p.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

270) IV-C-16 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:51:04 AM Sheet 270 of 276 
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HQ*GflQPS.J 

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TEL: 202-252-0451 Mar 13,92 5:02 No.001 P-02 

Note 

To: Howard Gruenspect 

Department of Energy 

From: Tom Kiernan 

E.P.A. 

Attached is a new draft of the WEPCO rule. We have made 

changes to reflect our discussions on March 10, 1992, including 

the following: 

o There is no change to*"air quality related values" for 

"visibility limitations" in the modeling requirement. 

Please note: EPA's Office of General Counsel continues to 

have strong concerns regarding the legality of referencing 

only visibility. We are still at a loss on the legal 

rationale and have not prepared a response to the DOI 

comment suggesting the change. 

o We have retained the five year tracking provision but have 

accommodated your request that sources be allowed to satisfy 

this requirement through utilization (rather than emissions) 

data. We have limited this alternative to situations where 

the emissions factors do not increase as a result of the 

physical or operational change. (If the unit's emissions 

rate increases, utilization could remain the same or even 

decrease yet emissions could still increase.) Other 

suggestions from you would be appreciated. 

o we have added the requested language regarding efficiency 

changes being treated the same as any other physical or 

operational change. 

o We have added a reference to the use of source categories 

for determining what constitutes "routine" and have noted 

our plan to issue guidance on the subject by early summer. 

Beyond these specific changes, we have generally revised the 

draft final rule and preamble submitted for interagency review on 

January 22, to follow the rule and preamble to the proposed rule 

(except for deletion of the NOx BACT presumption). However, many 

of the comments discussed raise issues that were not discussed in 

the proposal and our responses could not be drawn from the prior 

language. 
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76560-50 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Parts 51, 52, and 60 

REQUIREMENTS FOR PREPARATION, 

ADOPTION, AND SUBMITTAL OF IMPLEMENTATION 

PLANS; APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS; 

STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final Rule. 

SUMMARY: On June 14, 1991, EPA proposed amendments to its 

regulations governing applicability of the new source review 

(NSR) requirements of title I of the Clean Air Act (CAA) to 

physical or operational changes at electric utility 

generating units.—These proposed amendments clarified that 

certain utility pollution control projects (including fuel 

switches from a more polluting fuel to a less polluting fuel 

such as natural gas) should not be subject to NSR 

requirements. These proposed amendments also clarified the 

applicability of existing new source regulations to 

modifications in light of two recent Federal appellate court 

decisions: Wisconsin Electric Power Company v. Reilly 

(WEPCO), 893 F.2d 901 (7th Cir. 1990), and Puerto Rican 

Cement Company v. EPA. 889 F.2d 272 (1st Cir. 1989). Today 

EPA is taking final action on these changes. The 

regulations promulgated today will encourage pollution 
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control projects (including fuel switches to natural gas), 

clarify the scope of the two appellate decisions and, in 

general, assure that utilities can undertake pollution 

control projects required by the acid rain provisions of 

title IV of the CAA and other modifications with certainty 

as to the applicability of the various title I new source 

requirements. 

Specifically, today's amendments recognize a broad NSR 

exclusion for utility pollution control projects including 

fuel switches to less polluting fuels. These projects will 

not trigger NSR unless they render the unit less 

environmentally beneficial or cause or contribute to a 

violation of a national ambient air quality standard, PSD 

increment or visibility limitation. In addition, the rules 

implement an "actual-to-future-actual" methodology for 

determining whether certain other physical or operational 

changes at utilities are subject to NSR under either 

prevention of significant deterioration (PSD) or 

nonattainment provisions of Parts C and D, respectively, of 

title I the Act. In conjunction with the proposed 

methodology change, EPA also proposed to allow utilities to 

use as their pre-change baseline any two-year period within 

the last five years. 

Today's action also implements §§ 409 and 415 of title 

IV of the Clean Air Act Amendments of 1990 (1990 Amendments) 

which created special NSPS treatment for certain repowering 
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projects and a limited NSR exemption for temporary and 

permanent clean coal technology (CCT) projects and for 

certain "very clean" units. 

Finally, the regulatory changes promulgated today 

modify the provisions of the title I NSPS program to provide 

that a utility may use for its prechange baseline the 

highest hourly emissions rate achievable at any time during 

the 5-year period prior to the physical or operational 

change. 

In its June 14 notice, EPA also proposed to create a 

presumption that low-NOx burners would satisfy the best 

available control technology (BACT) requirements for 

modified utility units. As discussed in today's notice, EPA 

has determined not to adopt this presumption. 

DATES: This rule takes effect on (date of publication in 

FEDERAL REGISTER). Under § 307(b)(1) of the Act, petitions 

for judicial review must be filed on or before (60 days 

after the date of publication) in the U.S. Court of Appeals 

for the D.C. Circuit. 

ADDRESSES: Material relevant to this rulemaking may be 

found in Public Docket A-90-06. This docket is located in 

U.S. EPA's Central Docket Section (LE-131), Waterside Mall, 

M-1500, 401 M Street SW, Washington, D.C. 20460. The 

docket may be inspected between 8:00 a.m. and 3:00 p.m. on 

weekdays and a reasonable fee may be charged for copying. 
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FOR FURTHER INFORMATION CONTACT: Mr. David A. Solomon at 

(919) 541-5375, New Source Review Section (MD-15), Office of 

Air Quality Planning and Standards, U.S. EPA, Research 

Triangle Park, North Carolina 27711. 

SUPPLEMENTARY INFORMATION: 

The following outline reflects the organization of today's 

notice: 

I. Introduction 

II. Discussion of Final Action on Proposal 

A. Pollution Control Projects 

1. Regulatory Changes for Pollution Control Projects 

2. Additional Modeling Requirements 

B. Representative Annual Emissions 

C. The Causation Requirement 

D. Repowering 

E. Clean Coal Technology Demonstration Projects and Very 

Clean Units 

F. Calculation of NSPS Baseline 

G. Utility BACT Presumption 

H. Limitation of Proposal to Electric Utilities 

III. Miscellaneous 

A. Executive Order (E.O.) 12291 

B. Paperwork Reduction Act 

C. Economic Impact Assessment 

D. Regulatory Flexibility Act Certification 

E. Effective Date 
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F. Federalism Implications 

I. Introduction. 

On June 14, 1991, EPA proposed to amend its regulations 

implementing various title I new source review requirements 

governing major modifications as they apply to electric 

utility generating units. Specifically, an amendment to the 

definition of "major modification" in the regulations 

implementing the NSR provisions of part C and D, 

40 CFR Parts 51.165, 51.155, 52,21 and 52.24, excludes from 

NSR coverage the addition, replacement or use at existing 

electric utility generating units of any system or device 

whose primary function is the reduction of air pollutants 

(including switching to a less polluting fuel), so long as 

the pollution control project does not render the unit less 

environmentally beneficial.1 

The EPA also proposed to amend its NSR as they apply to 

utilities to: 

(1) set forth an actual-to-future-actual methodology 

for determining whether a physical or operational change is 

subject to NSR; 

1 Unless otherwise noted, references to "NSR" refer 

to the major new and modified source preconstruction review 

requirements of both part C (PSD) and part D (nonattainment) 

of title I of the Act. Regulations pertaining to these 

parts are codified at 40 CFR 51.165, 51.166, 52.21 and 

52.24. 
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(2) provide clarification that only those increases in 

emissions that actually result from the physical change or 

change in the method of operation are considered in 

determining whether the proposed change subjects the utility 

to NSR requirements; and 

(3) implement §§ 409 and 415 of title IV of the 1990 

Amendments which create special NSPS treatment for certain 

repowering projects and a limited NSR exemption for 

temporary and permanent CCT projects, and for certain "very 

clean" units. 

Finally, EPA announced that for purposes of 

establishing the baseline for the new actual-to-future 

methodology, EPA would interpret its existing regulations to 

allow the source to select any two years out of the five 

that preceded the proposed change. The EPA also proposed to 

amend its NSPS regulations (40 CFR Part 60) to allow a 

utility to use as a unit's pre-change baseline its highest 

hourly emissions rate achievable during the 5 years prior to 

the proposed change. 

In addition to these applicability changes, EPA 

proposed to create a presumption that low NOx burners would 

constitute BACT for NOx for modified utility units. 

In taking the actions announced today, EPA has relied 

on the written comments provided to the docket in this 

matter as well as testimony provided at a public hearing on 

the proposed rule conducted by EPA on July 14, 1991. 
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The public comment period, originally scheduled to 

close on August 19, 1991, was extended until September 18, 

1991 (56 FR 40843, August 16, 1991) to receive additional 

comments. The comment period was later reopened on 

November 25, 1991 (see 56 FR 59238) for 2 weeks to receive 

comments on the information contained in the transcript of a 

congressional hearing conducted by the Subcommittee on 

Health and the Environment of the House Committee on Energy 

and Commerce on July 22, 1991, and other related 

information. In response to several requests to extend the 

comment period, the comment period was extended for an 

additional 7 days, making the final deadline for comments 

December 17, 1991. See, 56 FR 65203. 

II. Discussion of Final Action on Proposal. 

A. Pollution Control Projects. 

1. Regulatory Changes for Pollution Control Projects. 

a. Background. 

Last June, EPA proposed to amend its regulations to 

clarify that a pollution control project (including a fuel 

switch to a less polluting fuel) undertaken at an electric 

utility steam generating unit would not trigger NSR under 

either the PSD or nonattainment programs. Both the PSD and 

nonattainment NSR programs2 apply to a "modification," which 

2 For a more detailed description of the existing 

regulatory structure of the NSR and NSPS programs of 

title I, readers are directed to section II, Background, of 

the June 14, 1991 notice. (56 FR 27631, 36-37). 
1 ,' 

to 

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is defined as "any physical change in, or change in the 

method of operation of, a stationary source which increases 

the amount of any air pollutant emitted by such source or 

which results in the emission of any air pollutant not 

previously emitted. CAA § 111(a)(4), 42 U.S.C. 7411(a)(4); 

see also CAA §§ 169(2)(C) and 171( ), 42 U.S.C. . This 

P.10 

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 i 

section contemplates a two-step test for determining whether 

activities at an existing facility constitute a modification 

subject to new source requirements. In the first step, the 

reviewing authority determines whether a physical or 

operational change will occur. If so, the reviewing 

authority proceeds in the second step to determine whether 

the physical or operational change will result in an 

emission increase over baseline levels. 

EPA proposed to amend its PSD and nonattainment 

regulations as they pertain to utility pollution control 

projects by exercising its authority under the statutory 

definition of "modification" to exclude "pollution control 

projects," which include certain fuel switches, from the 

definition of physical or operational change unless they 

render the unit less environmentally beneficial. 

In the proposed regulations, a pollution control 

project was defined as a project undertaken at a utility 

unit for purposes of reducing emissions from such unit. 

Pollution control projects are limited to the installation 

of conventional or innovative emissions control equipment, 
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including, but not limited to, installation of conventional 

and advanced flue gas desulfurization, sorbent injection for 

S02 and N0X controls, electrostatic precipitators, and 

projects undertaken to accommodate switching to a less 

polluting fuel, including natural gas or coal re-burning and 

the co-firing of natural gas and other fuels for the purpose 

of controlling S02 and N0X emissions. 

The proposal also included any activity that is 

necessary to accommodate switching to a less polluting fuel. 

Changes that are intended primarily to restore original 

capacity or to improve the operational efficiency of the 

facility were not considered to be part of a pollution 

control project. The pollution control project exclusion as 

proposed did not extend to source categories other than 

electric utility steam generating units. 

b. Comments Generally Favoring the EPA Proposal. 

In general, comments from industry supported the 

proposal to exclude pollution control projects. Commenters 

supporting the provision noted that the exclusion is 

consistent with the Act and EPA's earlier determinations 

regarding such projects. Indeed, several commenters 

expressed the view that no change in EPA's rules were 

necessary. One commenter noted that Congress indicated its 

intent not to apply NSPS or NSR requirements to pollution 

control projects by adopting the NSR definition of 

"modification." 
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Another commenter pointed out that because of the 

number of projects that will shortly be spawned by the acid 

rain provisions of the CAA, if permitting were required for 

every utility operator that plans a fuel switch or the 

installation of pollution control equipment, EPA would be 

overwhelmed with applications. This could affect the 

reliability of the electric utility industry and delay 

compliance with title IV. One commenter noted that a 

utility should not be prevented from qualifying for the 

pollution control exclusion if that utility takes steps to 

restore diminished capacity of a power plant at the same 

time that the utility undertakes a pollution control project 

such as repowering. 

Several commenters supported flexibility for utilities 

on strategies for S02 control. Two commenters noted that if 

the national S02 emissions cap is maintained, plant 

modifications that may increase S02 emissions at one unit 

should not trigger NSR or NSPS requirements. Another 

commenter suggested that in light of the S02 emissions caps, 

utilities should be permitted to undertake pollution control 

projects or make nonroutine modifications, even though such 

changes increase S02 emissions, without being forced to 

install technology (such as scrubbers) to control S02. 

c. Comments Generally Opposing the EPA Proposal. 

Commenters opposed to the exclusion of pollution 

control projects from NSR provisions disputed EPA's 
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authority to create such "exemptions" and disagreed that 

Congress intended to exempt pollution control projects from 

NSR. One commenter stated that the pollution control 

project exemption is illegal and conflicts with § 182(e)(2) 

of the Act, noting that while § 182(e)(2) provides limited 

NSR relief for some pollution control projects, it is not a 

blanket exemption from NSR, because the requirement to 

achieve the lowest achievable emission rate (LAER) remains 

effective, which demonstrates congressional intent to 

prevent EPA from granting broader exclusions. 

Opponents to the exclusion for pollution control 

projects also pointed out that efforts by utilities to 

reduce one pollutant can often increase emissions of 

another. Such efforts, as well as projects that reduce 

pollution in one area but increase it in another, should not 

be exempted from NSR or PSD provisions. Several commenters 

provided examples of how installation of pollution control 

equipment or fuel switching aimed at reduction of S02 also 

had the effect of increasing emissions of N0X and PM, and 

how installation of low-NOx burners increased VOC emissions. 

Some opponents to the exclusion for pollution control 

projects said that the definition of pollution control 

project is overly broad, and that EPA lacks authority to 

apply such a broad definition. 

d. Comments Suggesting Revisions to the Proposal. 

Several commenters, both for and against the exclusion, 
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suggested specific regulatory changes to the pollution 

control exemption. For instance, numerous commenters 

requested a clarification of the environmentally beneficial 

test. In addition, the following suggestions were made with 

regard to the definition of "pollution control project": 

(1) include any upgrade of the pollution control 

efficiencies of existing devices; 

(2) include "pollution prevention" changes such as 

leak detection and repair programs and the attendant site 

changes; 

(3) clarify that the pollution control project need 

not be a permanent change; 

(4) include boiler modifications involving natural gas 

cofiring, reburn, or reburn with sorbent injection even 

though there are benefits other than pollution control; and 

(5) include impacts on other Class I area air quality 

related values as well as visibility in determining whether 

a project that would increase emissions is nevertheless 

environmentally beneficial. 

e. The EPA Analysis. 

Based on a review of the comments, EPA has determined 

to adopt a formal pollution control project exclusion for 

electric utility steam generating units. Thus EPA is today 

adopting revisions to its PSD and nonattainment regulations 

for the addition, replacement or use at an existing electric 

utility steam generating unit of any system or device whose 
P.15 

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primary function is the reduction of air pollutants 

(including the switching to a less-polluting fuel where the 

primary purpose of the switch is the reduction of air 

pollutants). Under the regulations as adopted today, a 

utility undertaking a project meeting the pollution control 

project definition will not be subject to NSR under either 

PSD or nonattainment unless the project renders the unit 

less environmentally beneficial. 

In the proposed rule, EPA did not provide any specific 

definition of the environmentally beneficial standard. 

Numerous commenters noted the lack of a specific standard 

for the environmentally beneficial test and requested that 

EPA provide a definition for this new term and guidance as 

to how it will be applied. Of course, as noted in the 

proposal (56 FR 27634), pollution control projects at 

existing stationary sources are generally not subject to NSR 

requirements for the simple reason that they do not result 

in an increase in actual emissions. In addition, as also 

noted in the proposal (56 FR 27635), EPA has determined 

that, in general, Congress did not intend that pollution 

control projects be considered the type of activity that 

should trigger NSR. 

On the other hand, several commenters pointed out that 

a project that reduces one pollutant should not be allowed 

to increase emissions of another pollutant if that increase 

will cause or exacerbate a different pollution problem. 
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More specifically, an environmental commenter suggested that 

EPA had endorsed at the Congressional hearing a view that 

increases would not be allowed in nonattainment areas absent 

"compelling showing." The proposal sought to reconcile 

these factors by indicating that the exclusion would allow 

the permitting authority to consider projects on a case-bycase basis and further indicated that projects need not 

necessarily pass a quantitative emissions increase test to 

qualify for the exclusion. 

In addition, the modeling provision (discussed in the 

following section) provides that pollution control projects 

that will result in significant net increases over levels 

attributed to the source in the last modeling analysis 

prepared for the area, will be evaluted for their impact on 

NAAQS, PSD increments, and visibility limitations.3 This 

safeguard, in addition to the permitting agency's authority 

to determine a pollution control project to be less 

environmentally beneficial, prevents any emissions increase 

3 The NSR regulations define a "major modification" 

subject to review as any physical or operational change at a 

major stationary source that would result in a "significant 

net emissions increase" in any regulated pollutant. See 

e.g., 51.166(a)(1)(v)(A). In nonattainment areas 

"significant", in reference to a net emissions increase, is 

defined as a rate of emissions that would equal or exceed a 

specified amount. For example, under the current 

regulations a rate of 40 tons per year or more is 

"significant" for S02. [Cite] 
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from adversely affecting air quality in either an attainment 

or nonattainment area. 

Several commenters challenged the need for a regulatory 

exclusion, noting that EPA had already excluded numerous 

individual pollution control projects pursuant to its 

existing regulatory authority. However, while EPA has in 

fact made case-by-case determinations excluding pollution 

control projects from NSR, it has never provided a 

comprehensive statement of its policy in this regard nor 

formally included this exclusion in its NSR regulations 

governing SIP's or its own NSR regulations. Because of the 

enormous surge in projects that utilities can be expected to 

undertake in response to the acid rain provisions, EPA 

believes that a formal rulemaking spelling out the exact 

parameters of the exclusion is necessary. 

At least one commenter cautioned EPA against requiring 

sources to submit "applications" to secure the pollution 

control project exclusion, lest sources face excessive 

paperwork burdens and lengthy delays every time they change 

their pollution control equipment. Under today's rule, and 

consistent with the other NSR applicability decisions, 

sources remain responsible in the first instance for 

determining what permitting requirements apply to their 

activities. Beyond issuing any construction or operating 

permits that may be needed, the permitting authority is not 

necessarily involved unless a source seeks a determination 
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of NSR applicability on its own or a modeling analysis is 

required. 

Several commenters requested that this exclusion be 

extended to nonroutine repairs that are undertaken by the 

utility in conjunction with the pollution control project. 

However, title IVs overall national S02 ceiling and 

emission trading program do not allow EPA to simply ignore 

the local air quality impact of S02 increases at individual 

title IV-covered facilities. The national emissions caps 

established by title IV are not designed to protect plantspecific considerations of local air quality, the focus of 

title I's NSR requirements. This argument is also refuted 

by the plain language of title IV which by its terms does 

not supersede title I. See § 403(f), (g) 4113. 

Several opponents of the exclusion point out that 

certain pollution control technologies can actually increase 

emissions of other pollutants and that the installation of a 

pollution control project may result in increased 

utilization of the unit, and thereby result in an increase 

in actual emissions. As noted above and in the proposal, 

EPA expects that most pollution control projects will 

decrease actual emissions. Moreover, even though emissions 

increases are possible in some cases, EPA is not precluded 

from creating this exclusion. The mere fact of an emissions 

increase, standing alone, does not render the exclusion 

inconsistent with the Act. For instance, EPA regulations 
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have long excluded emissions increases associated with 

routine repairs, as well as increases in the operations of a 

unit in response to fluctuations in the market. [see, e.g., 

40 CFR 52.21(b)(2)(iii)(a), (f)]. Given the modeling 

safeguard and the overall benefit to the environment of 

pollution control projects, EPA is confident that the 

creation of this exclusion is a lawful and appropriate 

exercise of its powers. 

It was also suggested that the pollution control 

project exclusion is inconsistent with § 182(e)(2) of the 

CAA. Section 182(e)(2) provides that in extreme ozone 

nonattainment areas (the Los Angeles area is the only one), 

any physical or operational change "which results in any 

increase in emissions" will be considered a modification. 

The source can avoid the offset requirements (but not the 

rest of NSR) by internally offsetting (i.e., netting) any 

increase in emissions at a ratio of at least 1.3 to 1. The 

provision also provides that the extreme area offset 

provisions (but again not the rest of NSR) do not apply to 

the installation of equipment required to comply with "the 

applicable implementation plan, permit, or this Act." 

The EPA does not agree that this nonattainment 

provision, which applies to only one area, somehow precludes 

EPA from adopting an exclusion to its general NSR rules 

regarding pollution control projects. While there may be 

some overlap (i.e., utility compliance projects undertaken 
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in the Los Angeles area that qualify under this rule as 

pollution control projects), in general the two provisions 

are quite different. Today's rule is limited to utilities 

but applies to all areas of the country, while § 182(e)(2) 

applies to all source categories but only to the Los Angeles 

area. Section 182(e)(2) also appears to apply to a broader 

category of changes. There is no evidence that Congress 

intended this limited provision to preempt EPA from adopting 

a broad pollution control project exclusion. On the other 

hand, the Clean Air Act conferees did specifically direct 

EPA to find an administrative resolution of the WEPCO 

issues. Conference Comm., Joint Explanatory Statement of 

the Committee of the Conference to Accompany S. 1630. Rep. 

101-951, 101st Cong. 2nd Sess. (1990) pp. 344-45. For these 

reasons, EPA does not believe that § 182(e) directly or 

indirectly limits EPA's authority here. 

2. Additional Modeling Requirements. 

a. Background. 

A pollution control project cannot result in an 

emissions increase that will cause or contribute to a 

violation of a national ambient air quality standard, PSD 

increment, or visibility limitation. For this reason, the 

proposal included a safeguard provision that allowed the 

reviewing authority to require a source to perform an air 

quality impact analysis (modeling) whenever (1) the 

permitting authority has reason to believe that the 
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proposed change will result in a significant net increase in 

actual emissions of any criteria pollutant over levels used 

for that source in the most recent air quality impact 

analysis, and (2) the permitting authority has reason to 

believe that such an increase would cause or contribute to a 

violation of a NAAQS, increment or visibility limitation. 

If the modeling is conducted and the permitting agency 

determines that this increase in emissions will cause or 

contribute to a violation of any ambient standard, PSD 

increment, or visibility limitation, the pollution control 

project exclusion does not apply. 

b. Comments on the EPA Proposal. 

Many commenters viewed the modeling requirement as 

ensuring that the pollution control project exclusion will 

not have an adverse impact on local air quality because 

sources must still comply with all applicable emission 

limits necessary to protect NAAQS, PSD increments, and 

visibility. 

However, several commenters expressed concern over the 

adequacy of EPA's air quality impact analysis requirement as 

a safeguard due to the methodology proposed to calculate 

actual emissions. Specifically, an environmental group 

pointed out that using increases in "representative actual 

annual emissions" as the test for determining whether a 

pollution control project results in unacceptable impacts on 

air quality can exclude real emissions increases (e.g., due 
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to demand growth), and thus fails to account for the full 

impact of the project. This commenter asserted that 

increases in "actual emissions" should be the key to use of 

the pollution control project exclusion. 

Some commenters also objected due to the fact that the 

proposal relies on State and local agencies to be aware of 

the project and request the analysis. One commenter added 

that it is unclear how a violation of the NAAQS can be 

avoided before the fact and how the permitting agency could 

require an air quality analysis if the pollution control 

project is not subject to NSR. 

Finally, a government agency questioned why the 

safeguard provision protected "visibility limitations" when 

the PSD program is designed to protect all air quality 

related values in Class I areas. 

c. The EPA Analysis. 

After careful review of the proposal and the comments, 

EPA has determined to promulgate the modeling provision as 

proposed. The EPA does not believe the objections to this 

provision to be well-founded. Although the proposal does 

not explicitly require sources to inform the permitting 

authority of pollution control projects, EPA anticipates 

that in most, if not all, circumstances involving pollution 

control projects, permitting authorities will be aware of 

the source's intentions. For instance, state permitting 

requirements may require the source to bring the project to 
P.23 

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the permitting authority or the source may wish to do so to 

secure emission reduction credits for pollutants that will 

be decreased. In addition, most projects at utilities are 

typically subject to public scrutiny in a variety of forums 

as a result of filings made with Public Utility Commissions 

and other local, state or federal agencies. Consequently, 

it is unlikely that a utility could proceed with a pollution 

control project without some type of review regarding CAA or 

other requirements. This will be especially true of 

pollution control projects undertaken for the purpose of 

compliance with title IV. 

EPA disagrees with the environmental group comment that 

it is inappropriate to hinge use of the pollution control 

project exclusion on increases in "representative actual 

annual emissions" rather than increases in "actual 

emissions." The commenter is correct that the rule as 

proposed would in certain circumstances not subject to 

review significant increases in actual emissions from a 

source that follow completion of the pollution control 

project. However, the rule is clear that this could occur 

only where the increase in question in fact does not result 

from the pollution control project, but rather from an 

independent factor such as demand growth. As discussed 

above and in the proposed rule, it is not the purpose of the 

new source review program to subject all emissions increases 

to permitting requirements, only increases that result from 
P.24 

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a nonroutine change at an existing plant. The state may 

always revise its SIP to correct NAAQS violations that it 

concludes are caused by increased utilization but do not 

result from a pollution control project at that plant.4 

[Add discussion of AQRV objection.] 

B. Representative Actual Annual Emissions. 

a. Background. 

To determine if a physical or operational change at an 

existing electric utility steam generating unit would result 

in an increase in actual emissions and thus trigger NSR as a 

"major modification," EPA proposed to allow utilities to 

compare their actual emissions before and after the physical 

or operational change.5 As proposed, the "representative 

actual annual emissions" methodology allows the utility to 

compare its pre-change actual emissions with future actual 

emissions to determine if the proposed change will result in 

an increase in emissions. The EPA's existing regulations 

defined pre-change actual emissions as "the average rate, in 

4 In part, commenters' objections to use of the 

representative actual annual emissions methodology to 

determine if the pollution control project will result in a 

significant net emissions increase is grounded in a concern 

with the reliability of its methodology. These concerns are 

addressed in the following section. 

5 A full discussion of the NSR regulatory scheme 

including the methodology for determining when a change to 

an existing emissions unit will trigger NSR may be found in 

Section II of the proposal (56 FR 27631, 36-37). This 

discussion assumes that the reader's familiarity with that 

explanation. 
P.25 

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tons per year, at which the unit actually emitted the 

pollutant during a 2-year period which precedes the 

particular date and which is representative of normal source 

operation" (see, e.g., 40 CFR 52.21). The Administrator can 

allow the use of a different time period "upon a 

determination that it is more representative of normal 

source operation." Id. The EPA proposed to retain this 

regulatory language, but to presume that any 2 consecutive 

years within the 5 years prior to the proposed change is 

representative of normal source operations for a utility. 

Source owners or operators desiring to use a baseline period 

prior to the last 5 years may seek the reviewing authority's 

specific determination that such period is more 

representative of normal operations. 

Under the proposal, the future-actual projection is the 

product of: 

(1) the hourly emissions rate, which is based on the 

unit's physical and operational capabilities following the 

change and federally-enforceable operational restrictions 

that would affect the hourly emissions rate following this 

change; and 

(2) projected capacity utilization, which is based on 

(a) the unit's historical annual utilization, and (b) all 

available information regarding the unit's likely postchange capacity utilization. 
P.26 

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In projecting future utilization and emissions factors, 

the permitting authority may consider the company's 

historical operational data, its own representations, filing 

with Federal, State or local regulatory authorities, and 

compliance plans developed under title IV of the 1990 

Amendments. 

The projection of post-change capacity utilization for 

applicability purposes was to be based on a projection of 

utilization for a period after the physical or operational 

change. The EPA proposed to allow sources to base the 

projection of utilization on the 2 years immediately after 

the change, or a different consecutive 2-year period within 

the 10 years after the change, where the reviewing authority 

determines that such period is more representative of normal 

source operations. 

This methodology applies to all physical or operational 

changes at an existing electric utility generating unit, 

other than the addition of a new unit or the replacement of 

an existing unit. Under the proposed rules,, a unit is 

considered to be replaced if it would constitute a 

"reconstructed" until within the meaning of 40 CFR 60.15. 

b. Comments Generally Favoring the EPA Proposal. 

Several commenters favored the expansion of the time 

period for establishing the pre-change emissions baseline. 

Suggestions included: 
P.27 

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(1) allow the use of any 2 consecutive years within 

the last 5 years of operation to allow for a more 

representative baseline for units that have been shut down; 

(2) allow utilities to request to use periods of 

representative high utilization outside the 5 year time 

period; 

(3) add the "any 2 out of the prior 5 year baseline 

period" discussed in the preamble to 40 CFR parts 51, 52, 

and 60; 

(4) allow utilities to use the maximum utilization in 

any 1 year within at least the last 10 years, since 10 years 

is a more relevant capacity investment planning horizon than 

5 years; 

(5) clarify that the source will be able to select the 

relevant 2-year period with approval of the reviewing 

authority required only when the pre-change baseline is 

outside of the 5-year period proceeding the change; 

(6) expand the baseline calculation period from 

5 years to 10 years to be consistent with the after-change 

calculation period and to address a more representative time 

period; 

(7) allow the use of any 2 years (rather than 

consecutive years) due to long reserve shutdowns and because 

maintenance planning requires that utility boilers be 

operated in "abnormal" conditions for long durations; and 
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(8) require sources to back up the choice of which 

2 years to use with a short-term standard using an hourly 

rate, use the same 2-year period for determining the short 

term and annual rates, and codify the 2 years used for the 

limit. 

Several comments that recommended expanding the 

proposal to include industrial sources in the NSR exemption 

also noted that a "5-year window" is not satisfactory for 

industrial sources which do not always have representative 

periods of emissions immediately before a physical change. 

One industrial commenter suggested the use of any 2-year 

period be allowed. 

Commenters in favor of the future actual emissions 

calculation method noted that it will alleviate uncertainty 

for nonroutine repair, replacement, and maintenance projects 

while still protecting local air quality; the future-actual 

method reduces speculation and allows more reliance on 

factual data; and the actual-to-future-actual emissions 

comparison is more appropriate to look at the operating 

history and projected capacity of an existing unit to 

determine whether a change will increase emissions. One 

commenter stated that the actual-to-potential method 

discouraged environmentally beneficial modifications, but 

suggested that the most appropriate policy would be to adopt 

a potential-to-potential test. 
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One commenter noted that the actual-to-future-actual 

test would end what was felt to be the "unlawful and unfair 

practice" of using the NSR program to "arbitrarily reduce 

allowable hours of operation or rates of production for 

existing sources." Countering the argument that the actualto-future-actual test could create public health problems, 

two commenters noted that utilities must comply with all 

Federal, State and local air quality restrictions regardless 

of the tests used. Also supporting the actual-to-futureactual test, one commenter pointed out that source owners 

will be motivated by incentives in the Act, proposed 

regulations, and market forces to finance and engineer 

economic and efficient physical and operational changes at 

plants so as to achieve excellent environmental control. 

One commenter favored calculating future emissions over a 

representative 2-year period within a 5-year period after 

the change. 

c. Comments Generally Opposing the EPA Proposal. 

One opponent of the proposed methods stated that 

emission increases at power plants would now be fostered 

since the proposal will allow utilities to choose their own 

definitions for when emissions have increased. 

In general, opponents of the proposal regarding the 

pre-change baseline noted that the change is arbitrary and 

capricious and that there is no analysis in the docket 

suggesting that any 2-year period is more representative of 
P.30 

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pre-change maximum emissions. Commenters noted that under 

the proposal, sources could select the years in which they 

had the highest emissions in an attempt to minimize the 

appearance of an increase and escape NSR. One commenter 

noted that the change in baseline calculation methodology 

would give utilities such flexibility in refurbishing, 

repowering, and life extension projects as to bias 

competitive power markets towards the continued use of 

existing old units rather than the construction of new ones. 

Opponents to the use of future actual emissions stated 

that there is no reasoned basis for an unenforceable 

representative actual emissions approach, and application of 

this test to electric utilities is not consistent with EPA's 

established policy toward other sources. Other comments 

contended that the future actual test ignores all past 

precedents and that, in determining whether a modification 

triggers NSR, EPA should compare actual emissions for the 

current unit to potential emissions from the modified 

source; the future-actual test does not guard against 

artificially low estimates made by sources to escape NSR, 

nor does it protect against substantial increases made 

immediately after the 2-year period; and the future-actual 

emissions calculation procedure amounts to self-regulation 

and is easily subject to abuse. 

State and local air agencies generally opposed the 

future actual method of calculating post-change emissions. 
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One noted that the appropriate emission increase test should 

be determined on a case-by-case basis. One agency noted 

that the actual-to-future actual approach results in a 

significant relaxation of title I NSR requirements and would 

allow utilities to upgrade equipment which may have lost 

significant generating capacity without the equipment being 

subject to NSR, hampering local air quality attainment and 

maintenance efforts. There were several comments that 

future emissions cannot be reasonably determined solely on 

past operating history. One State noted that direction is 

needed on how actual versus potential emissions are 

estimated. 

A few commenters addressed the 2-year period after the 

proposed change which is the basis for calculating the 

future-actual emissions. Opponents of the future actual 

concept stated that use of such a provision would result in 

unrealistically low future emissions projections and shield 

a company against efforts to enforce NSR requirements at a 

source that increased emissions 3 years after making 

physical changes. 

An environmental group and several State agencies noted 

that the projected post-change emissions should become an 

enforceable permit condition in order to commit a source to 

limit its future emissions to a specific amount and to 

provide assurance that these projections are reasonable 

estimates of expected emissions. If a source will not 
P.32 

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accept such a permit condition, then the source should have 

to use potential post-change emissions. 

d. Comments Suggesting Revisions to the Proposal. 

Three commenters suggested a more flexible test for 

ascertaining S02 increases for determining applicability of 

NSR and NSPS requirements, namely a measure of pollution per 

unit of electrical output. 

Commenters made the following specific suggestions for 

changes surrounding the future actual calculation method: 

(1) develop guidelines to assist States in making 

like-kind determinations; 

(2) require like-kind replacements to use the 

representative actual annual emissions for calculation of 

actual emissions; 

(3) define "like-kind replacement" to include complete 

replacement of an existing emissions unit; 

(4) define "routine repair and replacement;" 

(5) apply the actual-to-actual test to like-kind 

replacement of an entire emitting unit; 

(6) allow new units or greenfield plants to rely on 

future actual emissions if they can reliably project future 

emissions; and 

(7) consider an alternative way to make the NSR 

accounting system consistent, such as basing it on past 

allowable to future allowable emissions. 

Other suggestions included the following: 
P.33 

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(1) provide guidance on routine repair and replacement 

and maintenance activities to include placing units on cold 

reserve and bringing them back on line, and 

(2) use a 2-year period other than immediately after 

the change only when the EPA cannot clearly demonstrate that 

the 2-year period immediately following the change is not 

representative. 

e. The EPA Analysis. 

The EPA has decided to promulgate the proposed 

"representative actual annual emissions" methodology for 

calculating emissions changes at utility steam generating 

units. After a thorough review of the comments, EPA 

concludes that the comparison of "actual emissions before" 

to a projection of "actual emissions after" a physical or 

operational change at an existing utility steam generating 

unit is workable and, with the added safeguard discussed 

below, is the most suitable method for evaluating emissions 

changes at such sources. The EPA will also retain the 

provisions excluding construction of new or replacement 

units from the "representative actual annual emissions" 

methodology. 

Many commenters questioned EPA's proposed presumption 

that sources may use, as the baseline, emissions from any 2 

consecutive years within the 5 years prior to the proposed 

change without regard to normal source operations. As 

discussed in the proposal, this presumption is consistent 
-32-

with EPA's decision in WEPCO and the 5-year period for 

"contemporaneous" emissions increases and decreases in 

40 CFR 52.21(b)(3)(i)(b).6 

Moreover, EPA is not reading "normal source operations" 

out of the regulation as changed. Rather, the presumption 

recognizes the nature of utility operations without 

compromising the existing regulatory language which requires 

that the pre-change 2-year period used in defining baseline 

emissions be representative of "normal" operations. For 

example, as a system a utility's "normal" operations means 

directly responding to a demand for electricity. A cold 

winter or hot summer will result in high levels of "normal" 

operations while a relatively mild year will produce lower 

"normal" operations. By presumably allowing a utility to 

use any 2 consecutive years within the past 5, the rule 

better takes into consideration that electricity demand and 

resultant utility operations fluctuate in response to 

various factors such as annual variability in climatic or 

economic conditions that affect demand, or changes at other 

plants in the utility system that affect the dispatch of a 

particular plant. By expanding a baseline for a utility to 

any consecutive 2 in the last 5 years, these types of 

fluctuations in operations can be more realistically 

6 This presumption does not apply to past 

modifications at an emissions unit for the purpose of 

determining contemporaneous emission changes at a source and 

cannot be used to extend the 5-year period specified in that 

provision [see 40 CFR 52.21(b)(3)(i)(b)]. 
P.35 

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considered, with the result being a presumptive baseline 

more closely representative of normal source operation. 

The EPA disagrees with comments seeking to allow the 

use of any 2 consecutive years within the last 5 years of a 

unit's "operation" rather within than the 5 years directly 

preceding the proposed change. A shifting of the 5-year 

period would be difficult to harmonize with definitions of 

contemporaneous contained in the regulations [see, e.g., 

40 CFR § 52.21(b)(3)(iii)]. This type of open-ended 

provision would even credit a unit which has been 

inoperative for 20 or 30 years or longer with a high level 

of emissions. The EPA notes, however, that as has always 

been the case under the prior regulations, any source owner 

or operator may request a determination that another 

baseline period is more representative of the unit's 

"normal" operations. 

Several commenters opposing today's regulatory changes 

charged that without appropriate assurances utilities could 

deliberately underestimate future operations (and thus 

emissions) for the purpose of avoiding review or that even 

where a forthright estimate is made, the forecast may prove 

inaccurate. EPA is concerned that without appropriate 

safeguards increases in future actual emissions that in fact 

resulted from the physical or operational change could go 

unnoticed and unreviewed. For this reason, EPA has added 

the safeguard explained below. 
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The EPA does not, however, agree with comments that 

post-change emissions estimates must always be made into 

permanent federally-enforceable permit conditions. To do so 

would permanently restrict a utility's legally allowable 

emission limits to its pre-change actual emissions level 

unless it subsequently underwent NSR, and would fail to 

account for the very real possibility that emissions might 

increase over baseline levels in the future for reasons 

unrelated to the physical or operational change in question. 

As discussed more fully in the following section, NSR 

applies only where the emissions increase is caused by the 

change. Thus the issue should be viewed more as one of 

tracking and monitoring post-change emissions levels at the 

modified unit to confirm that baseline emission levels are 

not exceeded as a result of the change. 

To guard against the possibility that significant 

increases in actual emissions attributable to the change may 

occur under this methodology, EPA is clarifying in the final 

regulations that any utility which utilizes the 

"representative actual annual emissions" methodology to 

determine that it is not subject to NSR must submit for 

5 years after the change sufficient records to determine if 

the change resulted in an increase in representative actual 

annual emissions. Utilities may use continuous emissions 

monitoring data, operational levels, fuel usage data, source 

test results or any other readily available data of 
P.37 

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sufficient accuracy for the purpose of documenting a unit's 

post-change actual annual emissions. Where the change does 

not increase the unit's emissions factor, i.e., the amount 

of pollution emitted by a source after control per unit of 

fuel combusted or material processed (such as pounds of 

sulfur dioxide emitted per ton of coal burned), the utility 

may submit utilization data, rather than emissions data, as 

a method of tracking post-change emissions. 

If this data suggests that the utility has increased 

annual emissions over baseline levels, the permitting 

authority should inquire whether the increase resulted from 

the physical or operational change. The utility may 

demonstrate that any increase was caused by an independent 

factor, such as demand growth. 

Such records are to be submitted to the permitting 

agency on an annual basis for a period of 5 years from the 

date normal operation begins at the modified source. A 

longer period, not to exceed 10 years, may be required by 

the permitting agency where it has determined that no period 

within the first five years following the change is 

representative of normal source operations. 

Since it is expected that utilities will submit the 

same data normally used to report emissions or operational 

levels under existing Federal, State or local air pollution 

control agency requirements, EPA does not envision 

documentation of post-change actual annual emissions as 
-36-

requiring any additional data collection burden on the part 

of a utility. 

The purpose of this provision is to provide a 

reasonable means of determining whether a significant 

increase in actual annual emissions resulting from a 

proposed change at an existing utility occurs within the 5 

years following the change. Thus the intent is to confirm 

the utility's initial projections rather than annually 

revisiting the issue of NSR applicability. If, however, the 

reviewing authority determines that the source's emissions 

have in fact increased significantly over baseline levels as 

a result of the change, the source would become subject to 

new source review requirements at that time. The EPA has 

adopted this approach and the time period because it 

believes that, in most cases, any emissions increase 

resulting from a physical or operational change at a utility 

unit would occur within the first 5 years of normal 

operation of the unit after the change. Thus, EPA will 

presume that any increase in emissions levels more than 

5 years after the change has occurred is not related to the 

physical or operational change. 

In response to comments regarding "like-kind" 

replacements, EPA notes that today's regulations recognize 

no distinction between "like-kind" replacements and other 

nonroutine physical or operational changes at a utility 

steam generating unit. The "actual-to-future-actual" 
P.39 

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methodology promulgated today for calculating emissions 

changes applies to all types of changes at utility units, 

including the replacement of "like-kind" components at an 

existing unit. However, the "like-kind" replacement of a 

whole unit is for all practical purposes a replacement unit 

and, therefore, is treated as a new unit. 

Although several commenters suggested that EPA should 

expand the representative actual emissions test to new and 

reconstructed units, EPA has decided not to do so. Since 

there is no relevant operating history for new or 

reconstructed units, it would not be possible to accurately 

project operations or emissions for these units. 

Consequently, the EPA has left unchanged the regulations 

which require that for any unit which has not begun normal 

operations, actual emissions are considered equal to the 

unit's potential-to-emit. 

A few commenters requested that EPA define or provide 

guidance on "routine repair, replacement and maintenance" 

activities. The June 14 proposal did not deal with this 

aspect of the regulations, nor do the regulatory changes 

promulgated today. However, EPA plans to issue guidance on 

this subject as part of a NSR regulatory update package 

which EPA presently intends to propose by early summer. In 

the meantime, EPA is today clarifying that the determination 

of whether a physical or operational change is "routine" 

under the NSR regulations, while made on a case-by-case 
P.40 

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basis, should include consideration of whether similar 

projects have been undertaken by sources within the relevant 

industrial category. 

C. The Causation Requirement. 

a. Background. 

The statutory definition of "modification" is limited 

to a physical or operational change "which increase the 

amount of any air pollutant". See CAA(lll)(a)(4), 

42 U.S.C. 7411(a)(4). The EPA's NSR regulations similarly 

limit the definition of major modification to a change "that 

would result in" an emissions increase. See, e.g., 40 CFR 

52.21(b)(2)(i). In keeping with these provisions, the 

proposed rule makes clear that where increased operations 

are in response to independent factors, such as system-wide 

demand growth, which would have occurred and affected the 

unit's operation even in the absence of the physical or 

operational changes, such increases do not "result from" the 

change and shall be excluded from the projection of future 

actual emissions. However, during the representative 

baseline period, a utility plant must have been able to 

accommodate the projected demand growth physically and 

legally even absent the particular change. Increased 

operations that could not have physically and legally been 

accommodated but for the proposed physical or operational 

change should be considered to result from the change. 

b. Comments Generally Favoring the EPA Proposal. 
P.41 

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Several utility representatives supported the proposed 

demand growth exclusion and the causation requirement. Many 

commenters requested clarification of certain points or 

expansion of certain provisions. One commenter noted that 

there should be a specific exclusion for emissions increases 

at a generating station resulting from generation shifts and 

decreased plant efficiencies caused by operation of 

pollution control systems. Another noted that the 

discussion of the criteria for recognizing "factors 

unrelated to the physical or operational change" should be 

improved upon because the proposed requirements that a 

facility must have been physically able to accommodate the 

projected growth during a "representative baseline period" 

could have a negative impact in utility capacity planning 

and investment decisions, depending upon how such a period 

is determined. 

One commenter noted that EPA should specifically 

recognize an exception for units which have been inactive, 

because a unit should not have to include all of its 

emissions due to demand growth merely because it was in need 

of repair or maintenance while inactive. Commenters asked 

that EPA better define "independent factors" in the context 

of the demand growth exclusion. Lastly, one commenter 

stated that the final rule should reconcile the "demand 

growth exclusion" with the existing "hours of operation/rate 

of production" exclusion by confirming that increases 
P.42 

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attributable to system-wide demand growth are already 

excluded under the already-existing exclusion and, 

therefore, the "demand growth exclusion" only applies where 

there is a federally-enforceable permit term limiting hours 

of operation or production rate. 

c. Comments Generally Opposing the EPA Proposal. 

Opponents of the exclusion of emissions attributable to 

demand growth contended that there is no rational basis for 

ignoring such emissions. When increased capacity or 

utilization is the immediate goal of a project and an 

increase in emissions occur, the project must be subject to 

NSR regardless of the underlying reasons for the increased 

capacity or utilization and corresponding emission increase. 

Contrary to the letter and purpose of the statute, the 

demand growth exclusion could result in major increases in 

actual emission going unreviewed and unregulated, would 

create serious local pollution problems, and would 

discriminate against companies that were successful in 

implementing energy efficiency programs. One local agency 

pointed out that it is virtually impossible to determine 

with any degree of certainty what portion of a unit's 

emissions are attributable to an increase in projected 

capacity utilization. 

In addition, commenters noted that the exemption will 

have an adverse effect on local agencies' ability to control 

emissions and that the time of construction of a 
P.43 

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modification is the most efficient and effective time to 

address such emissions. One commenter stated that the 

exclusion for demand growth may further bias competitive 

power markets toward existing units, and that EPA failed to 

consider the impact of the causation requirement on utility 

operations, emissions or competition in power markets. 

d. The EPA Analysis. 

After careful consideration of the comments received 

and further analysis of the issues involved, EPA has decided 

to promulgate the causation provision as proposed. 

Commenters argued that any post-change emissions 

increase, regardless of its origin, should subject a source 

to NSR. However, these arguments ignore the relevant 

statutory and regulatory modification provisions. No 

commenters challenging the provision have suggested that the 

statute and implementing regulations do not contain a 

causation provision. Rather, they argue that in the 

proposed rule EPA has misconstrued this requirement. 

Congress intended the NSR programs to apply "where 

industrial changes might increase pollution in an area." 

Alabama Power Co. v. Costle. 636 F.2d 323, 401 (D.C. Cir. 

1979); see also § 160(5) of the Act (a purpose of the PSD 

program is "to assure that any decision to permit increased 

air pollution in an area .. . is made only after careful 

evaluation of all the consequences of such a decision and 

after adequate procedural opportunities for informed public 
P.44 

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participation"). Based on these and other directives, EPA 

has in the past simply presumed that any significant 

emissions increase that followed a physical or operational 

change "resulted from" that change. 

In conjunction with developing the representative 

actual annual emissions methodology, EPA recognized that the 

analysis of the causation requirement may disclose that an 

emissions increase that follows a nonroutine physical or 

operational change is merely coincidental, and in fact 

results from independent factors such as demand growth. It 

is important to emphasize, however, that this does not 

amount to a per se exclusion of demand growth from the 

emissions increase calculation. Rather, demand growth can 

only be excluded to the extent it — and not the physical or 

operational change — is the cause of the emissions 

increase. The EPA believes that this is a reasonable 

interpretation of the statutory provision in question, and 

rejects the views of commenters who asserted that the Agency 

is compelled to retain its previous view of the statutory 

scheme. 

Consequently, where projected increased operations are 

in response to an independent factor, such as demand growth, 

which would have occurred and affected the unit's operations 

even in the absence of the physical or operational change, 

the increased operations cannot be said to result from the 

change and therefore may be excluded from the projection of 
P.45 

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the unit's future actual emissions. Conversely, where the 

increase would not have occurred but for the physical or 

operational change, that change will be deemed to have 

resulted in the increase. 

The EPA did receive numerous comments regarding the 

difficulty of applying this new interpretation. However, 

EPA believes it is possible to discern between emissions 

increases that are related to a physical or operational 

change from those that are not. This issue is a factdependent determination that must be resolved on a case-bycase basis. However, EPA has identified certain principles 

which should assist permitting authorities in making their 

determination. For example, as discussed in the proposal, 

EPA considers emissions increases due to increased 

operations that could not be physically or legally 

accommodated but for the proposed physical or operational 

change, to result from the change. The preamble to the 

proposal also made clear that any emissions increase 

attributable to a physical or operational change that 

significantly alters the efficiency of the plant, (see 

Puerto Rican Cement. 889 F.2d at 297-8), must continue to be 

included in the post-change emissions calculations. 

However, EPA in no way intends to discourage physical or 

operational changes that increase efficiency or reliability 

or lower operating costs. Rather, physical or operational 

changes undertaken for these reasons are treated the same as 
P.46 

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physical or operational changes undertaken for any other 

reason: they are only subject to NSR if they result in an 

emissions increase. 

Several commenters requested a clarification concerning 

a unit's ability to accommodate demand growth in its 

pre-change configuration. In EPA's view, such a 

clarification is not warranted. As discussed above, 

operational levels that a unit could not have achieved but 

for the physical or operational change are considered to 

result from the change. Post-change emissions increases 

associated with such operational levels must, therefore, be 

considered to result from the change and be taken into 

account for NSR applicability purposes. 

Numerous commenters pointed out that it may be very 

difficult to determine when an increase is caused by 

independent factors and when it is caused by the physical 

change. Also, an environmental commenter argued that this 

causation question must always be resolved in favor of 

including all post-change emission increases that follow a 

change which improves a unit's efficiency, since in its view 

an efficiency gain will always be the primary determinant of 

the utility's use of a generating unit, notwithstanding the 

presence of other necessary — but not of themselves 

sufficient — factors such as demand growth. However, as so 

formulated, the comment answers itself. If efficiency 

improvements are the predominant cause of the change in 
P.47 

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emissions and demand growth is not, the exclusion does not 

apply. But this is a question of fact which must be 

resolved on a case-by-case basis and depending on the 

individual facts and circumstances of the change at issue. 

EPA declines to create a presumption that every emissions 

increase that follows a change in efficiency is inextricably 

linked to the efficiency change. 

In calculating demand growth, utilities may rely on 

demand growth projections in the form of prior filings with 

Federal, State or local regulatory authorities (e.g., a 

governing PUC) or other documentation which projected 

expected operations of an emissions unit or utility plant 

past the date of a proposed change. The information should 

show how an emissions unit, plant, or utility system would 

have been expected to operate in the absence of the proposed 

change. 

The EPA disagrees with comments that this provision 

could result in major increases in actual emissions going 

unregulated with the potential to create serious local air 

pollution problems. First, the NSR major modification 

provisions do not apply to all increases in emissions, just 

emission increases which stem from a nonroutine physical or 

operational change at an existing major source. Second, as 

has already been observed, this provision does not amount to 

a per se exclusion of demand growth. Finally, this new 

provision does not diminish the scope of the coverage of 
P.48 

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EPA's NSR regulations. Rather, it merely incorporates into 

the actual-to-future-actual methodology a requirement of the 

pre-existing statutory and regulatory scheme. 

Moreover, in response to those concerns that a demand 

growth exclusion could lead to serious local air pollution 

problems, EPA notes the restrictions it placed on the 

overall future projection in the proposal: the level of 

emissions the source claims that it will operate at should 

be consistent with current assumptions regarding the 

source's emissions that are used in the relevant State 

Implementation Plan (SIP). 

Finally the EPA does not agree with the commenter 

requesting that the final rule confirm that increases 

attributable to system-wide demand growth are already 

excluded under the existing exclusion for increases in hours 

of operation and, therefore, the "demand growth exclusion" 

only applies where there is a federally-enforceable permit 

term limiting hours of operation or production rate. The 

commenter's statement is not correct. Although a source may 

vary its hours of operation or production as part of its 

everyday operations, an increase in emissions attributable 

to an increase in hours of operation or production rate 

which is the result of a construction-related activity is 

not excluded from review. See WEPCO, 893 F.2d at 916 n.ll; 

Puerto Rican Cement. 889 F.2d at 298. 
P.49 

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D. Repowering. 

a. Background. 

Title IV of the 1990 Amendments grants special 

treatment to utilities that seek to comply with mandated 

acid rain reductions by repowering a unit with qualifying 

Clean Coal Technology (CCT). See sections 402(12), 409(a). 

Repowering projects that qualify for an extension of the 

Phase II S02 requirements will be exempt from NSPS 

requirements, so long as the repowering "does not increase 

actual hourly emissions for any pollutant regulated under 

the Act" § 409(d). EPA proposed to interpret the 

requirement that repowering not lead to an increase in 

"actual hourly emissions" as an expression of Congressional 

intent that EPA should use the same general approach — one 

keyed to changes in maximum hourly emission rates — to 

determine applicability for repowering projects as it has 

for other physical or operational changes under the NSPS. 

Accordingly, EPA proposed that a repowering project which 

does not result in an increase over baseline in a unit's 

post-change hourly emissions will be eligible for this 

limited NSPS exemption. 

The statutory NSPS exemption applies to repowering of 

existing units at existing sources, so long as the project 

qualifies for an extension of the Phase II S02 requirements 

and satisfies the emissions increase test [see § 409(d)], 

Because of this explicit statutory provision, the 
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reconstruction limitations specified in 40 CFR 60.15 are not 

applicable to qualifying repowering projects. However, 

under the terms of § 409(d), new units located at a 

different site than the existing unit it replaces are not 

afforded special treatment. The EPA regulatory proposal on 

CCT followed these statutory provisions. In effect, EPA 

proposed to make all regulatory changes necessary to reflect 

these new CCT statutory provisions. The EPA also proposed 

to use the statutory definition of repowering set forth in 

§ 402(12). The EPA proposed regulations also provided for 

"expedited" NSR processing for repowering projects as 

required by § 409(e). 

b. Public Comment. 

The EPA did not receive any comments opposing the 

repowering proposal while several industry and Congressional 

commenters supported it. The Congressional commenters 

requested clarification of EPA's interpretation of term 

"repowering." The Congressional commenters stated that the 

proposed definition of "repowering" can be interpreted as 

limiting qualifying repowering technologies to those that 

only involve the replacement of the boiler, disqualifying 

highly-promising, multi-pollutant technologies that do not 

involve boiler replacement. 

c. The EPA Analysis. 

In light of the lack of negative comments, EPA is today 

promulgating the CCT provisions as proposed. This includes 
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no change in the definition of "repowering." However, EPA 

will follow an expansive interpretation of the term 

repowering, which should address many of the concerns 

expressed by some of the commenters while remaining 

consistent with statutory terms and Congressional intent. 

Section 402(12), in relevant part, defines "repowering" 

as follows: 

Replacement of an existing coalfired boiler with one of the following 

clean coal technologies: atmospheric or 

pressurized fluidized bed combustion, 

integrated gasification combined cycle, 

magnetohydrodynamics, direct and 

indirect coal-fired turbines, integrated 

gasification fuel cells or as determined 

by the Administrator, in consultation 

with the Secretary of Energy, a 

derivative of one or more of these 

technologies, and any other technology 

capable of controlling multiple 

combustion emissions simultaneously with 

improved boiler or generation efficiency 

and with significantly greater waste 

reduction relative to the performance of 

technology in widespread commercial use 

as of the date of enactment of the Clean 

Air Act Amendments of 1990 * * *7 

The definition thus provides for three major categories 

of repowering technologies: 

7 The last sentence in the definition of 

"repowering" in § 402(12) of the Act refers to a specific 

clean coal technology project in Tallahassee, Florida 

(Arvah B. Hopkins Station Unit 2 Circulating Fluidized-Bed 

Repowering Project) awarded November 30, 1990. 
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(1) Technologies specifically listed in the statute; 

(2) derivatives of one or more of these listed 

technologies; and 

(3) technologies which: 

(a) Are capable of controlling multiple combustion 

emissions simultaneously; 

(b) with improved boiler or generation efficiency; and 

(c) with significantly greater waste reduction than 

technologies in widespread commercial use as of the date of 

enactment of the Act (November 15, 1990). 

In accordance with the language of the statutory 

definition of repowering, the final rule provides that a 

qualifying repowering technology must involve "replacement" 

of an existing boiler. The language of § 402(12), though 

ambiguous in many significant respects, will not support an 

interpretation which fails to recognize that repowering 

requires use of an appropriate new technology instead of the 

existing boiler. 

The EPA considered whether the reference to boiler 

replacement in § 402(12) could be read as referring to only 

the first category of technologies. However, such an 

approach would require reading the provision as if the 

recital of the three alternative technologies began 

immediately after the phrase "repowering means," rather than 

after the phrase "repowering means replacement of an 
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existing coal-fired boiler with one of the following clean 

coal technologies:." 

Such a reading is inconsistent with the structure of 

the provision, in which the colon, which is "used chiefly to 

direct attention to matter that follows (as a list, 

explanation, or quotation)" [see Webster's Ninth New 

Collegiate Dictionary 266 (1985)], follows rather than 

precedes the reference to boiler replacement. Moreover, all 

three categories of technologies would be properly described 

as "the following clean coal technologies:." 

While it is true that the list following the colon, 

like the phrase "the following clean coal technologies:" 

could be read to refer exclusively to the seven named 

technologies (or to those technologies and their approved 

derivatives), such an interpretation would still fail to 

provide a satisfactory explanation of the grammatical 

structure of the provision. Either of these two readings 

would fail to explain how the technologies that, according 

to those readings do not consider boiler replacement, relate 

to the term "repowering." In other words, if the concept of 

boiler replacement were removed from either the third 

category of technologies or from both the second and third 

categories, the provision would read, with respect to those 

categories: 

The term "repowering" means * * * a 

derivative of one or more of (the seven) 

technologies, and any other technology 
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capable of (meeting the three 

performance criteria). 

The difficulty with this reading is that "repowering," 

whatever the precise scope of its definition, clearly means 

doing something with a derivative technology or a 

multipollutant control technology, rather than simply those 

technologies themselves. Requiring boiler replacement for 

all three categories avoids this particular infirmity. 

The EPA also considered another textual argument that 

could be advanced to support an interpretation of § 402(12) 

that boiler replacement is not required for the third 

category of technology, but it also is unpersuasive. It 

simply does not follow from the fact that the category of 

multipollutant control technologies alone has expressly 

enumerated performance criteria that those criteria are 

meant to be the exclusive test for qualifying technologies 

of these types. Because the third category of technology 

was intended to encompass types of technologies which were 

unknown on the date of enactment (and thus, unlike the prior 

categories, not susceptible to being enumerated in the 

statute) that category would necessarily have to include 

explicit defining criteria, whether or not the boiler 

replacement criterion applied to it. By the same token, the 

fact that the latter two categories are subject to EPA 

approval in consultation with DOE does not imply that this 

is the only criterion applicable to them. Each is subject 
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to additional criteria (i.e., the requirement of derivation 

in the case of the second category, and the three 

performance criteria in the case of the third category). 

The pivotal phrase "replacement of an existing 

coal-fired boiler" is undefined in the statute, and its 

scope is not clearly delineated by its context. Some of the 

seven listed technologies may not require total boiler 

replacement, although all require such extensive changes to 

the boiler that they are tantamount to boiler replacement. 

Under the principle of eiusdem generis, therefore, the 

Agency clearly has, at a minimum, ample discretion to treat 

as functional boiler replacement any changes broadly similar 

in scope to those involved in installing the seven named 

technologies. Such a definition would clearly represent the 

lower, not the upper, limit on the Agency's discretion to 

give meaning to the term "replacement". Accordingly, the 

statute confers on EPA the additional discretion to define 

boiler replacement in a functional manner that takes into 

account achievement of the specified performance criteria as 

well as the degree of changes to the boiler. By way of 

example, elsewhere in today's final rule the Agency 

considers a unit to be "replaced" if it would "constitute a 

reconstructed unit within the meaning of 40 CFR 60.15." In 

accordance with the above language EPA will use the 40 CFR 

60.15 test for "reconstruction" as general guidance in 

determining whether each individual application under § 409 
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involves sufficient replacement to qualify for a repowering 

extension and hence, an NSPS exemption. 

In short, because "Congress has not directly spoken to 

the precise question at issue," Chevron. U.S.A. v NRDC. 

467 U.S. 837, 842-43 (1984), EPA enjoys a siqnificant 

measure of discretion to determine to what extent 

replacement of less than 100 percent of the parts of an 

existing boiler could be deemed replacement for purposes of 

§ 402(12) and this rule. For the reasons discussed above, 

EPA believes the proposed regulatory language regarding 

repowering is reasonable. That proposal is today 

promulgated without change. 

E. Clean Coal Technology Demonstration Projects and Very 

Clean Units 

a. Background. 

Today's notice makes no changes with respect to the 

proposed provisions for CCT demonstration projects created 

by the 1990 Amendments. Temporary CCT demonstration 

projects are defined as those CCT demonstration projects 

lasting 5 years or less. Title IV of the amended Act gives 

these projects an exemption from NSPS, PSD, and 

nonattainment requirements [see § 415(b)(2)]. However, the 

facility is still subject to any applicable SIP and must 

comply with any other requirements necessary to attain and 

maintain the NAAQS. The EPA considers the 5-year period as 

beginning on the date of startup (as defined in 
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40 CFR 60.2). A temporary demonstration project may be 

converted to a permanent status at any time, provided it 

meets all the requirements that apply to a permanent CCT 

project the time of conversion. 

At the end of a temporary project, the facility must be 

returned to pre-demonstration conditions and hourly emission 

rates (or lower). The EPA considers emissions increases 

(above the predetermined levels) that are attributable to 

physical or operational changes, other than those necessary 

to restore that unit to its pre-demonstration condition, to 

be beyond the scope of the Congressional exemption. 

In addition, repowering projects-which are awarded 

funding from the DOE as permanent CCT demonstration projects 

are exempted from NSPS and PSD requirements, so long as 

potential emissions from the unit do not increase as a 

result of the project [see § 415(b)(3)]. However, 

repowering projects that qualify as pollution control 

projects will be treated as other pollution control projects 

for the purposes of the nonattainment provisions of title I 

of the Act. 

Finally, today's notice promulgates the statutory 

exemptions in § 415(c). In that section, Congress provided 

an exemption from NSPS and PSD for the reactivation of "very 

clean units" otherwise in compliance with the Act that had 

been shut down for at least the 2 years prior to enactment 

of the 1990 Amendments and that, prior to the shutdown, had 
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been equipped with pollution controls with a removal 

efficiency of at least 85 percent for S02 and 98 percent for 

particulates, and had been equipped with low-N0x burners. 

a. Comments Generally Favoring the EPA Proposal. 

Some commenters specifically mentioned that CCT 

demonstration projects should not be subject to NSR 

provisions. 

b. Comments Generally Opposing the EPA Proposal. 

Some commenters did not support the proposed blanket 

inclusion of all CCT projects as pollution control projects. 

One commenter suggested that each CCT project be reviewed on 

a case-by-case basis and, if the project results in higher 

emission levels, it should not be considered a pollution 

control project. Another commenter gave an example of a CCT 

project that converts an oil-fired unit to a higher emitting 

coal-fired unit, noting that this project should not be 

considered a pollution control project. 

One commenter opposed to the pollution control project 

exemption questioned the very narrow exemption from NSPS and 

PSD for the reactivation of well-controlled, very clean 

units that had been shut down for at least 2 years prior to 

the enactment of the 1990 Amendments. If such exemptions 

are granted, the commenter urged EPA to include a condition 

that any reactivated sources perform an air quality impact 

assessment and demonstrate that they would not cause or 
P.59 

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contribute to a violation of NAAQS, PSD increments, or 

visibility standards. 

c. Comments Suggesting Revisions to the Proposal. 

The following suggestions were made with regard to the 

definition of "pollution control project": 

(1) include all elements of CCT demonstration projects 

as an excluded project; 

(2) add the words "clean coal technology" in the 

examples of pollution control projects in 40 CFR 51.165, 

51.166, 52.21, and 53.24; and 

(3) use the statutory definition of CCT demonstration 

project in 60.14(j)(l). The statutory definition omits the 

requirement that at least 20 percent of the funding for a 

CCT demonstration project come from the Federal government. 

d. The EPA Analysis. 

After review of the public comments and further 

analysis of the subject provision, EPA has decided to 

promulgate the proposed rules implementing the CCT and very 

clean unit exemption created by the 1990 Amendments. The 

EPA views this action as merely incorporating into its 

existing regulatory framework statutory exemptions that were 

immediately effective upon passage of the 1990 Amendments. 

F. Calculation of NSPS Baseline 

a. Background. 

As discussed in the proposal, "any physical or 

operational change to an existing facility which results in 
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an increase in the emission rate to the atmosphere of any 

pollutant to which a standard applies" is a modification for 

NSPS applicability purposes [see 40 CFR 60.14(a)]. A 

prechange baseline must be established in order to determine 

if an increase in hourly emissions has occurred at a unit. 

Under current regulations, the emissions rate before and 

after a physical or operational change is evaluated at each 

unit by comparing the current hourly potential emissions at 

maximum operating capacity to hourly emissions at maximum 

capacity after the change. The reviewing authority 

disregards the unit's maximum design capacity in this 

calculation. The original design capacity of a unit, to the 

extent it differs from actual maximum capacity at the time 

that the baseline is established due to physical 

deterioration of the facility, is immaterial to this 

calculation. In its proposed regulations, EPA proposed 

that, for an existing electric utility steam generating 

unit, the pre-change baseline for NSPS applicability 

purposes shall be calculated using the highest hourly 

emissions rate achievable at any time during the 5 years 

prior to the change. 

b. Comments Generally Favoring the EPA Proposal. 

Several commenters noted that EPA's proposal will provide 

needed flexibility and alleviate uncertainty for nonroutine 

repair, replacement, and maintenance projects while still 

protecting local air quality. One commenter supported 
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retention of the key concept of equating contemporaneous 

emissions with representative emissions. 

c. Comments Generally Opposing the EPA Proposal. 

One commenter opposing the proposal noted that the 

provision for the maximum hourly emissions achievable during 

the last 5 years would result in a significant relaxation of 

NSPS requirements and would allow utilities to upgrade 

equipment which may have lost significant generating 

capacity without the equipment being subject to NSPS. 

Sources that have been operating below their maximum 

achievable emission rates for the 5 years prior to the 

change can cause increases in actual hourly emission rates, 

inconsistent with the intent of the NSPS program. In 

addition, the change in the baseline will allow utilities 

such a extensive ability to make unregulated changes such as 

refurbishment, repowering or life-extension as to interfere 

with competition between existing units and new units. 

d. Comments Suggesting Revisions to the Proposal. 

The most frequent comment on this part of the proposal 

was that the rule should be clarified to say that the 

baseline should reflect the last 5 years of operation, to 

address units that have not been operating. In this regard, 

commenters were concerned about whether the approach will 

ensure the establishment of past emission levels that are 

truly representative of normal source operations for utility 

units in cold storage for more than 5 years. 
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One commenter asked that the NSPS baseline 

[40 CFR 60.14(h)] be made consistent with the NSR pre-change 

baseline [40 CFR 52.21(b)(21)(ii)] by adding the phrase, "or 

other period deemed by the Administrator to be more 

representative of normal operation." One commenter remarked 

that if the rule cannot be changed to allow consideration of 

the past 5 years of operation, then EPA should select an 

alternative that would reflect a more representative 

baseline. In addition, some commenters asked for 

clarification that a unit may "net out" of NSPS requirements 

by switching to low sulfur coal. 

e. The EPA Analysis. 

After careful consideration of the comments received 

and further analysis of the subject provision, EPA has 

decided to promulgate the proposed revised methodology for 

calculating the pre-change baseline for NSPS applicability 

purposes for an existing electric utility steam generating 

unit. The amended methodology will use the highest hourly 

emissions rate achievable at any time during the 5 years 

prior to the change. 

The revised methodology retains the key concept in 

existing regulations that the baseline be determined during 

a period that is roughly contemporaneous with the proposed 

change at the affected facility. The EPA believes that this 

decision to revise the current regulation will allow 

utilities flexibility for nonroutine repair, replacement, 
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and maintenance projects. Also, the EPA believes that 

without this revision, the NSPS regulations may unduly 

burden utilities undertaking physical or operational changes 

in conjunction with the acid rain program. This change will 

allow utilities to demonstrate that an earlier, higher 

capacity was more representative of the unit's maximum 

hourly emissions rate. 

The EPA did not agree with comments that the use of the 

maximum hourly emissions achievable during the last 5 years 

would result in a significant relaxation of NSPS 

requirements and allow utilities to upgrade equipment which 

may have lost significant generating capacity without the 

equipment being subject to NSPS. The promulgated change 

provides a more flexible provision enabling units to 

establish a baseline that is representative of their 

physical and operational capacity in recent years, while 

still precluding the use of a baseline tied to original 

design capacity, which may bear no relationship to the 

facility's capacity in recent years. 

The EPA did not agree with the comment that degree of 

flexibility granted utilities to make unregulated changes 

such as refurbishment, repowering or life-extension projects 

as a result of rule changes would interfere with competition 

between existing units and new units. The prior regulations 

allowed refurbishment, repowering or life-extension 

projects, provided emissions does not increase above the 
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unit's current maximum hourly emissions rate. Both the 

prior and newly promulgated regulations require a unit that 

undergoes a refurbishment, repowering or life-extension 

project which increases emissions above the unit's actual 

current maximum hourly rate to be subject to NSPS. The 

promulgated regulation simply allows more flexibility in 

defining a unit's current capacity. 

The EPA cannot agree with comments that the methodology 

for computing the NSPS baseline reflect the last 5 years of 

operation rather than the 5 years prior to the change. As 

discussed in conjunction the NSR baseline, the use of such a 

baseline would credit a unit which has been inoperable for 

20 or 30 years, or longer, and in need of extensive 

nonroutine changes, with a emissions baseline that does not 

reflect current achievable levels of operations. The EPA 

notes, however, that the NSPS regulations have always 

allowed a dormant unit to demonstrate its current capacity 

in order to determine its emissions baseline. Thus an 

operable unit, or one in need of only routine maintenance or 

repair, which has been dormant for an extended period of 

time can still demonstrate its achievable capacity and 

associated emissions level by operating for a relatively 

short period of time. 

A commenter requested that the NSPS baseline be revised 

to be consistent with the NSR pre-change baseline by adding 

the phrase, "or other period deemed by the Administrator to 
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be more representative of normal operation." The EPA did 

not grant this request because it would change the emphasis 

of the NSPS program. As a technology-based program, the 

NSPS program examines maximum hourly emissions rates, 

expressed in kilograms per hour. Thus, emission increases 

for NSPS purposes are determined by changes in the hourly 

emissions rates at maximum physical capacity, regardless of 

how the unit has actually operated. In contrast, in light 

of the air quality planning component of the NSR program, 

the NSR regulations examine total actual annual emissions to 

the atmosphere. Consequently, normal operations over a 

period of time is considered for purposes of determining a 

source's impact on ambient air. For NSR applicability 

determination purposes emissions increases are determined by 

changes in actual annual emissions as expressed in tons per 

year. 

Some commenters requested clarification on "netting 

out" of NSPS requirements by switching to low sulfur coal. 

The proposed regulatory changes were specifically limited to 

addressing the maximum achievable emissions at a specific 

point in time (i.e., immediately prior to the change versus 

achievable over the last 5 years) and not the parameters 

used in quantifying maximum hourly emissions. Today's rule 

does not alter current NSPS regulations on this point. 

Under those present NSPS regulations, only physical 

limitations on maximum capacity are considered in 
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determining potential emissions at power plants. Thus, any 

prospective changes in fuel or raw materials accompanying 

the physical or operational change are not considered in 

determining maximum capacity. 

G. Utility BACT Presumption for N0X. 

a. Background. 

The EPA proposed to adopt an assumption that, in the 

case of PSD permits issued by EPA under 40 CFR 52.21, BACT 

for emissions of N0X from existing coal-fired electric 

utility steam generating units undergoing a modification is 

the technology required under § 407 of the Act. 

b. Comments Generally Favoring the EPA Proposal. 

Supporters of the low-NOx burner BACT presumption 

pointed to strong Congressional policy judgement favoring 

the use of low-NOx burner technology. The BACT presumption 

should provide greater certainty and consistency to 

utilities, yet one supporter thought it would not limit the 

permitting authority's ability or obligation to consider 

other factors. One commenter noted that the BACT 

presumption establishes that low-NOx burners constitute 

reasonable available control technology (RACT) as well as 

BACT. 

c. Comments Generally Opposing the EPA Proposal. 

Concluding that the presumption is unwarranted, 

misguided, and possibly illegal, several opponents of the 

BACT presumption noted that it forecloses consideration of 
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other N0X control technologies and ignores the demonstrated 

track record and cost-effectiveness of other technologies 

such as selective catalytic reduction (SCR) or selective 

noncatalytic reduction. Commenters noted that SCR 

technology is in use in more than 200 power plants in six 

nations and can achieve twice the N0X reduction achievable 

by low-NOx burners. The SCR or other technologies more 

effective than low-NOx burners may be needed as retrofit 

requirements to attain the ozone standard. 

Another comment voiced by opponents of the low-NOx 

burner BACT presumption, was that it cannot be reconciled 

with the statutory command for case-by-case decisions. The 

EPA does not have the right to make such a presumption and 

several instances were cited where EPA has upheld the caseby-case BACT determination process. The BACT presumption 

fails to recognize that there are site-specific 

considerations that will affect the selection of BACT. Some 

commenters representing State and local air agencies noted 

that they favored keeping the top-down BACT process. 

Opponents of the BACT presumption also noted that such 

a presumption improperly shifts the burden of technology 

analysis to States at a time when they are overburdened. In 

addition, it will have an adverse effect on the ability of 

State and local agencies to control emissions to the degree 

necessary because it limits an agency's attainment 

strategies. 
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Some of the northeastern States discussed a study of 

the relationship of N0X emissions and attainment of ozone 

standards in that area. The study concluded that 

substantial N0X and VOC emission reductions must be achieved 

in order to attain the ozone NAAQS, yet the low N0X burner 

technology will not result in sufficient N0X reductions to 

attain the ozone standard. 

The following comments opposing the BACT presumption 

were also made: 

(1) it ignores the legislative and policy imperatives 

to reduce N0X emissions; 

(2) the Act (§ 407) did not set BACT under the PSD 

program, it merely established a cost ceiling for N0X 

controls on existing sources under the acid rain program; 

(3) it will encourage utilities to structure their 

capacity expansion programs as modifications to existing 

units and this would effectively repeal the genuine NOx BACT 

technology requirements for companies that own aging power 

plants; 

(4) it sets a poor precedent; 

(5) it would undercut marketplace incentives to 

develop and promote new, cost-effective control 

technologies; and 

(6) the environmental impacts have not been 

determined. 
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d. Comments Suggesting Revisions to the Proposal. 

Commenters made three suggestions with respect to the 

BACT presumption: 

(1) "low-NOx burner technology" should be defined to 

encompass technologies such as fuel staging, air staging, 

in-furnace injection of urea/ammonia and natural gas 

cofiring and reburn, as well as N0X burners such as the PM 

and CF/SF or IFS models; 

(2) promoting maximum flexibility, low-NOx burners 

should not be mandatory if the unit can meet the emissions 

limits through other burner modifications or in-furnace 

processes; and 

(3) low-NOx burners can be used for tangentially-fired 

boilers to comply with title IV requirements according to 

the intent of Congress. 

e. The EPA Analysis. 

Based upon a consideration of the comments received, 

and a reexamination of the relevant facts and statutory 

provisions, EPA has determined not to adopt the proposed 

presumption regarding BACT for N0X. The EPA is concerned 

that this presumption would suggest preemption of the 

exercise of State discretion and case-by-case decisionmaking 

which Congress envisioned as fundamental to the BACT 

process. The presumption could also impede the development 

of more effective or less costly control options. 
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In light of its decision not to adopt a BACT low-NOx 

presumption, EPA will not respond to other objections raised 

by commenters.8 

I. Limitation of the Proposal to Electric Utilities. 

1. Background. 

Consistent with the proposed rule, the regulatory 

provisions promulgated today are limited to electric utility 

steam generating units. Such units are defined as any steam 

electric generating unit that is constructed for the purpose 

of supplying more than one-third of its potential electric 

output capacity and more that 25 megawatts of electrical 

output to any utility power distribution system for sale. 

In the proposal, EPA indicated that it was limiting this 

rulemaking to electric utility steam generating units for 

two reasons. First, title IV of the Act addresses acid 

precipitation and focuses exclusively on utility power 

plants. Today's ruling ensures that the title I and 

title IV programs will not impose conflicting requirements 

for those plants. The second reason that the provisions 

were limited to utilities is that EPA's extensive experience 

with electric utilities, the general similarity of equipment 

within the category, and the particularly extent of publicly 

available information, indicate that a revision to the NSR 

8 This includes comments on the environmental impacts 

of the low-NOx presumption, elaboration on what constitutes 

low-NOx burner technology, and the merits and current use of 

other NO control technologies as BACT. 
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applicability criteria for this source category is 

warranted. 

2. Public Comments. 

Several commenters noted that limitation of the 

proposal to electric utilities lacks rational justification 

as well as legal and technical support. Several noted that 

the limitation is unfair, arbitrary, and capricious. 

Typical of several letters, one commenter noted that EPA 

offered no qualitative evidence of underlying assumptions, 

and another noted that EPA violates the Administrative 

Procedures Act by limiting the proposal to electric 

utilities. To this commenter, the limitation discriminates 

against industrial sources and is not in line with the 

intentions of the legislation. One commenter noted that the 

WEPCO court did not base its analysis on any particular 

characteristics of the utility industry. 

Numerous commenters countered EPA's claim and 

justification for the limitation that the Agency has more 

experience with electric utilities than other industries. 

Illustrating that EPA has extensive experience with other 

industries, commenters mentioned chemical manufacturing, 

cement plants, refineries, paper mills, auto assembly 

plants, the 65 NSPS sources, and sources covered in numerous 

guideline documents and RACT guidance. In addition, several 

noted that the lack of understanding is a poor excuse for 

not applying the proposal to all industries. 
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Commenters also noted that other industries face the 

same problems that utilities do when attempting to install 

pollution control equipment. Like electric utilities, 

pollution control projects in other industries are generally 

environmentally beneficial, but the limitation of the 

exclusion to electric utilities as proposed would discourage 

the other source categories, from installing pollution 

control projects. 

Several commenters noted that other industries will be 

equally impacted by extensive regulations under titles I, 

III, and V, just as electric utilities will be affected by 

title IV. For example, pharmaceutical plants will undergo 

physical and operational changes to meet reasonably 

available control technology (RACT) and/or maximum 

achievable control technology, and these projects should not 

be subject to NSR or NSPS. They note that the burden 

burdens and supportive reasons for making the proposed 

changes are just as great for other categories of sources as 

they are for electric utilities. 

Some commenters pointed out that EPA presently applies 

the pollution control project exemption from NSPS to all 

industries and that existing NSR rules are not industryspecific. 

3. The EPA Analysis. 

The EPA does not find the factual or legal arguments in 

favor of expanding the present rulemaking to be compelling. 
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Prior to proposal of this rule, EPA considered going forward 

with a rule that applied to all source categories. However, 

the complexity of that task meant that a rule could not be 

developed in a short time frame, a fact that posed unique 

and serious difficulties for one source category, utilities. 

While the commenters favoring expansion of this rule to all 

source categories are accurate in their claims that sources 

outside utilities face Clean Air Act-mandated pollution 

control projects, utilities alone are singled out to 

participate in the 1990 Amendments' new acid rain program. 

This program requires that units subject to phase I of the 

program meet S02 reduction limits by 1995. Given the size, 

complexity, and expense of scrubbers and other S02 pollution 

control technologies, the affected utilities need guidance 

today as to the title I implications of their control 

strategies. While other sources may soon have new control 

requirements imposed on them, utility sources face the most 

immediate need for clarification of their NSR 

responsibilities. 

In addition, EPA also had high confidence that a 

workable "future-actual" methodology could be developed for 

the utility industry. The source population is relatively 

small and the technology in use is relatively uniform. 

Moreover, utility sources are largely regulated by PUC which 

evaluate anticipated utility growth as part of the 

regulatory oversight process. The fact of PUC review helps 
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ensure the reliability of utility projections of future 

operating conditions. The EPA anticipates that NSR 

permitting authorities will be able to draw upon PUC 

proceedings in evaluating utility claims of future 

utilization. 

In addition, the emissions monitoring provisions of 

title IV requires that continuous emissions monitoring data 

or other highly accurate methods for reporting actual 

emissions will be used for all affected sources. This will 

assure that actual emissions data will be readily available 

for utility sources subject to today's rule. Since other 

source categories are not subject to the variety of 

regulatory programs as utilities and for the other reasons 

noted above, EPA declines to extend this rulemaking to other 

sources. 

Notwithstanding this response, EPA currently has 

underway a separate rulemaking which will consider the 

desirability of adopting for other source categories the NSR 

pollution control project exclusion and the changes to the 

methodology for determining whether a source change 

constitutes a modification that have been adopted today for 

utilities. This rulemaking will also discharge EPA's 

obligation to propose and take final action on a potentialto-potential methodology as required by Exhibit B of the 

settlement agreement in Chemical Manufacturers Association 
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v. EPA (D.C. Cir., No. 79-1112). The EPA presently intends 

to propose these NSR revisions later this year. 

III. Miscellaneous 

A. E.O. 12291. 

Under E.O. 12291, EPA must judge whether a regulation 

is a "major rule" and therefore subject to the requirement 

for preparation of a Regulatory Impact Analysis (RIA). This 

ruling is not a major rule because it will reduce the 

economic costs of meeting the requirements of the Act. 

However, this ruling was submitted to the Office of 

Management and Budget (OMB) for review. Written comments 

from OMB to EPA and any EPA response are included in Docket 

A-90-06. 

B. Paperwork Reduction Act. 

The proposal package stated that no additional public 

reporting burden will result from this ruling. That is 

still the case despite final rule requirements for reporting 

emissions data to agencies for 5 years following a change 

and for documenting demand growth exclusion in applicability 

determinations, because this information is already required 

by other provisions of the law and the final rule in doing 

so is providing exclusions for the affected sources and the 

net result is a decrease in these source's public reporting 

burden. All information collection requirements of the 

Federal NSR and NSPS regulations have been approved by OMB 

under the provisions of the Paperwork Reduction Act, 
P.76 

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44 U.S.C. 3501, et seq., and have been assigned OMB control 

numbers 2060-0003 for NSR, and 2060-0023, 2060-0026 and 

2060-0072 for NSPS. The effect of this rule would be a 

reduction in paperwork related to complying with NSR and 

NSPS requirements, since this ruling provides additional 

clarification as to physical and operational changes that 

may be excluded from these requirements. 

C. Economic Impact Assessment 

The requirement for performing an Economic Impact 

Assessment under § 317 of the Act (42 U.S.C. 7617), does not 

apply to the amendments EPA is promulgating today. 

Section 317 applies only to "revisions which the 

Administrator determines to be substantial revisions." The 

promulgated amendments are not substantial revisions because 

they relieve current regulatory burdens. 

D. Regulatory Flexibility Act Certification. 

As noted in the proposal notice, this action is not 

subject to the certification provisions of § 605(b) of the 

Regulatory Flexibility Act because this rule will result in 

a reduction of administrative costs and no increase in 

control costs, therefore having no significant impact on 

industry. 

E. Effective Date. 

As stated earlier in this notice, this rule is 

effective immediately upon publication in the FEDERAL 

REGISTER. The EPA has concluded that, under § 307(d)(1) of 
P.77 

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the Act, the requirement of sec. 4(d) of the Administrative 

Procedures Act, 5 U.S.C. 553(d), for a 30-day waiting period 

before making a rule effective is not applicable. 

F. Federalism Implications. 

Under E.O. 12612, EPA must determine if a rule has 

federalism implications (i.e., 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). For those rules which have federalism 

implications, a Federalism Assessment is to be made. The 

EPA's determination is that there are no federalism 

implications; these are relatively minor changes to existing 

federal law and regulations. 

The executive order also requires that agencies, to the 

extent possible, refrain from limiting the State policy 

options, consult with States prior to taking any actions 

that would restrict State policy options, and take such 

actions only when there is clear constitutional authority 

and the presence of a problem of national scope. The 

executive order provides for preemption of State law, 

however, if there is a clear congressional intent for the 

agency to do so. Any such preemption, however, is to be 

limited to the extent possible Since the rule is a direct 

effort to ensure implementation of the 1990 CAA, EPA 

considers all of the above requirements to be met. 
P.78 

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Lists of Subjects 

40 CFR part 51 

Administrative procedure and practices, 

Intergovernmental relations, Air pollution control, NSR, 

Clean Coal Technology projects, Sulfur oxides, Nitrogen 

dioxide, Particulate matter, Carbon monoxide, Hydrocarbons, 

Lead. 

40 CFR part 52 

Air pollution control, NSR, Clean Coal Technology 

projects, Repowering, Sulfur oxides, Particulate matter, 

Nitrogen dioxide, Carbon monoxide, Hydrocarbons, Lead. 

40 CFR part 60 

Air pollution control, NSPS, Clean Coal Technology 

projects, Repowering, Sulfur oxides, Particulate matter, 

Nitrogen dioxide, Carbon monoxide, Hydrocarbons, Lead. 

Authority: 42 U.S.C. 7401(b)(1), 7410, 7411, 7470-

7479, 7491, 7501-7508, 7601 and 7602, as amended by the 

Clean Air Act Amendments of 1990, Pub. L. No. 101-549, 

104 Stat. 2399 (Nov. 15, 1990); 402, 409, 415 of the Clean 

Air Act as amended, 104 Stat. 2399; 42 U.S.C. 7401-7642 as 

amended by the Clean Air Act Amendments of 1990, 
P.79 

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Pub. L. NO. 101-549, 104 Stat, 2399 (Nov. 15, 1990); 

42 U.S.C. 7401, 7411, 7414, 7416, and 7601 as amended by the 

Clean Air Act Amendments of 1990, Pub. L. 101-549, 

104 Stat. 2399 (Nov. 15, 1990; 402, 409, 415 of the Clean 

Air Act as amended, 104 Stat. 2399, unless otherwise noted. 
P.80 

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For the reasons set forth in the preamble, Part 51 of 

Chapter I of title 40 of the code of Federal Regulations is 

proposed to be amended as follows: 

Part 51 - REQUIREMENTS FOR PREPARATION, ADOPTION, AND 

SUBMITTAL OF IMPLEMENTATION PLANS. 

1. The authority citation for Part 51 is amended to 

read as follows: 

Authority: 42 U.S.C. 7401(b)(1), 7410, 7411, 7470-

7479, 7491, 7501-7508, 7601 and 7602, as amended by the 

Clean Air Act Amendments of 1990, Pub. L. No. 101-549, 

104 Stat. 2399 (Nov. 15, 1990); 402, 409, 415 of the Clean 

Air Act as amended, 104 Stat. 2399, unless otherwise noted. 

2. Section 51.165 is proposed to be amended to read 

as follows: 

51.165 Permit requirements. 

(a) 

(D 

(v) 

Vc 

* 

* 

* 

* 

* 

* 

* 

* 

(C) A physical change or a change in the method of 

operation shall not include: 
P.81 

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(8) the addition, replacement or use of a 

pollution control project at an existing electric 

utility steam generating unit, unless the 

Administrator determines that such addition, 

replacement, or use renders the unit less 

environmentally beneficial, and except: 

(i) when the Administrator has reason to 

believe that the pollution control project 

would result in a significant net increase in 

representative actual annual emissions of any 

criteria pollutant over levels used for that 

source in the most recent air quality impact 

analysis in the area conducted for the 

purpose of title I, if any, and 

(ii) the Administrator determines that the 

increase will cause or contribute to a 

violation of any national ambient air quality 

standard or PSD increment, or visibility 

limitation. 

(9) The installation, operation, cessation, or 

removal of a temporary clean coal technology 

demonstration project, provided that the project 

complies with: 
P.82 

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(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 

standards during the project and after it is 

terminated. 

(10) The reactivation of a very clean coal-fired 

electric utility steam generating unit. 

(xii) 

(D) For any emissions unit (other than an electric 

utility steam generating unit specified in paragraph 

(E) of this subsection) that has not begun normal 

operations on a particular date, actual emissions shall 

equal the potential-to-emit of the unit on that date. 

(E) For an electric utility steam generating unit 

(other than a new unit or the replacement of an 

existing unit), actual emissions of the unit following 

the physical or operational change shall equal the 

representative actual annual emissions of the unit, 

provided the source owner or operator,maintains and 
P.83 

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submits to the permitting authority f on an annual basis 

for a period of 5 years from the date normal operation 

begins' at the modified unit, information demonstrating 

fciiaif the physical or operational change did mot result 

;i_i"an"emissions * increase* A'longer period from the 

'date normal operations begins, not to exceed id years, 

may be required toy the permitting authority if it 

determines such a period to be more representative of 

normal source post-change operations. 

(xx) "Electric utility steam generating unit" means any 

steam electric generating unit that is constructed for the 

purpose of supplying more than one-third of its potential 

electric output capacity and more than 25 megawatts (MW) 

electrical output to any utility power distribution system 

for sale. Any steam supplied to a steam distribution system 

for the purpose of providing steam to a steam-electric 

generator that would produce electrical energy for sale is 

also considered in determining the electrical energy output 

capacity of the affected facility. 

(xxi) "Representative actual annual emissions" means 

the average rate, in tons per year, at which the source is 

projected to emit a pollutant for the 2-year period after a 

physical change or change in the method of operation of a 

unit, (or a different consecutive 2-year period within 
P.84 

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10 years after that change, where the permitting authority 

determines that such period is more representative of normal 

source operations), considering the effect any such change 

will have on increasing or decreasing the hourly emissions 

rate and on projected capacity utilization. In projecting 

future emissions the permitting authority shall: 

(A) consider all relevant information, including 

but not limited to, historical operational data, 

the company's own representations, filings with 

the State or Federal regulatory authorities, and 

compliance plans under title IV of the Clean Air 

Act; and 

(B) exclude, in calculating any increase in 

emissions that results from the particular 

physical change or change in the method of 

operation at an electric utility steam generating 

unit, that portion of the unit's emissions 

following the change that is attributable to an 

increase in projected capacity utilization at the 

unit that is unrelated to the particular change, 

including any increased utilization due to the 

rate of electricity demand growth for the utility 

system as a whole. 
P.85 

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(xxii) "Temporary clean coal technology demonstration 

project" means a clean coal technology demonstration project 

that is operated for a period of 5 years or less, and which 

complies with the State implementation plan for the State in 

which the project is located and other requirements 

necessary to attain and maintain the national ambient air 

quality standards during the project and after it is 

terminated. 

(xxiii) "Clean coal technology" means any technology, 

including technologies applied at the precombustion, 

combustion, or post combustion stage, at a new or existing 

facility which will achieve significant reductions in air 

emissions of sulfur dioxide or oxides of nitrogen associated 

with the utilization of coal in the generation of 

electricity, or process steam which was not in widespread 

use as of November 15, 1990. 

(xxiv) "Clean coal technology demonstration project" 

means a project using funds (1) appropriated under the 

heading 'Department of Energy-Clean Coal Technology,' up to 

a total amount of $2,500,000,000 for commercial 

demonstration of clean coal technology, or (2) similar 

projects funded through appropriations for the Environmental 

Protection Agency. The Federal contribution for a 
P.86 

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qualifying project shall be at least 20 percent of the total 

cost of the demonstration project. 

(xxv) "Reactivation of a very clean coal-fired electric 

utility steam generating unit" means any physical change or 

change in the method of operation associated with the 

commencement of commercial operations by a coal-fired 

utility unit after a period of discontinued operation where 

the unit: 

(i) has not been in operation for the 2-year period 

prior to the enactment of the Clean Air Act Amendments 

of 1990, and the emissions from such unit continue to 

be carried in the permitting authority's emissions 

inventory at the time of enactment; 

(ii) was equipped prior to shut-down with a continuous 

system of emissions control that achieves a removal 

efficiency for sulfur dioxide of no less than 85 

percent and a removal efficiency for particulates of no 

less than 98 percent; 

(iii) is equipped with low-NOx burners prior to the 

time of commencement of operations following 

reactivation; and 
P.87 

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(iv) is otherwise in compliance with the requirements 

of the Clean Air Act. 

(xxvi) "Pollution control project" means any physical 

change or change in the method of operation, at an existing 

electric utility steam generating unit for purposes of 

reducing emissions from such unit. Such changes are limited 

to: 

(i) the installation of conventional or innovative 

pollution control technology, including but not limited 

to advanced flue gas desulfurization, sorbent injection 

for sulfur dioxide and nitrogen oxides controls and 

electrostatic precipitators; 

(ii) a physical change, or change in the method of 

operation, to accommodate switching to a fuel which is 

less polluting than the fuel in use prior to the change 

including, but not limited to natural gas or coal reburning, or the co-firing of natural gas and other 

fuels for the purpose of controlling emissions; 

(iii) a permanent clean coal technology demonstration 

project conducted under title II, sec. 101(d) of the 

Further Continuing Appropriations Act of 1985 

(sec. 5903(d) of title 42 of the United States Code), 
P.88 

-86-

or subsequent appropriations, up to a total amount of 

$2,500,000,000 for commercial demonstration of clean 

coal technology, or similar projects funded through 

appropriations for the Environmental Protection Agency; 

or 

(iv) a permanent clean coal technology demonstration 

project that constitutes a repowering project. 

3. Section 51.166 is proposed to be amended to read 

as follows: 

51.166 Prevention of significant deterioration of air 

quality. 

**** * 

(b) * * * 

(2) * * * 

(iii) A physical change or change in the method 

of operation shall not include: 

* * * * 

(h) the addition, replacement or use of a 

pollution control project at an existing electric 

utility steam generating unit, unless the 

Administrator determines that such addition, 
P.89 

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replacement, or use renders the unit less 

environmentally beneficial, and except: 

(a) when the reviewing authority has reason 

to believe that the pollution control project 

would result in a significant net increase in 

representative actual annual emissions of any 

criteria pollutant over levels used for that 

source in the most recent air quality impact 

analysis in the area conducted for the 

purpose of title I, if any, and 

(b) the reviewing authority determines that 

the increase will cause or contribute to a 

violation of any national ambient air quality 

standard or PSD increment, or visibility 

limitation. 

(i) any physical change or change in the method 

of operation at an existing electric utility 

generating unit (other than the addition of a new 

unit or the replacement of an existing unit) that 

would not result in a significant net increase in 

representative actual annual emissions of a 

regulated pollutant at the unit. 
P.90 

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(j) 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 

standards during the project and after it is 

terminated. 

(k) 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 potentialto-emit of any regulated pollutant emitted by the 

unit. This exemption shall apply on a pollutantby-pollutant basis. 

(1) The reactivation of a very clean coal-fired 

electric utility steam generating unit. 

(21) 
P.91 

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(iv) For any emissions unit (other than an electric 

utility steam generating unit specified in paragraph 

(v) of this subsection) that has not begun normal 

operations on a particular date, actual emissions shall 

equal the potential-to-emit of the unit on that date. 

(v) For an electric utility steam generating unit 

(other than a new unit or the replacement of an 

existing unit), actual emissions of the unit following 

the physical or operational change shall equal the 

representative actual annual emissions of the unit 

following the physical or operational change,provided 

the source owner or operator maintains and submits to 

the permitting authority, on an annual basis for a 

period of 5 years from the date normal operation begins 

at the modified unit, information demonstrating that 

the physical or operational change did not result in an 

emissioris increase. A longer period from the date 

normal operations begins, not to exceed 10 years, may 

be required by the permitting authority if it 

determines such a period to toe more representative of 

normal source post-change operations. 

(30) "Electric utility steam generating unit" means any 

steam electric generating unit that is constructed for 

the purpose of supplying more than one-third of its 
P.92 

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potential electric output capacity and more than 25 MW 

electrical output to any utility power distribution 

system for sale. Any steam supplied to a steam 

distribution system for the purpose of providing steam 

to a steam-electric generator that would produce 

electrical energy for sale is also considered in 

determining the electrical energy output capacity of 

the affected facility. 

(31) "Pollution control project" means any physical change 

or change in the method of operation at an existing 

electric utility steam generating unit for purposes of 

reducing emissions from such unit. Such changes are 

limited to: 

(i) the installation of conventional or 

innovative pollution control technology, including 

but not limited to advanced flue gas 

desulfurization, sorbent injection for sulfur 

dioxide and nitrogen oxides controls and 

electrostatic precipitators; 

(ii) a physical change, or change in the method 

of operation, to accommodate switching to a fuel 

which is less polluting than the fuel in use prior 

to the change, including but not limited to 
P.93 

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natural gas or coal re-burning, or the co-firing 

of natural gas and other fuels for the purpose of 

controlling emissions; 

(iii) a permanent clean coal technology 

demonstration project conducted under title II, 

sec. 101(d) of the Further Continuing 

Appropriations Act of 1985 (sec. 5903(d) of 

title 42 of the United States Code), or subsequent 

appropriations, up to a total amount of 

$2,500,000,000 for commercial demonstration of 

clean coal technology, or similar projects funded 

through appropriations for the Environmental 

Protection Agency, or 

(iv) a permanent clean coal technology 

demonstration project that constitutes a 

repowering project 

(32) "Representative actual annual emissions" means the 

average rate, in tons per year, at which the source is 

projected to emit a pollutant for the 2-year period 

after a physical change or change in the method of 

operation of a unit, (or a different consecutive 2-year 

period within 10 years after that change, where the 

reviewing authority determines that such period is more 
P.94 

-92-

representative of normal source operations), 

considering the effect any such change will have on 

increasing or decreasing the hourly emissions rate and 

on projected capacity utilization. In projecting 

future emissions the reviewing authority shall: 

(A) consider all relevant information, including 

but not limited to, historical operational data, 

the company's own representations, filings with 

the State or Federal regulatory authorities, and 

compliance plans under title IV of the Clean Air 

Act; and 

(B) exclude, in calculating any increase in 

emissions that results from the particular 

physical change or change in the method of 

operation at an electric utility steam generating 

unit, that portion of the unit's emissions 

following the change that is attributable to an 

increase in projected capacity utilization at the 

unit that is unrelated to the particular change, 

including any increased utilization due to the 

rate of electricity demand growth for the utility 

system as a whole. 
P.95 

-93-

(33) "Clean coal technology" means any technology, including 

technologies applied at the precombustion, combustion, 

or post combustion stage, at a new or existing facility 

which will achieve significant reductions in air 

emissions of sulfur dioxide or oxides of nitrogen 

associated with the utilization of coal in the 

generation of electricity, or process steam which was 

not in widespread use as of November 15, 1990. 

(34) "Clean coal technology demonstration project" means a 

project using funds (1) appropriated under the heading 

'Department of Energy-Clean Coal Technology', up to a 

total amount of $2,500,000,000 for commercial 

demonstration of clean coal technology, or (2) similar 

projects funded through appropriations for the 

Environmental Protection Agency. The Federal 

contribution for a qualifying project shall be at least 

20 percent of the total cost of the demonstration 

project. 

(35) "Temporary clean coal technology demonstration project" 

means a clean coal technology demonstration project 

that is operated for a period of 5 years or less, and 

which complies with the State implementation plan for 

the State in which the project is located and other 

requirements necessary to attain and maintain the 
P.96 

-94-

nation ambient air quality standards during and after 

the project is terminated. 

(36)(i) "Repowering" means replacement of an existing 

coal-fired boiler with one of the following clean 

coal technologies: atmospheric or pressurized 

fluidized bed combustion, integrated gasification 

combined cycle, magnetohydrodynamics, direct and 

indirect coal-fired turbines, integrated 

gasification fuel cells, or as determined by the 

Administrator, in consultation with the Secretary 

of Energy, a derivative of one or more of these 

technologies, and any other technology capable of 

controlling multiple combustion emissions 

simultaneously with improved boiler or generation 

efficiency and with significantly greater waste 

reduction relative to the performance of 

technology in widespread commercial use as of 

November 15, 1990. 

(ii) Repowering shall also include any oil and/or gasfired unit which as been awarded clean coal 

technology demonstration funding as of January 1, 

1991, by the Department of Energy. 
P.97 

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(iii) The reviewing authority shall give expedited 

consideration to permit applications for any 

source that satisfies the requirements of this 

subsection and is granted an extension under 

§ 409 of the Clean Air Act. 

(37) "Reactivation of a very clean coal-fired electric 

utility steam generating unit" means any physical change or 

change in the method of operation associated with the 

commencement of commercial operations by a coal-fired 

utility unit after a period of discontinued operation where 

the unit: 

(i) has not been in operation for the 2-year period 

prior to the enactment of the Clean Air Act Amendments 

of 1990, and the emissions from such unit continue to 

be carried in the permitting authority's emissions 

inventory at the time of enactment; 

(ii) was equipped prior to shut-down with a continuous 

system of emissions control that achieves a removal 

efficiency for sulfur dioxide of no less than 85 

percent and a removal efficiency for particulates of no 

less than 98 percent; 
P.98 

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(iii) is equipped with low-NOx burners prior to the 

time of commencement of operations following 

reactivation; and 

(iv) is otherwise in compliance with the requirements 

of the Clean Air Act. 
P.99 

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For the reasons set forth in the preamble, Part 52 of 

Chapter I of title 40 of the Code of Federal Regulations is 

proposed to be amended as follows: 

Part 52-APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS 

1. The authority citation for Part 52 is amended to 

read as follows: 

Authority: 42 U.S.C. 7401-7642 as amended by the Clean 

Air Act Amendments of 1990, Pub L. No. 101-549, 

104 Stat. 2399 (Nov. 15, 1990), unless otherwise noted. 

2. Section 52.21 is proposed to be amended to read as 

follows: 

52.21 Prevention of significant deterioration of air 

quality. 

(b) 

(2) 
P.100 

-98-

(iii) A physical change or a change in the method 

of operation shall not include: 

**** * 

(h) the addition, replacement or use of a 

pollution control project at an existing electric 

utility steam generating unit, unless the 

Administrator determines that such addition, 

replacement, or use renders the unit less 

environmentally beneficial, and except: 

(a) when the Administrator has reason to 

believe that the pollution control project 

would result in a significant net increase in 

representative actual annual emissions of any 

criteria pollutant over levels used for that 

source in the most recent air quality impact 

analysis in the area conducted for the 

purpose of title I, if any, and 

(b) the Administrator determines that the 

increase will cause or contribute to a 

violation of any national ambient air quality 

standard or PSD increment, or visibility 

limitation. 
p.1 

-99-

(i) 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 standards during the project 

and after it is terminated. 

(j) The installation or operation of a 

permanent clean coal technology 

demonstration project that constitutes 

repowering, provided that the project 

does not result in an increase in the 

potential to emit of any regulated 

pollutant emitted by the unit. This 

exemption shall apply on a pollutant-bypollutant basis. 

(k) The reactivation of a very clean coal-fired 

electric utility steam generating unit. 
P.2 

-100-

(21) 

(iv) For any emissions unit (other than an electric 

utility steam generating unit specified in paragraph 

(v) of this subsection) that has not begun normal 

operations on a particular date, actual emissions shall 

equal the potential to emit of the unit on that date. 

(v) For an electric utility steam generating unit 

(other than a new unit or the replacement of an 

existing unit), actual emissions of the unit following 

the physical or operational change shall equal the 

representative actual annual emissions of the 

unit,provided the source owner or operator maintains 

and submits to the permitting authority,%on an annual 

basis'for a period of 5 years from the date normal 

operation begins at;the modified unit, information 

demonstrating that the physical or operational change 

did not result in an emissions increase. A longer 

period from the date normal operations begins, not to 

exceed 10 years, may be required by the permitting 

authority if it' determines such a period to be more 

representative of normal source post-change operations. 
P.3 

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(31) "Electric utility steam generating unit" means any 

steam electric generating unit that is constructed for 

the purpose of supplying more than one-third of its 

potential electric output capacity and more than 25 MW 

electrical output to any utility power distribution 

system for sale. Any steam supplied to a steam 

distribution system for the purpose of providing steam 

to a steam-electric generator that would produce 

electrical energy for sale is also considered in 

determining the electrical energy output capacity of 

the affected facility. 

(32) "Pollution control project" means any physical change 

or change in the method of operation, at an existing 

electric utility steam generating unit for purposes of 

reducing emissions from such unit. Such changes are 

limited to: 

(i) the installation of conventional or innovative 

pollution control technology, including but not 

limited to advanced flue gas desulfurization, 

sorbent injection for sulfur dioxide and nitrogen 

oxides controls and electrostatic precipitators; 

(ii) a physical change, or change in the method of 

operation, to accommodate switching to a fuel 
P.4 

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which is less polluting than the fuel in use prior 

to the change including, but not limited to 

natural gas or coal re-burning, or the co-firing 

of natural gas and other fuels for the purpose of 

controlling emissions; 

(iii) a permanent clean coal technology 

demonstration project conducted under title II, 

sec. 101(d) of the Further Continuing 

Appropriations Act of 1985 (sec. 5903(d) of 

title 42 of the United States Code), or subsequent 

appropriations, up to a total amount of 

$2,500,000,000 for commercial demonstration of 

clean coal technology, or similar projects funded 

through appropriations for the Environmental 

Protection Agency; or 

(iv) a permanent clean coal technology 

demonstration project that constitutes a 

repowering project. 

(33) "Representative actual annual emissions" means the 

average rate, in tons per year, at which the source is 

projected to emit a pollutant for the 2-year period 

after a physical change or change in the method of 

operation of a unit, (or a different consecutive 2-year 
P.5 

-103-

period within 10 years after that change, where the 

Administrator determines that such period is more 

representative of normal source operations), 

considering the effect any such change will have on 

increasing or decreasing the hourly emissions rate and 

on projected capacity utilization. In projecting 

future emissions the Administrator shall: 

(i) consider all relevant information, including 

but not limited to, historical operational data, 

the company's own representations, filings with 

the State or Federal regulatory authorities, and 

compliance plans under title IV of the Clean Air 

Act; and 

(ii) exclude, in calculating any increase in 

emissions that results from the particular 

physical change or change in the method of 

operation at an electric utility steam generating 

unit, that portion of the unit's emissions 

following the change that is attributable to an 

increase in projected capacity utilization at the 

unit that is unrelated to the particular change, 

including any increased utilization due to the 

rate of electricity demand growth for the utility 

system as a whole. 
P.6 

-104-

(34) "Clean coal technology" means any technology, including 

technologies applied at the precombustion, combustion, 

or post combustion stage, at a new or existing facility 

which will achieve significant reductions in air 

emissions of sulfur dioxide or oxides of nitrogen 

associated with the utilization of coal in the 

generation of electricity, or process steam which was 

not in widespread use as of November 15, 1990. 

(35) "Clean coal technology demonstration project" means a 

project using funds (1) appropriated under the heading 

'Department of Energy-Clean Coal Technology', up to a 

total amount of $2,500,000,000 for commercial 

demonstration of clean coal technology, or (2) similar 

projects funded through appropriations for the 

Environmental Protection Agency. The Federal 

contribution for a qualifying project shall be at least 

2 0 percent of the total cost of the demonstration 

project. 

(3 6) "Temporary clean coal technology demonstration project" 

means a clean coal technology demonstration project 

that is operated for a period of 5 years or less, and 

which complies with the State implementation plans for 

the State in which the project is located and other 
P.7 

-105-

requirements necessary to attain and maintain the 

national ambient air quality standards during the 

project and after it is terminated. 

(37)(i) "Repowering" means replacement of an existing 

coal-fired boiler with one of the following clean 

coal technologies: atmospheric or pressurized 

fluidized bed combustion, integrated gasification 

combined cycle, magnetohydrodynamics, direct and 

indirect coal-fired turbines, integrated 

gasification fuel cells, or as determined by the 

Administrator, in consultation with the Secretary 

of Energy, a derivative of one or more of these 

technologies, and any other technology capable of 

controlling multiple combustion emissions 

simultaneously with improved boiler or generation 

efficiency and with significantly greater waste 

reduction relative to the performance of 

technology in widespread commercial use as of 

November 15, 1990. 

(ii) Repowering shall also include any oil and/or gasfired unit which has been awarded clean coal 

technology demonstration funding as of January 1, 

1991, by the Department of Energy. 
P.8 

-106-

(iii) The Administrator shall give expedited 

consideration to permit applications for 

any source that satisfies the 

requirements of this subsection and is 

granted an extension under § 409 of the 

Clean Air Act. 

(38) "Reactivation of a very clean coal-fired electric 

utility steam generating unit" means any physical 

change or change in the method of operation associated 

with the commencement of commercial operations by a 

coal-fired utility unit after a period of discontinued 

operation where the unit: 

(i) has not been in operation for the 2-year period 

prior to the enactment of the Clean Air Act Amendments 

of 1990, and the emissions from such unit continue to 

be carried in the permitting authority's emissions 

inventory at the time of enactment; 

(ii) was equipped prior to shut-down with a continuous 

system of emissions control that achieves a removal 

efficiency for sulfur dioxide of no less than 85 

percent and a removal efficiency for particulates of no 

less than 98 percent; 
P.9 

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(iii) is equipped with low-NOx burners prior to the 

time of commencement of operations following 

reactivation; and 

(iv) is otherwise in compliance with the 

requirements of the Clean Air Act. 

3. Section 52.24 is proposed to be amended to read as 

follows: 

52.24 Statutory restriction on new sources. 

(f) 

(5) 

* * * 

* * * 

(iii) A physical change or change in the method of 

operation shall not include: 

* * * 

(h) the addition, replacement or use of a pollution 

control project at an existing electric utility steam 

generating unit, unless the Administrator determines 
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that such addition, replacement, or use renders the 

unit less environmentally beneficial, and except: 

(1) when the Administrator has reason to 

believe that the pollution control project 

would result in a significant net increase in 

representative actual annual emissions of any 

criteria pollutant over levels used for that 

source in the most recent air quality impact 

analysis in the area conducted for the 

purpose of title I, if any, and 

(2) the Administrator determines that the 

increase will cause or contribute to a 

violation of any national ambient air quality 

standard or PSD increment, or visibility 

limitation. 

(i) The installation, operation, cessation, or removal 

of a temporary clean coal technology demonstration 

project, provided that the project complies with: 

(1) the State implementation plan for the State in 

which the project is located, and 
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(2) other reguirements necessary to attain and 

maintain the national ambient air quality 

standards during the project and after it is 

terminated. 

(j) The reactivation of a very clean coal-fired 

electric utility steam generating unit. 
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(13) * * * 

(iv) For any emissions unit (other than an electric 

utility steam generating unit specified in paragraph 

(v) of this subsection) that has not begun normal 

operations on a particular date, actual emissions shall 

equal the potential to emit of the unit on that date. 

(v) For an electric utility steam generating unit 

(other than a new unit or the replacement of an 

existing unit), actual emissions of the unit following 

the physical or operational change shall equal the 

representative actual annual emissions of the 

unit,provided the source owner or operator maintains 

and submits to the permitting authority r on an annual 

basis for a period of 5 years from the date normal 

operation begins at the modified unit, information 

demonstrating that the physical or operational changf 

did not result in an emissions increase. A longer 

period from the date normal operations begins, not to 

exceed 10 yearsr may be required by the permitting 

authority if it determines such' a period to be more 

representative "of normal source post-change operations. 

(18) "Electric utility steam generating unit" means any 

steam electric generating unit that is constructed for the 
P.13 

-Illpurpose of supplying more than one-third of its potential 

electric output capacity and more than 25 MW electrical 

output to any utility power distribution system for sale. 

Any steam supplied to a steam distribution system for the 

purpose of providing steam to a steam-electric generator 

that would produce electrical energy for sale is also 

considered in determining the electrical energy output 

capacity of the affected facility. 

(19) "Representative actual annual emissions" means the 

average rate, in tons per year, at which the source is 

projected to emit a pollutant for the 2-year period after a 

physical change or change in the method of operation of a 

unit, (or a different consecutive 2-year period within 

10 years after that change, where the Administrator 

determines that such period is more representative of normal 

source operations), considering the effect any such change 

will have on increasing or decreasing the hourly emissions 

rate and on projected capacity utilization. In projecting 

future emissions the Administrator shall: 

(i) consider all relevant information, including but 

not limited to, historical operational data, the 

company's own representations, filings with the State 

or Federal regulatory authorities, and compliance plans 

under title IV of the Clean Air Act; and 
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(ii) exclude, in calculating any increase in emissions 

that results from the particular physical change or 

change in the method of operation at an electric 

utility steam generating unit, that portion of the 

unit's emissions following the change that is 

attributable to an increase in projected capacity 

utilization at the unit that is unrelated to the 

particular change, including any increased utilization 

due to the rate of electricity demand growth for the 

utility system as a whole. 

(20) "Temporary clean coal technology demonstration 

project" means a clean coal technology demonstration project 

that is operated for a period of 5 years or less, and which 

complies with the State implementation plans for the State 

in which the project is located and other requirements 

necessary to attain and maintain the national ambient air 

quality standards during the project and after it is 

terminated. 

(21) "Clean coal technology" means any technology, 

including technologies applied at the precombustion, 

combustion, or post combustion stage, at a new or existing 

facility which will achieve significant reductions in air 

emissions of sulfur dioxide or oxides of nitrogen associated 

with the utilization of coal in the generation of 
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electricity, or process steam which was not in widespread 

use as of November 15, 1990. 

(22) "Clean coal technology demonstration project" means a 

project using funds (1) appropriated under the heading 

'Department of Energy-Clean Coal Technology', up to a total 

amount of $2,500,000,000 for commercial demonstration of 

clean coal technology, or (2) similar projects funded 

through appropriations for the Environmental Protection 

Agency. The Federal contribution for a qualifying project 

shall be at least 20 percent of the total cost of the 

demonstration project. 

(23) "Reactivation of a very clean coal-fired electric 

utility steam generating unit" means any physical change or 

change in the method of operation associated with the 

commencement of commercial operations by a coal-fired 

utility unit after a period of discontinued operation where 

the unit: 

(i) has not been in operation for the 2-year period 

prior to the enactment of the Clean Air Act Amendments 

of 1990, and the emissions from such unit continue to 

be carried in the permitting authority's emissions 

inventory at the time of enactment; 
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(ii) was equipped prior to shut-down with a continuous 

system of emissions control that achieves a removal 

efficiency for sulfur dioxide of no less than 85 

percent and a removal efficiency for particulates of no 

less than 98 percent; 

(iii) is equipped with low-NOx burners prior to the 

time of commencement of operations following 

reactivation; and 

(iv) is otherwise in compliance with the requirements 

of the Clean Air Act. 

(24) "Pollution control project" means any physical change 

or change in the method of operation, at an existing 

electric utility steam generating unit for purposes of 

reducing emissions from such unit. Such changes are limited 

to: 

(i) the installation of conventional or innovative 

pollution control technology, including but not limited 

to advanced flue gas desulfurization, sorbent-injection 

for sulfur dioxide and nitrogen oxides controls and 

electrostatic precipitators; 
P.17 

-115-

(ii) a physical change, or change in the method of 

operation, to accommodate switching to a fuel which is 

less polluting than the fuel in use prior to the change 

including, but not limited to natural gas or coal reburning, co-firing of natural gas and other fuels for 

the purpose of controlling emissions; 

(iii) a permanent clean coal technology demonstration 

project conducted under title II, sec. 101(d) of the 

Further Continuing Appropriations Act of 1985 

(sec. 5903(d) of title 42 of the United States Code), 

or subsequent appropriations, up to a total amount of 

$2,500,000,000 for commercial demonstration of clean 

coal technology, or similar projects funded through 

appropriations for the Environmental Protection Agency; 

or 

(iv) a permanent clean coal technology demonstration 

project that constitutes a repowering project. 
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For the reasons set forth in the preamble, Part 60 of 

Chapter I of title 40 of the Code of Federal Regulations is 

proposed to be amended as follows: 

PART 60-STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

1. The authority citation for Part 60 is amended to read 

as follows: 

Authority: 42 U.S.C. 7401, 7411, 7414, 7416, and 7601 

as amended by the Clean Air Act Amendments of 1990, 

Pub. L. 101-549, 104 Stat. 2399 (Nov./15, 1990; 402, 409, 

415 of the Clean Air Act as amended, 104 Stat. 2399, unless 

otherwise noted. 

2. Section 60.2 is proposed to be amended by adding the 

following definitions: 

"Clean coal technology demonstration project" means a 

project using funds appropriated under the heading 

'Department of Energy-Clean Coal Technology', up to a total 

amount of'$2,500,000,000 for commercial demonstrations of 

clean coal technology, or similar projects funded through 

appropriations for the Environmental Protection Agency. 
P.19 

-117-

"Electric utility steam generating unit" means any steam 

electric generating unit that is constructed for the purpose 

of supplying more than one-third of its potential electric 

output capacity and more than 25 MW electrical output to any 

utility power distribution system for sale. Any steam 

supplied to a steam distribution system for the purpose of 

providing steam to a steam-electric generator that would 

produce electrical energy for sale is also considered in 

determining the electrical energy output capacity of the 

affected facility. 

"Repowering" means replacement of an existing coal-fired 

boiler with one of the following clean coal technologies: 

atmospheric or pressurized fluidized bed combustion, 

integrated gasification combined cycle, 

magnetohydrodynamics, direct and indirect coal-fired 

turbines, integrated gasification fuel cells, or as 

determined by the Administrator, in consultation with the 

Secretary of Energy, a derivative of one or more of these 

technologies, and any other technology capable of 

controlling multiple combustion emissions simultaneously 

with improved boiler or generation efficiency and with 

significantly greater waste reduction relative to the 

performance of technology in widespread commercial use as of 

November 15, 1990. Repowering shall also include any oil 

and/or gas-fired unit which has been awarded clean coal 
P.20 

# , , 

-118-

technology demonstration funding as of January 1, 1991, by 

the Department of Energy. 

"Reactivation of a very clean coal-fired electric utility 

steam generating unit" means any physical change or change 

in the method of operation associated with the commencement 

of commercial operations by a coal-fired utility unit after 

a period of discontinued operation where the unit: 

(i) has not been in operation for the 2-year period 

prior to the enactment of the Clean Air Act Amendments 

of 1990, and the emissions from such unit continue to 

be carried in the permitting authority's emissions 

inventory at the time of enactment; 

(ii) was equipped prior to shut-down with a continuous 

system of emissions control that achieves a removal 

efficiency for sulfur dioxide of no less than 85 

percent and a removal efficiency for particulates of no 

less than 98 percent; 

(iii) is equipped with low-NOx burners prior to the 

time of commencement of operations following 

reactivation; and 
-119-

(iv) is otherwise in compliance with the requirements 

of the Clean Air Act. 

3. Section 60.14 is proposed to be amended to read as 

follows: 

60.14 MODIFICATION. 

**** * 

(h) No physical change, or change in the method of 

operation, at an existing electric utility steam generating 

unit shall be treated as a modification for the purposes of 

this section provided that such change does not increase the 

P.21 

maximum hourly emissions of any pollutant regulated under 

this section above the maximum hourly emissions achievable 

at that unit during the 5 years prior to the change. 

(i) Repowering projects that are awarded funding from 

the Department of Energy as permanent clean coal technology 

demonstration projects (or similar projects funded by EPA) 

are exempt from the requirements of this section provided 

that such change does not increase the maximum hourly 

emissions of any pollutant regulated under this section 

above the maximum hourly emissions achievable at that unit 

during the five years prior to the change. 
P.22 

-120-

(j)(1) Repowering projects that qualify for an 

extension under § 409(b) of the Clean Air Act are exempt 

from the requirements of this section, provided that such 

change does not increase the actual hourly emissions of any 

pollutant regulated under this section above the actual 

hourly emissions achievable at that unit during the 5 years 

prior to the change. 

(2) This exemption shall not apply to any new 

unit that: 

(a) is designated as a replacement for an 

existing unit; 

(b) qualifies under § 409(b) of the Clean 

Air Act for an extension of an emission 

limitation compliance date under § 405 of the 

Clean Air Act; and 

(c) is located at a different site than the 

existing unit. 

(k) The installation, operation, cessation, or removal 

of a temporary clean coal technology demonstration project 

is exempt from the requirements of this section. A 

"temporary clean coal control technology demonstration 
P.23 

M~,-~..~l -121-

project", for the purposes of this section is a clean coal 

technology demonstration project that is operated for a 

period of 5 years or less, and which complies with the State 

implementation plan for the State in which the project is 

located and other requirements necessary to attain and 

maintain the national ambient air quality standards during 

the project and after it is terminated. 

(1) The reactivation of a very clean coal-fired 

electric utility steam generating unit is exempt from the 

requirements of this section.