electric sales or natural gas-use
criteria (i.e., non-base load natural gas-fired and multi-fuel units,
respectively) will be subject to an input-based standard based on the
use of clean fuels. This section summarizes what emission standards we
proposed and related issues we solicited comment on, describes the
comments we received regarding the proposed emission standards and our
responses to those comments, and provides our rationale for the final
emission standards.
1. Proposed Standards
For large newly constructed, modified, and reconstructed stationary
combustion turbines (base load rating greater than 850 MMBtu/h), we
proposed an emission standard of 1,000 lb CO2/MWh-g. For
small stationary combustion turbines (base load rating of 850 MMBtu/h
or less), we proposed an emission standard of 1,100 lb CO2/
MWh-g. We also solicited comment on a range of 950-1,100 lb
CO2/MWh-g for large stationary combustion turbines and a
range of 1,000-1,200 lb CO2/MWh-g for small stationary
combustion turbines.
In addition, we solicited comment on increasing the size
distinction between large and small stationary combustion turbines to
900 MMBtu/h to account for larger aeroderivative designs; increasing
the size distinction to 1,000 MMBtu/h to account for future incremental
increases in base load ratings; increasing the size distinction to
between 1,300 to 1,800 MMBtu/h; and eliminating the size subcategories
altogether. To account for potential reduced efficiencies when units
are not operating at base load, we also solicited comment on whether a
separate, less stringent standard should be established for non-base
load combustion turbines.
2. Comments
As described previously, we are not finalizing the size-based
subcategories that we proposed and instead are finalizing emission
standards for sales- and fuel-based subcategories. Specifically, we are
finalizing emission standards for three subcategories of stationary
combustion turbines: base load natural-gas fired units, non-base load
natural gas-fired units and multi-fuel-fired units. The relevant
comments concerning the emission standards for the first two
subcategories are discussed below. Any comments we received supporting
tiered emission standards are included in the discussion of non-base
load natural gas-fired units. We did not receive comments on an
appropriate emission standard for multi-fuel-fired units.
a. Emission standards for Base Load Natural Gas-Fired Units
Many commenters stated that the proposed emission standards did not
properly take into account the losses in efficiency that occur due to
long-term degradation over multiple decades, operation at non-base load
conditions (load cycling, frequent startups and shutdowns, and part-
load operations), site-specific factors such as ambient conditions and
cooling technology, and secondary fuel use (e.g., distillate oil).
These commenters stated that the EPA should conduct a more
comprehensive analysis that addresses worst-case conditions for each of
these factors. They also stated that all of the units included in the
analysis supporting the proposal were relatively new and therefore have
experienced limited degradation. The commenters stated that, while some
degradation in efficiency can be recovered during periodic maintenance
outages, it is not always possible or feasible to repair a degraded
component immediately because repairs often involve extended outages
that must be scheduled well in advance. They stated that a new unit
that initially could meet the standard at base load conditions can
experience increasing heat rates with age even when adhering to the
manufacturer's recommended maintenance program.
Some commenters stated that the proposed standards were derived by
looking at emissions data from years with historically low natural gas
prices. They surmised that the NGCC units were taking advantage of
these prices by running at historically high capacity factors and
concluded that the efficiencies and CO2 emission rates
underlying the proposed standards were not representative of periods
with higher natural gas prices. Other commenters said that many NGCC
units are increasingly required to cycle and operate at lower
capacities (compared to the proposal's baseline) to accommodate hourly
variations in intermittent renewable generation. They anticipated that
this type of generation will increase, requiring NGCC units to start,
stop, and operate at part load more frequently than in the past,
increasing CO2 emissions.
Some commenters indicated that, during startup, combustion turbines
must be operated at low load for extended periods to gradually warm up
the HRSG to minimize thermal stresses on pressure vessels and boiler
tubes. During these startup periods, significant CO2
emissions occur, but steam production is not sufficient for the steam
turbine generator to produce electricity. They also stated that a
similar situation occurs during shutdown when the steam cycle does not
generate electricity, but the combustion turbine is still combusting
fuel as it proceeds through the shutdown process. These commenters
recommended that the EPA could address these issues by creating a
subcategory for NGCC units that cycle and operate at intermediate load.
Many commenters said that site-specific factors can often preclude
operators from achieving design efficiencies based on ISO conditions.
These factors include high elevations, high ambient temperatures, and
cooling system constraints. They stated that local water temperatures
can impact condenser operating pressure and heat rates. They also said
that areas with limited water resources could require systems that rely
on air-cooled condensers, which cannot achieve thermal efficiencies
comparable to water-cooled plants. These commenters stated that the
final rule should include provisions for addressing site-specific
constraints that preclude individual affected EGUs from achieving the
emissions rates achieved on average by other sources.
Some commenters stated that the proposed standards for modified and
reconstructed combustion turbines would foreclose future opportunities
for operators to undertake projects to restore the performance of both
degraded units subject to the NSPS and existing, pre-NSPS units. They
said that it is not possible to bring older combustion turbines (built
prior to the year 2000) up to the efficiency levels of modern units
because many newer technological options that deploy higher
temperatures are not available for pre-2000 combustion turbines.
Commenters from the power sector generally supported increasing the
standards to 1,100 lb CO2/MWh-g and 1,200 lb CO2/
MWh-g for the newly constructed large and small turbines, respectively.
They also advocated finalizing standards for modified and reconstructed
standards that are 10 percent higher than the final standards for new
sources because combustion turbines constructed prior to 2000 were not
included in the EPA's analysis.
Conversely, some commenters stated that the proposed standards for
combustion turbines do not reflect the emission rates that are
achievable by
[[Page 64618]]
modern, efficient NGCC power blocks. These commenters stated that the
appropriate standard, consistent with Congressional objectives under
CAA section 111, should be 800 lb CO2/MWh-g based on the
performance of the lowest emitters in the CAMD database. Some
commenters stated that a standard of 850 lb CO2/MWh-g
reflects BSER for high-capacity factor units because half of the NGCC
units in the CAMD database are achieving this level of emissions. One
commenter from the power sector who operates NGCC power plants stated
that the final standard for new large combustion turbines should be 925
lb CO2/MWh-g. Another commenter also supported an emission
standard of 925 lb CO2/MWh-g, which is consistent with
recent BACT determinations in the state of New York. Several other
commenters stated that a reasonable standard for new large combustion
turbines should be 950 lb CO2/MWh-g and that the final
standard for new small combustion turbines should be 1,000 lb
CO2/MWh-g. Numerous commenters stated that the final
standards for new sources should not exceed 1,000 lb CO2/
MWh-g for either large or small combustion turbines. Other commenters
stated that, because the standards were developed based on emission
rates that are being achieved by the majority of existing units, the
final standards should be the same for new, modified, and reconstructed
units.
b. Emission Standards for Non-Base Load Natural Gas-Fired Units and
Multi-Fuel-Fired Units
Many commenters stated that the EPA cannot finalize ``no emission
standard'' for non-base load units, which the EPA solicited comment on
in the broad applicability approach. They argued that this approach was
not consistent with the definition of ``standard of performance'' in
CAA section 111(a)(1), which requires there to be an ``emission
limitation'' that reflects a ``system of emission reduction.'' Some
commenters recommended that non-base load units should be subject to
work practice standards, such as operating safely with good air
pollution control practices, including CO2 monitoring and
reporting requirements. Other commenters pointed to recent PSD permits
that include tiered emission limits for the different roles served by
combustion turbines. They cited BACT limits from 1,328 to 1,450 lb
CO2/MWh-g for peaking units. One commenter supported tiered
limits consistent with recent BACT determinations in the state of New
York, which include limits for simple cycle combustion turbines of
1,450 lb CO2/MWh-g. An air quality regulator from a state
with rapidly increasing renewable generation supported a limit of 825
lb CO2/MWh-g for all base load NGCC units; 1,000 lb
CO2/MWh-g for large intermediate load NGCC units; 1,100 lb
CO2/MWh-g for small intermediate load NGCC units. This
commenter also recommended that the EPA set a numerical limit
specifically for peaking units after the completion of a peaking unit-
specific BSER analysis. Several commenters supported tiered standards
based on capacity factor. They proposed 825 lb CO2/MWh-g for
base load units (those operating over 4,000 hours annually), 875 lb
CO2/MWh-g for intermediate and load-following units (those
operating between 1,200 and 4,000 hours annually), and 1,100 lb
CO2/MWh-g for peaking units (those operating less than 1,200
hours per year).
3. Final Standards
a. Newly Constructed Base Load Natural Gas-Fired Units
In evaluating the achievability of the base load natural gas-fired
emission standard, we focused on three types of data. Specifically, we
looked at existing NGCC emission rates, recent PSD permit limits for
CO2 emissions, and NGCC design efficiency data and
specifications. Based on this analysis, we have concluded that an
emission rate of 1,000 lb CO2/MWh-g is appropriate for all
base load natural gas-fired combustion turbines, regardless of size.
Since the standards were proposed, the EPA has expanded the NGCC
emission rate analysis that supported the proposed emission standards
to include emissions information for NGCC units that commenced
operation in 2011, 2012, and 2013, and updated the emissions data to
include emissions through 2014. In our analysis, we evaluated 345 NGCC
units with online dates ranging from 2000 to 2013. The analysis
included emissions data from 2007 to 2014 as submitted to the EPA's
CAMD. The average maximum 12-operating-month CO2 emission
rate for all NGCC units was 897 lb CO2/MWh-g, with
individual unit maximums ranging from 751 to 1,334 lb CO2/
MWh-g.
Consistent with our proposed size-based subcategories, we also
reviewed the emissions data for small and large NGCC units separately.
For small units, we evaluated emissions data from 17 NGCC units with
heat input ratings of 850 MMBtu/h or less. These units had an average
maximum 12-operating-month CO2 emission rate of 953 lb/MWh-
g. Individual unit maximum emission rates ranged from 898 to 1,175 lb
CO2/MWh-g. Two of the units had a maximum emissions rate
equal to or greater than 1,000 lb CO2/MWh-g.\537\ However,
one of the units with a maximum emission rate above 1,000 lb
CO2/MWh-g was only selling approximately 20 percent of its
potential electric output (significantly below the design-specific
percentage electric sales threshold) when the emission rate occurred.
If this unit were a new unit, the applicable emission standard would be
the heat input-based clean fuels standard, and the unit would not be
out of compliance. Therefore, 16 of the 17 existing small NGCC units
have demonstrated that an emission rate of 1,000 lb CO2/MWh-
g is achievable. In addition, the six newest units, which commenced
construction between 2007 and 2012, all have maximum 12-operating-month
emission rates of less than 950 lb CO2/MWh-g. While these
units might not be old enough to have experienced degradation, their
maximum emission rates demonstrate that the final standard of 1,000 lb
CO2/MWh-g includes a significant compliance margin for any
future degradation.
---------------------------------------------------------------------------
\537\ For emission standards of 1,000 lb CO2/MWh-g
and above, the emission standard uses three significant figures. See
Section X.D.
---------------------------------------------------------------------------
For large units, the average maximum 12-operating-month emission
rate was 895 lb CO2/MWh-g, with individual unit maximum
emission rates ranging from 751 to 1,334 lb CO2/MWh-g.
Twenty-three of the 328 large NGCC units had maximum 12-operating-month
emission rates greater than 1,000 lb CO2/MWh-g. While we do
not have precise design efficiency information for each of these units,
and thus cannot calculate the precise percentage electric sales
threshold to which each unit would be subject, it appears that all of
the emission rates in excess of 1,000 lb CO2/MWh-g occurred
during periods when electric sales were low and would be below the
threshold. Thus, if these units were new units, they would only have to
comply with the heat input-based clean fuels standard. Therefore,
essentially all existing NGCC units would have been in compliance with
the final emission standard. We note also that there are 51 new NGCC
units that have started operation since 2010, and the average maximum
12-operating-month emission rate for these units is 833 lb
CO2/MWh-g. Therefore, the final emission standard includes a
very significant compliance margin to account for any potential future
degradation of large units.
[[Page 64619]]
To evaluate degradation further, the EPA reviewed the emission rate
information for the 55 oldest NGCC units in our data set (i.e., units
that came online in 2000 and 2001). According to the commenters, we
should expect to see degradation when reviewing the annual emissions
data for these turbines because they are 14 to 15 years old. However,
we did not see any sign of degradation. The CO2 rates for
these turbines have little standard deviation between 2007 and 2014. In
addition, there were many instances where the CO2 emission
rate of a unit actually decreased with age. This indicates that the
efficiency of the unit is increasing, possibly as a result of good
operating and maintenance procedures or upgrades to equipment that
improved efficiency beyond the original design. Based on these
findings, we have concluded that our analysis adequately accounts for
potential degradation.
We also evaluated the impact of elevation, ambient temperature,
cooling type, and operating conditions (startups, shutdowns, and
average run time per start) because commenters indicated that these
could affect a unit's ability to achieve the standard. We saw little
correlation between elevation or ambient temperature and emission rate.
In addition, any correlation was relatively small and would have an
insignificant impact on the ability of a unit to achieve the final
standard. We identified 32 large NGCC units with dry cooling towers.
The average maximum 12-operating-month emission rate for this group of
units was 875 lb CO2/MWh. This rate was actually lower than
the average rate for the large NGCC group as a whole. Based on these
findings, we have concluded that the final emission standard will not
limit the use of dry cooling technologies. Finally, the EPA evaluated
the impact of run time per start, average duty cycle, and number of
starts on emission rates. While these factors do influence emission
rates, the non-base load natural gas-fired subcategory inherently
addresses efficiency issues related to operating conditions.
In addition to evaluating existing NGCC emissions data, the EPA
reviewed the CO2 emission limits included in PSD
preconstruction permits issued since January 1, 2011. We evaluated all
permit limits over an annual period. In total, we identified 31 major
source PSD permits with 39 discrete limits on CO2 emissions.
Eight of the limits were expressed in terms of lb/h or tons per year,
so we did not include them in the analysis. In addition, one CHP unit
that generates electricity and supplies steam to a chemical plant was
in the data set. This facility had a permit limit of 1,362 lb
CO2/MWh based only on gross electrical output and does not
account for useful thermal output. Therefore, we did not include it in
the analysis either. Finally, we excluded two permits that did not
clearly specify if the output-based standard was on a gross or net
basis.
The remaining 28 permit limits were expressed in lb CO2/
MWh or a heat rate basis that could be converted to lb CO2/
MWh. Eight permit limits were based on net output, ranging from 774-936
lb CO2/MWh-n. The lowest emission limit was for a hybrid
power plant with a solar component that could contribute up to 50 MW.
Twenty permit limits were based on gross output, ranging from 833-1,100
lb CO2/MWh-g. Of these 28 permit limits, the only limit in
excess of our final emission standard of 1,000 lb CO2/MWh-g
is for a relatively small NGCC unit (base load rating of 366 MMBtu/h)
that commenced construction prior to the proposal and thus will not be
subject to the requirements of this final rule.
Each of the permit limits discussed above that is 1,000 lb
CO2/MWh or less includes all periods of operation, including
startup, shutdown, and malfunction events. In addition, each permit
limit was set after back up and additional fuel use were taken into
consideration. While some permits restrict fuel use to only natural
gas, others allow limited usage (duration and type) of back up and
other fuels. For example, the Pioneer Valley Energy Center has
unrestricted use of natural gas, but can burn ultra-low sulfur diesel
(ULSD) for up to 1,440 hours per 12-month period. This permit requires
the unit to comply with a limit of 895 lb CO2/MWh-n even
when burning up to 16 percent distillate oil. Each permit limit takes
into account the mode of operation for the combustion turbine. For
example, the permit for the Lower Colorado River Authority's Ferguson
plant evaluated emission limits for the plant at 50, 75, and 100
percent gross load. The emission limit of 918 lb CO2/MWh-n
accounts for the unit's expected operation at 50 percent gross load.
For NGCC units with duct burners on their HRSGs, the permit limits
account for the hours of operation with duct burners firing. Finally,
most of these permits include compliance margins to account for
efficiency losses due to degradation and other factors (e.g., actual
operating parameters, site-specific design considerations, and the use
of back up fuel). In total, these compliance margins result in a 10 to
13 percent increase in the permitted CO2 emission limits,
yet all of the limits except one were still below 1,000 lb
CO2/MWh-g.
Finally, we also reviewed NGCC design efficiency data and
specifications submitted to Gas Turbine World. Specifically, we
reviewed the reported efficiency data for 88 different 60 Hz NGCC units
manufactured by Alstom, GE Energy Aeroderivative and Heavy Duty,
Mitsubishi Heavy Industries, Pratt & Whitney, Rolls-Royce, and Siemens
Energy. The designs ranged in model year from 1977 to 2011, capacities
ranged from 31 to 1,026 MW, and base load ratings ranged from 236 to
3,551 MMBtu/h. The average reported design emission rate for these
units was 834 lb CO2/MWh-n and ranged from 725 to 941 lb
CO2/MWh-n. Therefore, our optional standard of 1,030 lb
CO2/MWh-n would allow for an average compliance margin of 24
percent, with a range from 10 to 42 percent, over the design rate.
Ninety-five percent of designs would have a compliance margin of 13
percent or more, the top end of the range of compliance margins
determined to be appropriate in the PSD permits we reviewed.
Because some commenters were concerned that smaller NGCC units will
not be able to achieve the emission standard, we specifically
considered the design rates for smaller units. For the 52 small units
(base load rating of 850 MMBtu/h or less), the average design emission
rate was 865 lb CO2/MWh and ranged from 796 to 941 lb
CO2/MWh-n. Therefore, our optional standard of 1,030 lb
CO2/MWh-n would allow for an average compliance margin of 19
percent, with a range of 10 to 29 percent, over the design rate.
Ninety-five percent of small NGCC designs would have a compliance
margin of 13 percent or more.
We further refined our analysis by only considering the most
efficient design for a given combustion turbine engine. For example, GE
Energy Aeroderivative offers four design options for its LM2500 model-
type, all with a rating of approximately 45 MW. The design emission
rates for these various options range from 827 to 914 lb
CO2/MWh-n. When only the most efficient models for a
particular combustion turbine engine design are considered, all NGCC
models have over a 13 percent compliance margin. In other words,
developers of new base load natural gas-fired combustion turbines
concerned about the achievability of the final standard have multiple
more efficient options offered by the same manufacturer. Therefore, we
have concluded that the final emission standard allows sufficient
flexibility for end users to select an
[[Page 64620]]
NGCC design appropriate for their specific requirements.
After considering these three sources of information--actual NGCC
emission rate data, PSD permit limits for NGCC facilities, and NGCC
design information--we have concluded that a standard of 1,000 lb
CO2/MWh is both achievable and appropriate for newly
constructed base load natural gas-fired combustion turbines. While we
anticipate that the large majority of new NGCC units will operate well
below this emission rate, this standard provides flexibility for
developers to take into account site-specific conditions (e.g., ambient
conditions and cooling system), operating characteristics (e.g., part-
load operation and frequent starting and stopping), and reduced
efficiency due to degradation. The standard also accommodates the full
size range of turbines.
We also expect multiple technology developments to further increase
the performance of new base load natural gas-fired stationary
combustion turbines. Vendors continue to improve the single cycle
efficiency of combustion turbines. The use of more efficient combustion
turbine engines improves the overall efficiency of NGCC facilities. In
addition, existing smaller NGCC facilities were likely designed using
single or dual pressure HRSGs without a reheat cycle. New designs can
incorporate three pressure steam generators with a reheat cycle to
improve the overall efficiency of the NGCC facility. Finally,
additional technologies to reduce emission rates for new combustion
turbines include CHP and integrated non-emitting technologies. For
example, an NGCC unit that is designed as a CHP unit where ten percent
of the overall output is useful thermal output would have an emission
rate approximately five percent less than an electric-only NGCC. In
sum, we believe that our final emission standards of 1,000 lb
CO2/MWh-g and 1,030 lb CO2/MW-n are not only
readily achievable, but likely conservative.
b. Reconstructed Base Load Natural Gas-Fired Units
We disagree with commenters that stated that reconstructed
combustion turbines will not be able to achieve the proposed emission
standards. For the reasons listed below, we have concluded that an
existing base load natural-gas fired unit that reconstructs can achieve
an emission rate of 1,000 lb CO2/MWh-g, regardless of its
size.
Highly efficient NGCC units include (1) an efficient combustion
turbine engine, (2) an efficient steam cycle, and (3) a combustion
turbine exhaust system that is ``matched'' to the steam cycle for
maximum efficiency. In order for an existing NGCC unit to trigger the
reconstruction provisions, the unit would have to essentially be
entirely rebuilt. This would involve extensive upgrades to both the
combustion turbine engine and the HRSG. Therefore, a reconstructed NGCC
unit will be able to maximize the efficiency of the turbine engine and
the steam cycle and match the two for maximum efficiency.
According to comments submitted in response to the proposal for
existing sources under CAA section 111(d), there are various options
available to improve the efficiency of existing combustion turbines.
One combustion turbine manufacturer provided comments describing
specific technology upgrades for the compressor, combustor, and gas
turbine components. This manufacturer stated that operators of existing
turbines can replace older internal components along the gas path with
state-of-the-art components that have higher aerodynamic efficiencies
and improved seal designs. These gas-path enhancements enable existing
sources to both improve the efficiency of the turbine engine and
improve the systems used for cooling the metal parts along the hot-gas
path to allow existing systems to achieve higher operating
temperatures. In total, the manufacturer stated that utilities
deploying these gas-path improvements on reconstructed industrial frame
combustion turbines with nominal output ratings of 170 to 180 MW can
increase their output by 10 MW while reducing CO2 emissions
by more than 2.6 percent compared to baseline. In addition to gas-path
and software improvements, the manufacturer stated that the newest low-
NOX combustor designs can be retrofitted on modified and
reconstructed turbines to achieve lower NOX emissions, which
improves turndown (i.e., to enable stable operations at lower loads
compared to the lowest stable load achievable at baseline conditions)
and efficiencies across all load conditions. The manufacturer indicated
that operators of existing combustion turbines deploying both state-of-
the-art gas-path and software upgrades and combustor upgrades can
increase output on frame-style turbines with nominal output ratings of
170 to 180 MW by 14 MW, while reducing CO2 emissions by 2.8
percent. In addition to the preceding upgrades, the manufacturer stated
that existing combustion turbines can achieve the largest efficiency
improvements by upgrading existing compressors with more advanced
compressor technologies, potentially improving the combustion turbine's
efficiency by an additional 3.8 percent. Thus, the total potential
CO2 emissions reductions for just the combustion turbine
portion of a combined cycle unit is 6.6 percent.
In addition to upgrades to the combustion turbine engine, an
operator reconstructing a NGCC unit will have the opportunity to
improve the efficiency of the HRSG and steam cycle. For example, a
steam turbine manufacturer identified three retrofit technologies
available for reducing the CO2 emissions rate of existing
steam turbines by 1.5 to 3 percent: (1) Steam-path upgrades can
minimize aerodynamic and steam leakage losses; (2) replacement of the
existing high pressure turbine stages with state-of-the-art stages
capable of extracting more energy from the same steam supply; and (3)
replacement of low-pressure turbine stages with larger diameter
components that extract additional energy and that reduce velocities,
wear, and corrosion.
In addition, an operator reconstructing a NGCC unit could upgrade
the entire steam cycle. For example, combined cycle units originally
constructed with only a single pressure level can be upgraded to also
include second and third pressure levels. Studies
538 539 540 show that converting a single pressure HRSG with
steam reheat to a double pressure configuration with steam reheat can
reduce the CO2 emission rate of a NGCC unit by 1.5 to 1.7
percent. These same studies show that converting from a single pressure
configuration with reheat to a triple pressure configuration with
reheat can yield a 1.8 to 2 percent reduction in the CO2
emission rate. Similarly, units constructed with only a double pressure
configuration without reheat can obtain a 0.4 percent reduction by
adding a reheat cycle or a 0.9 percent reduction by converting to a
triple pressure configuration and adding a reheat cycle. Existing NGCC
turbines that convert to these advanced HRSG configurations and that
deploy the previously discussed combustion turbine and steam turbine
upgrades can
[[Page 64621]]
realize CO2 emission rate reductions ranging from 6 to 10
percent, depending on their baseline design and condition. Based on the
available options to improve the efficiency of existing NGCC units and
the fact that the vast majority of existing NGCC units are already
achieving emission rates of 1,000 lb CO2/MWh-g or less, we
have concluded that all reconstructed NGCC units can achieve this
emission rate.
---------------------------------------------------------------------------
\538\ ``Exergetic and Economic Evaluation of the Effects of HRSG
Configurations on the Performance of Combined Cycle Power Plants.''
M. Mansouri, et al. Energy Conversion and Management 58:47-58, 2012.
\539\ ``Combined Cycle Power Plant Performance Analyses Based on
Single-Pressure and Multipressure Heat Recovery Steam Generator.''
M. Rahim, Journal of Energy Engineering, 138:136-145, 2012.
\540\ ``Thermodynamic Evaluation of Combined Cycle Plants.'' N.
Woudstras et al. Energy Conversion and Management 51:1099-1110,
2010.
---------------------------------------------------------------------------
Finally, we note that an owner or operator that is considering
reconstructing an existing simple cycle turbine should decide how they
wish to operate that turbine in the future. If they anticipate
operating above the percentage electric sales threshold, then they
should install a HRSG and steam turbine and convert to a NGCC power
block in accordance with our determination that NGCC is the BSER for
base load applications. If they intend to operate the turbine below the
percentage electric sales threshold, however, then the clean fuels
standard, described below, will apply.
c. Newly Constructed and Reconstructed Non-Base Load Natural Gas-Fired
Units
The EPA agrees with the commenters who stated that ``no emission
limit'' would be inconsistent with the requirements of CAA 111(a)(1).
We therefore are finalizing an input-based standard based on the use of
clean fuels for non-base load natural gas-fired combustion turbines in
recognition that efficiency can be reduced due to operation at low
loads, cycling, and frequent startups. The EPA has concluded that, at
this time, we do not have sufficient information to set a meaningful
output-based standard for non-base load natural gas-fired combustion
turbines. The input-based standard requires non-base load units to burn
fuels with an average emission rate of 120 lb CO2/MMBtu or
less. This standard is readily achievable because the CO2
emission rate of natural gas is 117 lb CO2/MMBtu. The most
common back up fuel is distillate oil, which has a CO2
emission rate of 163 lb CO2/MMBtu. A non-base load natural
gas-fired combustion turbine burning 9 percent distillate oil and 91
percent natural gas has an emission rate of 121 lb CO2/
MMBtu, which rounds to 120 lb CO2/MMBtu using two
significant digits. Therefore, the vast majority of owners and
operators of non-base load natural gas-fired combustion turbines will
be able to achieve the standard using business-as-usual fuels.
While the emission reductions that will result from restricting the
use of fuels with higher CO2 emission rates is minor, the
compliance burden is also minimal. Owners and operators of non-base
load natural gas-fired combustion turbines burning fuels with
consistent chemical compositions that meet the clean fuels requirement
(e.g., natural gas, ethane, ethylene, propane, naphtha, jet fuel
kerosene, fuel oils No. 1 and 2, and biodiesel) will only need to
maintain records that they burned these fuels in the combustion
turbine. No additional recordkeeping or reporting will be required.
Owners and operators burning fuels with higher CO2 emission
rates and/or chemical compositions that vary (e.g., residual oil, non-
jet fuel kerosene, landfill gas) will have to follow the procedures in
part 98 of this part to determine the average CO2 emission
rate of the fuels burned during the applicable 12-operating-month
compliance period and submit quarterly reports to verify that they are
in compliance with the required emission standard.
d. Newly Constructed and Reconstructed Multi-Fuel-Fired Units
We also are finalizing an input-based standard based on the use of
clean fuels, as opposed to an output-based standard, for multi-fuel
units for several reasons. Specifically, we do not currently have
continuous CO2 emissions data for multi-fuel-fired units, we
have not evaluated the potential efficiency impacts of different fuels,
and the range of carbon content of non-natural gas fuels complicates
establishing an appropriate output-based standard. Based on this lack
of data, we have concluded that we cannot establish an output-based
emission standard for multi-fuel-fired combustion turbines at this
time.
The input-based emissions standard for this subcategory is based on
the use of clean fuels. The use of clean fuels will ensure that newly
constructed and reconstructed combustion turbines minimize
CO2 emissions during all periods of operation by limiting
the use of fuels with higher CO2 emission rates. To
accurately represent the BSER and limit the ability of units to co-fire
higher CO2 emitting fuels with natural gas, we have
concluded that it is necessary to use an equation based on the heat
input from natural gas to determine the applicable emission standard.
The 12-operating-month standard will vary from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending on the fraction of heat
input from natural gas. The standard will be calculated by adding the
product of the percent of heat input from natural gas and 120 with the
product of the heat input from non-natural gas fuels and 160. For
example, a combustion turbine that burns 80 percent natural gas and 20
percent distillate oil would be subject to an emission standard of 130
lb CO2/MMBtu (rounded to two significant figures), which is
equivalent to the actual emission rate of a unit burning this
combination of fuels. On the other hand, a combustion turbine that
burns 100 percent residual oil would be subject to an emission standard
of 160 lb CO2/MMBtu, but would have a higher actual emission
rate, and would thus be out of compliance. In this way, the standard
will restrict higher carbon fuels from being burned in multi-fuel-fired
units, but will be readily achievable by units burning clean fuels.
According to information submitted to the EIA, the primary, non-
natural gas fuels used by combustion turbines today for the production
of electricity should all meet our definition of a clean fuel. Thus,
while the emission reductions that will result from restricting the use
of fuels with higher CO2 emission rates is minor, the
compliance burden is also minimal. Owners and operators of multi-fuel-
fired combustion turbines burning fuels with consistent chemical
compositions that meet the clean fuels requirement (e.g., natural gas,
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2,
and biodiesel) will only need to maintain records that they burned
these fuels in the combustion turbine. No additional recordkeeping or
reporting will be required. Owners and operators burning fuels with
higher CO2 emission rates and/or chemical compositions that
vary (e.g., residual oil, non-jet fuel kerosene, landfill gas) will
have to follow the procedures in part 98 of this part to determine the
average CO2 emission rate of the fuels burned during the
applicable 12-operating-month compliance period and submit quarterly
reports to verify that they are in compliance with the required
emission standard.
e. Modified Units
The EPA is not finalizing the proposed emission standards for
stationary combustion turbines that conduct modifications. As explained
in Section XV below, we are withdrawing the June 2014 proposal with
respect to these sources. We received a significant number of comments
asserting that modified combustion turbines could not meet the proposed
emission standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/
MWh-g for small turbines. For the reasons explained in Section IX.B.1
above, we have decided not to subcategorize combustion turbines based
on size for a number of reasons and are setting a single standard of
[[Page 64622]]
1,000 lb/MWh-g for all base load natural gas-fired turbines instead.
While we are confident that all new and reconstructed units will be
able to achieve this standard, we are less confident that all smaller
combustion turbines that undertake a modification, specifically those
that were constructed prior to 2000, will be able to do so. Until we
have the opportunity to further investigate the full range of
modifications that turbine owners and operators might undertake, we
consider it premature to finalize emission standards for these sources.
Combustion turbines have unique characteristics that make
determining an appropriate emission standard for modified sources a
more challenging task than for coal-fired boilers. For example, each
combustion turbine engine has a specific corresponding combustor. The
development of more efficient combustor upgrades for existing turbine
designs typically requires manufacturers to expend considerable
resources. Consequently, not all manufacturers offer combustor upgrades
for smaller or older designs because it would be difficult to recoup
their investment. In contrast, efficiency upgrades for boilers can
generally be installed regardless of the specific boiler's
characteristics.
In addition, natural gas has the lowest CO2 emission
rate (in terms of lb CO2/MMBtu) of any fossil fuel. As a
result, an owner or operator that adds the ability to burn a back up
fuel, such as distillate oil, to an existing turbine would likely
trigger an NSPS modification. This is a relatively low-capital-cost
upgrade that would significantly increase a unit's potential hourly
emission rate, even though the annual emissions increase would be
relatively minor because operating permits generally limit the amount
of distillate oil that a unit can burn. We need to conduct additional
analysis to determine an appropriate emission standard for units that
undertake this type of modification, which does not involve any of the
combustion turbine components that impact efficiency.
To be clear, the EPA is not reaching a final decision that
modifications should be subject to different requirements than we are
finalizing in this rule for new and reconstructed sources. We have made
no decisions, and this matter is not concluded. We plan to continue to
gather information, consider the options for modifications, and develop
a new proposal for modifications in the future. Therefore, the EPA is
withdrawing the proposed standards for all combustion turbines that
conduct modifications and is not issuing final standards for those
sources at this time. See Section XV below. We note that the effect of
this withdrawal is that modified combustion turbines will continue to
be existing sources subject to section 111(d).\541\
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\541\ As discussed above in Section VI.A of this preamble, a
modified source that is not covered by a final or pending proposed
standard continues to be an ``existing source'' and so will be
covered by requirements under section 111(d). Under the definition
of ``existing source'' in section 111(a)(6), an existing source is
any source that is not a new source. Under the definition of ``new
source'' in section 111(a)(2), a modified source is a new source
only if the modification occurs after the publication of regulations
(or proposed regulations, if earlier) that will be applicable to
that source. Because we are not finalizing regulations with respect
to modified steam turbines, and are withdrawing the proposal with
respect to such sources, there are neither final regulations nor
pending proposed regulations which will be applicable to such
modifications.
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X. Summary of Other Final Requirements for Newly Constructed, Modified,
and Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating
Units and Stationary Combustion Turbines
This section describes the final action's requirements regarding
startup, shutdown, and malfunction; continuous monitoring; emissions
performance testing; continuous compliance; and notification,
recordkeeping, and reporting for newly constructed, modified, and
reconstructed affected steam generating units and combustion turbines.
We also explain final decisions regarding several of these
requirements.
A. Startup, Shutdown, and Malfunction Requirements
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the D.C. Circuit vacated portions of two provisions in the
EPA's CAA section 112 regulations governing the emissions of hazardous
air pollutants (HAP) during periods of startup, shutdown, and
malfunction (SSM). Specifically, the Court vacated the SSM exemption
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that
under section 302(k) of the CAA, emissions standards or limitations
must be continuous in nature and that the SSM exemption violates the
CAA's requirement that some CAA section 112 standards apply
continuously.
Consistent with Sierra Club v. EPA, the EPA has established
standards in this rule that apply at all times. In establishing the
standards in this rule, the EPA has taken into account startup and
shutdown periods and, for the reasons explained below as well as in
Section V.J.1 above, has not established alternate standards for those
periods. Specifically, startup and shutdown periods are included in the
compliance calculation as periods of partial load. The final method to
calculate compliance is to sum the emissions for all operating hours
and to divide that value by the sum of the electric energy output (and
useful thermal energy output, where applicable for affected CHP EGUs),
over a rolling 12-operating-month period. In their compliance
determinations, sources must incorporate emissions from all periods,
including startup or shutdown, during which fuel is combusted and
emissions are being monitored, in addition to all power produced over
the periods of emissions measurements. As explained in Section V.J.1,
given that the duration of startup or shutdown periods is expected to
be small relative to the duration of periods of normal operation and
that the fraction of power generated during periods of startup or
shutdown is expected to be very small, the impact of these periods on
the total average over a 12-operating-month period is expected to be
minimal.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead they are, by
definition sudden, infrequent and not reasonably preventable failures
of emissions control, process or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting emissions standards,
nothing in CAA section 111 requires the agency to consider malfunctions
as part of that analysis. A malfunction should not be treated in the
same manner as the type of variation in performance that occurs during
routine operations of a source. A malfunction is a failure of the
source to perform in a ``normal or usual manner'' and no statutory
language compels the EPA to consider such events in setting CAA section
111 standards of performance.
Further, accounting for malfunctions in setting emission standards
would be difficult, if not impossible, given the myriad different types
of malfunctions that can occur across all sources in the
[[Page 64623]]
category and given the difficulties associated with predicting or
accounting for the frequency, degree, and duration of various
malfunctions that might occur. As such, the performance of units that
are malfunctioning is not ``reasonably'' foreseeable. See, e.g., Sierra
Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (``The EPA typically
has wide latitude in determining the extent of data-gathering necessary
to solve a problem. We generally defer to an agency's decision to
proceed on the basis of imperfect scientific information, rather than
to `invest the resources to conduct the perfect study.' '') See also,
Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (``In the
nature of things, no general limit, individual permit, or even any
upset provision can anticipate all upset situations. After a certain
point, the transgression of regulatory limits caused by `uncontrollable
acts of third parties,' such as strikes, sabotage, operator
intoxication or insanity, and a variety of other eventualities, must be
a matter for the administrative exercise of case-by-case enforcement
discretion, not for specification in advance by regulation.''). In
addition, emissions during a malfunction event can be significantly
higher than emissions at any other time of source operation. For
example, if an air pollution control device with 99 percent removal
goes off-line as a result of a malfunction (as might happen if, for
example, the bags in a baghouse catch fire) and the emission unit is a
steady state type unit that would take days to shut down, the source
would go from 99 percent control to zero control until the control
device was repaired. The source's emissions during the malfunction
would be 100 times higher than during normal operations. As such, the
emissions over a 4-day malfunction period would exceed the annual
emissions of the source during normal operations. As this example
illustrates, accounting for malfunctions could lead to standards that
are not reflective of (and significantly less stringent than) levels
that are achieved by a well-performing, non-malfunctioning source. It
is reasonable to interpret CAA section 111 to avoid such a result. The
EPA's approach to malfunctions is consistent with CAA section 111 and
is a reasonable interpretation of the statute.
Given that compliance with the emission standard is determined on a
12-operating-month rolling average basis, the impact of periods of
malfunctions on the total average over a 12-operating-month period is
expected to be minimal. Thus, malfunctions over that period are not
likely to result in a violation of the standard.
In the unlikely 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).
If the EPA determines in a particular case that an enforcement
action against a source for violation of an emission standard is
warranted, the source can raise any and all defenses in that
enforcement action and the federal district court will determine what,
if any, relief is appropriate. The same is true for citizen enforcement
actions. Similarly, the presiding officer in an administrative
proceeding can consider any defense raised and determine whether
administrative penalties are appropriate.
In summary, the EPA interpretation of the CAA and, in particular,
CAA section 111 is reasonable and encourages practices that will avoid
malfunctions. Administrative and judicial procedures for addressing
exceedances of the standards fully recognize that violations may occur
despite good faith efforts to comply and can accommodate those
situations.
In the January 2014 proposal for newly constructed EGUs, the EPA
had proposed to include an affirmative defense to civil penalties for
violations caused by malfunctions in an effort to create a system that
incorporates some flexibility, recognizing that there is a tension,
inherent in many types of air regulation, to ensure adequate compliance
while simultaneously recognizing that despite the most diligent of
efforts, emission standards may be violated under circumstances
entirely beyond the control of the source. Although the EPA recognized
that its case-by-case enforcement discretion provides sufficient
flexibility in these circumstances, it included the affirmative defense
to provide a more formalized approach and more regulatory clarity. See
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978)
(holding that an informal case-by-case enforcement discretion approach
is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73
(9th Cir. 1977) (requiring a more formalized approach to consideration
of ``upsets beyond the control of the permit holder''). Under the EPA's
regulatory affirmative defense provisions, if a source could
demonstrate in a judicial or administrative proceeding that it had met
the requirements of the affirmative defense in the regulation, civil
penalties would not be assessed. Recently, the U.S. Court of Appeals
for the District of Columbia Circuit vacated an affirmative defense in
one of the EPA's CAA section 112 regulations. NRDC v. EPA, 749 F.3d
1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in CAA
section 112 rule establishing emission standards for Portland cement
kilns). The court found that the EPA lacked authority to establish an
affirmative defense for private civil suits and held that under the
CAA, the authority to determine civil penalty amounts in such cases
lies exclusively with the courts, not the EPA. Specifically, the Court
found: ``As the language of the statute makes clear, the courts
determine, on a case-by-case basis, whether civil penalties are
`appropriate.''' See NRDC at 1063 (``[U]nder this statute, deciding
whether penalties are `appropriate' in a given private civil suit is a
job for the courts, not EPA.'').\542\ In light of NRDC, the EPA is not
including a regulatory affirmative defense provision in this final
rule. As explained above, if a source is unable to comply with
emissions standards as a result of a malfunction, the EPA may use its
case-by-case enforcement discretion to provide flexibility, as
appropriate. Further, as the D.C. Circuit recognized, in an EPA or
citizen enforcement action, the court has the discretion to consider
any defense raised and determine whether penalties are appropriate. Cf.
NRDC, at 1064 (arguments that violations were caused by unavoidable
technology failure can be made to the courts in future civil cases when
the issue arises). The same is true for the presiding officer in EPA
administrative enforcement actions.\543\
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\542\ The court's reasoning in NRDC focuses on civil judicial
actions. The court noted that ``EPA's ability to determine whether
penalties should be assessed for Clean Air Act violations extends
only to administrative penalties, not to civil penalties imposed by
a court.'' Id.
\543\ Although the NRDC case does not address the EPA's
authority to establish an affirmative defense to penalties that is
available in administrative enforcement actions, the EPA is not
including such an affirmative defense in the final rule. As
explained above, such an affirmative defense is not necessary.
Moreover, assessment of penalties for violations caused by
malfunctions in administrative proceedings and judicial proceedings
should be consistent. Cf. CAA section 113(e) (requiring both the
Administrator and the court to take specified criteria into account
when assessing penalties).
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[[Page 64624]]
B. Continuous Monitoring Requirements
The majority of comments received on the proposal supported the
EPA's use of existing monitoring requirements under the Acid Rain
Program, which are contained in 40 CFR part 75 requirements. In
response to this, the EPA is finalizing monitoring requirements that
incorporate and reference the part 75 monitoring requirements for the
majority of the CO2 and energy output monitoring
requirements while ensuring accuracy and stringency required under the
program.
This final rule requires owners or operators of EGUs that combust
solid fossil 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 rule allows owners or operators of affected 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 rule requires 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 rule requires EGU owners or operators to prepare and submit a
monitoring plan that includes both electronic and hard copy components,
in accordance with 40 CFR 75.53(g) and (h). The electronic portion of
the monitoring plan should be submitted to the EPA's CAMD using the
Emissions Collection and Monitoring Plan System (ECMPS) Client Tool.
The hard copy portion of the plan should be sent to the applicable
state and EPA Regional office. Further, all monitoring systems used to
determine the CO2 mass emission rates have to be certified
according to 40 CFR 75.20 and section 6 of part 75, appendix A within
the 180-day window of time allotted under 40 CFR 75.4(b), and are
required to meet the applicable on-going quality assurance procedures
in appendices B and D of part 75.
The rule requires 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 adjustments).
The rule requires 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 calculating
compliance with applicable emission limits. Additionally for EGUs using
CO2 CEMS, only unadjusted stack gas flow rate values should
be used in the emissions calculations. In this rule, part 75 bias
adjustment factors (BAFs) should 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.
Additionally if an affected EGU combusts natural gas and/or fuel oil
and the CO2 mass emissions rate are measured using Equation
G-4 in appendix G of part 75, then determination of site-specific
carbon-based F-factors using Equation F-7b in section 3.3.6 of appendix
F of part 75 is allowed, and use of these Fc values in the
emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature is also allowed.
This final rule includes the following special compliance
provisions for units with common stack or multiple stack
configurations; these provisions are consistent with 40 CFR 60.13(g):
If two or more EGUs share a common exhaust stack, are
subject to the same emission limit, and the operator is required to (or
elects to) determine compliance using CEMS, then monitoring the hourly
CO2 mass emission rate at the common stack instead of
monitoring each EGU separately is allowed. If this option is chosen,
the hourly gross electrical load (or steam load) is the sum of the
hourly loads for the individual EGUs and the operating time is
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 will be in compliance with
the CO2 emissions limit.
If the operator is required to (or elects to) determine
compliance using CEMS and the effluent from the EGU discharges to the
atmosphere through multiple stacks (or, if the effluent is fed to a
stack through multiple ducts and is monitored in the ducts), then
monitoring the hourly CO2 mass emission rate and the ``stack
operating time'' at each stack or duct separately is required. In this
case, compliance with the applicable emission limit is 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 rule requires 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 have the option to use back up monitoring systems, as
provided in 40 CFR 75.10(e) and 75.20(d), to help meet this data
capture requirement. This requirement is separate from the requirement
for a source to demonstrate compliance with an applicable emission
standard. When demonstrating compliance with an emission standard the
calculation must use all valid data to calculate a compliance average
even if the percent of valid hours recorded in the period is less than
the 95 percent requirement.
C. Emissions Performance Testing Requirements
Similarly to the comments received on monitoring for the proposal,
commenters in general supported the use of current testing requirements
required under the Acid Rain Program 40 CFR part 75 requirements. Thus
the EPA is finalizing requirements for performance testing as
consistent with part 75 requirements where appropriate to ensure the
quality and accuracy of data and measurements as required by the final
rule.
In accordance with 40 CFR 75.64(a), the final rule requires an EGU
owner or operator to begin reporting emissions data when monitoring
system certification is completed or when the 180-day window in 40 CFR
75.4(b) allotted for initial certification of the monitoring systems
expires (whichever date is earlier). For EGUs subject to the
[[Page 64625]]
1,400 lb CO2/MWh-g) emission standard, the initial
performance test consists 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 begins 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 40 CFR 60.8 are not required for this rule. Following the
initial compliance determination, the emission standard is met on a 12-
operating-month rolling average basis.
D. Continuous Compliance Requirements
Commenters supported the use of a 12-operating-month rolling
average for the compliance period for the final standards. In response,
this final rule specifies that compliance with the 1,400 lb
CO2/MWh-g emission limit is 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 is used together with the
gross output over that period of time to calculate the average
CO2 mass emissions rate.
The rule specifies that the first operating month included in the
initial 12-operating-month compliance period is the month in which
reporting of emissions data is required to begin under 40 CFR 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).
Initial compliance with the applicable emissions limit in kg/MWh is
calculated by dividing the sum of the hourly CO2 mass
emissions values by the total gross output for the 12-operating-month
period. Affected EGUs continue to be subject to the standards and
maintenance requirements in the CAA section 111 regulatory general
provisions contained in 40 CFR part 60, subpart A.
Several commenters stated that the final rule should require
operators to round their calculated emissions rates to three
significant figures when comparing their actual rates to the standard.
These commenters said that allowing use of only two significant digits
when calculating the 12-operating-month rolling average emission rate
would constitute relaxation of the standard by 5 percent because an
actual emission rate of 1,049.9 lb CO2/MWh rounds to 1,000
lb of CO2 per MWh when only two significant figures are
required in the final step of compliance calculations. Commenters also
suggested that the emission limits be written in scientific notation
(e.g., 1.10 x 10-3 lb CO2/MWh) to clarify the number of
significant digits that should be used when evaluating compliance.
Other commenters suggested that the final step in compliance
calculations should reflect rounding the emission rate to the nearest
whole number using the ASTM rounding convention (ASTM E29).
The General Provisions of Part 60 specify the rounding conventions
for compliance calculations at 40 CFR 60.13(h)(3) including the
provision that ``after conversion into units of the standard, the data
may be rounded to the same number of significant digits used in the
applicable subpart to specify the emission limit.''
The final rule requires that the 12-operating-month rolling average
emission rate must be rounded to three significant figures if the
applicable emissions standard is greater than or equal to 1,000 (e.g.,
an actual emission rate of 1,004.9 lb CO2/MWh is rounded to
1,000 lb CO2/MWh); for standards of 1000 or less, the final
rule requires rounding the actual emission rate to two significant
figures (e.g., an actual emission rate of 454.9 kg CO2/MWh
is rounded to 450 kg CO2/MWh). Historically, many of the
emissions limits under part 60 have been expressed to two significant
digits (e.g., the original SO2 emission standard for coal-
fired units under Subpart D was 1.2 lb SO2/MMBtu). The
rounding conventions under the General Provisions allow the reporting
of all emission rates in the range from 1.15 to 1.249 as 1.2 lb
SO2/MMBtu. During compliance periods with emissions at the
lower end of this range, the operator is required to report higher
emissions than actually occurred; during compliance periods at the
upper end of this range the operator is allowed to report lower
emissions than actually occurred. In either case the absolute error
remains small because the emission rate in this example is a relatively
small numerical value. In addition, the required emission reductions
typically are large enough that rounding does not impact the emission
control strategy of affected units. However, the final standards for
CO2 emissions include numerical values that are larger than
many historical emissions standards and require a relatively small
percent reduction in emissions. Accordingly, it is appropriate to
require the use of three significant digits when completing compliance
calculations resulting in numerical values larger than 1,000. This is
particularly important when considering the relatively small emission
rate changes that may be required for compliance with the unit-specific
emission standards being finalized for modified steam generating and
IGCC units because a rounding error of 5 percent may be larger than the
percent difference between the affected unit's historically best
emission rate and the emission rate immediately preceding the
modification.
The final rule requires rounding of emission rates with numerical
values greater than or equal to 1,000 to three significant figures and
rounding of rates with numerical values less than 1,000 to two
significant figures.
E. Notification, Recordkeeping, and Reporting Requirements
Commenters supported the coordination of notification,
recordkeeping, and reporting required under this rule in conjunction
with the requirements already in place under part 75, so the EPA has
made the requirements as efficient and streamlined as possible with the
current requirements under part 75. The final rule requires an EGU
owner or operator to comply with the applicable notification
requirements in 40 CFR 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 40 CFR
60.19. The rule also requires the applicable recordkeeping requirements
in subpart F of part 75 to be met. For EGUs using CEMS, the data
elements that are 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 are recorded include
hourly fuel flow rates, fuel usage times, fuel GCV, gross electric
generation.
The rule requires EGU owners or operators to keep records of the
calculations they perform to determine the total CO2 mass
emissions and gross output for each operating month. Records 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 are required to be kept. The
rule also requires sources to keep records of calculations performed to
determine site-specific carbon-based F-factors for
[[Page 64626]]
use in Equation G-4 of part 75, appendix G (if applicable).
Sources are required to keep all records for a period of 3 years.
All required records must be kept on-site for a minimum of two years,
after which the records can be maintained off-site.
The rule requires all affected EGU owners/operators to submit
quarterly electronic emissions reports in accordance with subpart G of
part 75. The reports in appendix G that do not include data required to
calculate compliance with the applicable CO2 emission
standard are not required to be reported under this rule. The rule
requires the reports in 40 CFR 60.5555 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 this rule.
Additionally, in the final rule and as part of an agency-wide
effort to streamline and facilitate the reporting of environmental
data, the rule requires selected data elements that pertain to
compliance under this rule, and that serve the purpose of identifying
violations of an emission standard, to be reported periodically using
ECMPS.
Specifically, EGU owners/operators must submit quarterly electronic
reports within 30 days after the end of each quarter consistent with
current part 75 reporting requirements. The first report is 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 12th operating month of a compliance
period (or periods) occurs during the calendar quarter, the average
CO2 mass emissions rate (kg/MWh) is 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 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
violations that occur during the quarter are identified. If there are
no compliance periods that end in the quarter, a definitive statement
to that effect must be included in the report. If one or more
compliance periods end in the quarter but there are no violations, a
statement to that effect must be included in the report.
Currently, ECMPS is not programmed to receive the additional
information included in the report required under 40 CFR 60.5555(a)(2)
for affected EGUs. However, we will make the necessary modifications to
the system in order to fully implement the reporting requirements of
this rule upon promulgation.
XI. Consistency Between BSER Determinations for This Rule and the Rule
for Existing EGUs
In the CAA section 111(d) rule for existing steam units and
combustion turbines that the EPA is promulgating at the same time as
this CAA section 111(b) rule, the EPA is identifying as part of the
BSER for those sources, building block 1 (for steam units, efficient
operation), building block 2 (for steam units, dispatch shift to
existing NGCC units), and building block 3 (for steam units and
combustion turbines, substitution of generation with new renewable
energy). In this section, we explain why the EPA is not identifying
building blocks 1, 2, or 3 as part of the BSER for new, modified, or
reconstructed steam generators or combustion turbines.
A. Newly Constructed Steam Generating Units
1. Preference for Technological Controls as the BSER for New EGUs
As discussed in this preamble and in more detail in the preamble to
the CAA section 111(d) rule for existing sources, the phrase ``system
of emission reduction'' is undefined and provides the EPA with
discretion in setting a standard of performance under CAA section
111(b) or emission guidelines under CAA section 111(d). Because the
phrase by its plain language does not limit our review of potential
systems in either context, the same systems could be considered for
application in new and existing sources. That said, many other factors
and considerations direct us to focus on different systems when
establishing a standard of performance under CAA section 111(b) and an
emission guideline under CAA section 111(d). Thus, it is useful to
describe part of the underlying basis for the BSER--partial CCS--that
the EPA has determined for new steam units before discussing the
building blocks that form the BSER for existing units.
For new steam generating units, the EPA is identifying, as the
BSER, systems of emission reduction that assure that these sources are
inherently low-emitting at the time of construction. The following
reasons support this approach to the BSER.
New sources are expected to have long operating lives over which
initial capital costs can be amortized. Thus, new construction is the
preferred time to drive capital investment in emission controls. In
this case, the BSER for new steam generators, partial CCS, requires
substantial capital expenditures, which new sources are best able to
accommodate.
While CAA section 111(b)(1)(B) and (a)(1) by their terms do not
mandate that the BSER assure that new sources are inherently low
emitting, that approach to the BSER is consistent with the legislative
history.\544\ See Section III.H.3.b.4 above. For instance, the 1970
Senate Committee Report explains that ``[t]he overriding purpose of
this section [concerning new source performance standards] 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.'' \545\ Existing sources, on the other hand,
would be regulated through emission standards, which were broadly
understood at the time to reflect available technology, alternative
methods of prevention and control, alternative fuels, processes, and
operating methods.\546\ \547\
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\544\ Although Congress expressed a clear preference that new
sources would be ``designed, built, equipped, operated, and
maintained so as to reduce emissions to a minimum,'' the Senate
Committee Report also makes clear that the term standard of
performance ``refers to the degree of emission control which can be
achieved through process changes, operation changes, direct emission
control, or other methods.'' Sen. Rep. No. 91-1196 at 15-17, 1970
CAA Legis. Hist. at 415-17 (emphasis added).
\545\ Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hist. at
416 (emphasis added).
\546\ See 1970 CAA Amendments, Pub. L. 91-604, section 4, 84
Stat. 1676, 1679 (Dec. 31, 1970) (describing information that the
EPA must issue to the states and appropriate air pollution control
agencies along with the issuance of ambient air quality criteria
under Section 4 of the 1970 CAA titled ``Ambient Air Quality and
Emission Standards'').
\547\ In the 1977 CAA Amendments, Congress revised section
111(a)(1) to mandate that the EPA base standards for new sources on
technological controls, but, at the same time, made clear that the
EPA was not required to base the emission guidelines for existing
sources on technological controls. In the 1990 CAA Amendments,
Congress repealed the section 111(a)(1) requirements that
distinguished between new and existing sources and largely restored
the 1970 CAA Amendments version of section 111(a)(1).
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[[Page 64627]]
2. Practical Implications of Including the Building Blocks
Several practical considerations make the building blocks
inappropriate for new sources. Thus, for the following reasons, the EPA
does not consider it appropriate to include the building blocks as part
of the BSER for new sources:
a. Additional Cost
Partial CCS will impose substantial (albeit reasonable) costs on
new steam-generating EGUs, and, as a result, the EPA does not believe
that including additional measures as part of the BSER would be
appropriate. One disadvantage in adding additional costs is that doing
so would make it more difficult for new steam-generating EGUs to
compete with new nuclear units. Because the BSER is selected after
considering cost (among other factors), the EPA is not required
to,\548\ and in this case believes it would not be appropriate to,
select the most stringent adequately demonstrated system of emission
reduction (through the combination of partial CCS and the building
blocks) for purposes of setting a standard of performance under CAA
section 111(b).
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\548\ For example, as early as a 1979 NSPS rulemaking for
affected EGUs, the EPA recognized that it was not required to
establish as the BSER the most stringent adequately demonstrated
system of emission reduction available, and instead could weigh the
amount of additional emission reductions against the costs. See 44
FR 52792, 52798 (Sept. 10, 1979) (``Although there may be emission
control technology available that can reduce emissions below those
levels required to comply with standards of performance, this
technology might not be selected as the basis of standards of
performance due to costs associated with its use. Accordingly,
standards of performance should not be viewed as the ultimate in
achievable emission control. In fact, the Act requires (or has
potential for requiring) the imposition of a more stringent emission
standard in several situations.'').
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Building block 1 measures are not appropriate (or would be
redundant) because the BSER for new steam generating units is based on
highly efficient supercritical technology, i.e., state-of-the-art,
efficient equipment. See Section V.K above. Accordingly, there is
little improvement in efficiency that can be justified as part of the
BSER.
Building block 2 and 3 measures are not appropriate for the BSER
because new steam units would have a significantly limited range of
options to implement building blocks 2 and 3. The new source
performance standard was proposed and is being finalized as a rate-
based standard. Thus, if building blocks 2 and 3 were included in the
BSER, a more stringent rate-based standard would be applicable to all
new sources. However, it is conceivable that the EPA could propose a
hybrid standard that would include both an emission-rate limit that
reflects partial CCS and a requirement for allowances that reflects
building blocks 2 and 3. Accordingly, the following discussion assumes
either a rate-based or mass-based standard, or part of a hybrid
standard.
In both a rate-based program and a mass-based program, building
blocks 2 and 3 measures can be implemented through a range of methods,
including trading with other EGUs. While it is not necessarily the case
that every existing source will be able to implement each of the
methods, in general, existing sources will have a range of measures to
choose from. However, at least some of those methods may not be
available to new sources, which would render compliance with their
emission limits more challenging and potentially more costly.
One example is emission trading with other affected EGUs. For
existing sources, emission trading is an important option for
implementing the building blocks. There are large numbers of existing
sources, and they will become subject to the section 111(d) standards
of performance at the same time. It may be more cost-effective for some
to implement the building blocks than others, and, as a result, some
may over-comply and some may under-comply, and the two groups may trade
with each other. Because of the large numbers of existing sources, the
trading market can be expected to be robust. Trading optimizes
efficiency. As a result, existing sources have more flexibility in the
overall amount of their investment in building blocks 2 and 3 and can
adjust investment obligations among themselves through emissions
trading.
In contrast, new sources construct one at a time, and it is unknown
how many new sources there will be. Without a sizeable number of new
sources, there will not be a robust trading market. Thus, a new source
cannot count on being able to find a new source trading partner. In
addition, it is not possible to count on new sources being able to
trade with existing sources, for several reasons. First, as noted,
there are indications in the legislative history that new sources
should be well-controlled at the source, which casts doubt on whether
new sources should be allowed to meet their standards through the
purchase of emission credits. Second, new sources must meet their
standards of performance as soon as they begin operations. If they do
so before the year 2022, when existing sources become subject to
section 111(d) state plan standards of performance, no existing sources
will be available as trading partners.
In addition, for section 111(d) sources, we are granting a 7-year
period of lead-time for the implementation of the building blocks. This
is due, in part, to the benefits of allowing the ERC and allowance
markets to develop. However, the new source standards take effect
immediately, so new sources would not have the advantage of this lead
time were they subject to more stringent standards that also reflected
the building blocks.\549\
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\549\ At least in theory, we could consider promulgating a
standard of performance for new affected EGUs that becomes more
stringent beginning in 7 years, based on a more stringent BSER. We
are not inclined to adopt that approach because section 111(b)(1)(B)
requires that we review and, if necessary, revise the section 111(b)
standards of performance no later than every 8 years anyway.
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In addition, if there are an unexpectedly large number of new
sources, then they would be obliged to invest in greater amounts of
building blocks 2 and 3, and that could reduce the amounts of building
blocks 2 and 3 available for existing sources, and thereby raise the
costs of building blocks 2 and 3 for existing sources. This could
compromise the BSER under section 111(d) and undermine the ability of
existing sources to comply with their section 111(d) obligations.\550\
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\550\ The EPA is authorized to consider the BSER for new and
existing sources in conjunction with each other. In the 1977 CAA
Amendments, Congress revised section 111(a)(1) to require
technological controls for new combustion sources at least in part
because this requirement would preclude new sources from relying on
low-sulfur coal to achieve their emission limits, which, in turn,
would free up low-sulfur coal for existing sources.
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B. New Combustion Turbines
For new combustion turbines, the building blocks are not
appropriate as part of the BSER either. Building block 1 is limited to
steam generating units, and therefore has no applicability to new
combustion turbines. Measures comparable to those in building block 1
would not be appropriate because new highly efficient NGCC construction
already entails high efficiency equipment and operation. Building block
2 is also limited to steam generating units and is not appropriate as
part of the BSER for new NGCC units because it would not result in any
emission reductions.
The reasons why building block 3 are not appropriate are the same
as discussed above for why building blocks 2 and 3 are not appropriate
for new steam generating units (limited range of options for
implementation (including lack of availability of trading), lack of
[[Page 64628]]
lead-time for implementation, and the possibility of reducing the
availability of renewable energy for existing sources).
C. Modified and Reconstructed Steam and NGCC Units
For modified and reconstructed steam generators, the EPA identified
the BSER as maintenance of high efficiency or implementation of a
highly efficient unit. The resulting emission limit must be met over
the specified time period and cannot be deviated from or averaged. As a
result, a modified or reconstructed steam generator generally will
require ongoing maintenance and may find it prudent to operate below
its limit as a safety margin. This represents a substantial commitment
of resources. For these units, the additional costs of implementing the
building blocks would not be appropriate.
In addition, building block 1 is not appropriate for modified or
reconstructed steam generating units because the BSER for these units
is already based on highly efficient performance. For the same reasons,
it does not make sense to attempt to develop the analogue to building
block 1 for reconstructed NGCC units--the BSER for them, too, is
already based on highly efficient performance.
Building block 2 is not appropriate for reconstructed NGCC units
because it would not yield any reductions.
Building blocks 2 and 3 are not appropriate for modified or
reconstructed steam generators, and building block 3 is not appropriate
for reconstructed NGCC units, for the same reasons that they are not
appropriate for new EGUs, as described above (limited range of options
for implementation (including lack of availability of trading), lack of
lead-time for implementation, and the possibility of reducing the
availability of renewable energy for existing sources).
XII. Interactions With Other EPA Programs and Rules
A. Overview
This final rule will, for the first time, regulate GHGs under CAA
section 111. In Section IX of the preamble to the proposed rule, the
EPA addressed how regulation of GHGs under CAA section 111 could have
implications for other EPA rules and for permits written under the CAA
Prevention of Significant Deterioration (PSD) preconstruction permit
program and the CAA Title V operating permit program. The EPA proposed
to adopt provisions in the regulations that explicitly addressed some
of these implications.
For purpose of the PSD program, the EPA is finalizing provisions in
part 60 of its regulations that make clear that the threshold for
determining whether a PSD source must satisfy the BACT requirement for
GHGs continues to apply after promulgation of this rule. This rule does
not require any additional revisions to State Implementation Plans. As
discussed further below, this final rule may have bearing on the
determination of BACT for new, modified, and reconstructed EGUs that
require PSD permits. With respect to the Title V operating permits
program, this rule does not affect whether sources are subject to the
requirement to obtain a Title V operating permit based solely on
emitting or having the potential to emit GHGs above major source
thresholds. However, this rule does have some implications for Title V
fees, which the EPA is addressing in this final rule.
Finally, the fossil fuel-fired EGUs covered in this rule are or
will be potentially impacted by several other recently finalized or
proposed EPA rules, and such potential interactions with other EPA
rules are discussed below.
B. Applicability of Tailoring Rule Thresholds Under the PSD Program
In our January 8, 2014 proposal, the EPA proposed to adopt
regulatory language in 40 CFR part 60 that would ensure the
promulgation of this NSPS would not undercut the application of rules
that limit the application of the PSD permitting program requirements
to only the largest sources of GHGs. An intervening decision of the
United States Supreme Court has, to a large extent, resolved the legal
issue that led the EPA to propose these part 60 provisions. The Supreme
Court has since clarified that the PSD program does not apply to
smaller sources based on the amount of GHGs they emit. However, because
the largest sources emitting GHGs remain subject to the PSD permitting
requirements, the EPA has concluded that it remains appropriate to
adopt the proposed regulatory provisions in 40 CFR part 60 in this
rule. We discuss our reasons for this action in detail below.
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 specific requirements, including application of BACT to each
pollutant subject to regulation under the CAA. Many states (and local
districts) are authorized by the EPA to administer the PSD program and
to issue PSD permits. If a state is not authorized, then the EPA issues
the PSD permits for facilities in that state.
To identify the pollutants subject to the PSD permitting program,
EPA regulations contain a definition of the term ``regulated NSR
pollutant.'' 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition
contains four subparts, which cover pollutants regulated under various
parts of the CAA. The second subpart covers pollutants regulated under
section 111 of the CAA. The fourth subpart is a catch-all provision
that applies to ``[a]ny pollutant that is otherwise subjection to
regulation under the Act.''
This definition and the associated PSD permitting requirements
applied to GHGs for the first time on January 2, 2011, by virtue of the
EPA's regulation of GHG emissions from motor vehicles, which first took
effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs
became subject to regulation under the CAA and the fourth subpart of
the ``regulated NSR pollutant'' definition became applicable to GHGs.
On June 3, 2010, the EPA issued a final rule, known as the
Tailoring Rule, which phased in permitting requirements for GHG
emissions from stationary sources under the CAA PSD and Title V
permitting programs (75 FR 31514). Under its understanding of the CAA
at the time, the EPA believed the Tailoring Rule was necessary to avoid
a sudden and unmanageable increase in the number of sources that would
be required to obtain PSD and Title V permits under the CAA because the
sources emitted GHGs emissions over applicable major source and major
modification thresholds. In Step 1 of the Tailoring Rule, which began
on January 2, 2011, the EPA limited application of PSD or Title V
requirements to sources of GHG emissions only if the sources were
subject to PSD or Title V ``anyway'' due to their emissions of non-GHG
pollutants. These sources are referred to as ``anyway sources.'' In
Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA
applied the PSD and Title V permitting requirements under the CAA to
sources that were classified as major, and, thus, required to obtain a
permit, based solely on their potential GHG emissions and to
modifications of otherwise major sources that required a PSD permit
because they increased only GHG emissions above applicable levels in
the EPA regulations.
In the PSD program, the EPA implemented the steps of the Tailoring
Rule by adopting a definition of the
[[Page 64629]]
term ``subject to regulation.'' The limitations in Step 1 of the
Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR
51.166(b)(48)(iv). With respect to ``anyway sources'' covered by PSD
during Step 1, this provision established that GHGs would not be
subject to PSD requirements unless the source emitted GHGs in the
amount of 75,000 tons per year (tpy) of carbon dioxide equivalent
(CO2e) or more. The primary practical effect of this
paragraph is that the PSD BACT requirement does not apply to GHG
emissions from an ``anyway source'' unless the source emits GHGs at or
above this threshold. The Tailoring Rule Step 2 limitations are
reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These
provisions contain thresholds that, when applied through the definition
of ``regulated NSR pollutant,'' function to limit the scope of the
terms ``major stationary source'' and ``major modification'' that
determine whether a source is required to obtain a PSD permit. See e.g.
40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR
51.166(b)(2).
This structure of the EPA's PSD regulations created questions
regarding the extent to which the limitations in the Tailoring Rule
would continue to apply to GHGs once they became regulated, through
this final rule, under section 111 of the CAA. 79 FR 1487-1488. As
discussed above, the definition of ``regulated NSR pollutant'' in the
PSD regulations contains a separate PSD trigger for air pollutants
regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the ``NSPS trigger
provision''). Thus, when GHGs become subject to a standard promulgated
under CAA section 111 for the first time under this rule, PSD
requirements would presumably apply for GHGs on an additional basis
besides through the regulation of GHGs from motor vehicles. However,
the Tailoring Rule, on the face of its regulatory provisions,
incorporated the revised thresholds it promulgated into only the fourth
subpart of the PSD definition of regulated NSR pollutant (``[a]ny
pollutant that otherwise is subject to regulation under the Act''). The
regulatory text does not clearly incorporate the thresholds into the
NSPS trigger provision in the second subpart (``[a]ny pollutant that is
subject to any standard promulgated under section 111 of the Act'').
For this reason, a question arose as to whether the Tailoring Rule
limitations would continue to apply to the PSD requirements after they
are independently triggered for GHGs by the NSPS that the EPA is now
promulgating. Stakeholders questioned 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 potentially subject to PSD under the CAA based on
GHG emissions.
In the January 8, 2014 proposed rule, the EPA explained that the
agency had included an interpretation in the Tailoring Rule preamble,
which means that the Tailoring Rule thresholds continue to apply if and
when the EPA promulgates requirements under CAA section 111. 79 FR 1488
(citing 75 FR 31582). Nevertheless, to ensure there would be no
uncertainty as to this issue, the EPA proposed to adopt explicit
language in 40 CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of
the agency's regulations. The proposed language makes clear that the
thresholds for GHGs in the EPA's PSD definition of ``subject to
regulation'' apply through the second subpart of the definition of
``regulated NSR pollutant'' to GHGs regulated under this rule.
The EPA received comments supporting the adoption of this proposed
language, but several commenters also expressed concern that adding
this language to part 60 alone would not be sufficient. Several
commenters urged the EPA to instead revise the PSD regulations in parts
51 and 52. In addition, commenters expressed concern that further steps
were needed to amend the SIPs before there would be certainty that the
Tailoring Rule limitations continued to apply after the adoption of
CO2 standards under CAA section 111 in this final rule.
On June 23, 2014, the United States Supreme Court, in Utility Air
Regulatory Group v. Environmental Protection Agency, issued a decision
addressing the application of PSD permitting requirements to GHG
emissions. The Supreme Court held that the EPA may not treat GHGs as an
air pollutant for purposes of determining whether a source is a major
source (or modification thereof) for the purpose of PSD applicability.
The Court also said that the EPA could continue to require that PSD
permits, otherwise required based on emissions of pollutants other than
GHGs, contain limitations on GHG emissions based on the application of
BACT. The Supreme Court decision effectively upheld PSD permitting
requirements for GHG emissions under Step 1 of the Tailoring Rule for
``anyway sources'' and invalidated application of PSD permitting
requirements to Step 2 sources based on GHG emissions. The Court also
recognized that, although the EPA had not yet done so, it could
``establish an appropriate de minimis threshold below which BACT is not
required for a source's greenhouse gas emissions.'' 134 S. Ct. at 2449.
In accordance with the Supreme Court decision, on April 10, 2015,
the U.S. Court of Appeals for the District of Columbia Circuit (the
D.C. Circuit) issued an amended judgment vacating the regulations that
implemented Step 2 of the Tailoring Rule, but not the regulations that
implement Step 1 of the Tailoring Rule. The court specifically vacated
40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's
regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR
52.21(b)(48)(iv). The court also directed the EPA to consider whether
any further revisions to its regulations are appropriate in light of
UARG v. EPA, and, if so, to undertake such revisions.
The practical effect of the Supreme Court's clarification of the
reach of the CAA is that it eliminates the need for Step 2 of the
Tailoring Rule and subsequent steps of the GHG permitting phase in that
the EPA had planned to consider under the Tailoring Rule. This also
eliminates the possibility that the promulgation of GHG standards under
section 111 could result in additional sources becoming subject to PSD
based solely on GHGs, notwithstanding the limitations the EPA adopted
in the Tailoring Rule. However, for an interim period, the EPA and the
states will need to continue applying parts of the PSD definition of
``subject to regulation'' to ensure that sources obtain PSD permits
meeting the requirements of the CAA.
The CAA continues to require that PSD permits issued to ``anyway
sources'' satisfy the BACT requirement for GHGs. Based on the language
that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR
52.21(b)(49)(iv), the EPA and states may continue to limit the
application of BACT to GHG emissions in those circumstances where a
source emits GHGs in the amount of at least 75,000 tpy on a
CO2e basis. The EPA's intention is for this to serve as an
interim approach while the EPA moves forward to propose a GHG
Significant Emission Rate (SER) that would establish a de minimis
threshold level for permitting GHG emissions under PSD. Under this
forthcoming rule, the EPA intends to propose restructuring the GHG
provisions in its PSD regulations so that the de minimis threshold for
GHGs will not reside within the definition of ``subject to
regulation.'' This restructuring will be designed to make the PSD
regulatory provisions on GHGs universally
[[Page 64630]]
applicable, without regard to the particular subparts of the definition
of ``regulated NSR pollutant'' that may cover GHGs. Upon promulgation
of this PSD rule, it will then provide a framework that states may use
when updating their SIPs consistent with the Supreme Court decision.
While the PSD rulemaking described above is pending, the EPA and
approved state, local, and tribal permitting authorities will still
need to implement the BACT requirement for GHGs. In order to enable
permitting authorities to continue applying the 75,000 tpy
CO2e threshold to determine whether BACT applies to GHG
emissions from an ``anyway source'' after GHGs are subject to
regulation under CAA section 111, the EPA has concluded that it
continues to be appropriate to adopt the proposed language in 40 CFR
60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed
regulations in subparts Da and KKKK, it is not necessary to adopt the
comparable provisions that the EPA proposed in 40 CFR 60.46Da(j) and 40
CFR 60.4315(b).
The EPA has evaluated 40 CFR 60.5515 in light of the Supreme Court
decision and the comments received on the question of whether this CAA
section 111 standard will undermine the application of the Tailoring
Rule limitations. While most of the Tailoring Rule limitations are no
longer needed to avoid triggering the requirement to obtain a PSD
permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv)
and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim
applicability level for the GHG BACT requirement in ``anyway source''
PSD permits. Thus, there continues to be a need to ensure that the
regulation of GHGs under CAA section 111 does not make this BACT
applicability level for anyway sources effectively inoperable. The
language in 40 CFR 60.5515 will continue to be effective at avoiding
this result after the judicial actions described above and the adoption
of this final rule. The provisions in part 60 reference 40 CFR
51.166(b)(48) and 40 CFR 52.21(b)(49) of the EPA's regulations.
However, the courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR
52.21(b)(49)(v), and the EPA will take steps soon to eliminate these
subparts from the CFR. As a result of these steps, the language of
final 40 CFR 60.5515 will not incorporate the vacated parts of 40 CFR
51.166(b)(48) and 40 CFR 52.21(b)(49), but these provisions in part 60
will continue to apply to those subparts of the PSD rules that are
needed on an interim basis to limit application of BACT to GHGs only
when emitted by an anyway source in amounts of 75,000 tpy
CO2e or more. Thus, in this final rule, the EPA is adopting
the proposed text of 40 CFR 60.5515 for this purpose without
substantial change.
As to the concern expressed by some commenters that revisions to
part 60 alone are not sufficient, the GHG SER rulemaking described
above will include proposed revisions to the PSD regulations in parts
51 and 52 that should ultimately address this concern. The EPA
acknowledges that the commenters concern will not be fully addressed
for an interim period of time, but (for the reasons discussed above)
the part 60 provisions adopted in this rule are sufficient to make
explicit that the 75,000 tpy CO2e BACT applicability level
for GHGs will apply to GHGs that are subject to regulation under the
CAA section 111 standards adopted in this rule.
Rather than adopting a temporary patch in its PSD regulations in
this rule to address the implications for PSD of regulating GHGs under
CAA section 111, the EPA believes it will be most efficient for the EPA
and the states if the EPA completes a comprehensive PSD rule that will
address all the implications of the Supreme Court decision. The
revisions the EPA will consider based on the Supreme Court decision
will inherently address the commenters concerns about the definition of
the ``subject to regulation'' and the proposed part 60 provisions. To
the extent this PSD rule is not complete before the EPA proposes
additional CAA section 111 standards for GHGs, the EPA will need to
consider adding provisions like 40 CFR 60.5515 to other subparts of
part 60. In a separate rulemaking finalized concurrently with this
rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705
in subpart UUUU to clarify that the regulated pollutant is the same for
both the CAA section 111(b) and section 111(d) rules. As of this time,
the EPA has not proposed GHG standards for other source categories
under CAA section 111. To the extent needed, this approach of adding
provisions to a few subparts in part 60 would be less burdensome to
states and more efficient than revising 40 CFR 51.166 at this time
solely to address the implications of regulating GHGs under CAA section
111.
The EPA understands that many commenters expressed concern that PSD
SIPs would also have to be amended to address the implications of
regulating GHGs under CAA section 111. However, the language in 40 CFR
60.5515 is designed to avoid the need for states to make revisions to
the PSD regulations in their SIPs at this time. The EPA has previously
observed that the form of each pollutant regulated under the PSD
program is derived from the form of the pollutant described in
regulations, such as an NSPS, that make the pollutant regulated under
the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar.
12, 1996); 75 FR 31522.
Moreover, it is more likely that states would need to consider a
SIP revision if the EPA were to revise 40 CFR 51.166 in this rule.
Revisions to 51.166 can trigger requirements for states to revise their
PSD program provisions under 40 CFR 51.166(a)(6).
Given the process required in states to review their SIPs and
submit them to the EPA for approval, it is most efficient for all
concerned when the EPA is able to consolidate its revisions to 40 CFR
51.166. The EPA, thus, believes it will be less work for states if we
issue a comprehensive set of rules addressing regulation of GHGs under
the PSD program after the Supreme Court decision.
In comments on the proposed rules, states generally did not express
concern that the proposed revisions to part 60 were insufficient to
avoid the need for SIP revisions. In our proposal, we addressed any
state with an approved PSD SIP program that applies to GHGs which
believed that this final rule would require the state to revise its SIP
so that the Tailoring Rule thresholds continue to apply. First, the EPA
encouraged any state that considered such revisions necessary to make
them as soon as possible. Second, if the state could do so promptly,
the EPA said it would 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 NSPS rule. 79
FR 1487. The EPA did not receive any comments or other feedback from
states requesting that the EPA narrow their program to ensure the
Tailoring Rule thresholds continue to apply after promulgating this
rule. We do not believe such action will be necessary in any state
after the Supreme Court decision and our action in this rule is to
adopt the proposed part 60 provisions for purposes of ensuring the Step
1 BACT applicability level for GHGs continues to apply on an interim
basis.
C. Implications for BACT Determinations Under PSD
New major stationary sources and major modifications at existing
major stationary sources are required by the
[[Page 64631]]
CAA to, among other things, obtain a permit under the PSD program
before commencing construction. The emission thresholds that define PSD
applicability can be found in 40 CFR parts 51 and 52, and the PSD
thresholds specific to GHGs are explained in the preceding section of
this preamble.
Sources that are subject to PSD must obtain a preconstruction
permit that contains emission limitations based on application of BACT
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. CAA section 169(3) defines BACT, in general, as:
``an emissions limitation . . . based on the maximum degree of
reduction for each pollutant . . . emitted from any proposed major
stationary source or major modification which the Administrator . .
. [considering energy, environmental, and economic impacts] . . .
determines is achievable for such facility . . .''
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 condition of CAA section 169(3) has historically been interpreted
to mean that BACT cannot be less stringent than any applicable standard
of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V
Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001 (March 2011)
(``GHG Permitting Guidance'' or ``Guidance'') at 20-21. Thus, upon
completion of an NSPS, the NSPS establishes a ``BACT Floor'' for PSD
permits that are issued to affected facilities covered by the NSPS.
BACT is a case-by-case review that considers a number of factors.
These factors include the availability, technical feasibility, control
effectiveness, and the economic, environmental and energy impacts of
the control option. See GHG Permitting Guidance at 17-46. The fact that
a minimum control requirement (i.e., the BACT Floor) is established by
the EPA through an applicable NSPS does not bar a permitting agency
from justifying a more stringent control level as BACT for a specific
PSD permit.
It is important to understand how this NSPS may relate to
determining BACT for new and existing EGUs that require PSD permits.
PSD generally applies to major sources, while this NSPS applies to
units that may be within a source. Under this NSPS, an affected
facility is a new EGU or a modified or reconstructed EGU. The new
source NSPS requirements apply, in general, to any stationary source
that adds a new EGU that is an affected facility under this NSPS. This
could, for example, include a proposed brand new (``greenfield'') power
plant or an existing power plant that proposes to add a new EGU (e.g.,
to increase its generating capacity). While this latter scenario is
considered a ``new affected facility'' under the NSPS, it is generally
viewed under PSD as a ``modification'' of an existing stationary
source. Thus, the new source NSPS requirements could apply to a
modification, as that term is defined under PSD.
In addition, this NSPS will apply to some modified and
reconstructed units, as those terms are defined under part 60.
Consequently, this NSPS could establish a BACT floor for existing
stationary sources that are modifying an existing EGU and experience an
emissions increase that makes the source subject to PSD review.
However, a physical change that triggers the NSPS modification or
reconstruction requirements does not necessarily subject the source to
PSD requirements, and vice versa. In general, in order to trigger the
NSPS modification or reconstruction requirements, a physical change
must increase the maximum hourly emission rate of the pollutant (to be
an NSPS modification) or the fixed capital cost of the change must
exceed 50 percent of the fixed capital cost of a comparable entirely
new facility (to be an NSPS reconstruction). See 40 CFR 60.2, 60.14,
60.15. Under the PSD program, however, a physical change (or change in
the method of operation) must result in an increase in annual emissions
of the pollutant by a specified emission threshold in order to be
subject to PSD requirements. This emission calculation considers the
unit's past annual emissions and its projected annual emissions. See,
e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions test
for a modification allows the existing source to consider qualifying
emission reductions and increases at the source within a
contemporaneous period to ``net out'' of, or avoid, triggering PSD
review. Thus, it is important to understand the differences in how the
term ``modification'' is used in the NSPS and PSD programs, and that a
physical change that is a modification under one program may not
necessarily be a modification under the other program.
In the preamble to the proposed NSPS for new sources, the EPA
discussed whether a standard of performance for the new source NSPS,
specifically the BSER for solid fuel-fired EGUs that is based on
partial CCS, could become the BACT floor when permitting a modified or
reconstructed EGU or non-EGU source. As noted above, BACT is a case-
specific review by a permitting agency. In evaluating BACT, the
permitting authority should consider all available control technologies
that have the potential for practical application to the facility or
emission unit under evaluation. See GHG Permitting Guidance at 24. This
BACT review must include any technologies that are part of an
applicable NSPS for the specific type of source and would therefore
establish the minimum level of stringency for the BACT. Thus, it is
possible that partial CCS could be considered in a BACT review as an
available control option for a modified or reconstructed EGU facility,
or for another type of source (e.g., natural gas processing plant), but
this NSPS is not an applicable standard to such sources so it would not
establish a requirement that partial CCS is a minimum level of
stringency for the BACT for those sources.
Some commenters expressed concern that, if the EPA finalizes a BSER
for utility boilers and IGCC units that is based on partial CCS, it
would establish a BACT Floor for new EGUs that would be inconsistent
with prior BACT determinations for EGUs in both permits issued by EPA
Regions and permits issued by state agencies on which the EPA has
commented. Many of these comments were more directed at the development
and deployment of CCS (i.e., the commenter did not believe CCS should
be the basis for BSER) rather than examining whether an NSPS should
establish the BACT floor for applicable sources, which is the legal
consequence of setting an NSPS under the terms of the CAA.
Consequently, we respond to these comments in other sections of this
preamble that support the selection of partial CCS as the basis for the
BSER for fossil fuel-fired electric utility steam generating units.
With regard to the commenters who stated that a BSER for EGUs that
is based on partial CCS would be inconsistent with BACT determinations
in previous GHG PSD permits, it is important to recognize that a BACT
determination is a case-by-case analysis and that technological
capabilities and costs evolve over time.\551\ In addition, to
[[Page 64632]]
date the EPA has not issued a PSD permit with GHG BACT for a source
that would be an affected facility requiring partial CCS under this
NSPS (i.e., a fossil fuel-fired steam generating unit), so one cannot
determine whether the EPA--as a PSD permitting authority--has been
either consistent or inconsistent by setting a BSER of partial CCS in
this NSPS. Although, in the course of a BACT review, some permitting
authorities may have determined that CCS is not technologically
feasible or economically achievable for a gas-fired EGU, because of the
case-by-case nature of the BACT analysis it does not automatically
follow that the same conclusion is appropriate for a solid fuel-fired
EGU. Furthermore, PSD permitting requirements first applied to GHGs in
January 2011 and more information about GHG control technology has been
gained in this four-and-a-half year period. Thus, we would expect BACT
decisions to evolve as well, such that a GHG BACT review for a coal-
fired EGU in 2015 may look very different from a review that was done
in 2011.
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\551\ In this regard, the 2011 GHG Permitting Guidance states
that ``although CCS is not in widespread use at this time, EPA
generally considers CCS to be an `available' add-on pollution
control technology for facilities emitting CO2 in large
amounts and industrial facilities with high-purity CO2
streams.'' GHG Permitting Guidance at 35. The Guidance goes on to
note that CCS may not be technically feasible at modified sources
(citing possible issues with ``space for CO2 capture
equipment at an existing facility''), or in other specific
circumstances. Id. at 36 (``Logistical hurdles for CCS may include
obtaining contracts for offsite land acquisition . . ., the need for
funding . . ., timing of available transportation infrastructure,
and developing a site for secure long term storage. Not every source
has the resources to overcome the offsite logistical barriers
necessary to apply CCS technology to its operations, and smaller
sources will likely be more constrained in this regard''). Id. at
42-3 EPA also noted that CCS may be expensive in individual
instances and thus eliminated as a control option for that reason
under step 4 of the BACT analysis, noting further that revenues from
EOR may offset other costs. Id. at 42-3. See also UARG v. EPA, 134
S.Ct. 2427, 2448 (2014) (noting that EPA's GHG Permitting Guidance
states that carbon capture is reasonably comparable to more
traditional, end-of-stack BACT technologies, and that petitioners do
not dispute that).
As explained at Section V.I.5 above, in determining that partial
CCS is BSER for new fossil fuel steam electric plants, the EPA has
carefully considered the issue of logistics (including cost
estimates for land acquisition, transportation, and sequestration)
and costs generally. Nor would new plants face the same types of
constraints as modified or reconstructed sources in a BACT
determination, since a new source has more leeway in choosing where
to site. See text at V.G.3. above. Moreover, the GHG Permitting
Guidance considered BACT determinations for all types of sources,
not just those for which the EPA has determined in this rule that
partial CCS is the BSER, and the concerns expressed in the Guidance
thus must be considered in that broader context.
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Additionally, if a state agency is processing a permit application
for a solid fuel-fired EGU and does not propose CCS as BACT (or does
not even consider CCS as an available control for BACT), the EPA is not
necessarily required to comment negatively on the draft permit, or to
otherwise request or require that the state agency amend the BACT to
include CCS. For state agencies that have their own EPA-approved state
implementation plan, the state has primacy over their permitting
actions and discretion to interpret their approved rules and to apply
the applicable federal and state regulatory requirements that are in
place at the time for the facility in question. The EPA's role is to
provide oversight to ensure that the state operates their PSD program
in accordance with the CAA and applicable rules. If the EPA does not
adversely comment on a certain draft permit or BACT determination, it
does not necessarily imply EPA endorsement of the proposed permit or
determination.
Some commenters also felt that the determination of partial CCS as
BSER is inconsistent with the agency's position on CCS in the EPA's GHG
Permitting Guidance, which they say supports the notion that additional
work is required before CCS can be integrated at full-scale electric
utility applications. It is important to recognize that the EPA's
Permitting Guidance is guidance, so it does not contain any final
determination of BACT for any source. Furthermore, we disagree with the
commenters' characterization of the GHG Permitting Guidance. The
Guidance specifically states ``[f]or the purposes of a BACT analysis
for GHGs, the EPA classifies CCS as an add-on pollution control
technology that is ``available'' for facilities emitting CO2
in large amounts, including fossil fuel-fired power plants, and for
industrial facilities with high-purity CO2 streams (e.g.,
hydrogen production, ammonia production, natural gas processing,
ethanol production, ethylene oxide production, cement production, and
iron and steel manufacturing). For these types of facilities, CCS
should be listed in Step 1 of a top-down BACT analysis for GHGs.'' GHG
Permitting Guidance at 32. As discussed elsewhere in the Guidance,
technologies that should be listed in Step 1 are those that ``have the
potential for practical application to the emissions unit and regulated
pollutant under evaluation.'' GHG Permitting Guidance at 24. The EPA
continues to stand by its position on the availability of CCS in this
context, as expressed in the GHG Permitting Guidance.
The GHG Permitting Guidance continues on to discuss case-specific
factors and potential limitations with applying CCS, and it
acknowledges that CCS may not be ultimately selected as BACT in
``certain cases'' based on technology feasibility and cost. GHG
Permitting Guidance at 36, 43. While acknowledging these potential
challenges when it was issued in March 2011, the Guidance clearly does
not rule out the selection of CCS as BACT for any source category and
it is forward looking. GHG Permitting Guidance at 43 (``. . . as a
result of ongoing research and development, . . . CCS may become less
costly and warrant greater consideration . . . in the future'') Nothing
in the Guidance is inconsistent with EPA's present position that CCS is
adequately demonstrated for the types of sources covered by this NSPS,
as articulated elsewhere in this preamble.
A commenter asserted that the GHG Permitting Guidance should be
amended because it calls for consideration of CCS in BACT
determinations even though the proposed NSPS identified ``partial CCS''
as BSER for new boiler and IGCC EGUs. The Guidance explains that ``the
purpose of Step 1 of the process is to cast a wide net and identify all
control options with potential application to the emissions unit under
review.'' GHG Permitting Guidance at 26. The EPA agrees that the GHG
Permitting Guidance only uses the term ``CCS'' and does not distinguish
``partial CCS'' from ``full CCS.'' But considering the purpose of Step
1 of the process, we believe that the term ``CCS'', as it is used in
the GHG Permitting Guidance, adequately describes the varying levels of
CO2 capture. A BACT review should analyze all available
technologies in order to adequately support the BACT determination, and
may require evaluation of partial CCS, full CCS, and/or no
CO2 capture. The specific facility type and CO2
capture conditions will dictate the level(s) of CO2 capture
that are most appropriate to consider as ``available'' in a BACT
review.
D. Implications for Title V Program
Under the Title V program, certain stationary sources, including
``major sources'' are required to obtain an operating permit. This
permit includes all of the CAA requirements applicable to the source,
including adequate monitoring, recordkeeping, and reporting
requirements to assure sources' compliance. These permits are generally
issued through EPA-approved state Title V programs.
In the January 8, 2014 proposal, the EPA discussed whether this
rulemaking would impact the applicability of Title V requirements to
major sources of GHGs. 79 FR 1489-90. The relevant issue for Title V
purposes was, in essence, whether promulgation of CAA section 111
requirements for GHGs
[[Page 64633]]
would undermine the Tailoring Rule, which, as explained above, phased
in permitting requirements for GHG emissions for stationary sources
under the CAA PSD and Title V permitting programs. Based on the EPA's
understanding of the CAA at that time, the proposal discussed this
issue in the context of the regulatory and statutory definitions of
``major source,'' focusing on revisions that had been made in the
Tailoring Rule to the definitions in the Title V regulations of ``major
source'' and ``subject to regulation.'' 79 FR 1489-90 (quoting 75 FR
31583). Under the Title V regulations, as revised by the Tailoring
Rule, ``major source'' is defined to include, in relevant part, ``a
major stationary source . . . that directly emits, or has the potential
to emit, 100 tpy or more of any air pollutant subject to regulation.''
The proposal further explained that the GHG threshold that had been
established in the Tailoring Rule had been incorporated into the
definition of ``subject to regulation'' under 40 CFR 70.2 and 71.2,
such that those definitions specify `` `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.' ''
Id. (quoting 75 FR 31583). The proposal thus concluded that the Title V
definition of ``major source,'' as revised by the Tailoring Rule, did
not on its face distinguish among types of regulatory triggers for
Title V. It further noted that the Title V program had already been
triggered for GHGs, and thus concluded that the promulgation of CAA
section 111 requirements would not further impact Title V applicability
requirements for major sources of GHGs. 79 FR 1489-90.
As noted elsewhere in this section, after the proposal for this
rulemaking was published, the United States Supreme Court issued its
opinion in UARG v. EPA, 134 S.Ct. 2427 (June 23, 2014), and in
accordance with that decision, the D.C. Circuit subsequently issued an
amended judgment in Coalition for Responsible Regulation, Inc. v.
Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-
1167 (D.C. Cir., April 10, 2015). Those decisions support the same
overall conclusion as the EPA discussed in the proposal, though for
different reasons.
With respect to Title V, the Supreme Court said in UARG v. EPA that
the EPA may not treat GHGs as an air pollutant for purposes of
determining whether a source is a major source required to obtain a
Title V operating permit. In accordance with that decision, the D.C.
Circuit's amended judgment in Coalition for Responsible Regulation,
Inc. v. Environmental Protection Agency, vacated the Title V
regulations under review in that case to the extent that they require a
stationary source to obtain a Title V permit solely because the source
emits or has the potential to emit GHGs above the applicable major
source thresholds. The D.C. Circuit also directed the EPA to consider
whether any further revisions to its regulations are appropriate in
light of UARG v. EPA, and, if so, to undertake to make such revisions.
These court decisions make clear that promulgation of CAA section 111
requirements for GHGs will not result in the EPA imposing a requirement
that stationary sources obtain a Title V permit solely because such
sources emit or have the potential to emit GHGs above the applicable
major source thresholds.\552\
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\552\ As explained elsewhere in this notice, the EPA intends to
conduct future rulemaking action to make the appropriate revisions
to the operating permit rules to respond to the Supreme Court
decision and the D.C. Circuit's amended judgment. To the extent
there are any issues related to the potential interaction between
the promulgation of CAA section 111 requirements for GHGs and Title
V applicability based on emissions above major source thresholds,
the EPA expects there would be an opportunity to consider those
during that rulemaking.
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To be clear, however, unless exempted by the Administrator through
regulation under CAA section 502(a), any source, including an area
source (a ``non-major source''), subject to an NSPS is 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. This aspect of the
Title V program is not affected by UARG v. EPA, as the EPA does not
read that decision to affect either the grounds other than those
described above on which a Title V permit may be required or the
applicable requirements that must be addressed in Title V permits.\553\
Consistent with the proposal, the EPA has concluded that this rule will
not affect non-major sources and there is no need to consider whether
to exempt non-major sources. Thus, sources that are subject to the CAA
section 111 standards promulgated in this rule are required to apply
for, and operate pursuant to, a Title V permit that assures compliance
with all applicable CAA requirements, including any GHG-related
applicable requirements.
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\553\ See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
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E. Implications for Title V Fee Requirements for GHGs
1. Why is the EPA revising Title V fee rules as part of this action?
The January 8, 2014 notice of proposed rulemaking (79 FR 1430) (the
``EGU GHG NSPS proposal'' or ``NSPS proposal'') proposed the first
section 111 standards to regulate GHGs at EGUs. That notice also
included proposed revisions to the fee requirements of the 40 CFR part
70 and part 71 operating permit rules under Title V of the CAA to avoid
inadvertent consequences for fees that would be triggered by the
promulgation of the first CAA section 111 standard to regulate GHGs. If
we do not revise the fee rules by the time of the promulgation of the
NSPS standards for GHGs, then approved part 70 programs implemented by
state, local and tribal permitting authorities \554\ that rely on the
``presumptive minimum'' approach and the part 71 program implemented by
the EPA would be required to account for GHGs in emissions-based fee
calculations at the same dollar per ton ($/ton) rate as other air
pollutants. The EPA believes this would result in the collection of
fees in excess of what is required to cover the reasonable costs of an
operating permit program. See NSPS proposal 79 FR 1490.
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\554\ Hereafter, for the sake of simplicity, we will generally
refer to part 70 permitting authorities as ``state'' permitting
authorities and refer to part 70 programs as ``state'' programs.
---------------------------------------------------------------------------
In response to these concerns, the EPA proposed regulatory changes
to limit the fees collected based on GHG emissions and proposed two fee
adjustment options to increase the fees collected based on the costs
for permitting authorities to conduct certain review activities related
to GHG emissions, while still providing sufficient funding for an
operating permit program. Also, we proposed an option that would have
provided for no fee adjustments to recover the costs of conducting
review activities related to GHG emissions. Id. 79 FR 1490. The EPA did
not propose any action related to state and local permitting
authorities that do not use the presumptive minimum approach.
Most commenters on the proposal, including state and local
permitting authorities, were supportive of exempting GHGs from the
emissions-based fee calculations of the permit
[[Page 64634]]
rules, but support for the fee adjustment options was mixed, with state
and local permitting authorities generally supporting either of the two
fee adjustments, and other commenters generally supporting the option
that provides for no fee adjustment.
2. Background on the Fee Requirements of Title V
In the NSPS proposal, the EPA explained the statutory and
regulatory background related to the requirement that permitting
authorities collect fees from the owner or operator of Title V sources
that are sufficient to cover the costs of the operating permit program.
CAA section 502(b)(3)(A) requires an operating permit program to
include a requirement that sources ``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.'' See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i)
requires that, in order to have an approvable operating permit program,
the permitting authority must show that ``the program will result in
the collection, in the aggregate, from all sources [required to get an
operating permit]'' of either ``an amount not less than $25 per ton of
each regulated pollutant [adjusted annually for changes in the consumer
price index], or such other amount as the Administrator may determine
adequately reflects the reasonable costs of the permit program.'' See
also 40 CFR 70.9(b)(2). This has been generally referred to as the
``presumptive minimum'' approach. If a permitting authority does not
wish to use the presumptive minimum approach, it may demonstrate ``that
collecting an amount less than the [presumptive minimum amount] will''
result in the collection of funds sufficient to cover the costs of the
program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This
has been generally referred to as the ``detailed accounting'' approach.
CAA section 502(b)(3)(B)(ii) sets forth a definition of ``regulated
pollutant'' for purposes of calculating the presumptive minimum that
includes each pollutant regulated under section 111 of the CAA. See
also 40 CFR 70.2.
3. What fee rules did we propose to revise?
In the NSPS proposal, to exempt GHGs from emissions-based fee
calculations, we proposed to exempt GHGs from the definition of
``regulated pollutant'' for purposes of operating permit fee
calculations (``the GHG exemption''). The EPA then proposed two
alternative ways to account for the costs of addressing GHGs in
operating permits through a cost adjustment. First, we proposed a
modest additional cost for each GHG-related activity of certain types
that a permitting authority would process (``the GHG adjustment option
1''). Alternatively, we proposed a modest additional increase in the
per ton rate used in the presumptive minimum calculation for all non-
GHG fee pollutants (``the GHG adjustment option 2''). The EPA also
solicited comment on an option that would provide no additional cost
adjustment to account for GHGs (``the GHG adjustment option 3''). All
of the GHG adjustment options are based on the assumption that the GHG
exemption is finalized. See NSPS Proposal 79 FR 1493-1495.
The EPA additionally proposed two clarifications. The first was
regulatory text in 40 CFR part 60, subparts Da, KKKK, and TTTT, to
clarify that GHGs, as opposed to CO2, is the regulated
pollutant for fee purposes (``the fee pollutant clarification''). Id.
at 1505, 1506 and 1511. The second was a proposal to move the existing
definition of ``Greenhouse gases (GHGs)'' within 40 CFR 70.2 and 71.2
to promote clarity in the regulations (``the GHG clarification''). Id.
79 FR 1490, 1517, 1518.
For background purposes, below is a brief summary of each of the
proposals.
a. The GHG Exemption
To address the fee issues discussed in the NSPS proposal, the EPA
proposed to exempt GHG emissions from the definition of ``regulated
pollutant (for presumptive fee calculation)'' in 40 CFR 70.2 and the
definition of ``regulated pollutant (for fee calculation)'' in 40 CFR
71.2.\555\ See NSPS preamble 79 FR 1493, 1495.
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\555\ Hereafter we will refer to these definitions as the ``fee
pollutant'' definitions. Also, note that both fee pollutant
definitions cross-reference the definitions of ``regulated air
pollutant'' which includes air pollutants ``subject to any standard
promulgated under section 111 of the Act.''
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b. The GHG Adjustment Option 1
The first proposed ``GHG adjustment'' option (option 1) was to
include an additional cost for each GHG-related activity of certain
types that a permitting authority would process (an activity-based
adjustment). The three activities identified for this option were ``GHG
completeness determination (for initial permit or for updated
application)'' at 43 hours of burden,\556\ ``GHG evaluation for a
modification or related permit action'' at 7 hours of burden, and ``GHG
evaluation at permit renewal'' at 10 hours of burden. See also 79 FR
1494, fn. 280 (providing a description of each of these activities).
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\556\ Burden is the hours of staff time necessary to perform a
task.
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For part 70, the burden hours per activity would be multiplied by
the cost of staff time (in $/hour) specific to the state, including
wages, benefits, and overhead, to determine the cost of each activity.
All the activities for a given period would be totaled to determine the
total GHG adjustment for the state. See 79 FR 1494.
For part 71, we proposed a labor rate assumption of $52 per hour in
2011 dollars. Using that labor rate, we proposed to determine the GHG
fee adjustment for each GHG permitting program activity to be a
specific dollar amount for each activity (``set fees'') that the source
would pay for each activity performed. See 79 FR 1495. The EPA proposed
to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this
option.
c. The GHG Adjustment Option 2
The second proposed GHG adjustment option (option 2) was to
increase the dollar per ton ($/ton) rates used in the fee calculations
for each non-GHG fee pollutant. The revised $/ton rates would be
multiplied by the total tons of non-GHG fee pollutants actually emitted
by any source to determine the applicable total fees. The EPA proposed
to increase the $/ton rates by 7 percent.\557\ See NSPS proposal 79 FR
1494, 1495.
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\557\ The EPA estimated that both options 1 and 2 would result
in about a 7 percent increase in the fees collected by operating
permit programs affected by the proposed rule. For example, the
presumptive minimum fee rate in effect for September 1, 2014 through
August 31, 2015 is $48.27/ton. A 7 percent increase under option 2
would result in a revised fee of $51.65/ton.
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d. The GHG Adjustment Option 3
The EPA also solicited comment on not charging any fees related to
GHGs (option 3). The basis for this proposed option was the observation
that most sources that need to address GHGs in a permit would also emit
non-GHG fee pollutants, and thus, the cost of permitting for any
particular source may be accounted for adequately without charging any
additional fees related to GHGs. Id. 79 FR 1494-1495.
e. The Fee Pollutant Clarification
Another fee-related proposal was to add regulatory text to 40 CFR
part 60, subparts Da, KKKK, and TTTT, to clarify that the fee pollutant
for operating permit purposes would be considered to be ``GHGs,'' (as
defined in
[[Page 64635]]
40 CFR 70.2 and 71.2),\558\ rather than solely CO2, which
would be regulated under the section 111 standards and implemented
through the EGU GHG NSPS. Id. 79 FR 1505, 1506, and 1511.
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\558\ Note that in 40 CFR 70.2 and 71.2, the term ``Greenhouse
gases (GHGs)'' is defined as the ``aggregate group of six greenhouse
gases: Carbon dioxide, nitrous oxide, methane, hydrofluorocarbons,
perfluorocarbons, and sulfur hexafluoride.''
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f. The GHG Clarification
The EPA proposed to move the existing definition of ``Greenhouse
gases (GHGs)'' within the definition of ``Subject to regulation'' in 40
CFR 70.2 and 71.2 to a separate definition within those sections to
promote clarity in the regulations. Id. 79 FR 1490, 1517, 1518.
4. What action is the EPA finalizing?
In this action, the EPA is finalizing the following elements as
proposed: (1) The GHG exemption, (2) the GHG adjustment option 1, and
(3) the fee pollutant clarification.
Public commenters on the proposal stated both support and
opposition to using the NSPS rulemaking action to revise the Title V
fee rules. Two commenters stated that proposing the Title V fee
revisions within the NSPS rulemaking would result in fewer commenters,
particularly state and local permitting authorities, having knowledge
of the changes to the fee rules and sufficient opportunity to comment
on the changes because the NSPS proposal is limited to a single source
category, and one stated that a separate proposal for the fee rules
would provide a sufficient opportunity for public comment. The EPA
believes it is appropriate to move forward with final action amending
the Title V fee regulations as part of this NSPS. As we explained in
the preamble for the proposal and elsewhere in this final rule, the fee
rules and the section 111 standards are interrelated because, if we do
not revise the fee rules, promulgation of the final NSPS will trigger
certain requirements related to Title V fees for GHG emissions that the
EPA believes will result in the collection of excessive fees in states
that implement the presumptive minimum approach and in the part 71
program. Thus, it is important to finalize the revisions to the fee
rules at the same time or prior to this NSPS, and it is within the
EPA's discretion to address the NSPS and the fee rules at the same time
as part of the same rulemaking action. In response to the commenters
who were concerned that including the fee rule proposal as part of the
NSPS proposal would result in the public not having sufficient public
comment opportunities, the EPA believes sufficient public comment
opportunities were provided on the fee rule changes because the
proposal met all public participation requirements and we provided
additional public outreach, including to state and local permitting
authorities, which discussed the fee rule proposal. In addition to the
publication of the proposed rulemaking in the Federal Register, the EPA
held numerous hearings, reached out to state partners and the public,
and developed numerous fact sheets and other information to support
public comment on this rule. The EPA has complied with the applicable
public participation requirements and executive orders. The proposal
met all the requirements for public notice--it contained a clear and
detailed explanation of how the part 70 and 71 rules would be affected
by the promulgation of the CAA section 111 standard for EGUs and how
the EPA proposed to revise the related regulatory provisions. We
received many comments on the proposal to revise the fee rule for
operating permits programs, and we are taking those comments into
consideration in the finalization of the rulemaking action.
a. The GHG Exemption
The EPA is taking final action to revise the definition of
regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2
and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt
GHG emissions. This regulatory amendment will have the effect of
excluding GHG emissions from being subject to the statutory ($/ton) fee
rate set for the presumptive minimum calculation requirement of part 70
and the fee calculation requirements of part 71. We received supportive
comments from the majority of public commenters, including state and
local permitting authorities and others, on revising the operating
permit rules to exempt GHGs from the emission-based calculations that
use the statutory fee rates. We are finalizing this portion of the
proposal for the same reasons we explained in the proposal notice,
including that leaving these regulations unchanged would have resulted
in the collection of fee revenue far beyond the reasonable costs of an
operating permit program. The EPA believes that these revisions (in
conjunction with the GHG adjustment, see below) are consistent with the
CAA requirements for fees pursuant to the authority of section
502(b)(3)(B)(i).
Some members of the public opposed the proposed GHG exemption for
reasons including that it may limit permitting authorities' ability to
charge sufficient fees to cover the cost of GHG permitting \559\ if the
state is barred from exceeding minimum requirements set by the EPA.
Despite this adverse comment, the EPA believes it is appropriate to
finalize the GHG exemption because we are not finalizing any
requirements that would require states to charge any particular fees to
any particular sources. The changes we are finalizing to part 70
concern the presumptive minimum approach, which sets a minimum fee
target for states that have decided to follow the presumptive minimum
approach. Neither the statute nor the final rule require any state
following the presumptive minimum approach (or any other approach) to
charge fees to sources using any particular method. Thus, the GHG
exemption will not limit states' ability to structure their individual
fee programs however they see fit in order to meet the requirement that
they collect revenue sufficient to cover all reasonable costs of their
permitting program. See CAA section 502(b)(3); 40 CFR 70.9(b)(3).
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\559\ We use the term ``GHG permitting'' in this section of the
notice to refer to measures undertaken by permitting authorities to
ensure that GHGs and any applicable requirements related to GHGs are
appropriately addressed in Title V permitting.
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b. The GHG Adjustment Option 1
The EPA is finalizing GHG adjustment option 1 because we believe it
will result in a system for the calculation of costs for part 70 and
fees for part 71 that is most directly related to the costs of GHG
permitting. The EPA has determined that some adjustment to cost and fee
accounting is important because the recent addition of GHG emissions to
the operating permitting program does add new burdens for permitting
authorities. Although GHG adjustment option 3 (no GHG permitting fee
adjustments) was supported by many industrial commenters, the EPA
rejected it because it is in tension with the statutory requirement
that permitting authorities collect sufficient fees to cover all the
reasonable costs of permitting. See CAA section 502(b)(3)(A). Some
state and local permitting authorities provided comments supporting
option 1, while others supported option 2, and some supported either
option, stating no preference. Also, a few state and local permitting
authorities supported finalizing no adjustment and a few others asked
for flexibility to set fee adjustments not proposed by the EPA, but
that they believed would be appropriate for their program.
[[Page 64636]]
The EPA is finalizing option 1 instead of option 2 because the
option 1 adjustments are based on the actual costs for permitting
authorities to process specific actions that require GHG reviews. The
option 2 approach, which would have added a 7 percent surcharge to the
$/ton rate used in the fee-related calculations, may have been
administratively easier to implement, but is tied to the emissions of
non-GHG air pollutants, which are not directly related to the costs of
GHG permitting.
Consistent with CAA section 502(b)(3)(B)(i), the Administrator has
determined that the final rule's approach of exempting GHG emissions
from fee-related calculations and accounting for the GHG permitting
costs through option 1 will result in fees that will cover the
reasonable costs of the permitting programs.
The EPA is revising the part 70 regulations through this final
action, specifically 40 CFR 70.9(b)(2), to modify the presumptive
minimum approach to add the activity-based cost of GHG permitting
activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the
emissions-based calculation of 40 CFR 70.9(b)(2)(i), which is being
revised to now exclude GHG emissions. To determine the activity-based
GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority
will multiply the burden hours for each activity (set forth in the
regulation) by the cost of staff time (in $ per hour), including wages,
benefits, and overhead, as determined by the state, for the particular
activities undertaken during the particular time period.
States that implement the presumptive minimum approach will need to
follow the final rule's option 1 approach.\560\ States that use the
detailed accounting approach are not directly affected by this
rulemaking, but they must ensure that their fee collection programs are
sufficient to fully fund all reasonable costs of the operating permit
program, including costs attributable to GHG-related permitting. The
EPA suggests states that use the detailed accounting approach consider
the 7 percent assumption for the costs of GHG permitting in any such
analysis, consistent with the EPA analysis of options 1 and 2 in the
proposal.
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\560\ A presumptive minimum state may require various changes to
its approved operating permit program before it may begin to
implement the option 1 approach. For example, its regulations, and/
or program procedures and practices, may need to be revised,
depending on the structure of the fee provisions in the state's
program; thus, the exact response necessary to address this final
action may vary from state to state.
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Consistent with 40 CFR 70.4(i), a state that wishes to change its
operating permit program as a result of this final rule must apprise
the EPA. The EPA will review the materials submitted concerning the
change and decide if a formal program revision process is needed and
will inform the state of next steps. The communication apprising the
EPA of any such changes should include at least a narrative description
of the change and any other information that will assist the EPA in its
assessment of the significance of the changes. Certain changes, such as
switching from the presumptive minimum method to a detailed accounting
method, will be considered substantial program revisions and be subject
to the requirements of 40 CFR 70.4(i)(2).
With respect to the part 71 program, in this final action the EPA
is revising 40 CFR 71.9(c) to require each part 71 source to pay an
annual fee which is the sum of the activity-based fee of 40 CFR
71.9(c)(8) and the emissions-based fee of 40 CFR 71.9(c)(1)-(4),\561\
which excludes GHG emissions. To determine the activity-based fee, the
revised 40 CFR 71.9(c)(8) requires the source to pay a ``set fee'' for
each listed activity that has been initiated since the fee was last
paid. Under part 71, fees are typically paid at the time of initial
application submittal, and thereafter, annually on the anniversary of
the initial fee payment, or on any other dates that may be established
in the permit. These set fees would not change until such time as we
may revise our part 71 rule to change the set fees.
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\561\ Note that the emissions-based fee calculation differs
somewhat depending on whether the part 71 program is being
implemented by the EPA (see 40 CFR 71.9(c)(1)); a state, local or
tribal agency with delegated authority from the EPA (see Sec.
71.9(c)(2)); the EPA with contractor assistance (see Sec.
71.9(c)(3)); or an agency with partial delegation authority (see
Sec. 71.9(c)(4)).
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The final rule implements the option 1 approach by listing three
activities performed by permitting authorities that involve GHG
reviews. The following describes the activities as described in our
proposal and certain clarifications we are making in the final rule to
ensure consistent implementation.
The EPA is finalizing that the first listed activity under option 1
is ``GHG completeness determination (for initial permit or updated
application).'' This activity must be counted for each new initial
permit application, even for applications that do not include GHGs
emissions or applicable requirements, since an important part of any
completeness determination will be to determine that GHG emissions and
applicable requirements have been properly addressed, as needed, in the
application. The fee for this activity is a one-time charge that covers
the initial application and any supplements or updates. The EPA
believes that a single charge for a GHG completeness determination will
be adequate to cover the reasonable costs for a permitting authority to
review an initial application and any subsequent application updates
related to initial permit issuance; thus, any updates to an initial
application are included in a single ``GHG completeness
determination,'' rather than as a separate activity for which the
source would be charged in addition to the completeness determination
for the initial application. This is an important distinction because
many sources submit multiple permit application updates, either
voluntarily or as required by the permitting authority, during
application review, many of which do not require a separate or
comprehensive completeness determination.
The EPA is finalizing regulatory text that would describe the
second listed activity as ``GHG evaluation for a permit modification or
related permit action.'' \562\ The EPA had proposed that the second
listed activity under option 1 would be ``GHG evaluation for a
modification or related permit action.'' For the final rule, we are
clarifying that we are adding a cost for a ``permit modification''
rather than for a ``modification.'' The term ``modification'' may be
interpreted to refer to any change at a source, even a change that
would not be required to be processed as a ``permit modification,''
while ``permit modification'' refers to any revision to an operating
permit that cannot be processed as an administrative permit amendment
and thus requires a review by a permitting authority as either a
significant or minor permit modification.
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\562\ The EPA notes that the term ``permit modification'' in
this context refers to all significant permit modifications and
minor permit modifications under operating permit rules, but not to
``administrative permit amendments,'' as such amendments are not
defined as ``permit modifications'' in the permit rules. See, e.g.,
40 CFR 70.7(d), (e), and (f).
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The EPA is finalizing the third activity as ``GHG evaluation at
permit renewal.'' This activity covers the processing of all permit
renewal applications and will involve evaluations of whether any GHG
applicable requirements are properly included.
Some members of the public commented that finalizing a GHG
adjustment would inappropriately
[[Page 64637]]
increase sources' financial burdens. The EPA has explained, both in the
proposal notice and elsewhere in this preamble, the importance of the
fee-related revisions to account for the costs associated with GHG-
related permitting. The EPA believes that the revisions being finalized
will result in modest and reasonable fee increases necessary to cover
states' increased costs.\563\ To the extent that commenters intended to
argue that the adjustments we proposed would exceed the actual costs of
GHG permitting, no commenters provided any information or analysis to
support that position. Some commenters did state that the costs
associated with GHG-related permitting should be minimal because few
applicable requirements will apply to GHGs. As stated earlier in this
notice, the EPA's cost estimate for the proposal concerned the
incremental costs of GHG permitting for any source, not just those that
would have, at the time of the analysis, triggered the requirement to
get a permit based on GHG emissions or applicable requirements.
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\563\ The EPA estimated in the proposal that option 1 would
result in about a 7 percent overall increase in the annual part 70
fees that are collected by all permitting authorities nationally.
See 79 FR 1494.
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Despite some comments received to the contrary, the EPA does not
believe it is appropriate to delay the finalization of the GHG
adjustment. The EPA does not believe such delays would be consistent
with CAA section 502(b)(3)(A) because states have been incurring costs
attributable to GHG permitting for several years now and increased fees
must be collected to cover the increased costs. The regulatory changes
being finalized in this action provide the states with optimal
flexibility and sufficient funding to implement their GHG permitting
programs. Some commenters had specifically stated that the EPA should
delay finalization of this rule until the completion of the next ICR
renewal process. While we do not believe delaying this rule is
appropriate, as explained above, the EPA notes that we remain committed
to collecting and analyzing additional data on costs attributable to
GHG permitting for operating permit programs. We may adjust the GHG
cost adjustments in future rulemakings if necessary to comply with the
requirements of the Act.
As an alternative to the options proposed by the EPA, some
commenters asserted that the EPA should make a GHG cost adjustment
using a separate, but reduced fee rate ($/ton) for GHGs. We, however,
believe that the option 1 approach of the final rule will be more
equitable for sources and more representative of actual costs because
option 1 considers the costs of the actual permitting activities
performed by a particular permitting authority, while any emissions-
based approach would not be as directly related to actual costs
incurred by permitting authorities.
Some commenters alleged that the EPA's proposal on adjustments to
the operating permit programs was vague. The EPA provided a thorough
discussion of our rationale in the proposal, including the basis for
the GHG adjustments, and we proposed regulatory text to implement our
proposal. We explained in the proposal that support for the cost
adjustment for GHGs under option 1 is contained in several analyses
performed by the EPA and approved by the OMB related to the effect of
the addressing GHG requirements in operating permits. These analyses
have been placed in the docket for this rulemaking. The analyses
include: The Regulatory Impact Assessment (RIA) for the Tailoring Rule
(see Regulatory Impact Analysis for the Final Prevention of Significant
Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report,
May 2010); the part 70 ICR change request for the Tailoring Rule (which
was based on the RIA for the Tailoring Rule); and the current ICR for
part 70 (EPA ICR number 1587.12; OMB control number 2060-0243).
Several commenters asked that we make changes to the option 1
approach that we proposed, such as adding new activities or decreasing
the costs we assumed for the proposal. In response to these comments,
we note that we received no quantitative data or other information from
commenters that we believe demonstrates the need to revise the list of
activities we included under option 1 or the burden hour assumptions
under option 1 for the activities. Note that to promote consistent
implementation of the final option 1 approach, the preamble describes
elsewhere a few clarifications concerning the activities under option 1
and one minor revision to the regulatory text of one of the activities.
Since the EPA's proposed rulemaking, the Supreme Court decided in
UARG v. EPA that the EPA may not treat GHGs as an air pollutant for
purposes of determining whether a source is a major source required to
obtain a Title V operating permit.\564\ The EPA's review of the effect
of the Supreme Court decision on the burden hour assumptions for the
GHG review activities under proposed option 1 is that the effects are
not significant enough to warrant revision of the burden hour
assumptions in the final rule. Proposed option 1 was based on the
assumption that permitting authorities would need to evaluate all
permit applications for initial permit issuance, significant and minor
permit modifications, and permit renewals for GHG issues (even if there
are no applicable GHG requirements). Even after the UARG v. EPA
decision, permitting authorities will continue to need to evaluate GHG
issues for sources applying for a title V permit and for permit
modifications and renewals for existing permits, and we do not
anticipate that the decision will significantly affect the total number
of such evaluations that will occur in any given year compared to the
assumptions in our analysis, which as explained above, were based on
the incremental costs of GHG permitting for any source. Thus, we are
finalizing the burden hour assumptions as they were proposed. See NSPS
proposal at 1494 and the supporting statement for the 2012 part 70 ICR
renewal. Also, as discussed previously, we remain committed to
collecting and analyzing additional data on costs and we may adjust the
burden hour assumptions or other aspects of option 1 in a future
rulemaking, if needed.
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\564\ The EPA does not, however, read the UARG decision to
affect other grounds on which a Title V permit may be required or
the applicable requirements that must be addressed in Title V
permits. See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
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c. The Fee Pollutant Clarification
We are also finalizing the proposed addition of text within 40 CFR
part 60, subpart TTTT, to clarify that the fee pollutant for operating
permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are
finalizing these provisions to add clarity to our regulations and to
avoid the potential need for possible future rulemakings to adjust the
title V fee regulations if any constituent of GHG, other than
CO2, becomes subject to regulation under section 111 for the
first time. The proposal was to add this clarifying text to 40 CFR part
60, subparts Da, KKKK, and TTTT. The final rule adds the clarification
text only to subpart TTTT because the EPA is
[[Page 64638]]
codifying all of the requirements for the affected EGUs in a new
subpart TTTT and including all CO2 emission standards for
the affected EGUs (electric utility steam generating units, as well as
natural gas-fired stationary combustion turbines) in that newly created
subpart. See Section III.B of this preamble for more on this subject.
d. The GHG Clarification
The EPA is taking no action at this time on the proposal to move
the definitions of ``Greenhouse gases (GHG)'' within the definition of
``Subject to regulation'' in 40 CFR parts 70 and 71. No public comments
were received on this proposed clarification; however, subsequent to
the proposal, on June 23, 2014, the Supreme Court in UARG v. EPA
decided that GHG emissions could not be used in making certain
applicability determinations under the operating permit rules. More
specifically with respect to title V, as described above, the Supreme
Court said that the EPA may not treat GHGs as an air pollutant for
purposes of determining whether a source is a major source required to
obtain a title V operating permit. In accordance with the Supreme Court
decision, on April 10, 2015, the D.C. Circuit issued an amended
judgment in Coalition for Responsible Regulation, Inc. v. Environmental
Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir.
April 10, 2015), which, among other things, vacated the title V
regulations under review in that case to the extent that they require a
stationary source to obtain a title V permit solely because the source
emits or has the potential to emit GHGs above the applicable major
source thresholds. The D.C. Circuit also directed the EPA to consider
whether any further revisions to its regulations are appropriate in
light of UARG v. EPA, and, if so, to undertake to make such revisions.
In response to the Supreme Court decision and the D.C. Circuit's
amended judgment, the EPA intends to conduct future rulemaking action
to make the appropriate revisions to the operating permit rules. As
part of any such future rulemaking action, the EPA may consider
finalizing the proposal to move the definitions of GHGs within the
operating permit rules.
F. Interactions With Other EPA Rules
Fossil fuel-fired EGUs are, or potentially will be, impacted by
several other recently finalized or proposed EPA rules.\565\ Many of
the rules that impact fossil fuel-fired EGUs apply to existing
facilities as well as newly constructed, modified, or reconstructed
facilities. In fact, the rules described below are more applicable to
existing EGUs than to newly constructed, modified, or reconstructed
EGUs. Although those rules will affect EGUs as existing sources,
because we expect that there will be few NSPS modifications or
reconstructions, we don't anticipate those rules affecting EGUs as
modified or reconstructed sources. In constructing new EGUs, sources
can take all applicable requirements of the various rules into
consideration.
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\565\ 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.
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1. Mercury and Air Toxics Standards (MATS)
On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to
reduce emissions of toxic air pollutants from new and existing coal-
and oil-fired EGUs. The MATS rule will reduce emissions of heavy
metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel
(Ni); and acid gases, including hydrochloric acid (HCl) and
hydrofluoric acid (HF). These toxic air pollutants, also known as
hazardous air pollutants or air toxics, are known to cause, or
suspected of causing, damage nervous system damage, cancer, and other
serious health effects. The MATS rule will also reduce SO2
and fine particle pollution, which will reduce particle concentrations
in the air and prevent thousands of premature deaths and tens of
thousands of heart attacks, bronchitis cases and asthma episodes.
New or reconstructed EGUs (i.e., sources that commence construction
or reconstruction after May 3, 2011) subject to the MATS rule are
required to comply by April 16, 2012 or upon startup, whichever is
later.
Existing sources subject to the MATS rule were required to begin
meeting the rule's requirements on April 16, 2015. Controls that will
achieve the MATS performance standards are being installed on many
units. Certain units, especially those that operate infrequently, may
be considered not worth investing in given today's electricity market,
and are closing. The final MATS rule provided a foundation on which
states and other permitting authorities could rely in granting an
additional, fourth year for compliance provided for by the CAA. States
report that these fourth year extensions are being granted. In
addition, the EPA issued an enforcement policy that provides a clear
pathway for reliability-critical units to receive an administrative
order that includes a compliance schedule of up to an additional year,
if it is needed to ensure electricity reliability.\566\
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\566\ Following promulgation of the MATS rule, industry, states
and environmental organizations challenged many aspects of the EPA's
threshold determination that regulation of EGUs is ``appropriate and
necessary'' and the final standards regulating hazardous air
pollutants from EGUs. The U.S. Court of Appeals for the D.C. Circuit
upheld all aspects of the MATS rule. White Stallion Energy Center v.
EPA, 748 F.3d 1222 (D.C. Cir. 2014). The decision was unanimous on
all issues except a dissent was filed because the EPA did not
consider cost when determining regulation of EGUs is appropriate. In
Michigan v. EPA, case no. 14-46, the Supreme Court reversed the D.C.
Circuit decision upholding the MATS rule finding that EPA erred by
not considering cost when determining that regulation of EGUs was
``appropriate'' pursuant to section 112(n)(1). The Supreme Court
considered only the narrow question of cost and did not review the
other holdings of the D.C. Circuit, nor did the Supreme Court vacate
the MATS rule.
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2. Cross-State Air Pollution Rule (CSAPR)
The CSAPR requires states to take action to improve air quality by
reducing SO2 and NOX emissions that cross state
lines. These pollutants react in the atmosphere to form fine particles
and ground-level ozone and are transported long distances, making it
difficult for other states to attain and maintain the NAAQS. The first
phase of CSAPR became effective on January 1, 2015, for SO2
and annual NOX, and May 1, 2015, for ozone season
NOX. The second phase will become effective on January 1,
2017, for SO2 and annual NOX, and May 1, 2017,
for ozone season NOX. Many of the power plants participating
in CSAPR have taken actions to reduce hazardous air pollutants for MATS
compliance that will also reduce SO2 and/or NOX.
In this way these two rules are complementary. Compliance with one
helps facilities comply with the other.
3. Requirements for Cooling Water Intake Structures at Power Plants
(316(b) Rule)
On May 19, 2014, the EPA issued a final rule under section 316(b)
of the Clean Water Act (33 U.S. Code section 1326(b)) (referred to
hereinafter as the 316(b) rule.) The rule was published on August 15,
2014 (79 FR 48300; August 15, 2014), and became effective October 14,
2014. The 316(b) rule establishes new standards to reduce injury and
death of fish and other aquatic life caused by cooling water intake
structures at existing power plants and manufacturing facilities.\567\
The 316(b)
[[Page 64639]]
rule subjects existing power plants and manufacturing facilities that
withdraw in excess of 2 million gallons per day (MGD) of cooling water,
and use at least 25 percent of that water for cooling purposes, to a
national standard designed to reduce the number of fish destroyed
through impingement and entrainment. Existing sources subject to the
316(b) rule are required to comply with the impingement requirements as
soon as practicable after the entrainment requirements are determined.
They must comply with applicable site-specific entrainment reduction
controls based on the schedule of requirements established by the
permitting authority. Additional information regarding the 316(b) rule
for existing sources is included in Section IX.C of the preamble to the
CAA section 111(d) emission guidelines for existing EGUs that the EPA
is finalizing simultaneously with this rule. Although the recently
issued 316(b) rule discussed here applies to existing sources, there
are also 316(b) technology-based standards for new sources with cooling
water intake structures.
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\567\ CWA section 316(b) provides that standards applicable to
point sources under sections 301 and 306 of the Act must require
that the location, design, construction and capacity of cooling
water intake structures reflect the best technology available for
minimizing adverse environmental impacts.
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4. Disposal of Coal Combustion Residuals From Electric Utilities (CCR
Rule)
On December 19, 2014, the EPA issued the final rule for the
disposal of coal combustion residuals from electric utilities. The rule
provides a comprehensive set of requirements for the safe disposal of
coal combustion residuals (CCRs), commonly known as coal ash, from
coal-fired power plants. The CCR rule establishes technical
requirements for existing and new CCR landfills and surface
impoundments under Subtitle D of the Resource Conservation and Recovery
Act (RCRA), the nation's primary law for regulating solid waste. New
CCR landfills and surface impoundments are required to meet the
technical criteria before any CCR is placed into the unit. Existing CCR
surface impoundments and landfills are subject to implementation
timeframes established in the rule for the individual technical
criteria. For additional information regarding the CCR rule, see
Section IX.C of the preamble to the CAA section 111(d) emission
guidelines for existing EGUs that the EPA is finalizing along with this
rule.
5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG
Rule)
The EPA is reviewing public comments and working to finalize the
proposed SE ELG rule which will impact fossil fuel-fired EGUs. In 2013,
the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) to
strengthen the controls on discharges from certain steam electric power
plants by revising technology-based effluent limitations guidelines and
standards for the steam electric power generating point source
category. The proposed regulation, which includes new requirements for
both existing and new generating units, would reduce impacts to human
health and the environment by reducing the amount of toxic metals and
other pollutants currently discharged to surface waters from power
plants. The EPA intends to take final action on the proposed rule by
September 30, 2015. Section IX.C of the preamble to the CAA section
111(d) emission guidelines for existing EGUs that the EPA is finalizing
simultaneously with this rule includes additional information regarding
the SE ELG rule.
The EPA recognizes the importance of assuring that each of the
rules described above can achieve its intended environmental objectives
in a commonsense, cost-effective manner, consistent with underlying
statutory requirements, and while assuring a reliable power system.
Executive Order (E.O.) 13563, ``Improving Regulation and Regulatory
Review,'' issued on January 18, 2011, states that ``[i]n developing
regulatory actions and identifying appropriate approaches, each agency
shall attempt to promote . . . coordination, simplification, and
harmonization.'' E.O. 13563 further states that ``[e]ach agency shall
also seek to identify, as appropriate, means to achieve regulatory
goals that are designed to promote innovation.'' Within the EPA, we are
paying careful attention to the interrelatedness and potential impacts
on the industry, reliability and cost that these various rulemakings
can have.
As discussed in earlier sections of this preamble, the EPA has
identified potential alternative compliance pathways for affected newly
constructed, modified, and reconstructed fossil fuel-fired steam
generating units. We are finalizing an emission standard for newly
constructed highly efficient fossil fuel-fired steam generating units
that can be met by capturing and storing approximately 16 to 23 percent
of the CO2 produced from the facility or by utilizing other
technologies such as natural gas co-firing. For a subcategory of steam
generating units that conduct ``large'' modifications according to
definitions in this final rule, we are finalizing an emission standard
that is based on a unit-specific emission limitation consistent with
each modified unit's best one-year historical performance and can be
met through a combination of best operating practices and equipment
upgrades. For reconstructed steam generating units, the EPA is
finalizing standards of performance based on the performance of the
most efficient generation technology available, which we concluded is
the use of the best available subcritical steam conditions for small
units and the use of supercritical steam conditions for large units.
The standards can also be met through other technology options such as
natural gas co-firing. In light of these potential alternative
compliance pathways, we believe that sources will have ample
opportunity to coordinate their response to this rule with any
obligations that may be applicable to affected EGUs as a result of the
MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which are or soon
will be final rules--and to do so in a manner that will help reduce
cost and ensure reliability, while also ensuring that all applicable
environmental requirements are met.\568\
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\568\ It should be noted that regulatory obligations imposed
upon states and sources operate independently under different
statutes and sections of statutes; the EPA expects that states and
sources will take advantage of available flexibilities as
appropriate, but will comply with all relevant legal requirements.
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The EPA is also endeavoring to enable EGUs to comply with
applicable obligations under other power sector rules as efficiently as
possible (e.g., by facilitating their ability to coordinate planning
and investment decisions with respect to those rules) and, where
possible, implement integrated compliance strategies. Section IX.C of
the preamble to the CAA section 111(d) emission guidelines for existing
EGUs that the EPA is finalizing simultaneously with this rule describes
such an example with respect to the SE ELG and CCR rules.
In light of the compliance flexibilities we are offering in this
action, we believe that sources will have ample opportunity to use
cost-effective regulatory strategies and build on their longstanding,
successful records of complying with multiple CAA, CWA, and other
environmental requirements, while assuring an adequate, affordable, and
reliable supply of electricity.
[[Page 64640]]
XIII. Impacts of This Action
As explained in the ``Regulatory Impact Analysis for the Standards
of Performance for Greenhouse Gas Emissions for New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units''
(EPA-452/R-15-005, August 2015) (RIA), available data indicate that,
even in the absence of the standards of performance for newly
constructed EGUs, existing and anticipated economic conditions will
lead electricity generators to choose new generation technologies that
will meet the standards without installation of additional controls.
Therefore, based on the analysis presented in Chapter 4 of the RIA, the
EPA projects that this final rule will result in negligible
CO2 emission changes, quantified benefits, and costs on
owners and operators of newly constructed EGUs by 2022.\569\ This
conclusion is based on the EPA's own modeling as well as projections by
EIA. While the primary conclusion of the analysis presented in the RIA
is that the standards for newly constructed EGUs will result in
negligible costs and benefits, the EPA has also performed several
illustrative analyses that show the potential impacts of the rule if
certain key assumptions were to change. This includes an analysis of
the impacts under a range of natural gas prices and the costs and
benefits associated with building an illustrative coal-fired EGU with
CCS. These are presented in Chapter 5 of the RIA.
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\569\ Conditions in the analysis year of 2022 are represented by
a model year of 2020.
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As also explained in the RIA for this final rule, the EPA also
expects that few sources will trigger either the NSPS modification or
reconstruction provisions that we are finalizing in this rule. In
Chapter 6 of the RIA, we discuss factors that limit our ability to
quantify the costs and benefits of the standards for modified and
reconstructed sources.
A. What are the air impacts?
As explained immediately above, the EPA does not anticipate that
this final rule will result in notable CO2 emission changes
by 2022 as a result of the standards of performance for newly
constructed EGUs. The owners of newly constructed EGUs will likely
choose technologies, primarily NGCC, which meet the standards even in
the absence of this rule due to existing economic conditions as normal
business practice.
As also explained immediately above, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.
New steam generating EGUs that choose to comply with the final
standard of performance by implementing partial post-combustion CCS are
likely to use commercially-available amine-based capture systems. Some
concern has been raised regarding emissions of amines and amine
degradation by-products (e.g., NH3) from the capture
process. To reduce the amine emissions, MHI introduced the first
optimized washing system within an absorber column in 1994, and
developed a proprietary washing system in 2003. In that system, a
proprietary reagent is added to the water washing section to capture
amine impurities such as amine, degraded amine, ammonia, formaldehyde,
acetaldehyde, carbonic acids and nitrosamines.\570\ MHI has continued
to improve this technology for further reduction of amine emissions and
established an ``advanced amine emission reduction system''.
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\570\ Sharma, S.; Azzi, M.; ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies'',
Fuel, 121, 178 (2014).
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Research performed by MHI at Alabama Power's Plant Barry indicated
that an increasing SO3 content in the flue gas caused a
significant increase of amine emissions. During testing, at Plant
Barry, MHI applied its proprietary washing system and confirmed that
the amine emission were drastically reduced.\571\ Others have also
studied emissions and control strategies and have determined that a
conventional multi-stage water wash and mist eliminator at the exit of
the CO2 scrubber is effective at removal of gaseous amine
and amine degradation products emissions.572 573 Additional
research continues in this area.
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\571\ Kamijo, T.; et al., ``SO3 Impact on Amine
Emission and Emission Reduction Technology'', Energy Procedia,
Volume 37, 1793 (2013).
\572\ Sharma, S. (2014).
\573\ Mertens, J.; et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine based post combustion carbon
capture: Lessons learned from field tests'', Int'l J. of GHG
Control, 13, 72 (2013).
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B. Endangered Species Act
Consistent with the requirements of section 7(a)(2) of the
Endangered Species Act (ESA), the EPA has also considered the effects
of this rule and has reviewed applicable ESA regulations, case law, and
guidance to determine what, if any, impact there may be to listed
endangered or threatened species or the designated critical habitat of
such species and whether consultation with the U.S. Fish and Wildlife
Service (FWS) and/or National Marine Fisheries Service (together, the
Services) is required by the ESA. Section 7(a)(2) of the ESA requires
federal agencies, in consultation with the Service(s), to ensure that
actions they authorize, fund, or carry out are not likely to jeopardize
the continued existence of federally listed endangered or threatened
species or result in the destruction or adverse modification of
designated critical habitat of such species. 16 U.S.C. 1536(a)(2).
Under relevant implementing regulations, ESA section 7(a)(2) applies
only to actions where there is discretionary federal involvement or
control. 50 CFR 402.03. Further, under the regulations consultation is
required only for actions that ``may affect'' listed species or
designated critical habitat. 50 CFR 402.14. Consultation is not
required where the action has no effect on such species or habitat.
Under this standard, it is the federal agency taking the action that
evaluates the action and determines whether consultation is required.
See 51 FR 19926, 19949 (June 3, 1986). Effects of an action include
both the direct and indirect effects that will be added to the
environmental baseline. 50 CFR 402.02. Direct effects are the direct or
immediate effects of an action on a listed species or its habitat.\574\
Indirect effects are those that are ``caused by the proposed action and
are later in time, but still are reasonably certain to occur.'' Id. To
trigger the consultation requirement, there must thus be a causal
connection between the federal action, the effect in question, and the
listed species, and if the effect is indirect, it must be reasonably
certain to occur.
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\574\ See Endangered Species Consultation Handbook, U.S. Fish &
Wildlife Service and National Marine Fisheries Service at 4-25(March
1998) (providing examples of direct effects: e.g., driving an off
road vehicle through the nesting habitat of a listed species of bird
and destroying a ground nest; building a housing unit and destroying
the habitat of a listed species).
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The EPA notes that the projected environmental effects of this
final action are positive: Reductions in overall GHG emissions, and
reductions in PM and ozone-precursor emissions (SOX and
NOX). The EPA recognizes that beneficial effects to listed
species can, as a general matter, result in a ``may affect''
determination under the ESA. However, the EPA's assessment that the
rule will have an overall net positive environmental effect by virtue
of reducing emissions of certain air pollutants does not address
whether the rule may affect any listed species or designated critical
habitat for ESA section 7(a)(2) purposes and does not constitute any
finding of effects for that purpose. The fact that the rule will have
overall positive effects on the national
[[Page 64641]]
and global environment does not mean that the rule may affect any
listed species in its habitat or the designated critical habitat of
such species within the meaning of ESA section 7(a)(2) or the
implementing regulations or require ESA consultation.
The EPA notes that the emission reductions achieved by the rule are
projected to be minor. See Section XIII.F and G. below, and RIA chapter
4. Although the final rule imposes substantial controls on
CO2 emissions, we project few if any new fossil fuel-fired
steam generating units to be built. Emissions reductions from turbines
are likewise projected to be minimal. Moreover, we reasonably project
that capacity additions during the analysis period out to 2022 would
already be compliant with the rule's requirements (e.g., natural gas
combined cycle units, low capacity factor natural gas combustion
turbines, and small amounts of coal-fired units with CCS supported by
federal and state funding). See RIA chapter 4.
With respect to the projected GHG emission reductions, the EPA does
not believe that such minor reductions trigger ESA consultation
requirements under section 7(a)(2). In reaching this conclusion, the
EPA is mindful of significant legal and technical analysis undertaken
by FWS and the U.S. Department of the Interior (DOI) in the context of
listing the polar bear as a threatened species under the ESA. In that
context, in 2008, FWS and DOI expressed the view that the best
scientific data available were insufficient to draw a causal connection
between GHG emissions and effects on the species in its habitat.\575\
The DOI Solicitor concluded that where the effect at issue is climate
change, proposed actions involving GHG emissions cannot pass the ``may
affect'' test of the section 7 regulations and thus are not subject to
ESA consultation.
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\575\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum
from David Longly Bernhardt, Solicitor, U.S. Department of the
Interior re: ``Guidance on the Applicability of the Endangered
Species Act's Consultation Requirements to Proposed Actions
Involving the Emission of Greenhouse Gases'' (Oct. 3, 2008).
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The EPA has also previously considered issues relating to GHG
emissions in connection with the requirements of ESA section 7(a)(2)
and has supplemented DOI's analysis with additional consideration of
GHG modeling tools and data regarding listed species. The EPA evaluated
this same issue in the context of the light duty vehicle GHG emission
standards for model years 2012-2016 and 2017-2025. There the agency
projected GHG emission reductions many orders of magnitude greater over
the lifetimes of the model years in question \576\ and, based on air
quality modeling of potential environmental effects, concluded that
``EPA knows of no modeling tool which can link these small, time-
attenuated changes in global metrics to particular effects on listed
species in particular areas. Extrapolating from global metric to local
effect with such small numbers, and accounting for further links in a
causative chain, remain beyond current modeling capabilities.'' EPA,
Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel
Economy Standards, Response to Comment Document for Joint Rulemaking at
4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion
after evaluating issues relating to potential improvements relevant to
both temperature and oceanographic pH outputs. The EPA's ultimate
finding was that ``any potential for a specific impact on listed
species in their habitats associated with these very small changes in
average global temperature and ocean pH is too remote to trigger the
threshold for ESA section 7(a)(2).''Id. The EPA believes that the same
conclusions apply to the present action, given that the projected
CO2 emission reductions are far less than those projected
for either of the light duty vehicle rules. See, e.g., Ground Zero
Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082,
1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a species
from a federal action is extremely remote, ESA does not require
consultation). The EPA's conclusion is entirely consistent with DOI's
analysis regarding ESA requirements in the context of federal actions
involving GHG emissions.\577\
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\576\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at
62894 Table III-68 (Oct. 15, 2012).
\577\ The EPA has received correspondence from Members of
Congress asserting that the Services have identified several listed
species affected by global climate change. The EPA's assessment of
ESA requirements in connection with the present rule does not
address whether global climate change may, as a general matter, be a
relevant consideration in the status of certain listed species.
Rather, the requirements of ESA section 7(a)(2) must be considered
and applied to the specific action at issue. As explained above, the
EPA's conclusion that ESA section 7(a)(2) consultation is not
required here is premised on the specific facts and circumstances of
the present rule and is fully consistent with prior relevant
analyses conducted by DOI, FWS, and the EPA.
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The EPA received a comment on the proposal referencing a prior
letter sent to the EPA by three U.S. Senators,\578\ which asserted that
the rule will cause a shift to alternative sources of energy such as
wind and solar and that such facilities may have impacts on listed
species. The comment inquired regarding ESA consultation in connection
with the rule. We reiterate that no consultation is required for a rule
without potential for a specific impact on listed species in their
habitats.
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\578\ See Letter from David Vitter, James M. Inhofe, and Mike
Crapo, United States Senate Committee on Environment and Public
Works, to Gina McCarthy, Administrator, U.S. Environmental
Protection Agency, and Dan Ashe, Director, U.S. Fish and Wildlife
Service, dated March 6, 2014.
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C. What are the energy impacts?
This final 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 will choose to build new EGUs
that comply with the regulatory requirements of this rule even in its
absence, primarily NGCC units, because of existing and expected market
conditions. As also previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.
D. What are the water and solid waste impacts?
This final rule is not anticipated to have notable impacts on water
or solid waste. As we have noted, the EPA believes that utilities and
project developers will choose to build new EGUs that comply with the
regulatory requirements of this rule even in its absence, primarily
through the construction of new NGCC units. As also previously stated,
the EPA expects few EGUs to trigger the NSPS modification or
reconstruction provisions in the period of analysis. Still there are
expected to be a small number of coal plants with CCS and the use of
CCS systems (especially post-combustion system) will increase the
amount of water used at the facility. If those plants utilize partial
CCS to meet the final standard of performance (i.e., approximately 16
to 23 percent capture), the increased water use will not be
significant. See Section V.O.2. The EPA is unaware of any solid waste
impact resulting from this rule.\579\
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\579\ Estimated costs for the rule include costs for fly ash and
bottom ash disposal and for spent solvent recovery and handling. See
``Cost and Performance Baseline for Fossil Energy Plants Volume 1a:
Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3'',
DOE/NETL-2015/1723 (July 2015) at pp. 43, 130.
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E. What are the compliance costs?
For steam generating EGUs, the EPA has carefully analyzed the costs
of meeting the promulgated standard of performance for a highly
efficient SCPC
[[Page 64642]]
using partial CCS and found these costs to be reasonable. See Sections
V.H and I above. This analysis assumes new capacity not otherwise
compliant with the standards would be constructed. Based on the
analysis in chapter 4 of the RIA, the EPA believes the standards of
performance for newly constructed EGUs will have no notable compliance
costs, because electric power companies are expected to build new EGUs
that comply with the regulatory requirements of this final rule even in
the absence of the rule, primarily NGCC units, due to existing and
expected market conditions. While the EPA's analysis and projections
from EIA continue to show that the rule is likely to result in
negligible costs and benefits due to existing generation choices, the
EPA recognizes that some companies may choose to construct coal or
other fossil fuel-fired units and has set standards for these units
accordingly. For this reason, 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.
In addition, the EPA believes the standards of performance for
modified and reconstructed EGUs will have minimal associated compliance
costs, because, as previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.
F. What are the economic and employment impacts?
The EPA does not anticipate that this final rule will result in
notable CO2 emission changes, energy impacts, monetized
benefits, costs, or economic impacts by 2022 as a result of the
standards of performance for newly constructed EGUs. The owners of
newly constructed EGUs will likely choose technologies that meet the
standards even in the absence of this rule, 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. See RIA chapter 4.6.\580\
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\580\ The employment analysis in the RIA is part of the EPA's
ongoing effort to ``conduct continuing evaluations of potential loss
or shifts of employment which may result from the administration or
enforcement of [the Act]'' pursuant to CAA section 321(a).
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As previously stated, the EPA anticipates few units will trigger
the NSPS modification or reconstruction provisions. As with the new
source standards, the EPA does not expect macroeconomic or employment
impacts as a result of the standards.
G. What are the benefits of the final standards?
We are not projecting direct monetized climate benefits in terms of
CO2 emission reductions associated with these standards of
performance. This is because, as stated above, the EPA believes that
electric power companies will choose to build new EGUs that comply with
the regulatory requirements of this rule even in its absence, primarily
NGCC units, because of existing and expected market conditions. See RIA
chapter 4. Moreover, a cost-reasonable standard is, in fact, what will
drive new technology deployment and provide a path forward for new
coal-fired capacity. See Section V.L above.
As also previously stated, the EPA anticipates few units will
trigger the NSPS modification or reconstruction provisions. In Chapter
6 of the RIA, we discuss factors that limit our ability to quantify the
costs and benefits of the standards for modified and reconstructed
sources.
XIV. Statutory and Executive Order Reviews
Additional information about these Statutory and Executive Orders
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This final action is a significant regulatory action that was
submitted to the Office of Management and Budget (OMB) for review. It
is a significant regulatory action because it raises novel legal or
policy issues arising out of legal mandates. Any changes made in
response to OMB recommendations have been documented in the established
dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495
(Standards of Performance for Greenhouse Gas Emissions from New
Stationary Sources: Electric Utility Generating Units) and Docket ID
No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and
Reconstructed Stationary Sources: Electric Utility Generating Units).
The EPA prepared an economic analysis of the potential costs and
benefits associated with this action. This analysis, which is contained
in the ``Regulatory Impact Analysis for the Standards of Performance
for Greenhouse Gas Emissions for New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units'' (EPA-452/R-15-
005, August 2015), is available in both dockets.
The EPA does not anticipate that this final action will result in
any notable compliance costs. Specifically, we believe that the
standards for newly constructed fossil fuel-fired EGUs (electric
utility steam generating units and natural gas-fired stationary
combustion turbines) will have negligible 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 action even in the absence of the action, because
of existing and expected market conditions. (See the RIA for further
discussion of sensitivities). The EPA does not project any new coal-
fired steam generating units without CCS to be built in the absence of
this action. However, because some companies may choose to construct
coal or other fossil fuel-fired EGUs, the RIA also analyzes project-
level costs of a unit with and without CCS, to quantify the potential
cost for a fossil fuel-fired EGU with CCS.
The EPA also believes that the standards for modified and
reconstructed fossil fuel-fired EGUs will result in minimal compliance
costs, because, as previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis (through 2022). In Chapter 6 of the RIA, we discuss
factors that limit our ability to quantify the costs and benefits of
the standards for modified and reconstructed sources.
B. Paperwork Reduction Act (PRA)
The information collection activities in this final action have
been submitted for approval to OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2465.03. Separate ICR documents were prepared
and submitted to OMB for the proposed standards for newly constructed
EGUs (EPA ICR number 2465.02) and the proposed standards for modified
and reconstructed EGUs (EPA ICR number 2506.01). Because the
CO2 standards for newly constructed, modified, and
reconstructed EGUs will be included in the same new subpart (40 CFR
part 60, subpart TTTT) and are being finalized in the same action, the
ICR document for this action includes estimates of the information
collection burden on owners and operators of newly constructed,
modified, and reconstructed EGUs. Estimated cost burden is based on
2013 Bureau of Labor Statistics (BLS) labor cost data.
[[Page 64643]]
Thus, all burden estimates are in 2013 dollars. Burden is defined at 5
CFR 1320.3(b). You can find a copy of the ICR in the dockets for this
action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-
0603), and it is briefly summarized here. The information collection
requirements are not enforceable until OMB approves them.
The recordkeeping and reporting requirements in this final action
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.
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. When OMB
approves this ICR, the agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final action.
1. Newly Constructed EGUs
This final action will impose minimal new information collection
burden on owners and operators of affected newly constructed fossil
fuel-fired EGUs (steam generating units and stationary combustion
turbines) 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 to comply with the emission
standards under the rule, there are no new information collection
costs, as the information required by the standards for newly
constructed EGUs is already collected and reported by other regulatory
programs.
The EPA believes that electric power companies will choose to build
new EGUs that comply with the regulatory requirements of the rule
because of existing and expected market conditions. The EPA does not
project any newly constructed coal-fired steam generating units that
commenced construction after proposal (January 8, 2014) to commence
operation over the 3-year period covered by this ICR. We estimate that
12 affected newly constructed NGCC units and 25 affected newly
constructed natural gas-fired simple cycle combustion turbines will
commence operation during that time period. As a result of this final
action, owners or operators of those newly constructed units will be
required to prepare a summary report, which includes reporting of
emissions and downtime, every 3 months.
2. Modified and Reconstructed EGUs
This final action is not expected to impose an information
collection burden under the provisions of the PRA on owners and
operators of affected modified and reconstructed fossil fuel-fired EGUs
(steam generating units and stationary combustion turbines). As
previously stated, the EPA expects few EGUs to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Specifically, the EPA believes it unlikely that fossil fuel-fired
electric utility steam generating units or stationary combustion
turbines will take actions that would constitute modifications or
reconstructions as defined under the EPA's NSPS regulations.
Accordingly, the standards for modified and reconstructed EGUs are not
anticipated to impose any information collection burden over the 3-year
period covered by this ICR. We have estimated, however, the information
collection burden that would be imposed on an affected EGU if it was
modified or reconstructed.
Although not anticipated, if an EGU were to modify or reconstruct,
this final action would impose minimal information collection burden on
those affected EGUs beyond what they would already be subject to under
the authorities of CAA 40 CFR parts 75 and 98. As described above, the
OMB has previously approved the information collection requirements
contained in the existing part 75 and 98 regulations. Apart from
certain reporting costs to comply with the emission standards under the
rule, there would be no new information collection costs, as the
information required by the final rule is already collected and
reported by other regulatory programs.
As stated above, although the EPA expects few sources will trigger
either the NSPS modification or reconstruction provisions, if an EGU
were to modify or reconstruct during the 3-year period covered by this
ICR, the owner or operator of the EGU will be required to prepare a
summary report, which includes reporting of emissions and downtime,
every 3 months. The annual reporting burden for such a unit is
estimated to be $1,333 and 16 labor hours. There are no annualized
capital costs or O&M costs associated with burden for modified or
reconstructed EGUs.
3. Information Collection Burden
The annual information collection burden for newly constructed,
modified, and reconstructed EGUs consists only of reporting burden as
explained above. The annual reporting burden for this collection
(averaged over the first 3 years after the effective date of the
standards) is estimated to be $60,977 and 651 labor hours. There are no
annualized capital costs or O&M costs associated with burden for newly
constructed, modified, or reconstructed EGUs. Average burden hours per
response are estimated to be 7 hours. The total number of respondents
over the 3-year ICR period is estimated to be 62.
C. Regulatory Flexibility Act (RFA)
I certify that this final action will not have a significant
economic impact on a substantial number of small entities under the
RFA. In making this determination, the impact of concern is any
significant adverse economic impact on small entities. An agency may
certify that a rule will not have a significant economic impact on a
substantial number of small entities if the rule relieves regulatory
burden, has no net burden or otherwise has a positive economic effect
on the small entities subject to the rule.
1. Newly Constructed EGUs
The EPA believes that electric power companies will choose to build
new fossil fuel-fired electric utility steam generating units or
natural gas-fired stationary combustion turbines that comply with the
regulatory requirements of the final rule because of existing and
expected market conditions. RIA Chapter 4. The EPA does not project any
new coal-fired steam generating units without CCS to be built. We
expect that any newly constructed natural gas-fired stationary
combustion turbines will meet the standards. We do not include an
analysis of the illustrative impacts on small entities that may result
from implementation of the final rule because we anticipate negligible
compliance costs over a range of likely sensitivity conditions as a
result of the standards for newly constructed EGUs. Thus the cost-to-
sales ratios for any affected small entity would be zero costs as
compared to annual sales revenue for the entity. Accordingly, there are
no anticipated
[[Page 64644]]
economic impacts as a result of the standards for newly constructed
EGUs. (See the ``Regulatory Impact Analysis for the Standards of
Performance for Greenhouse Gas Emissions for New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units''
(EPA-452/R-15-005, August 2015) for further discussion of
sensitivities.) We have therefore concluded that this final action will
have no net regulatory burden for all directly regulated small
entities.
2. Modified and Reconstructed EGUs
The EPA expects few fossil fuel-fired electric utility steam
generating units to trigger the NSPS modification provisions in the
period of analysis. An NSPS modification is defined as a physical or
operational change that increases the source's maximum achievable
hourly rate of emissions. The EPA does not believe that there are
likely to be EGUs that will take actions that would constitute
modifications as defined under the EPA's NSPS regulations.
In addition, the EPA expects few reconstructed fossil fuel-fired
electric utility steam generating units or natural gas-fired stationary
combustion turbines in the period of analysis. Reconstruction occurs
when a single project replaces components or equipment in an existing
facility and exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility.
In Chapter 6 of the RIA, we discuss factors that limit our ability
to quantify the costs and benefits of the standards for modified and
reconstructed sources. However, we do not anticipate that the rule
would impose significant costs on those sources, including any that are
owned by small entities. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015).
D. Unfunded Mandates Reform Act (UMRA)
This final action does not contain an unfunded mandate of $100
million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments.
The EPA believes the final rule will have negligible compliance
costs on owners and operators of newly constructed EGUs over a range of
likely sensitivity conditions because electric power companies will
choose to build new fossil fuel-fired electric utility steam generating
units or natural gas-fired stationary combustion turbines that comply
with the regulatory requirements of the rule because of existing and
expected market conditions. The EPA does not project any new coal-fired
steam generating units without CCS to be built and expects that any
newly constructed natural gas-fired stationary combustion turbines will
meet the standards. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015) for further
discussion of sensitivities.)
As previously stated, the EPA expects few fossil fuel-fired
electric utility steam generating units or natural gas-fired stationary
combustion turbines to trigger the NSPS modification or reconstruction
provisions in the period of analysis. In Chapter 6 of the RIA, we
discuss factors that limit our ability to quantify the costs and
benefits of the standards for modified and reconstructed sources.
However, we do not anticipate that the rule would impose significant
costs on those sources. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015).)
We have therefore concluded that the standards for newly
constructed, modified, and reconstructed EGUs do not impose enforceable
duties on any state, local or tribal governments, or the private
sector, that may result in expenditures by state, local and tribal
governments, in the aggregate, or to the private sector, of $100
million or more in any one year. We have also concluded that this
action does not have regulatory requirements that might significantly
or uniquely affect small governments. The threshold amount established
for determining whether regulatory requirements could significantly
affect small governments is $100 million annually and, as stated above,
we have concluded that the final action will not result in expenditures
of $100 million or more in any one year. Specifically, the EPA does not
project any new coal-fired steam generating units without CCS to be
built and expects that any newly constructed natural gas-fired
stationary combustion turbines will meet the standards. Further, the
EPA expects few fossil fuel-fired electric utility steam generating
units or natural gas-fired stationary combustion turbines to trigger
the NSPS modification or reconstruction provisions in the period of
analysis.
E. Executive Order 13132: Federalism
This final action does not have federalism implications. It will
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.
The EPA believes that electric power companies will choose to build new
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines that comply with the
regulatory requirements of the final rule because of existing and
expected market conditions. In addition, as previously stated, the EPA
expects few fossil fuel-fired electric utility steam generating units
or natural gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
We, therefore, anticipate that the final rule will impose minimal
compliance costs.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This final action does not have tribal implications as specified in
Executive Order 13175. The final rule will impose requirements on
owners and operators of newly constructed, modified, and reconstructed
EGUs. The EPA is aware of three facilities with coal-fired steam
generating units, as well as one facility with natural gas-fired
stationary combustion turbines, located in Indian Country, but is not
aware of any EGUs owned or operated by tribal entities. We note that
because the rule addresses CO2 emissions from newly
constructed, modified, and reconstructed EGUs, it will affect existing
EGUs such as those located at the four facilities in Indian Country
only if those EGUs were to take actions constituting modifications or
reconstructions as defined under the EPA's NSPS regulations. As
previously stated, the EPA expects few EGUs to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Thus, the rule will neither impose substantial direct compliance costs
on tribal governments nor preempt Tribal law. Accordingly, Executive
Order 13175 does not apply to this action.
Nevertheless, because the EPA is aware of Tribal interest in carbon
pollution standards for the power sector and, consistent with the EPA
Policy on Consultation and Coordination with Indian Tribes, the EPA
offered consultation with tribal officials during
[[Page 64645]]
development of this rule. Prior to the April 13, 2012 proposal (77 FR
22392), the EPA sent consultation letters to the leaders of all
federally recognized tribes. Although only newly constructed, modified,
and reconstructed EGUs will be affected by this action, the EPA's
consultation regarded planned actions for new and existing sources. 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. A description
of that consultation is included in the preamble to the proposed
standards for new EGUs (79 FR 1501, January 8, 2014).
The EPA also offered consultation to the leaders of all federally
recognized tribes after the proposed action for newly constructed EGUs
was signed on September, 20, 2013. On November 1, 2013, the EPA sent
letters to tribal leaders that provided information regarding the EPA's
development of carbon pollution standards for new, modified,
reconstructed and existing EGUs and offered consultation. No tribes
requested consultation regarding the standards for newly constructed
EGUs.
In addition to offering consultation, the EPA also conducted
outreach to tribes during development of this rule. The EPA held a
series of listening sessions prior to proposal of GHG standards for
newly constructed EGUs. Tribes participated in a session on February
17, 2011, with the state agencies, as well as in a separate session
with tribes on April 20, 2011. The EPA also held a series of listening
sessions prior to proposal of GHG standards for modified and
reconstructed EGUs and GHG emission guidelines for existing EGUs.
Tribes participated in a session on September 9, 2013, together with
the state agencies, as well as in a separate tribe-only session on
September 26, 2013. In addition, an outreach meeting was held on
September 9, 2013, with tribal representatives from some of the
federally recognized tribes. The EPA also met with tribal environmental
staff with the National Tribal Air Association, by teleconference, on
July 25, 2013, and December 19, 2013. Additional detail regarding this
stakeholder outreach is included in the preamble to the proposed
emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to Executive Order 13045 because it is
not economically significant as defined in Executive Order 12866. While
the action is not subject to Executive Order 13045, the EPA believes
that the environmental health or safety risk addressed by this action
has a disproportionate effect on children. Accordingly, the agency has
evaluated the environmental health and welfare effects of climate
change on children.
CO2 is a potent GHG that contributes to climate change
and is emitted in significant quantities by fossil fuel-fired power
plants. As stated above, the EPA believes the final rule will have
negligible effects on owners and operators of newly constructed EGUs
over a range of likely sensitivity conditions because electric power
companies will choose to build new fossil fuel-fired electric utility
steam generating units or natural gas-fired stationary combustion
turbines that comply with the regulatory requirements of the rule
because of existing and expected market conditions. However, 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. RIA
chapter 5. Under these scenarios, the rule would result in substantial
reductions of both CO2, and also fine particulate matter
(sulfate PM 2.5) such that net quantifiable benefits exceed regulatory
costs under a range of assumptions. Under these same scenarios, this
rule would have a positive effect for children's health.
The assessment literature cited in the EPA's 2009 Endangerment
Finding concluded that certain populations and lifestages, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects. The assessment literature since 2009
strengthens these conclusions by providing more detailed findings
regarding these groups' vulnerabilities and the projected impacts they
may experience.
These assessments describe how children's unique physiological and
developmental factors contribute to making them particularly vulnerable
to climate change. Impacts to children are expected from heat waves,
air pollution, infectious and waterborne illnesses, and mental health
effects resulting from extreme weather events. In addition, children
are among those especially susceptible to most allergic diseases, as
well as health effects associated with heat waves, storms, and floods.
Additional health concerns may arise in low income households,
especially those with children, if climate change reduces food
availability and increases prices, leading to food insecurity within
households.
More detailed information on the impacts of climate change to human
health and welfare is provided in Section II.A of this preamble.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This final action is not a ``significant energy action'' because it
is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. See Section V.O.3 above. The EPA
believes that electric power companies will choose to build new fossil
fuel-fired electric utility steam generating units or natural gas-fired
stationary combustion turbines that comply with the regulatory
requirements of the final rule because of existing and expected market
conditions. In addition, as previously stated, the EPA expects few
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Thus, this action is not anticipated to have notable impacts on
emissions, costs or energy supply decisions for the affected electric
utility industry.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This final action involves technical standards. The EPA has decided
to use 10 voluntary consensus standards (VCS) in the final rule.
One VCS, American National Standards Institute (ANSI) Standard
C12.20, ``American National Standard for Electricity Meters--0.2 and
0.5 Accuracy Classes,'' is cited in the final rule to assure consistent
monitoring of electric output. This standard establishes the physical
aspects and acceptable performance criteria for 0.2 and 0.5 accuracy
class electricity meters. This standard is available at http://www.ansi.org or by mail at American National Standards Institute
(ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036.
Six VCS, ASTM Methods D388-99, ``Standard Classification of Coals
by Rank''; D396-98, ``Standard Specification for Fuel Oils''; D975-08a,
``Standard Specification for Diesel Fuel Oils''; D3699-08, ``Standard
Specification for Kerosine''; D6751-11b,
[[Page 64646]]
``Standard Specification for Biodiesel Fuel Blend Stock (B100) for
Middle Distillate Fuels''; and D7467-10, ``Standard Specification for
Diesel Fuel Oil, Biodiesel Blend (B6 to B20)'' are cited in the final
rule to identify the different fuel types. ASTM D388 covers the
classification of coals by rank, that is, according to their degree of
metamorphism, or progressive alteration, in the natural series from
lignite to anthracite. ASTM D396 covers grades of fuel oil intended for
use in various types of fuel-oil-burning equipment under various
climatic and operating conditions. These include Grades 1 and 2 (for
use in domestic and small industrial burners), Grade 4 (heavy
distillate fuels or distillate/residual fuel blends used in commercial/
industrial burners equipped for this viscosity range), and Grades 5 and
6 (residual fuels of increasing viscosity and boiling range, used in
industrial burners). ASTM D975 covers seven grades of diesel fuel oils
based on grade, sulfur content, and volatility. These grades range from
Grade No. 1-D S15 (a special-purpose, light middle distillate fuel for
use in diesel engine applications requiring a fuel with 15 ppm sulfur
(maximum) and higher volatility than that provided by Grade No. 2-D S15
fuel) to Grade No. 4-D (a heavy distillate fuel, or a blend of
distillate and residual oil, for use in low- and medium-speed diesel
engines in applications involving predominantly constant speed and
load). ASTM D3699 covers two grades of kerosene suitable for use in
critical kerosene burner applications: No. 1-K (a special low-sulfur
grade kerosene suitable for use in non-flue-connected kerosene burner
appliances and for use in wick-fed illuminating lamps) and No. 2-K (a
regular grade kerosene suitable for use in flue-connected burner
appliances and for use in wick-fed illuminating lamps). ASTM D6751
covers biodiesel (B100) Grades S15 and S500 for use as a blend
component with middle distillate fuels. ASTM D7467 covers fuel blend
grades of 6 to 20 volume percent biodiesel with the remainder being a
light middle or middle distillate diesel fuel, collectively designated
as B6 to B20. These standards are available at http://www.astm.org or
by mail at ASTM International, 100 Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, PA 19428-2959.
Two VCS, American Society of Mechanical Engineers (ASME)
Performance Test Codes PTC 22-2014, ``Performance Test Codes on Gas
Turbines'' and PTC 46-1996, ``Performance Test Codes on Overall Plant
Performance'' are cited in the final rule for their guidance on
measuring the performance of stationary combustion turbines. PTC-22
provides directions and rules for conduct and report of results of
thermal performance tests for open cycle simple cycle combustion
turbines. The object is to determine the thermal performance of the
combustion turbine when operating at test conditions, and correcting
these test results to specified reference conditions. PTC 22 provides
explicit procedures for the determination of the following performance
results: corrected power, corrected heat rate (efficiency), corrected
exhaust flow, corrected exhaust energy, and corrected exhaust
temperature. Tests may be designed to satisfy different goals,
including absolute performance and comparative performance. The
objective of PTC 46 is to provide uniform test methods and procedures
for the determination of the thermal performance and electrical output
of heat-cycle electric power plants and combined heat and power units
(PTC 46 is not applicable to simple cycle combustion turbines). Test
results provide a measure of the performance of a power plant or
thermal island at a specified cycle configuration, operating
disposition and/or fixed power level, and at a unique set of base
reference conditions. PTC 46 provides explicit procedures for the
determination of the following performance results: corrected net
power, corrected heat rate, and corrected heat input. These standards
are available at http://www.asme.org or by mail at American Society of
Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990.
One VCS, International Organization for Standardization method ISO
2314:2009, ``Gas Turbines--Acceptance Tests'' is cited in the final
rule for its guidance on determining performance characteristics of
stationary combustion turbines. ISO 2314 specifies guidelines and
procedures for preparing, conducting and reporting thermal-acceptance
tests in order to determine and/or verify electrical power output,
mechanical power, thermal efficiency (heat rate), turbine exhaust gas
energy and/or other performance characteristics of open-cycle simple
cycle combustion turbines using combustion systems supplied with
gaseous and/or liquid fuels as well as closed-cycle and semi-closed-
cycle simple cycle combustion turbines. It can also be applied to
simple cycle combustion turbines in combined cycle power plants or in
connection with other heat recovery systems. ISO 2314 includes
procedures for the determination of the following performance
parameters, corrected to the reference operating parameters: electrical
or mechanical power output (gas power, if only gas is supplied),
thermal efficiency or heat rate; and combustion turbine engine exhaust
energy (optionally exhaust temperature and flow). This standard is
available at http://www.iso.org/iso/home.htm or by mail at
International Organization for Standardization (ISO), 1, ch. de la
Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland.
Since no EPA Methods were used, there was no need for a NTTAA
search. The rule also requires use of appendices A, B, D, F and G to 40
CFR part 75 and the procedures under 40 CFR 98.33; these appendices
contain standards that have already been reviewed under the NTTAA.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the U.S. The EPA defines environmental justice as the
fair treatment and meaningful involvement of all people regardless of
race, color, national origin, or income with respect to the
development, implementation, and enforcement of environmental laws,
regulations, and policies. The EPA has this goal for all communities
and persons across this Nation. It will be achieved when everyone
enjoys the same degree of protection from environmental and health
hazards and equal access to the decision-making process to have a
healthy environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health
and welfare effects of GHG emissions in its 2009 Endangerment Finding.
As part of the Endangerment Finding, the Administrator considered
climate change risks to minority or low-income populations, finding
that certain parts of the population may be especially vulnerable based
on their circumstances. Populations that were found to be particularly
vulnerable to
[[Page 64647]]
climate change risks include the poor, the elderly, the very young,
those already in poor health, the disabled, those living alone, and/or
indigenous populations dependent on one or a few resources. See
Sections XIV.F and G, above, where the EPA discusses Consultation and
Coordination with Tribal Governments and Protection of Children. The
Administrator placed weight on the fact that certain groups, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects.
The record for the 2009 Endangerment Finding summarizes the strong
scientific evidence in the major assessment reports 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 that the potential impacts of climate change raise
environmental justice issues. These reports concluded that poor
communities can be especially vulnerable to climate change impacts
because they tend to have more limited adaptive capacities and are more
dependent on climate-sensitive resources such as local water and food
supplies. In addition, Native American tribal communities possess
unique vulnerabilities to climate change, particularly those impacted
by degradation of natural and cultural resources within established
reservation boundaries and threats to traditional subsistence
lifestyles. Tribal communities whose health, economic well-being, and
cultural traditions depend upon the natural environment will likely be
affected by the degradation of ecosystem goods and services associated
with climate change. The 2009 Endangerment Finding record also
specifically noted that Southwest native cultures are especially
vulnerable to water quality and availability impacts. Native Alaskan
communities are already experiencing disruptive impacts, including
coastal erosion and shifts in the range or abundance of wild species
crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific
understanding of climate change risks to minority and low-income
populations in the United States.\581\ The new assessment literature
provides more detailed findings regarding these populations'
vulnerabilities and projected impacts they may experience. In addition,
the most recent assessment reports provides new information on how some
communities of color may be uniquely vulnerable to climate change
health impacts in the United States. These reports find that certain
climate change related impacts--including heat waves, degraded air
quality, and extreme weather events--have disproportionate effects on
low-income and some communities of color, raising environmental justice
concerns. Existing health disparities and other inequities in these
communities increase their vulnerability to the health effects of
climate change. In addition, assessment reports also find that climate
change poses particular threats to health, wellbeing, and ways of life
of indigenous peoples in the United States.
---------------------------------------------------------------------------
\581\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W.
Yohe, Eds., 2014: Climate Change Impacts in the United States: The
Third National Climate Assessment. U.S. Global Change Research
Program, 841 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, 1132 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part B: Regional Aspects. Contribution of Working
Group II to the Fifth Assessment Report of the Intergovernmental
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D.
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S.
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge
University Press, 688 pp.
---------------------------------------------------------------------------
As the scientific literature presented above and in the
Endangerment Finding illustrates, low income communities and some
communities of color are especially vulnerable to the health and other
adverse impacts of climate change.
The EPA believes the human health or environmental risk addressed
by this final action will not have potential disproportionately high
and adverse human health or environmental effects on minority, low-
income or indigenous populations. The final rule limits GHG emissions
from newly constructed, modified, and reconstructed fossil fuel-fired
electric utility steam generating units and newly constructed and
modified stationary combustion turbines by establishing national
emission standards for CO2.
The EPA has determined that the final rule will not result in
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because the
rule is not anticipated to notably affect the level of protection
provided to human health or the environment. The EPA believes that
electric power companies will choose to build new fossil fuel-fired
electric utility steam generating units and natural gas-fired
stationary combustion turbines that comply with the regulatory
requirements of the final rule because of existing and expected market
conditions. The EPA does not project any new coal-fired steam
generating units without CCS to be built and expects that any newly
built natural gas-fired stationary combustion turbines will meet the
standards. In addition, as previously stated, the EPA expects few
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
This final rule will ensure that, to whatever extent there are newly
constructed, modified, and reconstructed EGUs, they will use the best
performing technologies to limit emissions of CO2.
K. Congressional Review Act (CRA)
This final action is subject to the CRA, and the EPA will submit a
rule report to each House of the Congress and to the Comptroller
General of the United States. This action is not a ``major rule'' as
defined by 5 U.S.C. 804(2).
XV. Withdrawal of Proposed Standards for Certain Modified Sources
In this action, as discussed above in Sections IV and VI, the EPA
is issuing final standards of performance for affected fossil fuel-
fired steam generating EGUs that implement modifications resulting in
an increase of CO2 emissions (in lb/hr) of more than 10
percent. In addition, the EPA is withdrawing the proposed standards of
performance for emissions of carbon dioxide (CO2) from
modified fossil fuel-fired EGUs not covered by those final standards.
Specifically, the EPA is withdrawing the proposed standards for fossil
fuel-fired steam generating EGUs that implement modifications resulting
in an increase of CO2 emissions (in lb/hr) of less than or
equal to 10 percent. A detailed rationale for the withdrawal of these
proposed standards is provided in Section VI above.
The EPA is also, in this action, withdrawing proposed standards for
modified stationary combustion turbines. A detailed rationale for the
withdrawal of these proposed standards is provided in Section IX above.
The proposed standards for modified fossil fuel-fired EGUs that the
EPA is withdrawing in this action were published in the Federal
Register on June 18, 2014 (79 FR 34960).
[[Page 64648]]
XVI. 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, Incorporation by reference, 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: August 3, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, parts
60, 70, 71, and 98 of the Code of the Federal Regulations are 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.
0
2. Section 60.17 is amended by:
0
a. Redesignating paragraphs (d) through (t) as paragraphs (e) through
(u) and adding paragraph (d);
0
b. In newly redesignated paragraph (g), further redesignating paragraph
(g)(15) as paragraph (g)(17) and adding paragraphs (g)(15) and (16);
0
c. In newly redesignated paragraph (h), revising paragraphs (h)(37),
(42), (46), (138), (187), and (190); and
0
c. In newly redesignated paragraph (m), further redesignating paragraph
(m)(1) as paragraph (m)(2) and adding paragraph (m)(1).
The revisions and additions read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(d) The following material is available for purchase from the
American National Standards Institute (ANSI), 25 W. 43rd Street, 4th
Floor, New York, NY 10036, Telephone (212) 642-4980, and is also
available at the following Web site: http://www.ansi.org.
(1) ANSI No. C12.20-2010 American National Standard for Electricity
Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR
approved for Sec. 60.5535(d).
(2) [Reserved]
* * * * *
(g) * * *
(15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes,
(Issued December 31, 2014), IBR approved for Sec. 60.5580.
(16) ASME PTC 46-1996, Performance Test Code on Overall Plant
Performance, (Issued October 15, 1997), IBR approved for Sec. 60.5580.
* * * * *
(h) * * *
(37) ASTM D388-99 (Reapproved 2004) [epsiv]1 Standard
Classification of Coals by Rank, IBR approved for Sec. Sec. 60.41,
60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580.
* * * * *
(42) ASTM D396-98, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec. 60.41b, 60.41c, 60.111(b), 60.111a(b), and
60.5580.
* * * * *
(46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils,
IBR approved for Sec. Sec. 60.41b 60.41c, and 60.5580.
* * * * *
(138) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
* * * * *
(187) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
* * * * *
(190) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec. 60.41b, 60.41c,
and 60.5580.
* * * * *
(m) * * *
(1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition
(December 15, 2009), IBR approved for Sec. 60.5580.
* * * * *
0
3. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions for
Electric Generating Units
Applicability
Sec.
60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?
Emission Standards
60.5515 Which pollutants 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?
Monitoring and Compliance Determination Procedures
60.5535 How do I monitor and collect data to demonstrate compliance?
60.5540 How do I demonstrate compliance with my CO[ihel2] 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
EGU?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?
Table 1 of Subpart TTTT of Part 60--CO2 Emission
Standards for Affected Steam Generating Units and Integrated
Gasification Combined Cycle Facilities that Commenced Construction
after January 8, 2014 and Reconstruction or Modification after June
18, 2014
Table 2 of Subpart TTTT of Part 60--CO2 Emission
Standards for Affected Stationary Combustion Turbines that Commenced
Construction after January 8, 2014 and Reconstruction after June 18,
2014 (Net Energy Output-based Standards Applicable as Approved by
the Administrator)
Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of
Part 60 (General Provisions) to Subpart TTTT
Applicability
Sec. 60.5508 What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from a
steam generating unit,
[[Page 64649]]
IGCC, or a stationary combustion turbine that commences construction
after January 8, 2014 or commences modification or reconstruction after
June 18, 2014. An affected steam generating unit, IGCC, or stationary
combustion turbine shall, for the purposes of this subpart, be referred
to as an affected EGU.
Sec. 60.5509 Am I subject to this subpart?
(a) Except as provided for in paragraph (b) of this section, the
GHG standards included in this subpart apply to any steam generating
unit, IGCC, or stationary combustion turbine that commenced
construction after January 8, 2014 or commenced reconstruction after
June 18, 2014 that meets the relevant applicability conditions in
paragraphs (a)(1) and (2) of this section. The GHG standards included
in this subpart also apply to any steam generating unit or IGCC that
commenced modification after June 18, 2014 that meets the relevant
applicability conditions in paragraphs (a)(1) and (2) of this section.
(1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of
fossil fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater
than 25 MW of electricity to a utility power distribution system.
(b) You are not subject to the requirements of this subpart if your
affected EGU meets any of the conditions specified in paragraphs (b)(1)
through (10) of this section.
(1) Your EGU is a steam generating unit or IGCC that is currently
and always has been subject to a federally enforceable permit condition
limiting annual net-electric sales to no more than one-third of its
potential electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of combusting 50 percent or more non-fossil
fuel and is also subject to a federally enforceable permit condition
limiting the annual capacity factor for all fossil fuels combined of 10
percent (0.10) or less.
(3) Your EGU is a combined heat and power unit that is subject to a
federally enforceable permit condition limiting annual net-electric
sales to no more than either 219,000 MWh or the product of the design
efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating
unit(s), IGCC, or stationary combustion turbine(s) where the effective
generation capacity (determined based on a prorated output of the base
load rating of each steam generating unit, IGCC, or stationary
combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to
subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration
unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a
modification resulting in an hourly increase in CO2
emissions (mass per hour) of 10 percent or less (2 significant
figures). Modified units that are not subject to the requirements of
this subpart pursuant to this subsection continue to be existing units
under section 111 with respect to CO2 emissions standards.
(8) Your EGU is a stationary combustion turbine that is not capable
of combusting natural gas (e.g., not connected to a natural gas
pipeline).
(9) 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 January 8, 2014.
(10) 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 January 8, 2014.
Emission Standards
Sec. 60.5515 Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas standard in this subpart is in the form of a
limitation on emission of carbon dioxide.
(b) PSD and title V thresholds for greenhouse gases. (1) For the
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 Sec. 51.166(b)(48) of this chapter and in any SIP
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, Sec. 51.166(b)(48).
(2) For the 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 Sec. 52.21(b)(49) of this chapter.
(3) For the 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 the 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 emission standard must I meet?
(a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in Table 1 or 2 of this subpart, consistent with paragraphs (b), (c),
and (d) of this section, as applicable.
(b) Except as specified in paragraphs (c) and (d) of this section,
you must comply with the applicable gross energy output standard, and
your operating permit must include monitoring, recordkeeping, and
reporting methodologies based on the applicable gross energy output
standard. For the remainder of this subpart (for sources that do not
qualify under paragraphs (c) and (d) of this section), where the term
``gross or net energy output'' is used, the term that applies to you is
``gross energy output.''
(c) As an alternate to meeting the requirements in paragraph (b) of
this section, an owner or operator of a stationary combustion turbine
may petition the Administrator in writing to comply with the alternate
applicable net energy output standard. If the Administrator grants the
petition, beginning on the date the Administrator grants the petition,
the affected EGU must comply with the applicable net energy output-
based standard included in this subpart. Your operating permit must
include monitoring, recordkeeping, and reporting methodologies based on
the applicable net energy output standard. For the remainder of this
subpart, where the term ``gross or net energy output'' is used, the
term that applies to you is ``net energy output.'' Owners or
[[Page 64650]]
operators complying with the net output-based standard must petition
the Administrator to switch back to complying with the gross energy
output-based standard.
(d) Stationary combustion turbines subject to a heat input-based
standard in Table 2 of this subpart that are only permitted to burn one
or more uniform fuels, as described in paragraph (d)(1) of this
section, are only subject to the monitoring requirements in paragraph
(d)(1). All other stationary combustion turbines subject to a heat
input based standard in Table 2 are subject to the requirements in
paragraph (d)(2) of this section.
(1) Stationary combustion turbines that are only permitted to burn
fuels with a consistent chemical composition (i.e., uniform fuels) that
result in a consistent emission rate of 160 lb CO2/MMBtu or
less are not subject to any monitoring or reporting requirements under
this subpart. These fuels include, but are not limited to, natural gas,
methane, butane, butylene, ethane, ethylene, propane, naphtha,
propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and
biodiesel. Stationary combustion turbines qualifying under this
paragraph are only required to maintain purchase records for permitted
fuels.
(2) Stationary combustion turbines permitted to burn fuels that do
not have a consistent chemical composition or that do not have an
emission rate of 160 lb CO2/MMBtu or less (e.g., non-uniform
fuels such as residual oil and non-jet fuel kerosene) must follow the
monitoring, recordkeeping, and reporting requirements necessary to
complete the heat input-based calculations under this subpart.
General Compliance Requirements
Sec. 60.5525 What are my general requirements for complying with this
subpart?
Combustion turbines qualifying under Sec. 60.5520(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See Table 1 or 2 of this subpart
for the applicable CO2 emission standards.
(a) You must be in compliance with the emission standards in this
subpart that apply to your affected EGU at all times. However, you must
determine compliance with the emission standards only at the end of the
applicable operating month, as provided in paragraph (a)(1) of this
section.
(1) For each affected EGU 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 EGU at the end of the initial and each
subsequent 12-operating-month period.
(2) Consistent with Sec. 60.5520(d)(2), if your affected
stationary combustion turbine is subject to an input-based
CO2 emissions standard, you must determine the total heat
input in million Btus (MMBtu) from natural gas (HTIPng) and
the total heat input from all other fuels combined (HTIPo)
using one of the methods under Sec. 60.5535(d)(2). You must then use
the following equation to determine the applicable emissions standard
during the compliance period:
[GRAPHIC] [TIFF OMITTED] TR23OC15.002
Where:
CO2 emission standard = the emission standard during the
compliance period in units of lb/MMBtu.
HTIPng = the heat input in MMBtu from natural gas.
HTIPo = the heat input in MMBtu from all fuels other than
natural gas.
120 = allowable emission rate in lb of CO2/MMBtu for heat
input derived from natural gas.
160 = allowable emission rate in lb of CO2/MMBtu for heat
input derived from all fuels other than natural gas.
(b) At all times you must operate and maintain each affected EGU,
including associated equipment and monitors, 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 records, review of
reports required by this subpart, and inspection of the EGU.
(c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in Table 1 or 2 of this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
(1) For an affected EGU that commences commercial operation (as
defined in Sec. 72.2 of this chapter) on or after October 23, 2015,
the first month of the initial compliance period shall be the first
operating month (as defined in Sec. 60.5580) after the calendar month
in which emissions reporting is required to begin under:
(i) Section 63.5555(c)(3)(i), for units subject to the Acid Rain
Program; or
(ii) Section 63.5555(c)(3)(ii)(A), for units that are not in the
Acid Rain Program.
(2) For an affected EGU that has commenced COMMERCIAL operation (as
defined in Sec. 72.2 of this chapter) prior to October 23, 2015:
(i) If the date on which emissions reporting is required to begin
under Sec. 75.64(a) of this chapter has passed prior to October 23,
2015, emissions reporting shall begin according to Sec.
63.5555(c)(3)(i) (for Acid Rain program units), or according to Sec.
63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain
Program). The first month of the initial compliance period shall be the
first operating month (as defined in Sec. 60.5580) after the calendar
month in which the rule becomes effective; or
(ii) If the date on which emissions reporting is required to begin
under Sec. 75.64(a) of this chapter occurs on or after October 23,
2015, then the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec. 63.5555(c)(3)(ii)(A).
(3) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec. 63.5555(c)(3)(iii).
[[Page 64651]]
Monitoring and Compliance Determination Procedures
Sec. 60.5535 How do I monitor and collect data to demonstrate
compliance?
(a) Combustion turbines qualifying under Sec. 60.5520(d)(1) are
not subject to any requirements in this section other than the
requirement to maintain fuel purchase records for permitted fuel(s). If
your combustion turbine uses non-uniform fuels as specified under Sec.
60.5520(d)(2), you must monitor heat input in accordance with paragraph
(c)(1) of this section, and you must monitor CO2 emissions
in accordance with either paragraph (b), (c)(2), or (c)(5) of this
section. For all other affected sources, you must prepare a monitoring
plan to quantify the hourly CO2 mass emission rate (tons/h),
in accordance with the applicable provisions in Sec. 75.53(g) and (h)
of this chapter. The electronic portion of the monitoring plan must be
submitted using the ECMPS Client Tool and must be in place prior to
reporting emissions data and/or the results of monitoring system
certification tests under this subpart. The monitoring plan must be
updated as necessary. Monitoring plan submittals must be made by the
Designated Representative (DR), the Alternate DR, or a delegated agent
of the DR (see Sec. 60.5555(c)).
(b) You must determine the hourly CO2 mass emissions in
kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1)
through (5) of this section, or, if applicable, as provided in
paragraph (c) of this section.
(1) For an affected coal-fired EGU or for an IGCC unit you must,
and for all other affected EGUs you may, install, certify, operate,
maintain, and calibrate a CO2 continuous emission monitoring
system (CEMS) to directly measure and record hourly average
CO2 concentrations in the affected EGU exhaust gases emitted
to the atmosphere, and a flow monitoring system to measure hourly
average stack gas flow rates, according to Sec. 75.10(a)(3)(i) of this
chapter. As an alternative to direct measurement of CO2
concentration, provided that your EGU does not use carbon separation
(e.g., carbon capture and storage), you may use data from a certified
oxygen (O2) monitor to calculate hourly average
CO2 concentrations, in accordance with Sec.
75.10(a)(3)(iii) 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. Alternatively, you may
either use an appropriate fuel-specific default moisture value from
Sec. 75.11(b) or submit a petition to the Administrator under Sec.
75.66 of this chapter for a site-specific default moisture value.
(2) For each continuous 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 A and B to part 75 of this chapter.
(3) You must use only unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions rate from the
affected EGU; 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.
(4) You must select an appropriate reference method to setup
(characterize) the flow monitor and to perform the on-going RATAs, in
accordance with part 75 of this chapter. If you use a Type-S pitot tube
or a pitot tube assembly for the flow RATAs, you must calibrate the
pitot tube or pitot tube assembly; you may not use the 0.84 default
Type-S pitot tube coefficient specified in Method 2.
(5) Calculate the hourly CO2 mass emissions (kg) as
described in paragraphs (b)(5)(i) through (iv) of this section. Perform
this calculation only for ``valid operating hours'', as defined in
Sec. 60.5540(a)(1).
(i) Begin with the hourly CO2 mass emission rate (tons/
h), obtained either from Equation F-11 in Appendix F to part 75 of this
chapter (if CO2 concentration is measured on a wet basis),
or by following the procedure in section 4.2 of appendix F to part 75
of this chapter (if CO2 concentration is measured on a dry
basis).
(ii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in Sec. 72.2
of this chapter), to convert it to tons of CO2.
(iii) Finally, multiply the result from paragraph (b)(5)(ii) of
this section by 909.1 to convert it from tons of CO2 to kg.
Round off to the nearest kg.
(iv) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec. 75.57(e) of this chapter and must
be reported electronically under Sec. 75.64(a)(6) of this chapter. You
must use these data to calculate the hourly CO2 mass
emissions.
(c) If your affected EGU 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
according to paragraphs (c)(1) through (4) of this section. If you use
non-uniform fuels as specified in Sec. 60.5520(d)(2), you may
determine CO2 mass emissions during the compliance period
according to paragraph (c)(5) of this section.
(1) If you are subject to an output-based standard and you do not
install CEMS in accordance with paragraph (b) of this section, you must
implement the applicable procedures in appendix D to part 75 of this
chapter to determine hourly EGU 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) For each measured hourly heat input rate, use Equation G-4 in
appendix G to part 75 of this chapter to calculate the hourly
CO2 mass emission rate (tons/h). 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.
(3) For each ``valid operating hour'' (as defined in Sec.
60.5540(a)(1), multiply the hourly tons/h CO2 mass emission
rate from paragraph (c)(2) of this section by the EGU or stack
operating time in hours (as defined in Sec. 72.2 of this chapter), to
convert it to tons of CO2. Then, multiply the result by
909.1 to convert from tons of CO2 to kg. Round off to the
nearest two significant figures.
(4) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec. 75.57(e) of this chapter and must
be reported electronically under Sec. 75.64(a)(6) of this chapter. You
must use these data to calculate the hourly CO2 mass
emissions.
(5) If you operate a combustion turbine firing non-uniform fuels,
as an alternative to following paragraphs (c)(1) through (4) of this
section, you may determine CO2 emissions during the
compliance period using one of the following methods:
(i) Units firing fuel gas may determine the heat input during the
compliance period following the procedure under Sec. 60.107a(d) and
convert this heat input to CO2 emissions using Equation G-4
in appendix G to part 75 of this chapter.
(ii) You may use the procedure for determining CO2
emissions during the compliance period based on the use of the Tier 3
methodology under Sec. 98.33(a)(3) of this chapter.
(d) Consistent with Sec. 60.5520, you must determine the basis of
the emissions standard that applies to your
[[Page 64652]]
affected source in accordance with either paragraph (d)(1) or (2) of
this section, as applicable:
(1) If you operate a source subject to an emissions standard
established on an output basis (e.g., lb of CO2 per gross or
net MWh of energy output), you must install, calibrate, maintain, and
operate a sufficient number of watt meters to continuously measure and
record the hourly gross electric output or net electric output, as
applicable, from the affected EGU(s). These measurements must be
performed using 0.2 class electricity metering instrumentation and
calibration procedures as specified under ANSI Standards No. C12.20
(incorporated by reference, see Sec. 60.17). For a combined heat and
power (CHP) EGU, as defined in Sec. 60.5580, you must also install,
calibrate, maintain, and operate meters to continuously (i.e., hour-by-
hour) determine and record the total useful thermal output. For process
steam applications, you will need to install, calibrate, maintain, and
operate meters to continuously determine and record the hourly steam
flow rate, temperature, and pressure. Your plan shall ensure that you
install, calibrate, maintain, and operate meters to record each
component of the determination, hour-by-hour.
(2) If you operate a source subject to an emissions standard
established on a heat-input basis (e.g., lb CO2/MMBtu) and
your affected source uses non-uniform heating value fuels as delineated
under Sec. 60.5520(d), you must determine the total heat input for
each fuel fired during the compliance period in accordance with one of
the following procedures:
(i) Appendix D to part 75 of this chapter;
(ii) The procedures for monitoring heat input under Sec.
60.107a(d);
(iii) If you monitor CO2 emissions in accordance with
the Tier 3 methodology under Sec. 98.33(a)(3) of this chapter, you may
convert your CO2 emissions to heat input using the
appropriate emission factor in Table C-1 of part 98 of this chapter. If
your fuel is not listed in Table C-1, you must determine a fuel-
specific carbon-based F-factor (Fc) in accordance with
section 12.3.2 of EPA Method 19 of appendix A-7 to this part, and you
must convert your CO2 emissions to heat input using Equation
G-4 in appendix G to part 75 of this chapter.
(e) Consistent with Sec. 60.5520, if two or more affected EGUs
serve a common electric generator, you must apportion the combined
hourly gross or net energy output to the individual affected EGUs
according to the fraction of the total steam load contributed by each
EGU. Alternatively, if the EGUs are identical, you may apportion the
combined hourly gross or net electrical load to the individual EGUs
according to the fraction of the total heat input contributed by each
EGU.
(f) In accordance with Sec. Sec. 60.13(g) and 60.5520, if two or
more affected EGUs 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 in Table 1 or 2 of
this subpart, 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 or net energy output (electric,
thermal, and/or mechanical, as applicable) must be the sum of the
hourly loads for the individual affected EGUs 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
EGU sharing the stack is in compliance.
(g) In accordance with Sec. Sec. 60.13(g) and 60.5520 if the
exhaust gases from an affected EGU 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
Table 1 or 2 of this subpart by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the total gross or net energy output for the affected EGU.
Sec. 60.5540 How do I demonstrate compliance with my CO2
emissions standard and determine excess emissions?
(a) In accordance with Sec. 60.5520, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec. 60.5520(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in Table 1 or 2 of this
subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (7) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (i.e.,
either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass
emissions calculated under Sec. 60.5535(b) or (c), as applicable, and
either the generating load data from Sec. 60.5535(d)(1) for output-
based calculations or the heat input data from Sec. 60.5535(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
(1) Each compliance period shall include only ``valid operating
hours'' in the compliance period, i.e., operating hours for which:
(i) ``Valid data'' (as defined in Sec. 60.5580) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (kg) and, if a heat input-based standard applies, all the
parameters used to determine total heat input for the hour are also
obtained; and
(ii) The corresponding hourly gross or net energy output value is
also valid data (Note: For hours with no useful output, zero is
considered to be a valid value).
(2) You must exclude operating hours in which:
(i) The substitute data provisions of part 75 of this chapter are
applied for any of the parameters used to determine the hourly
CO2 mass emissions or, if a heat input-based standard
applies, for any parameters used to determine the hourly heat input; or
(ii) An exceedance of the full-scale range of a continuous emission
monitoring system occurs for any of the parameters used to determine
the hourly CO2 mass emissions or, if applicable, to
determine the hourly heat input; or
(iii) The total gross or net energy output (Pgross/net)
or, if applicable, the total heat input is unavailable.
(3) For each compliance period, at least 95 percent of the
operating hours in the compliance period must be valid operating hours,
as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO2 mass emissions by
summing the valid hourly CO2 mass emissions values from
Sec. 60.5535 for all of the valid operating hours in the compliance
period.
(5) Sources subject to output based standards. For each valid
operating hour of the compliance period that was used in paragraph
(a)(4) of this section to calculate the total CO2 mass
emissions, you must determine Pgross/net (the corresponding
hourly gross or net energy output in MWh) according to the
[[Page 64653]]
procedures in paragraphs (a)(3)(i) and (ii) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(1)(i) of this section, if there is no gross
or net electrical output, but there is mechanical or useful thermal
output, you must still determine the gross or net energy output for
that hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross
electrical, mechanical, or useful thermal output, you must use that
hour in the compliance determination. For hours or partial hours where
the gross electric output is equal to or less than the auxiliary loads,
net electric output shall be counted as zero for this calculation.
(i) Calculate Pgross/net for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of megawatt-hours (MWh). To convert each hourly gross or net
energy output (consistent with Sec. 60.5520) value reported under part
75 of this chapter to MWh, multiply by the corresponding EGU or stack
operating time.
[GRAPHIC] [TIFF OMITTED] TR23OC15.003
Where:
Pgross/net = In accordance with Sec. 60.5520, gross or
net energy output of your affected EGU for each valid operating hour
(as defined in Sec. 60.5540(a)(1)) 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 EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU 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, IGCC EGUs, or EGUs complying with a net energy
output based standard.
(Pe)A = Electric energy used for any auxiliary loads in
MWh. Not applicable for determining Pgross.
(Pt)PS = Useful thermal output of steam (measured
relative to SATP conditions, as applicable) that is used for
applications that do not generate additional electricity, produce
mechanical energy output, or enhance the performance of the affected
EGU. This is calculated using the equation specified in paragraph
(a)(5)(ii) of this section in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions, as applicable) from heat recovery that
is used for applications other than steam generation or performance
enhancement of the affected EGU in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions, as applicable) from any integrated equipment is used for
applications that do not generate additional steam, electricity,
produce mechanical energy output, or enhance the performance of the
affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total gross or net energy output consists
of electric or direct mechanical output and 20.0 percent of the
total gross or net energy output consists of useful thermal output
on a 12-operating-month rolling average basis, or 1.0 for all other
affected EGUs.
(ii) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
[GRAPHIC] [TIFF OMITTED] TR23OC15.004
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 SATP conditions or the energy in the condensate return
line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.
(6) Calculation of annual basis for standard. Sources complying
with energy output-based standards must calculate the basis (i.e.,
denominator) of their actual annual emission rate in accordance with
paragraph (a)(6)(i) of this section. Sources complying with heat input
based standards must calculate the basis of their actual annual
emission rate in accordance with paragraph (a)(6)(ii) of this section.
(i) In accordance with Sec. 60.5520 if you are subject to an
output-based standard, you must calculate the total gross or net energy
output for the affected EGU's compliance period by summing the hourly
gross or net energy output values for the affected EGU that you
determined under paragraph (a)(5) of this section for all of the valid
operating hours in the applicable compliance period.
(ii) If you are subject to a heat input-based standard, you must
calculate the total heat input for each fuel fired during the
compliance period. The calculation of total heat input for each
individual fuel must include all valid operating hours and must also be
consistent with any fuel-specific procedures specified within your
selected monitoring option under Sec. 60.5535(d)(2).
(7) If you are subject to an output-based standard, you must
calculate the CO2 mass emissions rate for the affected
EGU(s) (kg/MWh) by dividing the total CO2 mass emissions
value calculated according to the procedures in paragraph (a)(4) of
this section by the total gross or net energy output value calculated
according to the procedures in paragraph (a)(6)(i) of this section.
Round off the result to two significant figures if the calculated value
is less than 1,000; round the result to three significant figures if
the calculated value is greater than 1,000. If you are subject to a
heat input-based standard, you must calculate the CO2 mass
emissions rate for the affected EGU(s) (lb/MMBtu) by dividing the total
CO2 mass emissions value calculated according to the
procedures in paragraph (a)(4) of this section by the total heat input
calculated according to the procedures in paragraph (a)(6)(ii) of this
section. Round off the result to two significant figures.
(b) In accordance with Sec. 60.5520, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined according to the procedures specified in paragraph (a)(1)
through (7) of this section and must be less than or equal to the
applicable CO2 emissions standard in Table 1 or 2 of this
part, or the emissions standard calculated in accordance with Sec.
60.5525(a)(2).
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 (3) and 60.19, as applicable to your affected
EGU(s) (see Table 3 of this subpart).
[[Page 64654]]
(b) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable, to your affected EGUs.
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 EGUs that are required by Sec. 60.5525 to conduct
initial and on-going compliance determinations on a 12-operating-month
rolling average basis, you must submit electronic quarterly reports as
follows. After you have accumulated the first 12-operating months for
the affected EGU, you must submit a report for the calendar quarter
that includes the twelfth 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 (twelfth) operating month in a 12-operating-month
compliance period falls within the calendar quarter. You must calculate
each average CO2 mass emissions rate for the compliance
period according to the procedures in Sec. 60.5540. You must report
the dates (month and year) of the first and twelfth 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 where your EGU
violated the applicable CO2 emission standard;
(iii) If one or more compliance periods end in the quarter and
there are no violations for the affected EGU, you must include a
statement indicating this in the report;
(iv) The percentage of valid operating hours in each 12-operating-
month compliance period described in paragraph (a)(1)(i) of this
section (i.e., the total number of valid operating hours (as defined in
Sec. 60.5540(a)(1)) in that period divided by the total number of
operating hours in that period, multiplied by 100 percent);
(v) Consistent with Sec. 60.5520, the CO2 emissions
standard (as identified in Table 1 or 2 of this part) with which your
affected EGU must comply; and
(vi) Consistent with Sec. 60.5520, an indication whether or not
the hourly gross or net energy output (Pgross/net) values
used in the compliance determinations are based solely upon gross
electrical load.
(3) In the final quarterly report of each calendar year, you must
include the following:
(i) Consistent with Sec. 60.5520, gross energy output or net
energy output sold to an electric grid, as applicable to the units of
your emission standard, over the four quarters of the calendar year;
and
(ii) The potential electric output of the EGU.
(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)(1) For affected EGUs under this subpart that are also subject
to the Acid Rain Program, you must meet all applicable reporting
requirements and submit reports as required under subpart G of part 75
of this chapter.
(2) For affected EGUs under this subpart that are not in the Acid
Rain Program, you must also meet the reporting requirements and submit
reports as required under subpart G of part 75 of this chapter, to the
extent that those requirements and reports provide applicable data for
the compliance demonstrations required under this subpart.
(3)(i) For all newly-constructed affected EGUs under this subpart
that are also subject to the Acid Rain Program, you must begin
submitting the quarterly electronic emissions reports described in
paragraph (c)(1) of this section in accordance with Sec. 75.64(a) of
this chapter, i.e., beginning with data recorded on and after the
earlier of:
(A) The date of provisional certification, as defined in Sec.
75.20(a)(3) of this chapter; or
(B) 180 days after the date on which the EGU commences commercial
operation (as defined in Sec. 72.2 of this chapter).
(ii) For newly-constructed affected EGUs under this subpart that
are not subject to the Acid Rain Program, you must begin submitting the
quarterly electronic reports described in paragraph (c)(2) of this
section, beginning with data recorded on and after:
(A) The date on which reporting is required to begin under Sec.
75.64(a) of this chapter, if that date occurs on or after October 23,
2015; or
(B) October 23, 2015, if the date on which reporting would
ordinarily be required to begin under Sec. 75.64(a) of this chapter
has passed prior to October 23, 2015.
(iii) For reconstructed or modified units, reporting of emissions
data shall begin at the date on which the EGU becomes an affected unit
under this subpart, provided that the ECMPS Client Tool is able to
receive and process net energy output data on that date. Otherwise,
emissions data reporting shall be on a gross energy output basis until
the date that the Client Tool is first able to receive and process net
energy output data.
(4) If any required monitoring system has not been provisionally
certified by the applicable date on which emissions data reporting is
required to begin under paragraph (c)(3) of this section, the maximum
(or in some cases, minimum) potential value for the parameter measured
by the monitoring system shall be reported until the required
certification testing is successfully completed, in accordance with
Sec. 75.4(j) of this chapter, Sec. 75.37(b) of this chapter, or
section 2.4 of appendix D to part 75 of this chapter (as applicable).
Operating hours in which CO2 mass emission rates are
calculated using maximum potential values are not ``valid operating
hours'' (as defined in Sec. 60.5540(a)(1)), and shall not be used in
the compliance determinations under Sec. 60.5540.
(d) For affected EGUs subject to the Acid Rain Program, the reports
required under paragraphs (a) and (c)(1) of this section shall be
submitted by:
(1) The person appointed as the Designated Representative (DR)
under Sec. 72.20 of this chapter; or
(2) The person appointed as the Alternate Designated Representative
(ADR) under Sec. 72.22 of this chapter; or
(3) A person (or persons) authorized by the DR or ADR under Sec.
72.26 of this chapter to make the required submissions.
(e) For affected EGUs that are not subject to the Acid Rain
Program, the owner or operator shall appoint a DR and (optionally) an
ADR to submit the reports required under paragraphs (a) and (c)(2) of
this section. The DR and ADR must register with the Clean Air Markets
Division (CAMD) Business System. The DR may delegate the authority to
make the required submissions to one or more persons.
(f) If your affected EGU captures CO2 to meet the
applicable emission limit, you must report in accordance with the
requirements of 40 CFR part 98, subpart PP and either:
[[Page 64655]]
(1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, if injection occurs on-site, or
(2) Transfer the captured CO2 to an EGU or facility that
reports in accordance with the requirements of 40 CFR part 98, subpart
RR, if injection occurs off-site.
(3) Transfer the captured CO2 to a facility that has
received an innovative technology waiver from EPA pursuant to paragraph
(g) of this section.
(g) Any person may request the Administrator to issue a waiver of
the requirement that captured CO2 from an affected EGU be
transferred to a facility reporting under 40 CFR part 98, subpart RR.
To receive a waiver, the applicant must demonstrate to the
Administrator that its technology will store captured CO2 as
effectively as geologic sequestration, and that the proposed technology
will not cause or contribute to an unreasonable risk to public health,
welfare, or safety. In making this determination, the Administrator
shall consider (among other factors) operating history of the
technology, whether the technology will increase emissions or other
releases of any pollutant other than CO2, and permanence of
the CO2 storage. The Administrator may test the system
itself, or require the applicant to perform any tests considered by the
Administrator to be necessary to show the technology's effectiveness,
safety, and ability to store captured CO2 without release.
The Administrator may grant conditional approval of a technology, with
the approval conditioned on monitoring and reporting of operations. The
Administrator may also withdraw approval of the waiver on evidence of
releases of CO2 or other pollutants. The Administrator will
provide notice to the public of any application under this provision
and provide public notice of any proposed action on a petition before
the Administrator takes final action.
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)(1) For affected EGUs subject to the Acid Rain Program, you must
follow the applicable recordkeeping requirements and maintain records
as required under subpart F of part 75 of this chapter.
(2) For affected EGUs that are not subject to the Acid Rain
Program, you must also follow the recordkeeping requirements and
maintain records as required under subpart F of part 75 of this
chapter, to the extent that those records provide applicable data for
the compliance determinations required under this subpart. Regardless
of the prior sentence, at a minimum, the following records must be
kept, as applicable to the types of continuous monitoring systems used
to demonstrate compliance under this subpart:
(i) Monitoring plan records under Sec. 75.53(g) and (h) of this
chapter;
(ii) Operating parameter records under Sec. 75.57(b)(1) through
(4) of this chapter;
(iii) The records under Sec. 75.57(c)(2) of this chapter, for
stack gas volumetric flow rate;
(iv) The records under Sec. 75.57(c)(3) of this chapter for
continuous moisture monitoring systems;
(v) The records under Sec. 75.57(e)(1) of this chapter, except for
paragraph (e)(1)(x), for CO2 concentration monitoring
systems or O2 monitors used to calculate CO2
concentration;
(vi) The records under Sec. 75.58(c)(1) of this chapter,
specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for
oil flow meters;
(vii) The records under Sec. 75.58(c)(4) of this chapter,
specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through
(xi), for gas flow meters;
(viii) The quality-assurance records under Sec. 75.59(a) of this
chapter, specifically paragraphs (a)(1) through (12) and (15), for
CEMS;
(ix) The quality-assurance records under Sec. 75.59(a) of this
chapter, specifically paragraphs (b)(1) through (4), for fuel flow
meters; and
(x) Records of data acquisition and handling system (DAHS)
verification under Sec. 75.59(e) of this chapter.
(c) You must keep records of the calculations you performed to
determine the hourly and total CO2 mass emissions (tons)
for:
(1) Each operating month (for all affected EGUs); and
(2) Each compliance period, including, each 12-operating-month
compliance period.
(d) Consistent with Sec. 60.5520, you must keep records of the
applicable data recorded and calculations performed that you used to
determine your affected EGU's gross or net energy 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 Table 1 or 2 of this subpart.
(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 3 years after the date of
conclusion of each compliance period.
(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. Records that are
accessible from a central location by a computer or other means that
instantly provide access at the site meet this requirement. You may
maintain the records off site 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 EGU?
Notwithstanding any other provision of this chapter, certain parts
of the general provisions in Sec. Sec. 60.1 through 60.19, listed in
Table 3 to this subpart, do not apply to your affected EGU.
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).
[[Page 64656]]
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).
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM International in ASTM D388-99
(Reapproved 2004) [egr]1 (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.
Combined cycle unit 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
(HRSG) to generate additional electricity.
Combined heat and power unit or CHP unit, (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
output from the same primary energy source.
Design efficiency means the rated overall net efficiency (e.g.,
electric plus useful thermal output) on a lower heating value basis at
the base load rating, at ISO conditions, and at the maximum useful
thermal output (e.g., CHP unit with condensing steam turbines would
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one of the
following methods: ASME PTC 22 Gas Turbines (incorporated by reference,
see Sec. 60.17), ASME PTC 46 Overall Plant Performance (incorporated
by reference, see Sec. 60.17) or ISO 2314 Gas turbines--acceptance
tests (incorporated by reference, see Sec. 60.17).
Distillate oil means fuel oils that comply with the specifications
for fuel oil numbers 1 and 2, as defined by ASTM International in ASTM
D396-98 (incorporated by reference, see Sec. 60.17); diesel fuel oil
numbers 1 and 2, as defined by ASTM International in ASTM D975-08a
(incorporated by reference, see Sec. 60.17); kerosene, as defined by
ASTM International in ASTM D3699 (incorporated by reference, see Sec.
60.17); biodiesel as defined by ASTM International in ASTM D6751
(incorporated by reference, see Sec. 60.17); or biodiesel blends as
defined by ASTM International in ASTM D7467 (incorporated by reference,
see Sec. 60.17).
Electric Generating units or EGU means any steam generating unit,
IGCC unit, or stationary combustion turbine that is subject to this
rule (i.e., meets the applicability criteria)
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, the gross electric
or direct mechanical output from both the EGU (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) plus 100 percent of the useful thermal output.
(2) For steam generating units, the gross electric or mechanical
output from the affected EGU(s) (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 100
percent of the useful thermal output;
(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 useful thermal output on a 12-operating-month rolling
average basis, the gross electric or mechanical output from the
affected EGU (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 IGCC facilities),
that difference divided by 0.95, plus 100 percent of the useful thermal
output.
Heat recovery steam generating unit (HRSG) means an EGU 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 means a
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 the affected EGU 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 EGU 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 EGU(s), generate electricity and/or
thermal energy, or to enhance the performance of the affected EGU.
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. 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 CO2 content or
heating value.
Net-electric sales means:
(1) The gross electric sales to the utility power distribution
system minus purchased power; 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 an annual basis, the gross
electric sales to the utility power
[[Page 64657]]
distribution system minus purchased power of the thermal host facility
or facilities.
(3) Electricity supplied to other facilities that produce
electricity to offset auxiliary loads are included when calculating
net-electric sales.
(4) Electric sales that that result from a system emergency are not
included when calculating net-electric sales.
Net-electric output means the amount of gross generation the
generator(s) produces (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected EGU
plus 100 percent of the useful thermal output; or
(2) For combined heat and power facilities where at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output and at least 20.0 percent of the total gross
or net energy output consists of useful thermal output on a 12-
operating-month rolling average basis, the net electric or mechanical
output from the affected EGU divided by 0.95, plus 100 percent of the
useful thermal output.
Operating month means a calendar month during which any fuel is
combusted in the affected EGU at any time.
Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate and residual oil.
Potential electric output means 33 percent or the base load rating
design efficiency at the maximum electric production rate (e.g., CHP
units with condensing steam turbines will operate at maximum electric
production), whichever is greater, multiplied by the base load rating
(expressed in MMBtu/h) of the EGU, 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 EGU with a 100 MW
(341 MMBtu/h) fossil fuel heat input capacity would have a 306,000 MWh
12-month potential electric output capacity).
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25 [deg]C, 77 [deg]F) and 100.0 kilopascals (14.504 psi,
0.987 atm) pressure. The enthalpy of water at SATP conditions is 50
Btu/lb.
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. A stationary
combustion turbine that burns any solid fuel directly 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 EGU(s) or
auxiliary equipment.
System emergency means 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 EGU to
operate to avert loss of load.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in Sec. 75.20 of this chapter and appendix
A to part 75 of this chapter must be met before quality-assured data
are reported under this subpart; for on-going quality assurance, the
daily, quarterly, and semiannual/annual test requirements in sections
2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met
and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of
appendix B to part 75 of this chapter apply. For fuel flow meters, the
initial certification requirements in section 2.1.5 of appendix D to
part 75 of this chapter must be met before quality-assured data are
reported under this subpart (except for qualifying commercial billing
meters under section 2.1.4.2 of appendix D to part 75), and for on-
going quality assurance, the provisions in section 2.1.6 of appendix D
to part 75 apply (except for qualifying commercial billing meters).
Violation means a specified averaging period over which the
CO2 emissions rate is higher than the applicable emissions
standard located in Table 1 or 2 of this subpart.
[[Page 64658]]
Table 1 of Subpart TTTT of Part 60--CO[ihel2] Emission Standards for
Affected Steam Generating Units and Integrated Gasification Combined
Cycle Facilities That Commenced Construction After January 8, 2014 and
Reconstruction or Modification After June 18, 2014
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU CO[ihel2] Emission standard
------------------------------------------------------------------------
Newly constructed steam generating unit 640 kg CO2/MWh of gross energy
or integrated gasification combined output (1,400 lb CO2/MWh).
cycle (IGCC).
Reconstructed steam generating unit or 910 kg of CO2 per MWh of gross
IGCC that has base load rating of energy output (2,000 lb CO2/
2,100 GJ/h (2,000 MMBtu/h) or less. MWh).
Reconstructed steam generating unit or 820 kg of CO2 per MWh of gross
IGCC that has a base load rating energy output (1,800 lb CO2/
greater than 2,100 GJ/h (2,000 MMBtu/ MWh).
h).
Modified steam generating unit or IGCC. A unit-specific emission limit
determined by the unit's best
historical annual CO2 emission
rate (from 2002 to the date of
the modification); the
emission limit will be no
lower than:
1. 1,800 lb CO2/MWh-gross
for units with a base load
rating greater than 2,000
MMBtu/h; or
2. 2,000 lb CO2/MWh-gross
for units with a base load
rating of 2,000 MMBtu/h or
less.
------------------------------------------------------------------------
Table 2 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Stationary Combustion Turbines That Commenced Construction After January
8, 2014 and Reconstruction After June 18, 2014 (Net Energy Output-Based
Standards Applicable as Approved by the Administrator)
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU CO2 Emission standard
------------------------------------------------------------------------
Newly constructed or reconstructed 450 kg of CO2 per MWh of gross
stationary combustion turbine that energy output (1,000 lb CO2/
supplies more than its design MWh); or
efficiency or 50 percent, whichever is 470 kilograms (kg) of CO2 per
less, times its potential electric megawatt-hour (MWh) of net
output as net-electric sales on both a energy output (1,030 lb/MWh).
12-operating month and a 3-year
rolling average basis and combusts
more than 90% natural gas on a heat
input basis on a 12-operating-month
rolling average basis.
Newly constructed or reconstructed 50 kg CO2 per gigajoule (GJ) of
stationary combustion turbine that heat input (120 lb CO2/MMBtu).
supplies its design efficiency or 50
percent, whichever is less, times its
potential electric output or less as
net-electric sales on either a 12-
operating month or a 3-year rolling
average basis and combusts more than
90% natural gas on a heat input basis
on a 12-operating-month rolling
average basis.
Newly constructed and reconstructed 50 kg CO2/GJ of heat input (120
stationary combustion turbine that lb/MMBtu) to 69 kg CO2/GJ of
combusts 90% or less natural gas on a heat input (160 lb/MMBtu) as
heat input basis on a 12-operating- determined by the procedures
month rolling average basis. in Sec. 60.5525.
------------------------------------------------------------------------
Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
General provisions
citation Subject of citation Applies to subpart TTTT Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1............... Applicability............ Yes............................
Sec. 60.2............... Definitions.............. Yes............................ Additional terms defined
in Sec. 60.5580.
Sec. 60.3............... Units and Abbreviations.. Yes............................
Sec. 60.4............... Address.................. Yes............................ Does not apply to
information reported
electronically through
ECMPS. Duplicate
submittals are not
required.
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
Recordkeeping. submit the
notifications in Sec.
60.7(a)(1) and (3) and
to keep records of
malfunctions in Sec.
60.7(b), if applicable.
Sec. 60.8............... Performance tests........ No.............................
Sec. 60.9............... Availability of Yes............................
Information.
Sec. 60.10.............. State authority.......... Yes............................
Sec. 60.11.............. Compliance with standards No.............................
and maintenance
requirements.
Sec. 60.12.............. Circumvention............ Yes............................
Sec. 60.13.............. Monitoring requirements.. No............................. All monitoring is done
according to part 75.
[[Page 64659]]
Sec. 60.14.............. Modification............. Yes (steam generating units and
IGCC facilities).
No (stationary combustion
turbines.
Sec. 60.15.............. Reconstruction........... Yes............................
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 and Yes............................ Does not apply to
reporting requirements. notifications under
Sec. 75.61 or to
information reported
through ECMPS.
----------------------------------------------------------------------------------------------------------------
PART 70--STATE OPERATING PERMIT PROGRAMS
0
4. The authority citation for part 70 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
5. In Sec. 70.2, the definition of ``Regulated pollutant (for
presumptive fee calculation)'' is amended by:
0
a. Revising the introductory text;
0
b. Removing ``or'' from the end of paragraph (2);
0
c. Removing the period at the end of paragraph (3) and adding ``; or''
in its place; and
0
d. Adding paragraph (4).
The revision and additions read as follows:
Sec. 70.2 Definitions.
* * * * *
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.
* * * * *
0
6. Section 70.9 is amended by revising paragraph (b)(2)(i), and 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: 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 permit modification or related permit 7
action.....................................................
GHG evaluation at permit renewal............................ 10
------------------------------------------------------------------------
* * * * *
PART 71--FEDERAL OPERATING PERMIT PROGRAMS
0
7. The authority citation for part 71 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
8. In Sec. 71.2, the definition of ``Regulated pollutant (for fee
calculation)'' is amended by:
0
a. Removing ``or'' from the end of paragraph (2);
0
b. Removing the period at the end of paragraph (3) and adding ``; or''
in its place; and
0
b. Adding paragraph (4).
The revisions and additions read as follows:
Sec. 71.2 Definitions.
* * * * *
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.
* * * * *
0
9. 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 addition 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
[[Page 64660]]
(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 $2,236
updated 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
10. The authority citation for part 98 is revised to read as follows:
Authority: 42 U.S.C. 7401-7671q.
0
11. 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 subpart D facility;
(2) Report each facility identification number associated with the
annual GHG reports for each subpart RR facility to which CO2
is transferred; and
(3) Report the annual quantity of CO2 in metric tons
that is transferred to each subpart RR facility.
0
12. 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 subpart RR
facility.
[FR Doc. 2015-22837 Filed 10-22-15; 8:45 am]
BILLING CODE 6560-50-P