 6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51 and 52

[Docket ID No. EPA-HQ-OAR-2005-0163; FRL- xxxx-x]

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.

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 or Act).  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 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 New Source
Performance Standards (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.  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
today’s SNPR, as described below.  We characterize this hourly
emissions increase test option (maximum hourly achieved or maximum
hourly achievable) as Option 2. This action also proposes an additional
option that was not included in the October 2005 rule.  For the
additional option proposed today, which we characterize as our preferred
Option 1, we are proposing that an hourly emissions increase test
(either maximum achieved or maximum achievable, each with an
output-based option) 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.  

These proposed regulations interpret the emissions increase component of
the modification test under CAA section 111(a) (4), in the context of
NSR, for existing EGUs.  The proposed regulations would promote the
safety, reliability, and efficiency of EGUs.

Consistent with the primary purpose of the major NSR program, the
proposed regulations balance the economic need of sources to utilize
their existing physical and operating capacity with the environmental
benefit of regulating those emissions increase related to a change. 

	DATES:  Comments.  Comments must be received on or before [INSERT DATE
60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].  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
[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

Public Hearing:  If anyone contacts us requesting to speak at a public
hearing on or before [INSERT DATE 20 DAYS AFTER PUBLICATION IN THE
FEDERAL REGISTER], 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:

	  HYPERLINK "http://www.regulations.gov"  http://www.regulations.gov : 
Follow the on-line instructions for submitting comments.

	E-mail: a-and-r-docket@epa.gov.

	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 B102, 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   HYPERLINK "http://www.regulations.gov" 
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 www.regulations.gov or e-mail. 
The   HYPERLINK "http://www.regulations.gov"  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   HYPERLINK "http://www.regulations.gov" 
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   HYPERLINK
"http://www.regulations.gov"  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   HYPERLINK "http://www.regulations.gov" 
http://www.regulations.gov  or in hard copy at the U.S. Environmental
Protection Agency, Air Docket, EPA/DC, EPA West Building, Room B102,
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.


NOTE:  The EPA Docket Center suffered damage due to flooding during the
last week of June 2006.  The Docket Center is continuing to operate. 
However, during the cleanup, there will be temporary changes to Docket
Center telephone numbers, addresses, and hours of operation for people
who wish to make hand deliveries or visit the Public Reading Room to
view documents.  Consult EPA's Federal Register notice at 71 FR 38147
(July 5, 2006) or the EPA website at www.epa.gov/epahome/dockets.htm for
current information on docket operations, locations and telephone
numbers.  The Docket Center’s mailing address for U.S. mail and the
procedure for submitting comments to www.regulations.gov are not
affected by the flooding and will remain the same.

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: 
mcdonald.janet@epa.gov.

SUPPLEMENTARY INFORMATION:

I.  General Information  TC "I.  General Information" \f C \l "1"  

A.  Does this action apply to me?  TC "A.  What are the regulated
entities?" \f C \l "2"  

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:

Industry Group	SICa	NAICSb

Electric Services	491	221112

Federal government	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? tc \l2 "B.Where can I get a copy of this document and other
related information? 

In addition to being available in the docket, an electronic copy of this
proposal will also be available on the WWW.  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  
HYPERLINK "http://www.epa.gov/nsr"  http://www.epa.gov/nsr .

C.  What should I consider as I prepare my comments for EPA? tc \l2 "C.
How should I submit Confidential Business Information (CBI) to the
Agency? 

1.  Submitting CBI.  Do not submit this information to EPA through  
HYPERLINK "http://www.regulations.gov"  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 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 submit comments to 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 Results

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 tc \l2 "A. 
Executive Order 12866Regulatory Planning and Review 

B.  Paperwork Reduction Act tc \l2 "B.  Paperwork Reduction Act 

C.  Regulatory Flexibility Act (RFA) tc \l2 "C.  Regulatory Flexibility
Act (RFA) 

D.  Unfunded Mandates Reform Act tc \l2 "D.  Unfunded Mandates Reform
Act 

E.  Executive Order 13132:  Federalism tc \l2 "E.  Executive Order
13132Federalism 

F.  Executive Order 13175:  Consultation and Coordination with Indian
Tribal Governments tc \l2 "F.  Executive Order 13175Consultation and
Coordination with Indian Tribal Governments 

G.  Executive Order 13045:  Protection of Children from Environmental
Health Risks and Safety Risks tc \l2 "G.  Executive Order
13045Protection of Children from Environmental Health Risks and Safety
Risks 

H.  Executive Order 13211:  Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use tc \l2 "H. 
Executive Order 13211Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use	 

I.  National Technology Transfer and Advancement Act

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, EPA (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 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 today 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
today’s 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 today,
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).  In
that case, which was handed down on June 15, 2005, the Fourth Circuit
Court of Appeals ruled that EPA must use a consistent definition of the
term “modification” under CAA section 111(a)(4) for the purposes of
both the NSPS program under section 111 of the Act and the PSD program
under part C of the Act.  The Court further ruled that because EPA had
defined the term first in the NSPS regulations through a test based on
increases in a plant’s hourly rate of emissions, the PSD regulations
had to be interpreted to include a consistent hourly test.  We continue
to respectfully disagree with the Fourth Circuit’s decisions in Duke
Energy and continue to believe that we have the authority to define
“modification” differently in the NSPS and NSR programs.  However,
we believe that the options for a maximum hourly test that we proposed
in our October 2005 NPR and in today’s SNPR are an appropriate
exercise of our discretion. 

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 run.  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.  Oral arguments were heard on November 1, 2006.  Of course,
it is unclear at present, what, if any, impact a Supreme Court decision
would have on the rulemaking on which we take supplemental action today.
 We continue to believe that providing an hourly emissions test has
particular merit for EGUs.  Accordingly, we continue to pursue the
viability of imposing an hourly emissions test on EGUs for purposes of
major NSR applicability.  We will, of course, conform our final rule, to
the extent required, to the decision the Supreme Court renders. 

  SEQ CHAPTER \h \r 1 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   HYPERLINK
"http://www.epa.gov/nsr/publications.html" 
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 today 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 not to reduce emissions, but 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 today’s 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 today, for the maximum hourly emissions tests and today’s
additional proposals.  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 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.  

Table 1.  Proposed Options for Major NSR Applicability for Existing EGU

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

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 action
in a single Federal Register Notice and Response to Comments Document.

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, today 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). We propose
Option 1 for the purpose of maintaining the current significant net
emissions increase component of the emissions increase test. However, we
recognize that Option 1 does not offer the benefits of streamlining
major NSR program to the extent that would occur under Option 2.  

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 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 are
capped nationally.  Other commenters supported the output based format,
noting that it would encourage energy efficiency.

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 NOx (40 CFR 63.44a, 62 FR
36954, and  63 FR 49446).  We recently promulgated new output-based
emission limits for 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

In this action, we are providing regulatory language, data, and
additional information in support of our proposed rule, published by
notice dated October 20, 2005, “Prevention of Significant
Deterioration, Nonattainment Major New Source Review, and New Source
Performance Standards: Emissions Test for Electric Generating Units.” 
   (70 FR 61081.)  In the October 2005 NPR, we proposed to revise the
emissions test for existing EGUs that are subject to the regulations
governing the major NSR programs mandated by parts C and D of title I of
the CAA.  We proposed to adopt an hourly emissions increase test and to
remove the requirement to compute a significant emissions increase and a
significant net emissions increase on an annual basis.  We also proposed
three alternatives for an hourly emissions test: a maximum achievable
hourly emissions test, a maximum achieved hourly emissions test, and an
output-based hourly emissions test.  In today’s SNPR, we have grouped
those alternatives in our October 2005 proposal into Option 2.  In doing
so, we have recast the output option, as described above.  That is, 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.

The proposed maximum hourly achieved test would streamline NSR
applicability determinations.  The proposed maximum hourly achievable
test provides even more streamlining 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.  It reduces 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.

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 (SO2) and nitrogen oxides (NOx) 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 Clean
Air Interstate Rule, Clean Air Mercury Rule, and Clean Air Visibility
Rule.  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.  

The IPM v 2.1.9 is based on 2,053 model plants, which represent
13,819 EGUs, including 1,242 coal-fired EGUs.  This represents all
existing EGUs in the 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 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.  

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 (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
Appendix 3-2, available at   HYPERLINK
"http://www.epa.gov/airmarkets/epa-ipm/" 
http://www.epa.gov/airmarkets/epa-ipm/ .  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 at   HYPERLINK
"http://www.epa.gov/airmarkets/epa-ipm/" 
http://www.epa.gov/airmarkets/epa-ipm/ . 

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.  For the years
2001 - 2004, the average annual planned outage hours for all EGUs was
572.09 (about 23 days), the average annual maintenance outage hours for
all 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 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 unavailable due to forced outages
approximately 4 percent of the hours in a year for the years 2000 -
2004.

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 
 HYPERLINK "http://www.epa.gov/airmarkets/cair/analyses.html" 
http://www.epa.gov/airmarkets/cair/analyses.html . 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.

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 designed one IPM model run to evaluate whether efficiency
improvements that sources may make as a result of today’s 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 the hourly test and 5-year annual test could result
in emissions increases as compared to the 10-year annual emissions
increase test.  We call this run the NSR Efficiency Scenario.  We
assumed the least efficient EGUs would increase their efficiency by 4
percent.  The NSR Efficiency Scenario projects retrofitting of more
control devices, small reductions in national EGU SO2 and NOx emissions,
and a somewhat different pattern of local emissions 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 our Technical Support Document.  SEQ CHAPTER \h \r 1 

NSR Availability Scenarios – Description of the Scenarios

We also 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.  As with the NSR Efficiency Scenario,
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.  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.  

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.
also contains specific information on the assumptions about EGU
assumptions in the IPM v.2.1.9.

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
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.  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.  

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.  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. 
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.  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 with a 10-year—as opposed to a
5-year—baseline.

Table 2.  2020 National EGUs With Emission Controls Under NSR
Availability Scenarios

	EGUs with Additional Controls Compared to 2004 Base Case	EGUs with
Additional Controls Compared to CAIR/CAMR/CAVR 2020

	NSR Availability 2%	NSR Availability 4%	NSR Availability 2%	NSR
Availability 4%

FGD	109.62 GW	111.53 GW	1.71 GW	3.63 GW

SCR	73.47 GW	73.92 GW	0.62 GW	1.07 GW



2.  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.  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.

Table 3.  National EGU Emissions Under NSR Availability Scenarios
Compared to CAIR/CAMR/CAVR 2020 (tpy)



	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 and NOx emissions.  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 Impact

To examine the effect of the maximum hourly and 10-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.  Tables 4 and 5 show these comparisons.

Table 4  Changes in County-level SO2 Emissions NSR Availability (4%)
Scenario Compared to CAIR/CAMR/CAVR 2020



Changes in SO2 Emissions	Number of Counties 

Total number of counties with decreases	65

Decreases between 20,000 and 36,941 tpy	2

Decreases between 3,000 and 20,000 tpy	13

Decreases between 1,000 and 3,000 tpy	12

Decreases between 40 and 1000 tpy	31

Decreases up to 39 tpy	7

No change in EGU emissions	780

Increases up to 39 tpy	30

Increases between 40 and 1000 tpy	255

Increases between 1,000 and 3,000 tpy	47

Increases between 3,000 and 6,801 tpy	6

Total number of counties with increases	338

 

Table 5.  Changes in County-level NOx Emissions NSR Availability (4%)
Scenario Compared to CAIR/CAMR/CAVR 2020



Changes in NOx Emissions	Number of Counties 

Total number of counties with decreases	238

Decreases between 3,000 and 10,720 tpy	2

Decreases between 1,000 and 3,000 tpy	9

Decreases between 40 and 1000 tpy	61

Decreases up to 39 tpy	166

No change in EGU emissions	540

Increases up to 39 tpy	126

Increases between 40 and 1000 tpy	269

Increases between 1,000 and 3,000 tpy	9

Increases between 3,000 and 3,172 tpy	1

Total number of counties with increases	405



As Tables 4 and 5 show, 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.  Furthermore, EGUs are subject to national SO2
caps under the Acid Rain Program. 

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 10-year
baseline tests. 

As Table 4 shows, in counties with an SO2 emissions increase of at
least 40 tons per year (tpy), emission increases ranged from 43 to
6,801 tpy.  The degree of county-level emission decreases was higher
than that of the increases, ranging from 10 to 36,941 tpy.  This
pattern also occurred with NOx emissions.  As Table 5 shows, in
counties with a NOx emissions increase of at least 40 tpy, emission
increases ranged from 41 to 3,172 tpy.  The degree of county-level
emission decreases was higher than that of the NOx increases, ranging
from 1 to 10,720 tpy.  The increases and decreases occurred in CAIR and
non-CAIR States.

To gain a further perspective on the projected county-level SO2 and NOx
increases under the NSR Availability (4%) Scenario, we compared them to
recorded actual annual EGU SO2 and NOx emissions in 2003 - 2004.  We
examined actual annual emissions from CEMS data transmitted to the
Agency on these EGUs.  In 2004, 2 EGUs had emissions increases of ≥
3,721 tpy NOx as compared to 2003.  In 2004, 15 EGUs had emissions
increases of ≥ 6,801 tpy SO2 as compared to 2003.  Thus, the highest
county-level projected emissions increases for SO2 and NOx under the NSR
Availability (4%) Scenario are less than the emissions increases that
actually occurred, measured using CEMS, at individual EGUs over the
period of 2003 - 2004.  As this perspective shows, the local emissions
increases that the IPM results indicate could theoretically occur from
the proposed emissions increase test are not large.  They are also
within the variability that occurred under the current emissions
increase test between the years 2003 - 2004.

We next examined the reasons for the largest increases and decreases in
county-level emissions under the NSR Availability (4%) Scenario. 
Table 6 shows the counties with the largest decreases and increases in
SO2 and NOx emissions.

 Table 6  Largest County-level Decreases and Increases Under NSR
Availability (4%) Scenario (tpy)

5 counties with largest decrease in SO2 emissions under the NSR
Availability Scenario

State	County	Decrease 	Variations in unit-level data that would explain
the decrease

GA	Monroe	-36,941	Unit installs SCR and FGD in NSR 4% run, no control in
CAIR/CAMR/CAVR 2020

AL	Jackson	-27,572	Widow Creek Units 1-6 are retired in the NSR 4% run

TN	Sumner	-17,282	Units are partially retrofitted in BART, fully
retrofitted in NSR 4%

MN	Itasca	-10,759	FGD goes on unit 3 in the NSR 4% run

TX	Titus	-10,552	Welsh unit 1 gets FGD in NSR 4% run

5 counties with largest decrease in NOx emissions under NSR Scenario

State	County	Decrease 	Variations in unit-level data that would explain
the increase

GA	Monroe	-10,720	Scherer units get SCR and FGD retrofits in the 4% run

OH	Lucas	-3,038	Bay Shore units 2,3 get SCR and FGD retrofits in the NSR
4% run

OH	Montgomery	-2,722	Hutchings units 1-6 retire

PA	Clearfield	-1,782	Shawville unit 1 retires

WI	Buffalo	-1,770	Alma units 4 & 5 retire

5 counties with largest increase in SO2 emissions under the NSR
Availability Scenario

State	County	Increase 	Variations in unit-level data that would explain
the increase

GA	Bartow	6,801	No change in controls, total fuel use increases

MI	Monroe	5,065	No change in controls, total fuel use increases

MI	St. Clair	4,011	No change in controls, total fuel use increases

GA	Heard	3,720	No change in controls, total fuel use increases

KY	Jefferson	3,401	No change in controls, total fuel use increases

5 counties with largest increase in NOx emissions under the NSR
Availability Scenario

State	County	Increase 	Variations in unit-level data that would explain
the increase

NM	San Juan	3,172	No change in controls, total fuel use increases

MT	Rosebud	1,543	No change in controls, total fuel use increases

ND	Mercer	1,445	No change in controls, total fuel use increases

AZ	Coconino	1,379	No change in controls, total fuel use increases

WI	Grant	1,306	SCR on Nelson plant in CAIR/CAMR/CAVR 2020, no SCR under
NSR 4%; decrease in utilization in NSR 4% compared to CAIR/CAMR/CAVR
2020.



For most counties in Table 6 where SO2 and NOx emission decreases are
projected (Monroe, Georgia; Sumner, Tennessee; Itasca, Minnesota; Titus,
Texas; and Lucas, Ohio), the decreases occur because EGUs are projected
to install controls under the NSR Availability (4%) Scenario but are not
projected to install controls under CAIR/CAMR/CAVR.  This effect occurs
because as these EGUs increase their hours of operation, they reach a
break-even point where it becomes cost effective to install controls
rather than to buy allowances.  For other counties in Table 6 (Jackson
County, Alabama; Montgomery County, Ohio; Clearfield County,
Pennsylvania), decreases occur because EGUs are projected to retire
under the NSR Availability (4%) Scenario but are not projected to be
retired under CAIR/CAMR/CAVR 2020.  This effect occurs because more cost
effective generation from EGUs that increased their availability under
the NSR Availability Scenario displaces less cost effective generation
from other EGUs, which then retire.

As Table 6 shows, county-level SO2 and NOx increases are small and
sparsely distributed.  The increases are small even in the counties
where the highest SO2 and NOx increases are projected.  In most of the
counties in Table 6, the emission increases are due to increased fuel
use by the EGUs within those counties, consistent with increased hours
of operation.  The exception is Grant County, Wisconsin, where SCR for
the Nelson plant is projected under CAIR/CAMR/CAVR 2020, but not under
the NSR Availability (4%) Scenario.  In this instance, the projected
increases at the Nelson plant occur because under the CAIR/CAMR/CAVR
2020 IPM, it is modeled as putting on controls, and in the NSR
Availability run, the Nelson is modeled as not putting on controls. 
This EGU decreases its utilization in the NSR 4% Availability run
compared to CAIR/CAMR/CAVR 2020.  This result occurs because it is less
efficient compared to other EGUs.  If this particular EGU (or any other
EGU) were to increase its efficiency and utilization, it is likely that
it would put on controls, consistent with our finding that the more
hours an EGU operates, the likelier it is to install controls.  

To gain further perspective on the magnitude of the SO2 and NOx
emissions changes under the NSR Availability Scenario, we compared them
to total SO2 and NOx emissions at the State level.  Specifically, we
compared the net change in statewide EGU SO2 and NOx emissions under the
NSR Availability Scenario to the total State SO2 and NOx emissions under
CAIR/CAMR/CAVR 2020.  As Appendix A shows, in States where SO2
emissions increase under the NSR Availability Scenario as compared to
CAIR/CAMR/CAVR 2020, the net emissions increase is at most 3 percent of
the total SO2 emissions in the State.  As Appendix A shows, in States
where NOx emissions increase under the NSR Availability Scenario as
compared to CAIR/CAMR/CAVR 2020, the net emissions increase ranges is at
most 2 percent of the total NOx emissions in the State.  Thus where SO2
and NOx emissions increase under the NSR Availability Scenario, they are
small in comparison to total SO2 and NOx emissions at the State level.  

As we discussed in Section III.B. of this preamble, our approach is
based on average availability, assuming a constraint of 89 percent
availability.  Due to the variation in EGU hours of operation from year
to year, for modeling purposes it makes sense to assume an average
availability rather than to determine unit-by-unit availabilities for
each and every EGU in a given year.  We therefore believe the NSR
Availability Scenario provides a very conservative estimate of the
emissions increases that would theoretically occur under our proposed
regulations. 

SO2 and NOx Impact on Air Quality- NSR Availability Scenarios

As we discussed above, projected emissions changes under 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.  As we also
noted, the degree and pattern of these changes is consistent with those
under CAIR/CAMR/CAVR 2020, as described in Section III.C.5.   Moreover,
the emission changes under the NSR Availability Scenario are projected
using very conservative assumptions, as described above. 

Figures 1 and 2 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.  

Figure 1.  2020 County-level SO2 Emissions Changes With a 4% Increase
in EGU Availability

Figure 2.  2020 County-level NOx Emissions Changes With a 4% Increase
in EGU Availability

Based on the spatial distribution of SO2 and NOx emissions changes as
shown in Figures 1 and 2, 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 today’s proposed regulations
would be commensurate with that under the CMAQ modeling based on
CAIR/CAMR/CAVR 2020 Scenario emissions projections.

5.  SO2 and NOx Impact on Air Quality- CAIR/CAMR/CAVR 2020

We examined the air quality impact of EGU SO2 and NOx emissions on SO2,
NOx, PM2.5 (for which SO2 and NOx emissions are precursors), and 8-hour
ozone concentrations (for which NOx is a precursor).  Table 7 shows the
NAAQS and increments for each pollutant.  

Table 7.  NAAQS and Increments

	NAAQS	Class I Increment	Class II Increment	Class III Increment

SO2

Annual	0.03 ppm 

(80 ug/m3)	0.00076 ppm

(2 ug/m3)	0.0076 ppm

(20 ug/m3)	0.015 ppm

(40 ug/m3)

NOx

Annual	0.053 ppm 

(100 ug/m3)	0.0013 ppm

(2.5 ug/m3) 	0.013 ppm

(25 ug/m3)	0.026 ppm

(50 ug/m3)

PM2.5

Annual	15 ug/m3	4 ug/m3 PM10 surrogate	17 ug/m3 PM10 surrogate
34 ug/m3 PM10 surrogate

8-hour Ozone	0.08 ppm

(85 ppb)	none	none	none



We modeled the change in annual average concentrations of SO2 and NOx
under CAIR/CAMR/CAVR 2020 and compared these results to the base case
emissions in 2001 using the CMAQ model.  The annual average
concentrations projected for 2020 from the model are expressed in parts
per million (ppm).  The NAAQS and PSD increments are expressed in
micrograms per cubic meter (ug/m3).  To correlate the annual average
concentrations in ppm to air quality changes relative to the PSD
increments and NAAQS for SO2 and NO2 (precursor for NOx), we expressed
the NAAQS and increments in ppm using a standard conversion.  Table 7
shows these correlations.

We also modeled the change in annual average concentrations of PM2.5
under CAIR/CAMR/CAVR 2020 and compared these results to the base case
emissions in 2001 using the CMAQ model.  The annual average
concentrations projected for 2020 from the model are expressed in ug/m3,
consistent with the PM2.5 NAAQS and PSD increments.  PM2.5 increments
have not been proposed.  Consistent with our April 2005 policy memo, the
PM10 increments currently serve as surrogates for the PM2.5 increments. 


Finally, we modeled the annual average concentrations of 8-hour ozone
under CAIR/CAMR/CAVR 2020 and compared these results to the average
ambient concentrations for 1999 - 2003.

We evaluated the individual records for each cell in the CMAQ modeling
grid.  We then computed the difference in the modeled concentration in
2020 from the base-year concentration in 2001.  For each cell we
evaluated whether there was an increase in the concentration in the year
2020 when compared to 2001, and whether that increase was greater than
the Class I increments of 0.00076 ppm for SO2, 0.001325 ppm for NO2,
and 4 ug/m3 for PM10 (surrogate for PM2.5).  The analysis was performed
and the resulting map produced using the computing capabilities of
EPA’s GIS mapping system and underlying database software.  

For 8-hour ozone, we computed the difference in the modeled
concentration in 2020 from the baseline concentration of the 1999 - 2003
average ambient value.  This information by county is contained in a
spreadsheet file available on our website.  The analysis was performed
and the resulting map produced using the computing capabilities of
EPA’s GIS mapping system and underlying database software. 
Figures 3.3 through 3.5 of the Technical Support Document show the
change in annual average concentrations of SO2, NOx, and PM2.5
respectively under CAIR/CAMR/CAVR 2020 as compared to the base case
emissions in 2001.  Figure 3.6 shows the change in annual
concentrations of 8-hour ozone under CAIR/CAMR/CAVR 2020 as compared to
the 1999 - 2003 average ambient concentrations.

As Figure 3.3 shows, in most areas of the country SO2 concentrations
are projected to improve in 2020 over those in 2001, including
substantive improvements in many areas of the eastern United States. 
For the reasons we describe in detail in the Technical Support Document,
we do not believe any local area will exceed the SO2 Class I increment
due to EGU emissions increases in the NSR Availability Scenario as
compared to CAIR/CAMR/CAVR 2020, including any that might occur due to
the shifting of emission increases and decreases that might occur under
the proposed applicability tests. As Figure 3.3 also shows, no declines
in SO2 air quality greater than 0.0052 ppm are projected.  This level
is a smaller decline than the SO2 Class II and III increments, and we
therefore do not believe any local area will exceed its the SO2
Class II and III increments due to EGU emission increases, including
any that might occur due to the shifting of emission increases and
decreases that might occur under the proposed applicability tests. 
There are no areas in which the 2020 projected concentration exceeds
0.03 ppm SO2, the level of the NAAQS.  Therefore, we also do not
believe any local area will exceed its SO2 NAAQS due to EGU emission
increases, including any that might occur due to the shifting of
emission increases and decreases that might occur under the proposed
applicability tests.  

As Figure 3.4 shows, in most areas of the country NO2 concentrations
are projected to improve in 2020 over those in 2001, including
substantive improvements in many areas of the eastern United States. 
For the reasons we describe in detail in the Technical Support Document,
we do not believe any local area will exceed its Class I NO2 increment
due to EGU emissions increases, including any that might occur due to
the shifting of emission increases and decreases that might occur under
the proposed applicability tests.  As Figure 3.4 also shows, no
declines in NO2 air quality greater than 0.013 ppm are projected.  This
level is a smaller decline than the NO2 Class II and III increments,
and we therefore do not believe any local area will exceed the NO2
Class II and III increments due to EGU emission increases, including
any that might occur due to the shifting of emission increases and
decreases that might occur under the proposed applicability tests. 
There are no areas in which the 2020 projected concentration exceeds
0.053 ppm NO2, the level of the NAAQS.  Therefore, we also do not
believe any local area will exceed its NO2 NAAQS due to EGU emission
increases, including any that might occur due to the shifting of
emission increases and decreases that might occur under the proposed
applicability tests.  

As Figure 3.5 shows, in most areas of the country PM2.5 concentrations
are projected to improve in 2020 over those in 2001, including
substantive improvements in many areas of the eastern United States.  As
Figure 3.5 also shows, no declines in PM2.5 air quality greater than
2.96 µg/m3 are projected.  This level is a smaller decline than the
PM10 Class I, Class II, and III increments that currently serve as
surrogates for PM2.5 under our April 5, 2005 interim PM2.5 policy.  We
therefore do not believe any local area will exceed the PM10 Class I,
Class II, or Class III increments due to EGU SO2 or NOx emission
increases under the NSR Availability Scenario as compared to
CAIR/CAMR/CAVR 2020, including any that might occur due to the shifting
of emission increases and decreases that might occur under the proposed
applicability tests.  

We recently forecasted PM2.5 concentrations under CAIR/CAMR/CAVR 2020. 
As this documentation shows, we project 34 counties to be nonattainment
for PM2.5 in 2020.  For these 34 counties, we computed the net
emissions change in the EGU SO2 and NOx emissions between CAIR/CAMR/CAVR
2020 and NSR Availability.  Appendix D of the Technical Support
Document includes this analysis.  As we describe in detail in the
Technical Support Document, projected increases in SO2 and NOx 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 local
ambient effect as precursors to formation of PM2.5.  Therefore, we also
do not believe any local area will exceed its PM2.5 NAAQS due to EGU SO2
and NOx emission increases, including any that might occur due to the
shifting of emission increases and decreases that might occur under the
proposed applicability tests.  We discuss the impact of EGU PM2.5
emission changes under the NSR Availability Scenario on air quality in
Section III.D. of  this preamble.  

As Figure 3.6 shows, in most areas of the country 8-hour ozone
concentrations are projected to improve in 2020 over those in 2001,
including substantive improvements in many areas of the eastern United
States.  We recently forecasted 8-hour ozone concentrations under
CAIR/CAMR/CAVR 2020.  As this documentation shows, we project 21counties
to be nonattainment for 8-hour ozone in 2020.  There currently are no
PSD increments for ozone.  For the 21 counties in which we project
8-hour ozone nonattainment in 2020, we computed the net emissions change
in the EGU NOx emissions between CAIR/CAMR/CAVR 2020 and NSR
Availability.  Appendix E of the Technical Support Document includes
this analysis.  As we discuss in detail in the Technical Support
Document, projected increases in NOx 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 local ambient effect as
precursors to formation of 8-hour ozone.  Based on the size of the NOx
emissions increases, we also do not believe that local areas projected
to be 8-hour nonattainment in 2020 will exceed their 8-hour NAAQS due to
EGU NOx emission increases, including any that might occur due to the
shifting of emission increases and decreases that might occur under the
proposed applicability tests.

D.  NSR Availability Scenarios – Discussion of PM2.5 Results  

We used the NSR Availability Scenarios that we describe in Section III.B
of this preamble to examine the PM2.5 emissions and air quality impacts
of the proposed hourly emissions increase test.  This Section provides
the results of our analyses.  Our Technical Support Document provides
similar information for VOC and CO emissions.

1.  PM2.5 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. Gas-fired turbines are clean burning and BACT/LAER
for PM2.5 for these EGUs is no control.  

2.  PM2.5 National Emissions 

As Table 8 shows, EGUs  a small percentage of national PM2.5 emissions.

Table 8  EGU Emissions As Percent of 2020 National Emissions (tpy)

	 EGU 	National	EGU as % National

PM2.5	533,000	6,206,000	8.6% 



As Table 9 shows, the NSR Availability Scenarios project essentially no
changes in PM2.5 emissions nationally by 2020 as compared to emissions
under the CAIR/CAMR/CAVR Scenario.

Table 9  National EGU Emissions Under NSR Availability Scenario
Compared to CAIR/CAMR/CAVR 2020 (tpy)

	

CAIR/CAMR/CAVR

	

NSR 4%

	Change-NSR 4%

PM2.5	526,642	524,245	(2,397) 



As described in Section III 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 or an average annual
10-year baseline test, as opposed to the current average annual 5-year
baseline test, such increased hours of operation would not increase
national EGU PM2.5 emissions.  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 Local Emissions Impact

To examine the effect of the maximum hourly and 10-year baseline tests
on local air quality, we compared 2020 county-level EGU PM2.5 emissions
under the CAIR/CAMR/CAVR 2020 and NSR Availability (4%) Scenario. 
Table 10 shows these comparisons.

Table 10  Changes in County-level PM2.5 Emissions NSR Availability (4%)
Scenario

Total # of counties with decreases in EGU emissions	133

# of counties with decreases in EGU emissions between -1,001 and
-2,074 tpy	1

# of counties with decreases in EGU emissions between -40 and
-1,000 tpy	27

# of counties with decreases in EGU emissions between -1 and -39 tpy 
105

# of counties with no change in EGU emissions	437

# of counties with increases in EGU emissions between 1 and 39 tpy	250

# of counties with increases in EGU emissions between 40 and 536 tpy
134

Total # of counties with increases in EGU emissions	384



As Table 10 shows, the proposed revised NSR applicability tests would,
under the very conservative assumptions described in Section III.B.,
result in a somewhat different pattern of local emissions, with some
counties experiencing reductions, some experiencing increases, and some
remaining the same.  That is, this pattern occurs when increased
availability is assumed, such as we assume for present purposes would
occur under the proposed maximum hourly and 10-year baseline tests.  The
increases and decreases in county-level EGU PM2.5 emissions are small
and sparsely distributed.  

As Table 10 shows, the highest county-level PM2.5 emissions increase
was 536 tpy.  The increases and decreases occurred in CAIR and non-CAIR
States.  

To gain a further perspective on the projected county-level PM2.5
increases under the NSR Availability (4%) Scenario, we compared them to
actual annual EGU PM.2.5 emissions in 2003 - 2004.  We calculated the
actual annual PM2.5 emissions for each EGU using the actual heat input
(MMBtu) CEMS data and an emission factor.  In 2004, one EGU had an
emissions increase of ≥ 3,845 tpy PM2.5 as compared to 2003.  In
2004, one EGU had an emissions decrease of 2,080 tpy compared to 2003. 
Thus, the highest county-level projected emissions increases for PM2.5
under the NSR Availability (4%) Scenario are less than the emissions
increases that actually occurred, based on measured data, at individual
EGUs over the period of 2003 - 2004.  Furthermore, the greatest
county-level projected emissions decreases for PM2.5 under the NSR
Availability (4%) Scenario are less than the emissions decreases that
actually occurred, based on measured data, at individual EGUs over the
period of 2003 - 2004.  

As this perspective shows, the local PM2.5 emissions increases that the
IPM results indicate could theoretically occur from this action are not
large.  They are also within the variability that occurred under the
current emissions increase test between the years 2003 - 2004.

We next examined the reasons for the largest decreases and increases in
county-level emissions under the NSR Availability (4%) Scenario. 
Table 11 shows the counties with the largest decreases and increases in
EGU PM2.5 emissions.Table 11  Largest County-level Decreases and
Increases of Primary PM2.5 Under NSR Availability (4%) Scenario (tpy)

5 counties with largest decrease in Primary PM2.5 emissions under the
NSR Availability Scenario

State	County	County-level Emissions	Variations in unit-level data that
would explain the decrease



NSR Availability (4%)	CAIR/CAMR/CAVR 2020	Decrease

	Alabama	Jackson	1,384	3,457	-2,073	6 of 8 Widows Creek units retire

Pennsylvania	Lawrence	208	914	-706	New Caste units 3 and 4 retire

Ohio	Montgomery	2	670	-668	Hutchings units 1-6 retire

Ohio	Pickaway	1	649	-648	Picway retires

Pennsylvania	Snyder	0	614	-614	Sunbury retires

5 counties with largest increase in Primary PM2.5 emissions under the
NSR Availability Scenario

State	County	County-level Emissions	Variations in unit-level data that
would explain the increase



NSR Availability (4%)	CAIR/CAMR/CAVR 2020	Increase

	Minnesota	Sherburne	11,897	11,361	536	Heat input and emissions
increased at Sherburne Co's 3 units

Missouri	New Madrid	10,899	10,408	491	Heat input increased at New
Madrid's 2 units

Oklahoma	Mayes	8,230	7,863	367	Heat input increased

New Mexico	San Juan	7,969	7,609	360	Heat input increased

Texas	Titus	3,414	3,175	239	Heat input increased

For some counties in Table 11 where PM2.5 emission decreases are
projected, the decreases occur because heat input and emissions
decreased at existing units.  This effect occurs because more cost
effective generation from EGUs that increased their availability under
the NSR Availability Scenario displaces less cost effective generation
from other EGUs.  The less efficient EGUs then decrease their usage,
reflected by decreased heat input and emissions.  In Jackson Co.,
Alabama, decreases occur because EGUs are projected to retire under the
NSR Availability (4%) Scenario but are not projected to be retired under
CAIR/CAMR/CAVR 2020.  This effect also occurs because more cost
effective generation from EGUs that increased their availability under
the NSR Availability Scenario displaces less cost effective generation
from other EGUs, which then retire.  In other counties, PM2.5 emission
decreases occur because less new generation was projected for that
county under the NSR Availability Scenario as opposed to under
CAIR/CAMR/CAVR.  

As noted previously, county-level increases are small and sparsely
distributed.  As Table 11 shows, the PM2.5 increases are small even in
the counties where the highest increases are projected.  There are only
two counties in which the projected VOC emission increases (compared to
CAIR/CAMR/CAVR) are greater than 40 tpy.  In many of the counties shown
here, the emission increases are due to increased fuel use by the EGUs
within those counties, consistent with increased hours of operation.  In
other counties, emission increases occur where more new generation was
projected for that county under the NSR Availability Scenario as opposed
to under CAIR/CAMR/CAVR.  Increased generation due to new EGUs would be
subject to major NSR review and would not be affected by the proposed
emissions increase test.

PM2.5 Air Quality NSR Availability Scenarios

As we discussed in Section III.C.4., we modeled the change in annual
average concentrations of PM2.5 under CAIR/CAMR/CAVR 2020 and compared
these results to the base case emissions in 2001 using the CMAQ model. 
As we also noted in Section III.C.4., the PM10 increments currently
serve as surrogates for the PM2.5 increments, according to our April
2005 policy memo.  Figure 3.5 of the Technical Support Document shows
the change in annual average concentration of PM2.5 as compared to base
case emissions in 2001.  As Figure 3.5 shows, in most areas of the
country PM2.5 concentrations are projected to improve in 2020 over those
in 2001, including substantive improvements in many areas of the eastern
United States.  As Figure 3.5 also shows, no declines in PM2.5 air
quality greater than 2.96 µg/m3 are projected.  This level is a
smaller decline than the PM10 Class I, Class II, and III increments
that currently serve as surrogates for PM2.5.  We therefore do not
believe any local area will exceed the PM10 Class I, Class II, or
Class III increments due to EGU PM2.5 emission increases under the NSR
Availability Scenario as compared to CAIR/CAMR/CAVR 2020, including any
that might occur due to the shifting of emission increases and decreases
that might occur under the proposed applicability tests.  

As we discussed in Section III.C.4, we recently forecasted PM2.5
concentrations under CAIR/CAMR/CAVR 2020 and project 34 counties to be
nonattainment for PM2.5 in 2020.  For these 34 counties, we computed
the net emissions change in the EGU PM2.5 emissions between
CAIR/CAMR/CAVR 2020 and NSR Availability.  As we discuss in detail in
the Technical Support Document, the projected increases in PM2.5
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 as precursors to formation of PM2.5.  Furthermore, the
EPA has recently conducted additional air quality modeling of PM2.5 as
part of the Regulatory Impact Analysis for the final PM2.5 NAAQS.  Based
on this modeling, we tend to see further improvements in projected air
quality and lower predicted PM2.5 concentrations in 2020.  Therefore,
based on the small value of the emission increases under the NSR
Availability Scenario and on the findings from more recent PM2.5
modeling, we do not believe that any local area will exceed the PM2.5
NAAQS or the PM2.5 Class I increment due to EGU emission changes that
might occur as a result of the proposed changes to the NSR emissions
increase test. 

We discuss the impact of EGU SO2 and NOx emission increases under the
NSR Availability Scenario on PM2.5 air quality in Section III.C. of
this document.  

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.  Today, 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.   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 continue to include a
four-step process (with the second step revised as proposed today, and
with no proposals concerning the other steps):  (1) physical change of
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.  Option 1 retains the requirements for a significant
emissions increase and a significant net emissions increase.  Therefore,
if a post-change hourly emission increase is projected, 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 12 summarizes
these four steps.

Table 12.  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

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

Step 4:  Significant Net Emissions Increase as in the Current Rules



Option 1 would not eliminate—and therefore would have no effect
on—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 at and
baseline actual emissions.  [See §51.166(b) (3), §51.166(b) (23),
§51.166(b) (40), §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 §51.166(a)(7)(i) though (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) though (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.  

We are also proposing to add a definition of the “increases”
component of “modification” to the major NSR rules.  Under Option 1,
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.  In the alternative, we are
proposing the maximum hourly achievable test, and therefore we are also
proposing in the alternative 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 are found in 40 CFR 60.2.

Specifically, under Option 1, we are proposing to add two new sections
to the major NSR program rules that would include the two-step
provisions for modifications.  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 today’s 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 today’s SNPR, we are
recasting what we proposed in the NPR for the output-based methodology. 
In today’s 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 (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 today’s 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 12 and can be
found at proposed §51.167(f) (1).

In Sections IV.A and B, we describe our two broad approaches for the
hourly emissions increase test in more detail.  The regulatory language
proposed today 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  TC \l2 "C. 
Test for EGUs Based on Maximum Achieved Hourly Emissions 

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 §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 12, 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 §51.167(f) (1), we a 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
CEMS or 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)). 

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
§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 §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
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 §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 §51.124(q) for the definitions of “cogeneration
unit” and numerous other terms used in that definition.  We propose to
include definitions in §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 maximum
achieved hourly emissions test (see proposed §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 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.

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.

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 §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 §60.8(c) to clarify the meanings of
startup, shutdown, and malfunction in the context of this action.

The second data limitation reflects §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, §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, §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

Finally, we are proposing to incorporate provisions that are generally
analogous to those in §60.7(a) (4) and §60.7(f) concerning
notifications of proposed physical changes and changes in the method of
operation (proposed §51.167(g) (1) (i)), and records of such changes
(proposed §51.167(g) (2)).  The proposed requirements are identical for
Alternatives 1 through 4.

Specifically, you must provide a notification to the reviewing authority
at least 6 months before commencing construction on any physical or
operational change to an existing EGU that may increase the emissions
rate of any regulated NSR pollutant.  The notification must contain the
information in proposed §51.167(g) (1) (i) and the reviewing authority
may request additional relevant information after receiving the
notification.  

Although §60.7(a)(4) requires a notification only 60 days, or as soon
as practicable, before a change is commenced, we are proposing a 6-month
advance notification for Alternatives 1 through 4.  We believe that the
maximum achieved hourly emissions tests that we are proposing under
Alternatives 1 through 4 may entail relatively complex analyses, and
that reviewing authorities may need more than 60 days to review and
evaluate the notifications and analyses.  Further, we believe that it is
reasonable to require a notification 6 months in advance of a change
because changes to EGUs must be planned for a shutdown of the unit,
which are typically planned more than a year in advance.  We invite
comment on the practicality of requiring notifications 6 months in
advance under the maximum achieved hourly emissions test alternatives
proposed today.

You must also maintain a file of all information related to
applicability determinations that you make under this section, including
the specific information in proposed §51.167(g) (2).  These proposed
recordkeeping requirements are drawn from the requirements of §60.7(f).
 We are proposing that you must maintain the records until the later of
the following dates:  (1) 5 years after the EGU resumes regular
operation after the physical or operational change, and (2) 5 years
after the record was recorded.  This expands on the 2-year requirement
in §60.7(f) to be consistent with more recent recordkeeping
requirements, such as in the title V operating permit program (see 40
CFR 70.6(a) (3) (ii) (B)).

Under proposed Alternatives 1 through 4, regardless of any
preconstruction projections, 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 §51.167(f)(1)(iii) under Alternative 1).  Most
EGUs are already reporting hourly SO2 and NOx emissions through CEMS
data to EPA.  Therefore, the majority of 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).  Today 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.  

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 §60.14(h) into the new
§51.167(f) (1).  We propose that this regulatory language would
substantially mirror, but would not be identical to, §60.14(h).  As
with the definition of modification that we are proposing for
§51.167(h) (2), there are differences between the two programs that
prevent a wholesale adoption of the NSPS modification provisions of
§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, §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 §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 §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, §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 §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 §51.124(q) for the definitions of “cogeneration
unit” and related terms.  We propose to include definitions in
§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 §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.

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.

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 requirements

We are proposing nearly the same recordkeeping and reporting
requirements for the maximum achievable test (Alternatives 5 and 6) that
we propose for the maximum achieved hourly emissions test (Alternatives
1 through 4).  The only difference is in the amount of advance
notification required.  See Section IV.A.4 of this preamble for the
discussion of the common requirements.  The proposed rule language is
found at §51.167(g) (1) (ii) and (2).

The notification requirements are based on the requirements found in
§60.7(a) (4).  These NSPS provisions require a notification 60 days, or
as soon as practicable, before the change is commenced.  Although we
propose to require a 6-month advance notification under the maximum
achieved test for the reasons discussed above in Section IV.A.4 of this
preamble, we propose to retain the shorter notification requirement of
§60.7(a)(4) for the maximum achievable test.  Because determinations of
pre-change and post-change maximum hourly emissions rates typically are
made using emission factors under the maximum achievable test, we
believe that a notification 60 days, or as soon as practicable, in
advance of commencing the change is adequate to allow the reviewing
authority to review and evaluate the notification.

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 today’s 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 §51.166(a) (7) (iv)(a) would be amended to exempt
EGUs as follows.

Except for EGUs as defined in §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 d efined 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.  

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 13 shows Option 2, including Alternatives 1-6.

Table 13.  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 today’s 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 §51.166(a)(7)(i) though (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) though (7), and (s)(1)
through (4).  For example, we are proposing to amend §51.166(a)(7)(iii)
as follows.

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 for 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.   

VII.   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 today’s 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.   

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 §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.  We thus believe that, over a period that is
representative of normal operation, in general the maximum achievable
and maximum achieved hourly emissions test would lead to substantially
equivalent results.

Each of today’s 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 not to reduce emissions, but to balance the need for
environmental protection and economic growth.  As the analyses included
in today’s 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 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.  We propose Option 1, our
preferred Option, for the purpose of maintaining the current significant
net emissions increase component of the emissions increase test.  In
light of the additional complexity that netting adds, we solicit comment
on whether netting and significance levels would retain, in combination
with an hourly test, the usefulness they have under an annual test.  

The proposed maximum hourly tests would streamline major NSR by reducing
applicability determinations complexity.  The proposed maximum hourly
achievable test provides more streamlining by conforming them 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. We recognize
that Option 1, which retain an annual emissions increase test, would not
streamline the major NSR program as Option 2 would.  

We acknowledge that an output-based format may not be as effective a
measure of existing capacity utilization in some instances as our
input-based options.  However, 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. 

Moreover, the Court's rationale focused on the ability to “net” as
it relates to the addition of new units, rather than to changes existing
units, which is the concern of our proposed action.   Specifically, the
court stated:

         To [construe “increases” not to allow netting], however,
would require PSD review for many such routine alterations of a plant; a
new unit would contribute additional pollutants, these increases could
not be set off against the decrease resulting from abandonment of the
old unit, and thus the change would be come a ‘modification’ subject
to PSD review.  Not only would this result be extremely burdensome, it
was never intended by Congress in enacting the Clean Air Act
Amendments...

Because today's action does not change the emissions test that applies
when a major stationary sources adds a new emissions unit, the existing
regulations continue to satisfy the Alabama Power Court's interpretation
of Congressional intent, irrespective of today's proposed changes.   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. 

We request comment on all aspects of our legal and policy basis.

VIII. Statutory and Executive Order Reviews tc \l1 "VI.  Statutory and
Executive Order Reviews 

A.  Executive Order 12866:  Regulatory Planning and Review tc \l2 "A. 
Executive Order 12866Regulatory 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.

B.  Paperwork Reduction Act tc \l2 "B.  Paperwork Reduction Act 

The information collection requirements in this proposed rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.  The
Information Collection Request (ICR) document prepared by 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER],
a comment to OMB is best assured of having its full effect if OMB
receives it by [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE
FEDERAL REGISTER].  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) tc \l2 "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 today's 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 today(s 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. sections 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 today(s 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 provided in the proposed rule are not
expected to result in any increases in expenditure by any small entity. 


We have therefore concluded that today(s 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 tc \l2 "D.  Unfunded Mandates Reform
Act 

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 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 today(s
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 tc \l2 "E.  Executive Order
13132Federalism 

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 tc \l2 "F.  Executive Order 13175Consultation 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 today(s 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 today(s 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 tc \l2 "G.  Executive Order
13045Protection 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.

The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5-501 of the Order has the potential
to influence the regulation.  This rule is not subject to Executive
Order 13045, because we do not have reason to believe 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. 

H.  Executive Order 13211:  Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use tc \l2 "H. 
Executive Order 13211Actions 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 No. 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. 

Today(s proposed rule does not involve technical standards.  Therefore,
EPA is not considering the use of any voluntary consensus standards.

IX.  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, Electric Generating Unit, Nitrogen
oxides, Sulfur dioxide

40 CFR Part 52

	Environmental protection, Administrative practice and 

procedure, Air pollution control, Electric Generating Unit, Nitrogen
oxides, Sulfur dioxide.

____________________

Dated:

_____________________

Stephen L. Johnson,

 Administrator.  SEQ CHAPTER \h \r 1 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 §51.167 to read as follows:

§51.167  Preliminary major NSR applicability test for electric
generating units (EGUs)  TC "§51.167  Major modification procedures for
electric generating units (EGUs)" \f C \l "1"  .

(a)  What is the purpose of this section?  TC "(a)  What is the purpose
of this section?" \f C \l "2"    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?  TC "(b)  Am I subject to this
section?" \f C \l "2"    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?    TC "(c) 
What happens if a change to my EGU is determined to be a major
modification according to the procedures of this section?" \f C \l "2" 
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 §51.165 and/or §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 §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?  TC "(d)  What is the process for determining if a change
to an EGU constitutes a major modification?" \f C \l "2"    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 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?  (Step1)  TC "(e)  What types of physical or
operational changes are exempted from consideration under this section? 
(Step1)" \f C \l "2"    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 §51.165 or §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
§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 §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
§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) 
TC "(f)  How do I determine if my physical or operational change will
increase the amount of a regulated NSR pollutant emitted into the
atmosphere by my source?  (Step2)" \f C \l "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:  

 					Equation 1

Where:

 = average emissions rate, lb/hr;

	n = number of emissions rate values; and

  = ith emissions rate value, lb/hr

	(E)  Calculate the standard deviation of the data set, s, using
Equation 2:

 			Equation 2

	(F)  Calculate the Upper Tolerance Limit, UTL, of the data set using
Equation 3:

 Equation 3

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:  

 					Equation 1

Where:

 = average emissions rate, lb/MWh;

	n = number of emissions rate values; and

  = ith emissions rate value, lb/MWh

	(E)  Calculate the standard deviation of the data set, s, using
Equation 2:

 			Equation 2

	(F)  Calculate the Upper Tolerance Limit, UTL, of the data set using
Equation 3:

 Equation 3

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 is the highest rate at which the EGU
actually emitted the pollutant at any time during the 5-year period
immediately prior to the physical or operational change, determined as
follows:

	(A)  Select a period of 24 consecutive months within the 5-year period
immediately preceding when you begin actual construction of the physical
or operational change;

	(B)  Determine the highest emissions rate (lb/hr) actually achieved for
1 hour in the first 12 months and for 1 hour in the second 12 months of
the selected 24-month period, where the two 1-hour periods also fall in
different calendar years; and

	(C)  Calculate the arithmetic average of these two values. 

	(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 is the highest rate at which the EGU actually
emitted the pollutant at any time during the 5-year period immediately
prior to the physical or operational change, determined as follows:

	(A)  Select a period of 24 consecutive months within the 5-year period
immediately preceding when you begin actual construction of the physical
or operational change;

	(B)  Determine the highest emissions rate (lb/MWh) actually achieved
over a period of 1 hour in the first 12 months and over a period of 1
hour in the second 12 months of the selected 24-month period, where the
two 1-hour periods also fall in different calendar years; and

	(C)  Calculate the arithmetic average of these two values. 

	(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 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 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 6 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 7 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 §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 8 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 §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 – 6 .

	(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 7 and 8 .

	(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 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 notifications and recordkeeping?  You
must submit the notifications described in paragraph (g)(1) of this
section and keep the records described in paragraph (g)(2) of this
section.

	(1)  Notifications.  You must send a notification to your reviewing
authority for any physical or operational change to an existing EGU
which may increase the emissions rate of any regulated NSR pollutant
(that is, may trigger Step 2 as set out in paragraphs (d)(2) and (f) of
this section).  The following provisions apply to these notifications:

	(i)  Notifications requirements for Alternatives 1 – 6 for paragraph
(f)(1) of this section.

	(A)  The notification must be postmarked no later than 6 months before
the change is commenced.

	(B)  The notification must include information describing:

	(1)  The precise nature of the change;

	(2)  The present and proposed emission control systems;

	(3)  The productive capacity of the EGU before and after the change;
and 

	(4)  The expected completion date of the change. 

	(C)  The reviewing authority may request additional relevant
information subsequent to this notification.

	(ii)  Notification requirements for Alternatives 7 and 8 for paragraph
(f)(1) of this section.

	(A)  The notification must be postmarked 60 days or as soon as
practicable before the change is commenced.

	(B)  The notification must include information describing:

	(1)  The precise nature of the change;

	(2)  The present and proposed emission control systems;

	(3)  The productive capacity of the EGU before and after the change;
and 

	(4)  The expected completion date of the change. 

	(C)  The reviewing authority may request additional relevant
information subsequent to this notification.

	(2)  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:

	(i)  The file must include, but is not limited to, the following
information recorded in permanent form suitable for inspection:

	(A)  Continuous monitoring system, monitoring device, and performance
testing measurements; 

	(B)  All continuous monitoring system performance evaluations; 

	(C)  All continuous monitoring system or monitoring device calibration
checks;

	(D)  All adjustments and maintenance performed on these systems or
devices; and

	(E)  All other information relevant to any determination made under
this section of whether a change to an EGU is a modification. 

	(ii)  You must retain the file until the later of:

	(A)  The date 5 years following the date the EGU resumes regular
operation after the physical or operational change; and

	(B)  The date 5 years following the date of such measurements,
maintenance, reports, and records.  

	(h)  What definitions apply under this section?  TC "(j)  What
definitions apply under this section?" \f C \l "2"    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 §51.165(a)(1) or §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 §51.165(a)(1) or
§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 §51.124(q).  The
following terms are as defined in §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.

 Establishments owned and operated by Federal, State, or local
government are classified according to the activity in which they are
engaged.

 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 today’s 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. 

 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.

 Complete documentation for IPM, including the Base Case Scenario, is
available at   HYPERLINK "http://www.epa.gov/airmarkets/epa-ipm" 
http://www.epa.gov/airmarkets/epa-ipm . See also Docket Item
EPA-HQ-OAR-2005-0163-0133.

 See the NEEDS 2004 documentation for IPM v.2.1.9 in Exhibit 4-6,
which can be found at   HYPERLINK
"http://www.epa.gov/airmarkets/epa-ipm/section4genres.pdf" 
http://www.epa.gov/airmarkets/epa-ipm/section4genres.pdf .  See also
Docket Item EPA-HQ-OAR-2005-0163-0134.

 See also Docket Item EPA-HQ-OAR-2005-0163-0135

 See also Docket Item EPA-HQ-OAR-2005-0163-0135.

 The report is available at   HYPERLINK "http://www.nerc.com/~gads/" 
http://www.nerc.com/~gads/  and in the Docket as Item
EPA-HQ-OAR-2005-0163-0136.

 Also available as Docket Item EPA-HQ-OAR-2005-0163-0137.

 See our report, “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 report is available at  
HYPERLINK "http://www.epa.gov/air/interstateairquality/charts.html" 
http://www.epa.gov/air/interstateairquality/charts.html .  Also
available as Docket Item EPA-HQ-OAR-2005-0163-0137.

 While we believe it is most likely that an EGU would increase its hours
of operation under today’s proposed regulations due to reducing the
number of hours that the EGU is unavailable due to forced outage hours,
the analysis is applicable to increases in hours of operation for other
reasons.

 Available as Docket Item EPA-HQ-OAR-2005-0163-0138. (System Summary
Report for NSR Availability)

 See our report, “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 report is available at  
HYPERLINK "http://www.epa.gov/air/interstateairquality/charts.html" 
http://www.epa.gov/air/interstateairquality/charts.html .  The report is
also available as Docket Item EPA-HQ-OAR-2005-0163-0137.

 CAIR/CAMR/CAVR SO2 and NOx emissions available as Docket Item
EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_BART 13_2020_Pechan (to
EPA)07-11-05].  NSR SO2 and NOx Availability Emissions available as
Docket Item EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_NSR_OAQPS_
5_Pech_2020_07-05-06 (to EPA)]  National totals for CAIR/CAMR/CAVR and
NSR Availability include new units (IPM new units and planned-committed
units).

 CAIR/CAMR/CAVR SO2 and NOx emissions available as Docket Item
EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_BART 13_2020_Pechan (to
EPA)07-11-05].  NSR SO2 and NOx Availability Emissions available as
Docket Item EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_NSR_OAQPS_
5_Pech_2020_07-05-06 (to EPA)]

 Emission increases of at least 0.5 tpy.  Does not include emissions
due to new EGUs (IPM new units and IPM planned-committed units).  New
units (IPM new units and planned-committed units) were not included in
CAIR/CAMR/CAVR 2020 and NSR Availability county-level emission totals
because they had not been assigned to a county.  New EGUs would not be
subject to proposed rule.  New EGUs would be subject to major NSR,
including control technology review for installation of BACT/LAER. 

 Available as Docket Item EPA-HQ-OAR-2005-0163-0140.  (2000 - 2004
Electric Generation)

 Available as Docket Item EPA-HQ-OAR-2005-0163-0141. (2003 - 2004
Emission Changes)

 Analysis of largest county-level emission changes available as Docket
Item EPA-HQ-OAR-2005-0163-0141. CAIR/CAMR/CAVR SO2 and NOx emissions
available as Docket Item EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_BART
13_2020_Pechan (to EPA)07-11-05].  NSR Availability SO2 and NOx
Emissions available as Docket Item EPA-HQ-OAR-2005-0163-0139.  [EPA
219b_NSR_OAQPS_ 5_Pech_2020_07-05-06 (to EPA)]  Does not include
emissions due to new EGUs (IPM new units and IPM planned-committed
units).  

 Analysis of county-level SO2 and NOx changes available as Docket Item
EPA-HQ-OAR-2005-0163-0141.  Analysis of largest county-level emission
changes available as Docket Item EPA-HQ-OAR-2005-0163-0141.
CAIR/CAMR/CAVR SO2 and NOx emissions available as Docket Item
EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_BART 13_2020_Pechan (to
EPA)07-11-05].  NSR Availability SO2 and NOx Emissions available as
Docket Item EPA-HQ-OAR-2005-0163-0139.  [EPA 219b_NSR_OAQPS_
5_Pech_2020_07-05-06 (to EPA)]

 The CMAQ modeling was conducted as part of EPA’s multipollutant
legislative assessment and the results are available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp"  http://www.epa.gov/airmarkets/mp  .
Multipollutant Regulatory Analysis: The Clean Air Interstate Rule, The
Clean Air Mercury Rule, and the Clean Air Visibility Rule (EPA
promulgated rules, 2005).  The specific technical support document on
air quality modeling for CAIR/CAMR/CAVR, Technical Support Document for
Air Quality Modeling Technique, is available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/aqsupport/" 
http://www.epa.gov/airmarkets/mp/aqsupport/ .  It is also available as
Docket Item EPA-HQ-OAR-2005-0163-0142.  

 We used the following conversion factor:  ppm =
[(24.5)(ug/m3)]/[(1000)(molecular weight)] was used.  The conversion
factor can be found in Kenneth Wark and Cecil.F. Warner, Air Pollution:
Its Origin and Control, 1981, page 7.  The molecular weight for SO2 and
NO2 can be calculated from atomic weights found in Robert C. Weast, and
Melvin J. Astle, Handbook of Chemistry and Physics, 1979, end leaf. 

 The CMAQ modeling was conducted as part of EPA’s multipollutant
legislative assessment and the results are available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp"  http://www.epa.gov/airmarkets/mp  .
Multipollutant Regulatory Analysis: The Clean Air Interstate Rule, The
Clean Air Mercury Rule, and the Clean Air Visibility Rule (EPA
promulgated rules, 2005).  The specific technical support document on
air quality modeling for CAIR/CAMR/CAVR, Technical Support Document for
Air Quality Modeling Technique, is available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/aqsupport/" 
http://www.epa.gov/airmarkets/mp/aqsupport/ .  It is also available as
Docket Item EPA-HQ-OAR-2005-0163-0142.

 See Stephen D. Page, “Implementation of New Source Review
Requirements in PM2.5 Nonattainment Areas,” April 5, 2005, available
at 

  HYPERLINK "http://www.epa.gov/nsr/guidance.html" 
http://www.epa.gov/nsr/guidance.html  and as Docket Item
EPA-HQ-OAR-2005-0163-0143.

 This information is available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/index.html" 
http://www.epa.gov/airmarkets/mp/index.html .  (Air quality Modeling
Results Excel File, Impact on Ozone Concentrations by County.)  It is
also available as Docket Item EPA-HQ-OAR-2005-0163-0142. 

 The CMAQ modeling was conducted as part of EPA’s multipollutant
legislative assessment and the results are available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp"  http://www.epa.gov/airmarkets/mp  .
Multipollutant Regulatory Analysis: The Clean Air Interstate Rule, The
Clean Air Mercury Rule, and the Clean Air Visibility Rule (EPA
promulgated rules, 2005).  The specific technical support document on
air quality modeling for CAIR/CAMR/CAVR, Technical Support Document for
Air Quality Modeling Technique, is available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/aqsupport/" 
http://www.epa.gov/airmarkets/mp/aqsupport/ .  It is also available as
Docket Item EPA-HQ-OAR-2005-0163-0142.

 See Stephen D. Page, Director, “Implementation of New Source Review
Requirements in PM2.5 Nonattainment Areas,” April 5, 2005, available
at    HYPERLINK "http://www.epa.gov/nsr/guidance.html" 
http://www.epa.gov/nsr/guidance.html  and as Docket Item
EPA-HQ-OAR-2005-0163-01413.

 Analysis and supporting documentation available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/index.html" 
http://www.epa.gov/airmarkets/mp/index.html .  Also available as Docket
Item EPA-HQ-OAR-2005-0163-0142.

 Analysis and supporting documentation available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/index.html" 
http://www.epa.gov/airmarkets/mp/index.html .  Also available as Docket
Item EPA-HQ-OAR-2005-0163-0142.

 See Regulatory Impact Analysis for PM2.5 rule at pg  3-34.  Available
at   HYPERLINK "http://www.epa.gov/ttn/ecas/ria.html" 
http://www.epa.gov/ttn/ecas/ria.html  and as Docket Item
EPA-HQ-OAR-2005-0163-0144. 

 PM2.5 emissions information from PM2.5 NAAQS RIA, available at  
HYPERLINK "http://www.epa.gov/ttn/ecas/ria.html" 
http://www.epa.gov/ttn/ecas/ria.html .  Also available as Docket Item
EPA-HQ-OAR-2005-0163-0144.

 Emissions information Available as Docket Item
EPA-HQ-OAR-2005-0163-0146. [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).

 Available as Docket Item EPA-HQ-OAR-2005-0163-0146.  [NSR Availability
PM2.5, VOC, and CO]

 Emission increases of at least 0.5 tpy.  Does not include emissions
due to new EGUs (IPM new units and IPM planned-committed units).  New
units (IPM new units and planned-committed units) were not included in
CAIR/CAMR/CAVR 2020 and NSR Availability county-level emission totals
because they had not been assigned to a county.  New EGUs would not be
subject to proposed rule.  New EGUs would be subject to major NSR,
including control technology review for installation of BACT/LAER.

 Analysis and emission factors used available as Docket Item
EPA-HQ-OAR-2005-0163-0146.  [2003-2004 PM2.5, VOC, and CO Emissions]

 Analysis available as Docket Item EPA-HQ-OAR-2005-0163-0146.  [NSR
Availability PM2.5, VOC, and CO]  Emission increases of at least
0.5 tpy.  Does not include emissions due to new EGUs (IPM new units and
IPM planned-committed units).  

 The CMAQ modeling was conducted as part of EPA’s multipollutant
legislative assessment and the results are available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp"  http://www.epa.gov/airmarkets/mp  .
Multipollutant Regulatory Analysis: The Clean Air Interstate Rule, The
Clean Air Mercury Rule, and the Clean Air Visibility Rule (EPA
promulgated rules, 2005).  The specific technical support document on
air quality modeling for CAIR/CAMR/CAVR, Technical Support Document for
Air Quality Modeling Technique, is available at   HYPERLINK
"http://www.epa.gov/airmarkets/mp/aqsupport/" 
http://www.epa.gov/airmarkets/mp/aqsupport/ .  It is also available as
Docket Item EPA-HQ-OAR-2005-0163-0142 

 The Regulatory Impact Analysis for the PM2.5 NAAQS is available at  
HYPERLINK "http://www.epa.gov/ttn/ecas/ria.html" 
http://www.epa.gov/ttn/ecas/ria.html .  It is also available as Docket
Item EPA-HQ-OAR-2005-0163-0144.

 Mary Gibbons Natrella (1963).  “Experimental Statistics,” NBS
Handbook 91, U.S. Department of Commerce.  This work is available on the
internet at   HYPERLINK
"http://www.itl.nist.gov/div898/handbook/prc/section2/prc263.htm" 
http://www.itl.nist.gov/div898/handbook/prc/section2/prc263.htm .

 In the NSPS regulations, emissions rates are compared in terms of
kilograms per hour.  We use English units in today’s 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.

¢

®

¯

A

ç

摧㐹

hÆ_

 hü

혈F됃ကﰎ쀒!将

혈F됃ကﰎ쀒!将

葠ː摧䑰ç

h4I

hï

摧喰çe欀ㅤ

愀Ĥ摧ᕐö଀

摧䏀x欀뙤

摧䤁

hl

 hð

já

愀Ĥ摧ᕐöⴆ؀Ĥ摧敋_Ѐ)摧䤁

阂l혅መ

ዿ

愀Ĥ摧ᕐöⴆ؀Ĥ摧檙¬Ѐ)摧䤁

h)

”ÿMF

”ÿMF

”ÿMF

愀Ĥ摧櫔uЀ)摧䤁

-



u

v

Ÿ

 

Ë

Ì

h

i

j

u

v

|

ƒ

Ë

gd)

Ü

X

阂l혅መ

X

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

”ÿP	¤

愀Ĥ摧ᕐö

☊଀ᝆഀ߆퀁ĂŨༀ梄ሁā㄀$葞Ũ摧䯩i⤆㄀$摧䯩i

 hê

☊଀ᙆഀ߆ꀁąŨༀ梄ሁā㄀$葞Ũ摧䯩i⤆㄀$摧䯩i

˜

฀킄༂킄㄂$葝ː葞ː摧䯩i⤆㄀$摧䯩i✆㄀$摧䯩i

 hê

:

D

T

U

˜

Å

s

x

Î

Ï

 hê

8˜

Å

‚

愀Ĥ摧ᕐö

摧䯩i

h

h¼s

 hI

 hI

 hI

 hI

h 

j

j

 hê

C

Ž

Á

4

\

•

à



 

A

E

F

H

I

N

h

l

‡

ˆ

‘

•

À

Ç

Ë

ß

 

6

7

;

Z

^

_

a

b

g

“

—

˜

š

›

 

º

¾

Ù

Ú

ß

Uß

â

ã

ç

 h¸

 h¸

1

 h¸

 h¸

 h¸

 h¸

 h¸

 h¸

 h¸

 h¸

 h¸

y with due to fluctuations in equipment and control device performance
that are beyond the control of the EGU owner/operator. 

 PAGE   

  PAGE  1 

 PAGE   

 PAGE   59 

  PAGE  56 

  PAGE  60 

Prevention of Significant Deterioration, Nonattainment New Source
Review, and New Source Performance Standards:  Emission Increases for
Electric Generating Units – Page   PAGE  103  of   NUMPAGES  127 

 

 

