26202 Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 51 and 52 

[Docket ID No. EPA–HQ–OAR–2005–0163; 

FRL–8307–7] 

RIN–2060–AN28 

Supplemental Notice of Proposed 

Rulemaking for Prevention of 

Significant Deterioration and 

Nonattainment New Source Review: 

Emission Increases for Electric 

Generating Units 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Supplemental Notice of 

Proposed Rulemaking. 

SUMMARY: This action is a supplemental 

notice of proposed rulemaking (SNPR) 

to EPA’s October 20, 2005 notice of 

proposed rulemaking (NPR). In the 

October 2005 NPR, EPA (we) proposed 

to revise the emissions test for existing 

electric generating units (EGUs) that are 

subject to the regulations governing the 

Prevention of Significant Deterioration 

(PSD) and nonattainment major New 

Source Review (NSR) programs 

(collectively ‘‘NSR’’) mandated by parts 

C and D of title I of the Clean Air Act 

(CAA). We proposed three alternatives 

for the emissions test: a maximum 

achievable hourly emissions test, a 

maximum achieved hourly emissions 

test, and an output-based hourly 

emissions test. This action recasts the 

proposed options so that the outputbased test becomes an alternative 

method to implement the maximum 

achieved or maximum achievable 

hourly tests, rather than a separate 

option. This SNPR also proposes a new 

option in which the hourly emissions 

increase test is added to the existing 

requirements for computing a 

significant increase and a significant net 

emissions increase on an annual basis. 

It also includes proposed rule language 

and supplemental information for the 

October 2005 proposal, including an 

examination of the impacts on 

emissions and air quality. 

These proposed regulations interpret 

the emissions increase component of the 

modification test under CAA 111(a)(4), 

in the context of NSR, for existing EGUs. 

The proposed regulations would 

promote the safety, reliability, and 

efficiency of EGUs. We are seeking 

comment on all aspects of this proposed 

rule. 

DATES: Comments. Comments must be 

received on or before July 9, 2007. 

Under the Paperwork Reduction Act, 

comments on the information collection 

provisions must be received by the 

Office of Management and Budget 

(OMB) on or before June 7, 2007. 

Public Hearing: If anyone contacts us 

requesting to speak at a public hearing 

on or before May 29, 2007, we will hold 

a public hearing approximately 30 days 

after publication in the Federal 

Register. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA-HQ– 

OAR–2005–0163 by one of the following 

methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• E-mail: 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 3334, Washington, DC 

20004, Attention Docket ID No. EPA– 

HQ–OAR–2005–0163. Such deliveries 

are only accepted during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions. Direct your comments to 

Docket ID No. EPA-HQ-OAR–2005– 

0163. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov website is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional instructions on 

submitting comments, go to section B. of 

the SUPPLEMENTARY INFORMATION section 

of this document. 

Docket. All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, i.e., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the U.S. Environmental Protection 

Agency, Air Docket, EPA/DC, EPA West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Air Docket is (202) 566– 

1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Janet McDonald, Air Quality Policy 

Division (C504–03), U.S. Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, telephone number: 

(919) 541–1450; fax number: (919) 541– 

5509, or electronic mail e-mail address: 

mcdonald.janet@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

Entities potentially affected by the 

subject rule for this action are fossil-fuel 

fired boilers and turbines serving an 

electric generator with nameplate 

capacity greater than 25 megawatts 

(MW) producing electricity for sale. 

Entities potentially affected by the 

subject rule for this action also include 

State, local, and tribal governments. 

Categories and entities potentially 

affected by this action are expected to 

include: 


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Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 26203 

1Establishments owned and operated by Federal, 

State, or local government are classified according 

to the activity in which they are engaged. 

Industry Group SICa NAICSb

Electric Services .......................................... 491 221112. 

Federal government .................................... 122112 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. Fossilfuel fired electric utility steam generating units in Indian country. 

aStandard Industrial Classification 

b North American Industry Classification System. 

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 

World Wide Web. Following signature 

by the EPA Administrator, a copy of this 

notice will be posted in the regulations 

and standards section of our NSR home 

page located at http://www.epa.gov/nsr. 

C. What should I consider as I prepare 

my comments for EPA? 

1. Submitting CBI. Do not submit this 

information to EPA through http:// 

www.regulations.gov or e-mail. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD ROM that 

you mail to EPA, mark the outside of the 

disk or CD ROM as CBI and then 

identify electronically within the disk or 

CD ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI only to the 

following address: Roberto Morales, 

OAQPS Document Control Officer 

(C404–02), U.S. EPA, Research Triangle 

Park, NC 27711, Attention Docket ID 

No. EPA–HQ–OAR–2005–0163. 

2. Tips for Preparing Your Comments. 

When submitting comments, remember 

to: 

• Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

D. How can I find information about a 

possible public hearing? 

People interested in presenting oral 

testimony or inquiring if a hearing is to 

be held should contact Ms. Pamela S. 

Long, New Source Review Group, Air 

Quality Policy Division (C504–03), U.S. 

EPA, Research Triangle Park, NC 27711, 

telephone number (919) 541–0641. If a 

hearing is to be held, persons interested 

in presenting oral testimony should 

notify Ms. Long at least 2 days in 

advance of the public hearing. Persons 

interested in attending the public 

hearing should also contact Ms. Long to 

verify the time, date, and location of the 

hearing. The public hearing will provide 

interested parties the opportunity to 

present data, views, or arguments 

concerning these proposed rules. 

E. How is the preamble organized? 

The information presented in this 

preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this document 

and other related information? 

C. What should I consider as I prepare my 

comments for EPA? 

D. How can I find information about a 

possible public hearing? 

E. How is the preamble organized? 

II. Overview 

A. Option 1: Hourly Emissions Increase 

Test Followed by Annual 

Emissions Test 

B. Option 2: Hourly Emissions Increase 

Test 

III. Analyses Supporting Proposed Options 

A. The Integrated Planning Model 

B. NSR Availability Scenarios—

Description of the Scenarios 

C. NSR Availability Scenarios-Discussion 

of SO2 and NOX Results 

D. NSR Availability Scenarios-Discussion 

of PM2.5, VOC, and CO Results 

E. NSR Efficiency Scenario 

IV. Proposed Regulations for Option 1: 

Hourly Emissions Increase Test 

Followed by Annual Emissions Test 

A. Test for EGUs Based on Maximum 

Achieved Emissions Rates 

B. Test for EGUs Based on Maximum 

Achievable Emissions 

V. Proposed Regulations for Option 2: Hourly 

Emissions Increase Test 

VI. Legal Basis and Policy Rationale 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

VIII. Statutory Authority 

II. Overview 

This action is a SNPR to EPA’s 

October 20, 2005 (70 FR 61081) NPR. In 

the October 2005 NPR, we proposed to 

revise the emissions test for existing 

EGUs that are subject to the regulations 

governing the PSD and nonattainment 

major NSR programs (collectively 

‘‘NSR’’) mandated by parts C and D of 

title I of the CAA. We proposed three 

alternatives for the emissions test: a 

maximum achievable hourly emissions 

test, a maximum achieved hourly 

emissions test, and an output-based 

hourly emissions test. In the NPR, we 

did not propose to include, along with 

any of the revised NSR emissions tests, 

any provisions for computing a 

significant increase or a significant net 


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26204 Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 

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 outputbased emissions test. This action recasts 

the proposed options so that the output 

test, instead of being an alternative to 

the maximum hourly achieved or 

maximum hourly achievable tests, 

becomes an alternative method for 

sources to implement those two tests. 

Specifically, we propose that each of the 

two tests would be implemented 

through (i) an input method (as defined 

below), (ii) the output method, or (iii) at 

the source’s choice, either the input or 

output method. This action includes 

proposed rule language and 

supplemental information for the 

October 2005 proposal as it relates to 

the major NSR regulations, including an 

examination of the impacts on 

emissions and air quality that would 

result were we to finalize one of the 

applicability tests proposed in the 

October 2005 proposal or in this SNPR, 

as described below. 

This action also proposes an 

additional option that was not included 

in the October 2005 rule. For 

convenience, this action characterizes 

the tests contained in the October 2005 

NPR, described above, as Option 2 (with 

the maximum hourly achieved test 

characterized as Alternatives 1–4 and 

the maximum hourly achievable test 

characterized as Alternatives 5–6 within 

that Option 2, and with each of those 

tests including output-based 

alternatives). For the additional option 

proposed, which we characterize as 

Option 1, we are proposing that an 

hourly emissions increase test (either 

maximum achieved or maximum 

achievable, each with output-based 

alternatives) would include the 

significant net emissions increase test in 

the current major NSR rules, which is 

calculated on an actual-to-projectedactual 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.ll F.3dll (2005), 

cert. granted ll U.S.ll (2006). At 

the time of our proposal, the Fourth 

Circuit had denied the United States’

petition for rehearing on the decision in 

Duke Energy, but the deadline for filing 

a petition for certiorari to the United 

States Supreme Court had not yet 

passed. Subsequently, on December 28, 

2005, Intervenor plaintiffs 

Environmental Defense Fund, North 

Carolina Sierra Club, and North 

Carolina Public Interest Research Group 

filed a petition for certiorari asking the 

court to address several matters. On 

May 15, 2006 the United States 

Supreme Court granted the petition for 

a writ of certiorari. On April 2, 2007, the 

Supreme Court vacated and remanded 

the Fourth Circuit decision. [549 

U.S._l (2007)] , 75 U.S.L.W. 4167 

(April 2, 2007). 

When we published the proposal in 

October 2005, it was in part in response 

to the Fourth Circuit’s holding that EPA 

must read the 1980 PSD regulations to 

contain an hourly test, consistent with 

the NSPS regulations. The Supreme 

Court’s vacatur was based on its finding 

that such a reading of the 1980 PSD 

regulations ‘‘was inconsistent with their 

terms.’’ The Supreme Court, however, 

indicated that EPA may be able to revise 

the regulations when, as here, it has a 

rational reason for doing so. While there 

is no longer a need to provide national 

consistency in light of the Fourth 

Circuit decision, we believe that the 

options for a maximum hourly test that 

we proposed in our October 2005 NPR 

and continue to propose in this SNPR 

are an appropriate exercise of our 

discretion, especially in light of the 

substantial EGU emission reductions 

from more efficient air quality programs 

promulgated after 1980. Accordingly, 

we continue to pursue the viability of 

imposing an hourly emissions test on 

EGUs for purposes of major NSR 

applicability. 

In May 2001, President Bush’s 

National Energy Policy Development 

Group issued findings and key 

recommendations for a National Energy 

Policy. This document included 

numerous recommendations for action, 

including a recommendation that the 

EPA Administrator, in consultation with 

the Secretary of Energy and other 

relevant agencies, review NSR 

regulations, including administrative 

interpretation and implementation. The 

recommendation requested that we 

issue a report to the President on the 

impact of the regulations on investment 

in new utility and refinery generation 

capacity, energy efficiency, and 

environmental protection. Our report to 

the President and our recommendations 

in response to the National Energy 

Policy were issued on June 13, 2002. A 

copy of this information is available at 

http://www.epa.gov/nsr/ 

publications.html. 

In that report we concluded: 

As applied to existing power plants and 

refineries, EPA concludes that the NSR 

program has impeded or resulted in the 

cancellation of projects which would 

maintain and improve reliability, efficiency 

and safety of existing energy capacity. Such 

discouragement results in lost capacity, as 

well as lost opportunities to improve energy 

efficiency and reduce air pollution. (New 

Source Review Report to the President at pg. 

3.) 

On December 31, 2002, we promulgated 

final regulations that implemented 

several of the recommendations in the 

New Source Review Report to the 

President. However, that action left the 

NSR regulations as they related to 

utilities largely unchanged. This action 

continues to address the 

recommendations in the New Source 

Review Report to the President as they 

relate to electric utilities specifically 

and in light of the regulatory 

requirements for EGUs that have been 

promulgated since our 2002 regulations. 

The regulations proposed in the 

October 2005 NPR and on this action 

would promote the safety, reliability, 

and efficiency of EGUs. The proposed 

regulations are consistent with the 

primary purpose of the major NSR 

program, which is to balance the need 

for environmental protection and 

economic growth. The proposed 

regulations reasonably balance the 

economic need of sources to use 

existing physical and operating capacity 

with the environmental benefit of 

regulating those emissions increases 

related to a physical or operational 

change. This is particularly true in light 

of the substantial national EGU 

emissions reductions that other 

programs have achieved or are expected 

to achieve, which we described in detail 

at 70 FR 61083. Moreover, as the 

analyses included in this SNPR 

demonstrate, the proposed regulations 

would not have an undue adverse 

impact on local air quality. 

This section gives an overview of our 

proposed actions for major NSR 

applicability at existing EGUs, including 

the proposals in the NPR, as recast in 

this proposal, for the maximum hourly 

emissions tests and this additional 

proposal. Each of the options would 

promote the safety, reliability, and 

efficiency of EGUs. Each of the options 

would also balance the economic need 

of sources to use existing physical and 

operating capacity with the 

environmental benefit of regulating 

those emissions increases related to a 

change, considering the substantial 

national emissions reductions other 

programs have achieved or will achieve 


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Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 26205 

2For clarity, this table lists all of the steps in the 

applicability determinations under the various 

options and alternatives. These steps include, as 

Step 1, the determination of whether a physical 

change or change in the method of operation has 

occurred. This Step 1 is included in the table solely 

for purposes of clarity; neither the October 2005 

NPR nor this action proposes any action of any type 

(or makes any re-proposal) concerning the 

regulations defining physical change or change in 

the method of operation. Similarly, the steps also 

include, as Steps 3 and 4, the current net 

significance test; and this SNPR does not propose 

any action of any type (or make any re-proposal) 

concerning the current net significance test. Finally, 

this action does not propose any action of any type 

(or make any re-proposal) concerning the current 

applicability test for EGUs. 

3Steps 3 and 4 only apply when a unit fails Step 

2. (That is, it is determined that an hourly emissions 

increase would occur.) 

4 In this context, we use the term ‘‘input’’ as a 

convenient way to refer to the hourly emission rate 

test, and to distinguish it from the output test, 

which is calculated on the basis of hourly emissions 

per kilowatt hour of generation. 

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 2

Option 1 .......................................... Step 1: Physical Change or Change in the Method of Operation. 

Step 2: Hourly Emissions Increase Test. 

• Alternative 1—Maximum achieved hourly emissions; statistical approach; input basis. 

• Alternative 2—Maximum achieved hourly emissions; statistical approach; output basis. 

• Alternative 3—Maximum achieved hourly emissions; one-in-5-year baseline; input basis. 

• Alternative 4—Maximum achieved hourly emissions; one-in-5-year baseline; output basis. 

• Alternative 5—NSPS test—maximum achievable hourly emissions; input basis. 

• Alternative 6—NSPS test-maximum achievable hourly emissions; output basis. 

Step 3: Significant Emissions Increase Determined Using the Actual-to-Projected-Actual Emissions Test as 

in the Current Rules.3

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

Option 2 .......................................... Step 1: Physical Change or Change in the Method of Operation. 

Step 2: Hourly Emissions Increase Test. 

• Alternative 1—Maximum achieved hourly emissions; statistical approach; input basis. 

• Alternative 2—Maximum achieved hourly emissions; statistical approach; output basis. 

• Alternative 3—Maximum achieved hourly emissions; one-in-5-year baseline; input basis. 

• Alternative 4—Maximum achieved hourly emissions; one-in-5-year baseline; output basis. 

• Alternative 5—NSPS test—maximum achievable hourly emissions; input basis. 

• Alternative 6—NSPS test-maximum achievable hourly emissions; output basis. 

We request public comment on all 

aspects of this action. We intend to 

finalize either Option 1 or Option 2. We 

will also finalize either the maximum 

achieved or the maximum achievable 

alternative. We intend to respond to 

public comments on the October 20, 

2005 NPR and this notice in a single 

Federal Register Notice and Response to 

Comments Document at the time that 

we take final action. 

A. Option 1: Hourly Emissions Increase 

Test Followed by Annual Emissions Test 

In the NPR, we did not propose to 

include, along with any of the revised 

NSR emissions tests, any provisions for 

computing a significant emissions 

increase or a significant net emissions 

increase, although we solicited 

comment on retaining such provisions. 

Many commenters believed netting is 

required under the Alabama Power 

Court decision, and supported options 

retaining netting. Therefore, we are 

proposing that major NSR applicability 

would include an hourly emissions 

increase test, followed by the current 

regulatory requirements for the actualto-projected-actual emissions increase 

test to determine significance, and the 

significant net emissions increase test. 

We call this approach Option 1 and we 

are proposing it as our preferred option. 

Specifically, under Option 1, the major 

NSR program would include a four-step 

process as follows: (1) Physical change 

or change in the method of operation; 

(2) hourly emissions increase test ; (3) 

significant emissions increase as in the 

current major NSR regulations; and (4) 

significant net emissions increase as in 

the current major NSR regulations. 

Section IV of this preamble describes 

Option 1 in more detail. Our proposed 

regulatory language is for Option 1. 

Option 1 facilitates improvements for 

efficiency, safety, and reliability, 

without adverse air quality effects (as 

the discussion of the IPM and air quality 

analyses in Section III indicates). 

Specifically, changes that will not 

increase the hourly emissions rate—

such as those to make repairs to reduce 

the number of forced outages—do not 

require further review under Option 1. 

That is, if there would be no hourly 

emissions increase following a physical 

change or change in the method of 

operation, the proposed rule does not 

require a determination of whether a 

significant increase or a significant net 

emissions increase would occur. Thus, 

Option 1 would simplify major NSR for 

changes where there is no increase in 

hourly emissions. However, many 

public commenters urged that we retain 

the significant emissions increase 

component of the emissions increase 

test. Therefore, we are proposing further 

review under Option 1 in instances 

where a physical or operational change 

at a given unit would increase the 

hourly emissions rate, such as would 

occur where there is an increase in 

existing capacity. In such cases, Option 

1 requires further review using the 

significant increase and significant net 

emissions increase components of the 

current regulations. This approach 

retains an annual emissions test in 

determining NSR applicability. 

We are proposing both a maximum 

achieved hourly and a maximum 

achievable hourly emissions increase 

test under Step 2 of Option 1, which we 

discuss in detail in Section IV.A. of this 

preamble. Consistent with our policy 

goal of improving energy efficiency, we 

are proposing both an input 4 and 

output based format for both the 

maximum achievable and maximum 

achieved hourly emissions increase test 

options. Specifically, we are proposing 

the alternatives of (i) use of input-based 

methodology for each test, (ii) use of 

output-based methodology for each test, 

or (iii) allowing the source to choose 

between input- or output-based 

methodology. Some commenters 

strongly opposed an output-based 

format, believing that it would 

encourage emissions increases. We 

believe these concerns are mitigated in 

a system where total annual emissions 


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26206 Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 

5Complete documentation for IPM, including the 

Base Case Scenario, is available at http:// 

www.epa.gov/airmarkets/progsregs/epa-ipm/ 

index.html. See also Docket EPA–HQ–OAR–2005–

0163, DCN 01. 6See the NEEDS 2004 documentation for IPM 

v.2.1.9 in Exhibit 4–6, which can be found at 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/ 

past-modeling.html. See also Docket EPA–HQ–

OAR–2005–0163, DCN 02. 

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 nitrogen oxides (NOX ; 40 

CFR 63.44a, 62 FR 36954, and 63 FR 

49446). We recently promulgated new 

output-based emission limits for sulfur 

dioxide (SO2) and NOX under subpart 

Da of 40 CFR part 60 (71 FR 9866) and 

for combustion turbines. (71 FR 38482.) 

B. Option 2: Hourly Emissions Increase 

Test 

For Option 2, we are proposing a 

maximum achieved emissions increase 

test alternative and a maximum 

achievable emissions increase test 

alternative. For both the maximum 

achieved and maximum achievable 

emissions increase test, we are also 

proposing the alternatives of (i) the use 

of input-based methodology for each 

test; (ii) the use of output-based 

methodology for each test, or (iii) 

allowing the source to choose between 

input- or output-based methodology. We 

describe these alternatives in detail in 

Section V. of this preamble. 

Option 2 with the proposed maximum 

hourly achieved test would simplify 

NSR applicability determinations. 

Option 2 with the proposed maximum 

hourly achievable test provides even 

more simplicity by conforming NSR 

applicability determinations to NSPS 

applicability determinations. We also 

note the achieved and achievable tests 

eliminate the burden of projecting 

future emissions and distinguishing 

between emissions increases caused by 

the change from those due solely to 

demand growth, because any increase in 

the emissions under the hourly 

emissions tests would logically be 

attributed to the change. Both the 

achieved and achievable tests reduce 

recordkeeping and reporting burdens on 

sources because compliance will no 

longer rely on synthesizing emissions 

data into rolling average emissions. 

Option 2 would reduce the reviewing 

authorities’ compliance and 

enforcement burden compared to the 

current regulations. 

In the October 2005 NPR, we also 

solicited comment on whether, if we 

revised the NSR test to be a maximum 

achieved emissions test or output-based 

emissions test, we should revise the 

NSPS regulations to include a maximum 

achieved emissions test or an outputbased 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 multiregional, dynamic, deterministic linear 

programming model of the entire 

electric power sector. It provides 

forecasts of least-cost capacity 

expansion, electricity dispatch, and 

emission control strategies for meeting 

energy demand and environmental, 

transmission, dispatch, and reliability 

constraints. We have used the IPM 

extensively to evaluate the cost and 

emissions impacts of proposed policies 

to limit emissions of sulfur dioxide and 

nitrogen oxides from the electric power 

sector. The IPM was a key analytical 

tool in developing the Clean Air 

Interstate Regulation (CAIR; see 70 FR 

25162). However, the IPM capabilities 

and results are not limited to projections 

for CAIR States. It includes data for and 

projects emissions and controls for the 

electric sector in the contiguous United 

States. 

Each IPM model run is based on 

emissions controls on existing units, 

State regulations, cost and performance 

of generating technologies, SO2 and 

NOX heat rates, natural gas supply and 

prices, and electricity demand growth 

assumptions. This input is updated on 

a regular basis. We used the IPM to 

project EGU SO2 and NOX controls, 

emissions, and air quality in 2020 

considering projected emission controls 

under the CAIR, Clean Air Mercury Rule 

(CAMR), and Clean Air Visibility Rule 

(CAVR). For convenience, we refer to 

this projection as the CAIR/CAMR/ 

CAVR 2020 Base Case Scenario or, more 

simply, the Base Case Scenario. The 

IPM model used for this scenario is IPM 

v.2.1.9.5

The IPM v 2.1.9 is based on 2,053 

model plants, which represent 13,819 

EGUs, including 1,242 coal-fired EGUs.6

This represents all existing EGUs in the 


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7See also Docket EPA–HQ–OAR–2005–0163, 

DCN 03. 

8See also Docket EPA–HQ–OAR–2005–0163, 

DCN 03. 

9The report is available at http://www.nerc.com/ 

∼gads/ and in Docket EPA–HQ–OAR–2005–0163, 

DCN 04. 

contiguous United States as of 2004, as 

well as new units that are already 

planned or committed, and new units 

that are projected to come online by 

2007. The underlying data for these 

plants is contained in the National 

Electric Energy Data System (NEEDS), 

which contains geographic location, fuel 

use, emissions control, and other data 

on each existing EGU. NEEDS data for 

existing EGUs comes from a number of 

sources, including information 

submitted to EPA under the Title IV 

Acid Rain Program and the NOX Budget 

Program, as well as information 

submitted to the Department of Energy’s 

(DOE’s) Energy Information Agency, on 

Forms EIA 860 and 767. That is, the 

underlying data for each existing EGU 

in the IPM v.2.1.9 is information from 

an actual EGU in operation as of 2004 

that has been submitted to the EPA or 

the DOE. 

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. Plannedcommitted EGUs are those that are 

likely to come online, because ground 

has been broken, financing obtained, or 

other demonstrable factors indicate a 

high probability that the EGU will come 

online. Planned-committed units in IPM 

v.2.1.9 were based on two information 

sources: RDI NewGen database (RDI) 

distributed by Platts (http:// 

www.platts.com) and the inventory of 

planned-committed units assembled by 

DOE, Energy Information 

Administration, for their Annual Energy 

Outlook. Potential EGUs are those units 

that may be built at a future date in 

response to electricity demand. In IPM 

v.2.1.9, potential new units are modeled 

as additional capacity and generation 

that may come online in each model 

region. 

IPM v.2.1.9 also accounts for emission 

limitations due to State regulations and 

enforcement actions. It includes State 

regulations that limit SO2 and NOX

emissions from EGUs. These are 

included in Appendix 3–2, available at 

http://www.epa.gov/airmarkets/ 

progsregs/epa-ipm/docs/ 

bc3appendix.pdf.7 The IPM v.2.1.9 

includes NSR settlement requirements 

for the following six utility companies: 

SIGECO, PSEG Fossil, TECO, We 

Energies (WEPCO), VEPCO and Santee 

Cooper. The settlements are included as 

they existed on March 19, 2004. A 

summary of the settlement agreements 

is included in Appendix 3–3 of the IPM 

documentation and is available http:// 

www.epa.gov/airmarkets/progsregs/epaipm/docs/bc3appendix.pdf.8

In the IPM, EPA does not attempt to 

model unit-specific decisions to make 

equipment change or upgrades to nonenvironmental 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-byunit basis. 

Reliability is a critical element of 

power plant operation. Reliability is 

generally defined as whether an EGU is 

able to operate over sustained periods at 

the level of output required by the 

utility. One measure of reliability is 

availability, the percentage of total time 

in a given period that an EGU is 

available to generate electricity. An EGU 

is available if it is capable of providing 

service, regardless of the capacity level 

that can be provided. Availability is 

generally measured using the number of 

hours that an EGU operates annually. 

For example, if an EGU operated 8,760 

hours in a particular year, it was 100 

percent available. Each year, EGUs are 

not available for some number of hours 

due to planned outages, maintenance 

outages, and forced outages. 

IPM v.2.1.9 uses information from the 

North American Electric Reliability 

Council (NERC)’s Generator Availability 

Data System (GADS) to determine the 

annual availability for EGUs. The GADS 

database includes operating histories—

some dating back to the early 1960’s—

for more than 6,500 EGUs. These units 

represent more than 75 percent of the 

installed generating capacity in the 

United States and Canada. Each utility 

provides reports, detailing its units’

operation and performance. The reports 

include types and causes of outages and 

deratings, unit capacity ratings, energy 

production, fuel use, and design 

information. GADS provides a standard 

set of definitions for determining how to 

classify an outage on a unit, including 

planned outages, maintenance outages, 

and forced outages. The GADS data are 

reported and summarized annually. A 

planned outage is the removal of a unit 

from service to perform work on specific 

components that is scheduled well in 

advance and has a predetermined start 

date and duration (for example, annual 

overhaul, inspections, testing). Turbine 

and boiler overhauls or inspections, 

testing, and nuclear refueling are typical 

planned outages. 

A maintenance outage is the removal 

of a unit from service to perform work 

on specific components that can be 

deferred beyond the end of the next 

weekend, but requires the unit be 

removed from service before the next 

planned outage. Typically, maintenance 

outages may occur any time during the 

year, have flexible start dates, and may 

or may not have predetermined 

durations. For example, a maintenance 

outage would occur if an EGU 

experiences a sudden increase in fan 

vibration. The vibration is not severe 

enough to remove the unit from service 

immediately, but does require that the 

unit be removed from service soon to 

check the problem and make repairs. 

A forced outage is an unplanned 

component failure or other breakdown 

that requires the unit be removed from 

service immediately, that is, within 6 

hours, or before the end of the next 

weekend. A common cause of forced 

outages is boiler tube failure. 

Each EGU must report the number of 

hours due to planned outages, 

maintenance outages, and forced 

outages to NERC annually. NERC 

summarized the data for all coal-fired 

EGUs over the period from 2000–2004 

in its Annual Unit Performance 

Statistics Report.9 For the years 2001–

2004, the average annual planned 

outage hours for all coal-fired EGUs was 

572.09 (about 23 days), the average 

annual maintenance outage hours for all 

coal-fired EGUs was 156.27 (about 6 

days), and the average annual forced 

outage hours for all coal-fired EGUs was 

348.75 (about 14 days). The total annual 

unavailable hours for all coal-fired 

EGUs were 1,087.57, which is 15.1 

percent of the total annual hours of 

8,760. Based on this data, the IPM 

v.2.1.9 assumed coal-fired EGUs were 

85 percent available. As just noted, of 

the 1,087.57 total unavailable hours, 

348.75 were forced outage hours, which 

means that coal-fired EGUs were 


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10Also available in Docket EPA–HQ–OAR–2005–

0163, DCN 05. 

11See our presentation, ‘‘Contributions of CAIR/ 

CAMR/CAVR to NAAQS Attainment: Focus on 

Control Technologies and Emission Reductions in 

the Electric Power Sector,’’ on pages 39 and 43. The 

presentation is available at http://www.epa.gov/ 

cair/charts.html. Also available in Docket EPA–

HQ–OAR–2005–0163, DCN 05. 

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 http:// 

www.epa.gov/cair/charts.html.10 As this 

presentation shows, under the CAIR/ 

CAMR/CAVR 2020 Base Case Scenario, 

local SO2 and NOX emissions generally 

decrease, average SO2 and NOX

emission rates decrease, and national 

SO2 and NOX emissions decrease. As 

this document also shows, half of the 

coal-fired generation is expected to have 

scrubbers and either SCR or SNCR by 

2020. These effects occur throughout the 

contiguous 48 States, not just in the 

CAIR States. 

We developed IPM scenarios to 

examine the effects of our proposed 

regulations, including the maximum 

hourly emissions increase tests 

(achievable and achieved, on an input 

and output basis), on EGU emissions 

and control technologies. These new 

IPM scenarios incorporate the 

parameters used in the IPM model 

v.2.1.9 that we describe above, 

including information for the electric 

sector in the contiguous United States. 

Thus, these new IPM scenarios revise 

the parameters in the CAIR/CAMR/ 

CAVR 2020 Base Case Scenario 

consistent with the way EGUs might 

operate under the proposed major NSR 

applicability changes. We call these IPM 

scenarios the NSR Availability and the 

NSR Efficiency Scenarios, and discuss 

them in the following sections. 

B. NSR Availability Scenarios— 

Description of the Scenarios 

We developed two IPM scenarios, 

which we call the CAIR/CAMR/CAVR 

NSR Availability Scenarios, or, more 

simply, the NSR Availability Scenarios, 

to examine how changes to major NSR 

applicability under the proposed 

regulations could, by allowing sources 

to make repairs or improvements that 

increase hours of operation, affect 

emissions and control technology 

installation. The NSR Availability IPM 

scenarios are based on the CAIR/CAMR/ 

CAVR 2020 Scenario. 

The primary difference between the 

current applicability test and the 

proposed tests is that under the 

proposed tests, sources could more 

readily make repairs or improvements 

that prevent forced outages, and thereby 

allow the source to operate more hours. 

These repairs allow the source to 

operate at the higher availability level 

that it achieved before its equipment 

degraded so much as to cause more 

forced outages. 

Some commenters emphasized this 

difference between the current 

applicability test and our proposals in 

the NPR. They explained that because, 

as we noted at 70 FR 61100, hours of 

operation are considered in determining 

annual emissions under the actual-toprojected-actual test in the current 

major NSR program but have no role in 

any of our proposed hourly emissions 

increase test options, an EGU could 

make a change that does not increase 

the maximum hourly emissions rate, but 

does allow the source to run more 

hours. This change would not trigger 

review under a maximum hourly 

emissions increase test in any case, but 

in some cases might trigger review 

under the current major NSR emissions 

increase test based on annual emissions 

with a 5-year baseline period. These 

commenters assert that the proposed 

applicability tests could allow 

substantial increases in annual 

emissions without triggering NSR. 

For several reasons, we believe 

commenters have overstated the 

likelihood that substantial increases in 

annual emissions and resulting 

deterioration in air quality would occur 

under the proposed maximum hourly 

emissions tests, as opposed to the 

current annual emissions, 5-year 

baseline test. First, an EGU can increase 

its hours of operation under the current 

regulations, as long as it does not make 

a physical change or change in the 

method of operation. Information from 

the RBLC confirms that most EGUs are 

already permitted to run 8760 hours 

annually. That is, increases in hours of 

operation at most EGUs are not a change 

in the method of operation. They are 

allowed and frequently occur at many 

EGUs under the current regulations 

without triggering major NSR. Second, 

increases in actual emissions stemming 

from increases in hours of operation that 

are unrelated to the change, are not 

considered in determining projected 

actual emissions. To the extent that 

changes resulting in increased hours 

would occur under the proposed 

regulatory scheme, any resulting 

increases in emissions will be 

diminished as the CAIR and BART 

programs are implemented and the SO2

and NOX emissions for most EGUs are 

capped. As we described in detail in the 

NPR, 70 FR 61087, national and regional 

caps limit total actual annual EGU SO2

and NOX emissions. These caps greatly 

reduce the significance of hours of 

operations on actual emissions from the 

sector nationally. Furthermore, as we 

indicated in our recent report of the 

CAIR/CAMR/CAVR, the more hours an 

EGU operates, the more likely it is to 

install controls.11 Moreover, existing 

synthetic minor limits to avoid major 

NSR and enforceable limits on hours of 

operation on a particular EGU as a result 

of netting would remain in place under 

any revised emissions increase test. We 

thus believe the opportunities for many 

EGUs to significantly increase their 

emissions through higher hours of 

operation under a maximum hourly 

emissions increase test, as compared to 

the current annual emissions increase 

test with a 5-year baseline period, are 

generally limited. 

Nonetheless, we want to 

comprehensively examine the outcomes 

of a maximum hourly emissions 

increase test, using a robust 

methodology based on conservative 

(that is, protective of the environment) 

estimates. We therefore developed two 

IPM scenarios, which we call the CAIR/ 

CAMR/CAVR NSR Availability 

Scenarios, or, more simply, the NSR 

Availability Scenarios, to examine how 

changes to major NSR applicability 

under the proposed regulations could, 

by allowing sources to make repairs or 

improvements that increase hours of 

operation, affect emissions and control 

technology installation. These IPM 

scenarios are based on the CAIR/CAMR/ 

CAVR 2020 Scenario, which employs 

the IPM v.2.1.9 model that we describe 

in Section III. A. of this preamble, 

including information for the electric 

sector in the contiguous United States. 

Section III A. of this document also 

contains specific information on the 

assumptions about EGU assumptions in 

the IPM v.2.1.9. The NSR Availability 

Scenarios retain the heat input for each 

EGU from the CAIR/CAMR/CAVR 2020 

Scenario. That is, we did not assume 

that any existing EGU would increase its 

capacity in the NSR Availability 

Scenario. 

The parameters in the IPM model are 

based on availability for 6,500 EGUs 

over the 5-year period from 2000–2004. 

In the NSR Availability scenarios, 

however, we changed the parameters in 

IPM v.2.1.9 consistent with the way 

EGUs might operate under the more 

flexible regulations that we are 

proposing. That is, we assumed that 


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12While we believe it is most likely that an EGU 

would increase its hours of operation under these 

proposed regulations due to reducing the number 

of hours that the EGU is unavailable due to forced 

outage hurs, the analysis is applicable to increaes 

in hours of operation for other reasons. 

13Available in Docket EPA–HQ–OAR–2005–

0163, DCN 06. (System Summary Report for NSR 

Availability). 

14See our presentation, ‘‘Contributions of CAIR/ 

CAMR/CAVR to NAAQS Attainment: Focus on 

Control Technologies and Emission Reductions in 

the Electri Power Sector,’’ on pages 39 and 43. The 

presentation is available at http://www.epa.gov/ 

cair/charts.html. Also available in Docket EPA–

HQ–OAR–2005–0163, DCN 05. 

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 brokendown equipment in an effort to reduce 

the number of forced outages. Such 

actions would increase the safety, 

reliability, and efficiency of EGUs, 

consistent with one of our primary 

policy goals for our proposed 

regulations. 

Therefore, in the NSR Availability 

Scenario, we assumed that coal-fired 

EGUs would be able to make changes 

that affect forced outage hours in two, 

alternative, ways: (1) Coal-fired EGUs 

would reduce their forced outage hours 

by half (2 percent increase in 

availability); and (2) coal-fired EGUs 

would have no forced outage hours (4 

percent increase in availability). 

Therefore, in the first model run, we 

increased the coal-fired availability by 2 

percent, from 85 percent to 87 percent 

annually. In the second NSR EGU run, 

we increased coal-fired availability by 4 

percent, to 89 percent annually. We 

believe it is unlikely that an EGU would 

be able to make repairs that completely 

eliminate forced outage hours. However, 

we wanted a robust examination of 

changes that could impact emissions 

and air quality.12 We therefore made the 

very conservative assumption to 

increase to EGU availability by 2 

percent and 4 percent over the actual 

historical hours of operation for 6,500 

EGUs over the years 2000–2004. All 

other information in the NSR 

Availability Scenarios is the same as 

that in IPM v.2.1.9 used for the CAIR/ 

CAMR/CAVR Scenario. 

The NERC GADS calculates the 

average availability for an EGU by 

taking the actual total number of 

unavailable hours in a given year for all 

EGUs and dividing it evenly among the 

total number of EGUs. Based on the 

GADS data, the IPM assumes an upper 

bound of 85 percent availability for 

coal-fired EGUs. In GADS data for the 

years 2000–2004, some EGUs actually 

had more than 85 percent availability 

and some actually had less. The 

particular EGUs that had greater than 85 

percent availability and less than 85 

percent varied from year to year. 

Similarly, by eliminating forced outages, 

some EGUs could increase their 

availability by more than 2–4 percent 

and some EGUs could increase their 

availability by less than 2–4 percent. 

Likewise, the particular EGUs that were 

able to reduce their forced outage hours 

would also vary from year to year. For 

modeling purposes, it thus makes more 

sense to assume an average availability 

than to determine unit-by-unit 

availabilities for each and every EGU in 

a given year. 

Our approach based on average 

availability is also consistent with 

actual historical operations at particular 

EGUs and plantsites, which are most 

directly related to local emissions and 

air quality. Variation in actual annual 

hours of operation at a given EGU and 

at given plantsites do occur under 

current major NSR applicability. It is 

not uncommon for actual hours of 

operation for a particular EGU to vary 

by 348 hours (4 percent availability) or 

more from year to year. It is also not 

uncommon for the variation in actual 

hours of operation to occur among EGUs 

at a particular plantsite by 4 percent or 

more from year to year. For example, in 

one year Unit A might run 7,800 hours 

and Unit B might run 7,400 hours. In 

the next year Unit B might run 7,800 

hours and Unit A 7,400 hours. This 

pattern further supports an approach 

based on average availability for 

estimating local emissions. Changes in 

average availability, rather than the 

absolute availability of any given EGU, 

thus is appropriate for analyzing the 

impact of proposed changes to major 

NSR applicability. 

C. NSR Availability Scenarios—

Discussion of SO2 and NOX Results 

This section discusses the SO2 and 

NOX control device installation, 

national emissions, local emissions, and 

impact on air quality for EGUs under 

the NSR Availability Scenario. 

1. SO2 and NOX Control Device 

Installation. As Table 2 shows, the NSR 

Availability Scenarios project 

retrofitting of more control devices than 

under the CAIR/CAMR/CAVR 2020 

Scenario.13 This result occurs whether 

hours of operation increase by 2 percent 

or by 4 percent. Significantly, under the 

4 percent scenario, more Gigawatts 

(GW) of electric capacity are controlled 

than under the 2 percent scenario. For 

example, under NSR Availability 4%, 

there is 3.63 more GW of national EGU 

capacity with scrubbers than under 

CAIR/CAMR/CAVR 2020. These results 

are consistent with what IPM generally 

projects, as noted above; that is, the 

more hours an EGU operates, the more 

likely it is to install controls.14 We thus 

conclude that the more hours an EGU 

operates, the more likely it is to install 

controls, regardless of whether the 

major NSR applicability test is on an 

hourly basis or an annual basis. 


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15 15 FGD is flue gas desulfurization, also known 

as scrubbers, for control of SO2 emissions. 

16SCR is selective catalytic reduction, used for 

control of NOX emissions. 

17CAIR/CAMR/CAVR SO2 and NOX emissions 

available in Docket EPA–HQ–OAR–2005–0163, 

DCN 14. [EPA 219b_BART 13_2020_Pechan.xls]. 

NSR SO2 and NOX Availability Emissions available 

in Docket EPA–HQ–OAR–2005–0163, DCN 14. 

[EPA 219b_NSR_OAQPS_5_Pechan_2020.xls] 

National totals for CAIR/CAMR/CAVR and NSR 

Availability include new units (IPM new units and 

planned-committed units). 

18CAIR/CAMR/CAVR SO2 and NOX emissions 

available in Docket EPA–HQ–OAR–2005–0163, 

DCN 14. [EPA 219b_BART 13_2020_Pechan.xls]. 

NSR SO2 and NOX Availability Emissions available 

in Docket EPA–HQ–OAR–2005–0163, DCN 14. 

[EPA 219b_NSR_OAQPS_5_Pechan_2020.xls]. 

19Available in Docket EPA–HQ–OAR–2005–

0163, DCN 08. (2000–2004 Electric Generation). 

TABLE 2.—2020 NATIONAL EGUS WITH EMISSION CONTROLS UNDER NSR AVAILABILITY SCENARIOS

Emission 

control 

type 

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% 

FGD15 ................................. 109.62 GW .......................... 111.53 GW .......................... 1.71 GW .............................. 3.63 GW 

SCR16 ................................. 73.47 GW ............................ 73.92 GW ............................ 0.62 GW .............................. 1.07 GW 

2. SO2 and NOX National Emissions. 

As Table 3 shows, the NSR Availability 

Scenarios project essentially no changes 

in SO2 or NOX emissions nationally by 

2020 as compared to emissions under 

the CAIR/CAMR/CAVR 2020 

Scenario.17 This result is consistent 

with the fact that under the NSR 

Availability Scenarios, the amount of 

controls increases, compared to CAIR/ 

CAMR/CAVR 2020, and we find that 

these associated emissions decreases are 

offset by the emissions increases 

associated with the reduced forced 

outages and higher production levels. 

TABLE 3.—NATIONAL EGU EMISSIONS UNDER NSR AVAILABILITY SCENARIOS COMPARED TO CAIR/CAMR/CAVR 2020 

(TPY) 

Pollutant CAIR/CAMR/ 

CAVR NSR 4% NSR 2% Change-NSR 4% Change-NSR 2% 

SO2 .................................... 4,277,000 4,271,000 4,261,000 ¥6,000 <1% decrease ........ ¥16,000 <1% decrease. 

NOX ................................... 1,989,000 2,016,000 2,003,000 28,000 1% increase ............ 14,000 1% increase. 

As noted above, the NSR Availability 

Scenarios examine emissions changes 

based on very conservative estimates 

developed using actual historical hours 

of operation for 6,500 EGUs over the 

years 2000–2004. We conclude that to 

any extent that EGU hours of operation 

increase under a maximum hourly test, 

as opposed to the current average 

annual 5-year baseline test, such 

increased hours of operation would not 

increase national EGU SO2 emissions. 

The increased availability would have 

very little effect on national NOX

emissions, with approximately one 

percent increase nationally. This 

conclusion as to emissions in the 

contiguous 48 States supports extending 

the proposed rules nationwide, instead 

of limiting them to the States in the 

CAIR region. 

3. SO2 and NOX Local Emissions 

Impact. To examine the effect of the 

maximum hourly and 5-year baseline 

tests on local air quality, we compared 

2020 county-level EGU SO2 and NOX

emissions under the CAIR/CAMR/CAVR 

2020 and NSR Availability (4%) 

Scenario.18 We describe these changes 

in detail in Chapter 4 of the Technical 

Support Document (TSD). As the TSD 

shows, the proposed revised NSR 

applicability tests would, under the very 

conservative assumptions described 

above, result in a somewhat different 

pattern of local emissions, with some 

counties experiencing reductions, some 

experiencing increases, and some 

remaining the same. This pattern is 

consistent with the fact that most coalfired EGUs are in the CAIR region and 

therefore subject to regulations 

implementing the CAIR cap. According 

to the DOE’s Energy Information 

Agency, for the years 2003–2004, 

approximately 80 percent of the coal 

steam electric generation and 75 percent 

of all electric generation occurred in 

CAIR States.19 Furthermore, EGUs are 

subject to national SO2 caps under the 

Acid Rain Program. 

For these reasons, an increase in 

emissions in one area results in a 

decrease elsewhere. This dynamic 

occurs regardless of the major NSR 

applicability test for existing EGUs. 

Nonetheless, the NSR Availability 

Scenario demonstrates that this pattern 

continues to occur when increased 

availability is assumed, such as we 

assume for present purposes would 

occur under the proposed maximum 

hourly and 5-year baseline tests. 

4. SO2 and NOX Impact on Air 

Quality. In Chapter 4 of the TSD, we 

compare projected county-level SO2 and 

NOX emissions under NSR Availability 

4% to those projected under CAIR/ 

CAMR/CAVR 2020. Projected increases 

in emissions of these pollutants due to 

increased hours of operation at EGUs 

under the NSR Availability (4%) 

Scenario are small in magnitude and 

sparse across the continental U.S. 

Therefore, we would expect these 

increases to cause minimal local 

ambient effect, both directly on SO2 and 

NOX emissions and as precursors to 

formation of PM2.5 (SO2 and NOX

emissions) and ozone (NOX emissions). 

Because many counties experience 

decreases in emissions, we would 

further expect any local ambient effects 

from increased emissions to be 

somewhat diminished because of the 

emissions decreases elsewhere that 

yield regionwide improvements in air 

quality, including SO2, NOX, PM2.5, and 

ozone. We expect similar outcomes with 

respect to the NSR Availability (2%) 

Scenario where the emissions changes 

are smaller and constitute a pattern of 

increases and decreases that is similar to 

that of the NSR Availability (4%) 

Scenario. Based on the spatial 

distribution of SO2 and NOX emissions 

changes as shown in the TSD, we would 

also expect patterns of air quality 

changes respectively under the NSR 

Availability (4%) Scenario to be 

consistent with projections under CAIR/ 

CAMR/CAVR in 2020. We thus believe 

that the local air quality under this 

proposed regulations would be 

commensurate with that under the 


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20As we describe in more detail in the TSD, the 

CAIR/CAMR/CAVR modeling is available on our 

website and in the docket for this rulemaking. The 

CMAQ modeling was conducted as part of EPA’s 

multipollutant legislative assessment and the 

results are available in the Multipollutant 

Regulatory Analysis: The Clean Air Interstate Rule, 

The Clean Air Mercury Rule, and the Clean Air 

Visibility Rule (EPA promulgated rules, 2005) at 

http://www.epa.gov/airmarkets/progsregs/cair/

multi.html. The specific technical support 

document on air quality modeling for CAIR/CAMR/ 

CAVR, Technical Support Document for EPA’s 

Multipollutant Analysis; Methods for Projecting Air 

Quality Concentrations for EPA’s Multipollutant 

Analysis of 2005, is available at http:// 

www.epa.gov/airmarkets/progsregs/cair/multi.html 

by clicking on the Technical Support Document—

Air Quality Modeling Technique used for MultiPollutant Analysis link. It is also available in 

Docket EPA–HQ–OAR–2005–0163, DCN 09. 

Information on ozone modeling is available at 

http://www.epa.gov/airmarkets/progsregs/cair/

multi.html through the Air quality Modeling 

Results Excel File link. It is also available in Docket 

EPA–HQ–OAR–2005–0163, DCN 16. 

21See the Regulatory Impact Analysis for 2006 

NAAQS for Particle Pollution Chapter 3—Controls, 

page 34. Available at http://www.epa.gov/ttn/ecas/ 

ria.html and in Docket EPA–HQ–OAR–2005–0163, 

DCN 10. 

22CO emissions information from Clear Air 

Interstate Rule Emissions Inventory Technical 

Support Document, available at http:// 

www.epa.gov/interstateairquality/pdfs/ 

finaltech01.pdf. CO emissions rounded to nearest 

thousand ton level. Also available in Docket EPA–

HQ–OAR–2005–0163, DCN 11. PM2.5 and VOC 

emissions information from PM2.5 NAAQS RIA, 

available at http://www.epa.gov/ttn/ecas/ria.html. 

Also available in Docket EPA–HQ–OAR–2005–

0163, DCN 10. 

23Emissions information available in Docket 

EPA–HQ–OAR–2005–0163, DCN 17. [NSR 

Availability PM2.5, VOC, and CO] National totals for 

CAIR/CAMR/CAVR and NSR Availability include 

new units (IPM new units and planned-committed 

units). 

24Available in Docket EPA–HQ–OAR–2005–

0163, DCN 17. [NSR Availability PM2.5, VOC, and 

CO]. 

CMAQ modeling based on CAIR/CAMR/ 

CAVR 2020 Scenario emissions 

projections.20 That is, we believe local 

air quality under these proposed 

regulations would be commensurate 

with air quality we are projecting for 

2020 absent a change to the existing 

major NSR emissions increase test. 

D. NSR Availability Scenarios—

Discussion of PM2.5, VOC, and CO 

Results 

We used the NSR Availability 

Scenarios that we describe in Section 

III.B of this preamble to examine the 

PM2.5, VOC, and CO emissions and air 

quality impacts of the proposed hourly 

emissions increase test. This Section 

provides the results of our analyses. 

1. PM2.5, VOC, and CO Control Device 

Installation. As we discuss in the PM2.5

NAAQS RIA, our NEEDS indicates that 

as of 2004, 84 percent of all coal-fired 

EGUS have an ESP in operation, about 

14 percent of EGUs have a fabric filter, 

and roughly 2 percent have wet PM2.5

scrubbers.21 Gas-fired turbines are clean 

burning and BACT/LAER for these 

EGUs is no control. BACT/LAER for 

VOC and CO is good combustion 

control. Furthermore, EGU owner/ 

operators have natural incentives to 

reduce VOC and CO emissions. VOC 

and CO emissions are products of 

incomplete combustion. These 

compounds are discharged into the 

atmosphere when fuel remains 

unburned or is burned only partially 

during the combustion process. Fuel is 

a significant portion of total costs for 

EGUs, particularly for older EGUs where 

capital costs are paid off. EGU owner/ 

operators have in fact improved 

combustion practices to increase 

combustion efficiency, thereby limiting 

unburned fuel. Cost effective operation 

is especially desirable in areas where a 

cap and trade program increases the cost 

of operation by creating a cost to 

pollute, as is the case in the CAIR region 

where most ozone and PM2.5

nonattainment areas are located. 

2. PM2.5, VOC, and CO National 

Emissions. As Table 4 shows, EGUs 

contribute a small percentage of 

national PM2.5, CO, and VOC 

emissions.22

TABLE 4.—EGU EMISSIONS AS PERCENT OF 2020 NATIONAL EMISSIONS (TPY) 

Pollutant EGU National EGU as % 

National 

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

VOC ............................................................................................................................................. 45,000 12,414,000 0.4 

CO ................................................................................................................................................ 718,000 82,852,000 0.9 

As Table 5 shows, the NSR 

Availability Scenarios project 

essentially no changes in PM2.5, VOC, or 

CO emissions nationally by 2020 as 

compared to emissions under the CAIR/ 

CAMR/CAVR Scenario.23

TABLE 5.—NATIONAL EGU EMISSIONS UNDER NSR AVAILABILITY SCENARIO COMPARED TO CAIR/CAMR/CAVR 2020 

(TPY) 

Pollutant CAIR/CAMR/ 

CAVR NSR 4% Change-NSR 4% 

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

VOC ....................................................................................................................................... 45,020 45,391 371 

CO .......................................................................................................................................... 716,184 711,254 (4,930 ) 

As described in Section III.B of this 

preamble, the NSR Availability 

Scenarios examine emissions changes 

based on very conservative estimates 

developed using actual historical hours 

of operation for 6,500 EGUs over the 

years 2000–2004. We conclude that to 

any extent that EGU hours of operation 

increase under a maximum hourly 

emissions increase test, as opposed to 

the current average annual 5-year 

baseline test, such increased hours of 

operation would not increase national 

EGU PM2.5 and CO emissions. The 

increased availability would have very 

little effect on national VOC emissions, 

with less than half of a percent increase 

nationally. This conclusion as to 

emissions in the contiguous 48 States 

supports extending the proposed rules 

nationwide, instead of limiting them to 

the States in the CAIR region. 

3. PM2.5, VOC, and CO Local 

Emissions Impact. To examine the effect 

of the maximum hourly emission 

increase tests on local air quality, we 

compared 2020 county-level EGU PM2.5, 

VOC, and CO emissions under the 

CAIR/CAMR/CAVR 2020 and NSR 

Availability (4%) Scenario.24 We 


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25See the Clean Air Interstate Rule Emissions 

Inventory Technical Support Document on pgs 7 

and 38 at http://www.epa.gov/cair/pdfs/ 

finaltech01.pdf. Also available in Docket EPA–HQ–

OAR–2005–0163, DCN 11. 

26 Information from system summary report for 

the NSR Efficiency IPM Run. Available in Docket 

EPA–HQ–OAR–2005–0163, DCN 13 (System 

Summary Report for NSR Efficiency). CAIR/CAMR/ 

CAVR emissions available in Docket EPA–HQ–

OAR–2005–0163, DCN 14 [EPA 219b_BART 

13_2020_Pechan]. 27See our presentation, ‘‘Contributions of CAIR/ 

CAMR/CAVR to NAAQS Attainment: Focus on 

Control Technologies and Emission Reductions in 

the Electric Power Sector,’’ on pages 39 and 43. The 

presentation is available at http://www.epa.gov/ 

cair/charts.html. Also available in Docket EPA–

HQ–OAR–2005–0163, DCN 05. 

28CAIR/CAMR/CAVR SO2 and NOX emissions 

available in Docket EPA–HQ–OAR–2005–0163, 

DCN 14 [EPA 219b_BART 13_2020_Pechan]. NSR 

Efficiency SO2 and NOX Emissions available in 

Docket EPA–HQ–OAR–2005–0163, DCN 07 [EPA 

219b_NSR_OAQPS_ 2a_Pechan_2020_(to EPA) 4–

27–06]. NSR Efficiency PM2.5, VOC and CO 

Emissions available in Docket EPA–HQ–OAR–

2005–0163, DCN 18. National totals for CAIR/ 

CAMR/CAVR and NSR Efficiency include new 

units (IPM new units and planned-committed 

units). 

describe these changes in detail in 

Chapter 4 of the TSD. 

As Chapter 4 of the TSD shows, 

projected PM2.5, VOC, and CO emissions 

changes under the proposed revised 

NSR applicability tests would result in 

a somewhat different pattern of local 

emissions, with some counties 

experiencing reductions, some 

experiencing increases, and some 

remaining the same compared to 

emissions changes under CAIR/CAMR/ 

CAVR 2020. 

4. PM2.5, VOC, and CO Impact on Air 

Quality. As Chapter 4 of the TSD shows, 

projected increases in EGU PM2.5, VOC, 

and CO emissions due to increased 

hours of operation at EGUs under the 

NSR Availability (4%) Scenario are 

small in magnitude and sparse across 

the continental U.S. Therefore, we 

would expect these increases to cause 

minimal changes in local ambient effect 

in comparison to that observed under 

CAIR/CAMR/CAVR for PM2.5 and ozone 

(for which VOC is a precursor). Because 

many counties experience decreases in 

emissions, we would further expect any 

local ambient effects from increased 

emissions to be somewhat diminished 

because of the emissions decreases 

elsewhere that yield regionwide 

improvements in air quality. 

We have not modeled national or 

regional air quality improvements in CO 

concentrations. As noted in Table 4, 

however, EGU CO emissions are less 

than one percent of national CO 

emissions. According to our latest 

analysis, 2020 national CO emissions 

are projected to be 19,892,017 tons less 

than 2001 national CO emissions.25

Local CO emissions are generally a 

function of traffic congestion from 

mobile sources. For these reasons, EGUs 

do not contribute significantly to 

national or local CO emissions. 

The projected increases in CO 

emissions due to increased hours of 

operation at EGUs under the NSR 

Availability (4%) Scenario are small in 

magnitude and sparse across the 

continental U.S. We would expect these 

increases to cause minimal local 

ambient effect on CO. Therefore, based 

on the small increases and sparse 

distribution of CO emissions compared 

to CAIR/CAMR/CAVR 2020, and the 

small contribution of EGU emissions to 

national and local CO levels, we project 

no notable local impact on air quality 

from EGU CO emissions from NSR 

Availability 4%. 

E. NSR Efficiency Scenario. 

We designed another IPM model run 

to evaluate whether efficiency 

improvements that sources may make as 

a result of these proposed regulations 

would lead to local emissions increases 

and adverse effects on ambient air 

quality. Aside from independent factors 

such as climate and economy, efficiency 

is a primary determinant of the hours of 

operation of a given EGU. Neither the 

current annual emissions increase test 

nor any of the proposed EGU emission 

increase test alternatives directly 

measure an EGU’s efficiency. However, 

the output-based alternatives 

(Alternatives 2, 4, and 6), which are 

expressed in a lb/KWh format that 

measures mass emissions per unit of 

electricity, are closely related to an 

EGU’s efficiency. Thus, an output-based 

test encourages efficient units, which 

has well-recognized benefits. We 

anticipate that the output-based 

alternatives in particular, and the other 

alternatives to a lesser extent, could 

have the effect of encouraging EGUs to 

increase their efficiency. For these 

reasons, we focused on efficiency to 

examine whether an hourly test could 

result in emissions increases as 

compared to the annual emissions 

increase test. We call this run the NSR 

Efficiency Scenario. We assumed the 

least efficient EGUs (approximately 35% 

of all EGUs) would increase their 

efficiency by 4 percent. 

We ran the IPM with this scenario (4 

percent efficiency increase for 371 coalfired EGU, no increase in physical and 

operating existing capacity) and 

compared the results to the CAIR/ 

CAVR/CAMR IPM model. We found 

approximately the same results from the 

NSR Efficiency Scenario as from the 

NSR Availability Scenarios. We describe 

the results of the NSR Efficiency 

analysis in detail in Chapter 5 of our 

TSD. 

1. Control Device Installation. As 

Table 6 shows, the NSR Efficiency 

Scenario projects retrofitting of more 

control devices for SO2 and NOX than 

under the CAIR/CAMR/CAVR 2020.26

These results are consistent with what 

IPM generally projects. The more 

efficient an EGU is, the more cost 

effective it is to operate. The more cost 

effective it is to operate, the more hours 

it will operate. The more hours it 

operates, the more likely it is to install 

controls.27 We thus conclude that the 

more efficiently an EGU operates, the 

more likely it is to install controls, 

regardless of whether the major NSR 

applicability test is on an hourly basis 

or an annual basis with a 5-year 

baseline. 

TABLE 6.—2020 NATIONAL EGUS WITH EMISSION CONTROLS-NSR EFFICIENCY

Emissions control type EGUs with additional controls compared to 2004 

controls case 

EGUs with additional 

controls compared to CAIR/ 

CAMR/CAVR 2020 

FGD .................................................................................. 109 GW ............................................................................ 1.5 GW. 

SCR .................................................................................. 74 GW ............................................................................. 1.0 GW. 

2. National Emissions. As Table 7 

shows, the NSR Efficiency Scenarios 

project reductions in SO2 and NOX

emissions nationally by 2020 as 

compared to emissions under the Base 

Case Scenario.28 This result is 

consistent with the fact that under the 

NSR Efficiency Scenario, the amount of 

controls increases, compared to the Base 

Case. 


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TABLE 7.—NATIONAL EGU EMISSIONS UNDER NSR EFFICIENCY SCENARIO COMPARED TO CAIR/CAMR/CAVR 2020 

(TPY) 

Pollutant 

Total Emissions 

Under CAIR/ 

CAMR/CAVR 

Total Emissions 

Under NSR efficiency 

Emissions Change 

Under NSR Efficiency Compared 

to CAIR/CAMR/ 

CAVR 

SO2 ............................................................................................................................ 4,277,000 4,265,000 ¥12,000 

NOX ............................................................................................................................ 1,989,000 1,984,000 ¥5,000 

PM2.5 .......................................................................................................................... 526,642 529,647 3,005 

VOC ........................................................................................................................... 45,019 44,835 ¥184 

CO .............................................................................................................................. 716,184 711,314 ¥4,870 

As noted above, the NSR Efficiency 

Scenarios examine emissions changes 

based on very conservative estimates of 

technically feasible improvements in 

efficiency. We conclude that to any 

extent that EGU efficiency increases 

under a maximum hourly emissions 

increase test, as opposed to the current 

average annual 5-year baseline test, such 

increased efficiency would not increase 

national EGU SO2, NOX, VOC, and CO 

emissions. The increased efficiency 

would have very little effect on national 

PM2.5 emissions, with less than half of 

a percent increase nationally. This 

conclusion as to emissions in the 

contiguous 48 States supports extending 

the proposed rules nationwide, instead 

of limiting them to the States in the 

CAIR region. 

3. Local Emissions and Air Quality. 

The NSR Efficiency Scenario projects a 

somewhat different pattern of local 

emissions compared to CAIR/CAMR/ 

CAVR 2020. The NSR Efficiency 

Scenario projects decreases in many 

counties compared to CAIR/CAMR/ 

CAVR 2020. Where there are projected 

increases in local SO2, NOX, PM2.5, 

VOC, and CO emissions, they are small 

in magnitude and sparse across the 

continental United States. Therefore, we 

would expect these increases to cause 

minimal local ambient impact effect. We 

describe the NSR Efficiency Scenario 

analysis and its results in detail in 

Chapters 5 and 6 our TSD. 

IV. Proposed Regulations for Option 1: 

Hourly Emissions Increase Test 

Followed By Annual Emissions Test 

In the NPR, we did not propose to 

include, along with any of the revised 

NSR emissions tests, any provisions for 

computing a significant increase or a 

significant net emissions increase, 

although we solicited comment on 

retaining such provisions. Many 

commenters preferred to retain an 

annual emissions increase test in 

addition to the hourly emissions 

increase test. We are proposing Option 

1, in which the hourly emissions 

increase test would be followed by the 

actual-to-projected-actual emissions 

increase test and the significant net 

emissions increase test in the current 

regulations. Specifically, changes that 

will not increase the hourly emissions 

rate-such as those to make repairs to 

reduce the number of forced outages-do 

not require further review under Option 

1. However, if there would be an hourly 

emissions increase following a physical 

change or change in the method of 

operation, the proposed rule requires a 

determination of whether a significant 

increase or a significant net emissions 

increase would occur. Thus, Option 1 

retains the netting provisions in the 

current regulations. Option 1 also 

facilitates improvements for efficiency, 

safety, and reliability, without adverse 

air quality effects (as the above 

discussion of the IPM and air quality 

analyses indicates). 

We are proposing that Option 1 would 

apply to all EGUs. We are also 

requesting comment on whether Option 

1 should be limited to the geographic 

area covered by CAIR, or to the 

geographic area covered by both CAIR 

and BART. We are also proposing that 

the Option 1 would apply to all 

regulated NSR pollutants. However, we 

also request comment on whether 

Option 1 should be limited to increases 

of SO2 and NOX emissions. 

Under Option 1, the major NSR 

program would include a four-step 

process (with the second step revised as 

proposed, while retaining the other 

steps): (1) Physical change or change in 

the method of operation as in the 

current major NSR regulations; (2) 

hourly emissions increase test 

(maximum achieved hourly emissions 

rate or maximum achievable hourly 

emissions rate, each with output-based 

alternatives); (3) significant emissions 

increase as in the current major NSR 

regulations; and (4) significant net 

emissions increase as in the current 

major NSR regulations. 

For a modification to occur under 

Option 1, under Step 1, a physical 

change or change in the method of 

operation must occur, and, under Step 

2, that change must result in an hourly 

emissions increase at the existing EGU. 

If a post-change hourly emissions 

increase is projected, Option 1 retains 

the requirements for a significant 

emissions increase and a significant net 

emissions increase. In such cases, under 

Step 3, the owner/operator would 

determine whether an emissions 

increase would occur using the actualto-projected-actual annual emissions 

test in the current regulations. There 

would be no conversion from annual to 

hourly emissions. Finally, in Step 4, as 

in the current regulations, if a 

significant emissions increase is 

projected to occur, the source would 

still not be subject to major NSR unless 

there was a determination that a 

significant net emissions increase would 

occur. Table 8 summarizes these four 

steps. 

TABLE 8.—MAJOR NSR APPLICABILITY FOR EXISTING EGUS UNDER OPTION 1 

Option 1 ............. Step 1: Physical Change or Change in the Method of Operation. 

Step 2: Hourly Emissions Increase Test. 

• Alternative 1—Maximum achieved hourly emissions; statistical approach; input basis. 

• Alternative 2—Maximum achieved hourly emissions; statistical approach; output basis. 

• Alternative 3—Maximum achieved hourly emissions; one-in-5-year baseline; input basis. 

• Alternative 4—Maximum achieved hourly emissions; one-in-5-year baseline; output basis. 

• Alternative 5—NSPS test—maximum achievable hourly emissions; input basis. 


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29Steps 3 and 4 only apply when a unit fails Step 

2. (That is, it is determined that an hourly emissions 

increase would occur.) 

TABLE 8.—MAJOR NSR APPLICABILITY FOR EXISTING EGUS UNDER OPTION 1—Continued 

• Alternative 6—NSPS test—maximum achievable hourly emissions; output basis. 

Step 3: Significant Emissions Increase Determined Using the Actual-to-Projected-Actual Emissions Test as in the Current 

Rules.29

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

Option 1 would not alter the 

provisions in the current major NSR 

regulations pertaining to a significant 

emissions increase and a significant net 

emissions increase. Therefore, the 

regulations would retain the definitions 

of net emissions increase, significant, 

projected actual emissions, and baseline 

actual emissions. [See § 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) through (iii), (b)(9), 

(b)(12), (b)(14)(ii), (b)(15), (b)(18), (i)(1) 

through (9), (j)(1) through (4), (m)(1) 

through (3), (p)(1) through (7), (r)(1) 

through (7), and (s)(1) through (4) 

analogous provisions in 40 CFR 51.165, 

52.21, 52.24, and appendix S to 40 CFR 

part 51. 

We are also proposing regulatory 

language containing the two-step 

modification provisions. (Steps 1 and 2 

of Option 1, as outlined in Table 8.) As 

we noted at 70 FR 61088, you can find 

the regulatory text defining 

‘‘modification’’ within the NSPS general 

provision regulations at 40 CFR 60.2 

and 60.14. Substantially mirroring CAA 

111(a)(4), § 60.2 contains a general 

description of the two components an 

activity must satisfy to qualify as a 

modification. § 60.14 elaborates on the 

general description contained in § 60.2 

by more precisely defining how you 

measure the amount of pollution that 

results from an activity, and listing 

activities that do not qualify as physical 

changes or changes in the method of 

operation. (that is, the ‘‘increases’’

component of the modification 

definition, or Step 2.) As we proposed 

at 70 FR 61090, we have added a 

definition of modification in § 51.167, 

which mirrors the provisions in § 60.2. 

We are also proposing to add 

requirements defining the ‘‘increases’’

component of ‘‘modification’’ to the 

major NSR rules, analogous to the 

provisions in § 60.14. Specifically, the 

definition of modification in the 

proposed rules requires that an increase 

in the amount of regulated NSR 

pollutants must be determined 

according to the provisions in paragraph 

(f) of § 51.167. Under Option 1, 

Alternatives 1–4, we are proposing to 

define the ‘‘increases’’ component to 

mean maximum hourly emissions rate 

achieved. That is, if a physical change 

or change in the method of operation (as 

defined under existing regulations, 

which we are not proposing to change) 

is projected to result in an increase in 

the maximum hourly emissions rate 

expected to be achieved over the 

maximum hourly emissions rate 

actually achieved at the EGU prior to 

the change, a modification would occur. 

The requirements for the maximum 

achieved alternatives are in proposed 

§ 51.167(f)(1), Alternatives 1–4. Under 

Option 1, Alternatives 5 and 6, we are 

proposing to define the ‘‘increases’’

component to mean maximum 

achievable hourly emissions. For 

maximum achievable hourly emissions 

on an input basis, we are proposing to 

add a definition of the ‘‘increases’’

component of ‘‘modification’’ that 

substantially mirrors the definition of 

the ‘‘increases’’ component of 

‘‘modification’’ in the NSPS provisions, 

which is found in 40 CFR 60.2. These 

requirements are in proposed 

§ 51.167(f)(1), Alternative 5. For the 

maximum achievable alternative on an 

output basis (Alternative 6), the 

requirements are in proposed 

§ 51.167(f)(1), Alternative 6. 

To incorporate the two-step 

modification provisions under Option 1, 

we are proposing to add two new 

sections to the major NSR program 

rules. The first, 40 CFR 51.167, would 

specify the requirements that State 

Implementation Plans must include for 

major NSR applicability at existing 

EGUs, including those for both 

attainment and nonattainment areas. 

(Proposed rule language for 40 CFR 

51.167 accompanies this SNPR.) The 

second, 40 CFR 52.37, would contain 

the requirements for major NSR 

applicability for existing EGUs where 

we are the reviewing authority. 

Although the proposed amendatory 

language is for 40 CFR 51.167, we are 

proposing that the same requirements 

would apply under 40 CFR 52.37, 

differing only in that the Administrator 

is the reviewing authority, rather than 

the State, local, or tribal agency. 

Although this notice does not contain 

specific regulatory language, we are 

proposing that either 40 CFR 51.167 or 

40 CFR 52.37, as appropriate, would 

contain the requirements for emissions 

increases at EGUs for all sections of the 

Code of Federal Regulations that contain 

the major NSR program, including 40 

CFR 51.165, 51.166, 52.21, 52.24, and 

appendix S of 40 CFR part 51, as well 

as any regulations we finalize to 

implement major NSR in Indian 

Country. We are also proposing to make 

the same changes where necessary to 

conform the general provisions in parts 

51 and 52 to the requirements of the 

major NSR program, such as in the 

definition of modification in 40 CFR 

52.01. In addition, we are proposing to 

remove all applicability requirements 

for existing EUSGUs in all sections of 

the CFR that contain the major NSR 

program, as the EGU requirements 

would supersede these requirements. 

In the NPR, we proposed three 

alternatives for the hourly emissions 

increase test-the NSPS maximum 

achievable hourly emissions test, 

maximum achieved hourly emissions, 

and an output-based measure of hourly 

emissions. As some commenters noted, 

we did not give much detail about the 

output-based measure of hourly 

emissions. In this SNPR, we are 

recasting what we proposed in the NPR 

for the output-based methodology. In 

this SNPR, both the maximum achieved 

hourly emissions test and the maximum 

achievable hourly emissions test 

include output-based alternatives. 

Specifically, we are proposing two 

broad approaches under Option 1: (1) A 

maximum achieved hourly emissions 

test; and (2) a maximum achievable 

hourly emissions test. If we adopt the 

maximum achieved hourly emissions 

test, we may require that it be expressed 

in an input-based format (lb/hr) or an 

output-based format (lb/MWh). 

Alternatively, and as we did in our 

recently promulgated NSPS for 

combustion turbines (40 CFR part 60, 

subpart KKKK, July 6, 2006), we may 

also adopt both an input and output 

based format. If we adopt both formats, 

sources, at their choice, would be able 

to implement the hourly emissions test 

in either input-or output-based formats. 

Likewise, if we adopt the maximum 

achievable hourly emissions test, it may 

be expressed in an input-based format 


cprice-sewell on PROD1PC66 with PROPOSALS2
Federal Register / Vol. 72, No. 88 / Tuesday, May 8, 2007 / Proposed Rules 26215 

30Mary Gibbons Natrella (1963). ‘‘Experimental 

Statistics,’’ NBS Handbook 91, U.S. Department of 

Commerce. This work is available on the Internet 

at http://www.itl.nist.gov/div898/handbook/prc/ 

section2/prc263.htm. 

(lb/hr), an output-based format (lb/ 

MWh), or both. We are also proposing 

two methods for computing maximum 

achieved emissions: (1) Statistical 

approach; and (2) one-in-5-year 

baseline. In terms of the regulatory 

language that accompanies this notice, 

we are proposing six alternatives for 

determining whether a physical or 

operational change at an EGU is a 

modification. These alternatives are 

summarized in Table 9 and can be 

found at proposed § 51.167(f)(1). 

In Sections IV.A and B below, we 

describe our two approaches for the 

hourly emissions increase test in more 

detail. The regulatory language 

proposed for these approaches (that is, 

maximum achieved and maximum 

achievable hourly emissions increase 

tests) would apply under both Option 1 

and Option 2. Option 2, as described 

below in Section V, would eliminate the 

significance and netting steps that are 

included under current applicability 

regulations, whereas Option 1 would 

not eliminate the significance and 

netting steps. This action includes 

proposed rule language for Option 1. 

A. Test for EGUs Based on Maximum 

Achieved Emissions Rates 

As one approach, we are proposing 

that the hourly emissions increase test 

would be based on an EGU’s historical 

maximum hourly emissions rate. We 

call this approach the maximum 

achieved hourly emissions test. Under 

this approach, an EGU owner/operator 

would determine whether an emissions 

increase would occur by comparing the 

pre-change maximum actual hourly 

emissions rate to a projection of the 

post-change maximum actual hourly 

emissions rate. We request comment on 

all alternatives for the maximum 

achieved hourly emissions increase test 

(see proposed Alternatives 1 through 4 

for § 51.167(f)(1)), as well as on other 

possible approaches for determining 

maximum achieved hourly emissions. 

In particular, we request comments on 

whether the proposed maximum 

achieved methodologies would account 

for variability inherent in EGU 

operations and air pollution control 

devices. 

1. Determining the Pre-Change 

Emissions Rate. The pre-change 

maximum actual hourly emissions rate 

would be determined using the highest 

rate at which the EGU actually emitted 

the pollutant within the 5-year period 

immediately before the physical or 

operational change. Thus, the maximum 

achieved emissions test is based on 

specific measures of actual historical 

emissions during a representative 

period. 

We are proposing four alternatives for 

determining the pre-change maximum 

hourly emissions rate actually achieved, 

which we denote here and in the 

proposed rule language as Alternatives 

1 through 4. As shown above in Table 

9, these alternatives consist of two 

different methods for determining the 

pre-change maximum emissions rate 

(i.e., the statistical approach and the 

one-in-5-year baseline approach), each 

of which can be applied on an input (lb/ 

hr) basis or output (lb/MWh) basis. In 

addition to these four alternatives, 

which are included in the proposed rule 

language at § 51.167(f)(1), we are 

proposing that the source would have a 

choice of implementing the test on 

either an input-or output-basis. 

Proposed Alternatives 1 and 2 (input 

basis and output basis, respectively) 

utilize a statistical approach for you to 

use to analyze continuous emission 

monitoring system (CEMS) or predictive 

emission monitoring system (PEMS) 

data from the 5 years preceding the 

physical or operational change to 

determine the maximum actual 

pollutant emissions rate. The statistical 

approach utilizes actual recorded data 

from periods of representative operation 

to calculate the maximum actual 

emissions rate associated with the prechange maximum actual operating 

capacity in the past 5 years. The 

maximum actual emissions rate is 

expressed as the upper tolerance limit 

(UTL). The UTL concept and equations 

are derived from work conducted by the 

National Bureau of Standards (now the 

National Institute of Standards and 

Technology (NIST)).30

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 


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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 prechange 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 inputbased (lb/hr) alternatives. Proposed 

Alternatives 2 and 4 provide specific 

proposed rule language for the outputbased (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 


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31 In the NSPS regulations, emissions rates are 

compared in terms of kilograms per hour. We use 

English units in this proposed rulemaking in 

keeping with longstanding practice in the major 

NSR program, where annual emissions are generally 

computed using the lb/hr rate and hours of 

operation. 

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 include 

the following types of data in your 

calculations: 

• Emissions rate data associated with 

startups, shutdowns, or malfunctions of 

your EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

• CEMS or PEMS data recorded 

during monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

• Emissions rate data from periods of 

noncompliance when your EGU was 

operating above an emission limitation 

that was legally enforceable at the time 

the data were collected. 

• Data from any period for which the 

information is inadequate for 

determining emissions rates, including 

information related to the limitations 

listed above. 

The first two of these limitations are 

based on requirements of the NSPS 

General Provisions in subpart A of part 

60. The prohibition of data from periods 

of startup, shutdown, and malfunction 

is found in the section on performance 

tests, specifically § 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-toprojected-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 prechange and post-change emissions rates. 

4. Recordkeeping and Reporting 

Requirements. Under proposed 

Alternatives 1 through 4, an emissions 

increase has occurred if the emissions 

rate actually achieved in any one hour 

during the 5 years after the change 

exceeds the pre-change maximum actual 

hourly emissions rate (see, for example 

§ 51.167(f)(1)(iii) under Alternative 1). 

Most EGUs are already reporting hourly 

SO2 and NOX emissions through CEMS 

data to EPA as part of their requirements 

under the Acid Rain program and will 

continue to be required to do so under 

the CAIR. The Acid Rain and CAIR 

programs also require recordkeeping 

and reporting for EGUs not using CEMS, 

such that hourly emissions. PM2.5, VOC, 

and CO emissions can be computed 

from SO2 and NOX emissions data. 

Therefore, emissions increases of 

regulated NSR pollutants will be 

transparent to the Agency and to the 

public. However, we request comment 

on whether additional recordkeeping 

and reporting requirements for postchange emissions should be required 

where EGUs are not using CEMS to 

measure emissions. 

B. Test for EGUs Based on Maximum 

Achievable Emissions Rates 

As we stated in our October 2005 NPR 

(70 FR 61090), we are proposing to 

allow existing EGUs to use the same 

maximum achievable hourly emissions 

test applied in the NSPS to determine 

whether a physical or operational 

change results in an emissions increase 

under the major NSR program. This test 

is based on a comparison of pre-change 

and post-change emissions rates in 

pounds per hour (lb/hr).31 We are 

proposing an additional variation on the 

NSPS test, which would compare prechange 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 PostChange 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 


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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. 

• CEMS or PEMS data recorded 

during monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

• Data from any period for which 

there is inadequate information for 

determining emissions rates, including 

information related to the limitations 

listed above. 

These proposed data limitations are 

the same as three of the four data 

limitations that we are proposing for the 

maximum achieved tests (Alternatives 1 

through 4). See Section IV.A.3. above for 

the discussion of these three data 

limitations. 

3. Recordkeeping and Reporting for 

Hourly Emissions. We are proposing the 

same recordkeeping and reporting 

approach for the maximum achievable 

test (Alternatives 5 and 6) that we 

propose for the maximum achieved 

hourly emissions test (Alternatives 1 

through 4). We describe our approach in 

Section IV.A.4 of this preamble. 

V. Proposed Regulations for Option 2: 

Hourly Emissions Increase Test 

This section contains details on the 

proposed regulatory language for Option 

2, the hourly emissions increase test. 

We are proposing that Option 2 would 

apply to all existing EGUs. As we noted 

at 70 FR 61093, however, we are also 

requesting comment on whether Option 

2 should be limited to the geographic 

area covered by CAIR, or to the 

geographic area covered by both CAIR 

and BART. We are also proposing that 

the Option 2 would apply to all 

regulated NSR pollutants. However, we 

also request comment on whether 

Option 2 should be limited to increases 

of SO2 and NOX emissions. 

In this SNPR, for Option 2 we are 

proposing to exempt EGUs from the 

procedures in the current regulations for 

determining a significant emissions 

increase and a significant net emissions 

increase. Specifically, we are proposing 

to exempt EGUs from the applicability 

procedures based on a significant 

emissions increase and significant net 

emissions increase in the current 

regulations at 40 CFR 51.165, 51.166, 

52.21, and 52.24 and in appendix S to 

40 CFR part 51. That is, we are 

proposing to amend each of these 

sections to exempt EGUs from all 

provisions for significant emissions 

increases and significant net emission 

increases. For example, under Option 2 

the provisions for determining a 

significant emissions increase and a 

significant net emissions increase in 

§ 51.166(a) (7) (iv)(a) would be amended 

to exempt EGUs as follows. 

(a) 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 defined in paragraphs 

(b)(3) and (b)(23) of this section). The project 

is not a major modification if it dos not cause 

a significant emissions increase. If the project 

causes a significant emissions increase, then 

the project is a major modification only if it 

also results in a significant net emissions 

increase. 


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We are proposing to amend all other 

provisions for significant emissions 

increase and significant net emissions 

increase in the current regulations at 40 

CFR 51.165, 51.166, 52.21, and 52.24 

and in appendix S to 40 CFR part 51 in 

an analogous manner to exempt EGUs. 

In place of the applicability 

procedures in the current regulations 

concerning significant emissions 

increase and significant net emissions 

increase, Option 2 applies an hourly 

emissions increase test to EGUs. We 

describe these as Steps 1 and 2, which 

comprise the two-step modification test 

and are the same as under Option 1, in 

Section IV of this preamble. As with 

Option 1, under Option 2, we are 

proposing to develop two new sections 

(40 CFR 51.167 and 52.37) to the major 

NSR program rules that would include 

the two-step provisions for 

modifications at EGUs. Thus, the 

amendatory language in this action 

applies to Option 2 as it relates to Steps 

1 and 2. That is, under Option 2, EGUs 

would be subject to the new two-step 

requirements for modifications. They 

would not be subject to the 

requirements in the existing regulations 

for major modifications. 

Alternatives 1–6, comprising Step 2 of 

Option 2, are the same as under Option 

1. We describe these alternatives in 

detail above in Section IV of this 

preamble. Table 10 shows Option 2, 

including Alternatives 1–6. 

TABLE 9.—MAJOR NSR APPLICABILITY FOR EXISTING EGUS UNDER OPTION 2 

Option 2 ......................................................... Step 1: Physical Change or Change in the Method of Operation. 

Step 2: Hourly Emissions Increase Test. 

• Alternative 1—Maximum achieved hourly emissions; statistical approach; input basis. 

• Alternative 2—Maximum achieved hourly emissions; statistical approach; output basis. 

• Alternative 3—Maximum achieved hourly emissions; one-in-5-year baseline; input basis. 

• Alternative 4—Maximum achieved hourly emissions; one-in-5-year baseline; output basis. 

• Alternative 5—NSPS test—maximum achievable hourly emissions; input basis. 

• Alternative 6—NSPS test—maximum achievable hourly emissions; output basis. 

Under Option 2, if a physical or 

operational change at an existing EGU is 

found to be a modification according to 

this hourly emissions test, the EGU 

would then be subject to all the 

substantive major NSR requirements of 

the existing regulations. Accordingly, 

we are also proposing to revise the 

substantive provisions in all the current 

major NSR regulations that apply to 

major modifications to apply also to 

modifications at EGUs. The amendatory 

language in this proposed rule does not 

include specific provisions for these 

changes. The substantive provisions to 

be amended would include, but not be 

limited to, the provisions in 

§ 51.166(a)(7)(i) through (iii), (b)(9), 

(b)(12), (b)(14)(ii), (b)(15), (b)(18), (i)(1) 

through (9), (j)(1) through (4), (m)(1) 

through (3), (p)(1) through (7), (r)(1) 

through (7), and (s)(1) through (4). For 

example, we are proposing to amend 

§ 51.166(a)(7)(iii) as follows. 

(iii) No new major stationary source, major 

modification, or modification at an EGU to 

which the requirements of paragraphs (j) 

through (r)(5) of this section apply shall 

begin actual construction without a permit 

that states that the major stationary source, 

major modification, or modification at an 

EGU will meet those requirements. 

We are proposing to amend all other 

provisions in the current regulations at 

40 CFR 51.165, 51.166, 52.21, and 52.24 

and in appendix S to 40 CFR part 51 in 

an analogous manner to require that the 

substantive provisions in all the current 

major NSR regulations apply to 

modifications at EGUs. 

VI. Legal Basis and Policy Rationale 

This section supplements the legal 

arguments in our October 2005 

proposal. (70 FR 70565.) In that action, 

we provided our legal basis and 

rationale for the proposed maximum 

achievable hourly emissions test and 

our alternative proposal, the maximum 

achieved hourly emissions test. We 

noted that the key statutory provisions 

provide, in relevant part, that a 

‘‘modification’’ that triggers NSR occurs 

when a physical change or change in the 

method of operation ‘‘increases the 

amount of any air pollutant emitted’’ by 

the source. Although the Court in New 

York v. EPA held that the quoted 

provision refers to increases in actual 

emissions, the Court further indicated 

that the statute was silent as to the 

method for determining whether 

increases occur. 

When a statute is silent or ambiguous 

with respect to specific issues, the 

relevant inquiry for a reviewing court is 

whether the Agency’s interpretation of 

the statutory provision is permissible. 

Chevron U.S.A., Inc. v. NRDC, Inc. 467 

U.S. 837, 865 (1984). Accordingly, we 

have broad discretion to propose a 

reasonable method by which to 

calculate emissions increases for 

purposes of NSR applicability. 

This action continues to propose both 

the maximum achievable hourly 

emissions increase test and the 

maximum achieved hourly emissions 

increase test. We set forth legal basis 

and rationale in the NPR for these two 

tests. In this SNPR, however, we 

provide additional legal and policy 

basis for the hourly emissions increase 

tests, on both an input and output basis. 

We believe that a test based on 

maximum actual hourly emissions is a 

reasonable measure of actual emissions. 

It measures actual emissions at peak, or 

close to peak, physical and operational 

capacity. For reasons described 

elsewhere, and summarized below, we 

believe this approach implements sound 

policy objectives. 

As we noted at 70 FR 61091, we 

believe that a test based on maximum 

achievable hourly emissions remains a 

test based on actual emissions. The 

reason is that, as noted in the October 

2005 proposal, as a practical matter, for 

most, if not all EGUs, the hourly rate at 

which the unit is actually able to emit 

is substantively equivalent to that unit’s 

historical maximum hourly emissions. 

That is, most, if not all EGUs will 

operate at their maximum actual 

physical and operational capacity at 

some point in a 5-year period. In 

general, highest emissions occur during 

the period of highest utilization. As a 

result, both the maximum achievable 

and maximum achieved hourly 

emissions increase tests allow an EGU 

to utilize all of its existing capacity, and 

in this aspect the hourly rate at which 

the unit is actually able to emit is 

substantively equivalent under both 

tests. 

Some commenters took issue with 

this statement, arguing that maximum 

achievable emissions could differ from 

maximum achieved emissions for a 

given EGU for any given period as a 

result of factors independent of the 

physical or operational change, 

including variability of the sulfur 

content in the coal being burned. 


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32Commenters stated that the maximum achieved 

test is difficult to comply with due to fluctuations 

in equipment and control device performance that 

are beyond the control of the EGU owner/operator. 

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.32

We thus believe that, over a period that 

is representative of normal operations, 

in general the maximum achievable and 

maximum achieved hourly emissions 

test would lead to substantially 

equivalent results. 

Each of these proposed options would 

promote the safety, reliability, and 

efficiency of EGUs. Each of the options 

would balance the economic need of 

sources to use existing operating 

capacity with the environmental benefit 

of regulating those emission increases 

related to a change, considering the 

substantial national emissions 

reductions other programs have 

achieved or will achieve from EGUs. 

The proposed regulations are consistent 

with the primary purpose of the major 

NSR program, which is to balance the 

need for environmental protection and 

economic growth. As the analyses 

included in this SNPR demonstrate, the 

proposed regulations would not have an 

undue adverse impact on local air 

quality. Furthermore, as our analyses 

demonstrate, increases in hours of 

operation at EGUs, to the extent they 

may change under a maximum hourly 

rate test, do not increase national SO2, 

NOX, PM2.5, VOC, or CO emissions. 

Consistent with earlier analyses, our 

analyses demonstrate that in a system 

where most of the national emissions 

are capped, the more hours an EGU 

operates, the more likely it is to install 

controls. 

Moreover, each of the proposed 

options also offers additional benefits 

consistent with our overall policy goals. 

Option 1 would simplify major NSR for 

changes where there is no increase in 

hourly emissions. However, many 

public commenters urged that we retain 

the significant emissions increase 

component of the emissions increase 

test. Therefore, we propose Option 1, 

our preferred Option, for the purpose of 

maintaining the current significant net 

emissions increase component of the 

emissions increase test. 

Option 2 with the proposed maximum 

hourly tests would simplify major NSR 

by reducing applicability 

determinations complexity. Option 2 

with the proposed maximum hourly 

achievable test provides more simplicity 

by conforming major NSR applicability 

determinations to NSPS applicability 

determinations. We also note that 

Option 2 (both achievable and achieved 

alternatives) eliminates the burden of 

projecting future emissions and 

distinguishing between emissions 

increases caused by the change from 

those due solely to demand growth, 

because any increase in the emissions 

under the maximum hourly achievable 

emissions test would logically be 

attributed to the change. In addition, 

Option 2 reduces recordkeeping and 

reporting burdens on sources because 

compliance will no longer rely on 

synthesizing emissions data into rolling 

average emissions. Option 2 would also 

reduce the reviewing authorities’

compliance and enforcement burden. 

Consistent with our policy goal of 

encouraging efficient use of existing 

energy capacity, we are continuing to 

propose an output-based format for the 

hourly emissions increase tests. An 

output-based standard establishes 

emission limits in a format that 

incorporates the effects of unit 

efficiency by relating emissions to the 

amount of useful energy generated, not 

the amount of fuel burned. By relating 

emission limitations to the productive 

output of the process, output-based 

emission limits encourage energy 

efficiency because any increase in 

overall energy efficiency results in a 

lower emission rate. Allowing energy 

efficiency as a pollution control 

measure provides regulated sources 

with an additional compliance option 

that can lead to reduced compliance 

costs as well as lower emissions. The 

use of more efficient technologies 

reduces fossil fuel use and leads to 

multi-media reductions in 

environmental impacts both on-site and 

off-site. 

Option 2 does not include steps for 

determining whether significant net 

emissions increases have occurred. We 

recognize that the D.C. Circuit, in the 

seminal case, Alabama Power v. EPA, 

636 F.2d 323 (D.C. Cir. 1980), which 

was handed down before Chevron, held 

that failure to interpret ‘‘increases’’ to 

allow netting would be ‘‘unreasonable 

and contrary to the expressed purposes 

of the PSD provisions. * * * ’’ Id. at 

401. As we noted at 70 FR 61093, it is 

important to place this ruling in the 

context of the rules before the Court at 

that time. Our 1978 regulations required 

a source-wide accumulation of 

emissions increases without providing 

for an ability to offset these accumulated 

increases with any source-wide 

decreases. In finding that we must apply 

a bubble approach, the Court held that 

we could not require sources to 

accumulate increases without also 

accumulating decreases. It is unclear 

whether the Court would have reached 

the same conclusion if the emissions 

test before the Court only considered the 

increases from the project under review 

and not source-wide increases from 

multiple projects. We request comment 

on our observations related to the 

Alabama Power Court’s decision related 

to netting and whether a major NSR 

program without netting can be 

supported under the Act. 

With respect to the significance 

levels, which, like netting, are not 

included under Option 2, we recognize 

that Alabama Power also upheld 

significance levels as a ‘‘permissible 

* * * exercise of agency power, 

inherent in most statutory schemes, to 

overlook circumstances that in context 

may fairly be considered de minimis.’’

Id. At 360. It is clear, however, that the 

Court considered the establishment of 

significance levels as discretionary. We 

believe that significance levels are not 

important to include in the rules 

proposed in Option 2 because under 

those rules, relatively minor changes for 

which the significance levels might 

come into play would not increase the 

maximum hourly rate. By comparison, 

the changes that do increase the 

maximum hourly rate are likely to be 

capacity increases that should not, by 

their nature, be considered de minimis. 


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We request comment on all aspects of 

our legal and policy basis. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), this 

action is a ‘‘significant regulatory 

action.’’ The action was identified as a 

‘‘significant regulatory action’’ because 

it raises novel legal or policy issues. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under EO 12866 and 

any changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with this action. This 

analysis is contained in the Information 

Collection Request (ICR) document 

assigned EPA ICR number 1230.19. A 

copy of the analysis is available in the 

docket for this action and the analysis 

is briefly summarized in the Paperwork 

Reduction Act section. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The ICR 

document prepared by EPA has been 

assigned EPA ICR number 1230.19. 

Certain records and reports are 

necessary for the State or local agency 

(or the EPA Administrator in nondelegated areas), for example, to: (1) 

Confirm the compliance status of 

stationary sources, identify any 

stationary sources not subject to the 

standards, and identify stationary 

sources subject to the rules; and (2) 

ensure that the stationary source control 

requirements are being achieved. The 

information would be used by the EPA 

or State enforcement personnel to (1) 

identify stationary sources subject to the 

rules, (2) ensure that appropriate control 

technology is being properly applied, 

and (3) ensure that the emission control 

devices are being properly operated and 

maintained on a continuous basis. 

Based on the reported information, the 

State, local or tribal agency can decide 

which plants, records, or processes 

should be inspected. 

The proposed rule would reduce 

burden for owners and operators of 

major stationary sources. We expect the 

proposed rule would simplify 

applicability determinations, eliminate 

the burden of projecting future 

emissions and distinguishing between 

emissions increases caused by the 

change from those due solely to demand 

growth, and reduce recordkeeping and 

reporting burdens. Over the 3-year 

period covered by the ICR, we estimate 

an average annual reduction in burden 

for all industry entities that would be 

affected by the proposed rule. For the 

same reasons, we also expect the 

proposed rule to reduce burden for State 

and local authorities reviewing permits 

when fully implemented. However, 

there would be a one-time, additional 

burden for State and local agencies to 

revise their SIPs to incorporate the 

proposed changes. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purpose of 

responding to the information 

collection; adjust existing ways to 

comply with any previously applicable 

instructions and requirements; train 

personnel to respond to a collection of 

information; search existing data 

sources; complete and review the 

collection of information; and transmit 

or otherwise disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations are listed 

in 40 CFR parts 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this ICR, under 

Docket ID number EPA–HQ–OAR–

2005–1063. Submit any comments 

related to the ICR for this proposed rule 

to EPA and OMB. See ADDRESSES

section at the beginning of this notice 

for where to submit comments to EPA. 

Send comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, Northwest, Washington, DC 

20503, Attention: Desk Officer for EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after May 8, 2007, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by June 7, 2007. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of this notice on small entities, small 

entity is defined as: (1) A small business 

that is a small industrial entity as 

defined in the U.S. Small Business 

Administration (SBA) size standards. 

(See 13 CFR 121.201); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less than 50,000; or (3) a 

small organization that is any not-forprofit enterprise that is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this notice on small entities, 

I certify that this action will not have a 

significant economic impact on a 

substantial number of small entities. In 

determining whether a rule has a 

significant economic impact on a 

substantial number of small entities, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the 

proposed rule on small entities.’’ 5 

U.S.C. 603 and 604. Thus, an agency 

may certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden, or 

otherwise has a positive economic 

effect, on all of the small entities subject 

to the rule. 

We believe that these proposed rule 

changes will relieve the regulatory 

burden associated with the major NSR 

program for all EGUs, including any 

EGUs that are small businesses. This is 

because the proposed rule would 

simplify applicability determinations, 

eliminate the burden of projecting 

future emissions and distinguishing 

between emissions increases caused by 

the change from those due solely to 

demand growth, and by reducing 

recordkeeping and reporting burdens. 

As a result, the program changes 


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provided in the proposed rule are not 

expected to result in any increases in 

expenditure by any small entity. 

We have therefore concluded that this 

proposed rule would relieve regulatory 

burden for all small entities. We 

continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this rule 

would not contain a Federal mandate 

that would result in expenditures of 

$100 million or more by State, local, 

and tribal governments, in the aggregate, 

or the private sector in any 1 year. 

Although initially these changes are 

expected to result in a small increase in 

the burden imposed upon reviewing 

authorities in order for them to be 

included in the State’s SIP, these 

revisions would ultimately simplify 

applicability determinations, eliminate 

the burden of reviewing projected future 

emissions and distinguishing between 

emissions increases caused by the 

change from those due solely to demand 

growth, and reduce the burden 

associated with making compliance 

determinations. Thus, this action is not 

subject to the requirements of sections 

202 and 205 of the UMRA. 

For the same reasons stated above, we 

have determined that this notice 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. Thus, this action is 

not subject to the requirements of 

section 203 of the UMRA. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’

This proposed rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. We estimate a 

one-time burden of approximately 2,240 

hours and $83,000 for State agencies to 

revise their SIPs to include the proposed 

regulations. However, these revisions 

would ultimately simplify applicability 

determinations, eliminate the burden of 

reviewing projected future emissions 

and distinguishing between emissions 

increases caused by the change from 

those due solely to demand growth, and 

reduce the burden associated with 

making compliance determinations. 

This will in turn reduce the overall 

burden of the program. Thus, Executive 

Order 13132 does not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. There are no 

Tribal authorities currently issuing 

major NSR permits. To the extent that 

this proposed rule may apply in the 

future to any EGU that may locate on 

tribal lands, tribal officials are afforded 

the opportunity to comment on tribal 

implications in this notice. Thus, 

Executive Order 13175 does not apply 

to this rule. 

Although Executive Order 13175 does 

not apply to this proposed rule, EPA 

specifically solicits comment on this 

proposed rule from tribal officials. We 

will also consult with tribal officials, 

including officials of the Navaho Nation 

lands on which Navajo Power Plant and 

Four Corners Generating Plant are 

located, before promulgating the final 

regulations. In the spirit of Executive 

Order 13132, and consistent with EPA 

policy to promote communications 

between EPA and State and local 

government, EPA specifically solicits 

comment on this proposed rule from 

State and local governments. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

This proposed rule is not subject to 

the Executive Order because it is not 

economically significant as defined in 

Executive Order 12866, and because the 

Agency does not have reason to believe 


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the environmental health or safety risks 

addressed by this action present a 

disproportionate risk to children. We 

believe that, based on our analysis of 

electric utilities, this rule as a whole 

will result in equal environmental 

protection to that currently provided by 

the existing regulations, and do so in a 

more streamlined and effective manner. 

The public is invited to submit or 

identify peer-reviewed studies and data, 

of which the agency may not be aware, 

that assessed results of early life 

exposure to electric utilities. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ [66 FR 28355 (May 

22, 2001)] because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. In 

fact, this rule improves owner/operator 

flexibility concerning the supply, 

distribution, and use of energy. 

Specifically, the proposed rule would 

increase owner/operators’ ability to 

utilize existing capacity at EGUs. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (’’NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (for 

example, materials specifications, test 

methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. The NTTAA directs 

EPA to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This proposed rule does not involve 

technical standards. Therefore, EPA is 

not considering the use of any voluntary 

consensus standards. EPA welcomes 

comments on this aspect of the 

proposed rulemaking and, specifically, 

invites the public to identify 

potentially-applicable voluntary 

consensus standards and to explain why 

such standards should be used in this 

regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment. This proposed rule 

amendment, in conjunction with other 

existing programs, would not relax the 

control measures on sources regulated 

by the rule and therefore would not 

cause emissions increases from these 

sources. 

VIII. Statutory Authority 

The statutory authority for this action 

is provided by sections 307(d) (7) (B), 

101, 111, 114, 116, and 301 of the CAA 

as amended (42 U.S.C. 7401, 7411, 7414, 

7416, and 7601). This notice is also 

subject to section 307(d) of the CAA (42 

U.S.C. 7407(d)). 

List of Subjects 

40 CFR Part 51 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Nitrogen dioxide, 

Sulfur dioxide. 

40 CFR Part 52 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Nitrogen dioxide, 

Sulfur dioxide. 

Dated: April 25, 2007. 

Stephen L. Johnson, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 51—[AMENDED] 

1. The authority citation for part 51 

continues to read as follows: 

Authority: 23 U.S.C. 101; 42 U.S.C. 7401—

7671q. 

Subpart I—[Amended] 

2. Add § 51.167 to read as follows: 

§ 51.167 Preliminary major NSR 

applicability test for electric generating 

units (EGUs). 

(a) What is the purpose of this 

section? State Implementation Plans and 

Tribal Implementation Plans must 

include the requirements in paragraphs 

(b) through (h) of this section for 

determining (prior to or after 

construction) whether a change to an 

EGU is a modification for purposes of 

major NSR applicability. Deviations 

from these provisions will be approved 

only if the State or Tribe demonstrates 

that the submitted provisions are at least 

as stringent in all respects as the 

corresponding provisions in paragraphs 

(b) through (h) of this section. 

(b) Am I subject to this section? You 

must meet the requirements of this 

section if you own or operate an EGU 

that is located at a major stationary 

source, and you plan to make a change 

to the EGU. 

(c) What happens if a change to my 

EGU is determined to be a modification 

according to the procedures of this 

section? If the change to your EGU is a 

modification according to the 

procedures of this section, you must 

determine whether the change is a major 

modification according to the 

procedures of the major NSR program 

that applies in the area in which your 

EGU is located. That is, you must 

evaluate your modification according to 

the requirements set out in the 

applicable regulations approved 

pursuant to § 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? 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 


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changes.) If so, go on to Step 2 

(paragraph (d)(2) of this section). 

(2) Step 2. Will the physical or 

operational change to the EGU increase 

the amount of any regulated NSR 

pollutant emitted into the atmosphere 

by the source (as determined according 

to paragraph (f) of this section) or result 

in the emissions of any regulated NSR 

pollutant(s) into the atmosphere that the 

source did not previously emit? If so, 

the change is a modification. 

(e) What types of actions are not 

physical changes or changes in the 

method of operation? (Step 1) For 

purposes of this section, a physical 

change or change in the method of 

operation shall not include: 

(1) Routine maintenance, repair, and 

replacement; 

(2) Use of an alternative fuel or raw 

material by reason of an order under 

sections 2(a) and (b) of the Energy 

Supply and Environmental 

Coordination Act of 1974 (or any 

superseding legislation) or by reason of 

a natural gas curtailment plan pursuant 

to the Federal Power Act; 

(3) Use of an alternative fuel by reason 

of an order or rule under section 125 of 

the Act; 

(4) Use of an alternative fuel at a 

steam generating unit to the extent that 

the fuel is generated from municipal 

solid waste; 

(5) Use of an alternative fuel or raw 

material by a stationary source which 

the source is approved to use under any 

permit issued under 40 CFR 52.21 or 

under regulations approved pursuant to 

§ 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 pollutantby-pollutant basis; or 

(10) For purposes of evaluating 

attainment pollutants, the reactivation 

of a very clean coal-fired EGU. 

(f) How do I determine if there is an 

emissions increase? (Step 2) You must 

determine if the physical or operational 

change to your EGU increases the 

amount of any regulated NSR pollutant 

emitted to the atmosphere using the 

method in paragraph (f)(1) of this 

section, subject to the limitations in 

paragraph (f)(2) of this section. If the 

physical or operational change to your 

EGU increases the amount of any 

regulated NSR pollutant emitted into 

the atmosphere or results in the 

emission of any regulated NSR 

pollutant(s) into the atmosphere that 

your EGU did not previously emit, the 

change is a modification as defined in 

paragraph (h)(2) of this section. 

Alternative 1 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant for which you 

have hourly average CEMS or PEMS 

emissions data with corresponding fuel 

heat input data, compare the pre-change 

maximum actual hourly emissions rate 

in pounds per hour (lb/hr) to a 

projection of the post-change maximum 

actual hourly emissions rate in lb/hr, 

subject to the provisions in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) Pre-change emissions. Determine 

the pre-change maximum actual hourly 

emissions rate as follows: 

(A) Select a period of 365 consecutive 

days within the 5-year period 

immediately preceding when you begin 

actual construction of the physical or 

operational change. Compile a data set 

(for example, in a spreadsheet) with the 

hourly average CEMS or PEMS (as 

applicable) measured emissions rates 

and corresponding heat input data for 

all of the hours of operation for that 365- 

day period for the pollutant of interest. 

(B) Delete any unacceptable hourly 

data from this 365-day period in 

accordance with the data limitations in 

paragraph (f)(2) of this section. 

(C) Extract the hourly data for the 10 

percent of the remaining data set 

corresponding to the highest heat input 

rates for the selected period. This step 

may be facilitated by sorting the data set 

for the remaining operating hours from 

the lowest to the highest heat input 

rates. 

(D) Calculate the average emissions 

rate from the extracted (i.e., highest 10 

percent heat input rates) data set, using 

Equation 1: 

x n xi

i

n

= =

∑

1

1

Equation 1

Where: 

x ̄ = average emissions rate, lb/hr; 

n = number of emissions rate values; and 

xi = ith emissions rate value, lb/hr 

(E) Calculate the standard deviation of 

the data set, s, using Equation 2: 

s

X

X

n

n

i

i

i

n

i

n

=

−





 





−

=

=

∑

∑ 2 1

2

1

1 Equation 2

(F) Calculate the Upper Tolerance 

Limit, UTL, of the data set using 

Equation 3: 


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UTL x s

Z Z

Z

n

Z

Z

n p p

q

p

q

= +∗

+ ( ) − − ∗ − ( )

















∗ −



 − −

−

−

−

1 1

2 1

2

1

2 1

2

1

2 1 











− ∗ − ( )

































− 1

2 1

1

2 Z

n

q

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: 

x n xi

i

n

= =

∑

1

1

Equation 1

Where: 

x ̄ = average emissions rate, lb/MWh; 

n = number of emissions rate values; and 

xi = ith emissions rate value, lb/MWh 

(E) Calculate the standard deviation of 

the data set, s, using Equation 2: 

s

X

X

n

n

i

i

i

n

i

n

=

−





 





−

=

=

∑

∑ 2 1

2

1

1 Equation 2

(F) Calculate the Upper Tolerance 

Limit, UTL, of the data set using 

Equation 3: 

UTL x s

Z Z

Z

n

Z

Z

n p p

q

p

q

= +∗

+ ( ) − − ∗ − ( )

















∗ −



 − −

−

−

−

1 1

2 1

2

1

2 1

2

1

2 1 











− ∗ − ( )

































− 1

2 1

1

2 Z

n

q

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 for the 


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pollutant is the highest emissions rate 

(lb/hr) actually achieved by the EGU for 

1 hour at any time during the 5-year 

period immediately preceding when 

you begin actual construction of the 

physical or operational change. 

(ii) Pre-change emissions—data 

sources. You must determine the 

highest pre-change hourly emissions 

rate for each regulated NSR pollutant 

using the best data available to you. Use 

the highest available source of data in 

the following hierarchy, unless your 

reviewing authority has determined that 

a data source lower in the hierarchy will 

provide better data for your EGU: 

(A) Continuous emissions monitoring 

system (CEMS). 

(B) Approved predictive emissions 

monitoring system (PEMS). 

(C) Emission tests/emission factor 

specific to the EGU to be changed. 

(D) Material balance calculations. 

(E) Published emission factor. 

(iii) Post-change emissions—

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve in 

any 1 hour in the 5 years following the 

date the EGU resumes regular operation 

after the physical or operational change. 

An emissions increase results from the 

physical or operational change if this 

projected maximum actual hourly 

emissions rate exceeds the pre-change 

maximum actual hourly emissions rate. 

(iv) Post-change emissions—actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

hourly emissions rate actually achieved 

in the 5 years after the change exceeds 

the pre-change maximum actual hourly 

emissions rate. 

Alternative 4 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

pre-change maximum actual emissions 

rate in pounds per megawatt-hour (lb/ 

MWh) to a projection of the post-change 

maximum actual emissions rate in lb/ 

MWh, subject to the provisions in 

paragraphs (f)(1)(i) through (iv) of this 

section. For EGUs that are cogeneration 

units, emissions rates are determined 

based on gross energy output. For other 

EGUs, emissions rates are determined 

based on gross electrical output. 

(i) Pre-change emissions—general 

procedures. The pre-change maximum 

actual emissions rate for the pollutant is 

the highest emissions rate (lb/MWh) 

actually achieved by the EGU over any 

period of 1 hour during the 5-year 

period immediately preceding when 

you begin actual construction of the 

physical or operational change. 

(ii) Pre-change emissions—data 

sources. You must determine the 

highest pre-change emissions rate for 

each regulated NSR pollutant using the 

best data available to you. Use the 

highest available source of data in the 

following hierarchy, unless your 

reviewing authority has determined that 

a data source lower in the hierarchy will 

provide better data for your EGU: 

(A) Continuous emissions monitoring 

system (CEMS). 

(B) Approved predictive emissions 

monitoring system (PEMS). 

(C) Emission tests/emission factor 

specific to the EGU to be changed. 

(D) Material balance calculations. 

(E) Published emission factor. 

(iii) Post-change emissions—

preconstruction projections. For each 

regulated NSR pollutant, you must 

project the maximum emissions rate 

that your EGU will actually achieve over 

any period of 1 hour in the 5 years 

following the date the EGU resumes 

regular operation after the physical or 

operational change. An emissions 

increase results from the physical or 

operational change if this projected 

maximum actual emissions rate exceeds 

the pre-change maximum actual 

emissions rate. 

(iv) Post-change emissions—actually 

achieved. Regardless of any 

preconstruction projections, an 

emissions increase has occurred if the 

emissions rate actually achieved over 

any period of 1 hour in the 5 years after 

the change exceeds the pre-change 

maximum actual emissions rate. 

Alternative 5 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

maximum achievable hourly emissions 

rate before the physical or operational 

change to the maximum achievable 

hourly emissions rate after the change. 

Determine these maximum achievable 

hourly emissions rates according to 

§ 60.14(b) of this chapter. No physical 

change, or change in the method of 

operation, at an existing EGU shall be 

treated as a modification for the 

purposes of this section provided that 

such change does not increase the 

maximum hourly emissions of any 

regulated NSR pollutant above the 

maximum hourly emissions achievable 

at that unit during the 5 years prior to 

the change. 

Alternative 6 for paragraph (f)(1): 

(1) Emissions increase test. For each 

regulated NSR pollutant, compare the 

maximum achievable emissions rate in 

pounds per megawatt-hour (lb/MWh) 

before the physical or operational 

change to the maximum achievable 

emissions rate in lb/MWh after the 

change. Determine these maximum 

achievable emissions rates according to 

§ 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 postchange maximum emissions rates under 

paragraph (f)(1) of this section, the 

following limitations apply to the types 

of data that you may use: 

(i) Data limitations for Alternatives 1–

4. 

(A) You must not use emissions rate 

data associated with startups, 

shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use emissions rate 

data from periods of noncompliance 

when your EGU was operating above an 

emission limitation that was legally 

enforceable at the time the data were 

collected. 

(D) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(i)(A) 

through (C) of this section. 

(ii) Data limitations for Alternatives 5 

and 6. 

(A) You must not use emissions rate 

data associated with startups, 


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shutdowns, or malfunctions of your 

EGU, as defined by applicable 

regulation(s) or permit term(s), or 

malfunctions of an associated air 

pollution control device. A malfunction 

means any sudden, infrequent, and not 

reasonably preventable failure of the 

EGU or the air pollution control 

equipment to operate in a normal or 

usual manner. 

(B) You must not use continuous 

emissions monitoring system (CEMS) or 

predictive emissions monitoring system 

(PEMS) data recorded during 

monitoring system out-of-control 

periods. Out-of-control periods include 

those during which the monitoring 

system fails to meet quality assurance 

criteria (for example, periods of system 

breakdown, repair, calibration checks, 

or zero and span adjustments) 

established by regulation, by permit, or 

in an approved quality assurance plan. 

(C) You must not use data from any 

period for which the information is 

inadequate for determining emissions 

rates, including information related to 

the limitations in paragraphs (f)(2)(ii)(A) 

and (B) of this section. 

(g) What are my requirements for 

recordkeeping? You must maintain a file 

of all information related to 

determinations that you make under 

this section of whether a change to an 

EGU is a modification, subject to the 

following provisions: 

(1) The file must include, but is not 

limited to, the following information 

recorded in permanent form suitable for 

inspection: 

(i) Continuous monitoring system, 

monitoring device, and performance 

testing measurements; 

(ii) All continuous monitoring system 

performance evaluations; 

(iii) All continuous monitoring system 

or monitoring device calibration checks; 

(iv) All adjustments and maintenance 

performed on these systems or devices; 

and 

(v) All other information relevant to 

any determination made under this 

section of whether a change to an EGU 

is a modification. 

(2) You must retain the file until the 

later of: 

(i) The date 5 years following the date 

the EGU resumes regular operation after 

the physical or operational change; and 

(ii) The date 5 years following the 

date of such measurements, 

maintenance, reports, and records. 

(h) What definitions apply under this 

section? The definitions in paragraphs 

(h)(1) and (2) of this section apply. 

Except as specifically provided in this 

paragraph (h), terms used in this section 

have the meaning accorded them under 

§ 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. 

[FR Doc. E7–8263 Filed 5–7–07; 8:45 am] 

BILLING CODE 6560–50–P 


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