[Federal Register Volume 72, Number 88 (Tuesday, May 8, 2007)]
[Proposed Rules]
[Pages 26202-26227]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-8263]
[[Page 26201]]
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Part II
Environmental Protection Agency
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40 CFR Parts 51 and 52
Supplemental Notice of Proposed Rulemaking for Prevention of
Significant Deterioration and Nonattainment New Source Review: Emission
Increases for Electric Generating Units; Proposed Rule
Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed
Rules
[[Page 26202]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51 and 52
[Docket ID No. EPA-HQ-OAR-2005-0163; FRL-8307-7]
RIN-2060-AN28
Supplemental Notice of Proposed Rulemaking for Prevention of
Significant Deterioration and Nonattainment New Source Review: Emission
Increases for Electric Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental Notice of Proposed Rulemaking.
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SUMMARY: This action is a supplemental notice of proposed rulemaking
(SNPR) to EPA's October 20, 2005 notice of proposed rulemaking (NPR).
In the October 2005 NPR, EPA (we) proposed to revise the emissions test
for existing electric generating units (EGUs) that are subject to the
regulations governing the Prevention of Significant Deterioration (PSD)
and nonattainment major New Source Review (NSR) programs (collectively
``NSR'') mandated by parts C and D of title I of the Clean Air Act
(CAA). We proposed three alternatives for the emissions test: a maximum
achievable hourly emissions test, a maximum achieved hourly emissions
test, and an output-based hourly emissions test. This action recasts
the proposed options so that the output-based test becomes an
alternative method to implement the maximum achieved or maximum
achievable hourly tests, rather than a separate option. This SNPR also
proposes a new option in which the hourly emissions increase test is
added to the existing requirements for computing a significant increase
and a significant net emissions increase on an annual basis. It also
includes proposed rule language and supplemental information for the
October 2005 proposal, including an examination of the impacts on
emissions and air quality.
These proposed regulations interpret the emissions increase
component of the modification test under CAA 111(a)(4), in the context
of NSR, for existing EGUs. The proposed regulations would promote the
safety, reliability, and efficiency of EGUs. We are seeking comment on
all aspects of this proposed rule.
DATES: Comments. Comments must be received on or before July 9, 2007.
Under the Paperwork Reduction Act, comments on the information
collection provisions must be received by the Office of Management and
Budget (OMB) on or before June 7, 2007.
Public Hearing: If anyone contacts us requesting to speak at a
public hearing on or before May 29, 2007, we will hold a public hearing
approximately 30 days after publication in the Federal Register.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2005-0163 by one of the following methods:
http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
E-mail: [email protected].
Mail: Attention Docket ID No. EPA-HQ-OAR-2005-0163, U.S.
Environmental Protection Agency, EPA West (Air Docket), 1200
Pennsylvania Avenue, NW., Mail code: 6102T, Washington, DC 20460.
Please include a total of 2 copies. In addition, please mail a copy of
your comments on the information collection provisions to the Office of
Information and Regulatory Affairs, Office of Management and Budget
(OMB), Attn: Desk Officer for EPA, 725 17th Street, NW., Washington, DC
20503.
Hand Delivery: U.S. Environmental Protection Agency, EPA
West (Air Docket), 1301 Constitution Avenue, Northwest, Room 3334,
Washington, DC 20004, Attention Docket ID No. EPA-HQ-OAR-2005-0163.
Such deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2005-0163. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through http://www.regulations.gov or e-
mail. The http://www.regulations.gov website is an ``anonymous access''
system, which means EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an e-mail comment directly to EPA without going through http://www.regulations.gov, your e-mail 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, 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 EPA cannot read your comment due to technical difficulties
and cannot contact you for clarification, 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. For additional instructions on submitting comments, go to
section B. of the SUPPLEMENTARY INFORMATION section of this document.
Docket. All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, i.e., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically in http://www.regulations.gov or in hard copy at the U.S. Environmental
Protection Agency, Air Docket, EPA/DC, EPA West Building, Room 3334,
1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Public Reading Room is
(202) 566-1744, and the telephone number for the Air Docket is (202)
566-1742.
FOR FURTHER INFORMATION CONTACT: Ms. Janet McDonald, Air Quality Policy
Division (C504-03), U.S. Environmental Protection Agency, Research
Triangle Park, NC 27711, telephone number: (919) 541-1450; fax number:
(919) 541-5509, or electronic mail e-mail address:
[email protected].
SUPPLEMENTARY INFORMATION:
I. General Information
A. Does this action apply to me?
Entities potentially affected by the subject rule for this action
are fossil-fuel fired boilers and turbines serving an electric
generator with nameplate capacity greater than 25 megawatts (MW)
producing electricity for sale. Entities potentially affected by the
subject rule for this action also include State, local, and tribal
governments. Categories and entities potentially affected by this
action are expected to include:
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Industry Group SIC\a\ NAICS\b\
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Electric Services............... 491 221112.
Federal government.............. \1\22112 Fossil-fuel fired electric
utility steam generating
units owned by the Federal
government.
State/local/Tribal government... 22112 Fossil-fuel fired electric
utility steam generating
units owned by
municipalities. Fossil-
fuel fired electric
utility steam generating
units in Indian country.
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\a\ Standard Industrial Classification
\b\ North American Industry Classification System.
B. Where can I get a copy of this document and other related
information?
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\1\ Establishments owned and operated by Federal, State, or
local government are classified according to the activity in which
they are engaged.
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In addition to being available in the docket, an electronic copy of
this proposal will also be available on the World Wide Web. Following
signature by the EPA Administrator, a copy of this notice will be
posted in the regulations and standards section of our NSR home page
located at http://www.epa.gov/nsr.
C. What should I consider as I prepare my comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through
http://www.regulations.gov or e-mail. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information in a disk
or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM
as CBI and then identify electronically within the disk or CD ROM the
specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2. Send or deliver information
identified as CBI only to the following address: Roberto Morales, OAQPS
Document Control Officer (C404-02), U.S. EPA, Research Triangle Park,
NC 27711, Attention Docket ID No. EPA-HQ-OAR-2005-0163.
2. Tips for Preparing Your Comments. When submitting comments,
remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Follow directions--The agency may ask you to respond to
specific questions or organize comments by referencing a Code of
Federal Regulations (CFR) part or section number.
Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns, and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
D. How can I find information about a possible public hearing?
People interested in presenting oral testimony or inquiring if a
hearing is to be held should contact Ms. Pamela S. Long, New Source
Review Group, Air Quality Policy Division (C504-03), U.S. EPA, Research
Triangle Park, NC 27711, telephone number (919) 541-0641. If a hearing
is to be held, persons interested in presenting oral testimony should
notify Ms. Long at least 2 days in advance of the public hearing.
Persons interested in attending the public hearing should also contact
Ms. Long to verify the time, date, and location of the hearing. The
public hearing will provide interested parties the opportunity to
present data, views, or arguments concerning these proposed rules.
E. How is the preamble organized?
The information presented in this preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. What should I consider as I prepare my comments for EPA?
D. How can I find information about a possible public hearing?
E. How is the preamble organized?
II. Overview
A. Option 1: Hourly Emissions Increase Test Followed by Annual
Emissions Test
B. Option 2: Hourly Emissions Increase Test
III. Analyses Supporting Proposed Options
A. The Integrated Planning Model
B. NSR Availability Scenarios--Description of the Scenarios
C. NSR Availability Scenarios-Discussion of SO2 and
NOX Results
D. NSR Availability Scenarios-Discussion of PM2.5,
VOC, and CO Results
E. NSR Efficiency Scenario
IV. Proposed Regulations for Option 1: Hourly Emissions Increase
Test Followed by Annual Emissions Test
A. Test for EGUs Based on Maximum Achieved Emissions Rates
B. Test for EGUs Based on Maximum Achievable Emissions
V. Proposed Regulations for Option 2: Hourly Emissions Increase Test
VI. Legal Basis and Policy Rationale
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
VIII. Statutory Authority
II. Overview
This action is a SNPR to EPA's October 20, 2005 (70 FR 61081) NPR.
In the October 2005 NPR, we proposed to revise the emissions test for
existing EGUs that are subject to the regulations governing the PSD and
nonattainment major NSR programs (collectively ``NSR'') mandated by
parts C and D of title I of the CAA. We proposed three alternatives for
the emissions test: a maximum achievable hourly emissions test, a
maximum achieved hourly emissions test, and an output-based hourly
emissions test. In the NPR, we did not propose to include, along with
any of the revised NSR emissions tests, any provisions for computing a
significant increase or a significant net
[[Page 26204]]
emissions increase, although we solicited comment on retaining such
provisions. In addition, we solicited comment on whether, if we revised
the NSR test to be a maximum achieved emissions test or output-based
emissions test, we should revise the NSPS regulations to include a
maximum achieved emissions test or an output-based emissions test. This
action recasts the proposed options so that the output test, instead of
being an alternative to the maximum hourly achieved or maximum hourly
achievable tests, becomes an alternative method for sources to
implement those two tests. Specifically, we propose that each of the
two tests would be implemented through (i) an input method (as defined
below), (ii) the output method, or (iii) at the source's choice, either
the input or output method. This action includes proposed rule language
and supplemental information for the October 2005 proposal as it
relates to the major NSR regulations, including an examination of the
impacts on emissions and air quality that would result were we to
finalize one of the applicability tests proposed in the October 2005
proposal or in this SNPR, as described below.
This action also proposes an additional option that was not
included in the October 2005 rule. For convenience, this action
characterizes the tests contained in the October 2005 NPR, described
above, as Option 2 (with the maximum hourly achieved test characterized
as Alternatives 1-4 and the maximum hourly achievable test
characterized as Alternatives 5-6 within that Option 2, and with each
of those tests including output-based alternatives). For the additional
option proposed, which we characterize as Option 1, we are proposing
that an hourly emissions increase test (either maximum achieved or
maximum achievable, each with output-based alternatives) would include
the significant net emissions increase test in the current major NSR
rules, which is calculated on an actual-to-projected-actual annual
emissions basis. We are also clarifying that Option 1 is our preferred
option.
When we proposed a revised emissions test for EGUs in October 2005,
we referenced United States v. Duke Energy Corp., 411 F.3d 539 (4th
Cir.) rehearing den.---- F.3d---- (2005), cert. granted ---- U.S.----
(2006). At the time of our proposal, the Fourth Circuit had denied the
United States' petition for rehearing on the decision in Duke Energy,
but the deadline for filing a petition for certiorari to the United
States Supreme Court had not yet passed. Subsequently, on December 28,
2005, Intervenor plaintiffs Environmental Defense Fund, North Carolina
Sierra Club, and North Carolina Public Interest Research Group filed a
petition for certiorari asking the court to address several matters. On
May 15, 2006 the United States Supreme Court granted the petition for a
writ of certiorari. On April 2, 2007, the Supreme Court vacated and
remanded the Fourth Circuit decision. [549 U.S.---- (2007)] , 75
U.S.L.W. 4167 (April 2, 2007).
When we published the proposal in October 2005, it was in part in
response to the Fourth Circuit's holding that EPA must read the 1980
PSD regulations to contain an hourly test, consistent with the NSPS
regulations. The Supreme Court's vacatur was based on its finding that
such a reading of the 1980 PSD regulations ``was inconsistent with
their terms.'' The Supreme Court, however, indicated that EPA may be
able to revise the regulations when, as here, it has a rational reason
for doing so. While there is no longer a need to provide national
consistency in light of the Fourth Circuit decision, we believe that
the options for a maximum hourly test that we proposed in our October
2005 NPR and continue to propose in this SNPR are an appropriate
exercise of our discretion, especially in light of the substantial EGU
emission reductions from more efficient air quality programs
promulgated after 1980. Accordingly, we continue to pursue the
viability of imposing an hourly emissions test on EGUs for purposes of
major NSR applicability.
In May 2001, President Bush's National Energy Policy Development
Group issued findings and key recommendations for a National Energy
Policy. This document included numerous recommendations for action,
including a recommendation that the EPA Administrator, in consultation
with the Secretary of Energy and other relevant agencies, review NSR
regulations, including administrative interpretation and
implementation. The recommendation requested that we issue a report to
the President on the impact of the regulations on investment in new
utility and refinery generation capacity, energy efficiency, and
environmental protection. Our report to the President and our
recommendations in response to the National Energy Policy were issued
on June 13, 2002. A copy of this information is available at http://www.epa.gov/nsr/publications.html.
In that report we concluded:
As applied to existing power plants and refineries, EPA
concludes that the NSR program has impeded or resulted in the
cancellation of projects which would maintain and improve
reliability, efficiency and safety of existing energy capacity. Such
discouragement results in lost capacity, as well as lost
opportunities to improve energy efficiency and reduce air pollution.
(New Source Review Report to the President at pg. 3.)
On December 31, 2002, we promulgated final regulations that implemented
several of the recommendations in the New Source Review Report to the
President. However, that action left the NSR regulations as they
related to utilities largely unchanged. This action continues to
address the recommendations in the New Source Review Report to the
President as they relate to electric utilities specifically and in
light of the regulatory requirements for EGUs that have been
promulgated since our 2002 regulations.
The regulations proposed in the October 2005 NPR and on this action
would promote the safety, reliability, and efficiency of EGUs. The
proposed regulations are consistent with the primary purpose of the
major NSR program, which is to balance the need for environmental
protection and economic growth. The proposed regulations reasonably
balance the economic need of sources to use existing physical and
operating capacity with the environmental benefit of regulating those
emissions increases related to a physical or operational change. This
is particularly true in light of the substantial national EGU emissions
reductions that other programs have achieved or are expected to
achieve, which we described in detail at 70 FR 61083. Moreover, as the
analyses included in this SNPR demonstrate, the proposed regulations
would not have an undue adverse impact on local air quality.
This section gives an overview of our proposed actions for major
NSR applicability at existing EGUs, including the proposals in the NPR,
as recast in this proposal, for the maximum hourly emissions tests and
this additional proposal. Each of the options would promote the safety,
reliability, and efficiency of EGUs. Each of the options would also
balance the economic need of sources to use existing physical and
operating capacity with the environmental benefit of regulating those
emissions increases related to a change, considering the substantial
national emissions reductions other programs have achieved or will
achieve
[[Page 26205]]
from EGUs. Our preferred Option is Option 1. We will select the final
option after weighing the public comments on the Options. Table 1
summarizes our two Options.
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\2\ For clarity, this table lists all of the steps in the
applicability determinations under the various options and
alternatives. These steps include, as Step 1, the determination of
whether a physical change or change in the method of operation has
occurred. This Step 1 is included in the table solely for purposes
of clarity; neither the October 2005 NPR nor this action proposes
any action of any type (or makes any re-proposal) concerning the
regulations defining physical change or change in the method of
operation. Similarly, the steps also include, as Steps 3 and 4, the
current net significance test; and this SNPR does not propose any
action of any type (or make any re-proposal) concerning the current
net significance test. Finally, this action does not propose any
action of any type (or make any re-proposal) concerning the current
applicability test for EGUs.
Table 1.--Proposed Options for Major NSR Applicability for Existing EGU
\2\
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Option 1.......................... Step 1: Physical Change or Change in
the Method of Operation.
Step 2: Hourly Emissions Increase
Test.
Alternative 1--Maximum
achieved hourly emissions;
statistical approach; input basis.
Alternative 2--Maximum
achieved hourly emissions;
statistical approach; output basis.
Alternative 3--Maximum
achieved hourly emissions; one-in-5-
year baseline; input basis.
Alternative 4--Maximum
achieved hourly emissions; one-in-5-
year baseline; output basis.
Alternative 5--NSPS test--
maximum achievable hourly
emissions; input basis.
Alternative 6--NSPS test-
maximum achievable hourly
emissions; output basis.
Step 3: Significant Emissions
Increase Determined Using the
Actual-to-Projected-Actual
Emissions Test as in the Current
Rules.\3\
Step 4: Significant Net Emissions
Increase as in the Current Rules.
Option 2.......................... Step 1: Physical Change or Change in
the Method of Operation.
Step 2: Hourly Emissions Increase
Test.
Alternative 1--Maximum
achieved hourly emissions;
statistical approach; input basis.
Alternative 2--Maximum
achieved hourly emissions;
statistical approach; output basis.
Alternative 3--Maximum
achieved hourly emissions; one-in-5-
year baseline; input basis.
Alternative 4--Maximum
achieved hourly emissions; one-in-5-
year baseline; output basis.
Alternative 5--NSPS test--
maximum achievable hourly
emissions; input basis.
Alternative 6--NSPS test-
maximum achievable hourly
emissions; output basis.
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We request public comment on all aspects of this action. We intend
to finalize either Option 1 or Option 2. We will also finalize either
the maximum achieved or the maximum achievable alternative. We intend
to respond to public comments on the October 20, 2005 NPR and this
notice in a single Federal Register Notice and Response to Comments
Document at the time that we take final action.
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\3\ Steps 3 and 4 only apply when a unit fails Step 2. (That is,
it is determined that an hourly emissions increase would occur.)
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A. Option 1: Hourly Emissions Increase Test Followed by Annual
Emissions Test
In the NPR, we did not propose to include, along with any of the
revised NSR emissions tests, any provisions for computing a significant
emissions increase or a significant net emissions increase, although we
solicited comment on retaining such provisions. Many commenters
believed netting is required under the Alabama Power Court decision,
and supported options retaining netting. Therefore, we are proposing
that major NSR applicability would include an hourly emissions increase
test, followed by the current regulatory requirements for the actual-
to-projected-actual emissions increase test to determine significance,
and the significant net emissions increase test. We call this approach
Option 1 and we are proposing it as our preferred option. Specifically,
under Option 1, the major NSR program would include a four-step process
as follows: (1) Physical change or change in the method of operation;
(2) hourly emissions increase test ; (3) significant emissions increase
as in the current major NSR regulations; and (4) significant net
emissions increase as in the current major NSR regulations. Section IV
of this preamble describes Option 1 in more detail. Our proposed
regulatory language is for Option 1.
Option 1 facilitates improvements for efficiency, safety, and
reliability, without adverse air quality effects (as the discussion of
the IPM and air quality analyses in Section III indicates).
Specifically, changes that will not increase the hourly emissions
rate--such as those to make repairs to reduce the number of forced
outages--do not require further review under Option 1. That is, if
there would be no hourly emissions increase following a physical change
or change in the method of operation, the proposed rule does not
require a determination of whether a significant increase or a
significant net emissions increase would occur. Thus, Option 1 would
simplify major NSR for changes where there is no increase in hourly
emissions. However, many public commenters urged that we retain the
significant emissions increase component of the emissions increase
test. Therefore, we are proposing further review under Option 1 in
instances where a physical or operational change at a given unit would
increase the hourly emissions rate, such as would occur where there is
an increase in existing capacity. In such cases, Option 1 requires
further review using the significant increase and significant net
emissions increase components of the current regulations. This approach
retains an annual emissions test in determining NSR applicability.
We are proposing both a maximum achieved hourly and a maximum
achievable hourly emissions increase test under Step 2 of Option 1,
which we discuss in detail in Section IV.A. of this preamble.
Consistent with our policy goal of improving energy efficiency, we are
proposing both an input \4\ and output based format for both the
maximum achievable and maximum achieved hourly emissions increase test
options. Specifically, we are proposing the alternatives of (i) use of
input-based methodology for each test, (ii) use of output-based
methodology for each test, or (iii) allowing the source to choose
between input- or output-based methodology. Some commenters strongly
opposed an output-based format, believing that it would encourage
emissions increases. We believe these concerns are mitigated in a
system where total annual emissions
[[Page 26206]]
are capped nationally. Other commenters supported the output-based
format, noting that it would encourage energy efficiency.
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\4\ In this context, we use the term ``input'' as a convenient
way to refer to the hourly emission rate test, and to distinguish it
from the output test, which is calculated on the basis of hourly
emissions per kilowatt hour of generation.
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We agree that an output-based test encourages efficient units,
which has well-recognized benefits. The more efficient an EGU, the less
it emits for a given period of operation. For example, a 50 MW
combustion turbine that operates 500 hours a year, for 25,000 MWh per
year at an emission rate of 75 ppm, would emit 46 tons per year at 25
percent efficiency, 41 tons per year at 28 percent efficiency, 37 tons
per year at 31 percent efficiency, and 34 tons per year at 34 percent
efficiency.
Furthermore, we have established pollution prevention as one of our
highest priorities. One of the opportunities for pollution prevention
is maximizing the efficiency of energy generation. An output-based
standard establishes emission limits in a format that incorporates the
effects of unit efficiency by relating emissions to the amount of
useful energy generated, not the amount of fuel burned. By relating
emission limitations to the productive output of the process, output-
based emission limits encourage energy efficiency because any increase
in overall energy efficiency results in a lower emission rate. Allowing
energy efficiency as a pollution control measure provides regulated
sources with an additional compliance option that can lead to reduced
compliance costs as well as lower emissions. The use of more efficient
technologies reduces fossil fuel use and leads to multi-media
reductions in environmental impacts both on-site and off-site. On-site
benefits include lower emissions of all products of combustion,
including hazardous air pollutants, as well as reducing any solid waste
and wastewater discharges. Off-site benefits include the reduction of
emissions and non-air environmental impacts from the production,
processing, and transportation of fuels.
While output-based emission limits have been used for regulating
many industries, input-based emission limits have been the traditional
method to regulate steam generating units. However, this trend is
changing as we seek to promote pollution prevention and provide more
compliance flexibility to combustion sources. For example, in 1998 we
amended the NSPS for electric utility steam generating units (40 CFR
part 60, subpart Da) to use output-based standards for nitrogen oxides
(NOX ; 40 CFR 63.44a, 62 FR 36954, and 63 FR 49446). We
recently promulgated new output-based emission limits for sulfur
dioxide (SO2) and NOX under subpart Da of 40 CFR
part 60 (71 FR 9866) and for combustion turbines. (71 FR 38482.)
B. Option 2: Hourly Emissions Increase Test
For Option 2, we are proposing a maximum achieved emissions
increase test alternative and a maximum achievable emissions increase
test alternative. For both the maximum achieved and maximum achievable
emissions increase test, we are also proposing the alternatives of (i)
the use of input-based methodology for each test; (ii) the use of
output-based methodology for each test, or (iii) allowing the source to
choose between input- or output-based methodology. We describe these
alternatives in detail in Section V. of this preamble.
Option 2 with the proposed maximum hourly achieved test would
simplify NSR applicability determinations. Option 2 with the proposed
maximum hourly achievable test provides even more simplicity by
conforming NSR applicability determinations to NSPS applicability
determinations. We also note the achieved and achievable tests
eliminate the burden of projecting future emissions and distinguishing
between emissions increases caused by the change from those due solely
to demand growth, because any increase in the emissions under the
hourly emissions tests would logically be attributed to the change.
Both the achieved and achievable tests reduce recordkeeping and
reporting burdens on sources because compliance will no longer rely on
synthesizing emissions data into rolling average emissions. Option 2
would reduce the reviewing authorities' compliance and enforcement
burden compared to the current regulations.
In the October 2005 NPR, we also solicited comment on whether, if
we revised the NSR test to be a maximum achieved emissions test or
output-based emissions test, we should revise the NSPS regulations to
include a maximum achieved emissions test or an output-based emissions
test. This SNPR concerns the emissions test for existing EGUs in the
major NSR programs. It does not address the emissions test for existing
EGUs under the NSPS program.
III. Analyses Supporting Proposed Options
We examined how our proposed options for major NSR applicability
for EGUs would affect control technology installation, emissions, and
air quality. We conducted two separate analyses using the Integrated
Planning Model (IPM). Our analyses show that none of the proposed
options would have a detrimental impact on county-level emissions or
local air quality. This section discusses our analyses and findings.
More extensive information on our analyses is available in the
Technical Support Document, which is available in Docket ID No. EPA-HQ-
OAR-2005-0163.
A. The Integrated Planning Model
We use the IPM to analyze the projected impact of environmental
policies on the electric power sector in the 48 contiguous States and
the District of Columbia. The IPM is a multi-regional, dynamic,
deterministic linear programming model of the entire electric power
sector. It provides forecasts of least-cost capacity expansion,
electricity dispatch, and emission control strategies for meeting
energy demand and environmental, transmission, dispatch, and
reliability constraints. We have used the IPM extensively to evaluate
the cost and emissions impacts of proposed policies to limit emissions
of sulfur dioxide and nitrogen oxides from the electric power sector.
The IPM was a key analytical tool in developing the Clean Air
Interstate Regulation (CAIR; see 70 FR 25162). However, the IPM
capabilities and results are not limited to projections for CAIR
States. It includes data for and projects emissions and controls for
the electric sector in the contiguous United States.
Each IPM model run is based on emissions controls on existing
units, State regulations, cost and performance of generating
technologies, SO2 and NOX heat rates, natural gas
supply and prices, and electricity demand growth assumptions. This
input is updated on a regular basis. We used the IPM to project EGU
SO2 and NOX controls, emissions, and air quality
in 2020 considering projected emission controls under the CAIR, Clean
Air Mercury Rule (CAMR), and Clean Air Visibility Rule (CAVR). For
convenience, we refer to this projection as the CAIR/CAMR/CAVR 2020
Base Case Scenario or, more simply, the Base Case Scenario. The IPM
model used for this scenario is IPM v.2.1.9.\5\
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\5\ Complete documentation for IPM, including the Base Case
Scenario, is available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html. See also Docket EPA-HQ-OAR-2005-0163, DCN 01.
---------------------------------------------------------------------------
The IPM v 2.1.9 is based on 2,053 model plants, which represent
13,819 EGUs, including 1,242 coal-fired EGUs.\6\ This represents all
existing EGUs in the
[[Page 26207]]
contiguous United States as of 2004, as well as new units that are
already planned or committed, and new units that are projected to come
online by 2007. The underlying data for these plants is contained in
the National Electric Energy Data System (NEEDS), which contains
geographic location, fuel use, emissions control, and other data on
each existing EGU. NEEDS data for existing EGUs comes from a number of
sources, including information submitted to EPA under the Title IV Acid
Rain Program and the NOX Budget Program, as well as
information submitted to the Department of Energy's (DOE's) Energy
Information Agency, on Forms EIA 860 and 767. That is, the underlying
data for each existing EGU in the IPM v.2.1.9 is information from an
actual EGU in operation as of 2004 that has been submitted to the EPA
or the DOE.
---------------------------------------------------------------------------
\6\ See the NEEDS 2004 documentation for IPM v.2.1.9 in Exhibit
4-6, which can be found at http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html. See also Docket EPA-HQ-OAR-2005-0163,
DCN 02.
---------------------------------------------------------------------------
The IPM v.2.1.9 model also accounts for growth in the EGU sector
that is projected to occur through new builds, including both planned-
committed units and potential units. Planned-committed EGUs are those
that are likely to come online, because ground has been broken,
financing obtained, or other demonstrable factors indicate a high
probability that the EGU will come online. Planned-committed units in
IPM v.2.1.9 were based on two information sources: RDI NewGen database
(RDI) distributed by Platts (http://www.platts.com) and the inventory
of planned-committed units assembled by DOE, Energy Information
Administration, for their Annual Energy Outlook. Potential EGUs are
those units that may be built at a future date in response to
electricity demand. In IPM v.2.1.9, potential new units are modeled as
additional capacity and generation that may come online in each model
region.
IPM v.2.1.9 also accounts for emission limitations due to State
regulations and enforcement actions. It includes State regulations that
limit SO2 and NOX emissions from EGUs. These are
included in Appendix 3-2, available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/bc3appendix.pdf.\7\ The IPM v.2.1.9 includes NSR
settlement requirements for the following six utility companies:
SIGECO, PSEG Fossil, TECO, We Energies (WEPCO), VEPCO and Santee
Cooper. The settlements are included as they existed on March 19, 2004.
A summary of the settlement agreements is included in Appendix 3-3 of
the IPM documentation and is available http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/bc3appendix.pdf.\8\
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\7\ See also Docket EPA-HQ-OAR-2005-0163, DCN 03.
\8\ See also Docket EPA-HQ-OAR-2005-0163, DCN 03.
---------------------------------------------------------------------------
In the IPM, EPA does not attempt to model unit-specific decisions
to make equipment change or upgrades to non-environmental related
equipment that could affect efficiency, availability or cost to operate
the unit (and thus the amount of generation). Modeling such decisions
would require either obtaining or making assumptions about the
condition of equipment at units and would greatly increase model size,
limiting its applicability in policy analysis. Specifically, IPM does
not project that any particular existing EGU will make physical or
operational changes that increase its efficiency, generation, or
emissions. Therefore, IPM does not predict which particular EGUs will
be subject to the major NSR applicability requirements. However, as
discussed below, EPA has specially designed inputs to IPM that provide
useful information directly related to major NSR applicability
requirements. As we discuss below, these inputs are in the form of
constraints to the IPM model rather than changes on a unit-by-unit
basis.
Reliability is a critical element of power plant operation.
Reliability is generally defined as whether an EGU is able to operate
over sustained periods at the level of output required by the utility.
One measure of reliability is availability, the percentage of total
time in a given period that an EGU is available to generate
electricity. An EGU is available if it is capable of providing service,
regardless of the capacity level that can be provided. Availability is
generally measured using the number of hours that an EGU operates
annually. For example, if an EGU operated 8,760 hours in a particular
year, it was 100 percent available. Each year, EGUs are not available
for some number of hours due to planned outages, maintenance outages,
and forced outages.
IPM v.2.1.9 uses information from the North American Electric
Reliability Council (NERC)'s Generator Availability Data System (GADS)
to determine the annual availability for EGUs. The GADS database
includes operating histories--some dating back to the early 1960's--for
more than 6,500 EGUs. These units represent more than 75 percent of the
installed generating capacity in the United States and Canada. Each
utility provides reports, detailing its units' operation and
performance. The reports include types and causes of outages and
deratings, unit capacity ratings, energy production, fuel use, and
design information. GADS provides a standard set of definitions for
determining how to classify an outage on a unit, including planned
outages, maintenance outages, and forced outages. The GADS data are
reported and summarized annually. A planned outage is the removal of a
unit from service to perform work on specific components that is
scheduled well in advance and has a predetermined start date and
duration (for example, annual overhaul, inspections, testing). Turbine
and boiler overhauls or inspections, testing, and nuclear refueling are
typical planned outages.
A maintenance outage is the removal of a unit from service to
perform work on specific components that can be deferred beyond the end
of the next weekend, but requires the unit be removed from service
before the next planned outage. Typically, maintenance outages may
occur any time during the year, have flexible start dates, and may or
may not have predetermined durations. For example, a maintenance outage
would occur if an EGU experiences a sudden increase in fan vibration.
The vibration is not severe enough to remove the unit from service
immediately, but does require that the unit be removed from service
soon to check the problem and make repairs.
A forced outage is an unplanned component failure or other
breakdown that requires the unit be removed from service immediately,
that is, within 6 hours, or before the end of the next weekend. A
common cause of forced outages is boiler tube failure.
Each EGU must report the number of hours due to planned outages,
maintenance outages, and forced outages to NERC annually. NERC
summarized the data for all coal-fired EGUs over the period from 2000-
2004 in its Annual Unit Performance Statistics Report.\9\ For the years
2001-2004, the average annual planned outage hours for all coal-fired
EGUs was 572.09 (about 23 days), the average annual maintenance outage
hours for all coal-fired EGUs was 156.27 (about 6 days), and the
average annual forced outage hours for all coal-fired EGUs was 348.75
(about 14 days). The total annual unavailable hours for all coal-fired
EGUs were 1,087.57, which is 15.1 percent of the total annual hours of
8,760. Based on this data, the IPM v.2.1.9 assumed coal-fired EGUs were
85 percent available. As just noted, of the 1,087.57 total unavailable
hours, 348.75 were forced outage hours, which means that coal-fired
EGUs were
[[Page 26208]]
unavailable due to forced outages approximately 4 percent of the hours
in a year for the years 2000-2004.
---------------------------------------------------------------------------
\9\ The report is available at http://www.nerc.com/~gads/ and in
Docket EPA-HQ-OAR-2005-0163, DCN 04.
---------------------------------------------------------------------------
We recently released a graphic presentation of electric power
sector results under CAIR/CAMR/CAVR. Entitled ``Contributions of CAIR/
CAMR/CAVR to NAAQS Attainment: Focus on Control Technologies and
Emission Reductions in the Electric Power Sector,'' it is available at
http://www.epa.gov/cair/charts.html.\10\ As this presentation shows,
under the CAIR/CAMR/CAVR 2020 Base Case Scenario, local SO2
and NOX emissions generally decrease, average SO2
and NOX emission rates decrease, and national SO2
and NOX emissions decrease. As this document also shows,
half of the coal-fired generation is expected to have scrubbers and
either SCR or SNCR by 2020. These effects occur throughout the
contiguous 48 States, not just in the CAIR States.
---------------------------------------------------------------------------
\10\ Also available in Docket EPA-HQ-OAR-2005-0163, DCN 05.
---------------------------------------------------------------------------
We developed IPM scenarios to examine the effects of our proposed
regulations, including the maximum hourly emissions increase tests
(achievable and achieved, on an input and output basis), on EGU
emissions and control technologies. These new IPM scenarios incorporate
the parameters used in the IPM model v.2.1.9 that we describe above,
including information for the electric sector in the contiguous United
States. Thus, these new IPM scenarios revise the parameters in the
CAIR/CAMR/CAVR 2020 Base Case Scenario consistent with the way EGUs
might operate under the proposed major NSR applicability changes. We
call these IPM scenarios the NSR Availability and the NSR Efficiency
Scenarios, and discuss them in the following sections.
B. NSR Availability Scenarios--Description of the Scenarios
We developed two IPM scenarios, which we call the CAIR/CAMR/CAVR
NSR Availability Scenarios, or, more simply, the NSR Availability
Scenarios, to examine how changes to major NSR applicability under the
proposed regulations could, by allowing sources to make repairs or
improvements that increase hours of operation, affect emissions and
control technology installation. The NSR Availability IPM scenarios are
based on the CAIR/CAMR/CAVR 2020 Scenario.
The primary difference between the current applicability test and
the proposed tests is that under the proposed tests, sources could more
readily make repairs or improvements that prevent forced outages, and
thereby allow the source to operate more hours. These repairs allow the
source to operate at the higher availability level that it achieved
before its equipment degraded so much as to cause more forced outages.
Some commenters emphasized this difference between the current
applicability test and our proposals in the NPR. They explained that
because, as we noted at 70 FR 61100, hours of operation are considered
in determining annual emissions under the actual-to-projected-actual
test in the current major NSR program but have no role in any of our
proposed hourly emissions increase test options, an EGU could make a
change that does not increase the maximum hourly emissions rate, but
does allow the source to run more hours. This change would not trigger
review under a maximum hourly emissions increase test in any case, but
in some cases might trigger review under the current major NSR
emissions increase test based on annual emissions with a 5-year
baseline period. These commenters assert that the proposed
applicability tests could allow substantial increases in annual
emissions without triggering NSR.
For several reasons, we believe commenters have overstated the
likelihood that substantial increases in annual emissions and resulting
deterioration in air quality would occur under the proposed maximum
hourly emissions tests, as opposed to the current annual emissions, 5-
year baseline test. First, an EGU can increase its hours of operation
under the current regulations, as long as it does not make a physical
change or change in the method of operation. Information from the RBLC
confirms that most EGUs are already permitted to run 8760 hours
annually. That is, increases in hours of operation at most EGUs are not
a change in the method of operation. They are allowed and frequently
occur at many EGUs under the current regulations without triggering
major NSR. Second, increases in actual emissions stemming from
increases in hours of operation that are unrelated to the change, are
not considered in determining projected actual emissions. To the extent
that changes resulting in increased hours would occur under the
proposed regulatory scheme, any resulting increases in emissions will
be diminished as the CAIR and BART programs are implemented and the
SO2 and NOX emissions for most EGUs are capped.
As we described in detail in the NPR, 70 FR 61087, national and
regional caps limit total actual annual EGU SO2 and
NOX emissions. These caps greatly reduce the significance of
hours of operations on actual emissions from the sector nationally.
Furthermore, as we indicated in our recent report of the CAIR/CAMR/
CAVR, the more hours an EGU operates, the more likely it is to install
controls.\11\ Moreover, existing synthetic minor limits to avoid major
NSR and enforceable limits on hours of operation on a particular EGU as
a result of netting would remain in place under any revised emissions
increase test. We thus believe the opportunities for many EGUs to
significantly increase their emissions through higher hours of
operation under a maximum hourly emissions increase test, as compared
to the current annual emissions increase test with a 5-year baseline
period, are generally limited.
---------------------------------------------------------------------------
\11\ See our presentation, ``Contributions of CAIR/CAMR/CAVR to
NAAQS Attainment: Focus on Control Technologies and Emission
Reductions in the Electric Power Sector,'' on pages 39 and 43. The
presentation is available at http://www.epa.gov/cair/charts.html.
Also available in Docket EPA-HQ-OAR-2005-0163, DCN 05.
---------------------------------------------------------------------------
Nonetheless, we want to comprehensively examine the outcomes of a
maximum hourly emissions increase test, using a robust methodology
based on conservative (that is, protective of the environment)
estimates. We therefore developed two IPM scenarios, which we call the
CAIR/CAMR/CAVR NSR Availability Scenarios, or, more simply, the NSR
Availability Scenarios, to examine how changes to major NSR
applicability under the proposed regulations could, by allowing sources
to make repairs or improvements that increase hours of operation,
affect emissions and control technology installation. These IPM
scenarios are based on the CAIR/CAMR/CAVR 2020 Scenario, which employs
the IPM v.2.1.9 model that we describe in Section III. A. of this
preamble, including information for the electric sector in the
contiguous United States. Section III A. of this document also contains
specific information on the assumptions about EGU assumptions in the
IPM v.2.1.9. The NSR Availability Scenarios retain the heat input for
each EGU from the CAIR/CAMR/CAVR 2020 Scenario. That is, we did not
assume that any existing EGU would increase its capacity in the NSR
Availability Scenario.
The parameters in the IPM model are based on availability for 6,500
EGUs over the 5-year period from 2000-2004. In the NSR Availability
scenarios, however, we changed the parameters in IPM v.2.1.9 consistent
with the way EGUs might operate under the more flexible regulations
that we are proposing. That is, we assumed that
[[Page 26209]]
some owner/operators might make changes that increase the hours of
operation of some EGUs. It is unlikely that an owner/operator would be
able to make changes that reduce the hours that an EGU is unavailable
due to a planned outage or a maintenance outage. However, EGUs would be
able to make changes that increase their hours of operation as a result
of a reduction in the number and length of forced outages.
Specifically, with more flexibility concerning the number of hours EGUs
operate annually, EGU owner/operators may replace broken-down equipment
in an effort to reduce the number of forced outages. Such actions would
increase the safety, reliability, and efficiency of EGUs, consistent
with one of our primary policy goals for our proposed regulations.
Therefore, in the NSR Availability Scenario, we assumed that coal-
fired EGUs would be able to make changes that affect forced outage
hours in two, alternative, ways: (1) Coal-fired EGUs would reduce their
forced outage hours by half (2 percent increase in availability); and
(2) coal-fired EGUs would have no forced outage hours (4 percent
increase in availability). Therefore, in the first model run, we
increased the coal-fired availability by 2 percent, from 85 percent to
87 percent annually. In the second NSR EGU run, we increased coal-fired
availability by 4 percent, to 89 percent annually. We believe it is
unlikely that an EGU would be able to make repairs that completely
eliminate forced outage hours. However, we wanted a robust examination
of changes that could impact emissions and air quality.\12\ We
therefore made the very conservative assumption to increase to EGU
availability by 2 percent and 4 percent over the actual historical
hours of operation for 6,500 EGUs over the years 2000-2004. All other
information in the NSR Availability Scenarios is the same as that in
IPM v.2.1.9 used for the CAIR/CAMR/CAVR Scenario.
---------------------------------------------------------------------------
\12\ While we believe it is most likely that an EGU would
increase its hours of operation under these proposed regulations due
to reducing the number of hours that the EGU is unavailable due to
forced outage hurs, the analysis is applicable to increaes in hours
of operation for other reasons.
---------------------------------------------------------------------------
The NERC GADS calculates the average availability for an EGU by
taking the actual total number of unavailable hours in a given year for
all EGUs and dividing it evenly among the total number of EGUs. Based
on the GADS data, the IPM assumes an upper bound of 85 percent
availability for coal-fired EGUs. In GADS data for the years 2000-2004,
some EGUs actually had more than 85 percent availability and some
actually had less. The particular EGUs that had greater than 85 percent
availability and less than 85 percent varied from year to year.
Similarly, by eliminating forced outages, some EGUs could increase
their availability by more than 2-4 percent and some EGUs could
increase their availability by less than 2-4 percent. Likewise, the
particular EGUs that were able to reduce their forced outage hours
would also vary from year to year. For modeling purposes, it thus makes
more sense to assume an average availability than to determine unit-by-
unit availabilities for each and every EGU in a given year.
Our approach based on average availability is also consistent with
actual historical operations at particular EGUs and plantsites, which
are most directly related to local emissions and air quality. Variation
in actual annual hours of operation at a given EGU and at given
plantsites do occur under current major NSR applicability. It is not
uncommon for actual hours of operation for a particular EGU to vary by
348 hours (4 percent availability) or more from year to year. It is
also not uncommon for the variation in actual hours of operation to
occur among EGUs at a particular plantsite by 4 percent or more from
year to year. For example, in one year Unit A might run 7,800 hours and
Unit B might run 7,400 hours. In the next year Unit B might run 7,800
hours and Unit A 7,400 hours. This pattern further supports an approach
based on average availability for estimating local emissions. Changes
in average availability, rather than the absolute availability of any
given EGU, thus is appropriate for analyzing the impact of proposed
changes to major NSR applicability.
C. NSR Availability Scenarios--Discussion of SO2 and NOX Results
This section discusses the SO2 and NOX
control device installation, national emissions, local emissions, and
impact on air quality for EGUs under the NSR Availability Scenario.
1. SO2 and NOX Control Device Installation. As Table 2 shows, the
NSR Availability Scenarios project retrofitting of more control devices
than under the CAIR/CAMR/CAVR 2020 Scenario.\13\ This result occurs
whether hours of operation increase by 2 percent or by 4 percent.
Significantly, under the 4 percent scenario, more Gigawatts (GW) of
electric capacity are controlled than under the 2 percent scenario. For
example, under NSR Availability 4%, there is 3.63 more GW of national
EGU capacity with scrubbers than under CAIR/CAMR/CAVR 2020. These
results are consistent with what IPM generally projects, as noted
above; that is, the more hours an EGU operates, the more likely it is
to install controls.\14\ We thus conclude that the more hours an EGU
operates, the more likely it is to install controls, regardless of
whether the major NSR applicability test is on an hourly basis or an
annual basis.
---------------------------------------------------------------------------
\13\ Available in Docket EPA-HQ-OAR-2005-0163, DCN 06. (System
Summary Report for NSR Availability).
\14\ See our presentation, ``Contributions of CAIR/CAMR/CAVR to
NAAQS Attainment: Focus on Control Technologies and Emission
Reductions in the Electri Power Sector,'' on pages 39 and 43. The
presentation is available at http://www.epa.gov/cair/charts.html.
Also available in Docket EPA-HQ-OAR-2005-0163, DCN 05.
[[Page 26210]]
Table 2.--2020 National EGUs With Emission Controls Under NSR Availability Scenarios
----------------------------------------------------------------------------------------------------------------
EGUs with additional controls EGUs with additional controls compared to
compared to 2004 base case CAIR/CAMR/CAVR 2020
Emission control type ----------------------------------------------------------------------------------
NSR availability NSR availability NSR availability
2% 4% 2% NSR availability 4%
----------------------------------------------------------------------------------------------------------------
FGD\15\...................... 109.62 GW....... 111.53 GW....... 1.71 GW......... 3.63 GW
SCR\16\...................... 73.47 GW........ 73.92 GW........ 0.62 GW......... 1.07 GW
----------------------------------------------------------------------------------------------------------------
2. SO2 and NOX National Emissions. As Table 3 shows, the NSR
Availability Scenarios project essentially no changes in SO2
or NOX emissions nationally by 2020 as compared to emissions
under the CAIR/CAMR/CAVR 2020 Scenario.\17\ This result is consistent
with the fact that under the NSR Availability Scenarios, the amount of
controls increases, compared to CAIR/CAMR/CAVR 2020, and we find that
these associated emissions decreases are offset by the emissions
increases associated with the reduced forced outages and higher
production levels.
---------------------------------------------------------------------------
\15\ 15 FGD is flue gas desulfurization, also known as
scrubbers, for control of SO2 emissions.
\16\ SCR is selective catalytic reduction, used for control of
NOX emissions.
\17\ CAIR/CAMR/CAVR SO2 and NOX emissions
available in Docket EPA-HQ-OAR-2005-0163, DCN 14. [EPA 219b--BART
13--2020--Pechan.xls]. NSR SO2 and NOX
Availability Emissions available in Docket EPA-HQ-OAR-2005-0163, DCN
14. [EPA 219b--NSR--OAQPS--5--Pechan--2020.xls] National totals for
CAIR/CAMR/CAVR and NSR Availability include new units (IPM new units
and planned-committed units).
Table 3.--National EGU Emissions Under NSR Availability Scenarios Compared to CAIR/CAMR/CAVR 2020 (tpy)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Pollutant CAIR/CAMR/CAVR NSR 4% NSR 2% Change-NSR 4% Change-NSR 2%
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................... 4,277,000 4,271,000 4,261,000 -6,000 <1% decrease......... -16,000 <1% decrease.
NOX...................................... 1,989,000 2,016,000 2,003,000 28,000 1% increase.......... 14,000 1% increase.
--------------------------------------------------------------------------------------------------------------------------------------------------------
As noted above, the NSR Availability Scenarios examine emissions
changes based on very conservative estimates developed using actual
historical hours of operation for 6,500 EGUs over the years 2000-2004.
We conclude that to any extent that EGU hours of operation increase
under a maximum hourly test, as opposed to the current average annual
5-year baseline test, such increased hours of operation would not
increase national EGU SO2 emissions. The increased
availability would have very little effect on national NOX
emissions, with approximately one percent increase nationally. This
conclusion as to emissions in the contiguous 48 States supports
extending the proposed rules nationwide, instead of limiting them to
the States in the CAIR region.
3. SO2 and NOX Local Emissions Impact. To examine the effect of the
maximum hourly and 5-year baseline tests on local air quality, we
compared 2020 county-level EGU SO2 and NOX
emissions under the CAIR/CAMR/CAVR 2020 and NSR Availability (4%)
Scenario.\18\ We describe these changes in detail in Chapter 4 of the
Technical Support Document (TSD). As the TSD shows, the proposed
revised NSR applicability tests would, under the very conservative
assumptions described above, result in a somewhat different pattern of
local emissions, with some counties experiencing reductions, some
experiencing increases, and some remaining the same. This pattern is
consistent with the fact that most coal-fired EGUs are in the CAIR
region and therefore subject to regulations implementing the CAIR cap.
According to the DOE's Energy Information Agency, for the years 2003-
2004, approximately 80 percent of the coal steam electric generation
and 75 percent of all electric generation occurred in CAIR States.\19\
Furthermore, EGUs are subject to national SO2 caps under the
Acid Rain Program.
---------------------------------------------------------------------------
\18\ CAIR/CAMR/CAVR SO2 and NOX emissions available
in Docket EPA-HQ-OAR-2005-0163, DCN 14. [EPA 219b--BART 13--2020--
Pechan.xls]. NSR SO2 and NOX Availability Emissions
available in Docket EPA-HQ-OAR-2005-0163, DCN 14. [EPA 219b--NSR--
OAQPS--5--Pechan--2020.xls].
\19\ Available in Docket EPA-HQ-OAR-2005-0163, DCN 08. (2000-
2004 Electric Generation).
---------------------------------------------------------------------------
For these reasons, an increase in emissions in one area results in
a decrease elsewhere. This dynamic occurs regardless of the major NSR
applicability test for existing EGUs. Nonetheless, the NSR Availability
Scenario demonstrates that this pattern continues to occur when
increased availability is assumed, such as we assume for present
purposes would occur under the proposed maximum hourly and 5-year
baseline tests.
4. SO2 and NOX Impact on Air Quality. In Chapter 4 of the TSD, we
compare projected county-level SO2 and NOX
emissions under NSR Availability 4% to those projected under CAIR/CAMR/
CAVR 2020. Projected increases in emissions of these pollutants due to
increased hours of operation at EGUs under the NSR Availability (4%)
Scenario are small in magnitude and sparse across the continental U.S.
Therefore, we would expect these increases to cause minimal local
ambient effect, both directly on SO2 and NOX
emissions and as precursors to formation of PM2.5
(SO2 and NOX emissions) and ozone (NOX
emissions). Because many counties experience decreases in emissions, we
would further expect any local ambient effects from increased emissions
to be somewhat diminished because of the emissions decreases elsewhere
that yield regionwide improvements in air quality, including
SO2, NOX, PM2.5, and ozone. We expect
similar outcomes with respect to the NSR Availability (2%) Scenario
where the emissions changes are smaller and constitute a pattern of
increases and decreases that is similar to that of the NSR Availability
(4%) Scenario. Based on the spatial distribution of SO2 and
NOX emissions changes as shown in the TSD, we would also
expect patterns of air quality changes respectively under the NSR
Availability (4%) Scenario to be consistent with projections under
CAIR/CAMR/CAVR in 2020. We thus believe that the local air quality
under this proposed regulations would be commensurate with that under
the
[[Page 26211]]
CMAQ modeling based on CAIR/CAMR/CAVR 2020 Scenario emissions
projections.\20\ That is, we believe local air quality under these
proposed regulations would be commensurate with air quality we are
projecting for 2020 absent a change to the existing major NSR emissions
increase test.
---------------------------------------------------------------------------
\20\ As we describe in more detail in the TSD, the CAIR/CAMR/
CAVR modeling is available on our website and in the docket for this
rulemaking. The CMAQ modeling was conducted as part of EPA's
multipollutant legislative assessment and the results are available
in the Multipollutant Regulatory Analysis: The Clean Air Interstate
Rule, The Clean Air Mercury Rule, and the Clean Air Visibility Rule
(EPA promulgated rules, 2005) at http://www.epa.gov/airmarkets/progsregs/cair/multi.html. The specific technical support document
on air quality modeling for CAIR/CAMR/CAVR, Technical Support
Document for EPA's Multipollutant Analysis; Methods for Projecting
Air Quality Concentrations for EPA's Multipollutant Analysis of
2005, is available at http://www.epa.gov/airmarkets/progsregs/cair/multi.html by clicking on the Technical Support Document--Air
Quality Modeling Technique used for Multi-Pollutant Analysis link.
It is also available in Docket EPA-HQ-OAR-2005-0163, DCN 09.
Information on ozone modeling is available at http://www.epa.gov/airmarkets/progsregs/cair/multi.html through the Air quality
Modeling Results Excel File link. It is also available in Docket
EPA-HQ-OAR-2005-0163, DCN 16.
---------------------------------------------------------------------------
D. NSR Availability Scenarios--Discussion of PM2.5, VOC, and CO Results
We used the NSR Availability Scenarios that we describe in Section
III.B of this preamble to examine the PM2.5, VOC, and CO
emissions and air quality impacts of the proposed hourly emissions
increase test. This Section provides the results of our analyses.
1. PM2.5, VOC, and CO Control Device Installation. As we discuss in
the PM2.5 NAAQS RIA, our NEEDS indicates that as of 2004, 84
percent of all coal-fired EGUS have an ESP in operation, about 14
percent of EGUs have a fabric filter, and roughly 2 percent have wet
PM2.5 scrubbers.\21\ Gas-fired turbines are clean burning
and BACT/LAER for these EGUs is no control. BACT/LAER for VOC and CO is
good combustion control. Furthermore, EGU owner/operators have natural
incentives to reduce VOC and CO emissions. VOC and CO emissions are
products of incomplete combustion. These compounds are discharged into
the atmosphere when fuel remains unburned or is burned only partially
during the combustion process. Fuel is a significant portion of total
costs for EGUs, particularly for older EGUs where capital costs are
paid off. EGU owner/operators have in fact improved combustion
practices to increase combustion efficiency, thereby limiting unburned
fuel. Cost effective operation is especially desirable in areas where a
cap and trade program increases the cost of operation by creating a
cost to pollute, as is the case in the CAIR region where most ozone and
PM2.5 nonattainment areas are located.
---------------------------------------------------------------------------
\21\ See the Regulatory Impact Analysis for 2006 NAAQS for
Particle Pollution Chapter 3--Controls, page 34. Available at http://www.epa.gov/ttn/ecas/ria.html and in Docket EPA-HQ-OAR-2005-0163,
DCN 10.
---------------------------------------------------------------------------
2. PM2.5, VOC, and CO National Emissions. As Table 4 shows, EGUs
contribute a small percentage of national PM2.5, CO, and VOC
emissions.\22\
---------------------------------------------------------------------------
\22\ CO emissions information from Clear Air Interstate Rule
Emissions Inventory Technical Support Document, available at http://www.epa.gov/interstateairquality/pdfs/finaltech01.pdf. CO emissions
rounded to nearest thousand ton level. Also available in Docket EPA-
HQ-OAR-2005-0163, DCN 11. PM2.5 and VOC emissions information from
PM2.5 NAAQS RIA, available at http://www.epa.gov/ttn/ecas/ria.html.
Also available in Docket EPA-HQ-OAR-2005-0163, DCN 10.
Table 4.--EGU Emissions As Percent of 2020 National Emissions (tpy)
----------------------------------------------------------------------------------------------------------------
EGU as %
Pollutant EGU National National
----------------------------------------------------------------------------------------------------------------
PM2.5........................................................... 533,000 6,206,000 8.6
VOC............................................................. 45,000 12,414,000 0.4
CO.............................................................. 718,000 82,852,000 0.9
----------------------------------------------------------------------------------------------------------------
As Table 5 shows, the NSR Availability Scenarios project
essentially no changes in PM2.5, VOC, or CO emissions
nationally by 2020 as compared to emissions under the CAIR/CAMR/CAVR
Scenario.\23\
---------------------------------------------------------------------------
\23\ Emissions information available in Docket EPA-HQ-OAR-2005-
0163, DCN 17. [NSR Availability PM2.5, VOC, and CO]
National totals for CAIR/CAMR/CAVR and NSR Availability include new
units (IPM new units and planned-committed units).
Table 5.--National EGU Emissions Under NSR Availability Scenario Compared to CAIR/CAMR/CAVR 2020 (tpy)
----------------------------------------------------------------------------------------------------------------
Pollutant CAIR/CAMR/CAVR NSR 4% Change-NSR 4%
----------------------------------------------------------------------------------------------------------------
PM2.5........................................................ 526,642 524,245 (2,397)
VOC.......................................................... 45,020 45,391 371
CO........................................................... 716,184 711,254 (4,930)
----------------------------------------------------------------------------------------------------------------
As described in Section III.B of this preamble, the NSR
Availability Scenarios examine emissions changes based on very
conservative estimates developed using actual historical hours of
operation for 6,500 EGUs over the years 2000-2004. We conclude that to
any extent that EGU hours of operation increase under a maximum hourly
emissions increase test, as opposed to the current average annual 5-
year baseline test, such increased hours of operation would not
increase national EGU PM2.5 and CO emissions. The increased
availability would have very little effect on national VOC emissions,
with less than half of a percent increase nationally. This conclusion
as to emissions in the contiguous 48 States supports extending the
proposed rules nationwide, instead of limiting them to the States in
the CAIR region.
3. PM2.5, VOC, and CO Local Emissions Impact. To examine the effect
of the maximum hourly emission increase tests on local air quality, we
compared 2020 county-level EGU PM2.5, VOC, and CO emissions
under the CAIR/CAMR/CAVR 2020 and NSR Availability (4%) Scenario.\24\
We
[[Page 26212]]
describe these changes in detail in Chapter 4 of the TSD.
---------------------------------------------------------------------------
\24\ Available in Docket EPA-HQ-OAR-2005-0163, DCN 17. [NSR
Availability PM2.5, VOC, and CO].
---------------------------------------------------------------------------
As Chapter 4 of the TSD shows, projected PM2.5, VOC, and
CO emissions changes under the proposed revised NSR applicability tests
would result in a somewhat different pattern of local emissions, with
some counties experiencing reductions, some experiencing increases, and
some remaining the same compared to emissions changes under CAIR/CAMR/
CAVR 2020.
4. PM2.5, VOC, and CO Impact on Air Quality. As Chapter 4 of the
TSD shows, projected increases in EGU PM2.5, VOC, and CO
emissions due to increased hours of operation at EGUs under the NSR
Availability (4%) Scenario are small in magnitude and sparse across the
continental U.S. Therefore, we would expect these increases to cause
minimal changes in local ambient effect in comparison to that observed
under CAIR/CAMR/CAVR for PM2.5 and ozone (for which VOC is a
precursor). Because many counties experience decreases in emissions, we
would further expect any local ambient effects from increased emissions
to be somewhat diminished because of the emissions decreases elsewhere
that yield regionwide improvements in air quality.
We have not modeled national or regional air quality improvements
in CO concentrations. As noted in Table 4, however, EGU CO emissions
are less than one percent of national CO emissions. According to our
latest analysis, 2020 national CO emissions are projected to be
19,892,017 tons less than 2001 national CO emissions.\25\ Local CO
emissions are generally a function of traffic congestion from mobile
sources. For these reasons, EGUs do not contribute significantly to
national or local CO emissions.
---------------------------------------------------------------------------
\25\ See the Clean Air Interstate Rule Emissions Inventory
Technical Support Document on pgs 7 and 38 at http://www.epa.gov/cair/pdfs/finaltech01.pdf. Also available in Docket EPA-HQ-OAR-2005-
0163, DCN 11.
---------------------------------------------------------------------------
The projected increases in CO emissions due to increased hours of
operation at EGUs under the NSR Availability (4%) Scenario are small in
magnitude and sparse across the continental U.S. We would expect these
increases to cause minimal local ambient effect on CO. Therefore, based
on the small increases and sparse distribution of CO emissions compared
to CAIR/CAMR/CAVR 2020, and the small contribution of EGU emissions to
national and local CO levels, we project no notable local impact on air
quality from EGU CO emissions from NSR Availability 4%.
E. NSR Efficiency Scenario.
We designed another IPM model run to evaluate whether efficiency
improvements that sources may make as a result of these proposed
regulations would lead to local emissions increases and adverse effects
on ambient air quality. Aside from independent factors such as climate
and economy, efficiency is a primary determinant of the hours of
operation of a given EGU. Neither the current annual emissions increase
test nor any of the proposed EGU emission increase test alternatives
directly measure an EGU's efficiency. However, the output-based
alternatives (Alternatives 2, 4, and 6), which are expressed in a lb/
KWh format that measures mass emissions per unit of electricity, are
closely related to an EGU's efficiency. Thus, an output-based test
encourages efficient units, which has well-recognized benefits. We
anticipate that the output-based alternatives in particular, and the
other alternatives to a lesser extent, could have the effect of
encouraging EGUs to increase their efficiency. For these reasons, we
focused on efficiency to examine whether an hourly test could result in
emissions increases as compared to the annual emissions increase test.
We call this run the NSR Efficiency Scenario. We assumed the least
efficient EGUs (approximately 35% of all EGUs) would increase their
efficiency by 4 percent.
We ran the IPM with this scenario (4 percent efficiency increase
for 371 coal-fired EGU, no increase in physical and operating existing
capacity) and compared the results to the CAIR/CAVR/CAMR IPM model. We
found approximately the same results from the NSR Efficiency Scenario
as from the NSR Availability Scenarios. We describe the results of the
NSR Efficiency analysis in detail in Chapter 5 of our TSD.
1. Control Device Installation. As Table 6 shows, the NSR
Efficiency Scenario projects retrofitting of more control devices for
SO2 and NOX than under the CAIR/CAMR/CAVR
2020.\26\ These results are consistent with what IPM generally
projects. The more efficient an EGU is, the more cost effective it is
to operate. The more cost effective it is to operate, the more hours it
will operate. The more hours it operates, the more likely it is to
install controls.\27\ We thus conclude that the more efficiently an EGU
operates, the more likely it is to install controls, regardless of
whether the major NSR applicability test is on an hourly basis or an
annual basis with a 5-year baseline.
---------------------------------------------------------------------------
\26\ Information from system summary report for the NSR
Efficiency IPM Run. Available in Docket EPA-HQ-OAR-2005-0163, DCN 13
(System Summary Report for NSR Efficiency). CAIR/CAMR/CAVR emissions
available in Docket EPA-HQ-OAR-2005-0163, DCN 14 [EPA 219b--BART
13--2020--Pechan].
\27\ See our presentation, ``Contributions of CAIR/CAMR/CAVR to
NAAQS Attainment: Focus on Control Technologies and Emission
Reductions in the Electric Power Sector,'' on pages 39 and 43. The
presentation is available at http://www.epa.gov/cair/charts.html.
Also available in Docket EPA-HQ-OAR-2005-0163, DCN 05.
Table 6.--2020 National EGUs with Emission Controls-NSR Efficiency
----------------------------------------------------------------------------------------------------------------
EGUs with additional
Emissions control type controls compared to 2004 EGUs with additional controls compared to
controls case CAIR/CAMR/CAVR 2020
----------------------------------------------------------------------------------------------------------------
FGD.................................... 109 GW.................... 1.5 GW.
SCR.................................... 74 GW..................... 1.0 GW.
----------------------------------------------------------------------------------------------------------------
2. National Emissions. As Table 7 shows, the NSR Efficiency
Scenarios project reductions in SO2 and NOX
emissions nationally by 2020 as compared to emissions under the Base
Case Scenario.\28\ This result is consistent with the fact that under
the NSR Efficiency Scenario, the amount of controls increases, compared
to the Base Case.
---------------------------------------------------------------------------
\28\ CAIR/CAMR/CAVR SO2 and NOX emissions
available in Docket EPA-HQ-OAR-2005-0163, DCN 14 [EPA 219b--BART
13--2020--Pechan]. NSR Efficiency SO2 and NOX
Emissions available in Docket EPA-HQ-OAR-2005-0163, DCN 07 [EPA
219b--NSR--OAQPS-- 2a--Pechan--2020--(to EPA) 4-27-06]. NSR
Efficiency PM2.5, VOC and CO Emissions available in
Docket EPA-HQ-OAR-2005-0163, DCN 18. National totals for CAIR/CAMR/
CAVR and NSR Efficiency include new units (IPM new units and
planned-committed units).
[[Page 26213]]
Table 7.--National EGU Emissions Under NSR Efficiency Scenario Compared to CAIR/CAMR/CAVR 2020 (tpy)
----------------------------------------------------------------------------------------------------------------
Emissions Change
Total Emissions Total Emissions Under NSR
Pollutant Under CAIR/CAMR/ Under NSR Efficiency
CAVR efficiency Compared to CAIR/
CAMR/CAVR
----------------------------------------------------------------------------------------------------------------
SO2.................................................... 4,277,000 4,265,000 -12,000
NOX.................................................... 1,989,000 1,984,000 -5,000
PM2.5.................................................. 526,642 529,647 3,005
VOC.................................................... 45,019 44,835 -184
CO..................................................... 716,184 711,314 -4,870
----------------------------------------------------------------------------------------------------------------
As noted above, the NSR Efficiency Scenarios examine emissions
changes based on very conservative estimates of technically feasible
improvements in efficiency. We conclude that to any extent that EGU
efficiency increases under a maximum hourly emissions increase test, as
opposed to the current average annual 5-year baseline test, such
increased efficiency would not increase national EGU SO2,
NOX, VOC, and CO emissions. The increased efficiency would
have very little effect on national PM2.5 emissions, with
less than half of a percent increase nationally. This conclusion as to
emissions in the contiguous 48 States supports extending the proposed
rules nationwide, instead of limiting them to the States in the CAIR
region.
3. Local Emissions and Air Quality. The NSR Efficiency Scenario
projects a somewhat different pattern of local emissions compared to
CAIR/CAMR/CAVR 2020. The NSR Efficiency Scenario projects decreases in
many counties compared to CAIR/CAMR/CAVR 2020. Where there are
projected increases in local SO2, NOX,
PM2.5, VOC, and CO emissions, they are small in magnitude
and sparse across the continental United States. Therefore, we would
expect these increases to cause minimal local ambient impact effect. We
describe the NSR Efficiency Scenario analysis and its results in detail
in Chapters 5 and 6 our TSD.
IV. Proposed Regulations for Option 1: Hourly Emissions Increase Test
Followed By Annual Emissions Test
In the NPR, we did not propose to include, along with any of the
revised NSR emissions tests, any provisions for computing a significant
increase or a significant net emissions increase, although we solicited
comment on retaining such provisions. Many commenters preferred to
retain an annual emissions increase test in addition to the hourly
emissions increase test. We are proposing Option 1, in which the hourly
emissions increase test would be followed by the actual-to-projected-
actual emissions increase test and the significant net emissions
increase test in the current regulations. Specifically, changes that
will not increase the hourly emissions rate-such as those to make
repairs to reduce the number of forced outages-do not require further
review under Option 1. However, if there would be an hourly emissions
increase following a physical change or change in the method of
operation, the proposed rule requires a determination of whether a
significant increase or a significant net emissions increase would
occur. Thus, Option 1 retains the netting provisions in the current
regulations. Option 1 also facilitates improvements for efficiency,
safety, and reliability, without adverse air quality effects (as the
above discussion of the IPM and air quality analyses indicates).
We are proposing that Option 1 would apply to all EGUs. We are also
requesting comment on whether Option 1 should be limited to the
geographic area covered by CAIR, or to the geographic area covered by
both CAIR and BART. We are also proposing that the Option 1 would apply
to all regulated NSR pollutants. However, we also request comment on
whether Option 1 should be limited to increases of SO2 and
NOX emissions.
Under Option 1, the major NSR program would include a four-step
process (with the second step revised as proposed, while retaining the
other steps): (1) Physical change or change in the method of operation
as in the current major NSR regulations; (2) hourly emissions increase
test (maximum achieved hourly emissions rate or maximum achievable
hourly emissions rate, each with output-based alternatives); (3)
significant emissions increase as in the current major NSR regulations;
and (4) significant net emissions increase as in the current major NSR
regulations.
For a modification to occur under Option 1, under Step 1, a
physical change or change in the method of operation must occur, and,
under Step 2, that change must result in an hourly emissions increase
at the existing EGU. If a post-change hourly emissions increase is
projected, Option 1 retains the requirements for a significant
emissions increase and a significant net emissions increase. In such
cases, under Step 3, the owner/operator would determine whether an
emissions increase would occur using the actual-to-projected-actual
annual emissions test in the current regulations. There would be no
conversion from annual to hourly emissions. Finally, in Step 4, as in
the current regulations, if a significant emissions increase is
projected to occur, the source would still not be subject to major NSR
unless there was a determination that a significant net emissions
increase would occur. Table 8 summarizes these four steps.
Table 8.--Major NSR Applicability for Existing EGUs Under Option 1
------------------------------------------------------------------------
------------------------------------------------------------------------
Option 1...................... Step 1: Physical Change or Change in the
Method of Operation.
Step 2: Hourly Emissions Increase Test.
Alternative 1--Maximum achieved
hourly emissions; statistical approach;
input basis.
Alternative 2--Maximum achieved
hourly emissions; statistical approach;
output basis.
Alternative 3--Maximum achieved
hourly emissions; one-in-5-year
baseline; input basis.
Alternative 4--Maximum achieved
hourly emissions; one-in-5-year
baseline; output basis.
Alternative 5--NSPS test--
maximum achievable hourly emissions;
input basis.
[[Page 26214]]
Alternative 6--NSPS test--
maximum achievable hourly emissions;
output basis.
Step 3: Significant Emissions Increase
Determined Using the Actual-to-
Projected-Actual Emissions Test as in
the Current Rules.\29\
Step 4: Significant Net Emissions
Increase as in the Current Rules.
------------------------------------------------------------------------
Option 1 would not alter the provisions in the current major NSR
regulations pertaining to a significant emissions increase and a
significant net emissions increase. Therefore, the regulations would
retain the definitions of net emissions increase, significant,
projected actual emissions, and baseline actual emissions. [See Sec.
51.166(b)(3), Sec. 51.166(b)(23), Sec. 51.166(b)(40), Sec.
51.166(b)(47), and analogous provisions in 40 CFR 51.165, 52.21, 52.24,
and appendix S to 40 CFR part 51.] The regulations would also retain
all provisions in the current regulations that refer to major
modifications, including, but not limited to, those in Sec.
51.166(a)(7)(i) through (iii), (b)(9), (b)(12), (b)(14)(ii), (b)(15),
(b)(18), (i)(1) through (9), (j)(1) through (4), (m)(1) through (3),
(p)(1) through (7), (r)(1) through (7), and (s)(1) through (4)
analogous provisions in 40 CFR 51.165, 52.21, 52.24, and appendix S to
40 CFR part 51.
---------------------------------------------------------------------------
\29\ Steps 3 and 4 only apply when a unit fails Step 2. (That
is, it is determined that an hourly emissions increase would occur.)
---------------------------------------------------------------------------
We are also proposing regulatory language containing the two-step
modification provisions. (Steps 1 and 2 of Option 1, as outlined in
Table 8.) As we noted at 70 FR 61088, you can find the regulatory text
defining ``modification'' within the NSPS general provision regulations
at 40 CFR 60.2 and 60.14. Substantially mirroring CAA 111(a)(4), Sec.
60.2 contains a general description of the two components an activity
must satisfy to qualify as a modification. Sec. 60.14 elaborates on
the general description contained in Sec. 60.2 by more precisely
defining how you measure the amount of pollution that results from an
activity, and listing activities that do not qualify as physical
changes or changes in the method of operation. (that is, the
``increases'' component of the modification definition, or Step 2.) As
we proposed at 70 FR 61090, we have added a definition of modification
in Sec. 51.167, which mirrors the provisions in Sec. 60.2. We are
also proposing to add requirements defining the ``increases'' component
of ``modification'' to the major NSR rules, analogous to the provisions
in Sec. 60.14. Specifically, the definition of modification in the
proposed rules requires that an increase in the amount of regulated NSR
pollutants must be determined according to the provisions in paragraph
(f) of Sec. 51.167. Under Option 1, Alternatives 1-4, we are proposing
to define the ``increases'' component to mean maximum hourly emissions
rate achieved. That is, if a physical change or change in the method of
operation (as defined under existing regulations, which we are not
proposing to change) is projected to result in an increase in the
maximum hourly emissions rate expected to be achieved over the maximum
hourly emissions rate actually achieved at the EGU prior to the change,
a modification would occur. The requirements for the maximum achieved
alternatives are in proposed Sec. 51.167(f)(1), Alternatives 1-4.
Under Option 1, Alternatives 5 and 6, we are proposing to define the
``increases'' component to mean maximum achievable hourly emissions.
For maximum achievable hourly emissions on an input basis, we are
proposing to add a definition of the ``increases'' component of
``modification'' that substantially mirrors the definition of the
``increases'' component of ``modification'' in the NSPS provisions,
which is found in 40 CFR 60.2. These requirements are in proposed Sec.
51.167(f)(1), Alternative 5. For the maximum achievable alternative on
an output basis (Alternative 6), the requirements are in proposed Sec.
51.167(f)(1), Alternative 6.
To incorporate the two-step modification provisions under Option 1,
we are proposing to add two new sections to the major NSR program
rules. The first, 40 CFR 51.167, would specify the requirements that
State Implementation Plans must include for major NSR applicability at
existing EGUs, including those for both attainment and nonattainment
areas. (Proposed rule language for 40 CFR 51.167 accompanies this
SNPR.) The second, 40 CFR 52.37, would contain the requirements for
major NSR applicability for existing EGUs where we are the reviewing
authority. Although the proposed amendatory language is for 40 CFR
51.167, we are proposing that the same requirements would apply under
40 CFR 52.37, differing only in that the Administrator is the reviewing
authority, rather than the State, local, or tribal agency. Although
this notice does not contain specific regulatory language, we are
proposing that either 40 CFR 51.167 or 40 CFR 52.37, as appropriate,
would contain the requirements for emissions increases at EGUs for all
sections of the Code of Federal Regulations that contain the major NSR
program, including 40 CFR 51.165, 51.166, 52.21, 52.24, and appendix S
of 40 CFR part 51, as well as any regulations we finalize to implement
major NSR in Indian Country. We are also proposing to make the same
changes where necessary to conform the general provisions in parts 51
and 52 to the requirements of the major NSR program, such as in the
definition of modification in 40 CFR 52.01. In addition, we are
proposing to remove all applicability requirements for existing EUSGUs
in all sections of the CFR that contain the major NSR program, as the
EGU requirements would supersede these requirements.
In the NPR, we proposed three alternatives for the hourly emissions
increase test-the NSPS maximum achievable hourly emissions test,
maximum achieved hourly emissions, and an output-based measure of
hourly emissions. As some commenters noted, we did not give much detail
about the output-based measure of hourly emissions. In this SNPR, we
are recasting what we proposed in the NPR for the output-based
methodology. In this SNPR, both the maximum achieved hourly emissions
test and the maximum achievable hourly emissions test include output-
based alternatives. Specifically, we are proposing two broad approaches
under Option 1: (1) A maximum achieved hourly emissions test; and (2) a
maximum achievable hourly emissions test. If we adopt the maximum
achieved hourly emissions test, we may require that it be expressed in
an input-based format (lb/hr) or an output-based format (lb/MWh).
Alternatively, and as we did in our recently promulgated NSPS for
combustion turbines (40 CFR part 60, subpart KKKK, July 6, 2006), we
may also adopt both an input and output based format. If we adopt both
formats, sources, at their choice, would be able to implement the
hourly emissions test in either input-or output-based formats.
Likewise, if we adopt the maximum achievable hourly emissions test, it
may be expressed in an input-based format
[[Page 26215]]
(lb/hr), an output-based format (lb/MWh), or both. We are also
proposing two methods for computing maximum achieved emissions: (1)
Statistical approach; and (2) one-in-5-year baseline. In terms of the
regulatory language that accompanies this notice, we are proposing six
alternatives for determining whether a physical or operational change
at an EGU is a modification. These alternatives are summarized in Table
9 and can be found at proposed Sec. 51.167(f)(1).
In Sections IV.A and B below, we describe our two approaches for
the hourly emissions increase test in more detail. The regulatory
language proposed for these approaches (that is, maximum achieved and
maximum achievable hourly emissions increase tests) would apply under
both Option 1 and Option 2. Option 2, as described below in Section V,
would eliminate the significance and netting steps that are included
under current applicability regulations, whereas Option 1 would not
eliminate the significance and netting steps. This action includes
proposed rule language for Option 1.
A. Test for EGUs Based on Maximum Achieved Emissions Rates
As one approach, we are proposing that the hourly emissions
increase test would be based on an EGU's historical maximum hourly
emissions rate. We call this approach the maximum achieved hourly
emissions test. Under this approach, an EGU owner/operator would
determine whether an emissions increase would occur by comparing the
pre-change maximum actual hourly emissions rate to a projection of the
post-change maximum actual hourly emissions rate. We request comment on
all alternatives for the maximum achieved hourly emissions increase
test (see proposed Alternatives 1 through 4 for Sec. 51.167(f)(1)), as
well as on other possible approaches for determining maximum achieved
hourly emissions. In particular, we request comments on whether the
proposed maximum achieved methodologies would account for variability
inherent in EGU operations and air pollution control devices.
1. Determining the Pre-Change Emissions Rate. The pre-change
maximum actual hourly emissions rate would be determined using the
highest rate at which the EGU actually emitted the pollutant within the
5-year period immediately before the physical or operational change.
Thus, the maximum achieved emissions test is based on specific measures
of actual historical emissions during a representative period.
We are proposing four alternatives for determining the pre-change
maximum hourly emissions rate actually achieved, which we denote here
and in the proposed rule language as Alternatives 1 through 4. As shown
above in Table 9, these alternatives consist of two different methods
for determining the pre-change maximum emissions rate (i.e., the
statistical approach and the one-in-5-year baseline approach), each of
which can be applied on an input (lb/hr) basis or output (lb/MWh)
basis. In addition to these four alternatives, which are included in
the proposed rule language at Sec. 51.167(f)(1), we are proposing that
the source would have a choice of implementing the test on either an
input-or output-basis.
Proposed Alternatives 1 and 2 (input basis and output basis,
respectively) utilize a statistical approach for you to use to analyze
continuous emission monitoring system (CEMS) or predictive emission
monitoring system (PEMS) data from the 5 years preceding the physical
or operational change to determine the maximum actual pollutant
emissions rate. The statistical approach utilizes actual recorded data
from periods of representative operation to calculate the maximum
actual emissions rate associated with the pre-change maximum actual
operating capacity in the past 5 years. The maximum actual emissions
rate is expressed as the upper tolerance limit (UTL). The UTL concept
and equations are derived from work conducted by the National Bureau of
Standards (now the National Institute of Standards and Technology
(NIST)).\30\
---------------------------------------------------------------------------
\30\ Mary Gibbons Natrella (1963). ``Experimental Statistics,''
NBS Handbook 91, U.S. Department of Commerce. This work is available
on the Internet at http://www.itl.nist.gov/div898/handbook/prc/section2/prc263.htm.
---------------------------------------------------------------------------
In conducting the analysis, you would select a period of 365
consecutive days from the 5 years preceding the change. Next, you would
compile a data set (for example, in a spreadsheet) for the pollutant of
interest with the hourly average CEMS or PEMS (as applicable) measured
emissions rates (in lb/hr for Alternative 1, or lb/MWh for Alternative
2) and corresponding heat input data for all of the EGU operating hours
in that period. From that data set, you would delete selected hourly
data from this 365-day period in accordance with certain data
limitations. Specifically, you would delete data from periods of
startup, shutdown, and malfunction; periods when the CEMS or PEMS was
out of control (as described below); and periods of noncompliance,
according to proposed Sec. 51.167(f)(2) as explained below in Section
IV.A.3 on data limitations.
The next step in the procedure is to sort the data set for the
remaining operating hours by heat input rates. You would then extract
the hourly data for the 10 percent of the data set corresponding to the
highest heat input rates for the selected period. The next step is to
apply basic statistical analyses to the extracted CEMS or PEMS hourly
emissions rate data, calculating the average emissions rate, the
standard deviation, and finally the UTL. See the proposed rule language
for Alternatives 1 and 2 at Sec. 51.167(f)(1) for the specifics of the
calculations. As included in the proposed rule, Alternatives 1 and 2
calculate the UTL for the 99.9th percentile of the population (of
hourly emissions rate readings) at the 99 percent confidence level.
That is, under the proposed methodology we would expect, with a 99
percent confidence level, 99.9 percent of the hourly emissions rate
data to be less than the UTL value. We are also proposing a 90
percentile of the population (of hourly emissions rate readings). We
request comment on these proposed levels. In particular we request
comment on whether a 99 or 90 percentile of the population (of hourly
emissions rate readings) would be more appropriate. We also request
comment on whether a 95 or 90 percent confidence level would be more
appropriate.
Alternatives 1 and 2 focus on EGU emissions during periods of
representative operation at the greatest actual operating capacity of
the unit, as demonstrated over the preceding 5 years (that is, the
capacity that the unit actually utilized in the preceding 5 years). We
believe that this is appropriate for a test with the purpose of,
essentially, determining whether a physical or operational change
increases the capacity of the unit, or the capacity utilization of the
unit, over that achieved in the past 5 years. We further believe that
the statistical approach properly accounts for the variability inherent
in EGU operations and air pollution control technology. This approach
helps to ensure that the emissions from an EGU will not exceed its pre-
change maximum achieved hourly emissions rate simply through the random
variability of the system, when a change has not expanded the capacity
of the unit. Thus, the statistical approach utilizes actual recorded
data from periods of representative operation to calculate the maximum
actual hourly emissions rate in the past 5 years. We expect that for
the most part, this rate will be associated with the pre-change
[[Page 26216]]
maximum actual operating capacity during this period.
Because Alternatives 1 and 2 can be used only if one has CEMS or
PEMS data, we cannot adopt these alternatives alone. That is, if we
elect to include either or both of these alternatives in the final
rule, we will also finalize another alternative to be used for
emissions of any regulated NSR pollutants that a source does not
measure directly with a CEMS or PEMS.
While we believe that the statistical approach would be best
applied to hourly emissions data from the periods of highest heat input
rates, we also propose and request comment on the option of sorting and
extracting data based on the hourly emissions rate itself in lb/hr or
lb/MWh, as applicable. In this alternative method for conducting the
statistical approach, you would compile a data set in the same manner
as in Alternatives 1 and 2. As in Alternatives 1 and 2, you would
delete selected hourly data from this 365-day period in accordance with
the same data limitations. Specifically, you would delete data from
periods of startup, shutdown, and malfunction; periods when the CEMS or
PEMS was out of control (as described below); and periods of
noncompliance, as defined in proposed Sec. 51.167(f)(2). However, the
data would then be sorted by the recorded hourly average emissions
rates, rather than by heat input rates. You would then extract the
hourly data for the 10 percent of the data set corresponding to the
highest hourly emissions rate readings for the selected period. You
would next apply basic statistical analyses to the extracted CEMS or
PEMS hourly emissions rate data, calculating the average emissions
rate, the standard deviation, and finally the UTL. Under this alternate
statistical method based on recorded hourly emissions rates, we are
proposing a 99.9 percentile of the population (of hourly emissions rate
readings) at a 99 percent confidence level. That is, under the proposed
methodology we would expect, with a 99 percent confidence level, 99.9
percent of the hourly emissions rate data to be less than the UTL
value. We are also proposing a 90 percentile of the population (of
hourly emissions rate readings). We request comment on these proposed
levels. In particular we request comment on whether a 99 or 90
percentile of the population (of hourly emissions rate readings) would
be more appropriate. We also request comment on whether a 95 or 90
percent confidence level would be more appropriate.
Proposed Alternatives 3 and 4 for determining the pre-change
maximum actual emissions rate use the highest emissions rate (in lb/hr
and lb/MWh, respectively) actually achieved for any hour within the 5-
year period immediately before the physical or operational change. That
is, the pre-change maximum emissions rate could be an emissions rate
that was actually achieved for only 1 hour in the 5-year period.
Under Alternatives 3 and 4, the highest hourly emissions rate would
be determined based on historical actual emissions. You must determine
the highest pre-change hourly emissions rate for each regulated NSR
pollutant using the best data available to you. You must use the
highest available source of data in the hierarchy presented below,
unless your reviewing authority has determined that a data source lower
in the hierarchy will provide better data for your EGU:
Continuous emissions monitoring system.
Approved PEMS.
Emission tests/emission factor specific to the EGU to be
changed.
Material balance.
Published emission factor (such as AP-42).
Under this hierarchy, most EGUs will use CEMS to measure the
highest hourly SO2 and NOX emissions. Some EGUs
are currently equipped with CEMS to measure CO, and would thus use CEMS
to measure historical hourly CO emissions. For other pollutants, we
anticipate most EGUs would measure historical actual emissions using
emission tests, site-specific emission factors, or mass balances (where
applicable). We request comment on appropriate measures of historical
actual emissions for all regulated NSR pollutants for all EGUs. In
particular, we request comment on appropriate measures of historical
actual emissions of CO, VOC, and lead, as turbines may not have
significant emissions of these regulated NSR pollutants. We also
request comment on whether emission factors that are not site-specific,
such as those in AP-42, would be appropriate measures of historical
actual emissions.
As discussed above, proposed Alternatives 1 and 3 provide specific
proposed rule language for the input-based (lb/hr) alternatives.
Proposed Alternatives 2 and 4 provide specific proposed rule language
for the output-based (lb/MWh) alternatives, largely repeating the
proposed language for Alternatives 1 and 3, respectively. For purposes
of the output-based alternatives, the proposed language for their
input-based counterparts is adjusted in the following ways:
Emissions rates would be expressed in terms of lb/MWh,
rather than lb/hr.
For EGUs that are cogeneration units, emissions rates
would be determined based on gross energy output. For other EGUs,
emissions rates would be determined based on gross electrical output.
Actual and projected emissions rates in lb/MWh would be
determined over a 1-hour averaging period (that is, a period of one
hour of continuous operation, rather than an instantaneous spike).
We are proposing a gross output basis for this test, rather that
net output, due to the difficulties involved in determining net output.
This gross output basis is consistent with our recent revisions to the
NSPS for EUSGUs (40 CFR part 60, subpart Da; 71 FR 9866) and stationary
combustion turbines (40 CFR part 60, subpart KKKK; 71 FR 38487).
For the output-based alternatives, we propose to cite the
definitions in the CAIR rule at Sec. 51.124(q) for the definitions of
``cogeneration unit'' and numerous other terms used in that definition.
We propose to include definitions in Sec. 51.167(h)(2) of this rule
for ``gross electrical output'' and ``gross energy output.'' We propose
to add definitions for ``gross power output'' and ``useful thermal
energy output,'' which are terms used in the proposed definition of
``gross energy output.'' We invite comment on the output-based approach
in general, the proposed output-based alternatives, and the related
definitions we are proposing.
2. Determining the Post-Change Emissions Rate. We are proposing the
same approach to post-change emissions for Alternatives 1 through 4.
Specifically, for each regulated NSR pollutant, you must project the
maximum emissions rate that your EGU will actually achieve in any 1
hour in the 5 years following the date the EGU resumes regular
operation after the physical or operational change. An emissions
increase results from the physical or operational change if this
projected maximum actual hourly emissions rate exceeds the pre-change
maximum actual hourly emissions rate. Regardless of any preconstruction
projections, you must treat an emissions increase as occurring if the
emissions rate actually achieved in any 1 hour during the 5 years after
the change exceeds the pre-change maximum actual hourly emissions rate.
3. Data Limitations in Determining Emissions Rates. We are
proposing four limitations on the data used to determine pre-change and
post-change maximum emissions rates under the
[[Page 26217]]
maximum achieved hourly emissions test (see proposed Sec.
51.167(f)(2)(i)). The proposed limitations are identical for
Alternatives 1 through 4. For purposes of determining maximum emissions
rates under the maximum achieved test, we propose that you must not
include the following types of data in your calculations:
Emissions rate data associated with startups, shutdowns,
or malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
CEMS or PEMS data recorded during monitoring system out-
of-control periods. Out-of-control periods include those during which
the monitoring system fails to meet quality assurance criteria (for
example, periods of system breakdown, repair, calibration checks, or
zero and span adjustments) established by regulation, by permit, or in
an approved quality assurance plan.
Emissions rate data from periods of noncompliance when
your EGU was operating above an emission limitation that was legally
enforceable at the time the data were collected.
Data from any period for which the information is
inadequate for determining emissions rates, including information
related to the limitations listed above.
The first two of these limitations are based on requirements of the
NSPS General Provisions in subpart A of part 60. The prohibition of
data from periods of startup, shutdown, and malfunction is found in the
section on performance tests, specifically Sec. 60.8(c), which states,
in pertinent part:
Operations during periods of startup, shutdown, and malfunction
shall not constitute representative conditions for the purpose of a
performance test nor shall emissions in excess of the level of the
applicable emission limit during periods of startup, shutdown, and
malfunction be considered a violation of the applicable emission
limit unless otherwise specified in the applicable standard.
The principle set out in this paragraph is that emissions during
periods of startup, shutdown, and malfunction are not representative
and typically should not figure into emission calculations. We propose
to apply this principle to all data required to comply with the
requirements in this action, and not limit it to performance test data.
We do not believe that emissions during startup, shutdown, or
malfunction are a reasonable basis for determining whether a physical
or operational change at an EGU would result in an hourly emissions
increase. It is more appropriate to focus on emissions during normal
operations, which are expected to correlate more closely with the
actual operating capacity of the EGU than would emissions during
periods of startup, shutdown, or malfunction. The proposed rule
language also expands slightly on the language of Sec. 60.8(c) to
clarify the meanings of startup, shutdown, and malfunction in the
context of this action.
The second data limitation reflects Sec. 60.13(h), which states
that ``data recorded during periods of continuous system breakdown,
repair, calibration checks, and zero and span adjustments shall not be
included in data averages computed under this paragraph.'' We do not
believe that this type of unrepresentative CEMS or PEMS data, which may
bear no relationship to actual emissions, should be included in
calculations of maximum achieved emissions rates. The proposed rule
language refers to and defines ``monitoring system out-of-control
periods,'' in keeping with more current terminology for monitoring
systems.
The third proposed data limitation listed above would prohibit the
use of emissions rate data from periods of noncompliance when your EGU
was operating above an emission limitation that was legally enforceable
at the time the data were collected. This reflects existing
requirements under the major NSR program, specifically the definition
of ``baseline actual emissions'' that is used in the actual-to-
projected-actual applicability test. (See, for example, Sec.
51.166(b)(47)(i)(b).)
The fourth proposed data limitation reflects existing requirements
under the major NSR program, again in the definition of ``baseline
actual emissions'' that is used in the actual-to-projected-actual
applicability test. (See, for example, Sec. 51.166(b)(47)(i)(d).) This
limitation would preclude the use of data from periods where there is
inadequate information for determining emissions rates, including
information related to the other three data limitations. This provision
is simply intended to ensure that you generate reliable, defensible
values for pre-change and post-change emissions rates.
4. Recordkeeping and Reporting Requirements. Under proposed
Alternatives 1 through 4, an emissions increase has occurred if the
emissions rate actually achieved in any one hour during the 5 years
after the change exceeds the pre-change maximum actual hourly emissions
rate (see, for example Sec. 51.167(f)(1)(iii) under Alternative 1).
Most EGUs are already reporting hourly SO2 and
NOX emissions through CEMS data to EPA as part of their
requirements under the Acid Rain program and will continue to be
required to do so under the CAIR. The Acid Rain and CAIR programs also
require recordkeeping and reporting for EGUs not using CEMS, such that
hourly emissions. PM2.5, VOC, and CO emissions can be
computed from SO2 and NOX emissions data.
Therefore, emissions increases of regulated NSR pollutants will be
transparent to the Agency and to the public. However, we request
comment on whether additional recordkeeping and reporting requirements
for post-change emissions should be required where EGUs are not using
CEMS to measure emissions.
B. Test for EGUs Based on Maximum Achievable Emissions Rates
As we stated in our October 2005 NPR (70 FR 61090), we are
proposing to allow existing EGUs to use the same maximum achievable
hourly emissions test applied in the NSPS to determine whether a
physical or operational change results in an emissions increase under
the major NSR program. This test is based on a comparison of pre-change
and post-change emissions rates in pounds per hour (lb/hr).\31\ We are
proposing an additional variation on the NSPS test, which would compare
pre-change and post-change achievable emissions rates in pounds per
megawatt-hour (lb/MWh). In the discussion that follows and in the
proposed rule language, we refer to these two approaches as
Alternatives 5 and 6, respectively.
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\31\ In the NSPS regulations, emissions rates are compared in
terms of kilograms per hour. We use English units in this proposed
rulemaking in keeping with longstanding practice in the major NSR
program, where annual emissions are generally computed using the lb/
hr rate and hours of operation.
---------------------------------------------------------------------------
1. Determining Pre-Change and Post-Change Emissions Rates. Under
Alternative 5, the major NSR regulations would apply at an EGU if a
physical or operational change results in any increase above the
maximum hourly emissions achievable at that unit during the 5 years
prior to the change. Under this alternative, we are proposing to
incorporate provisions similar to those in Sec. 60.14(h) into the new
Sec. 51.167(f) (1). We propose that this regulatory language would
substantially mirror, but would not be identical to, Sec. 60.14(h). As
with the definition of modification that we are proposing for Sec.
51.167(h) (2), there are differences between the two
[[Page 26218]]
programs that prevent a wholesale adoption of the NSPS modification
provisions of Sec. 60.14(h). Specifically, our proposed rule language
addresses the full range of pollutants regulated under the major NSR
program by referring to the ``regulated NSR pollutants,'' while the
NSPS provisions limit the analysis to those pollutants regulated under
an applicable NSPS. Also, as we previously explained at 70 FR 61090, we
are proposing that the emissions increase test would apply to EGUs,
rather than to EUSGUs. Under Alternative 5, Sec. 51.167(f) (1) would
---------------------------------------------------------------------------
read as follows:
Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable hourly emissions rate before the
physical or operational change to the maximum achievable hourly
emissions rate after the change. Determine these maximum achievable
hourly emissions rates according to Sec. 60.14(b) of this chapter.
No physical change, or change in the method of operation, at an
existing EGU shall be treated as a modification for the purposes of
this section provided that such change does not increase the maximum
hourly emissions of any regulated NSR pollutant above the maximum
hourly emissions achievable at that unit during the 5 years prior to
the change.
As stated in this proposed rule language, pre-change and post-
change hourly emissions rates would be determined according to the NSPS
provisions in Sec. 60.14(b). That is, hourly emissions increases would
be determined using emission factors, material balances, continuous
monitor data, or manual emission tests.
Alternative 6 is also based on the NSPS ``maximum achievable''
test, but is modified to an energy output (lb/MWh) basis. Under
Alternative 6, Sec. 51.167(f) (1) would read as follows:
Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable emissions rate in pounds per
megawatt-hour (lb/MWh) before the physical or operational change to
the maximum achievable emissions rate in lb/MWh after the change.
Determine these maximum achievable emissions rates according to
Sec. 60.14(b) of this chapter, using emissions rates in lb/MWh
achievable over 1 hour of continuous operation in place of mass
emissions rates. For EGUs that are cogeneration units, determine
emissions rates based on gross energy output. For other EGUs,
determine emissions rates based on gross electrical output. No
physical change, or change in the method of operation, at an
existing EGU shall be treated as a modification for the purposes of
this section provided that such change does not increase the maximum
emissions rate of any regulated NSR pollutant above the maximum
emissions rate achievable at that unit during the 5 years prior to
the change.
To maintain an hourly basis for the emissions rate, the proposed
language specifies that the maximum achievable emissions rate in lb/MWh
is to be determined based on what is achievable over 1 hour of
continuous operation (that is, a 1-hour averaging period rather than an
instantaneous spike). In addition, as noted above in the discussion of
the output-based alternatives under the maximum achieved hourly
emissions test (Alternatives 2 and 4), we propose to cite the
definition in the CAIR rule at Sec. 51.124(q) for the definitions of
``cogeneration unit'' and related terms. We propose to include
definitions in Sec. 51.167(h) (2) of this rule for ``gross electrical
output,'' ``gross energy output,'' ``gross power output,'' and ``useful
thermal energy output.''
2. Data Limitations in Determining Emissions Rates. We are
proposing three limitations on the data used to calculate the pre-
change and post-change emissions rates under the maximum achievable
hourly emissions test (see proposed Sec. 51.167(f) (2) (ii)). The
proposed limitations are identical for Alternatives 5 and 6. For
purposes of determining maximum emissions rates under the maximum
achievable test, we propose that you must not use the following types
of data in your calculations:
Emissions rate data associated with startups, shutdowns,
or malfunctions of your EGU, as defined by applicable regulation(s) or
permit term(s), or malfunctions of an associated air pollution control
device. A malfunction means any sudden, infrequent, and not reasonably
preventable failure of the EGU or the air pollution control equipment
to operate in a normal or usual manner.
CEMS or PEMS data recorded during monitoring system out-
of-control periods. Out-of-control periods include those during which
the monitoring system fails to meet quality assurance criteria (for
example, periods of system breakdown, repair, calibration checks, or
zero and span adjustments) established by regulation, by permit, or in
an approved quality assurance plan.
Data from any period for which there is inadequate
information for determining emissions rates, including information
related to the limitations listed above.
These proposed data limitations are the same as three of the four
data limitations that we are proposing for the maximum achieved tests
(Alternatives 1 through 4). See Section IV.A.3. above for the
discussion of these three data limitations.
3. Recordkeeping and Reporting for Hourly Emissions. We are
proposing the same recordkeeping and reporting approach for the maximum
achievable test (Alternatives 5 and 6) that we propose for the maximum
achieved hourly emissions test (Alternatives 1 through 4). We describe
our approach in Section IV.A.4 of this preamble.
V. Proposed Regulations for Option 2: Hourly Emissions Increase Test
This section contains details on the proposed regulatory language
for Option 2, the hourly emissions increase test. We are proposing that
Option 2 would apply to all existing EGUs. As we noted at 70 FR 61093,
however, we are also requesting comment on whether Option 2 should be
limited to the geographic area covered by CAIR, or to the geographic
area covered by both CAIR and BART. We are also proposing that the
Option 2 would apply to all regulated NSR pollutants. However, we also
request comment on whether Option 2 should be limited to increases of
SO2 and NOX emissions.
In this SNPR, for Option 2 we are proposing to exempt EGUs from the
procedures in the current regulations for determining a significant
emissions increase and a significant net emissions increase.
Specifically, we are proposing to exempt EGUs from the applicability
procedures based on a significant emissions increase and significant
net emissions increase in the current regulations at 40 CFR 51.165,
51.166, 52.21, and 52.24 and in appendix S to 40 CFR part 51. That is,
we are proposing to amend each of these sections to exempt EGUs from
all provisions for significant emissions increases and significant net
emission increases. For example, under Option 2 the provisions for
determining a significant emissions increase and a significant net
emissions increase in Sec. 51.166(a) (7) (iv)(a) would be amended to
exempt EGUs as follows.
(a) Except for EGUs as defined in Sec. 51.167(h)(1) of this
Subpart, and except as otherwise provided in paragraphs (a)(7)(v)
and (vi) of this section, and consistent with the definition of
major modification contained in paragraph (b)(2) of this section, a
project is a major modification for a regulated NSR pollutant if it
causes two types of emissions increases--a significant emissions
increase (as defined in paragraph (b)(39) of this section), and a
significant net emissions increase (as defined in paragraphs (b)(3)
and (b)(23) of this section). The project is not a major
modification if it dos not cause a significant emissions increase.
If the project causes a significant emissions increase, then the
project is a major modification only if it also results in a
significant net emissions increase.
[[Page 26219]]
We are proposing to amend all other provisions for significant
emissions increase and significant net emissions increase in the
current regulations at 40 CFR 51.165, 51.166, 52.21, and 52.24 and in
appendix S to 40 CFR part 51 in an analogous manner to exempt EGUs.
In place of the applicability procedures in the current regulations
concerning significant emissions increase and significant net emissions
increase, Option 2 applies an hourly emissions increase test to EGUs.
We describe these as Steps 1 and 2, which comprise the two-step
modification test and are the same as under Option 1, in Section IV of
this preamble. As with Option 1, under Option 2, we are proposing to
develop two new sections (40 CFR 51.167 and 52.37) to the major NSR
program rules that would include the two-step provisions for
modifications at EGUs. Thus, the amendatory language in this action
applies to Option 2 as it relates to Steps 1 and 2. That is, under
Option 2, EGUs would be subject to the new two-step requirements for
modifications. They would not be subject to the requirements in the
existing regulations for major modifications.
Alternatives 1-6, comprising Step 2 of Option 2, are the same as
under Option 1. We describe these alternatives in detail above in
Section IV of this preamble. Table 10 shows Option 2, including
Alternatives 1-6.
Table 9.--Major NSR Applicability for Existing EGUs Under Option 2
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Option 2........................................................... Step 1: Physical Change or Change in the
Method of Operation.
Step 2: Hourly Emissions Increase Test.
Alternative 1--Maximum achieved
hourly emissions; statistical approach;
input basis.
Alternative 2--Maximum achieved
hourly emissions; statistical approach;
output basis.
Alternative 3--Maximum achieved
hourly emissions; one-in-5-year baseline;
input basis.
Alternative 4--Maximum achieved
hourly emissions; one-in-5-year baseline;
output basis.
Alternative 5--NSPS test--maximum
achievable hourly emissions; input basis.
Alternative 6--NSPS test--maximum
achievable hourly emissions; output basis.
----------------------------------------------------------------------------------------------------------------
Under Option 2, if a physical or operational change at an existing
EGU is found to be a modification according to this hourly emissions
test, the EGU would then be subject to all the substantive major NSR
requirements of the existing regulations. Accordingly, we are also
proposing to revise the substantive provisions in all the current major
NSR regulations that apply to major modifications to apply also to
modifications at EGUs. The amendatory language in this proposed rule
does not include specific provisions for these changes. The substantive
provisions to be amended would include, but not be limited to, the
provisions in Sec. 51.166(a)(7)(i) through (iii), (b)(9), (b)(12),
(b)(14)(ii), (b)(15), (b)(18), (i)(1) through (9), (j)(1) through (4),
(m)(1) through (3), (p)(1) through (7), (r)(1) through (7), and (s)(1)
through (4). For example, we are proposing to amend Sec.
51.166(a)(7)(iii) as follows.
(iii) No new major stationary source, major modification, or
modification at an EGU to which the requirements of paragraphs (j)
through (r)(5) of this section apply shall begin actual construction
without a permit that states that the major stationary source, major
modification, or modification at an EGU will meet those
requirements.
We are proposing to amend all other provisions in the current
regulations at 40 CFR 51.165, 51.166, 52.21, and 52.24 and in appendix
S to 40 CFR part 51 in an analogous manner to require that the
substantive provisions in all the current major NSR regulations apply
to modifications at EGUs.
VI. Legal Basis and Policy Rationale
This section supplements the legal arguments in our October 2005
proposal. (70 FR 70565.) In that action, we provided our legal basis
and rationale for the proposed maximum achievable hourly emissions test
and our alternative proposal, the maximum achieved hourly emissions
test. We noted that the key statutory provisions provide, in relevant
part, that a ``modification'' that triggers NSR occurs when a physical
change or change in the method of operation ``increases the amount of
any air pollutant emitted'' by the source. Although the Court in New
York v. EPA held that the quoted provision refers to increases in
actual emissions, the Court further indicated that the statute was
silent as to the method for determining whether increases occur.
When a statute is silent or ambiguous with respect to specific
issues, the relevant inquiry for a reviewing court is whether the
Agency's interpretation of the statutory provision is permissible.
Chevron U.S.A., Inc. v. NRDC, Inc. 467 U.S. 837, 865 (1984).
Accordingly, we have broad discretion to propose a reasonable method by
which to calculate emissions increases for purposes of NSR
applicability.
This action continues to propose both the maximum achievable hourly
emissions increase test and the maximum achieved hourly emissions
increase test. We set forth legal basis and rationale in the NPR for
these two tests. In this SNPR, however, we provide additional legal and
policy basis for the hourly emissions increase tests, on both an input
and output basis.
We believe that a test based on maximum actual hourly emissions is
a reasonable measure of actual emissions. It measures actual emissions
at peak, or close to peak, physical and operational capacity. For
reasons described elsewhere, and summarized below, we believe this
approach implements sound policy objectives.
As we noted at 70 FR 61091, we believe that a test based on maximum
achievable hourly emissions remains a test based on actual emissions.
The reason is that, as noted in the October 2005 proposal, as a
practical matter, for most, if not all EGUs, the hourly rate at which
the unit is actually able to emit is substantively equivalent to that
unit's historical maximum hourly emissions. That is, most, if not all
EGUs will operate at their maximum actual physical and operational
capacity at some point in a 5-year period. In general, highest
emissions occur during the period of highest utilization. As a result,
both the maximum achievable and maximum achieved hourly emissions
increase tests allow an EGU to utilize all of its existing capacity,
and in this aspect the hourly rate at which the unit is actually able
to emit is substantively equivalent under both tests.
Some commenters took issue with this statement, arguing that
maximum achievable emissions could differ from maximum achieved
emissions for a given EGU for any given period as a result of factors
independent of the physical or operational change, including
variability of the sulfur content in the coal being burned.
[[Page 26220]]
We have long recognized that the highest hourly emissions do not
always occur at the point of highest capacity utilization, due to
fluctuations in process and control equipment operation, as well as in
fuel content and firing method. In fact, we justified an emission
factor approach as our preferred approach when we proposed the NSPS
regulations at Sec. 60.14 in 1974. (See 39 FR 36947.) As we also noted
in developing these NSPS provisions for modifications, ``measurement
techniques such as emission tests or continuous monitors are sensitive
to routine fluctuations in emissions, and thus a method is needed to
distinguish between significant increases in emissions and routine
fluctuations in emissions.'' (39 FR 36947.) At that time, we proposed a
statistical method for use with stack tests and continuous monitors to
measure actual emissions to address this issue.
In light of these concerns, we developed a statistical approach for
the maximum achieved hourly emissions increase test to assure that it
identifies the maximum hourly pollutant emissions value (for example
maximum lb/hr NOX during a specific one-year period). The
statistical procedure would provide an estimate of the highest value
(99.9 percentage level) in the period represented by the data set. We
believe that this approach mitigates some of the uncertainty associated
with trying to identify the highest hourly emissions rate at the
highest capacity utilization.\32\ We thus believe that, over a period
that is representative of normal operations, in general the maximum
achievable and maximum achieved hourly emissions test would lead to
substantially equivalent results.
---------------------------------------------------------------------------
\32\ Commenters stated that the maximum achieved test is
difficult to comply with due to fluctuations in equipment and
control device performance that are beyond the control of the EGU
owner/operator.
---------------------------------------------------------------------------
Each of these proposed options would promote the safety,
reliability, and efficiency of EGUs. Each of the options would balance
the economic need of sources to use existing operating capacity with
the environmental benefit of regulating those emission increases
related to a change, considering the substantial national emissions
reductions other programs have achieved or will achieve from EGUs. The
proposed regulations are consistent with the primary purpose of the
major NSR program, which is to balance the need for environmental
protection and economic growth. As the analyses included in this SNPR
demonstrate, the proposed regulations would not have an undue adverse
impact on local air quality. Furthermore, as our analyses demonstrate,
increases in hours of operation at EGUs, to the extent they may change
under a maximum hourly rate test, do not increase national
SO2, NOX, PM2.5, VOC, or CO emissions.
Consistent with earlier analyses, our analyses demonstrate that in a
system where most of the national emissions are capped, the more hours
an EGU operates, the more likely it is to install controls.
Moreover, each of the proposed options also offers additional
benefits consistent with our overall policy goals. Option 1 would
simplify major NSR for changes where there is no increase in hourly
emissions. However, many public commenters urged that we retain the
significant emissions increase component of the emissions increase
test. Therefore, we propose Option 1, our preferred Option, for the
purpose of maintaining the current significant net emissions increase
component of the emissions increase test.
Option 2 with the proposed maximum hourly tests would simplify
major NSR by reducing applicability determinations complexity. Option 2
with the proposed maximum hourly achievable test provides more
simplicity by conforming major NSR applicability determinations to NSPS
applicability determinations. We also note that Option 2 (both
achievable and achieved alternatives) eliminates the burden of
projecting future emissions and distinguishing between emissions
increases caused by the change from those due solely to demand growth,
because any increase in the emissions under the maximum hourly
achievable emissions test would logically be attributed to the change.
In addition, Option 2 reduces recordkeeping and reporting burdens on
sources because compliance will no longer rely on synthesizing
emissions data into rolling average emissions. Option 2 would also
reduce the reviewing authorities' compliance and enforcement burden.
Consistent with our policy goal of encouraging efficient use of
existing energy capacity, we are continuing to propose an output-based
format for the hourly emissions increase tests. An output-based
standard establishes emission limits in a format that incorporates the
effects of unit efficiency by relating emissions to the amount of
useful energy generated, not the amount of fuel burned. By relating
emission limitations to the productive output of the process, output-
based emission limits encourage energy efficiency because any increase
in overall energy efficiency results in a lower emission rate. Allowing
energy efficiency as a pollution control measure provides regulated
sources with an additional compliance option that can lead to reduced
compliance costs as well as lower emissions. The use of more efficient
technologies reduces fossil fuel use and leads to multi-media
reductions in environmental impacts both on-site and off-site.
Option 2 does not include steps for determining whether significant
net emissions increases have occurred. We recognize that the D.C.
Circuit, in the seminal case, Alabama Power v. EPA, 636 F.2d 323 (D.C.
Cir. 1980), which was handed down before Chevron, held that failure to
interpret ``increases'' to allow netting would be ``unreasonable and
contrary to the expressed purposes of the PSD provisions. * * * '' Id.
at 401. As we noted at 70 FR 61093, it is important to place this
ruling in the context of the rules before the Court at that time. Our
1978 regulations required a source-wide accumulation of emissions
increases without providing for an ability to offset these accumulated
increases with any source-wide decreases. In finding that we must apply
a bubble approach, the Court held that we could not require sources to
accumulate increases without also accumulating decreases. It is unclear
whether the Court would have reached the same conclusion if the
emissions test before the Court only considered the increases from the
project under review and not source-wide increases from multiple
projects. We request comment on our observations related to the Alabama
Power Court's decision related to netting and whether a major NSR
program without netting can be supported under the Act.
With respect to the significance levels, which, like netting, are
not included under Option 2, we recognize that Alabama Power also
upheld significance levels as a ``permissible * * * exercise of agency
power, inherent in most statutory schemes, to overlook circumstances
that in context may fairly be considered de minimis.'' Id. At 360. It
is clear, however, that the Court considered the establishment of
significance levels as discretionary. We believe that significance
levels are not important to include in the rules proposed in Option 2
because under those rules, relatively minor changes for which the
significance levels might come into play would not increase the maximum
hourly rate. By comparison, the changes that do increase the maximum
hourly rate are likely to be capacity increases that should not, by
their nature, be considered de minimis.
[[Page 26221]]
We request comment on all aspects of our legal and policy basis.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action.'' The action was
identified as a ``significant regulatory action'' because it raises
novel legal or policy issues. Accordingly, EPA submitted this action to
the Office of Management and Budget (OMB) for review under EO 12866 and
any changes made in response to OMB recommendations have been
documented in the docket for this action.
In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
Information Collection Request (ICR) document assigned EPA ICR number
1230.19. A copy of the analysis is available in the docket for this
action and the analysis is briefly summarized in the Paperwork
Reduction Act section.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR
document prepared by EPA has been assigned EPA ICR number 1230.19.
Certain records and reports are necessary for the State or local
agency (or the EPA Administrator in non-delegated areas), for example,
to: (1) Confirm the compliance status of stationary sources, identify
any stationary sources not subject to the standards, and identify
stationary sources subject to the rules; and (2) ensure that the
stationary source control requirements are being achieved. The
information would be used by the EPA or State enforcement personnel to
(1) identify stationary sources subject to the rules, (2) ensure that
appropriate control technology is being properly applied, and (3)
ensure that the emission control devices are being properly operated
and maintained on a continuous basis. Based on the reported
information, the State, local or tribal agency can decide which plants,
records, or processes should be inspected.
The proposed rule would reduce burden for owners and operators of
major stationary sources. We expect the proposed rule would simplify
applicability determinations, eliminate the burden of projecting future
emissions and distinguishing between emissions increases caused by the
change from those due solely to demand growth, and reduce recordkeeping
and reporting burdens. Over the 3-year period covered by the ICR, we
estimate an average annual reduction in burden for all industry
entities that would be affected by the proposed rule. For the same
reasons, we also expect the proposed rule to reduce burden for State
and local authorities reviewing permits when fully implemented.
However, there would be a one-time, additional burden for State and
local agencies to revise their SIPs to incorporate the proposed
changes.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purpose of responding to the information
collection; adjust existing ways to comply with any previously
applicable instructions and requirements; train personnel to respond to
a collection of information; search existing data sources; complete and
review the collection of information; and transmit or otherwise
disclose the information.
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 EPA's
regulations are listed in 40 CFR parts 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, including use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number EPA-HQ-OAR-2005-1063. Submit
any comments related to the ICR for this proposed rule to EPA and OMB.
See ADDRESSES section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, Northwest, Washington, DC 20503, Attention: Desk
Officer for EPA. Since OMB is required to make a decision concerning
the ICR between 30 and 60 days after May 8, 2007, a comment to OMB is
best assured of having its full effect if OMB receives it by June 7,
2007. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act (RFA)
The 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 notice on small
entities, small entity is defined as: (1) A small business that is a
small industrial entity as defined in the U.S. Small Business
Administration (SBA) size standards. (See 13 CFR 121.201); (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; or (3) a small organization that is any not-for-profit
enterprise that is independently owned and operated and is not dominant
in its field.
After considering the economic impacts of this notice on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. In
determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analyses is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the proposed rule on small entities.'' 5 U.S.C. 603
and 604. Thus, an agency may certify that a rule will not have a
significant economic impact on a substantial number of small entities
if the rule relieves regulatory burden, or otherwise has a positive
economic effect, on all of the small entities subject to the rule.
We believe that these proposed rule changes will relieve the
regulatory burden associated with the major NSR program for all EGUs,
including any EGUs that are small businesses. This is because the
proposed rule would simplify applicability determinations, eliminate
the burden of projecting future emissions and distinguishing between
emissions increases caused by the change from those due solely to
demand growth, and by reducing recordkeeping and reporting burdens. As
a result, the program changes
[[Page 26222]]
provided in the proposed rule are not expected to result in any
increases in expenditure by any small entity.
We have therefore concluded that this proposed rule would relieve
regulatory burden for all small entities. We continue to be interested
in the potential impacts of the proposed rule on small entities and
welcome comments on issues related to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements.
We have determined that this rule would not contain a Federal
mandate that would result in expenditures of $100 million or more by
State, local, and tribal governments, in the aggregate, or the private
sector in any 1 year. Although initially these changes are expected to
result in a small increase in the burden imposed upon reviewing
authorities in order for them to be included in the State's SIP, these
revisions would ultimately simplify applicability determinations,
eliminate the burden of reviewing projected future emissions and
distinguishing between emissions increases caused by the change from
those due solely to demand growth, and reduce the burden associated
with making compliance determinations. Thus, this action is not subject
to the requirements of sections 202 and 205 of the UMRA.
For the same reasons stated above, we have determined that this
notice contains no regulatory requirements that might significantly or
uniquely affect small governments. Thus, this action is not subject to
the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that 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.''
This proposed rule does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. We estimate a one-time burden of
approximately 2,240 hours and $83,000 for State agencies to revise
their SIPs to include the proposed regulations. However, these
revisions would ultimately simplify applicability determinations,
eliminate the burden of reviewing projected future emissions and
distinguishing between emissions increases caused by the change from
those due solely to demand growth, and reduce the burden associated
with making compliance determinations. This will in turn reduce the
overall burden of the program. Thus, Executive Order 13132 does not
apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This proposed rule does not
have tribal implications, as specified in Executive Order 13175. There
are no Tribal authorities currently issuing major NSR permits. To the
extent that this proposed rule may apply in the future to any EGU that
may locate on tribal lands, tribal officials are afforded the
opportunity to comment on tribal implications in this notice. Thus,
Executive Order 13175 does not apply to this rule.
Although Executive Order 13175 does not apply to this proposed
rule, EPA specifically solicits comment on this proposed rule from
tribal officials. We will also consult with tribal officials, including
officials of the Navaho Nation lands on which Navajo Power Plant and
Four Corners Generating Plant are located, before promulgating the
final regulations. In the spirit of Executive Order 13132, and
consistent with EPA policy to promote communications between EPA and
State and local government, EPA specifically solicits comment on this
proposed rule from State and local governments.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045: ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
This proposed rule is not subject to the Executive Order because it
is not economically significant as defined in Executive Order 12866,
and because the Agency does not have reason to believe
[[Page 26223]]
the environmental health or safety risks addressed by this action
present a disproportionate risk to children. We believe that, based on
our analysis of electric utilities, this rule as a whole will result in
equal environmental protection to that currently provided by the
existing regulations, and do so in a more streamlined and effective
manner. The public is invited to submit or identify peer-reviewed
studies and data, of which the agency may not be aware, that assessed
results of early life exposure to electric utilities.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' [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. In fact, this
rule improves owner/operator flexibility concerning the supply,
distribution, and use of energy. Specifically, the proposed rule would
increase owner/operators' ability to utilize existing capacity at EGUs.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (''NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (for example, materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA directs EPA
to provide Congress, through OMB, explanations when the Agency decides
not to use available and applicable voluntary consensus standards.
This proposed rule does not involve technical standards. Therefore,
EPA is not considering the use of any voluntary consensus standards.
EPA welcomes comments on this aspect of the proposed rulemaking and,
specifically, invites the public to identify potentially-applicable
voluntary consensus standards and to explain why such standards should
be used in this regulation.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 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 United States.
EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. This proposed rule amendment, in conjunction with other
existing programs, would not relax the control measures on sources
regulated by the rule and therefore would not cause emissions increases
from these sources.
VIII. Statutory Authority
The statutory authority for this action is provided by sections
307(d) (7) (B), 101, 111, 114, 116, and 301 of the CAA as amended (42
U.S.C. 7401, 7411, 7414, 7416, and 7601). This notice is also subject
to section 307(d) of the CAA (42 U.S.C. 7407(d)).
List of Subjects
40 CFR Part 51
Environmental protection, Administrative practice and procedure,
Air pollution control, Nitrogen dioxide, Sulfur dioxide.
40 CFR Part 52
Environmental protection, Administrative practice and procedure,
Air pollution control, Nitrogen dioxide, Sulfur dioxide.
Dated: April 25, 2007.
Stephen L. Johnson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:
PART 51--[AMENDED]
1. The authority citation for part 51 continues to read as follows:
Authority: 23 U.S.C. 101; 42 U.S.C. 7401--7671q.
Subpart I--[Amended]
2. Add Sec. 51.167 to read as follows:
Sec. 51.167 Preliminary major NSR applicability test for electric
generating units (EGUs).
(a) What is the purpose of this section? State Implementation Plans
and Tribal Implementation Plans must include the requirements in
paragraphs (b) through (h) of this section for determining (prior to or
after construction) whether a change to an EGU is a modification for
purposes of major NSR applicability. Deviations from these provisions
will be approved only if the State or Tribe demonstrates that the
submitted provisions are at least as stringent in all respects as the
corresponding provisions in paragraphs (b) through (h) of this section.
(b) Am I subject to this section? You must meet the requirements of
this section if you own or operate an EGU that is located at a major
stationary source, and you plan to make a change to the EGU.
(c) What happens if a change to my EGU is determined to be a
modification according to the procedures of this section? If the change
to your EGU is a modification according to the procedures of this
section, you must determine whether the change is a major modification
according to the procedures of the major NSR program that applies in
the area in which your EGU is located. That is, you must evaluate your
modification according to the requirements set out in the applicable
regulations approved pursuant to Sec. 51.165 and/or Sec. 51.166,
depending on the regulated NSR pollutants emitted and the attainment
status of the area in which your EGU is located for those pollutants.
Section 51.165 sets out the requirements for State nonattainment major
NSR programs, while Sec. 51.166 sets out the requirements for State
PSD programs.
(d) What is the process for determining if a change to an EGU is a
modification? The two-step process set out in paragraphs (d)(1) and (2)
of this section is used to determine (before beginning actual
construction) whether a change to an EGU located at a major stationary
source is a modification. Regardless of any preconstruction
projections, a modification has occurred if a change satisfies both
steps in the process.
(1) Step 1. Is the change a physical change in, or change in the
method of operation of, the EGU? (See paragraph (e) of this section for
a list of actions that are not physical or operational
[[Page 26224]]
changes.) If so, go on to Step 2 (paragraph (d)(2) of this section).
(2) Step 2. Will the physical or operational change to the EGU
increase the amount of any regulated NSR pollutant emitted into the
atmosphere by the source (as determined according to paragraph (f) of
this section) or result in the emissions of any regulated NSR
pollutant(s) into the atmosphere that the source did not previously
emit? If so, the change is a modification.
(e) What types of actions are not physical changes or changes in
the method of operation? (Step 1) For purposes of this section, a
physical change or change in the method of operation shall not include:
(1) Routine maintenance, repair, and replacement;
(2) Use of an alternative fuel or raw material by reason of an
order under sections 2(a) and (b) of the Energy Supply and
Environmental Coordination Act of 1974 (or any superseding legislation)
or by reason of a natural gas curtailment plan pursuant to the Federal
Power Act;
(3) Use of an alternative fuel by reason of an order or rule under
section 125 of the Act;
(4) Use of an alternative fuel at a steam generating unit to the
extent that the fuel is generated from municipal solid waste;
(5) Use of an alternative fuel or raw material by a stationary
source which the source is approved to use under any permit issued
under 40 CFR 52.21 or under regulations approved pursuant to Sec.
51.165 or Sec. 51.166, or which:
(i) For purposes of evaluating attainment pollutants, the source
was capable of accommodating before January 6, 1975, unless such change
would be prohibited under any federally enforceable permit condition
which was established after January 6, 1975 pursuant to 40 CFR 52.21 or
under regulations approved pursuant to 40 CFR part 51 subpart I or
Sec. 51.166; or
(ii) For purposes of evaluating nonattainment pollutants, the
source was capable of accommodating before December 21, 1976, unless
such change would be prohibited under any federally enforceable permit
condition which was established after December 21, 1976 pursuant to 40
CFR 52.21 or under regulations approved pursuant to 40 CFR part 51
subpart I or Sec. 51.166;
(6) An increase in the hours of operation or in the production
rate, unless such change is prohibited under any federally enforceable
permit condition which was established after January 6, 1975 (for
purposes of evaluating attainment pollutants) or after December 21,
1976 (for purposes of evaluating nonattainment pollutants) pursuant to
40 CFR 52.21 or regulations approved pursuant to 40 CFR part 51 subpart
I or Sec. 51.166;
(7) Any change in ownership at a stationary source;
(8) The installation, operation, cessation, or removal of a
temporary clean coal technology demonstration project, provided that
the project complies with:
(i) The State Implementation Plan for the State in which the
project is located; and
(ii) Other requirements necessary to attain and maintain the
national ambient air quality standard during the project and after it
is terminated;
(9) For purposes of evaluating attainment pollutants, the
installation or operation of a permanent clean coal technology
demonstration project that constitutes repowering, provided that the
project does not result in an increase in the potential to emit of any
regulated pollutant emitted by the unit. This exemption shall apply on
a pollutant-by-pollutant basis; or
(10) For purposes of evaluating attainment pollutants, the
reactivation of a very clean coal-fired EGU.
(f) How do I determine if there is an emissions increase? (Step 2)
You must determine if the physical or operational change to your EGU
increases the amount of any regulated NSR pollutant emitted to the
atmosphere using the method in paragraph (f)(1) of this section,
subject to the limitations in paragraph (f)(2) of this section. If the
physical or operational change to your EGU increases the amount of any
regulated NSR pollutant emitted into the atmosphere or results in the
emission of any regulated NSR pollutant(s) into the atmosphere that
your EGU did not previously emit, the change is a modification as
defined in paragraph (h)(2) of this section.
Alternative 1 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant for
which you have hourly average CEMS or PEMS emissions data with
corresponding fuel heat input data, compare the pre-change maximum
actual hourly emissions rate in pounds per hour (lb/hr) to a projection
of the post-change maximum actual hourly emissions rate in lb/hr,
subject to the provisions in paragraphs (f)(1)(i) through (iii) of this
section.
(i) Pre-change emissions. Determine the pre-change maximum actual
hourly emissions rate as follows:
(A) Select a period of 365 consecutive days within the 5-year
period immediately preceding when you begin actual construction of the
physical or operational change. Compile a data set (for example, in a
spreadsheet) with the hourly average CEMS or PEMS (as applicable)
measured emissions rates and corresponding heat input data for all of
the hours of operation for that 365-day period for the pollutant of
interest.
(B) Delete any unacceptable hourly data from this 365-day period in
accordance with the data limitations in paragraph (f)(2) of this
section.
(C) Extract the hourly data for the 10 percent of the remaining
data set corresponding to the highest heat input rates for the selected
period. This step may be facilitated by sorting the data set for the
remaining operating hours from the lowest to the highest heat input
rates.
(D) Calculate the average emissions rate from the extracted (i.e.,
highest 10 percent heat input rates) data set, using Equation 1:
[GRAPHIC] [TIFF OMITTED] TP08MY07.000
Where:
x = average emissions rate, lb/hr;
n = number of emissions rate values; and
xi = ith emissions rate value, lb/hr
(E) Calculate the standard deviation of the data set, s, using
Equation 2:
[GRAPHIC] [TIFF OMITTED] TP08MY07.001
(F) Calculate the Upper Tolerance Limit, UTL, of the data set using
Equation 3:
[[Page 26225]]
[GRAPHIC] [TIFF OMITTED] TP08MY07.002
Where:
Z1-p = 3.090, Z score for the 99.9 percentage of
interval; and
Z1-q = 2.326, Z score for the 99 percent confidence
level.
(G) Use the UTL calculated in paragraph (f)(1)(i)(F) of this
section as the pre-change maximum actual hourly emissions rate.
(ii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iii) Post-change emissions-actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 2 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant for
which you have hourly average CEMS or PEMS emissions data with
corresponding fuel heat input data, compare the pre-change maximum
actual emissions rate in pounds per megawatt-hour (lb/MWh) to a
projection of the post-change maximum actual emissions rate in lb/MWh,
subject to the provisions in paragraphs (f)(1)(i) through (iii) of this
section. For EGUs that are cogeneration units, emissions rates are
determined based on gross energy output. For other EGUs, emissions
rates are determined based on gross electrical output.
(i) Pre-change emissions. Determine the pre-change maximum actual
emissions rate as follows:
(A) Select a period of 365 consecutive days within the 5-year
period immediately preceding when you begin actual construction of the
physical or operational change. Compile a data set (for example, in a
spreadsheet) with the hourly average CEMS or PEMS (as applicable)
measured emissions rates in lb/MWh and corresponding heat input data
for all of the hours of operation for that 365-day period for the
pollutant of interest.
(B) Delete any unacceptable hourly data from this 365-day period in
accordance with the data limitations in paragraph (f)(2) of this
section.
(C) Extract the hourly data for the 10 percent of the remaining
data set corresponding to the highest heat input rates for the selected
period. This step may be facilitated by sorting the data set for the
remaining operating hours from the lowest to the highest heat input
rates.
(D) Calculate the average emissions rate from the extracted (i.e.,
highest 10 percent heat input rates) data set, using Equation 1:
[GRAPHIC] [TIFF OMITTED] TP08MY07.003
Where:
x = average emissions rate, lb/MWh;
n = number of emissions rate values; and
xi = ith emissions rate value, lb/MWh
(E) Calculate the standard deviation of the data set, s, using
Equation 2:
[GRAPHIC] [TIFF OMITTED] TP08MY07.004
(F) Calculate the Upper Tolerance Limit, UTL, of the data set using
Equation 3:
[GRAPHIC] [TIFF OMITTED] TP08MY07.005
Where:
Z1-p = 3.090, Z score for the 99.9 percentage of
interval; and
Z1-q = 2.326, Z score for the 99 percent confidence
level.
(G) Use the UTL calculated in paragraph (f)(1)(i)(F) of this
section as the pre-change maximum actual hourly emissions rate.
(ii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve over any period of 1 hour in the 5
years following the date the EGU resumes regular operation after the
physical or operational change. An emissions increase results from the
physical or operational change if this projected maximum actual
emissions rate exceeds the pre-change maximum actual emissions rate.
(iii) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
emissions rate actually achieved over any period of 1 hour in the 5
years after the change exceeds the pre-change maximum actual emissions
rate.
Alternative 3 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the pre-change maximum actual hourly emissions rate in pounds
per hour (lb/hr) to a projection of the post-change maximum actual
hourly emissions rate in lb/hr, subject to the provisions in paragraphs
(f)(1)(i) through (iv) of this section.
(i) Pre-change emissions--general procedures. The pre-change
maximum actual hourly emissions rate for the
[[Page 26226]]
pollutant is the highest emissions rate (lb/hr) actually achieved by
the EGU for 1 hour at any time during the 5-year period immediately
preceding when you begin actual construction of the physical or
operational change.
(ii) Pre-change emissions--data sources. You must determine the
highest pre-change hourly emissions rate for each regulated NSR
pollutant using the best data available to you. Use the highest
available source of data in the following hierarchy, unless your
reviewing authority has determined that a data source lower in the
hierarchy will provide better data for your EGU:
(A) Continuous emissions monitoring system (CEMS).
(B) Approved predictive emissions monitoring system (PEMS).
(C) Emission tests/emission factor specific to the EGU to be
changed.
(D) Material balance calculations.
(E) Published emission factor.
(iii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve in any 1 hour in the 5 years
following the date the EGU resumes regular operation after the physical
or operational change. An emissions increase results from the physical
or operational change if this projected maximum actual hourly emissions
rate exceeds the pre-change maximum actual hourly emissions rate.
(iv) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
hourly emissions rate actually achieved in the 5 years after the change
exceeds the pre-change maximum actual hourly emissions rate.
Alternative 4 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the pre-change maximum actual emissions rate in pounds per
megawatt-hour (lb/MWh) to a projection of the post-change maximum
actual emissions rate in lb/MWh, subject to the provisions in
paragraphs (f)(1)(i) through (iv) of this section. For EGUs that are
cogeneration units, emissions rates are determined based on gross
energy output. For other EGUs, emissions rates are determined based on
gross electrical output.
(i) Pre-change emissions--general procedures. The pre-change
maximum actual emissions rate for the pollutant is the highest
emissions rate (lb/MWh) actually achieved by the EGU over any period of
1 hour during the 5-year period immediately preceding when you begin
actual construction of the physical or operational change.
(ii) Pre-change emissions--data sources. You must determine the
highest pre-change emissions rate for each regulated NSR pollutant
using the best data available to you. Use the highest available source
of data in the following hierarchy, unless your reviewing authority has
determined that a data source lower in the hierarchy will provide
better data for your EGU:
(A) Continuous emissions monitoring system (CEMS).
(B) Approved predictive emissions monitoring system (PEMS).
(C) Emission tests/emission factor specific to the EGU to be
changed.
(D) Material balance calculations.
(E) Published emission factor.
(iii) Post-change emissions--preconstruction projections. For each
regulated NSR pollutant, you must project the maximum emissions rate
that your EGU will actually achieve over any period of 1 hour in the 5
years following the date the EGU resumes regular operation after the
physical or operational change. An emissions increase results from the
physical or operational change if this projected maximum actual
emissions rate exceeds the pre-change maximum actual emissions rate.
(iv) Post-change emissions--actually achieved. Regardless of any
preconstruction projections, an emissions increase has occurred if the
emissions rate actually achieved over any period of 1 hour in the 5
years after the change exceeds the pre-change maximum actual emissions
rate.
Alternative 5 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable hourly emissions rate before the
physical or operational change to the maximum achievable hourly
emissions rate after the change. Determine these maximum achievable
hourly emissions rates according to Sec. 60.14(b) of this chapter. No
physical change, or change in the method of operation, at an existing
EGU shall be treated as a modification for the purposes of this section
provided that such change does not increase the maximum hourly
emissions of any regulated NSR pollutant above the maximum hourly
emissions achievable at that unit during the 5 years prior to the
change.
Alternative 6 for paragraph (f)(1):
(1) Emissions increase test. For each regulated NSR pollutant,
compare the maximum achievable emissions rate in pounds per megawatt-
hour (lb/MWh) before the physical or operational change to the maximum
achievable emissions rate in lb/MWh after the change. Determine these
maximum achievable emissions rates according to Sec. 60.14(b) of this
chapter, using emissions rates in lb/MWh achievable over 1 hour of
continuous operation in place of mass emissions rates. For EGUs that
are cogeneration units, determine emissions rates based on gross energy
output. For other EGUs, determine emissions rates based on gross
electrical output. No physical change, or change in the method of
operation, at an existing EGU shall be treated as a modification for
the purposes of this section provided that such change does not
increase the maximum emissions rate of any regulated NSR pollutant
above the maximum emissions rate achievable at that unit during the 5
years prior to the change.
(2) Data limitations for maximum emissions rates. For purposes of
determining pre-change and post-change maximum emissions rates under
paragraph (f)(1) of this section, the following limitations apply to
the types of data that you may use:
(i) Data limitations for Alternatives 1-4.
(A) You must not use emissions rate data associated with startups,
shutdowns, or malfunctions of your EGU, as defined by applicable
regulation(s) or permit term(s), or malfunctions of an associated air
pollution control device. A malfunction means any sudden, infrequent,
and not reasonably preventable failure of the EGU or the air pollution
control equipment to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use emissions rate data from periods of
noncompliance when your EGU was operating above an emission limitation
that was legally enforceable at the time the data were collected.
(D) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(i)(A) through (C) of
this section.
(ii) Data limitations for Alternatives 5 and 6.
(A) You must not use emissions rate data associated with startups,
[[Page 26227]]
shutdowns, or malfunctions of your EGU, as defined by applicable
regulation(s) or permit term(s), or malfunctions of an associated air
pollution control device. A malfunction means any sudden, infrequent,
and not reasonably preventable failure of the EGU or the air pollution
control equipment to operate in a normal or usual manner.
(B) You must not use continuous emissions monitoring system (CEMS)
or predictive emissions monitoring system (PEMS) data recorded during
monitoring system out-of-control periods. Out-of-control periods
include those during which the monitoring system fails to meet quality
assurance criteria (for example, periods of system breakdown, repair,
calibration checks, or zero and span adjustments) established by
regulation, by permit, or in an approved quality assurance plan.
(C) You must not use data from any period for which the information
is inadequate for determining emissions rates, including information
related to the limitations in paragraphs (f)(2)(ii)(A) and (B) of this
section.
(g) What are my requirements for recordkeeping? You must maintain a
file of all information related to determinations that you make under
this section of whether a change to an EGU is a modification, subject
to the following provisions:
(1) The file must include, but is not limited to, the following
information recorded in permanent form suitable for inspection:
(i) Continuous monitoring system, monitoring device, and
performance testing measurements;
(ii) All continuous monitoring system performance evaluations;
(iii) All continuous monitoring system or monitoring device
calibration checks;
(iv) All adjustments and maintenance performed on these systems or
devices; and
(v) All other information relevant to any determination made under
this section of whether a change to an EGU is a modification.
(2) You must retain the file until the later of:
(i) The date 5 years following the date the EGU resumes regular
operation after the physical or operational change; and
(ii) The date 5 years following the date of such measurements,
maintenance, reports, and records.
(h) What definitions apply under this section? The definitions in
paragraphs (h)(1) and (2) of this section apply. Except as specifically
provided in this paragraph (h), terms used in this section have the
meaning accorded them under Sec. 51.165(a)(1) or Sec. 51.166(b), as
appropriate to the situation (for example, the attainment status of the
area where your source is located for a particular regulated NSR
pollutant of interest). Terms not defined here or in Sec. 51.165(a)(1)
or Sec. 51.166(b) (as appropriate) have the meaning accorded them
under the applicable requirements of the Clean Air Act, 42 U.S.C. 7401,
et seq.
(1) Terms related to EGUs that are defined in Sec. 51.124(q). The
following terms are as defined in Sec. 51.124(q):
Boiler.
Bottoming-cycle cogeneration unit.
Cogeneration unit.
Combustion turbine.
Electric generating unit or EGU.
Fossil fuel.
Fossil-fuel-fired.
Generator.
Maximum design heat input.
Nameplate capacity.
Potential electrical output capacity.
Sequential use of energy.
Topping-cycle cogeneration unit.
Total energy input.
Total energy output.
Useful power.
Useful thermal energy.
Utility power distribution system.
(2) Other terms defined for the purposes of this section.
Attainment pollutant means a regulated NSR pollutant for which your
EGU may be subject to the PSD program that is applicable in the area
where your EGU is located. In general, attainment pollutants are the
regulated NSR pollutants listed in the PSD program for which there is
no NAAQS or for which the area in which your EGU is located is
designated as attainment or unclassifiable according to part 81 of this
chapter. However, pollutant or precursor transport considerations may
cause such regulated NSR pollutants to be treated as nonattainment
pollutants as defined in this paragraph (h)(2) (for example, if your
EGU is located in an ozone transport region).
Gross electrical output means the electricity made available for
use by the generator associated with the EGU.
Gross energy output means, with regard to a cogeneration unit, the
sum of the gross power output and the useful thermal energy output
produced by the cogeneration unit.
Gross power output means, with regard to a cogeneration unit,
electricity or mechanical energy made available for use by the
cogeneration unit.
Modification, for an EGU, means any physical change in, or change
in the method of operation of, an EGU which increases the amount of any
regulated NSR pollutant emitted into the atmosphere by that source or
which results in the emission of any regulated NSR pollutant(s) into
the atmosphere that the source did not previously emit. An increase in
the amount of regulated NSR pollutants must be determined according to
the provisions in paragraph (f) of this section. For purposes of this
section, a physical change or change in the method of operation shall
not include the types of actions listed in paragraph (e) of this
section.
Nonattainment pollutant means a regulated NSR pollutant for which
your EGU may be subject to the nonattainment major NSR program that is
applicable in the area where your EGU is located. In general,
nonattainment pollutants are the regulated NSR pollutants listed in the
nonattainment major NSR program for which the area in which your EGU is
located is designated as nonattainment according to part 81 of this
chapter. However, pollutant or precursor transport considerations may
cause such regulated NSR pollutants to be treated as attainment
pollutants as defined in this paragraph (h)(2).
Useful thermal energy output means, with regard to a cogeneration
unit, the thermal energy made available for use in any industrial or
commercial process, or used in any heating or cooling application, that
is, total thermal energy made available for processes and applications
other than electrical or mechanical generation. Thermal output for this
section means the energy in recovered thermal output measured against
the energy in the thermal output at 15 degrees Celsius and 101.325
kilopascals of pressure.
[FR Doc. E7-8263 Filed 5-7-07; 8:45 am]
BILLING CODE 6560-50-P