[Federal Register Volume 79, Number 117 (Wednesday, June 18, 2014)]
[Proposed Rules]
[Pages 34960-34994]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-13725]
[[Page 34959]]
Vol. 79
Wednesday,
No. 117
June 18, 2014
Part III
Environmental Protection Agency
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40 CFR Part 60
Carbon Pollution Standards for Modified and Reconstructed Stationary
Sources: Electric Utility Generating Units; Proposed Rules
Federal Register / Vol. 79 , No. 117 / Wednesday, June 18, 2014 /
Proposed Rules
[[Page 34960]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2013-0603; FRL 9910-00-OAR]
RIN 2060-AR88
Carbon Pollution Standards for Modified and Reconstructed
Stationary Sources: Electric Utility Generating Units
AGENCY: Environmental Protection Agency.
ACTION: Proposed rule.
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SUMMARY: The Environmental Protection Agency (EPA) is proposing
standards of performance for emissions of greenhouse gases from
affected modified and reconstructed fossil fuel-fired electric utility
generating units. Specifically, the EPA is proposing standards to limit
emissions of carbon dioxide from affected modified and reconstructed
electric utility steam generating units and from natural gas-fired
stationary combustion turbines. This rule, as proposed, would continue
progress already underway to reduce carbon dioxide emissions from the
electric power sector in the United States.
DATES: Comments on the proposed standards. Comments on the proposed
standards must be received on or before October 16, 2014.
Comments on the information collection request. Under the Paperwork
Reduction Act (PRA), since the Office of Management and Budget (OMB) is
required to make a decision concerning the information collection
request between 30 and 60 days after June 18, 2014, a comment to the
OMB is best assured of having its full effect if the OMB receives it by
July 18, 2014.
Public Hearing. In a separate action in the Federal Register, the
EPA is proposing Clean Air Act (CAA) section 111(d) emission guidelines
for existing fossil fuel-fired electric utility generating units (EGUs)
and is announcing public hearings associated with that action. Because
of the interconnected nature of this proposed rulemaking with the
proposed Carbon Pollution Emission Guidelines for Existing Stationary
Sources: Electric Utility Generating Units, we will hold joint hearings
on both proposed rulemakings. Please consult the Federal Register
document proposing Emission Guidelines for Existing Sources for
information on public hearings for both actions. Additionally,
information for the joint public hearings will be posted on the
following Web sites: http://www2.epa.gov/carbon-pollution-standards and
http://www2.epa.gov/cleanpowerplan. If any dates, times or locations of
announced public hearings are changed for the proposed emission
guidelines, then the public hearing dates, times and locations for this
action will also change accordingly. If you would like to speak at the
public hearing(s), please register by following instructions provided
in the document for the emission guidelines proposed in the Federal
Register. Please note that written statements and supporting
information submitted during the comment period will be considered with
the same weight as oral comments and supporting information presented
at the public hearing(s).
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2013-0603, by one of the following methods:
At the Web site http://www.regulations.gov: Follow the instructions
for submitting comments.
Email: Send your comments by electronic mail (email) to [email protected], Attn: Docket ID No. EPA-HQ-OAR-2013-0603.
Facsimile: Fax your comments to (202) 566-9744, Attn: Docket ID No.
EPA-HQ-OAR-2013-0603.
Mail: Send your comments to the EPA Docket Center, U.S. EPA, Mail
Code 28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Attn:
Docket ID No. EPA-HQ-OAR-2013-0603. Comments on the information
collection provisions should be mailed to the Office of Information and
Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St. NW.,
Washington, DC 20503.
Hand Delivery or Courier: Deliver your comments to the EPA Docket
Center, William Jefferson Clinton Building West, Room 3334, 1301
Constitution Ave. NW., Washington, DC 20004, Attn: Docket ID No. EPA-
HQ-OAR-2013-0603. Such deliveries are accepted only during the Docket
Center's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding Federal holidays), and special arrangements
should be made for deliveries of boxed information.
Instructions: All submissions must include the agency name and
docket ID number (EPA-HQ-OAR-2013-0603). The EPA's policy is to include
all comments received without change, including any personal
information provided, in the public docket, available online at http://www.regulations.gov, unless the comment includes information claimed to
be confidential business information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through http://www.regulations.gov or email. Send or deliver information identified as
CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, U.S. EPA, Research Triangle Park, NC 27711, Attention Docket
ID No. EPA-HQ-OAR-2013-0603. Clearly mark the information you claim to
be CBI. For CBI information on a disk or CD-ROM that you mail to the
EPA, mark the outside of the disk or CD-ROM as CBI and then identify
electronically within the disk or CD-ROM the specific information you
claim as CBI. In addition to one complete version of the comment that
includes information claimed as CBI, you must submit a copy of the
comment that does not contain the information claimed as CBI for
inclusion in the public docket. Information so marked will not be
disclosed except in accordance with procedures set forth in 40 CFR part
2.
The EPA requests that you also submit a separate copy of your
comments to the contact person identified below (see FOR FURTHER
INFORMATION CONTACT). If the comment includes information you consider
to be CBI or otherwise protected, you should send a copy of the comment
that does not contain the information claimed as CBI or otherwise
protected.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means the EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties, and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption and be free of any
defects or viruses.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although
[[Page 34961]]
listed in the index, some information is not publicly available (e.g.,
CBI or other information whose disclosure is restricted by statute).
Certain other material, such as copyrighted material, will be publicly
available only in hard copy. Publicly available docket materials are
available either electronically at http://www.regulations.gov or in
hard copy at the EPA Docket Center, William Jefferson Clinton Building
West, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20004. The
Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding federal holidays. The telephone number for the Public
Reading Room is (202) 566-1744, and the telephone number for the Air
Docket is (202) 566-1742. Visit the EPA Docket Center homepage at
http://www.epa.gov/epahome/dockets.htm for additional information about
the EPA's public docket.
In addition to being available in the docket, an electronic copy of
this proposed rule will be available on the World Wide Web (WWW).
Following signature, a copy of this proposed rule will be posted at the
following address: http://www2.epa.gov/carbon-pollution-standards.
FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Energy
Strategies Group, Sector Policies and Programs Division (D243-01), U.S.
EPA, Research Triangle Park, NC 27711; telephone number (919)541-4003,
facsimile number (919)541-5450; email address:
[email protected] or Dr. Nick Hutson, Energy Strategies Group,
Sector Policies and Programs Division (D243-01), U.S. EPA, Research
Triangle Park, NC 27711; telephone number (919)541-2968, facsimile
number (919)541-5450; email address: [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:
AEO Annual Energy Outlook
APPA American Public Power Association
BSER Best System of Emission Reduction
CAA Clean Air Act
CAP Climate Action Plan
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CFB Circulating Fluidized Bed
CH4 Methane
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE/NETL Department of Energy/National Energy Technology Laboratory
EGU Electric Utility Generating Unit
EO Executive Order
EPA Environmental Protection Agency
FB Fluidized Bed
FR Federal Register
GHG Greenhouse Gas
HFC Hydrofluorocarbon
HRSG Heat Recovery Steam Generator
ICR Information Collection Request
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
lb CO2/MWh Pounds of CO2 per Megawatt-hour
lb CO2/MWh-net Pounds of CO2 per Megawatt-hour
on a net output basis
LCOE Levelized Cost of Electricity
MMBtu/h Million British Thermal Units per Hour
MPa Megapascal
MW Megawatt
MWe Megawatt Electrical
MWh Megawatt-hour
N2 Nitrogen Gas
N2O Nitrous Oxide
NOX Nitrogen Oxide
NAICS North American Industry Classification System
NGCC Natural Gas Combined Cycle
NGR Natural Gas Reburning
NRC National Research Council
NRECA National Rural Electric Cooperative Association
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act
OFA Overfire Air
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbons
PM2.5 Particular Matter less than 2.5 micrometer in
diameter
PRA Paperwork Reduction Act
psi Pounds per square inch
psig Pounds per square inch-guage
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
SBA Small Business Administration
SCC Social cost of carbon
SCPC Supercritical pulverized coal
SF6 Sulfur Hexafluoride
SO2 Sulfur dioxide
Tg Teragram (one trillion (10\12\) grams)
TSD Technical Support Document
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard
WWW Worldwide Web
Organization of This Document. The information presented in this
preamble is organized as follows:
I. General Information
A. Executive Summary
B. Overview
C. Does this action apply to me?
II. Background
A. Climate Change Impacts From GHG Emissions
B. GHG Emissions From Fossil Fuel-Fired EGUs
C. The Utility Power Sector
D. Statutory Background
E. Regulatory Background
F. Stakeholder Outreach
G. Modifications and Reconstructions
III. Proposed Requirements for Modified and Reconstructed Sources
A. Applicability Requirements
B. Emission Standards
C. Startup, Shutdown and Malfunction Requirements
D. Continuous Monitoring Requirements
E. Emissions Performance Testing Requirements
F. Continuous Compliance Requirements
G. Notification, Recordkeeping and Reporting Requirements
IV. Rationale for Reliance on Rational Basis To Regulate GHG From
Fossil Fuel-Fired EGUs
A. Rational Basis and Endangerment Finding
B. Source Categories
V. Rationale for Applicability Requirements
VI. Rationale for Emission Standards for Reconstructed Fossil Fuel-
Fired Utility Boilers and IGCC Units
A. Overview
B. Identification of Best System of Emissions Reduction
C. Determination of the Level of the Standard
D. Compliance Period
VII. Rationale for Emission Standards for Modified Fossil Fuel-Fired
Utility Boilers and IGCC Units
A. Introduction
B. Identification of the Best System of Emission Reduction
C. Determination of the Level of the Standard
D. Compliance Period
VIII. Rationale for Emission Standards for Reconstructed Natural
Gas-Fired Stationary Combustion Turbines
A. Identification of the Best System of Emission Reduction
B. Determination of the Standards of Performance
IX. Rationale for Emission Standards for Modified Natural Gas-Fired
Stationary Combustion Turbines
A. Identification of the Best System of Emission Reduction
B. Determination of the Standards of Performance
X. Impacts of the Proposed Action
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance costs?
D. How will this proposal contribute to climate change
protection?
E. What are the economic and employment impacts?
F. What are the benefits of the proposed standards?
XI. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review, and
Executive Order 13563, Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132, Federalism
[[Page 34962]]
F. Executive Order 13175, Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045, Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898, Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
XII. Statutory Authority
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
On June 25, 2013, in conjunction with the announcement of his
Climate Action Plan (CAP), President Obama issued a Presidential
Memorandum directing the EPA to issue a new 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.'' Consistent with the Presidential Memorandum, on September 20,
2013, the Administrator signed proposed carbon pollution standards for
newly constructed fossil fuel-fired power plants. The proposal was
published on January 8, 2014 (79 FR 1430; January 2014 proposal).
Specifically, under the authority of CAA section 111(b), the EPA
proposed new source performance standards (NSPS) to limit emissions of
carbon dioxide (CO2) from newly constructed fossil fuel-
fired electric utility steam generating units (utility boilers and
integrated gasification combined cycle (IGCC) units) and newly
constructed natural gas-fired stationary combustion turbines.
In this action, under the authority of CAA section 111(b), the EPA
is proposing 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. Specifically, the EPA is proposing
standards of performance for: (1) Modified fossil fuel-fired utility
boilers and IGCC units, (2) modified natural gas-fired stationary
combustion turbines, (3) reconstructed fossil fuel-fired utility
boilers and IGCC units, and (4) reconstructed natural gas-fired
stationary combustion turbines. Consistent with the requirements of CAA
section 111(b), these proposed 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.
In a separate action, under CAA section 111(d), the EPA is
proposing emission guidelines for states to use in developing plans to
limit CO2 emissions from existing fossil fuel-fired EGUs.
States must then submit plans to the EPA under timing set by that
action.
2. Summary of the Major Provisions
The proposed standards for the affected modified and reconstructed
sources are summarized below in Table 1.
Table 1--Summary of BSER and Proposed Standards for Affected Sources
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Affected source BSER Standard
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Modified Utility Boilers and Most efficient Co-proposed
IGCC Units. generation at Alternative 1
source 1. Source would be
achievable required to meet a
through a unit-specific
combination of emission limit
best operating determined by the
practices and unit's best
equipment historical annual
upgrades. CO2 emission rate
(from 2002 to the
date of the
modification) plus
an additional 2
percent emission
reduction; the
emission limit will
be no lower than:
a. 1,900 lb CO2/MWh-
net for sources with
heat input >2,000
MMBtu/h.
OR
b. 2,100 lb CO2/MWh-
net for sources with
heat input <=2,000
MMBtu/h.
Modified Utility Boilers and Most efficient Co-proposed
IGCC Units. generation at Alternative 2
source Source would be
achievable required to meet a
through a unit-specific
combination of emission limit
best operating dependent upon when
practices and the modification
equipment occurs.
upgrades.
1. Sources that
modify prior to
becoming subject to
a CAA 111(d) plan
would be required to
meet a unit-specific
emission limit
determined by the
unit's best
historical annual
CO2 emission rate
(from 2002 to date
of the modification)
plus an additional 2
percent emission
reduction; the
emission limit will
be no lower than:
a. 1,900 lb CO2/MWh-
net for sources with
heat input >2,000
MMBtu/h.
OR
b. 2,100 lb CO2/MWh-
net for sources with
heat input <=2,000
MMBtu/h.
2. Sources that
modify after
becoming subject to
a CAA 111(d) plan
would be required to
meet a unit-specific
emission limit
determined by the
111(b) implementing
authority from the
results of an energy
efficiency
improvement audit.
Modified Natural Gas-Fired Efficient NGCC 1. Sources with heat
Stationary Combustion technology. input >850 MMBtu/h
Turbines. would be required to
meet an emission
limit of 1,000 lb
CO2/MWh-gross.
2. Sources with heat
input <=850 MMBtu/h
would be required to
meet an emission
limit of 1,100 lb
CO2/MWh-gross.
Reconstructed Utility Boilers Most efficient 1. Sources with heat
and IGCC Units. generating input >2,000 MMBtu/h
technology at would be required to
the affected meet an emission
source. limit of 1,900 lb
CO2/MWh-net.
2. Sources with heat
input <=2,000 MMBtu/
h would be required
to meet an emission
limit of 2,100 lb
CO2/MWh-net.
Reconstructed Natural Gas- Efficient NGCC 1. Sources with heat
Fired Stationary Combustion technology. input >850 MMBtu/h
Turbines. would be required to
meet an emission
limit of 1,000 lb
CO2/MWh-gross.
2. Sources with heat
input <=850 MMBtu/h
would be required to
meet an emission
limit of 1,100 lb
CO2/MWh-gross.
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[[Page 34963]]
For the reasons discussed in the ``Legal Memorandum'' \1\
supporting document in the docket for the rulemaking for CO2
emissions from existing EGUs under CAA section 111(d), all existing
sources that become modified or reconstructed sources and which are
subject to a CAA section 111(d) plan at the time of the modification or
reconstruction, will remain in the CAA section 111(d) plan and remain
subject to any applicable regulatory requirements in the plan, in
addition to being subject to regulatory requirements under CAA section
111(b).
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\1\ The ``Legal Memorandum'' supporting document is available in
the rulemaking docket for the proposed emission guidelines for
existing source power plants, Docket ID: EPA-HQ-OAR-2013-0602.''
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It should be noted that the EPA intends each standard of
performance proposed in this rulemaking to be severable from each other
standard of performance, such that if one or more of the standards of
performance were to be remanded or vacated in a court challenge, the
EPA intends for the other standards to remain in effect. The EPA also
intends each BSER determination or alternative determination, as
applicable, for modified utility boilers and IGCC units, and for
modified natural gas-fired stationary combustion turbines, to be
severable from each other BSER determination. In all of these cases,
the EPA believes that the standards of performance and associated best
systems of emission reduction operate independently of each other.\2\
The EPA also intends that the standards applicable to the units that
modify after the unit is subject to a 111(d) plan are severable and
that if those standards were over-turned, the standards applicable to
units that modify when they are not subject to a 111(d) plan would
apply to all modified sources, regardless of the timing of their
modification.
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\2\ See K Mart Corp. v. Cartier, Inc., 486 U.S. 281, 294 (1988)
(holding that a regulation was severable because the ``[t]he
severance and invalidation of [the subsection at issue would] not
impair the function of the statute as a whole, and there [was] no
indication that the regulation would not have been passed but for
its inclusion.'').
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The EPA is proposing that the form of the standards for modified
and reconstructed natural gas-fired stationary combustion turbines be
consistent with the standards for newly constructed natural gas-fired
stationary combustion turbines proposed on January 8, 2014 (79 FR
1430). In that proposal, the EPA proposed standards for turbines on a
gross output basis, but also took comment on standards on a net output
basis. The EPA is similarly proposing standards on a gross output
basis, while soliciting comment on net output based standards, in
today's proposal for modified and reconstructed natural gas-fired
stationary combustion turbines. To the extent that the EPA finalizes
modified and reconstructed standards for stationary combustion turbines
that are consistent with the standards for newly constructed stationary
combustion turbines, the EPA intends to take the same approach with
regards to the use of net or gross output in both final actions.
3. Costs and Benefits
As explained in the regulatory impact analysis (RIA) \3\ for this
proposed rule and further below, the EPA expects few units would
trigger either the modification or the reconstruction provisions that
we are proposing today. Because there have been a limited number of
units that have notified the EPA of NSPS modifications in the past, we
have conducted an illustrative analysis of the costs and benefits for a
representative modified unit. Based on the analysis, the EPA projects
that this proposed rule will result in potential CO2
emission changes, quantified benefits, and costs for a unit that is
subject to the modification provision. In this illustrative example,
based on a hypothetical 500 MW coal-fired unit, we estimate costs, net
of fuel savings, of $0.78 million to $4.5 million (2011$) and
CO2 reductions of 133,000 to 266,000 tons in 2025. The
climate benefits from reductions in CO2, combined with the
health co-benefits from reductions in sulfur dioxide (SO2),
nitrogen oxides (NOX), and fine particulate matter
(PM2.5), total $18 to $33 million (2011$) at a 3
percent discount rate for emission reductions in 2025 for the lowest
emission reduction scenario, and $35 to $65 million ($2011) at a 3
percent discount rate for emission reductions in 2025 for the highest
emission reduction scenario.\4\
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\3\ The RIA for this proposal is presented as Chapter 9 of the
RIA for the companion rulemaking for proposed Emission Guidelines
for Greenhouse Gas Emissions from Existing Stationary Sources:
Electric Utility Generating Units.
\4\ For purposes of this summary, we present climate benefits
from CO2 that were estimated using the model average
social cost of carbon (SCC) at a 3 percent discount rate. We
emphasize the importance and value of considering the full range of
SCC values, however, which include the model average at 2.5 and 5
percent, and the 95th percentile at 3 percent. Similarly, we
summarize the health co-benefits in this summary at a 3 percent
discount rate. We provide estimates based on additional discount
rates in the RIA.
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B. Overview
1. What authority is the EPA relying on to address power plant
CO2 emissions?
The U.S. Supreme Court ruled, in Massachusetts v. EPA, that
greenhouse gases (GHGs) \5\ meet the definition of ``air pollutant'' in
the CAA,\6\ and premised its decision in AEP v. Connecticut \7\ 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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\5\ Greenhouse gas pollution is the aggregate group of the
following gases: CO2, methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).
\6\ 549 U.S. 497, 520 (2007).
\7\ 131 S.Ct. 2527, 2537-38 (2011).
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Congress established requirements under section 111 of the 1970 CAA
to control air pollution from new stationary sources through NSPS.
Specifically, as explained in greater detail in section II below, CAA
section 111(b) authorizes the EPA to set ``standards of performance''
for new (including modified) stationary sources from listed source
categories to limit emissions of air pollutants to the environment, and
the EPA's implementing regulations provide that new sources include
reconstructed sources.\8\ Under CAA section 111(a)(1), the EPA must set
these standards at the level of emission reduction that reflects the
``best system of emission reduction . . . adequately demonstrated,''
taking into account technical feasibility, costs, and other factors.
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\8\ 40 CFR part 60 subpart A
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For more than four decades, the EPA has used its authority under
CAA section 111 to set cost-effective emission standards that ensure
newly constructed, reconstructed and modified stationary sources use
the best performing technologies to limit emissions of harmful air
pollutants. In this proposal, the EPA is following the same well-
established interpretation and application of the law under CAA section
111 to address GHG emissions from modified and reconstructed fossil
fuel-fired electric steam generating units and natural gas-fired
stationary combustion turbines.
2. What sources would be regulated by the proposed standards?
The proposed standards of performance would regulate GHG emissions
from modified and reconstructed (1) fossil fuel-fired electric steam
generating units--utility boilers and IGCC units--whose non-
[[Page 34964]]
GHG emissions are regulated under 40 CFR part 60, subpart Da, and (2)
natural gas-fired stationary combustion turbines, whose non-GHG
emissions are regulated under 40 CFR part 60, subpart KKKK. Natural
gas-fired stationary combustion turbines that supply less than one-
third of their potential electric output to the grid are not subject to
standards in today's proposal.
The CAA and the EPA's implementing regulations define a
``modification,'' for purposes of NSPS applicability, as a physical or
operational change that increases the source's maximum achievable
hourly rate of emissions, with certain exceptions.\9\
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\9\ CAA Section 111(a)(4); 40 CFR 60.2, 60.14.
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Under the EPA's 1975 framework regulations covering CAA section 111
standards of performance, ``reconstruction'' means 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.\10\
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\10\ 40 CFR 60.15(b).
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3. Why is the EPA issuing this proposed rule?
GHG pollution threatens the American public's health and welfare by
contributing to long-lasting changes in our climate system that can
have a range of negative effects on human health and the environment.
The impacts could include: Longer, more intense and more frequent heat
waves; more intense precipitation events and storm surges; less
precipitation and more prolonged droughts in the West and Southwest;
increased frequency and severity of short-term droughts in some other
U.S. regions; more fires and insect pest outbreaks in American forests,
especially in the West; and increased ground level ozone pollution,
otherwise known as smog, which has been linked to asthma and premature
death. Health risks from climate change are especially serious for
children, the elderly and those with heart and respiratory problems.
Unlike most other air pollutants, GHGs may persist in the
atmosphere from decades to millennia, depending on the specific GHG.
This special characteristic makes it crucial to act now to limit GHG
emissions from fossil fuel-fired power plants, specifically emissions
of CO2, since they are the nation's largest sources of
carbon pollution.
As previously noted, on June 25, 2013, President Obama issued a
Presidential Memorandum directing the EPA to address carbon pollution
from the power sector. As an initial step to limit carbon pollution
from power plants, on January 8, 2014, the EPA published a proposed
rule to limit GHG emissions from newly constructed fossil fuel-fired
electric steam generating units (utility boilers and IGCC units) and
newly constructed natural gas-fired stationary combustion turbines. The
EPA is now taking another step to limit carbon pollution in this
country by issuing a proposed rule to limit GHG emissions from modified
and reconstructed fossil fuel-fired electric steam generating units and
modified and reconstructed natural gas-fired stationary combustion
turbines.
Although we expect that the modification and reconstruction
standards of performance in this rulemaking will apply to few sources--
since there have been a limited number in the past--these standards
serve another important purpose that may affect a larger number of
sources: Providing an incentive, and the information needed, for
existing sources to structure their actions to achieve their operating
and business goals without triggering the modification or
reconstruction standards. For example, the modification standard
encourages existing sources that undertake physical or operational
changes to do so in a manner that does not increase their emission
rate.
4. What is the EPA's approach to setting standards for modified and
reconstructed EGUs under CAA section 111(b)?
CAA section 111(b) requires the EPA to establish standards of
performance that reflect the degree of emission limitation that is
achievable through the application of the ``best system of emission
reduction'' which (taking into account the cost of achieving such
reduction and any nonair quality health and environmental impact and
energy requirements) the EPA determines has been adequately
demonstrated. The text and legislative history of CAA section 111, as
well as relevant court decisions identify the factors for the EPA to
consider in making a BSER determination. They include, among others,
whether the system of emission reduction is technically feasible,
whether the costs of the system are reasonable, the amount of emissions
reductions that the system would generate, and whether the standard
would effectively promote further deployment or development of advanced
technologies. The case law addressing section 111 makes it clear that
the EPA has discretion in weighing these factors, and that as a result,
the EPA may weigh them differently for different types of sources or
air pollutants. See further discussion of this case law in section VI
below.
For each of the standards being proposed in today's action, the EPA
considered a number of alternatives and evaluated them against the
factors.
The BSER we are proposing for each category of affected sources and
the proposed standards of performance based on these BSER--as described
immediately below--are based on that evaluation, as discussed in
sections VI-IX below.
5. What are the BSER and the standard of performance for modified
fossil fuel-fired utility boilers and IGCC units?
The EPA proposes that the BSER for modified fossil fuel-fired
boilers and IGCC units is each unit's own best potential performance
based on a combination of best operating practices and equipment
upgrades. Specifically, the EPA is proposing unit-specific emission
standards consistent with this BSER determination and is co-proposing
two alternative standards for modified utility steam generating units.
In the first co-proposed alternative, modified utility boilers and IGCC
units would be subject to a single emission standard. Specifically,
under the first co-proposed alternative, a modified source would be
required to meet a unit-specific emission limit determined by the
affected source'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 has determined that this standard
can 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
specifies that modified facilities would not have to meet an emission
standard more stringent than the corresponding standard for
reconstructed EGUs. The EPA also solicits comment on whether, for units
that have become subject to a CAA section 111(d) plan, the period of
best historical performance should be the years from 2002 to the time
when the unit becomes subject to the CAA section 111(d) plan, rather
than to the time of the modification. This could address the concern
that sources that make improvements to their CO2 emission
[[Page 34965]]
rate as a result of a CAA section 111(d) plan would have lower baseline
emissions from which to calculate their required rate.
It is our interpretation that, as we discuss in detail in the Legal
Memorandum,\11\ an existing source would continue to be subject to CAA
section 111(d) requirements after it becomes a modified source, whether
the modification occurs before or after the promulgation of a CAA
section 111(d) plan. Therefore EPA is co-proposing that modified
sources would be required to meet unit-specific emission standards that
would depend on the timing of the modification. 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 source'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). 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 BSER and standards of
performance for modified fossil-fired electric utility steam generating
units are discussed further in section VII of this preamble.
---------------------------------------------------------------------------
\11\ ``Legal Memorandum for Proposed Carbon Pollution Guidelines
for Existing Power Plants'' Technical Support Document available in
rulemaking docket ID: EPA-HQ-OAR-2013-0602.
---------------------------------------------------------------------------
6. What is the BSER and standard of performance for modified natural
gas-fired stationary combustion turbines?
For modified natural gas-fired stationary combustion turbines, the
EPA is proposing standards of performance based on efficient Natural
Gas Combined Cycle (NGCC) technology as the BSER. The emission limits
proposed for these sources are 1,000 lb CO2/MWh-gross for
facilities with heat input ratings greater than 850 MMBtu/h, and 1,100
lb CO2/MWh-gross for facilities with heat input ratings of
850 MMBtu/h or less. For sources that are subject to a CAA section
111(d) plan, the EPA is also soliciting comment on whether the sources
should be allowed to elect, as an alternative to the otherwise
applicable numeric standard, to instead meet a unit-specific emission
standard that is determined by the CAA section 111(d) implementing
authority based on implementation of identified energy efficiency
improvement opportunities applicable to the source. This is discussed
further in section IX of this preamble.
7. What are BSER and the standard of performance for reconstructed
fossil fuel-fired utility boilers and IGCC units?
For reconstructed utility boilers and IGCC units, the EPA is
proposing a standard of performance with BSER based on the most
efficient generating technology for these types of units (i.e.,
reconstructing the boiler to use higher steam, temperature and
pressure, even if the boiler was not originally designed to do so
\12\). The proposed emission limit for these sources is 1,900 lb
CO2/MWh-net for sources with a heat input rating of greater
than 2,000 MMBtu/h or 2,100 lb CO2/MWh-net for sources with
a heat input rating of 2,000 MMBtu/h or less. The difference in the
proposed 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 could
also be met through other technology options such as natural gas co-
firing. This is discussed further in section VI below.
---------------------------------------------------------------------------
\12\ Steam with higher temperature and pressure has more thermal
energy which can be more efficiently converted to electrical energy.
---------------------------------------------------------------------------
As discussed in the Legal Memorandum,\13\ a reconstruction would
have no effect on the applicability of an approved CAA section 111(d)
plan; thus, a source that is subject to requirements in a CAA section
111(d) plan would remain subject to those requirements.
---------------------------------------------------------------------------
\13\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
---------------------------------------------------------------------------
8. What are BSER and the standard of performance for reconstructed
natural gas-fired stationary combustion turbines?
The EPA is proposing to find efficient NGCC technology to be the
BSER for reconstructed stationary combustion turbines. Therefore, the
EPA is proposing that larger units be required to meet a standard of
1,000 lb CO2/MWh-gross and that smaller units be required to
meet a standard of 1,100 lb CO2/MWh-gross. This is discussed
further in section VIII below.
A reconstruction would have no effect on the applicability of an
approved CAA section 111(d) plan on the existing source; thus, a source
that is subject to requirements in a CAA section 111(d) plan would
remain subject to those requirements, even after reconstruction.
9. How is EPA proposing to codify the requirements?
In the January 2014 proposal of carbon pollution standards for
newly constructed power plants (79 FR 1430), the EPA co-proposed two
options for codifying applicable requirements for covered sources.
Under the first option the EPA proposed to codify the standards of
performance for the respective sources within existing 40 CFR part 60
subparts so that applicable GHG standards for electric utility steam
generating units would be included in subpart Da and applicable GHG
standards for stationary combustion turbines would be included in
subpart KKKK. Under the second option, the EPA co-proposed to create a
new subpart TTTT and to include all GHG standards of performance for
covered sources in that newly created subpart.
In this action for modified and reconstructed sources, the EPA co-
proposes the same two options for codifying the applicable standards.
For consistency, the EPA intends--when it takes final action on this
proposal and on the January 2014 proposal for newly constructed
sources, respectively--to codify the standards in the same way for the
sources addressed under the two proposals.
10. What is the organization and approach for this proposal?
Section II of this preamble provides a brief summary of background
information on climate change impacts of GHG emissions, GHG emissions
from fossil-fuel fired EGUs, the utility power sector, the statutory
and regulatory background relevant to this rulemaking, and the EPA's
stakeholder outreach activities. Section II also contains additional
information on the regulatory and litigation history of CAA section
111.
The specific proposed requirements for modified and reconstructed
sources are described in detail in section III of this preamble. The
rationale for reliance on a rational basis to regulate GHG emissions
from fossil fuel-fired EGUs and the rationale for the applicability
requirements in today's proposal are presented in sections IV and V of
this preamble, respectively. Sections VI through IX of this preamble
describe the rationale for each of the proposed emission standards,
including an explanation of the determination of the BSER for
reconstructed fossil fuel-fired utility boilers and IGCC units and
modified fossil fuel-fired utility boilers and IGCC units, as well as
for
[[Page 34966]]
reconstructed natural gas-fired stationary combustion turbines and
modified natural gas-fired stationary combustion turbines. Impacts of
the proposed action are described in section X of this preamble. A
discussion of statutory and executive order reviews is provided in
section XI of this preamble, and the statutory authority for this
action is provided in section XII of this preamble.
It should be noted that this rulemaking overlaps in certain
respects with two other related rulemakings: The January 2014 proposed
rulemaking for CO2 emissions from newly constructed affected
EGUs, and the rulemaking for existing EGUs that the EPA is proposing at
the same time as the present rulemaking. In a number of places in this
preamble, the EPA cross-references parts of those two rulemakings.
However, each of these three rulemakings is independent of the other
two, and each has its own rulemaking docket. Accordingly, anyone who
wishes to comment on any aspect of this rulemaking, including anything
described by a cross-reference to one of the other two related
rulemakings, should make those comments on this rulemaking.
C. Does this action apply to me?
The entities potentially affected by the proposed standards are
shown in Table 2 below.
Table 2--Potentially Affected Entities a
----------------------------------------------------------------------------------------------------------------
Examples of potentially affected
Category NAICS code 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 North American Industry Classification (NAICS) categories for source categories that own and
operate electric power generating units (including boilers and stationary combined cycle combustion turbines).
\b\ Federal, state or local government-owned and operated establishments are classified according to the
activity in which they are engaged.
This table is not intended to be exhaustive, but rather to provide
a guide for readers regarding entities likely to be affected by this
proposed action. To determine whether your facility, company, business,
or organization, would be regulated by this proposed action, you should
examine the applicability criteria in 40 CFR 60.1. If you have any
questions regarding the applicability of this action to a particular
entity, consult either the air permitting authority for the entity or
your EPA regional representative as listed in 40 CFR 60.4 (General
Provisions).
II. Background
In this section,\14\ we discuss climate change impacts from GHG
emissions, both on public health and public welfare, present
information about GHG emissions from fossil-fuel fired EGUs, describe
the utility power sector and summarize the statutory and regulatory
background relevant to this rulemaking. We close this section by
describing stakeholder outreach and a brief history of modifications
and reconstructions in the power sector.
---------------------------------------------------------------------------
\14\ This background section is intended to provide the same or
very similar background information as provided in the companion
proposals for new sources (79 FR 1430) and existing sources (the CAA
section 111(d) proposal in today's Federal Register). Any minor
differences in phrasing between this proposal and the companion
proposals are not intended to state a substantive difference.
---------------------------------------------------------------------------
A. Climate Change Impacts From GHG Emissions
In 2009, the EPA Administrator issued the document known as the
Endangerment Finding under CAA section 202(a)(1).\15\ In the
Endangerment Finding, which focused on public health and public welfare
impacts within the United States, the Administrator found that elevated
concentrations of GHGs in the atmosphere may reasonably be anticipated
to endanger public health and welfare of current and future
generations. We summarize these adverse effects on public health and
welfare briefly here.\16\
---------------------------------------------------------------------------
\15\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66496 (December 15, 2009) (``Endangerment Finding'').
\16\ The January 8, 2014, preamble to the proposed GHG standards
for new EGUs (79 FR 1430) and the RIA supporting that proposal
include a more detailed summary of the public health and welfare
impacts detailed in the 2009 Endangerment Finding, as well as a
discussion of the science supporting the EPA's conclusions regarding
the question of whether GHG endanger public health and welfare
including: (1) The process by which the Administrator reached the
Endangerment Finding in 2009; (2) the EPA's response in 2010 to ten
administrative petitions for reconsideration of the Endangerment
Finding (the Reconsideration Denial); and (3) the decision by the
United States Court of Appeals for the District of Columbia Circuit
in 2012 to uphold the Endangerment Finding and the Reconsideration
Denial.
---------------------------------------------------------------------------
1. Public Health Impacts Detailed in the 2009 Endangerment Finding \17\
---------------------------------------------------------------------------
\17\ ``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'').
---------------------------------------------------------------------------
Climate change caused by human emissions of GHGs threatens public
health 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., including in the largest
metropolitan areas with the worst ozone problems, and thereby increase
the risk of morbidity and mortality. Other public health threats also
stem from projected increases in intensity or frequency of extreme
weather associated with climate change, such as increased hurricane
intensity, increased frequency of intense storms, and heavy
precipitation. Increased coastal storms and storm surges due to rising
sea levels are expected to cause increased drownings and other health
impacts. Children, the elderly, and the poor are among the most
vulnerable to these climate-related health effects.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
\18\
---------------------------------------------------------------------------
\18\ ``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'').
---------------------------------------------------------------------------
Climate change caused by human emissions of GHGs also threatens
public welfare in multiple ways. 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
[[Page 34967]]
face increased risks from storm and flooding damage to property, as
well as adverse impacts from rising sea level, such as land loss due to
inundation, erosion, wetland submergence and habitat loss. Climate
change is expected to result in an increase in peak electricity demand,
and extreme weather from climate change threatens energy,
transportation, and water resource infrastructure. Climate change may
exacerbate ongoing environmental pressures in certain settlements,
particularly in Alaskan indigenous communities. Climate change also is
very likely to fundamentally rearrange U.S. ecosystems over the 21st
century. Though some benefits may balance adverse effects on
agriculture and forestry in the next few decades, the body of evidence
points towards increasing risks of net adverse impacts on U.S. food
production, agriculture and forest productivity as temperature
continues to rise. These impacts are global and may exacerbate problems
outside the U.S. that raise humanitarian, trade, and national security
issues for the U.S.
3. New Scientific Assessments
As outlined in Section VIII.A. of the 2009 Endangerment Finding,
the EPA's approach to providing the technical and scientific
information to inform the Administrator's judgment regarding the
question of whether GHGs endanger public health and welfare was to rely
primarily upon the recent, major assessments by the U.S. Global Change
Research Program (USGCRP), the Intergovernmental Panel on Climate
Change (IPCC), and the National Research Council (NRC) of the National
Academies. These assessments addressed the scientific issues that the
EPA was required to examine, were comprehensive in their coverage of
the GHG and climate change issues, and underwent rigorous and exacting
peer review by the expert community, as well as rigorous levels of U.S.
government review. Since the administrative record concerning the
Endangerment Finding closed following the EPA's 2010 Reconsideration
Denial, a number of such assessments have been released. These
assessments include the 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 ``Climate Change Impacts in the United States''
(Climate Change Impacts), 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 reviewed these new assessments and finds that the
improved understanding of the climate system they present strengthens
the case that GHGs endanger public health and welfare.
In addition, these assessments highlight the urgency of the
situation as the concentration of CO2 in the atmosphere
continues to rise. Absent a reduction in emissions, a recent NRC
assessment projected that concentrations by the end of the century
would increase to levels that the Earth has not experienced for
millions of years.\19\ 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.'' \20\
---------------------------------------------------------------------------
\19\ National Research Council, Understanding Earth's Deep Past,
p. 1.
\20\ Id., p.138.
---------------------------------------------------------------------------
What this means, as stated in another NRC assessment, is that:
Emissions of carbon dioxide from the burning of fossil fuels
have ushered in a new epoch where human activities will largely
determine the evolution of Earth's climate. Because carbon dioxide
in the atmosphere is long lived, it can effectively lock Earth and
future generations into a range of impacts, some of which could
become very severe. Therefore, emission reductions choices made
today matter in determining impacts experienced not just over the
next few decades, but in the coming centuries and millennia.\21\
---------------------------------------------------------------------------
\21\ National Research Council, Climate Stabilization Targets,
p. 3.
Moreover, due to the time-lags inherent in the Earth's climate, the
Climate Stabilization Targets assessment notes that the full warming
from any given concentration of CO2 reached will not be
realized for several centuries.
The recently released USGCRP ``National Climate Assessment'' \22\
emphasizes that climate change is already happening now and it is
happening in the United States. The assessment documents the increases
in some extreme weather and climate events in recent decades, the
damage and disruption to infrastructure and agriculture, and projects
continued increases in impacts across a wide range of peoples, sectors,
and ecosystems.
---------------------------------------------------------------------------
\22\ U.S. Global Change Research Program, Climate Change Impacts
in the United States: The Third National Climate Assessment, May
2014 Available at http://nca2014.globalchange.gov/.
---------------------------------------------------------------------------
These assessments underscore the urgency of reducing emissions now:
Today's emissions will otherwise lead to raised atmospheric
concentrations for thousands of years, and raised Earth system
temperatures for even longer. Emission reductions today will benefit
the public health and public welfare of current and future generations.
Finally, it should be noted that the concentration of
CO2 in the atmosphere continues to rise dramatically. 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 (ppm).\23\ The average concentration in 2013 was 396 ppm. And
the monthly concentration in April of 2014 was 401 ppm, the first time
a monthly average has exceeded 400 ppm since record keeping began at
Mauna Loa in 1958, and for at least the past 800,000 years according to
ice core records.\24\
---------------------------------------------------------------------------
\23\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
\24\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
---------------------------------------------------------------------------
B. GHG Emissions From Fossil Fuel-Fired EGUs
Fossil fuel-fired EGUs are by far the largest emitters of GHGs,
primarily in the form of CO2, among stationary sources in
the U.S., and among fossil fuel-fired units, coal-fired units are by
far the largest emitters. This section describes the amounts of those
emissions and places those amounts in the context of the national
inventory of GHGs.
The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \25\ (the U.S. GHG Inventory) to comply with
commitments under the United Nations Framework Convention on Climate
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sectors. It provides the information in Table 3
below, which presents total U.S.
[[Page 34968]]
anthropogenic emissions and sinks \26\ of GHGs, including
CO2 emissions, for the years 1990, 2005 and 2012.
---------------------------------------------------------------------------
\25\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2012'', Report EPA 430-R-14-003, United States Environmental
Protection Agency, April 15, 2014.
\26\ Sinks are a physical unit or process that stores GHGs, such
as forests or underground or deep sea reservoirs of carbon dioxide.
Table 3--U.S. GHG Emissions and Sinks by Sector
[Teragram carbon dioxide equivalent (Tg CO2 Eq.)] \27\
------------------------------------------------------------------------
Sector 1990 2005 2012
------------------------------------------------------------------------
Energy......................... 5,260.1 6,243.5 5,498.9
Industrial Processes........... 316.1 334.9 334.4
Solvent and Other Product Use.. 4.4 4.4 4.4
Agriculture.................... 473.9 512.2 526.3
Land Use, Land-Use Change and 13.7 25.5 37.8
Forestry......................
Waste.......................... 165.0 133.2 124.0
----------------------------------------
Total Emissions............ 6,233.2 7,253.8 6,525.6
Land Use, Land-Use Change and (831.3) (1,030.7) (979.3)
Forestry (Sinks)..............
----------------------------------------
Net Emissions (Sources and 5,402.1 6,223.1 5,546.3
Sinks)....................
------------------------------------------------------------------------
Total fossil energy-related CO2 emissions (including
both stationary and mobile sources) are the largest contributor to
total U.S. GHG emissions, representing 77.7 percent of total 2012 GHG
emissions.\28\ In 2012, fossil fuel combustion by the electric power
sector--entities that burn fossil fuel and whose primary business is
the generation of electricity--accounted for 38.7 percent of all
energy-related CO2 emissions.\29\ Table 4 below presents
total CO2 emissions from fossil fuel-fired EGUs, for years
1990, 2005 and 2012.
---------------------------------------------------------------------------
\27\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2012, Report EPA 430-R-14-003, United
States Environmental Protection Agency, April 15, 2014.
\28\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2012'', Report EPA 430-R-14-003, United
States Environmental Protection Agency, April 15, 2014.
\29\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States
Environmental Protection Agency, April 15, 2014.
Table 4--U.S. GHG Emissions From Generation of Electricity From
Combustion of Fossil Fuels (Tg CO2) \30\
------------------------------------------------------------------------
GHG Emissions 1990 2005 2012
------------------------------------------------------------------------
Total CO2 from fossil fuel 1,820.8 2,402.1 2,022.7
combustion EGUs...............
--from coal................ 1,547.6 1,983.8 1,511.2
--from natural gas......... 175.3 318.8 492.2
--from petroleum........... 97.5 99.2 18.8
------------------------------------------------------------------------
C. The Utility Power Sector
---------------------------------------------------------------------------
\30\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States
Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------
Electricity in the United States is generated by a range of
sources--from power plants that use fossil fuels like coal, oil, and
natural gas, to non-fossil sources, such as nuclear, solar, wind and
hydroelectric power. In 2013, over 67 percent of power in the U.S. was
generated from the combustion of coal, natural gas, and other fossil
fuels, over 40 percent from coal and over 26 percent from natural
gas.\31\ In recent years, though, the proportion of new renewable
generation coming on line has increased dramatically. For instance,
over 38 percent of new generating capacity (over 5 GW out of 13.5 GW)
built in 2013 used renewable power generation technologies.\32\
---------------------------------------------------------------------------
\31\ U.S. Energy Information Administration (EIA), ``Table 7.2b
Electricity Net Generation: Electric Power Sector Electric Power
Sector,'' data from April 2014 Monthly Energy Review, release date
April 25, 2014. Available at: http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&freq=m.
\32\ 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.
---------------------------------------------------------------------------
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 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). 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 syngas composed of
carbon monoxide and hydrogen, which can be combusted in a combined
cycle system to generate power.
D. Statutory Background
CAA section 111 authorizes the EPA to prescribe new source
performance standards (NSPS) applicable to certain new stationary
sources (including
[[Page 34969]]
modified and reconstructed sources).\33\ 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.\34\
---------------------------------------------------------------------------
\33\ CAA section 111(b)(1)(A).
\34\ See generally 40 CFR part 60, subparts D-MMMM.
---------------------------------------------------------------------------
Once the EPA has listed a source category, the EPA proposes and
then promulgates ``standards of performance'' for ``new sources'' in
the category.\35\ A ``new source'' is ``any stationary source, the
construction or modification of which is commenced after,'' in general,
the date of the proposal.\36\ 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.'' \37\ The
EPA, through regulations, has determined that certain types of changes
are exempt from consideration as a modification.\38\
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\35\ CAA section 111(b)(1)(B).
\36\ CAA section 111(a)(2).
\37\ CAA section 111(a)(4).
\38\ 40 CFR 60.2, 60.14(e).
---------------------------------------------------------------------------
The EPA's 1975 framework regulations also 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.\39\
---------------------------------------------------------------------------
\39\ 40 CFR 60.15.
---------------------------------------------------------------------------
CAA section 111(a)(1) defines a ``standard of performance'' as a
standard for emissions of air pollutants which reflects the degree of
emission limitation achievable through the application of the best
system of emission reduction which (taking into account the cost of
achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated. This definition makes
clear that the standard of performance must be based on ``the best
system of emission reduction . . . adequately demonstrated'' (BSER).
The standard that the EPA develops, based on the BSER, is commonly a
numeric emission limit, expressed as a performance level (e.g., a rate-
based standard). Generally, the EPA does not prescribe a particular
technological system that must be used to comply with a standard of
performance. Rather, sources generally may select any measure or
combination of measures that will achieve the emissions level of the
standard.\40\ In establishing standards of performance, the EPA has
significant discretion to create subcategories based on source type,
class or size.\41\
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\40\ CAA section 111(b)(5).
\41\ CAA section 111(b)(2).
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When the EPA establishes NSPS for new sources in a particular
source category, the EPA is also required, under CAA section 111(d)(1),
to establish requirements for existing sources in that source category
for any air pollutant that, in general, is not regulated under the CAA
section 109 requirements for the National Ambient Air Quality Standards
or regulated under the CAA section 112 requirements for hazardous air
pollutants. Unlike CAA section 111(b), which gives EPA direct authority
to set national standards, CAA section 111(d) requires the EPA to
promulgate emission guidelines directing states to develop and submit,
for EPA approval, state plans that include standards of performance for
the existing sources.
E. Regulatory Background
In 1971, the EPA initially included fossil fuel-fired (which
includes natural gas, petroleum and coal) EGUs that use steam-
generating boilers in a category that it listed under CAA section
111(b)(1)(A),\42\ and the EPA promulgated the first set of standards of
performance for sources in that category, which it codified in subpart
D.\43\ 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),\44\ and the EPA promulgated standards of performance for
that source category in 1979, which the EPA codified in subpart GG.\45\
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\42\ 36 FR 5931 (March 31, 1971)
\43\ ``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.
\44\ 42 FR 53657 (October 3, 1977).
\45\ ``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.\46\ 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.\47\ 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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\46\ 44 FR 33580 (June 11, 1979).
\47\ 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 no standards of performance for GHG emissions.\48\ Petitioners
sought judicial review of the rule by the DC Circuit, contending, among
other issues, that the rule was required to include standards of
performance for GHG emissions from EGUs.\49\ The January 8, 2014
preamble to the proposed CO2 standards for new EGUs \50\
includes a discussion of the GHG-related litigation of the 2006 Final
Rule as well as other GHG-associated litigation.
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\48\ ``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).
\49\ State of New York, et al. v. EPA, No. 06-1322.
\50\ 79 FR 1430.
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F. Stakeholder Outreach
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 and non-
governmental organizations.
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.
[[Page 34970]]
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 has conducted subsequent outreach sessions: The vast
majority of which occurred between September 2013 and November 2013.
The agency held 11 public listening sessions; one national listening
session in Washington, DC and 10 listening sessions in locations across
the country. In addition to the 11 public listening sessions, the EPA
has 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 provided and encouraged multiple
opportunities to engage with each one of the 50 states. The agency met
with electric utility associations and electricity grid operators.
Agency officials have engaged with labor unions and with leaders
representing large and small industries. Because of the focus of the
standard on the electricity sector, many of the EPA's meetings with
industry have been with utilities and industry representatives directly
related to the electricity sector. The agency has also met with energy
industries such as coal and natural gas interests. In addition, the
agency has met with companies that offer new technology to prevent or
reduce carbon pollution, including companies that represent renewable
energy and energy efficiency interests. The EPA has also met with
representatives of energy intensive industries, such as the iron and
steel and aluminum industries, to help understand the issues related to
large industrial purchasers of electricity. Agency officials engaged
with representatives of environmental justice organizations,
environmental groups, and religious organizations.
Although this stakeholder outreach was primarily framed around the
GHG emission guidelines for existing EGUs, the outreach encompassed
issues relevant to this proposed rulemaking for modified and
reconstructed EGUs. For example, existing EGUs would be subject to
standards for modified and reconstructed EGUs should they undertake
modification or reconstruction actions, and, thus it is important that
we understand previous state and stakeholder experience with reducing
CO2 emissions in the power sector.
A detailed discussion of this stakeholder outreach is included in
the preamble to the GHG emission guidelines for existing affected EGUs
being proposed in a separate action today.
G. Modifications and Reconstructions
1. Modifications
The EPA's current regulations \51\ define an NSPS ``modification''
as a physical or operational change that increases the source's maximum
achievable hourly rate of emissions, with certain exemptions.\52\
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\51\ The discussion of the EPA's regulations in this rulemaking
is for background purposes only. The EPA is not re-opening, and thus
is not soliciting comment on, any provision in its existing
regulations.
\52\ 40 CFR 60.2, 60.14.
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Based on current information, the EPA believes that projects may
involve equipment changes to improve efficiency that could have the
effect of increasing a source's maximum achievable hourly emission rate
(lb CO2/h), even while decreasing its actual output based
emission rate (lb CO2/MWh). However, based on current
information, the most likely projects that could increase the maximum
achievable hourly rate of CO2 emissions would involve the
installation of add-on control equipment required to meet CAA
requirements for criteria and hazardous air pollutants. These increases
in CO2 emissions would generally be small and would occur as
a chemical by-product of the operation of the control equipment. All of
these actions, however, would be exempted from the definition of
modification under the current NSPS regulations.\53\
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\53\ 40 CFR 60.14.
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There are, however, some actions that could potentially trigger the
modification provisions of CAA section 111(b). For example, in some
cases, generation from a fossil fuel-fired electric utility steam
generating unit is limited not by the size of the boiler, but by other
factors, such as the size of the steam turbine or limitations in the
particulate control equipment that, in turn, limit the amount of coal
that can be combusted. If the steam turbine or particulate control
device is upgraded, more coal can be combusted in the boiler,
increasing hourly emissions.
Our base of knowledge concerning the types of NSPS modifications
has depended largely on self-reporting by power plants and on the
enforcement actions brought against power plants. Over the lengthy
history of the NSPS program, the number of modifications that we are
aware of is limited.
2. Comments on the April 2012 Proposal for New Sources Related to
Modifications
In the April 13, 2012 proposed Standards of Performance for
Greenhouse Gas Emissions for New Stationary Sources: Electric Utility
Generating Units (77 FR 22392),\54\ the EPA did not propose standards
of performance for modified sources; however, it did specifically
request comment on the types of modifications that may be expected and
on the appropriate control measures that may be applied. The agency
received a number of comments addressing standards for modified and
reconstructed EGUs.\55\ The EPA subsequently withdrew that proposed
rulemaking.\56\ While many of those comments informed today's proposal,
the EPA is not responding to those comments in this rulemaking, and if
members of the public wish to express views on this rulemaking they
must do so in comments on this rulemaking.
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\54\ The proposal was subsequently withdrawn with the
publication of the January 8, 2014 proposal.
\55\ The comments are available in the rulemaking docket. Docket
ID: EPA-HQ-OAR-2011-0660.
\56\ 79 FR 1352.
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Many of those comments emphasized that a standard of performance
that is based on carbon capture and storage (CCS) (or partial CCS) is
not appropriate for modified EGUs. Some commenters suggested that a
well-designed CAA section 111(d) program could obviate the need to set
separate standards of performance for modified sources. Several
commenters disagreed with EPA's assertion that it lacked adequate
information to propose standards for modified sources (at that time),
stating that proposed standards should be based on energy efficiency
measures.
3. Reconstructions
The EPA's framework regulations, interpreting the definition of
``new source'' in CAA section 111(a)(2), provide that an existing
source, ``upon reconstruction,'' becomes subject to the standard of
performance for new sources.\57\ The regulations define reconstruction
as the replacement of components of an existing facility to such 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 set forth in
this part.
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\57\ 40 CFR 60.15(a).
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[[Page 34971]]
Thus, a reconstruction occurs if the existing source replaces
components to such an extent that the capital costs of the new
components exceed 50 percent of the capital costs of an entirely new
facility, even if the existing source does not increase its emissions.
In addition, the component replacement constitutes a reconstruction
only if it is technologically and economically feasible for the source
to meet the applicable standards. The purpose of the reconstruction
provision is to avoid creating any regulatory incentive to perpetuate
the operation of a facility, instead of replacing it at the end of its
useful life with a newly constructed affected facility.
The regulations require the owner or operator of an existing source
that proposes to replace components to an extent that exceeds the 50
percent level to notify the EPA and provide specified information. This
information must include: The name and address of the owner or
operator; the location of the existing facility; a brief description of
the existing facility and the components which are to be replaced; a
description of existing and proposed air pollution control equipment;
an estimate of the fixed capital cost of the replacements and of
constructing a comparable entirely new facility; the estimated life of
the existing facility after the replacements; and, a discussion of any
economic or technical limitations the facility may have in complying
with the applicable standards of performance after the proposed
replacements. The regulations require the EPA to determine, within a
specified time period, whether the proposed replacement constitutes a
reconstruction.\58\ The determination shall be based on: The fixed
capital cost in comparison to the cost to construct a comparable
entirely new facility; the estimated life of the facility after the
replacements compared to the life of a comparable entirely new
facility; the extent to which the components being replaced cause or
contribute to emissions from the facility; and any economic or
technical limitations on compliance with applicable standards of
performance which are inherent in the proposed replacements.
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\58\ 40 CFR 60.15(d)-(e).
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Historically, few EGUs have undertaken reconstructions. Because of
the relative prices of coal and natural gas, and the relative costs of
reconstructing an existing coal-fired EGU and constructing an entirely
new NGCC unit, the EPA expects that few existing coal-fired EGUs will
undertake projects that will qualify the unit to be a reconstructed
source during the analysis period of this rulemaking (i.e., through
2025). The EPA also does not expect existing NGCC units to undertake
reconstructions during the analysis period (i.e., through 2025) because
most of them are relatively young (over 80 percent of the NGCC fleet
came on-line after 2000).
While there are specific provisions in the EPA's implementing
regulations at 40 CFR 60.15 on what constitutes a reconstructed source
(as just described), there is not such guidance on when an existing
source replaces components to such a degree that it goes beyond a
reconstruction and becomes essentially a newly constructed source.
Historically there has been little need to distinguish between
reconstructed sources and newly constructed sources as the standards of
performance are typically the same for either. However, the standards
proposed in today's action are different--for reasons we explain
later--and, therefore, there is a need to clearly delineate between a
reconstructed source and a newly constructed source. For example, it is
clear that an entirely new greenfield facility would constitute a newly
constructed source. It is EPA's view that, a new unit that is built on
property contiguous with an existing source--but not in the same
footprint as the existing source--would also constitute a newly
constructed source. And, it is EPA's view that a unit that entirely, or
for all practical purposes, completely replaces an existing sources by
being constructed on the replaced source's existing footprint would
also constitute a newly constructed source. The EPA solicits comment on
the delineation between a reconstructed source, which would be subject
to standards proposed in today's action, and a newly constructed
source, which would be subject to standards proposed in the January
2014 proposal (79 FR 1430), for those situations where significant
equipment is being replaced (enough to exceed the reconstruction
threshold) but the entire unit is not being rebuilt.
In addition, the EPA requests comment on having an upper capital
cost threshold for reconstruction, such that facilities that exceed
that threshold would be subject to the standard of performance for
newly constructed sources. With respect to this concept, the EPA
requests comment on both: (1) The idea of having an upper threshold and
(2) the appropriate upper threshold. With respect to the appropriate
upper threshold, EPA specifically requests comment on an upper
threshold within the range of 75 to 100 percent of the cost of an
entirely new and comparable facility. Finally, the EPA requests comment
on whether this upper threshold should be coupled with a provision
comparable to 40 CFR 60.15(b)(2) and 60.15(f)(4), such that a facility
that exceeded the upper threshold would not be subject to the new
construction standard if it was technologically and economically
infeasible for that facility to meet the new construction standard.
4. Comments on the April 2012 Proposal for New Sources Related to
Reconstructions
In the April 13, 2012 proposed Standards of Performance for
Greenhouse Gas Emissions for New Stationary Sources: Electric Utility
Generating Units (77 FR 22392), the EPA did not propose standards of
performance for reconstructed sources; however, it did specifically
request comment on the types of reconstructions that may be expected
and on the appropriate control measures that may be applied. The agency
received a number of comments addressing standards for reconstructed
EGUs.\59\ As noted above, the agency subsequently withdrew that
proposal and is not responding to those comments in this rulemaking, so
that if members of the public wish to express views on this rulemaking
they must do so in comments on this rulemaking.
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\59\ The comments are available in the rulemaking docket. Docket
ID: EPA-HQ-OAR-2011-0660.
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Many of the comments on the April 13, 2012 proposal supported a
delay in proposing standards for reconstructed sources. Others did not
favor the delay and suggested, instead, that reconstructed sources be
subject to the same standard as newly constructed sources. One
commenter expressed concern that an existing source that elected to
retrofit with CCS technology (perhaps in reliance on enhanced oil
recovery (EOR) markets) might trigger the requirements for a
reconstruction due to the high cost of CCS technology. The commenter
suggested that the EPA exclude the cost of retrofitting CCS technology
in order to eliminate barriers to voluntary use of that technology.
Several commenters expressed concern that a reconstruction could be
essentially a new plant built on a few remaining parts of an old plant.
The commenters expressed concern that such reconstructed sources would
face a standard that is much less stringent than a newly constructed
greenfield source.
[[Page 34972]]
III. Proposed Requirements for Modified and Reconstructed Sources
A. Applicability Requirements
We generally refer to fossil fuel-fired electric 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 sources meet both the definition of ``affected'' and
``covered'' EGUs subject to an emission standard as provided by this
proposed rule, and the criteria for being considered ``modified'' and
``reconstructed'' sources as defined under the provisions of CAA
section 111 and the EPA's regulations.
The EPA is proposing generally similar applicability requirements,
for purposes of this rule, that the EPA proposed in the January 2014
proposal.\60\ \61\ This section describes those requirements.
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\60\ See 79 FR 1445 and 1446. Note that the statements in the
January 2014 Proposal that ``existing sources undertaking
modifications or reconstructions; or certain projects under
development, including the proposed Wolverine EGU project in Rogers
City, Michigan (and, perhaps, up to two others)'' are not subject to
that rulemaking, 79 FR 1446, are not relevant for purposes of the
present rulemaking concerning modifications and reconstructions.
\61\ In the January 2014 proposal, the EPA solicited comment on
whether certain applicability requirements were appropriate in light
of the fact that they assumed that the source had an operating
history. In this rulemaking, the affected sources that would be
undertaking modifications or reconstructions do have an operating
history. As a result, to the extent the solicitation of comment in
the January 2014 just described may be read to identify concerns
about those applicability requirements, those concerns do not apply
to this rulemaking.
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To be considered an EGU under subpart Da, the boiler or IGCC must
be: (1) Capable of combusting more than 250 MMBtu/h heat input of
fossil fuel,\62\ (2) constructed for the purpose of supplying more than
one-third of its potential net-electric output capacity to any utility
power distribution system for sale \63\ (that is, to the grid), and (3)
constructed for the purpose of supplying more than 25 MW net-electric
output to the grid.\64\ In the January 2014 proposal, we proposed to
revise the third criterion to read ``more than 219,000 MWh,'' as
opposed to ``25 MW,'' net-electric output to the grid. This proposed
change to 219,000 MWh net sales is consistent with the EPA Acid Rain
Program (ARP) definition, and we have concluded that it is functionally
equivalent to the 25 MW net sales language. The 25 MW sales value has
been interpreted to be the continuous sale of 25 MW of electricity on
an annual basis, which is equivalent to 219,000 MWh. In the January
2014 proposal, we proposed to include two additional applicability
criteria specific to applicability with the GHG standards: (1) That a
facility actually sells more than one-third of its potential electric
output and more than 219,000 MWh to the grid on an annual basis for
boilers and IGCC facilities and on a 3-year average for combustion
turbines, and (2) that the GHG standards are not applicable to
facilities that combust 10 percent or less fossil fuel on a 3-year
average. In this proposal, we are not proposing that any of these
additional applicability criteria apply for modified or reconstructed
boilers or IGCC facilities. Therefore, any modified or reconstructed
boiler or IGCC facility that meets the general applicability of subpart
Da would also be subject to the GHG requirements. For stationary
combustion turbines, we are proposing to maintain all of these
criteria, along with the additional criteria specific to stationary
combustion turbines, included in the January 2014 proposal: That only
stationary combustion turbines that combust over 90 percent on a 3-year
rolling average basis are subject to a numerical GHG standard.
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\62\ E.g., 40 CFR 60.40Da(a)(1).
\63\ 40 CFR 60.41Da (definition of (``Electric utility steam-
generating unit'').
\64\ Id.
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We are proposing and soliciting comment on an additional amendment,
not included in the January 2014 proposal, to clarify that net-electric
sales, for applicability purposes, includes electricity supplied to
other facilities that produce electricity to offset auxiliary loads.
Without this amendment, smaller EGUs that are co-located with larger
EGUs could claim that they do not meet the rule applicability criteria
because their generated power is used to offset the parasitic loads of
the larger facility. We are also soliciting comment if the 10 percent
fossil fuel use criteria should be based on 3 consecutive calendar
years or on a 3 year rolling average basis.
Consistent with the January 2014 proposal, we are proposing several
additional adjustments to the way applicability is currently determined
under subpart Da for purposes of modifications and reconstructions.
First, we are proposing that the definition of ``potential electric
output'' be revised to include ``or the design net electric output
efficiency'' as an alternative to the default one-third efficiency
value (i.e., the proposed definition is ``33 percent or the design net
electric output efficiency times the maximum design heat input capacity
of the steam generating unit, divided by 3,413 Btu/KWh, divided by
1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent
efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel
heat input capacity would have a 310,000 MWh 12 month potential
electrical output capacity)'' (emphasis added)). Next, we are proposing
to add ``of the thermal host facility or facilities'' to the definition
of ``net-electric output'' (i.e., the proposed definition would read
``. . . the gross electric sales to the utility power distribution
system minus purchased power of the thermal host facility or facilities
on a calendar year basis'' (emphasis added).
Finally, consistent with the January 2014 proposal, to avoid
circumvention of the intent of the emission standards (e.g., by having
auxiliary equipment provide steam to the EGU to increase the output of
the EGU and not including the CO2 emissions in determining
the emission rate) and to provide additional flexibility to the
regulated community through additional compliance options, we are
proposing to amend the definition of a steam generating unit to include
``plus any integrated equipment that provides electricity or useful
thermal output to either the affected facility or auxiliary equipment''
in place of the existing language ``plus any integrated combustion
turbines and fuel cells.'' The proposed definition would read, ``any
furnace, boiler, or other device used for combusting fuel for the
purpose of producing steam (nuclear steam generators are not included)
plus any integrated equipment that provides electricity or useful
thermal output to either the affected facility or auxiliary equipment''
(emphasis added). We are also proposing to add the additional language
to the definition of IGCC in subpart Da (or subpart TTTT) and
stationary combustion turbine in subpart KKKK (or subpart TTTT).
This action proposes to set standards only for emissions of
CO2. The pollutant we propose to regulate could also be
identified as a broader suite of GHGs. However, we are not proposing to
set standards for any other GHGs, such as methane (CH4) or
nitrous oxide (N2O), because they represent less than 1
percent of total estimated GHG emissions from fossil fuel-fired
electric power generating units. This is consistent with the approach
that was taken in the proposed standards for newly constructed EGUs (79
FR 1430).
We are also not proposing standards for certain types of sources.
These include modified and reconstructed boilers and IGCC units that
were constructed for the purpose of selling one-third or less of their
potential output and 219,000 MWh or less to the grid. These units are
not covered under
[[Page 34973]]
subpart Da for any other pollutants but are rather covered as
industrial boilers under subpart Db or stationary combustion turbines
under subpart KKKK. We are also not proposing standards for two types
of units that are currently covered under subpart KKKK for other
pollutants at this time. The first type of units is stationary
combustion turbines that were constructed for the purpose of selling or
are selling one-third or less of their potential output or 219,000 MWh
or less to the grid. These units only account for a small amount of the
CO2 emissions from fossil fuel-fired EGUs. The second type
of units is modified or reconstructed non-natural gas-fired stationary
combustion turbines.\65\ Under the proposed approach, applicability
with the NSPS for stationary combustion turbines could change on an
annual basis depending on electric sales and for facilities burning
fuels other than natural gas (e.g., burning backup oil).
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\65\ Oil-fired stationary combustion turbines, including both
simple and combined cycle units, are not subject to these proposed
standards. These units are typically used only in areas that do not
have reliable access to pipeline natural gas (for example, in non-
continental areas).
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B. Emission Standards
In this rulemaking, the EPA is proposing standards of performance
for CO2 emissions from modified and reconstructed EGUs
within two categories and several subcategories of affected fossil
fuel-fired EGUs.
The proposed standards of performance for the utility boiler and
IGCC category are in the form of net energy output-based CO2
emission limits expressed in units of mass of CO2 per unit
of net energy output (e.g., net electrical output plus 75 percent of
the useful thermal output), specifically, in lb CO2/MWh-net.
This emission limit would apply to affected sources upon the effective
date of the final action. In this document, we sometimes refer to ``net
energy output'' as ``net output.''
As explained earlier, the proposed standards of performance for
natural gas-fired stationary combustion turbines are in the form of a
gross output-based emission limit expressed in units of mass of
CO2 per unit of gross energy output, specifically, in lb
CO2/MWh-gross. We also solicit comment on whether we should
use a net output-based approach.
The proposed method to calculate compliance is the same as was
proposed in the January 2014 proposal. Compliance would be calculated
as the sum of the emissions for all operating hours divided by the sum
of the useful energy output over a rolling 12-operating-month period.
In the alternative, as in the January 2014 proposal, we solicit comment
on requiring calculation of compliance on an annual (calendar year)
period. See 79 FR 1477.
We are proposing additional amendments to the definition of useful
thermal output. The current definition excludes energy used to enhance
the performance of the affected facility from being considered as
useful thermal output. The intent of this restriction is to clarify
that thermal energy that is directly used by the affected facility to
create additional output (e.g., the economizer) is not counted as
useful thermal output. Without this restriction, the energy could be
doubled counted--once as useful thermal output and again as electric
output. This could also be interpreted to exclude thermal energy used
to reduce fuel moisture (e.g., coal drying) as being useful thermal
output because it enhances the performance of the affected facility.
However, coal-drying could be done at a separate offsite facility by an
industrial boiler prior to delivery at the power plant. In that
scenario, the CO2 emissions from the industrial boiler would
not be included when the coal-fired boiler determined compliance with
the proposed standards even though the overall emissions to the
atmosphere could be greater than for an integrated system where the
thermal energy for the drying is supplied by the power plant.
Therefore, we are proposing that thermal energy used for reducing fuel
moisture be counted as useful thermal output. This approach would avoid
potential disincentives for integrating coal drying at power plants. We
are also proposing that default useful thermal output be measured
relative to standard ambient temperature and pressure (25 [deg]C and
14.5 pounds per square inch (psi)) instead of International
Organization for Standardization (ISO) conditions (15 [deg]C and 14.7
psi). In other words, at standard ambient temperature and pressure
(SATP) conditions, the amount of useful thermal energy (commonly called
``enthalpy'') is considered to be zero. The rationale behind providing
a relative measurement of thermal output is so that measurements are
made relative to the energy content in the makeup water. We have
concluded that standard ambient conditions are more representative than
ISO conditions of the energy content in the makeup water. In addition,
we are proposing the combined heat and power (CHP) facilities with high
energy condensate return would measure the energy in the condensate
when determining the useful thermal output. In addition, we are
soliciting comment on providing credit for useful thermal output in the
range of two-thirds to 100 percent.
1. Emission Standards for Modified Utility Boilers and IGCC Units
The EPA is proposing that affected modified utility boilers and
IGCC units must meet a standard of performance based on the source's
best potential performance, achieved through a combination of best
operating practices and equipment upgrades, as the BSER. The EPA is co-
proposing two alternative standards of performance. In the first
alternative, modified sources would be required to meet a unit-specific
numeric emission standard that is 2 percent lower than the unit's best
demonstrated annual performance during the years from 2002 to the year
the modification occurs.
Based on analysis of existing data, the EPA has determined that
this standard can be met through a combination of best operating
practices and equipment upgrades. In an analysis to determine
opportunities for heat rate improvement in the U.S. coal-fired utility
power fleet, the EPA found that a total of 6 percent improvement, on
average, can be achieved through two types of measures: Best operating
practices that have the potential to improve heat rate, on average, by
4 percent, and equipment upgrades that have the potential to improve
heat rate, on average, by an additional 2 percent.\66\ The EPA also
proposes that the unit-specific emission rates that would apply to
affected modified utility boilers and IGCC units would be no more
stringent (i.e., no lower) than 1,900 lb CO2/MWh-net for
units with a heat input rating greater than 2,000 MMBtu/h, and no more
stringent (i.e., no lower) than 2,100 lb CO2/MWh-net for
units with a heat input rating of 2,000 MMBtu/h or less. These proposed
constraints on the stringency of unit-specific emission rate standards
are consistent with the emission rate standards proposed in today's
action for reconstructed utility boilers and IGCC units--based on the
EPA's review and analysis of the emissions from the best available
generating technology. The EPA is soliciting comment on whether the
most stringent standard for modified steam generating units should take
into account the current steam cycle of the
[[Page 34974]]
facility. For example, should large subcritical steam generating units
have a most stringent standard that is less stringent (i.e., greater
than) 1,900 lb CO2/MWh-net, which is based on the use of a
supercritical steam cycle.
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\66\ Additional detail can be found in the Technical Support
Document: ``GHG Abatement Measures'' (Chapter 2: Heat Rate
Improvement at Existing Coal-fired EGUs), available in rulemaking
docket ID: EPA-HQ-OAR-2013-0602.
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As we discuss in the Legal Memorandum \67\, existing sources that
are subject to requirements under an approved CAA section 111(d) plan
would remain subject to those requirements after undertaking a
modification or reconstruction. Therefore, we are co-proposing a second
alternative--that modified sources would be required to meet a unit-
specific numeric emission standard that would be dependent on the
timing of the modification relative to the adoption of a CAA section
111(d) plan that covers the source. Specifically, the EPA proposes 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-proposed alternative--that is, the modified source would be required
to meet a unit-specific emission limit determined by the affected
source's best demonstrated historical performance (in the years from
2002 to the time of the modification) with an additional 2 percent
emission reduction. 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(b) implementing
authority and would be based on the source's expected performance after
implementation of identified unit-specific energy efficiency
improvement opportunities. We seek comment on all aspects of these co-
proposals, including whether the CAA section 111(b) implementing
authority would determine the unit-specific emission limit, even when
the implementing authority is a state, as opposed to the EPA.
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\67\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
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In addition, we solicit comment on alternative ways to determine
the best potential performance at affected modified utility boilers and
IGCC units. Specifically, we are requesting comment on whether the
unit-specific numerical emission standard should be based on the single
best annual emission rate (for the years 2002 to the year when the
modification occurs) or the best three consecutive year average
emission rate. We also solicit comment on whether there are
circumstances where it would not be appropriate to require that the
best historical emission rate be made 2 percent more stringent, or
where some other increment of additional stringency should be required.
The EPA also seeks comment on including an additional compliance
option for modified utility boilers and IGCC units. Specifically, we
seek comment on including uniform emission standards that are similar
to the standards proposed for reconstructed utility boilers and IGCC
units. Specifically, we seek comment on a standard of 1,900 lb
CO2/MWh-net for modified supercritical sources with a heat
input rating of greater than 2,000 MMBtu/h and a standard of 2,100 lb
CO2/MWh-net for all modified subcritical sources and for
modified supercritical sources with a heat input rating of 2,000 MMBtu/
h or less. The EPA further seeks comment on whether this option should
be available only to sources that modify before becoming subject to an
approved CAA section 111(d) plan or to all modified boilers and IGCC
units, regardless of the timing of the modification.
The EPA further solicits comment on whether, in the case of
modified utility boilers and IGCC units subject to a CAA section 111(d)
plan, there are any circumstances in which the emission limit should be
calculated by not including the 2 percent additional emission reduction
based on equipment upgrades. This may, for example, be appropriate in
cases where the state plan requires heat rate improvements which
improve on the source's historical performance, or where the source has
recently implemented aggressive measures to improve its operating
efficiency, and as a result, the additional 2 percent improvement may
be unnecessary or not reasonable.
The EPA also solicits comment on requiring modified utility boilers
and IGCC units subject to a CAA section 111(d) plan to take, as their
unit-specific emission rate, the lower of (1) the emission rate they
are subject to under the CAA section 111(d) plan, or (2) the emission
rate that is 2 percent less than the unit's best demonstrated annual
performance during the years from 2002 to the year the modification
occurs. Similarly, the EPA solicits comment on whether modified utility
boilers and IGCC units subject to a CAA section 111(d) plan could be
evaluated on a case-by-case basis to determine whether, as their CAA
section 111(b) standard, they should continue to be subject to the CAA
section 111(d) requirements to which they are subject. One method of
doing this might be through a delegation of the EPA's CAA section
111(b) authority over that source to the state administering the
applicable CAA section 111(d) plan. Under this option the modified
utility boilers and IGCC units would be considered to be only ``new
sources'' under 111(a)(2).
The EPA further seeks comment on whether the time period of the
unit's best demonstrated performance should be limited to the years
from 2002 to the time that the unit becomes subject to a CAA section
111(d) plan--rather than to the date that the modification occurs. The
EPA also seeks comment on whether the time period for best historic
performance should be from 2002 to the date of modification--unless the
source can provide evidence of significant heat rate improvements that
have already been implemented, in which case the time period would be
from the year of the first heat rate improvement to the modification.
The EPA also seeks comment on whether, and under what
circumstances, a modified utility boiler or IGCC unit that modifies
prior to becoming subject to a CAA section 111(d) plan should also be
allowed to meet a emission limit that is determined from the results of
an energy assessment or audit. The EPA also requests comment on whether
this approach should be limited to sources that may have voluntarily,
or for any other reason, implemented energy efficiency measures in the
time period between 2002 and the date of the modification and whether
those sources should be required to provide evidence of those energy
efficiency improvements.
The EPA also solicits comment on whether we should--as we have
proposed in this action--have different standards of performance for
modified utility boilers and IGCC units depending on whether a CAA
section 111(d) plan has been submitted (or a federal plan promulgated).
On the one hand, a CAA section 111(d) plan may not necessarily impose
obligations on a particular unit. On the other hand, such a plan may
impose significant obligations on a particular source, and if that
source modifies, it may not be as well positioned to implement
additional controls. A state, in developing a CAA section 111(d) plan,
may choose to confer with its sources to determine whether any expect
to modify, and, if any do, to take that into account in developing the
state plan.
2. Emission Standards for Modified Natural Gas-Fired Stationary
Combustion Turbines
For affected modified natural gas-fired stationary combustion
turbines, this action proposes standards of performance that are based
on efficient NGCC technology as the BSER. The emission limits proposed
for these
[[Page 34975]]
sources are 1,000 lb CO2/MWh-gross for facilities with heat
input ratings greater than 850 MMBtu/h, and 1,100 lb CO2/
MWh-gross for facilities with heat input ratings of 850 MMBtu/h or
less.\68\
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\68\ This subcategorization of stationary combustion turbines is
consistent with the subcategories used in the combustion turbine
(subpart KKKK) criteria pollutant NSPS. The size limit of 850 MMBtu/
h corresponds to approximately 100 MWe.
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In the companion rulemaking proposing emission guidelines under CAA
section 111(d) for CO2 emissions from existing affected
EGUs, the EPA is proposing that an existing source that becomes subject
to requirements under CAA section 111(d) will continue to be subject to
those requirements even after it undertakes a modification or
reconstruction. This is also discussed in greater detail in the Legal
Memorandum.\69\ Under this interpretation, a modified or reconstructed
source would be subject to both (1) the CAA section 111(d) requirements
that it had previously been subject to and (2) the modified source or
reconstructed source standard under CAA section 111(b) proposed in this
rulemaking.
---------------------------------------------------------------------------
\69\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-2013-0602.
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The EPA also solicits comment on an optional alternative method for
calculating the emission limit that would be applicable to an affected
modified natural gas-fired stationary combustion turbine after that
unit becomes subject to a CAA section 111(d) plan. The EPA specifically
seeks comment on the option of allowing the affected source to meet a
unit-specific emission limit that is determined by the CAA section
111(b) implementing authority from an assessment to identify energy
efficiency improvement opportunities for the affected source.
3. Emission Standard for Reconstructed EGUs
Reconstructed fossil fuel-fired boilers and IGCC units with a heat
input rating that is greater than 2,000 MMBtu/h would be required to
meet a standard of 1,900 lb CO2/MWh-net. Reconstructed
fossil fuel-fired utility boilers and IGCC units with a heat input
rating that is 2,000 MMBtu/h or less would be required to meet a
standard of 2,100 lb CO2/MWh-net.
Reconstructed natural gas-fired stationary combustion turbines with
a heat input rating greater than 850 MMBtu/h would be required to meet
a standard of 1,000 lb CO2/MWh-gross. Reconstructed
combustion turbines with a heat input rating of 850 MMBtu/h or less
would be required to meet a standard of 1,100 lb CO2/MWh-
gross.
While the EPA is proposing these standards of performance, we are
also taking comment on a range of potential emission limits.
Specifically, we solicit comment on the following emission limit
ranges:
(1) For reconstructed fossil fuel-fired boilers and IGCC units with
a heat input rating that is greater than 2,000 MMBtu/h, a range of
1,700-2,100 lb CO2/MWh-net;
(2) for reconstructed fossil fuel-fired boilers and IGCC units with
a heat input rating of 2,000 MMBtu/h or less, a range of 1,900-2,300 lb
CO2/MWh-net;
(3) for reconstructed stationary combustion turbines with a heat
input rating greater than 850 MMBtu/h, a range of 950-1,100 lb
CO2/MWh-gross; and
(4) for reconstructed stationary combustion turbines with a heat
input rating of 850 MMBtu/h or less, a range of 1,000-1,200 lb
CO2/MWh-gross.
We also solicit comment on whether: (1) The standards for utility
boilers and IGCC units should be subcategorized by primary fuel type,
(2) the small utility boiler and IGCC unit subcategory should be
limited to utility boilers so that all IGCC units would be in the large
subcategory regardless of size, or if there are sufficient alternate
compliance technologies (e.g., co-firing natural gas) that the small
unit subcategory is unnecessary and should be eliminated so that those
sources would be required to meet the same emission standard as large
utility boilers and IGCC units, and (3) an annual short-term
performance test should be required for stationary combustion turbines
in addition to the 12-operating-month rolling average standard.
Requiring an initial and annual short term compliance test that is
numerically more stringent than the 12-operating-month standard for
modified and reconstructed stationary combustion turbines would insure
that efficient stationary combustion turbines are installed and
properly maintained. The less stringent 12-month rolling average
standard would be set at a level that would account for operating
conditions where the emission rate is higher than design conditions.
4. Net Output
We are proposing standards for modified and reconstructed units as
net output emission rates. We are also requesting comment on using
either gross output standards or adjusted gross output based standards
in the final rule.\70\
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\70\ In the January 8, 2014 proposal for new sources, we
proposed standards as gross output emission rates, See 79 FR 1447
and 1448. In the rulemaking for existing sources that we are
proposing concurrently with this rulemaking, we are proposing
emission guidelines that call for state standards as net output
emission rates (but seek comment on gross output-based emission
rates).
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C. Startup, Shutdown and Malfunction Requirements
We are proposing the standards in this rule apply at all times,
including during periods of startup and shutdown. This section provides
a summary of the requirements.
1. Startups and Shutdowns
Consistent with Sierra Club v. EPA,\71\ the EPA is proposing
standards in this rule that apply at all times, including during
startups and shutdowns. In proposing the standards in this rule, the
EPA has taken into account startup and shutdown periods, which are
included in the compliance calculation as periods of partial load. The
proposed method to calculate compliance is to sum the emissions for all
operating hours and to divide that value by the sum of the electric
energy output and useful thermal energy output, where applicable for
CHP EGUs, over a rolling 12-operating-month period. The EPA is
proposing that sources incorporate in their compliance determinations
emissions from all periods, including startup or shutdown, during which
fuel is combusted and emissions monitors are not out of control, in
addition to all power produced over the periods of emissions
measurements. Given that the duration of startup or shutdown periods
are expected to be small relative to the duration of periods of normal
operation and that the fraction of power generated during periods of
startup or shutdown is expected to be very small, the impact of these
periods on the total average is expected to be minimal.
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\71\ 551 F.3d 1019 (D.C. Cir. 2008).
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2. Malfunctions
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as ``any sudden, infrequent, and not
reasonably preventable failure of air pollution control equipment,
process equipment, or a process to operate in a normal or usual manner.
Failures that are caused in part by poor maintenance or careless
operation are not malfunctions'' (40 CFR 60.2). The EPA has determined
that CAA section 111 does not require that emissions that occur during
periods of malfunction be
[[Page 34976]]
factored into development of CAA section 111 standards. Nothing in CAA
section 111 or in case law requires that the EPA anticipate and account
for the innumerable types of potential malfunction events in setting
emission standards. CAA section 111 provides that the EPA set standards
of performance which reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. A
malfunction is a failure of the source to perform in a ``normal or
usual manner'' and no statutory language compels EPA to consider such
events in setting standards based on the ``best system of emission
reduction.'' The ``application of the best system of emission
reduction'' is more appropriately understood to include units operating
in such a way as to avoid malfunctions.
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 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 and thus accounting for
malfunctions could lead to standards that are 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.
In the event that a source fails to comply with the applicable CAA
section 111 standards as a result of a malfunction event, the EPA would
determine an appropriate response based on, among other things, the
good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as undertake 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
(containing the definition of malfunction).
Further, to the extent the EPA files an enforcement action against
a source for violation of an emission standard, the source can raise
any and all defenses in that enforcement action and at 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 several prior rules, the EPA had included 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, in
ensuring 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 such an affirmative defense in one of the
EPA's CAA section 112(d) regulations. NRDC v. EPA, No. 10-1371, 2014
U.S. App. LEXIS 7281 (D.C. Cir. April 18, 2014) (vacating affirmative
defense provisions in CAA section 112(d) 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 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 also id. at *21 (``[U]nder this
statute, deciding whether penalties are `appropriate' in a given
private civil suit is a job for the courts, not EPA.'').\72\ In light
of NRDC, the EPA is not including a regulatory affirmative defense
provision in this rulemaking. 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 DC 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.id. at *24. (stating that arguments that violation were
caused by unavoidable technology failure can be made to the courts in
future civil cases when the issue arises). The same logic applies to
EPA administrative enforcement actions.
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\72\ 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.
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D. Continuous Monitoring Requirements
We are proposing the same monitoring requirements for modified and
reconstructed sources as were proposed for newly constructed sources in
the January 2014 proposal. This section provides a summary of the
requirements. For additional detail, see 79 FR 1450 and 1451.
Today's proposed rule would require owners or operators of EGUs
that combust solid fuel to install, certify, maintain, and operate
continuous emission monitoring systems (CEMS) to
[[Page 34977]]
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/
h).
The proposed rule would allow owners or operators of EGUs that burn
exclusively gaseous or liquid fuels to install fuel flow meters as an
alternative to CEMS and to calculate the hourly CO2 mass
emissions rates using Equation G-4 in Appendix G to 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 to part 75.
In addition to requiring monitoring of the CO2 mass
emission rate, the proposed rule would require EGU owners or operators
to monitor the hourly unit operating time and ``gross output'',
expressed in megawatt hours (MWh). The gross output includes electrical
output plus any mechanical output, plus 75 percent of any useful
thermal output.
The proposed rule would require EGU owners or operators to prepare
and submit a monitoring plan that includes both electronic and hard
copy components, in accordance with 40 CFR 75.53(g) and (h). Further,
all monitoring systems used to determine the CO2 mass
emission rates would have to be certified according to section 75.20
and section 6 of part 75, Appendix A within the 180-day window of time
allotted under section 75.4(b), and would be required to meet the
applicable on-going quality assurance procedures in Appendices B and D
to part 75.
The proposed rule would require only those operating hours in which
valid data are collected and recorded for all of the parameters in the
CO2 mass emission rate equation to be used for compliance
purposes. Additionally for EGUs using CO2 CEMS, only
unadjusted stack gas flow rate values would be used in the emissions
calculations. In this proposal, part 75 bias adjustment factors (BAFs)
would not be applied to the flow rate data. These restrictions on the
use of Part 75 data for Part 60 compliance are consistent with previous
NSPS regulations and revisions.
Certain variations from and additions to the basic Part 75
monitoring would be required and are detailed in the January 2014
proposal (See 79 FR 1451).
Special compliance provisions for units with common stack or
multiple stack configurations, consistent with section 60.13(g), would
be required and are detailed in the January 2014 proposal (see 79 FR
1451).
The proposed rule would require 95 percent of the operating hours
in each compliance period (including the compliance periods for the
intermediate emission limits) to be valid hours, i.e., operating hours
in which quality-assured data are collected and recorded for all of the
parameters used to calculate CO2 mass emissions. EGU owners
or operators would have the option to use backup monitoring systems, as
provided in sections 75.10(e) and 75.20(d), to help meet this proposed
data capture requirement.
We are proposing two additional amendments to the monitoring
requirements. First, we are proposing that measurements of electricity
output (both gross and net) be measured using 0.2 class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Second, we are proposing that hours with no
gross generation or where the gross generation is less than the
auxiliary loads be reported as zero instead of a negative value.
Steam is the most common type of useful thermal output for NSPS
purposes. The amount of useful energy flowing in a steam header is
measured with the following components: a flow meter (to determine the
volumetric flow rate of steam in cubic meters per hour or the mass flow
rate in kilograms per hour), a thermocouple or resistance temperature
detector (to determine the temperature of the steam), and an
electromechanical transmitter (to determine the pressure of the steam).
The accuracy of the measurement of useful thermal energy calculation is
the product of the accuracies of the flow, temperature, and pressure
measurements. The January 2014 proposal includes requirements for the
measurement of useful thermal output from CHP systems, but does not
include associated specifications for quality assurance of the
underlying flow, temperature, and pressure measurements. The EPA is
considering and soliciting comment on requiring that manufacturers'
maintenance recommendations be followed and include, at a minimum,
annual inspection and calibration requirements for the flow meters,
thermocouples or resistance temperature detectors (RTDs), and
electromechanical transmitters used to acquire the steam flow rates and
properties integral to calculation of useful thermal output.
The EPA is soliciting information on: (1) The technologies that are
appropriate for continuous monitoring of useful thermal output, and (2)
whether the EPA should specify the technologies to be used. For
example, should technology choices be limited to ultrasonic, coriolis,
averaging pitot tube with 2 differential pressure cells, or shedding
vortex since they appear to be the most accurate? The EPA is also
soliciting information on the costs of operating these systems,
including ongoing maintenance, calibration intervals, and other quality
assurance costs. Finally, with regard to the quality assurance
requirements for continuous monitoring of useful thermal output, the
EPA is soliciting comment on the appropriate ASTM, ANSI, or ASME
standards (e.g., ASME PTC 4-2013, ASME PTC 19.5-2004 and ASME MFC-6-
2013) that should be incorporated by reference into the final standards
of performance. This would be an alternative to specifying technologies
in order to ensure monitoring data are of sufficient quality for
demonstrating compliance with the proposed efficiency standards.
E. Emissions Performance Testing Requirements
We are proposing the same emissions performance testing
requirements for modified and reconstructed sources as were proposed
for newly constructed sources in the January 2014 proposal. This
section provides a summary of the requirements. For additional detail,
see 79 FR 1451.
In accordance with section 75.64(a), the proposed rule would
require an EGU owner or operator to begin reporting emissions data when
monitoring system certification is completed or when the 180-day window
in section 75.4(b) allotted for initial certification of the monitoring
systems expires (whichever date is earlier). The initial performance
test would consist of the first 12-operating-months of data, starting
with the month in which emissions are first required to be reported.
The initial 12-operating-month compliance period would begin with the
first month of the first calendar year of EGU operation in which the
facility exceeds the capacity factor applicability threshold.
The traditional 3-run performance tests (i.e., stack tests)
described in section 60.8 would not be required for this rule.
Following the initial compliance determination, the emission standard
would be met on a 12-operating-month rolling average basis.
F. Continuous Compliance Requirements
We are proposing the same continuous compliance requirements for
modified and reconstructed sources as were proposed for newly
constructed sources in the January 2014 proposal.
[[Page 34978]]
This section provides a summary of the requirements. For additional
detail, see 79 FR 1451.
Today's proposed rule specifies that compliance with the mass
emissions rate limits would be determined on a 12-operating-month
rolling average basis, updated after each new operating month. For each
12-operating-month compliance period, quality-assured data from the
certified Part 75 monitoring systems would be used together with the
gross output over that period of time to calculate the average
CO2 mass emissions rate.
The proposed rule specifies that the first operating month included
in the initial 12-operating-month compliance period would be the month
in which reporting of emissions data is required to begin under section
75.64(a), i.e., either the month in which monitoring system
certification is completed or the month in which the 180-day window
allotted to finish certification testing expires (whichever month is
earlier).
We are proposing that initial compliance with the applicable
emissions limit in kg/MWh be calculated by dividing the sum of the
hourly CO2 mass emissions values by the total gross output
for the 12-operating-month period. Affected EGUs would 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.
G. Notification, Recordkeeping and Reporting Requirements
We are proposing the same notification, recordkeeping and reporting
requirements for modified and reconstructed sources as were proposed
for newly constructed sources in the January 2014 proposal. This
section provides a summary of the requirements. For additional detail,
see 79 FR 1451 and 1452.
Today's proposed rule would require an EGU owner or operator to
comply with the applicable notification requirements in sections
60.7(a)(1) and (a)(3), section 60.19 and section 75.61. The proposed
rule would also require the applicable recordkeeping requirements in
subpart F of Part 75 to be met. For EGUs using CEMS, the data elements
that would be recorded include, among others, hourly CO2
concentration, stack gas flow rate, stack gas moisture content (if
needed), unit operating time, and gross electric generation. For EGUs
that exclusively combust liquid and/or gaseous fuel(s) and elect to
determine CO2 emissions using Equation G-4 in Appendix G of
Part 75, the key data elements in subpart F that would be recorded
include hourly fuel flow rates, fuel usage times, fuel GCV, gross
electric generation.
The proposed rule would require EGU owners or operators to keep
records of the calculations performed to determine the total
CO2 mass emissions and gross output for each operating
month. Records would be kept of the calculations performed to determine
the average CO2 mass emission rate (kg/MWh) and the
percentage of valid CO2 mass emission rates in each
compliance period. The proposed rule would also require records to be
kept of calculations performed to determine site-specific carbon-based
F-factors for use in Equation G-4 of Part 75, Appendix G (if
applicable).
The proposed rule would require all affected EGU owners/operators
to submit quarterly electronic emissions reports in accordance with
subpart G of Part 75. The proposed rule would require these reports to
be submitted using the Emissions Collection and Monitoring Plan System
(ECMPS) Client Tool. Except for a few EGUs that may be exempt from the
Acid Rain Program (e.g., oil-fired units), this is not a new reporting
requirement. Sources subject to the Acid Rain Program are already
required to report the hourly CO2 mass emission rates that
are needed to assess compliance with today's rule.
Additionally, in the proposed rule and as part of an Agency-wide
effort to streamline and facilitate the reporting of environmental
data, the rule would require that quarterly electronic ``excess
emissions'' reports be submitted using ECMPS, within 30 days after the
end of each quarter. Reporting the percentage of valid CO2
mass emission rates is necessary to demonstrate compliance with the
requirement to obtain valid data for 95 percent of the operating hours
in each compliance period. Any excess emissions that occur during the
quarter would be identified.
IV. Rationale for Reliance on Rational Basis To Regulate GHG From
Fossil Fuel-Fired EGUs
A. Rational Basis and Endangerment Finding
In the January 2014 proposal, the EPA proposed that, in order to
regulate GHG from newly constructed fossil fuel-fired EGUs, the EPA
needed a rational basis, but that CAA section 111 did not require an
endangerment finding. The EPA further proposed that even if CAA section
111 did require such a finding, the EPA's rational basis would qualify
as one. The EPA expects to finalize the January 2014 proposal by the
time that it finalizes this proposed rulemaking for affected modified
and reconstructed fossil fuel-fired EGUs, and in that event, the EPA
would not be required to further address the rational basis or
endangerment finding in this rulemaking.
However, because this rulemaking is a separate action from the
January 2014 proposal, the EPA is making the same proposal--that the
EPA has a rational basis for this rulemaking, and that no endangerment
finding is required, but that if one is, the EPA's rational basis would
qualify as one--which it made in the January 2014 proposal. See 79 FR
1452 through 1456.
B. Source Categories
This proposal addresses the same two source categories--fossil
fuel-fired steam generating units (utility boilers and IGCC units) and
natural gas-fired stationary combustion turbines--that were addressed
by the January 2014 proposal. In the January 2014 proposal, the EPA
included a proposal and co-proposal for the treatment of the two
affected source categories, and for how the regulatory requirements
applicable to these source categories would be codified in 40 CFR part
60. Specifically, the EPA proposed to create subcategories within each
category, and to codify the regulatory requirements for each
subcategory in 40 CFR part 60, subparts Da and KKKK, respectively. In
addition, the EPA co-proposed to combine the two categories for
purposes of regulating the CO2 emissions, and to codify all
the CO2 regulatory requirements in a new subpart, TTTT.
As noted, the EPA expects to finalize the January 2014 proposal by
the time that it finalizes this proposed rulemaking for modified and
reconstructed fossil fuel-fired EGUs. It is the EPA's intent that the
approach for categorization and codification will be the same in the
final action for this proposal as is finalized for the January 2014
proposal. However, because this rulemaking is a separate action from
the January 2014 proposal, the EPA is making the same proposal and co-
proposal with regard to categories and codification for modified and
reconstructed sources that it made with regard to new construction
sources in the January 2014 proposal. That is, the EPA proposes to
create subcategories within each category and to codify the regulatory
requirements in 40 CFR part 60, subparts Da and KKKK, respectively; and
in addition, the EPA co-proposes to combine the two categories for
purposes of regulating CO2 emissions, and to codify all the
CO2 regulatory requirements in a new subpart TTTT. See 79 FR
1452 through 1454.
[[Page 34979]]
V. Rationale for Applicability Requirements
The rationale for several of the proposed applicability
requirements for modified and reconstructed sources is the same as that
in the January 2014 proposal. This section provides a summary of the
rationale for these requirements along with rationale for differences
with the applicability included in the January 2014 proposal. In
addition, we are soliciting comment on multiple alternative approaches
to the applicability criteria.
The following four proposed applicability criteria are consistent
with the January 2014 proposal. First, this proposal includes within
the definition of a utility boiler, IGCC unit, and stationary
combustion turbine that is subject to the proposed requirements, any
integrated device that provides electricity or useful thermal output to
the boiler, the stationary combustion turbine or to power auxiliary
equipment. The rationale behind including integrated equipment
recognizes that the integrated equipment may be a type of combustion
unit that emits GHGs, and that it is important to assure that those GHG
emissions are included as part of the overall GHG emissions from the
affected source. Also consistent with the January 2014 proposal, we are
considering including in the definition of the affected facility co-
located non-emitting energy generation equipment included in the
facility operating permit but that is not integrated into the operation
of the affected facility.
Second, we are also proposing a different definition of potential
electric output from the current definition that determines the
potential electric output (in MWh on an annual basis) considering only
the design heat input capacity of the facility and does not account for
efficiency. It assumes a 33 percent net electric efficiency, regardless
of the actual efficiency of the facility. Therefore, we are proposing a
definition of potential electric output that allows the source the
option of calculating its potential electric output on the basis of its
actual design electric output efficiency on a net output basis, as an
alternative to the default one-third value.
Third, we are proposing to apply the one-third sales criterion on a
rolling 3-year basis instead of an annual basis for stationary
combustion turbines for multiple reasons. First, extending the period
to 3 years would ensure that the CO2 standards apply only to
intermediate and base load EGUs by allowing facilities intended to
generally operate at low capacity factors (e.g. simple cycle turbines
that generally sell less than one-third of their potential electric
output) to avoid applicability. Second, only 0.2 percent of existing
simple cycle turbines had a 3-year average capacity factor of greater
than one-third between 2000 and 2012. We are soliciting comment on ways
to address potential complications resulting from having different time
periods for applicability and the actual emission standard. For
example, a stationary combustion turbine that runs at a 60 percent
capacity factor for years one and two but only a 5 percent capacity
factor on year three would meet the proposed applicability requirements
for all 3 years (since applicability is determined on a 3-year rolling
average basis). However, the emission standard is on a 12-month rolling
average basis and if the hours of operation on year three are even and
spread out in each month the facility likely operated at low loads and
may have difficulty achieving the proposed standard. This could be
further complicated if the facility burned fuels other than natural gas
during year 3 since the 90 percent natural gas applicability would
still apply even though other fuels were burned during the emissions
standard period.
Finally, we propose that if CHP facilities meet the general
applicability criteria they should be subject to the same requirements
as electric-only generators. However, one potential issue that we have
identified is inequitable applicability to third-party CHP developers
compared to CHP facilities owned by the facility using the thermal
output from the CHP facility. We are therefore proposing to add ``of
the thermal host facility or facilities'' to the definition of net-
electric output for qualifying CHP facilities (i.e., the clause would
read, ``the gross electric sales to the utility power distribution
system minus purchased power of the thermal host facility or facilities
on a calendar year basis'' (emphasis added)). This would make
applicability consistent for both facility-owned CHP and third-party-
owned CHP.
The rationale for following applicability criteria is different
from the January 2014 proposal. To clarify that existing boiler and
IGCC facilities would continue to be included in CAA section 111(d)
state programs regardless of their actual electric sales or fossil fuel
use, we are deleting the criteria to be considered an EGU. These
criteria include that the facility must (1) actually sell one-third of
their potential electric output and 219,000 MWh on an annual basis and
(2) the applicability exemption for facilities, than burn fossil fuel
for 10 percent or less of the heat input during a 3-year rolling
average period. The sales criteria exemption was intended to exempt low
capacity factor facilities since they would have additional
difficulties meeting the standards in the January 2014 proposal.
However, the proposed standards for boilers and IGCC facilities in this
rulemaking are less stringent and are achievable by low capacity factor
facilities, so the applicability exemption would not be applicable. The
low fossil use exemption was designed to exempt facilities that are
capable of combusting fossil fuel, but burn primarily non fossil fuels.
These facilities (e.g., wood-fired EGUs) typically are inherently less
efficient than fossil fuel-fired EGUs, and we are soliciting comment on
if we should subcategorize boilers and IGCC facilities where fossil
fuel consists of 10 percent or less of the heat input during. In the
event we establish a subcategory, should the heat input be determined
on an annual or 3-year rolling period and should the standard be an
alternate numerical limit or ``no emission standard.''
In the January 2014 proposal, we also solicit comment on various
issues concerning, and different approaches to, the applicability
requirements for steam generating units and combustion turbines.\73\
For additional detail, see 79 FR 1459 through 1461. We are soliciting
comment on additional approaches to address potential unintended
negative environmental impacts and to address issues concerning how the
general applicability of the CAA section 111(b) NSPS potentially
impacts the CAA section 111(d) rulemaking, since only EGUs that would
be included under the CAA section 111(b) applicability if they were
newly constructed, modified or reconstructed are included in the state
CAA section 111(d) goals.
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\73\ Requests for comment in the January 2014 proposal regarding
the appropriateness of certain applicability requirements that are
based on a source's operations do not apply to this proposed
rulemaking. Whereas newly constructed sources would not have a
history of operating, in this rulemaking, the affected sources that
would be undertaking modifications or reconstructions do have an
operating history.
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In the January 2014 proposal, we proposed a dual electric sales
applicability criterion for stationary combustion turbines of 219,000
MWh and 33 percent sales of potential electric output on a 3-year
rolling average basis. In addition, we specifically solicited comment
on a range of 20 to 40 percent sales of potential electric output.
However, the dual electric sales applicability could potentially result
in
[[Page 34980]]
the installation, modification or reconstruction of smaller, less
efficient simple cycle combustion turbines rather than larger, more
efficient simple cycle combustion turbines. For simple cycle combustion
turbines that are smaller than approximately 70 MW, the 219,000 MWh
sales would be the determining criteria for whether the facility is
subject to an emission standard. Smaller EGUs can sell over one-third
of their potential electric output and still not be subject to a GHG
emission standard. This could potentially place larger, more efficient
simple cycle combustion turbines at a disadvantage since they would be
limited to selling less (e.g., one-third) of their potential electric
output. This could result in higher GHG emissions, and we are
soliciting comment on approaches to minimize this outcome. One approach
we are considering is changing the ``one-third potential electric
output'' sales criteria to ``the design net efficiency times the
potential electric output'' for simple cycle combustion turbines. This
would have the effect of allowing the most efficient larger simple
cycle combustion turbines currently available to sell approximately 38
percent of their potential electric output on a 3-year rolling average
before an emission standard would apply. The smallest aeroderivative
stationary combustion turbine designs have efficiencies of
approximately 30 percent or greater, but these combustion turbine
engines are smaller in size and the 219,000 MWh sales limit would still
be the controlling criterion. Lower efficiency industrial frame
turbines have efficiencies of approximately 28 percent. Therefore, in
this approach, applicability with an emission standard would in general
increase the electric sales criteria for the larger, more efficient
aeroderivative simple cycle combustion turbines and decrease it larger,
less efficient industrial frame simple cycle turbines. We are
soliciting comment on if this change would be sufficient to avoid the
potential adverse environmental impact mentioned previously or if a
multiplication factor, such as 1.1 (we are soliciting comment on an
appropriate factor), should be applied to the design net efficiency to
determine the percent sales applicability criterion. The percent
electric sales criterion would read, for example, ``1.1 times the
design net efficiency times the potential electric output'' for simple
cycle combustion turbines. The result of this approach is that the most
efficient simple cycle turbines would be able to sell approximately 42
percent of their potential electric output prior to becoming subject to
a GHG standard. Conversely, the least efficient simple cycle turbines
would be limited to selling 31 percent of their potential electric
output prior to becoming subject to a GHG standard. The 42 percent
sales criterion is approximately equivalent to allowing 4,000 hours of
operation on a 3-year average at 90 percent load before a GHG standard
would apply. We are also soliciting comment on eliminating the
additional 219,000 MWh sales criterion for stationary combustion
turbines so that stationary combustion turbines would be subject to a
GHG emission standard once they sell the specified percentage of
potential electric output to the grid. This would eliminate any
incentive to install multiple smaller, less efficient stationary
combustion turbines rather than fewer larger, more efficient stationary
combustion turbines. This approach would recognize the environmental
benefit of installing more efficient simple cycle turbines regardless
of size. However, this change could also potentially cover a larger
percentage of industrial combined heat and power facilities. We are
therefore soliciting comment on if the 219,000 MWh electric sales
criterion should only be eliminated for non-CHP stationary combustion
turbines. As an alternative, we are soliciting comment on an
applicability exemption, and the criteria for that exemption, for
highly efficient CHP facilities.
We are also soliciting comment on whether the percent sales of
potential electric output is sufficient to account for the potential
increased use of simple cycle combustion turbines due to the expected
increased percentage of electricity generated from renewable generation
in the future. Due to the intermittent nature of some renewable
technologies, such as wind and solar, the electric grid must be
balanced by using some type of quick response backup generation or
rapid reductions in load. The EPA is soliciting comment on the extent
to which simple cycle combustion turbines will be used to support
additional renewable generation. We also solicit comment on the
ability, relative costs and overall GHG emissions of energy storage
systems (e.g., utility battery stations or flywheels) and on demand
response programs to balance demand and generation from renewable
electricity generation.
In addition, some of the initial feedback we received in public
comments \74\ on the January 2014 proposal suggests that the emissions
data that the EPA used in developing the natural gas-fired stationary
combustion turbine standards do not completely account for degradation
in performance over the entire life of an NGCC. Also, commenters noted
that NGCC units are expected to operate differently in the future due
to the increased percentage of power generated from renewable sources,
such as wind and solar. In addition, initial feedback suggested that
the size distinction between large and small stationary combustion
turbines should be adjusted.
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\74\ All public comments on the January 2014 proposal are
available in the rulemaking docket, Docket ID: EPA-HQ-OAR-2013-0495.
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The EPA is soliciting comment on whether a separate standard should
be established for load-following (i.e., intermediate capacity factor)
NGCC EGUs. The more stringent standard would apply only during periods
of high annual capacity factors and a less stringent standard would
apply during periods of intermediate load (e.g., when electric sales
are between 33 to 60 percent of the potential electric output). This
approach addresses two potential issues with the standards in the
January 2014 proposal. First, certain NGCC units are designed to be
highly efficient when operated as load-following units, but these
design characteristics reduce the efficiency at base load. Conversely,
the NGCC units with the highest base load design efficiencies are not
necessarily as efficient as NGCC designed and intended to be used as
load-following EGUs. Therefore, a full-load efficiency performance test
would not necessarily result in the lowest CO2 emissions in
practice. Second, NGCC units operating as load-following EGUs are
inherently less efficient than NGCC units operating at base load.
Establishing a standard that varies with load would assure that NGCC
units that are operated as base load units are as efficient as possible
and still account for inherent lower efficiencies at part-load
conditions.
We are requesting comment on a full range of alternatives for low
capacity factor stationary combustion turbines and/or simple cycle
combustion turbines to the general applicability thresholds we proposed
in the January 2014 proposal. This includes soliciting comment on
whether we should: Establish a separate numerical limit for low
capacity factor stationary combustion turbines and/or simple cycle
combustion turbines; exempt all such units; set a higher capacity
factor threshold applicable to all simple cycle turbines; establish a
variable capacity
[[Page 34981]]
factor that would allow more efficient, lower emitting turbines to run
and be permitted for longer periods of operation (e.g., a higher
capacity factor for the most efficient turbines being progressively
lowered for lower efficiency turbines); or establish a CO2
emission limitation in the form of an annual tonnage cap based on
allowable emissions from smaller, less efficient units that do not
exceed the 33 percent and 219,000 MWh thresholds regardless of hours
operated. The EPA is considering all these options in its treatment of
simple cycle combustion turbines and solicits comments on the merits of
these options or variations of them. The EPA intends--when it takes
final action on this proposal and on the January 2014 proposal for
newly constructed sources--to finalize the same standards and
applicability criteria for newly constructed, modified and
reconstructed natural gas-fired stationary combustion turbines.
Consistent with the January 2014 proposal, the EPA is proposing the
size distinction between large and small combustion turbines be a base
load heat input rating of the combustion turbine engine of 850 MMBtu/h.
As explained in the January 2014 proposal, this distinction is
consistent with the criteria pollutant NSPS for stationary combustion
turbines, which was based on the largest aeroderivative turbine design
available at the time. However, incremental adjustments have been made
to aeroderivative designs and the base load rating of the largest
aeroderivative turbines now exceeds 850 MMBtu/h. The EPA is soliciting
comment on increasing the size distinction between large and small
stationary combustion turbines to 900 MMBtu/h to account for larger
aeroderivative designs or to 1,000 MMBtu/h to account for future
incremental increases in base load ratings. Alternately, the EPA is
soliciting comment on increasing the size distinction to between 1,300
to 1,800 MMBtu/h. There are currently no combined cycle combustion
turbines offered with turbine engine base load rating between those
sizes.
VI. Rationale for Emission Standards for Reconstructed Fossil Fuel-
Fired Utility Boilers and IGCC Units
A. Overview
In this section, we explain our rationale for emission standards
for reconstructed fossil fuel-fired utility boiler and IGCC units,
which are based on our proposal that the most efficient generating
technology is the BSER for these types of units.
CAA section 111(b)(1)(B) authorizes the EPA to promulgate
``standards of performance'' for new sources, including modified and
reconstructed sources. The CAA directs that standards of performance
must consist of emission limits that are based on the ``best system of
emission reduction . . . adequately demonstrated,'' taking into account
cost and other factors. In this manner, CAA section 111 provides that
the EPA's central task is to identify the BSER.
Over a 40-year period, the U.S. Court of Appeals for the District
of Columbia Circuit (D.C. Circuit or Court) has issued a number of
decisions interpreting this CAA provision, including its component
elements.\75\ Consistent with this case law, the EPA determines the
best demonstrated system based on the following key considerations,
among others:
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\75\ Portland Cement Association v. Ruckelshaus, 486 F.2d 375
(D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427,
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir.
1981); Portland Cement Association v. EPA, 665 F.3d 177 (D.C. Cir.
2011).
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The system of emission reduction must be technically
feasible.
The EPA must consider the amount of emissions reductions
that the system would generate.
The costs of the system must be reasonable. The EPA may
consider the costs on the source level, the industry-wide level, and,
at least in the case of the power sector, on the national level in
terms of the overall costs of electricity and the impact on the
national economy over time.\76\
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\76\ As discussed in the January 2014 Proposal, the D.C.
Circuit's case law formulates the cost consideration in various
ways: The costs must not be ``exorbitant [ ]'', Essex Chemical Corp.
v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), see Lignite
Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999); ``greater
than the industry could bear and survive,'' Portland Cement
Association v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975); or
``excessive'' or ``unreasonable.'' Sierra Club v. Costle, 657 F.2d
298, 343 (D.C. Cir. 1981). In the January 2014 Proposal, EPA stated
that ``these various formulations of the cost standard . . . are
synonymous,'' and, for convenience, EPA used ``reasonableness'' as
the formulation. EPA takes the same approach in this proposal.
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The EPA must also consider that CAA section 111 is
designed to promote the deployment, development and implementation of
technology.77 78
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\77\ See discussion of case law and legislative history in the
January 2014 proposal. 79 FR 1430, 1465 (cols.1-2) (January 8,
2014).
\78\ It should be noted that in one of the earliest cases, Essex
Chemical Corp. v. Ruckelshaus, in 1973, the Court stated that
because the standard must be ``achievable,'' the emission limits
must be technically feasible, and added that ``[a]n adequately
demonstrated system 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.'' Essex
Chemical Corp. v. Ruckelshaus, 486 F.2d at 427. This case law may be
read to treat technical feasibility as the measure for whether the
standard of performance is ``achievable,'' not as a criteria for
whether the system of emission reduction is the ``best system of
emission reduction . . . adequately demonstrated.'' However, for
convenience, we may refer to technical feasibility as another of the
criteria for the BSER.
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Other considerations are also important, including that the EPA
must also consider energy impacts, and, as with costs, may consider
them on the source level and on the nationwide structure of the power
sector over time. Importantly, the EPA has discretion to weigh these
various considerations, may determine that some merit greater weight
than others, and may vary the weighting depending on the source
category. The EPA discussed the CAA requirements and Court
interpretations of the BSER at length in the January 2104 proposal, 79
FR 1462 through 1467, and incorporates by reference that discussion in
this rulemaking.
It should be noted at the outset that the EPA determined that
reconstructions are a type of construction, and therefore subject to
CAA section 111(b), as part of the 1975 framework regulations, and the
EPA is not re-opening that determination.\79\ The EPA also defined
reconstructions in those regulations, and the EPA is not reopening that
definition in this rulemaking. These provisions have two main
specifications: (1) That reconstruction occurs upon replacement of
components if the fixed capital cost of the new components exceeds 50
percent of the fixed capital cost that would be required to construct
an entirely new comparable facility, and, (2) that it is
technologically and economically feasible for the facility to comply
with the applicable standards of performance after the replacements. 40
CFR 60.15. These reconstruction provisions have not been amended since
originally promulgated in 1975, and have been implemented for numerous
source categories.
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\79\ 40 FR 58417-58418, December 16, 1975 (final NSPS
modification, notification, and reconstruction provisions).
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B. Identification of Best System of Emissions Reduction
The EPA evaluated seven different control technology configurations
as potentially representing 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
[[Page 34982]]
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.\80\
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\80\ Note that we also evaluated these seven different
technology configurations as potentially representing BSER for
modified utility boilers and IGCC units. The subsequent discussion
of each of these is also applicable for that evaluation as well.
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We discuss each of these alternatives below, and explain why we
propose that for reconstructed fossil fuel-fired boiler and IGCC EGUs
the most efficient generating technology qualifies as the BSER.
1. Partial CCS
We considered the implementation of partial CCS as the BSER at
affected reconstructed utility boilers and IGCC units. In the January
2014 proposal (79 FR 1430), the EPA found that, for new units, partial
CCS has been adequately demonstrated and is technically feasible; it
can be implemented at costs that are not unreasonable; it provides
meaningful emission reductions; its implementation will serve to
promote further development and deployment of the technology; and it
would not have a significant impact on nationwide energy prices. The
EPA also noted in the January 2014 proposal that most of the relatively
few new projects that are in the development phase are already planning
to implement CCS, so that partial CCS was consistent with current
industry trends.
Partial CCS has been demonstrated at some existing EGUs. It has
been demonstrated at a large pilot scale (e.g., 20 MW or greater) at
two facilities: At Southern Company's Plant Barry and at AEP's
Mountaineer Power Plant. A full scale, 110 MW project is currently
being retrofitted at SaskPower's Boundary Dam coal-fired EGU in Canada
and is expected to begin operation in 2014. Another large scale
retrofit project (240 MW) is in advanced stages of project development
at NRG Energy's WA Parish facility. There are also a number of smaller
examples of CCS retrofits on coal-fired power plants.\81\
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\81\ Technical Support Document, ``Effect of EPAct05 on BSER for
New Fossil Fuel-fired Boilers and IGCCs,'' available in rulemaking
docket ID: EPA-HQ-OAR-2013-0495.
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However, the EPA does not, at present, have sufficient information
about costs to propose that partial CCS is the BSER for reconstructed
utility boilers and IGCC units. Utility boilers are numerous and
diverse in size and configuration, and the EPA does not have sufficient
information about the range of specific configurations that would be
necessary to estimate the cost of partial CCS, on either a source-
specific basis or an industry-wide basis. In particular, retrofitting a
plant with partial CCS would entail integrating the carbon capture
equipment with the affected unit's steam cycle (or with an external
source of steam or heat) in order to release the captured
CO2 and regenerate the solvent or sorbent. The cost of a
retrofit would depend on many site-specific details, including the
space available for the capture equipment, and the EPA lacks
information on such details for a significant portion of the industry.
Therefore, the EPA does not propose to find that partial CCS is the
BSER for CO2 emissions from reconstructed fossil fuel-fired
utility boilers and IGCC units.
2. Conversion to or Co-Firing With Natural Gas
While conversion to or co-firing with natural gas in a utility
boiler is a technically feasible option to reduce CO2
emission rates, it is an inefficient way to generate electricity
compared to use of an NGCC and the resultant CO2 reductions
are relatively expensive. The EPA found costs for natural gas co-firing
to range from approximately $83/ton to $150/ton of CO2
avoided.\82\ Even for cases where the natural gas could be co-fired
without any capital investment or impact on the performance of the
affected facility (e.g., an existing IGCC facility that already has a
sufficient natural gas supply), the costs of CO2 reduction
would still be approximately $75/ton of CO2 avoided.
Therefore, we are not proposing natural gas co-firing as part of the
BSER for modified or reconstructed steam generating units.
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\82\ Chapter 2, GHG Abatement Measures Technical Support
Document, available in Docket EPA-HQ-OAR-2013-0602.
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However, we specifically solicit comment on whether natural gas
reburning (NGR) and/or similar technologies \83\ should be included as
part of the BSER for reconstructed utility boilers and IGCC units. NGR
is a combustion technology in which a portion of the main fuel heat
input is diverted to locations above the burners, creating a secondary
combustion zone called the reburn zone. In NGR, the secondary (or
reburn) fuel, natural gas, is injected to produce a slightly fuel rich
reburn zone. Overfire air (OFA) is added above the reburn zone to
complete burnout. As flue gas passes through the reburn zone, part of
the NOX formed in the main combustion zone is reduced by
hydrocarbon fragments (free radicals) and converted to molecular
nitrogen (N2). With NGR at 15 and 20 percent of the heat
input to a coal-fired boiler, the CO2 emission rate would be
reduced by 6 percent and 8 percent, respectively. In addition to
reducing CO2 emissions, a potential financial benefit of NGR
compared to natural gas co-firing is the generation of additional
NOX reductions. These reductions could reduce costs a source
is currently paying for compliance with NOX requirements,
including operations and maintenance costs associated with existing
controls such as selective catalytic reduction systems and/or the cost
of emission allowances under certain pollution control programs.
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\83\ Fuel lean gas reburning (FLGR\TM\), also known as
controlled gas injection, similar to NGR. In FLGR\TM\, natural gas
is injected above the main combustion zone at a lower temperature
zone than in NGR and avoids creating a fuel-rich zone and maintains
overall fuel-lean conditions. The FLGR\TM\ technology is reported to
achieve NOX control comparable to NGR using less than 10%
natural gas heat input without the requirement for OFA. At a 10
percent heat input reburn rate, the CO2 emission rate of
a coal-fired EGU would be reduced by 4 percent.
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The EPA also requests comment on whether there are other factors or
technologies related to co-firing that reduce its cost, and whether for
these or other reasons, co-firing should be considered as BSER for
reconstructed fossil fuel-fired electric utility steam generating
units.
3. CHP
CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP reduces air pollution and greenhouse gas emissions. CHP has lower
emission rates and can be more economic than separate electric and
thermal generation. However, not all potentially modified and
reconstructed utility boilers and IGCC units are located close enough
to thermal hosts to economically or efficiently use the recovered
thermal energy. Therefore, we are not proposing to find that CHP is the
BSER for reconstructed utility boilers and IGCC units or stationary
combustion turbines.
4. Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal with or without photovoltaic
generation) with a fossil fuel-fired EGU.
[[Page 34983]]
Both coal-fired and NGCC EGUs have demonstrated the technical
feasibility of integrating concentrating solar thermal energy for use
in boiler feed water heating, preheating makeup water, and/or producing
steam for use in the steam turbine or to power the boiler feed pumps.
While hybrid power plants can reduce the CO2 emission rate
by several percent compared to similar non-hybrid power plants, not all
modified and reconstructed EGUs may have the space or meteorological
conditions to generate enough solar thermal energy to successfully
convert to a hybrid power plant. Solar thermal facilities require
abundant sunshine and significant land area and the EPA does not have
sufficient information about the range of specific configurations that
would be necessary to estimate the cost of implementation, on either a
source-specific basis or an industry-wide basis. We solicit comment on
whether hybrid power plant technology is broadly applicable to modified
and reconstructed EGUs and on the costs of integrating non-emitting
generation.
Our understanding is that one of the benefits of hybrid fossil EGUs
is decreased incremental cost of the non-emitting (e.g., solar thermal)
generated electricity due to the ability to use equipment (e.g., HRSG,
steam turbine, condenser, etc.) already included at the fossil fuel-
fired EGU, as well as improvement of the electrical generation
efficiency of the non-emitting generation. For example, solar thermal
often produces steam at relatively low temperatures and pressures and
the conversion efficiency of the thermal energy in the steam to
electricity is relatively low. In a hybrid power plant, the lower
quality steam is heated to higher temperatures and pressures in the
boiler (or HRSG) prior to expansion in the steam turbine, where it
produces electricity. Upgrading the relatively low grade steam produced
by the solar thermal facility improves the relative conversion
efficiencies of the solar thermal to electricity process. The primary
incremental costs of the non-emitting solar thermal generation in a
hybrid power plant is the costs of the mirrors, additional piping, and
a steam turbine that is 10 to 20 percent larger than a comparable
fossil only EGU to accommodate the additional steam load during sunny
hours.
We specifically solicit comment on an alternate, but similar,
approach for modified and reconstructed fossil fuel-fired EGUs to
integrate lower emitting generation. The recovered thermal energy from
natural gas-fired combustion turbines, fuel cells, or other combustion
technology could be used to reheat or preheat boiler feed water
(minimizing the steam that is otherwise extracted from the steam
turbine), preheat makeup water and combustion air, produce steam for
use in the steam turbine or to power the boiler feed pumps, or use the
exhaust directly in the boiler to generate steam. In theory, this could
lower generation costs as well the GHG emissions rate for a coal-fired
EGU. However, at this time we do not have sufficient information on the
costs or technical feasibility of this approach to include it as the
BSER for reconstructed fossil fuel-fired utility boilers.
5. Reductions in Generation Associated With Dispatch Changes, Renewable
Generation, and Demand Side Energy Efficiency
In the companion proposal in today's Federal Register, which
proposes emission guidelines for existing fossil fuel-fired EGUs, the
EPA considered numerous measures that can and are being implemented to
improve emission rates and to limit overall CO2 emissions
from fossil fuel-fired EGUs. The EPA grouped those measures into four
main categories, or ``building blocks.'' The EPA proposed that each of
the building blocks represents a method of CO2 emission
reduction at existing fossil fuel-fired EGUs that, when combined with
the other building blocks, represent the ``best system of emission
reduction . . . adequately demonstrated'' for existing fossil-fuel-
fired EGUs under a 111(d) program. The building blocks are:
1. Lowering the carbon intensity of generation at individual
affected EGUs (e.g., through heat rate improvements);
2. Reducing emissions of the most carbon-intensive affected EGUs to
the extent that this can be accomplished cost-effectively by shifting
generation to less carbon-intensive existing NGCC units, including NGCC
units that are under construction;
3. Reducing emissions of carbon-emitting EGUs to the extent that
this can be accomplished cost-effectively by expanding the amount of
new, lower (or no) carbon-intensity generation; and,
4. Reducing emissions of carbon-emitting EGUs to the extent that
this can be accomplished cost-effectively by increasing demand-side
energy efficiency.
In this rulemaking, we are, in effect, utilizing building block
one--lowering the carbon intensity of generation at individual affected
EGUs through heat rate improvements--as part of the BSER determination
for modified units, but we are not proposing that building blocks two,
three, or four are components of the BSER determination. We solicit
comment on whether building blocks two, three and four would be
appropriate in light of the fact that, unlike the CAA section 111(d)
emission guidelines proposal, which will result in state plans that
cover all existing sources, this proposal will result in a federal rule
that covers only those sources that modify or reconstruct. We note that
it is not possible in advance to determine which sources will do so. We
solicit 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.
6. Efficiency Improvements Achieved Through the Use of the Most
Efficient Generation Technology
We also considered whether the proposed emission limit for
reconstructed fossil fuel-fired utility boilers and IGCC units should
be based on the performance of the most efficient generation technology
available, which we believe is a supercritical pulverized coal (SCPC)
or supercritical circulating fluidized bed (CFB) boiler for large
sources, and subcritical for small sources. We propose to find that
these technologies meet the criteria for the BSER.\84\
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\84\ Note that the discussion of efficiency improvements in this
section is limited to reconstructed utility boilers and IGCC units.
We discussed efficiency improvements for modifications below.
---------------------------------------------------------------------------
a. Technical Feasibility
The use of supercritical steam conditions has been demonstrated by
many facilities since the 1960s for both large and small EGUs. In fact,
the world's first commercial supercritical pressure EGU was the 125 MW
Philo Unit 6 that commenced operation in 1957. Currently commercially
available materials capable of tolerating steam conditions of 30
megapascal (MPa) (4,350 psi) and 605 [deg]C (1,120 [deg]F) have been
demonstrated at coal-fired EGUs. In addition, even though the majority
of recently constructed coal-fired EGUs use a single steam reheat
cycle, the use of a dual steam reheat cycle has been demonstrated by
multiple facilities as technically feasible. For a facility to be
considered reconstructed for NSPS purposes, the boiler itself would
have to be substantially refurbished. As part of a reconstruction, an
owner/operator would be able to replace the steam tubing and other
necessary equipment to allow the use of the best demonstrated steam
cycle. Therefore, this option is technically feasible.
[[Page 34984]]
It should be noted that this approach identifies as the BSER
changes in production technology that would result in fewer emissions,
and not add-on technology that would control emissions. The kraft pulp
mill NSPS (40 CFR part 60, subpart BB) is an example in which different
equipment design (rather than add-on control) is the BSER for a
modification or reconstruction.
b. CO2 Reductions
The U.S. Department of Energy National Energy Technology Laboratory
(DOE/NETL) has estimated that a new SCPC boiler using subbituminous
coal would emit 7 percent less CO2 per MWh than a comparable
subcritical boiler. Therefore, we estimate that this standard will
result in reduction in emissions of at least 7 percent when compared to
the expected emissions of a reconstructed EGU using subcritical steam
conditions. Smaller EGUs often use relatively low steam parameters and
increasing the steam parameters to the maximum subcritical steam
parameters reduces the CO2 emissions rate. The average steam
pressure and temperature for small EGUs that were reported to the
information collection request associated with the Mercury and Air
Toxics Standards rulemaking is 11 MPa (1,630 pounds per square inch
guage (psig)) and 527 [deg]C (980 [deg]F) and 40 percent have no steam
reheat. Increasing the steam pressure to 20 MPa (2,900 psig) and 568
[deg]C (1,054 [deg]F) would reduce the CO2 emission rate by
6 percent. In addition, the use of a single steam reheat cycle reduces
the CO2 emission rate by 10 percent compared to an
equivalent EGU without a steam reheat cycle.
While the percent reduction in CO2 emissions rate using
efficiency improvements achieved through the use of the most efficient
generation technology is less than could be achieved by a number of the
other alternatives for the BSER that the EPA considered, as noted
above, those other alternatives do not meet other criteria for the
BSER. Efficiency improvements achieved through the use of the most
efficient generation technology do achieve the greatest emission
reductions of any of the remaining alternatives that the EPA is
considering.
c. Costs, Structure of the Energy Sector
DOE/NETL has estimated, based on the levelized cost of electricity
(LCOE), that the capital costs of a SCPC EGU are approximately 3
percent more than a comparable subcritical EGU. In fact, the reduced
fuel costs are significant enough that the overall cost to generate
electricity is actually lower for a SCPC EGU compared to a subcritical
EGU. Therefore, the emission reductions are considered cost effective
for larger EGUs.
For smaller boilers, less than approximately 200 MW, it is the
understanding of the EPA that manufacturers of steam turbines do not
currently offer turbines that have been thermodynamically optimized to
use supercritical steam conditions. Instead, for smaller applications,
they would typically adapt their larger turbines for the application.
The resulting designs have a higher cost premium than larger
supercritical steam turbines and do not take full advantage of the
potential efficiency improvements and the benefits of using a
supercritical steam cycle are reduced. Therefore, for smaller
reconstructed EGUs the EPA has determined that the BSER is the use of
highest available subcritical steam conditions. The maximum viable
subcritical steam parameters are 21 MPa (3,000 psi) and 570 [deg]C
(1,060 [deg]F). The EPA specifically solicits comment on the efficiency
benefits and the costs of using supercritical steam conditions for
smaller EGU designs. Modern materials are widely available that can
tolerate the maximum subcritical steam parameters. Therefore, we
anticipate the incremental cost of increasing steam parameters within
subcritical conditions is low. We solicit comment on these costs.
Designating the most efficient generation technology as the BSER
for reconstructed fossil fuel-fired utility boilers and IGCC units will
not have significant impacts on nationwide electricity prices. The
reason is that the additional costs of the use of efficient generation
will, on a nationwide basis, be small because few reconstructed coal-
fired projects are expected and because at least some of these
reconstructions can be expected to incorporate the most efficient
generation technology even in the absence of a standard.
For the same reason, designation of the most efficient generation
technology as the BSER for reconstructed fossil fuel-fired utility
boilers and IGCC units will not have adverse effects on the structure
of the power sector, will not impact fuel diversity, and will not have
adverse effects on the supply of electricity.
d. Incentive for Technological Innovation
As noted above, the case law makes clear that the EPA is to
consider the effect of its selection of BSER on technological
innovation or development, but that the EPA also has the authority to
weigh this factor along with the other ones. When it comes to the
selection of the BSER, the EPA recognizes that reconstructed sources
face inherent constraints that newly constructed greenfield sources do
not; as a result, reconstructed sources present different, and in some
ways more limited, opportunities for technological innovation or
development. In this case, identifying the most efficient generation
technology as the BSER promotes the further extension of that
technology throughout the industry.
While some of the other options that the EPA considered in
determining the BSER for reconstructed utility boilers and IGCC units
would have led to greater opportunities for technology advancement, for
the reasons discussed above, those other options did not meet other
criteria. While the proposed standard is based on the use of the best
available steam cycle, other energy efficiency measures will likely be
developed and used (improved economizers, etc.) and these technologies
will be transferrable to other EGUs.
7. Efficiency Improvements Achieved Through a Combination of Best
Operating Practices and Equipment Upgrades
The EPA also considered whether a combination of best operating
practices and equipment upgrades would qualify as the BSER for a
reconstruction. These measures are discussed in greater detail in
Section VII of this preamble. A reconstruction, because it occurs only
when an owner/operator spends more than 50 percent of the cost of a
replacement unit, generally entails fundamental decisions about what
type of unit to rebuild. For example, one reconstruction occurred
following an explosion at the boiler and resulted in a rebuild of the
entire unit including both the boiler and the accompanying steam
turbine.
Because a reconstruction generally entails rebuilding the unit,
operating practices and equipment upgrades are not applicable as BSER.
Those entail smaller scale changes to the unit that may be expected to
be rebuilt anyway. In addition, the emission reductions that could be
achieved through best operating practices and equipment upgrades are
smaller than the most efficient generation technology.
C. Determination of the Level of the Standard
Once the EPA has determined that a particular system or technology
represents BSER, the EPA must establish an emission standard based on
[[Page 34985]]
that system or technology. To determine an achievable emission
standard, we reviewed the emission rate information submitted by
owners/operators of coal-fired EGUs to the EPA's Clean Air Markets
Division. For reconstructed fossil fuel-fired boiler and IGCC EGUs, the
EPA proposes to find that the best available steam cycle--which qualify
as the BSER--supports a standard of 1,900 lb CO2/MWh-net for
large EGUs (i.e., those with heat input greater than 2,000 MMBtu/h),
and 2,100 lb CO2/MWh-net for small EGUs (i.e., those with a
heat input 2,000 MMBtu/h or less). The DOE/NETL estimates that an IGCC
unit emission rate is comparable to those achieved by a supercritical
coal-fired EGU. Therefore, for both technologies, these levels of the
standard are based on the emission performance that can be achieved by
a large pulverized or CFB coal unit using supercritical steam
conditions and a small unit using subcritical steam conditions.
We are also soliciting comment on whether the emission limit may be
more appropriately set at a different level. Based on the rationale
included in the Technical Support Document (TSD),\85\ we are soliciting
comment on a range of 1,700 to 2,100 lb CO2/MWh-net for
large units and 1,900 to 2,300 lb CO2/MWh-net for small
units. An emission rate of 1,700 lb CO2/MWh-net could
potentially be met by an EGU using advanced ultra-supercritical steam
conditions.\86\
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\85\ ``Best System of Emissions Reduction (BSER) for
Reconstructed Electric Utility Steam Generating Units (EGUs) and
Integrated Gasification Combined Cycle Facilities (IGCC)'' Technical
Support Document available in the rulemaking docket (EPA-HQ-OAR-
2013-0603).
\86\ Advanced ultra-supercritical steam conditions are 700-760
[deg]C (1,290-1,400 [deg]F) and 36 MPa (5,000 psi).
---------------------------------------------------------------------------
We are not currently considering a standard more stringent than
1,700 lb CO2/MWh-net for large units. Available information
indicates that an EGU facility could not meet a standard of 1,600 lb
CO2/MWh-net based on the use of an advanced ultra-
supercritical steam cycle, and instead would be required to implement
partial CCS, co-fire approximately 40 percent natural gas directly in
the boiler, or integrate non emitting or lower emitting technology in
the facility's design (i.e., a hybrid power plant). We are not
currently considering a standard more stringent than 1,900 lb
CO2/MWh-net for small units because available information
indicates that a small EGU facility could only meet a standard of 1,800
lb CO2/MWh-net burning bituminous coal and using the best
available subcritical steam cycle. Modified facilities burning other
coal types would be required to implement partial CCS, co-fire
approximately 10 percent natural gas directly in the boiler, or
integrate non-emitting or lower emitting technology in the facility's
design (i.e., a hybrid power plant).
We are not currently considering a standard less stringent than
2,100 lb CO2/MWh-net for large units because at that level,
the NSPS would not necessarily promote the use of the best available
steam cycle. At an emissions rate of 2,200 lb CO2/MWh, large
EGUs would not be required to use efficient generation technologies
(e.g., they could use subcritical steam conditions). We are not
currently considering a standard less stringent than 2,300 lb
CO2/MWh-net for small units because at that level, the NSPS
would not necessarily promote the use of the best available steam
conditions because many smaller subcritical units are operating well
below 2,300 lb CO2/MWh-net.
D. Compliance Period
The EPA is proposing that sources would be required to meet the
proposed standards on a 12 operating-month rolling basis. The proposed
compliance period requirements and rationale are the same as in the
January 2014 proposal. This section provides a summary of the
rationale. For additional detail, see 79 FR 1481 and 1482.
The 12-operating-month averaging period being proposed is important
because of the inherent variability in power plant GHG emissions rates.
Establishing a shorter averaging period would necessitate establishing
a standard to account for the conditions that result in the lowest
efficiency and therefore the highest GHG emissions rate.
EGU efficiency has a significant impact on the source's GHG
emission rate. EGU efficiency can vary from month to month throughout
the year. For example, high ambient temperature can negatively impact
the efficiency of combustion turbine engines and steam generating
units. As a result, an averaging period shorter than 12 operating-
months would require us to set a standard that could be achieved under
these conditions. This standard could potentially be high enough that
it would not be a meaningful constraint during other parts of the year.
In addition, operation at low load conditions can also negatively
impact efficiency. It is likely that for some short period of time an
EGU will operate at an unusually low load. A short averaging period
that accounts for this operation would again not produce a meaningful
constraint for typical loads.
On the other hand, a 12-operating-month rolling average explicitly
accounts for variable operating conditions, allows for a more
protective standard and decreased compliance burden, allows EGUs to
have and use a consistent basis for calculating compliance (i.e.,
ensuring that 12 operating months of data would be used to calculate
compliance irrespective of the number of long-term outages), and
simplifies compliance for state permitting authorities. The EPA
proposes that it is not necessary to have a shorter averaging period
for CO2 from these sources because the effect of GHGs on
climate change depends on global atmospheric concentrations which are
dependent on cumulative total emissions over time, rather than hourly
or daily emissions fluctuations or local pollutant concentrations.
Unlike for emissions of criteria and hazardous air pollutants, we do
not believe that there are measureable implications to health or
environmental impacts from short-term higher CO2 emission
rates as long as the 12-month average emissions rate is maintained.
VII. Rationale for Emission Standards for Modified Fossil Fuel-Fired
Utility Boilers and IGCC Units
A. Introduction
In this section we explain our rationale for proposing, as the
``best system of emission reduction . . . adequately demonstrated'' for
modified fossil fuel-fired utility boiler and IGCC EGUs, a combination
of best operating practices and equipment upgrades.
We include in this discussion: (1) Our rationale for rejecting
other alternatives as BSER, (2) a description of efficiency
improvements achieved through a combination of best operating practices
and equipment upgrades and our rationale for selecting it as BSER, and
(3) our rationale for co-proposed alternative standards of performance
based on this BSER (including varying the standard depending upon
whether the affected source would be subject to a CAA section 111(d)
plan (or promulgated federal plan) for CO2).
B. Identification of the Best System of Emission Reduction
1. Options Considered
For the same reasons explained above for reconstructed fossil fuel-
fired boiler and IGCC EGUs, the EPA is not proposing the following
options to be BSER for modified fossil fuel-fired utility boiler and
IGCC units: (1) The use of partial CCS, (2) conversion to (or co-firing
with) natural gas, (3) the use of CHP, (4) Hybrid Power Plants, and (5)
[[Page 34986]]
reductions in generation associated with dispatch changes, renewable
generation, and demand side energy efficiency.
In this section, we evaluate two other options for BSER: (1)
Efficiency improvements achieved through the use of the most efficient
generation technology, and (2) efficiency improvements achieved through
a combination of best operating practices and equipment upgrades.
2. Use of the Most Efficient Generation Technology
We considered whether the BSER for modified fossil fuel-fired
utility boilers and IGCC units should be based on the performance of
the most efficient generation technology available, which we believe is
a supercritical \87\ unit (i.e., a SCPC or supercritical CFB boiler)
for large sources, and a subcritical unit for small sources. However,
as was previously noted, the existing fleet of fossil fuel-fired steam-
generating boilers is numerous and diverse in size and configuration
(including steam parameters), and the EPA does not have sufficient
information about the range of configurations that would be necessary
to estimate the cost of upgrading the steam cycle (switching to higher
grade of materials in the furnace, replacement of the steam drum and
conversion to a once through design, etc.) and auxiliary equipment to
the most efficient generating technology. For a given boiler design,
steam pressures and temperatures are limited by the properties of the
materials (boiler tubes, etc.) and cannot be increased without
replacing those components. We do not have sufficient information on
the number of components that would need to be replaced or on the costs
of replacing individual components. Furthermore, we recognize that, in
at least some cases, requiring a unit to meet levels achievable by a
supercritical unit, when it was not originally designed to do so, could
require significant modifications to both the boiler and turbine that
could start to approach the replacement cost for the unit.
---------------------------------------------------------------------------
\87\ 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 improves the efficiency of a steam turbine converting
thermal energy to electricity, which in turn leads to increased
efficiency and a lower emission rate.
---------------------------------------------------------------------------
Unlike in the case of reconstruction explained above, it is the
understanding of the EPA that modifications do not typically involve
the type of boiler rebuilding that would make this an option with
reasonable cost. Consequently, the EPA does not propose to find that
the use of the most efficient generation technology meets the criteria
for the BSER for a uniform nationwide standard of performance.
3. Best Operating Practices and Equipment Upgrades
The second option that EPA considered for modified fossil fuel-
fired utility boilers and IGCC units is a combination of best operating
practices and equipment upgrades. Best operating practices includes
both operating the unit in the most efficient manner for a given
operating condition and replacing worn components in a timely manner.
Equipment upgrades involve replacing existing components with upgraded
ones or a more extensive overhaul of major equipment (turbine or
boiler). We propose to find that this option meets the criteria for
BSER for these EGUs.
In addition, we are co-proposing two alternative standards of
performance reflective of this BSER. In the first co-proposed
alternative, all modified utility boilers and IGCC units will be
required to meet a unit-specific emission standard. In the second co-
proposed alternative, modified sources will be required to meet unit-
specific emission limits that will depend on whether the affected unit
undertakes the modification before it becomes subject to a CAA section
111(d) state plan (or promulgated federal plan), or after it becomes
subject to such a plan. Each variation of the BSER meets the criteria,
which we discuss next. We describe the variations in more detail in the
section concerning the standards of performance, which follows the
discussion of the criteria.
a. Technical Feasibility
A wide range of studies have been performed evaluating the
opportunity to improve the heat rate (or efficiency) \88\ of an
existing power plant without upgrading to the most efficient generation
technology available. These studies are summarized in Chapter 2 of the
TSD, ``GHG Abatement Measures'' \89\ which explains that, while the
studies are different in the level of detail and assumptions, the
results of the studies overall suggest that the U.S. coal-fired EGU
existing fleet is theoretically capable of achieving heat rate
improvements ranging from 9 to 15 percent.
---------------------------------------------------------------------------
\88\ The heat rate is a common way to measure EGU efficiency. As
the efficiency of a fossil fuel-fired EGU is increased, less fuel is
burned per kilowatt-hour (kWh) generated by the EGU. This results in
a corresponding decrease in CO2 and other air pollutant
emissions. Heat rate is expressed as the number of British thermal
units (Btu) or kilojoules (kJ) that are required to generate 1 kWh
of electricity. Lower heat rates are associated with more efficient
fossil fuel-fired EGUs.
\89\ Chapter 2: Heat Rate Improvement at Existing Coal-fired
EGUs, Available in the rulemaking docket. Docket ID: EPA-HQ-OAR-
2013-0603.
---------------------------------------------------------------------------
Many of the detailed engineering studies describe a wide range of
opportunities to improve heat rate including improvements to the: (1)
Materials handling equipment at the plant, (2) economizer, (3) boiler
control systems, (4) soot blowers, (5) air heaters, (6) steam turbine,
(7) feed water heaters, (8) condenser, (9) boiler feed pumps, (10)
induced draft (ID) fans, (11) emission controls, and (12) water
treatment systems.
As the studies show, these types of upgrades have been made at a
wide range of power plants, demonstrating their technical feasibility.
b. CO2 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.
c. Costs
The EPA reviewed the engineering studies available in the
literature and selected the Sargent & Lundy 2009 study \90\ as the
basis for its assessment of heat rate improvement potentials from
equipment and system upgrades. We focused on thirteen heat rate
improvement methods discussed by Sargent & Lundy and listed in Table 2-
13 of the ``GHG Abatement Measures'' TSD. We used the average of the
estimated costs (in $/kW) for each method to develop the cost-ranked
list of heat rate improvement methods (listed by costs from lowest to
highest in the table). The first nine items in Table 2-13 contribute
about 15 percent of the total average $/kW cost for all items. We
believe it is reasonable to consider those nine no-cost and low-cost
heat rate improvement methods as belonging in the category of what has
been described above as best practices. The remaining four methods are
higher cost heat rate improvement opportunities that we believe
properly fall into the category discussed here as equipment or system
upgrades. Using an average of the ranges of potential Btu improvements
estimated by Sargent & Lundy for the
[[Page 34987]]
four upgrade methods, equipment or system upgrades could provide a 4
percent heat rate improvement if all were applied on an EGU that has
not already made those upgrades.
---------------------------------------------------------------------------
\90\ Coal-fired Power Plant Heat Rate Reductions, SL-009597
Final Report, January 2009. Available in the rulemaking docket and
at http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.
---------------------------------------------------------------------------
The 2009 Sargent & Lundy study included an estimated range of heat
rate improvement, and the associated range of capital cost for each
heat rate improvement method, for units ranging in size from 200 MW to
900 MW. If the methods and unit sizes are combined, as though they were
all applied on a single EGU, the range of Sargent & Lundy estimated Btu
reductions (412 to 1,205 Btu) resulted in associated combined capital
costs in the range of $40-150/kW. The wide ranges of estimated Btu
reductions and capital costs are indicative of the wide range of real
differences in the many details of site specific EGU designs, fuel
types, age, size, ambient conditions, current physical condition, etc.
The EPA's analysis, therefore, assumed $100/kW as a representative
combined heat rate improvement capital cost to achieve whatever Btu
reduction is possible at an average site.
The EPA heat rate improvement analysis resulted in the following
summary conclusions:
Some degree of heat rate improvement is already economic
for high heat rate--high coal cost EGUs.
If a fleet-wide average 6 percent heat rate is technically
feasible, it would also be economic on the basis of fuel savings alone,
before consideration of the value of the associated CO2
emission reductions, on a fleet-wide basis at today's coal prices if
the associated average capital cost is about $75/kW or less.
Even at a capital cost of $100/kW and an Integrated
Planning Model (IPM) projected 2020 coal price of $2.62/MMBtu, the
fleet-wide cost of CO2 reduction via 6 percent heat rate
improvement would be a relatively low $7.7/tonne of CO2
avoided.
Based on this assessment, the EPA determines that the unit-specific
emission limit based on historical best performance (which captures the
good operating practice at the unit) coupled with an additional 2
percent reduction (which captures minimum opportunities for additional
heat rate improvements from equipment and system upgrades) can be
achieved at reasonable cost.
The EPA's modeling tools do not allow projection of any specific
number of utility boilers and IGCC units that are expected to trigger
the NSPS modification provision. As discussed below, however, the EPA
believes there are likely to be few. Hence, a unit-specific standard of
performance will not have significant impacts on nationwide electricity
prices or on the structure of the nation's energy sector.
d. Incentive for Technological Development
As noted previously, the case law makes clear that the EPA is to
consider 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 proposed standards promote technological
development by promoting further development and market penetration of
equipment upgrades and process changes that improve plant efficiency.
C. Determination of the Level of the Standard
Once the EPA has determined that a particular system or technology
represents BSER, the EPA must establish an emission standard based on
that technology.
Because the existing fossil fuel-fired steam-generating boilers are
numerous and diverse in size and configuration--and because the EPA has
no way to predict which of those sources may modify--developing a
single standard for all modified utility boilers or IGCC units is
challenging. The EPA considered a sub-categorization approach, but, as
is detailed in Chapter 2 of the TSD, ``GHG Abatement Measures,''
analysis of available data did not support a number of potential sub-
categorization options--such as unit size, type or age--that
intuitively seemed logical.
In this action, the EPA is co-proposing two alternative standards
of performance for modified utility boilers and IGCC units. In the
first co-proposed alternative, all modified sources would meet a unit-
specific emission limit. In the second co-proposed alternative, the
modified source would be required to meet a unit-specific emission
limit that will depend on the timing of the modification.
For utility boilers or IGCC units undertaking modifications, the
EPA is proposing that the BSER has two components: (1) That the source
operates consistently with its own best demonstrated historical
performance; and (2) that the source implements other available heat
rate improvement measures including upgrading of some components of the
unit. Specifically, for the first co-proposed alternative, a modified
utility boiler or IGCC unit would be required to maintain an emission
rate that equals the unit's best demonstrated annual performance during
the years from 2002 to the year the modification occurs, multiplied by
98 percent (i.e., a 2 percent further reduction), but not to be more
stringent than the emission limit that would be applicable to the
source if it were a reconstructed source. Consistent with the heat rate
improvement analysis in the CAA section 111(d) proposal, we selected
2002 to assure we captured the impacts of maintenance cycles and year
to year natural variability in CO2 emission rate performance
to capture the best historical performance. We solicit comment on
whether we should select a year prior to or subsequent to 2002 for
purposes of determining the best historical emission rate.
As mentioned, the EPA is also co-proposing standards of performance
that are dependent on the timing of the modification. Specifically, a
source that modifies prior to becoming subject to a CAA section 111(d)
plan would be required to meet an emission limit that is determined
using the same methodology described in the first co-proposed
alternative. The modified utility boiler or IGCC unit would be required
to maintain an emission rate that equals the unit's best demonstrated
annual performance during the years from 2002 to the year the
modification occurs, multiplied by 98 percent (i.e., a 2 percent
further reduction based on equipment upgrades), but not to be more
stringent than the emission limit applicable to a corresponding
reconstructed source. The EPA is proposing that units undertaking
modifications after they become subject to a CAA section 111(d) plan
would be required to meet a unit-specific emission limit that is
determined by the CAA section 111(d) implementing authority from an
assessment to identify energy efficiency improvement opportunities for
the affected source. This standard is informed by the fact that, as we
discuss in the Legal Memorandum,\91\ these sources would remain subject
to the requirements of the CAA section 111(d) plan even after
modifying.
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\91\ Legal Memorandum available in rulemaking docket ID: EPA-HQ-
OAR-20913-0602.
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The EPA also solicits comment on whether the period of best
historical performance should be the years from
[[Page 34988]]
2002 to the time when the unit becomes subject to the CAA section
111(d) plan, rather than to the time of the modification.
We are considering different standards applicable before and after
a source becomes subject to a CAA section 111(d) plan because we are
concerned that, as a result of implementation of state plans, the
additional 2 percent efficiency improvement may be unachievable for a
substantial number of sources that make efficiency improvements as part
of a CAA section 111(d) plan. Specifically, we are concerned that where
a state imposes efficiency improvements on a source, or where a source
undertakes efficiency improvements to comply with the state plan, it
will have already attained the maximum level of efficiency improvement
that is achievable for that unit. As a result, the source would be
unable to undertake additional improvements to meet the highest level
of efficiency plus the additional 2 percent reduction (based on
equipment upgrades) that we are considering. We recognize that in some
states, CAA section 111(d) plans may require no or limited efficiency
improvements on a specific unit. In such cases, we expect such a unit
to be able to achieve the standard we are considering for sources that
modify prior to becoming subject to a CAA section 111(d) plan.
Accordingly, for such sources, we anticipate that the audit process
that we are considering will result in an emission rate consistent with
the highest level of efficiency plus 2 percent (based on equipment
upgrades) that we are considering for sources that modify prior to
becoming subject to a state plan.
For this co-proposal, the EPA is proposing that the date for
determining whether a unit is subject to a CAA section 111(d) plan is
the date that the plan is initially submitted to the EPA. Although a
state's plan is still subject to the EPA's approval, we believe this
represents a reasonable point to determine that a source is subject to
a CAA section 111(d) plan, because at that point the operator would
know what requirements the source would have to meet, and would have
confirmation of the state's intention to submit that plan to meet the
requirements of CAA section 111(d). We are also taking comment on a
range of other dates including: June 30, 2016 (the original state plan
submission deadline), the date that the state promulgates its rule, the
date the EPA approves the rule, and January 1, 2020 (the proposed
initial compliance date for state plans).
For a source modifying after a CAA section 111(d) plan becomes
applicable, a unit-specific emission standard will be determined by the
CAA section 111(d) implementing authority from the results of an energy
efficiency audit to identify technically feasible heat rate improvement
opportunities at the affected source.
An energy efficiency audit, or assessment, is an in-depth energy
study identifying all energy conservation measures appropriate for a
facility given its operating parameters. An energy audit is a process
that involves a thorough examination of potential savings from energy
efficiency improvements, pollution prevention, and productivity
improvement. It leads to the reduction of emissions of pollutants
through process changes and other efficiency modifications. Besides
reducing operating and maintenance costs, improving energy efficiency
results in decreased fuel use which results in a corresponding decrease
in emissions. Such an energy assessment requirement is included in the
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters (40 CFR part 63, subpart DDDDD).
We propose that the energy assessment would include, at a minimum,
the following elements:
1. A visual inspection of the facility to identify steam leaks or
other sources of reduced efficiency;
2. a review of available engineering plans and facility operation
and maintenance procedures and logs; and
3. a comprehensive report detailing the ways to improve efficiency,
the cost of specific improvements, benefits, and the time frame for
recouping those investments.
We propose that the energy assessment be conducted by energy
professionals or engineers that have expertise in evaluating energy
systems. We specifically request comment on: (1) Whether energy
assessor certification should be required; (2) if certification were
required, what the basis of the certification should be; and (3)
whether there are organizations that provide certification of
specialists in evaluating energy systems. We propose that the CAA
section 111(d) implementing authority will determine a unit-specific
emission limit based on the results of the energy efficiency audit and
we also request comment on: (1) Whether the rule should require
implementation of identified energy efficiency improvements; and (2) if
implementation were required, what the determining factor(s) for
requiring the improvements should be. Finally, we request comment on:
(1) Whether an energy efficiency audit recently completed (e.g., within
3 years of the modification) that meets or is amended to meet the
rule's energy audit requirements can be used to satisfy the energy
efficiency audit requirement and, in such instances, whether energy
assessor approval and qualification requirements should be waived; and
(2) whether facilities that operate under an energy management program
compatible to ISO 50001 \92\ that includes the affected units can be
used to satisfy the energy efficiency audit requirement.
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\92\ ISO 50001 is a specification created by the International
Organization for Standardization (ISO) for an energy management
system. The standard specifies the requirements for establishing,
implementing, maintaining and improving an energy management system,
whose purpose is to enable an organization to follow a systematic
approach in achieving continual improvement of energy performance,
including energy efficiency, energy security, energy use and
consumption.
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The EPA also seeks comment on whether, and under what
circumstances, the energy audit methodology--i.e., determining the
emission limit from the results of the energy audit--should be an
option for sources that modify before becoming subject to a CAA section
111(d) plan. In particular, the EPA seeks comment on whether the audit
methodology should be an option for all units that modify, prior to
becoming subject to a CAA section 111(d) plan, or if it should be an
option for sources that provide evidence that significant energy
efficiency improvements were implemented after 2002 but before the
modification.
D. Compliance Period
The EPA is proposing that sources would be required to meet the
proposed standards on a 12 operating-month rolling basis. The
compliance period requirements and rationale being proposed for
modified boilers and IGCC units are the same as the requirements and
rationale being proposed for reconstructed utility boilers and IGCC
units (see section VII.D. of this preamble), as well as the compliance
period requirements and rationale in the January 2014 proposal. For
additional detail, see 79 FR 1481 and 1482.
VIII. Rationale for Emission Standards for Reconstructed Natural Gas-
Fired Stationary Combustion Turbines
A. Identification of the Best System of Emission Reduction
The EPA evaluated three different control technology configurations
as potentially representing the ``best system of emissions reductions .
. .
[[Page 34989]]
adequately demonstrated'' for reconstructed natural gas-fired
stationary combustion turbines: (1) NGCC technology with CCS, (2) NGCC
technology by itself, and (3) high efficiency simple cycle
aeroderivative turbines.
1. NGCC Technology With CCS
We are not proposing to find that CCS technology is the BSER for
reconstructed natural gas-fired stationary combustion turbines for the
same reasons we are not proposing to find that CCS technology is the
BSER for steam-generating units: an owner/operator of an existing
source that is undertaking reconstruction has challenges not faced when
building a new NGCC unit because the existing unit may be located at a
site with space constraints that would make installation of CCS
problematic. We do not have sufficient information about the universe
of existing sources to be able to determine the costs of CCS, in light
of these space constraints.
2. NGCC Technology
For the reasons explained below, we find NGCC technology to be BSER
for reconstructed natural gas-fired stationary combustion turbines.
a. Technical Feasibility
NGCC technology is widely used in the power sector today. There are
hundreds of NGCCs in the U.S. and in other countries.
b. Emission Reductions
NGCC technology is the most efficient technology for natural-gas
fired stationary combustion turbines. It has an emission rate that is
approximately 25 percent lower than the most effective main alternative
technology, which is the simple cycle combustion turbine.
c. Cost
NGCC technology is one of the lowest cost forms of baseload and
intermediate load electricity generation. Even in the case of a simple
cycle turbines that operates at a capacity factor of greater than one-
third, the cost of replacement with a NGCC unit is likely to be cost
effective based on consideration of fuel savings alone. In the proposal
for newly constructed sources (79 FR 1459), we explained that at
capacity factors of greater than 20 percent, the LCOE of a combined
cycle unit would be less than the LCOE of a simple cycle turbine.
Because the cost of adding a HRSG to a simple cycle turbine is less
than the cost of building a full combined cycle unit, the same holds
true with a comparison of replacing a simple cycle turbine and
upgrading it to a combined cycle turbine. Furthermore, if the owner/
operator of a simple cycle turbine wishes to make a modification, they
could do so--without having to comply with the requirements of this
proposal--by maintaining an average annual capacity factor of less than
one-third. As we explained in the proposal, few simple cycle turbines
operate at an annual capacity factor of greater than one-third. (79 FR
1459)
d. Incentive for Technology Innovation
We recognize that because NGCC technology is already the state of
the art technology, and is widely used, for natural gas stationary
combustion turbines, identifying this technology as the BSER may not
provide significant incentive for technology innovation. However, we
are according less weight to this factor in this case because we
consider this technology to be highly efficient and because the only
more stringent alternative--CCS--is one that we are not proposing to
identify as BSER, for reasons discussed above.
3. High Efficiency Simple Cycle Aeroderivative Turbines
The use of high efficiency simple cycle aeroderivative turbines
does not provide emission reductions when compared to the NGCC
technology. According to the Annual Energy Outlook (AEO) 2013 emissions
rate information, advanced simple cycle combustion turbines have a base
load rating CO2 emissions rate of 1,150 lb CO2/
MWh-gross, which is higher than the base load rating emission rates of
830 and 760 lb CO2/MWh-gross for the conventional and
advanced NGCC model facilities, respectively. In addition, simple cycle
technology is more expensive than NGCC technology; and it does not
further develop or promote use of the most advanced emission control
technology. For these reasons, we do not find it to be the BSER for
reconstructed natural gas-fired stationary combustion turbines.
B. Determination of the Standards of Performance
The proposed standards of performance for reconstructed natural
gas-fired stationary combustion turbines, which are based on BSER being
efficient NGCC technology, are consistent with those that were proposed
for newly constructed natural gas-fired stationary combustion turbine
sources, as described in the January 2014 proposal (79 FR 1430). The
EPA intends--when it takes final action on this proposal and on the
January 2014 proposal for newly constructed sources, respectively--to
finalize the same standards for newly constructed, modified and
reconstructed natural gas-fired stationary combustion turbines. The EPA
solicits comment on this approach and on any reasons why these sources
should not have consistent standards.
In the January 2014 proposal, the EPA indicated that it had
reviewed the CO2 emissions data from 2007 to 2011 for
natural gas-fired (non-CHP) combined cycle units that commenced
operation on or after January 1, 2000, and that reported complete
electric generation data, including output from the steam turbine, to
the EPA. A more detailed description of the emissions data analysis is
included in a TSD in the docket for that rulemaking \93\ and is also
included in the docket for this proposal.
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\93\ ``Standard of Performance for Natural Gas-Fired Combustion
Turbines'' Technical Support Document, Docket ID: EPA-HQ-OAR-2013-
0495.
---------------------------------------------------------------------------
Consistent with the January 2014 proposal, the EPA proposes to
subcategorize the turbines into the same two size-related subcategories
currently in subpart KKKK for standards of performance for the
combustion turbine criteria pollutants. These subcategories are based
on whether the design heat input rate to the turbine engine is either
850 MMBtu/h or less, or greater than 850 MMBtu/h. We further propose to
establish different standards of performance for these two
subcategories.
This subcategorization has a basis in differences in several types
of equipment used in the differently sized units, which affect the
efficiency of the units. Because of these differences in equipment and
inherent efficiencies of scale, the smaller capacity NGCC units (850
MMBtu/h and smaller) are less efficient than the larger units (larger
than 850 MMBtu/h). We are proposing standards of performance of 1,000
lb CO2/MWh-gross for the large units and 1,100 lb
CO2/MWh-gross for the small units; and we are requesting
comment on a range of 950 to 1,100 lb CO2/MWh-gross for the
large turbine subcategory and 1,000 to 1,200 lb CO2/MWh-
gross for the small turbine subcategory.
IX. Rationale for Emission Standards for Modified Natural Gas-Fired
Stationary Combustion Turbines
A. Identification of the Best System of Emission Reduction
We believe that the analysis above with regards to reconstructed
natural gas-fired stationary combustion turbines is also applicable to
modified natural gas-fired stationary combustion
[[Page 34990]]
turbines.\94\ The only potential difference that the EPA has identified
is consideration of cost because the actions that could trigger
modification are less extensive changes at the facility. We have
considered four different scenarios that could trigger the modification
provisions: (1) Modification of an older (e.g., pre-2000) combined
cycle unit, (2) modification of a newer (e.g., a built in 2000 or
later) combined cycle unit, (3) upgrading of a simple cycle turbine to
a combined cycle unit, and, (4) modification to a simple cycle turbine
other than upgrading to a combined cycle unit. As described below, in
each of these cases, we believe that NGCC is cost-effective.
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\94\ Technical Support Document ``Standard of Performance for
Natural Gas-Fired Combustion Turbines'' available in the rulemaking
docket. Docket ID: EPA-HQ-OAR-2013-0603.
---------------------------------------------------------------------------
1. Modifications to an Older (e.g., Pre-2000) Combined Cycle Unit
Because the performance of combined cycle technology has improved
so significantly since 2000, we believe that upgrading to current
technology is likely to be cost effective when one considers a
combination of fuel savings, and performance benefits (the ability to
start up the unit more quickly and operate more efficiently over a
wider range of loads).
2. Modifications to a Newer Combined Cycle Unit
These modifications are likely to be made to return the unit to
close to its original operating performance, would be consistent with
the requirements of today's proposal, and are not likely to
significantly increase the cost of the project.
3. Upgrading a Simple Cycle Turbine to a Combined Cycle Unit
These modifications would be made to upgrade the efficiency of the
unit, are consistent with the requirements of today's proposal, and are
not likely to significantly increase the cost of the project.
4. Modifications to a Simple Cycle Turbine Other Than Upgrading to
Combined Cycle
As was noted above--and in the proposal for newly constructed
sources--when operating at higher capacity factors, the use of combined
cycle technology instead of simple cycle technology pays for itself in
fuel savings alone.
For these reasons, we find the use of NGCC technology to be BSER
for modified natural gas-fired combustion turbines.
B. Determination of the Standards of Performance
We propose that the same standards of performance described above
for reconstructed natural gas-fired stationary combustion turbines are
also appropriate for modified natural gas-fired stationary combustion
turbines.
We are requesting comment on a range of 950 to 1,100 lb
CO2/MWh-gross (430 to 500 kg CO2/MWh) for the
large turbine subcategory and 1,000 to 1,200 lb CO2/MWh-
gross (450 to 540 kg CO2/MWh) for the small turbine
subcategory.
For sources that are subject to a CAA section 111(d) plan, the EPA
is also soliciting comment on whether the sources should be allowed to
elect, as an alternative to the otherwise applicable numeric standard,
to meet a unit-specific emission standard, determined by the CAA 111(d)
implementing authority, based on implementation of identified energy
efficiency improvement opportunities applicable to the source.
X. Impacts of the Proposed Action \95\
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\95\ Note that the EPA does not project any difference in the
impacts between the alternative to regulate sources under subparts
Da and KKKK versus regulating them under new subpart TTTT.
---------------------------------------------------------------------------
As explained in the RIA for this proposed rule, the EPA expects few
sources will trigger either the NSPS modification or reconstruction
provisions that we are proposing today. Because the EPA is aware of a
limited number of units that have notified the EPA of NSPS
modifications in the past, we have conducted an illustrative analysis
of the costs and benefits for a representative unit. Based on the
analysis, which is presented in Chapter 9 of the RIA, the EPA expects
that this proposed rule will result in potential CO2
emission changes, quantified benefits, and costs for a unit that was
subject to the modification provision. In this illustrative example
based on a hypothetical 500 MW coal-fired unit, we estimate costs, net
of fuel savings, of $0.78 million to $4.5 million (2011$) and
CO2 reductions of 133,000 to 266,000 tons in 2025. The
combined climate benefits from reductions in CO2 and health
co-benefits from reductions in SO2, NOX, and
PM2.5 total $18 to $33 million (2011$) at a 3 percent
discount rate for emission reductions in 2025 for the lowest emission
reductions scenario and $35 to $65 million (2011$) at a 3 percent
discount rate for emission reductions in 2025 for the highest emission
reduction scenario.\96\
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\96\ For purposes of this summary, we present climate benefits
from CO2 that were estimated using the model average SCC
at a 3 percent discount rate. We emphasize the importance and value
of considering the full range of SCC values, however, which include
the model average at 2.5 and 5 percent, and the 95th percentile at 3
percent. Similarly, we summarize the health co-benefits in this
synopsis at a 3 percent discount rate. We provide estimates based on
additional discount rates in the RIA.
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A. What are the air impacts?
As explained immediately above, the EPA expects few modified or
reconstructed EGUs in the period of analysis. Because there have been a
limited number of units that have notified the EPA of NSPS
modifications in the past, we have conducted an illustrative analysis
of the impacts for a hypothetical unit that triggered the modification
provision. For this illustrative example, we estimate CO2
reductions of 133,000 to 266,000 tons in 2025. Additionally, we
estimate co-reductions of SO2, NOX, and
PM2.5.
B. What are the energy impacts?
This proposed rule is not anticipated to have significant impacts
on the supply, distribution, or use of energy. As previously stated,
the EPA expects few reconstructed or modified EGUs in the period of
analysis and the nationwide cost impacts to be minimal as a result.
C. What are the compliance costs?
The EPA believes this proposed rule will have minimal compliance
costs associated with it, because, as previously stated, the EPA
expects few modified or reconstructed EGUs in the period of analysis.
Because the EPA is aware of a limited number of units that have
notified the EPA of NSPS modifications in the past, we have conducted
an illustrative analysis of the costs and benefits for a representative
unit. Based on the analysis, which is presented in Chapter 9 of the
RIA, the EPA estimates compliance costs, net of fuel savings, of $0.78
to $4.5 million (2011$) in 2025 for a hypothetical unit that triggered
the modification provisions.
D. How will this proposal contribute to climate change protection?
As previously explained, the special characteristics of GHGs make
it important to take action to control the largest emissions categories
without delay. Unlike most traditional air pollutants, GHGs persist in
the atmosphere for time periods ranging from decades to millennia,
depending on the gas. Fossil fuel-fired power plants emit more GHG
emissions than any other stationary source category in the U.S.
This proposed rule would limit GHG emissions from modified fossil
fuel-
[[Page 34991]]
fired electric utility steam generating units (utility boilers and IGCC
units) to levels consistent with the unit's best potential performance.
GHG emissions from reconstructed utility boilers and IGCC units would
be limited to levels consistent with modern, efficient generating
technology (e.g., supercritical steam cycles). While the EPA expects
few units to trigger the modification or reconstruction provisions,
this proposed rule would limit GHG emissions from any modified and
reconstructed stationary combustion turbines to levels consistent with
modern, efficient natural gas combined cycle technology. As a result,
this proposed rule will contribute to the actions required to slow or
reverse the accumulation of GHG concentrations in the atmosphere, which
is necessary to protect against projected climate change impacts and
risks.
E. What are the economic and employment impacts?
As previously stated, the EPA anticipates few units will trigger
the proposed modification or reconstruction provisions. For this
reason, the proposed standards will result in minimal emission
reductions, costs, or quantified benefits by 2025. There are no
macroeconomic or employment impacts expected as a result of these
proposed standards.
F. What are the benefits of the proposed standards?
As previously stated, the EPA anticipates few units will trigger
the proposed modification or reconstruction provisions. Because there
have been a limited number of units that have notified the EPA of NSPS
modifications in the past, we have conducted an illustrative analysis
of the costs and benefits for a representative unit. Based on the
analysis, which is presented in Chapter 9 of the RIA, the combined
climate benefits from reductions in CO2 and health co-
benefits from reductions in SO2, NOX, and
PM2.5 total $18 to $33 million (2011$) at a 3 percent
discount rate for emission reductions in 2025 for the lowest emission
reductions scenario and $35 to $65 million (2011$) at a 3 percent
discount rate for emission reductions in 2025 for the highest emission
reduction scenario.\97\
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\97\ For purposes of this summary, we present climate benefits
from CO2 that were estimated using the model average
social cost of carbon (SCC) at a 3 percent discount rate. We
emphasize the importance and value of considering the full range of
SCC values, however, which include the model average at 2.5 percent
and 5 percent, and the 95th percentile at 3 percent. Similarly, we
summarize the health co-benefits in this synopsis at a 3 percent
discount rate. We provide estimates based on additional discount
rates in the RIA.
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XI. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it ``raises novel
legal or policy issues arising out of legal mandates.'' Accordingly,
the EPA submitted this action to the OMB for review under Executive
Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes
made in response to the OMB recommendations have been documented in the
docket for this action. In addition, the EPA prepared an analysis of
the potential costs and benefits associated with this action. This
analysis is contained in Chapter 9 of the Regulatory Impact Analysis
for Emission Guidelines for Greenhouse Gas Emissions from Existing
Stationary Sources: Electric Utility Generating Units.
As explained in the RIA for this proposed rule, in the period of
analysis (through 2025) the EPA anticipates few sources will trigger
either the modification or the reconstruction provisions proposed.
Because there have been a few units that have notified the EPA of NSPS
modifications in the past, we have conducted an illustrative analysis
of the costs and benefits for a representative unit that is included in
Chapter 9 of the RIA.
B. Paperwork Reduction Act
This proposed action is not expected to impose an information
collection burden under the provisions of the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. Burden is defined at 5 CFR 1320.3(b). As
previously stated, the EPA expects few modified or reconstructed EGUs
in the period of analysis. Specifically, the EPA believes it unlikely
that fossil fuel-fired electric utility steam generating units (utility
boilers and IGCC units) or stationary combustion turbines will take
actions that would constitute modifications or reconstructions as
defined under the EPA's NSPS regulations. Accordingly, this proposed
action is not anticipated to impose any information collection burden
over the 3-year period covered by this Information Collection Request
(ICR). We have estimated, however, the information collection burden
that would be imposed on an affected EGU if it was modified or
reconstructed. The information collection requirements in this proposed
rule have been submitted for approval to the Office of Management and
Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
The ICR document prepared by the EPA has been assigned the EPA ICR
number 2465.03.
The EPA intends to codify the standards of performance in the same
way for both this proposed action and the January 2014 proposal for
newly constructed sources and is proposing the same recordkeeping and
reporting requirements that were included in the January 2014
proposal.\98\ See 79 FR 1498 and 1499. Although not anticipated, if an
EGU were to modify or reconstruct, this proposed action would impose
minimal information collection burden on affected sources beyond what
those sources would already be subject to under the authorities of CAA
parts 75 and 98. The 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
potential energy metering modifications to comply with net energy
output based emission limits proposed in this action and certain
reporting costs, which are mandatory for all owners/operators subject
to CAA section 111 national emission standards, there would be no new
information collection costs, as the information required by this
proposed rule is already collected and reported by other regulatory
programs. The recordkeeping and reporting requirements are specifically
authorized by CAA section 114 (42 U.S.C. 7414). All information
submitted to the EPA pursuant to the recordkeeping and reporting
requirements for which a claim of confidentiality is made is
safeguarded according to Agency policies set forth in 40 CFR part 2,
subpart B.
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\98\ The information collection requirements in the January 2014
proposal have been submitted for approval to the OMB under the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR document
prepared by the EPA for the January 2014 proposal has been assigned
the EPA ICR number 2465.02.
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Although, as stated above, the EPA expects few sources will trigger
either the NSPS modification or reconstruction provisions that we are
proposing, if an EGU were to modify or reconstruct during the 3-year
period covered by this ICR, it is likely that an EGU's energy metering
equipment would need to be
[[Page 34992]]
modified to comply with proposed net energy output based CO2
emission limits. Specifically, the EPA estimates that it would take
approximately 3 working months for a technician to retrofit existing
energy metering equipment to meet the proposed net energy output
requirements. In addition, after modifications are made that enable a
facility to measure net energy output, each EGU's Data Acquisition
System (DAS) would need to be upgraded to accommodate reporting of net
energy output rate based emissions. A modified or reconstructed EGU
would be required to prepare a quarterly summary report, which includes
reporting of emissions and downtime, every 3 months. The reporting
burden for such a unit (averaged over the first 3 years after the
effective date of the standards) is estimated to be $17,217 and 205
labor hours. Estimated cost burden is based on 2013 Bureau of Labor
Statistics (BLS) labor cost data. Average burden hours per response are
estimated to be 47.3 hours and the average number of annual responses
over the 3-year ICR period is 4.33 per year. Burden is defined at 5 CFR
1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2013-0603. Submit any comments related to the ICR to the EPA and
OMB. See ADDRESSES section at the beginning of this proposed rule for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Officer for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after June 18, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by July 18, 2014.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small
entities, small entity is defined as:
(1) A small business that is defined by the SBA's regulations at 13
CFR 121.201 (for the electric power generation industry, the small
business size standard is an ultimate parent entity with less than 750
employees.);
(2) a small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
(3) a small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.
After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
The EPA expects few modified utility boilers, IGCC units, or
stationary combustion turbines 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.
Because there have been a limited number of units that have
notified the EPA of NSPS modifications in the past, the RIA for this
proposed rule includes an illustrative analysis of the costs and
benefits for a representative unit.
Based on the analysis, the EPA estimates that this proposed rule
could result in CO2 emission changes, quantified benefits,
or costs for a hypothetical unit that triggered the modification
provision. However, we do not anticipate this proposed rule would
impose significant costs on those sources, including any that are owned
by small entities.
In addition, the EPA expects few reconstructed fossil fuel-fired
electric utility steam generating units (utility boilers and IGCC
units) or 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. Due to the limited data available on reconstructions, it
is not possible to conduct a representative illustrative analysis of
what costs and benefits might result from this proposal in the unlikely
case that a unit were to reconstruct. However, based on the low number
of previous reconstructions and the BSER determination based on the
most efficient available generating technology, we would expect this
proposal to result in no significant CO2 emission changes,
quantified benefits, or costs for NSPS reconstructions. Accordingly,
there are no anticipated economic impacts as a result of the proposed
standards for reconstructed EGUs.
Nevertheless, the EPA is aware that there is substantial interest
in the proposed rule among small entities (municipal and rural electric
cooperatives). As summarized in section II.G. of this preamble, the EPA
has conducted an unprecedented amount of stakeholder outreach. As part
of that outreach, agency officials participated in many meetings with
individual utilities as well as meetings with electric utility
associations. Specifically, the EPA Administrator, Gina McCarthy,
participated in separate meetings with both the National Rural Electric
Cooperative Association (NRECA) and the American Public Power
Association (APPA). The meetings brought together leaders of the rural
cooperatives and public power utilities from across the country. The
Administrator discussed and exchanged information on the unique
challenges, in particular the financial structure, of NRECA and APPA
member utilities. A detailed discussion of the stakeholder outreach is
included in the preamble to the emission guidelines for existing
affected electric utility generating units being proposed in a separate
action.
In addition, as described in the RFA section of the preamble to the
proposed standards of performance for GHG emissions from new EGUs (79
FR 1499 and 1500), the EPA conducted outreach to representatives of
small entities while formulating the provisions of the proposed
standards. Although only new EGUs would be affected by those proposed
standards, the outreach regarded planned actions for newly constructed,
reconstructed, modified and existing sources.
While formulating the provisions of this proposed rule, the EPA
considered the input provided over the course of the stakeholder
outreach. We invite comments on all aspects of this proposal
[[Page 34993]]
and its impacts, including potential impacts on small entities.
D. Unfunded Mandates Reform Act
This proposed rule does not contain a federal mandate that may
result in expenditures of $100 million or more for state, local and
tribal governments, in the aggregate, or the private sector in any one
year. As previously stated, the EPA expects few modified or
reconstructed fossil fuel-fired electric utility steam generating units
(utility boilers and IGCC units) or stationary combustion turbines in
the period of analysis. Accordingly, this proposed rule is not subject
to the requirements of sections 202 or 205 of UMRA.
This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments.
In light of the interest among governmental entities, the EPA
initiated consultations with governmental entities while formulating
the provisions of the proposed standards for newly constructed EGUs.
This outreach regarded planned actions for newly constructed,
reconstructed, modified and existing sources. As described in the UMRA
discussion in the preamble to the proposed standards of performance for
GHG emissions from newly constructed EGUs (79 FR 1500 and 1501), the
EPA consulted with the following 10 national organizations representing
state and local elected officials: (1) National Governors Association;
(2) National Conference of State Legislatures; (3) Council of State
Governments; (4) National League of Cities; (5) U.S. Conference of
Mayors; (6) National Association of Counties; (7) International City/
County Management Association; (8) National Association of Towns and
Townships; (9) County Executives of America; and (10) Environmental
Council of States. On February 26, 2014, the EPA re-engaged with those
governmental entities to provide a pre-proposal update on the emission
guidelines for existing EGUs and emission standards for modified and
reconstructed EGUs.
While formulating the provisions of these proposed standards, the
EPA also considered the input provided over the course of the extensive
stakeholder outreach conducted by the EPA (see section II.G. of this
preamble).
E. Executive Order 13132, Federalism
This proposed action does not have federalism implications. It
would not have substantial direct effects on the states, on the
relationship between the national government and the states, or on the
distribution of power and responsibilities among the various levels of
government, as specified in Executive Order 13132. This proposed action
would not impose substantial direct compliance costs on state or local
governments, nor would it preempt state law. Thus, Executive Order
13132 does not apply to this action.
However, as described in the Federalism discussion in the preamble
to the proposed standards of performance for GHG emissions from newly
constructed EGUs (79 FR 1501, January 8, 2014), the EPA consulted with
state and local officials in the process of developing the proposed
standards for newly constructed EGUs. This outreach regarded planned
actions for newly constructed, reconstructed, modified and existing
sources. The EPA engaged 10 national organizations representing state
and local elected officials. The UMRA discussion in the preamble to the
proposed standards of performance for GHG emissions from newly
constructed EGUs (79 FR 1500 and 1501) includes a description of the
consultation. In addition, on February 26, 2014, the EPA re-engaged
with those governmental entities to provide a pre-proposal update on
the emission guidelines for existing EGUs and emission standards for
modified and reconstructed EGUs. While formulating the provisions of
these proposed standards, the EPA also considered the input provided
over the course of the extensive stakeholder outreach conducted by the
EPA (see section II.G. of this preamble). In the spirit of Executive
Order 13132 and consistent with the EPA policy to promote
communications between the EPA and state and local governments, the EPA
specifically solicits comment on this proposed action from state and
local officials.
F. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It would neither
impose substantial direct compliance costs on tribal governments, nor
preempt Tribal law. This proposed rule would impose requirements on
owners and operators of reconstructed and modified EGUs. The EPA is
aware of three coal-fired EGUs located in Indian country but is not
aware of any EGUs owned or operated by tribal entities. The EPA notes
that this proposal would only affect existing sources such as the three
coal-fired EGUs located in Indian country, if those EGUs were to take
actions constituting modifications or reconstructions as defined under
the EPA's NSPS regulations. However, as previously stated the EPA
expects few modified or reconstructed EGUs in the period of analysis.
Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, the
EPA conducted outreach to tribal environmental staff and offered
consultation with tribal officials in developing this action. Because
the EPA is aware of tribal interest in carbon pollution standards for
the power sector, prior to proposal of GHG standards for newly
constructed power plants, the EPA offered consultation with tribal
officials early in the process of developing the proposed regulation to
permit them to have meaningful and timely input into its development.
The EPA's consultation regarded planned actions for newly constructed,
reconstructed, modified, and existing sources. The Consultation and
Coordination with Indian Tribal Governments discussion in the preamble
to the proposed standards of performance for GHG emissions from newly
constructed EGUs (79 FR 1501) includes a description of that
consultation.
During development of this proposed regulation, consultation
letters were sent to 584 tribal leaders. The letters provided
information regarding the EPA's development of both the NSPS for
modified and reconstructed EGUs and emission guidelines for existing
EGUs and offered consultation. No tribes have requested consultation.
Tribes were invited to participate in the national informational
webinar held August 27, 2013, and to which tribes were invited. In
addition, a consultation/outreach meeting was held on September 9,
2013, with tribal representatives from some of the 584 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. In those teleconferences, the EPA provided background information
on the GHG emission guidelines to be developed and a summary of issues
being explored by the agency. Additional detail regarding this
stakeholder outreach is included in the preamble to the emission
guidelines for existing affected electric utility generating units
being proposed in a separate action today. The EPA also held a series
of listening sessions prior to proposal of GHG standards for newly
constructed power plants. Tribes participated in a session on February
17, 2011, with the state
[[Page 34994]]
agencies, as well as in a separate session with tribes on April 20,
2011.
The EPA will also hold additional meetings with tribal
environmental staff during the public comment period, to inform them of
the content of this proposal, as well as offer further consultation
with tribal officials where it is appropriate. We specifically solicit
additional comment from tribal officials on this proposed rule.
G. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Order has the potential to influence the regulation. This action is
not subject to Executive Order 13045 because it is based solely on
technology performance.
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This proposed action is not a ``significant energy action'' as
defined in Executive Order 13211 (66 FR 28355, May 22, 2001) because it
is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. As previously stated, the EPA expects
few reconstructed or modified EGUs in the period of analysis and
impacts on emissions, costs or energy supply decisions for the affected
electric utility industry to be minimal as a result.
I. National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15
U.S.C. 272 note) directs the EPA to use VCS in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) developed or adopted by one or more voluntary
consensus bodies. The NTTAA directs the EPA to provide Congress,
through annual reports to the OMB, with explanations when an agency
does not use available and applicable VCS.
This proposed rulemaking involves technical standards. The EPA
proposes to use the following standards in this proposed rule: ASTM
D388-12 (Standard Classification of Coals by Rank), ASTM D396-13c
(Standard Specification for Fuel Oils), ASTM D975-14 (Standard
Specification for Diesel Fuel Oils), D3699-13b (Standard Specification
for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels), ASTM D7467-13
(Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to
B20)), and ANSI C12.20 (American National Standard for Electricity
Meters--0.2 and 0.5 Accuracy Classes). The EPA is proposing use of
Appendices A, B, D, F and G to 40 CFR part 75; these Appendices contain
standards that have already been reviewed under the NTTAA.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
action.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the U.S.
This proposed rule limits GHG emissions from modified and
reconstructed fossil fuel-fired electric utility steam generating units
(utility boilers and IGCC units) and stationary combustion turbines by
establishing national emission standards for CO2. The EPA
has determined that this proposed rule would not result in
disproportionately high and adverse human health or environmental
effects on minority, low-income and indigenous populations because it
does not affect the level of protection provided to human health or the
environment. As previously stated, the EPA expects few modified or
reconstructed fossil fuel-fired electric utility steam generating units
(utility boilers and IGCC units) or stationary combustion turbines in
the period of analysis.
XII. 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 in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: June 2, 2014.
Gina McCarthy,
Administrator.
Proposed Rule Amendment With Changes
The Environmental Protection Agency proposed rule amending 40 CFR
parts 60, 70, 71, and 98, which was published at 79 FR 1430, January 8,
2014, proposed amendments to the regulatory text of 40 CFR part 60,
subparts Da and KKKK, and, as an alternative to amending subparts Da
and KKKK, to create a new subpart (40 CFR part 60, subpart TTTT) to
include GHG standards for newly constructed EGUs. To facilitate
understanding the amendments being proposed in this proposal, we are
providing a Technical Support Document in the docket for this
rulemaking in track changes that shows the proposed amendments
considering the amendments proposed in the January 8, 2014, Federal
Register publication.
[FR Doc. 2014-13725 Filed 6-17-14; 8:45 am]
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