[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:

[[Page 26203]]



------------------------------------------------------------------------
         Industry Group             SIC\a\             NAICS\b\
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
\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\
------------------------------------------------------------------------
 
------------------------------------------------------------------------
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.
------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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