p.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

273)IV-C-19 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:51:04 AM Sheet 273 of 276 
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IV-C-|*| 

Note to File: The attached draft regulatory package was sent to David Rivkin, Counsel to 

the Council on Competitiveness, Art Fraas, OIARA, OMB, and Paul Bailey, DOE. 
J . J 

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S f V^T ^ a^j/f 3/j0/fi . ~ ^ 

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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: The applicability of the new source requirements 

of title I of the Clean Air Act (CAA) to physical or 

operational changes at electric utility generating units is 

an issue of considerable interest at this time because of 

the recent passage of the 1990 CAA Amendments (1990 

Amendments). Many utilities will be undertaking major 

pollution control projects at their units in the next few 

years. In enacting title IV, Congress did not suspend any 

title I requirements for this work. However, the massive 

industry-wide undertakings of pollution control projects 

warrants a clarification of the new source review (NSR) 

requirements of title I. In particular, NSR provisions 

should not inadvertently bias a utility towards or against 

any means of complying with the acid rain provisions. The 

EPA believes the amendments adopted today and the 

clarification of its current policy under its present NSR 
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regulations provide adequate assurances that utilities can •< 

undertake title IV pollution control projects without 

uncertainty as to the applicability of the various title I 

new source requirements. At the same time, the 

applicability of existing new source regulations to 

modifications has been the source of two recent Federal 

appellate decisions, Wisconsin Electric Power Co. v. Reilly. 

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

Cement Co. v. EPA. 889 F.2d 292 (1st Cir. 1989). As a 

result, EPA is today adopting clarifying amendments to these 

regulations that confirmed policies regarding some of these 

provisions as they apply to utility projects. 

The EPA today adopts a broad NSR exclusion for utility 

pollution control projects, adhering to its policy that new 

source regulations already generally exclude coverage of 

pollution control projects undertaken at electric utility 

units. Similarly, EPA is today adopting an "actual to 

future actual" methodology for determining whether all other 

nonroutine physical or operational changes at utilities 

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

unit) are subject to NSR under either prevention of 

significant deterioration (PSD) or nonattainment provisions. 

For those utility projects which undergo PSD NSR, EPA 

proposed a presumption that for EPA-issued permits, "low-NOx 

burners" can satisfy the best available control technology 

(BACT) requirements. The EPA has determined not to adopt 

this presumption. 
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In addition, EPA is also modifying its regulations 

implementing the modification provisions of the title I new 

source performance standards (NSPS) program to provide that 

a utility may use for its pre-change baseline the highest 

hourly emissions rate achievable at any time during the 5 

years prior to the physical or operational change. In 

addition, EPA is modifying its regulations to reflect 

changes made by Congress in the 1990 Amendments to the 

applicability of new source requirements to clean coal 

technology (CCT) and repowering projects, and to "very 

clean" units. 

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

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

FOR FURTHER INFORMATION CONTACT: Mr. David A. Solomon at 

(919) 541-5375 or Mr. Larry Elmore at (919) 541-5433, New 

Source Review Section (MD-15), Office of Air Quality 
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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. Background 

A. The New Source Performance Standards, Prevention of 

Significant Deterioration and Nonattainment Programs of 

Title I 

B. The Two-Step Test for Modifications 

C. Step One: Physical or Operational Change 

D. Step Two: Emissions Increases for NSPS Applicability 

E. Step Two: Emissions Increases Under NSR Requirements 

1. Existing Regulations 

2. The WEPCO and Puerto Rican Cement Decisions 

F. The Clean Air Act Amendments of 1990 

1. New Source Review and the Acid Rain Provisions 

2. Repowering and Clean Coal Technology Projects 

III. 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 
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E. Clean Coal Technology Demonstration Projects and Very 

Clean Units 

F. Calculation of NSPS Baseline 

G. Utility BACT Presumption 

H. Applicability Determinations 

I. 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 

F. Federalism Implications 

I. Introduction. 

The EPA today amends its regulations implementing the 

various title I new source requirements governing physical 

or operational changes at electric utility generating units. 

Specifically, these changes are being issued to clarify the 

coverage of the NSPS, PSD and nonattainment preconstruction 

review requirements of title I of the CAA to projects 

undertaken at electric utility steam generating units.-

1 The regulations define electric utility steam 

generating units as any steam electric generating unit that 

is constructed for the purpose of supplying more than onethird of its potential electric output capacity and more 

than 25 megawatts (MW) of electrical output to any utility 

power distribution system for sale [see e.g., proposed 

40 CFR 51.165(XX)]. 
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The EPA today amends the definition of "major 

modification" in 40 CFR parts 51 and 52 to set forth the 

conditions under which 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 the switching to a less polluting fuel 

where the primary purpose of the switch is the reduction of 

air pollutants) will or will not subject the source to 

preconstruction review. Specifically, EPA is adopting in 

PSD and nonattainment areas a regulatory exclusion 

explicating its authority under the statutory definition of 

"modification" and confirming EPA's current practice that 

pollution control projects which "do not render the unit 

less environmentally beneficial" are not "physical or 

operational changes," and hence, are not "modifications" for 

the purposes of parts C and D of title I and are not "major 

modifications" for the purposes of EPA's regulations 

implementing those provisions. The EPA is today also 

amending its PSD and nonattainment NSR regulations (40 CFR 

parts 51 and 52)2 as they apply to utilities to (1) clarify 

the NSR baseline for determining whether a proposed physical 

or operational change will subject a utility to the 

preconstruction review requirements of these provisions; (2) 

2 For the purposes of this notice, references to "new 

source review" (or "NSR") refer to the preconstruction 

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

(nonattainment) of the CAA, unless otherwise indicated. 
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set forth an actual-to-future-actual methodology for 

determining whether a physical or operational change is 

subject to NSR; (3) provide further clarification of the 

existing regulatory requirement that only those increases in 

emissions that actually result from the physical change or 

change in the method of operation can be considered in 

determining whether the proposed change subjects the utility 

to NSR requirements; and (4) implement §§ 409 and 415 of 

title IV of the 1990 Amendments which create special NSPS 

treatment for certain repowering projects and limited NSR 

exemptions for temporary and permanent CCT projects, and for 

certain "very clean" units. Finally, EPA is also amending 

its NSPS regulations (40 CFR part 60) to allow a utility to 

use as its pre-change baseline its highest hourly emissions 

rate achievable during the 5 years prior to the proposed 

physical or operational change. 

Today's rule addressing pollution control projects and 

other non-routine physical and operational changes at 

electric utility units is timely for several reasons. 

First, the 1990 Amendments establish, in title IV, a new 

control scheme for addressing the acid rain problem which 

focuses exclusively and immediately on utility power plants, 

title IV will force most electric utility steam generating 

units to undertake pollution control projects and provides 

full flexibility to achieve compliance without a bias 

towards or against any particular pollution control method. 
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Second, the Agency believes its extensive experience with 

other non-routine physical and operational changes at such 

units and the unique characteristics of the electric utility 

industry (e.g., the general similarity of equipment within 

the category and the extent of publicly available 

information) support a revision to the NSR applicability 

criteria for this source category. Further, while Congress 

did not make significant changes in the NSR and NSPS 

statutory language in 1990, the conference committee 

provided the following guidance to EPA in its Joint 

Explanatory Statement: 

"[T]he deletion of most provisions 

relating to the WEPCO decision is not 

intended to affect or prejudice in any 

way the issues or resolution of the 

WEPCO matter. At the same time, the 

conferees urge a quick resolution of the 

WEPCO matter by EPA as appropriate." 

Conference Comm., Joint Explanatory Statement of the 

Committee of the Conference to Accompany S. 163 0, 

Rep. 101-952, 101st. Cong., 2nd Sess. (1990) pp. 344-45. In 

passing title IV, Congress did not suspend any requirements 

of title I. However title I and title IV are clearly 

intended to work in concert, not conflict, and today's 

ruling is intended to ensure that harmony. 

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. Background 

A. The New Source Performance Standards, Prevention 

of Significant Deterioration and Nonattainment 

Programs of Title I 

Title I of the CAA has three programs specifically 

designed to ensure that no new air pollution — whether from 

new sources or from modifications to existing sources — can 

be emitted unless the source complies with new source 

requirements. 

The 1970 CAA required EPA to promulgate technologybased NSPS applicable to the construction or modification of 

stationary sources that cause or contribute significantly to 

air pollution which may reasonably be anticipated to 
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endanger public health or welfare [see CAA § 111(b)(1)(A), 

42 U.S.C. 7411(b)(1)(A)]. The NSPS provisions were 

"designed to prevent new air pollution problems" by 

regulating newly-constructed sources and changes occurring 

at existing sources that result in emissions increases (see 

National Asphalt Pavement Assoc, v. Train,. 539 F.2d 775, 783 

(D.C. Cir. 1976); see also H.R. Rep. No. 1146, 91st Cong., 

2d Sess. 3, reprinted in 1970 U.S. Code Cong. & Admin. News 

5356, 5358). Congress defined the term "modification" 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" 

[see CAA § 111(a)(4), 42 U.S.C. 7411(a)(4)]. 

In 1977, Congress adopted additional amendments to the 

CAA. These changes included preconstruction permitting 

requirements for major new and modified sources under two 

programs, prevention of significant deterioration (PSD) and 

nonattainment NSR (respectively, parts C and D of the CAA). 

Congress intended these programs to apply generally where 

industrial changes might increase pollution in an area. 

Alabama Power Co. v. Costle. 636 F.2d 323, 400 (D.C. Cir. 

1979) . Congress incorporated in parts C and D the same 

definition of the term "modification" set forth in the NSPS 

provisions [see CAA § 111(a)(4), 169(2)(C), and 171(4)]. 
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The NSR program for PSD (CAA §§ 160-169) applies in 

attainment areas, i.e., those areas which have attained the 

national ambient air quality standards (NAAQS). To receive 

a PSD permit, a prospective major new source or major 

modification must (among other things) show that (1) it will 

not cause or contribute to a violation of the available air 

quality "increment" (designed to prevent ambient air quality 

from deteriorating by more than certain specified levels), 

(2) it will not cause or contribute to a violation of a 

NAAQS, and (3) it will use the "BACT," which must be at 

least as stringent as any applicable NSPS or hazardous 

pollutant standard under § 112 of the CAA. 

Part D of the 1977 Amendments applies to nonattainment 

areas, i.e., those areas which have not met the NAAQS under 

§ 109. To receive a permit in such areas, major new and 

modified sources must (among other things) (1) obtain 

emissions offsets, thereby assuring that reasonable progress 

toward attainment of the NAAQS will occur, and (2) comply 

with the "lowest achievable emission rate (LAER)" (see CAA 

§ 171-173) .

3 

3 The 1970 CAA also included a provision applicable to 

construction or modification of any stationary source. This 

provision is presently set forth in § 110(a)(2)(C). Today's 

notice does not propose to change the scope of the 

regulations implementing this provision (see 40 CFR 51.160-

164) . 
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B. The Two-Step Test for Modifications 

The modification provisions of the NSPS and NSR 

programs are based on the broad NSPS definition of 

"modification" in § 111(a)(4) of the CAA. That 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, 

which is largely the same for NSPS and NSR, the reviewing 

authority determines whether a physical or operational 

change will occur.4 If so, the reviewing authority proceeds 

in the second step to determine whether the physical or 

operational change will result in an emissions increase over 

baseline levels. In this second step, the applicable rules 

branch apart, reflecting the fundamental distinctions 

between the technology-based provisions of NSPS and the air 

quality-based provisions of NSR. 

Briefly, the NSPS program examines maximum hourly 

emissions rates, expressed in kilograms per hour.5 

Emissions increases for NSPS purposes are determined by 

4 This is further described in section III.H below. 

5 An hourly emissions rate may be determined by a 

stack test or calculated from the product of the 

instantaneous emissions rate, 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) times the production 

rate (such as tons of coal burned per hour) (see 40 CFR 

60.14). 
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changes in the hourly emissions rates at maximum physical 

capacity. On the other hand, the NSR regulations examine 

total emissions to the atmosphere. For applicability 

determination purposes, emissions increases under NSR are 

determined by changes in annual emissions as expressed in 

tons per year (tpy).6 

C. Step One: Physical or Operational Change 

The EPA has always recognized that the definition of 

physical or operational change in § 111(a)(4) could, 

standing alone, encompass the most mundane activities at an 

industrial facility (even the repair or replacement of a 

single leaky pipe, or a change in the way that pipe is 

utilized). However, EPA has always recognized that Congress 

obviously did not intend to make every activity at a source 

subject to new source requirements. 

As a result, EPA has defined "modification" in the NSPS 

and NSR regulations to include common-sense exclusions from 

the "physical or operational change" component of the 

definition. For example, both sets of regulations contain 

similar exclusions for routine maintenance, repair, and 

replacement; for increases in the hours of operation or in 

6 Annual emissions may be calculated as the product of 

the hourly emissions rate times the utilization rate, 

expressed as hours of operation per year, or as the product 

of an emissions factor (e.g., from Compilation of Air 

Pollutant Emission Factors. AP-42, 4th Ed. and subsequent 

supplements) in units of mass emitted per unit of process 

throughput times the annual throughput [see 40 CFR 

52.21(b)(21)]. 
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the production rate; and for certain types of fuel switches 

[see e.g., 40 CFR 52.21(b)(2)(iii) and 60.14(e)]. In 

addition, with respect to pollution control equipment, the 

NSPS regulations contain an exclusion for: 

The addition or use of any system or 

device whose primary function is the 

reduction of air pollutants, except when 

an emissions control system is removed 

or is replaced by a system which the 

Administrator determines to be less 

environmentally beneficial. 

40 CFR 60.14(e)(5). As will be discussed, in recent 

individual applicability determinations EPA has excluded 

pollution control projects from NSR following a similar 

"environmentally beneficial" test. 

D. Step Two: Emissions Increases for NSPS 

Applicability 

The EPA's NSPS regulations define the term 

"modification" as any "physical or operational change to an 

existing facility which results in an increase in the 

emission rate to the atmosphere of any pollutant to which a 

standard applies" (see 40 CFR 60.2 and 60.14). Under 

current NSPS regulations, emissions increases, for 

applicability purposes, are calculated by comparing the 

hourly emission rate, at maximum physical capacity, before 

and after the physical or operational change. That is, to 

determine whether a change to an existing facility will 

increase the emissions rate, the existing NSPS regulations 

authorize the use of an "emissions factor analysis," or a 
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materials balance, continuous monitoring, or manual 

emissions test to evaluate emissions before and after the 

change [see 40 CFR 60.14(b)(2)]. 

Absent the exclusions from modifications specified at 

40 CFR 60.14(e), any increase in emissions to the atmosphere 

over the previous emissions rate will subject the unit to 

NSPS [see 40 CFR 60.14(a) and (b)]. In addition, under the 

"reconstruction rules," physical or operational changes 

which would cost 50 percent or more of the total cost of a 

comparable new facility may be classified as reconstructions 

(see 40 CFR 60.15) and are subject to NSPS as a new source, 

even if there is no emissions increase. 

E. Step Two: Emissions Increases Under NSR 

Requirements 

1. Existing Regulations 

The EPA's regulations implementing the PSD and 

nonattainment programs require preconstruction review for 

sources undertaking a "major modification," i.e.. a physical 

change or change in the method of operations "that would 

result in a significant net emissions increase of any 

pollutant subject to regulation under the CAA" [see 40 CFR 

52.21(b)(2)(i), 52.24(f)(5)].7 A "net emissions increase" 

7 The current PSD program is set forth in two sets of 

regulations. One of the regulations cited (40 CFR 52.21) is 

part of the Federal PSD permit program which applies as part 

of a Federal implementation plan for States that have not 

submitted a PSD program meeting the regulatory requirements 

of 40 CFR 51.166 [standards for PSD provisions in State 

(continued...) 
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is defined as the increase in "actual emissions" from the 

particular physical or operational change together with any 

other "contemporaneous" increases or decreases in actual 

emissions [see 40 CFR 52.21(b)(3)(i)].8 

Applicability of the CAA's NSR provisions must be 

determined in advance of construction and is pollutant 

specific. In cases involving existing sources, this 

requires a pollutant-by-pollutant projection of the 

emissions increases, if any, that will result from the 

physical or operational change. Specifically, to determine 

whether a proposed physical or operational change will 

result in an emissions increase, the source must first 

determine a baseline level of actual emissions. The 

7(...continued) 

implementation plans (SIP)]. In most States where the 

Federal requirements apply, EPA has delegated the authority 

to implement the PSD program back to the State. Roughly 

two-thirds of the States are implementing their own PSD 

program pursuant to an EPA-approved SIP. Sections 52.21 and 

51.166 have identical modification provisions. 

The EPA's regulations for nonattainment areas are set 

forth at 40 CFR § 51.165, 52.24 and in part 51, Appendix S. 

These sections contain applicability provisions regarding 

modification that are largely identical to those in the PSD 

provisions. 

8 Roughly speaking, "contemporaneous" emissions 

increases or decreases are those which have occurred between 

the date 5 years preceding the proposed physical or 

operational change and the date that the increase from the 

change occurs [see 40 CFR 52.21(b)(3)(ii)]. Once a 

modification is determined to be major, the PSD requirements 

apply only to those specific pollutants for which there 

would be a significant net emissions increase [see e.g., 

40 CFR 52.21(j)(3) (best available control technology); 

40 CFR 52.21(m)(1)(b) (air quality analysis)]. 
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regulations define actual emissions on a particular date as 

"the average rate, in tpy, 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 40 CFR 52.21(b)(21)(ii)]. The 

Administrator "shall" allow use of a different time period 

"upon a determination that it is more representative of 

normal source operation." Id. The EPA has typically used 

the 2 years immediately preceding the physical or 

operational change to establish the baseline [see 

45 FR 52676, 52705, 52718 (1980)]. However, it can allow 

the use of an earlier 2-year period that is more 

representative of normal source operations. For example, in 

WEPCO, EPA found the fourth and fifth years prior to the 

modification more representative of WEPCO's normal 

operations. 

Because the applicability determination must be 

made in advance of construction, EPA's NSR regulations 

provide that when an emissions unit "has not begun normal 

operations," actual emissions equal the "potential-to-emit 

of the unit" [see 40 CFR 52.21(b)(21)(iv)]. This approach 

is referred to as the actual-to-potential methodology. This 

regulatory provision may be overcome — and NSR will not 

apply — if the source owner agrees, in a federallyenforceable instrument — not to increase its actual 
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emissions above baseline level [see e.g., 

40 CFR 52.21(b)(4)]. 

2. The WEPCO and Puerto Rican Cement Decisions 

As noted above, to calculate whether a physical or 

operational change "increases" emissions, EPA regulations 

require it to find an increase in actual emissions [see 

40 CFR 52.21(b)(3)(i)(a)]. Where the emissions unit has not 

"begun normal operations," EPA regulations recognize that 

future actual emissions are difficult to predict and employ 

future "potential" emissions as a proxy [see 

40 CFR 52.21(b)(21)(iv)]. The linchpin under the current 

regulations for predicting future emissions after a 

modification is thus whether the unit has "begun normal 

operations." 

Two recent Federal appellate court decisions have 

addressed EPA's interpretation of the phrase "begun normal 

operations." These decisions, Puerto Rican Cement Co.. Inc. 

v. US EPA. 889 F.2d 292 (1st Cir. 1989) and Wisconsin Elec. 

Power Co. v. Reillv. 893 F.2d 901 (7th Cir. 1990) ("WEPCO"), 

occasion a reexamination of EPA's interpretation of the 

phrase, and of the usefulness of the regulatory language 

itself. The meaning of the phrase is highly fact-dependent, 

and these decisions have created uncertainty regarding its 

application; thus, as described later in this notice, EPA 

today to changes its regulations for electric utility steam 

generating units to employ a more useful criterion. 
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Both cases involved physical changes to existing 

emissions units, but changes of differing extent, nature and 

result. In Puerto Rican Cement, the owner of a cement 

plant9 with several kilns sought to convert one "wet" kiln 

into a "dry" kiln, and to combine that kiln with another 

kiln (see 889 F.2d at 293). The court observed that the 

total production capacity of the renovated single kiln would 

exceed the combined production capacity of the previous two 

separate kilns by "about 35%." Id. It noted that the 

renovated single kiln would employ a different "cementmaking process" than the original kiln from which it was 

"converted," id. And it said that the new kiln would be 

"more efficient [and] may lead the firm to decide to 

increase the level of production." id. at 297 (emphasis in 

original). In reviewing EPA's interpretation of "begun 

normal operations," the court applied a highly deferential 

standard of review, since an agency's interpretation of its 

own regulatory language is typically given "'controlling 

weight unless it is plainly erroneous or inconsistent with 

the regulation'" [see 889 F.2d at 297, quoting Udall v. 

Tallman. 380 U.S. 1, 16-17 (1965) (citation omitted)]. The 

court concluded that on the facts of the case, EPA's 

interpretation that "normal operations" had not begun was 

9 Puerto Rican Cement involved a cement plant, not an 

electric utility, but the court's legal analysis of the 

phrase "begun normal operations" in the current regulations 

is relevant to all facilities. 
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not "arbitrary or irrational," id. at 298, and hence EPA's 

application of the actual-to-potential test to predict 

future emissions was permissible. 

In WEPCO. 893 F.2d 901, the Seventh Circuit was faced 

with a different kind of modification. There renovations 

were proposed for several older (35 to 50 year old) coalfired electric utility boilers. The physical changes 

involved repair and replacement of turbine-generators, steam 

drums and other major components. The EPA contended, as it 

had in Puerto Rican Cement, that these changes went beyond 

"normal operations" and thus warranted use of future 

potential emissions as the test for an emissions increase 

over past actual emissions. Here the court disagreed with 

EPA's interpretation that "normal operations" had not begun. 

The court coined the phrase "like-kind replacement" to 

describe the type of renovation occurring at the WEPCo 

plant. Id. at 917. The court described a "like-kind 

replacement" as one that "does not 'change or alter' the 

design or nature of the facility. Rather, it merely allows 

the facility to operate again as it had before the specific 

equipment deteriorated." Jd. at 908. In determining 

whether such a "like-kind replacement" had "begun normal 

operations," £d. at 917, the court considered whether a 

"realistic assessment of [the] impact [of the change] on 

ambient air quality levels is possible.'" Id. at 917 

[quoting Alabama Power Co. v. Costle. 636 F.2d 323, 379 
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(D.C. Cir. 1979)]. The court said that where the 

renovations were "like-kind replacements," EPA could not 

reasonably interpret its regulations to say that such a unit 

was so different that it has not "begun normal operations." 

Thus, it concluded that the "actual-to-potential" test could 

not be applied, under EPA's regulations, to units simply 

undergoing "like-kind replacements."10 

Neither of these decisions specified the threshold for 

when a unit has "begun normal operations." Based on these 

decisions, under its current regulations, EPA must consider 

the facts of each case and apply the actual-to-potential 

test only where the change is sufficiently significant to 

support a finding that "normal operations" have not "begun." 

At least for changes that are "like kind replacements," 

"normal operations" have begun, and the actual-to-potential 

test is impermissible. 

Because the "begun normal operations" criterion is 

highly fact-dependent and its application is inherently 

case-by-case, it may be an uncertain indicator of what 

emissions test will be applied in a given instance. 

However, EPA's extensive experience with electric utilities, 

and the generally similar nature of operations within this 

source category, provide EPA an adequate basis on which to 

10 On remand, EPA employed an actual-to-future actual 

test, comparing WEPCO's representative actual emissions for 

the baseline period to estimated future actual emissions 

based on all the available facts in the record. 
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predict future actual emissions from such units in most 

cases. Consequently, as explained below, EPA is today 

revising its regulations to apply the actual-to-actual test 

on all physical or operational changes at electric utility 

steam generating units save those that are an addition of a 

new unit or constitute a replacement of an existing unit. 

F. The Clean Air Act Amendments of 1990 

1. New Source Review and the Acid Rain Provisions 

The 1990 Amendments, Pub L. No. 101-549, 104 Stat. 2399 

(Nov. 15, 1990), made numerous changes in the nonattainment 

provisions of the CAA and added a new title to address the 

problem of acid rain. The amendments attack nonattainment 

problems with a broad array of new requirements all designed 

to bring all areas of the country into attainment with the 

national ambient air quality standards for all pollutants. 

These requirements include traffic reduction strategies, use 

of alternative clean fuels, increased offset requirements 

for stationary sources, and changes in the threshold size of 

stationary sources subject to NSR. A principal theme of the 

legislation is the establishment of categories of 

nonattainment areas based on the severity of the pollution 

problem. The more severe the area, the more controls 

Congress required be imposed. 

The Amendments also establish, in title IV, a new 

control scheme for addressing the acid rain problem. The 

exclusive focus of this program is on utility power plant 
P.25 

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emissions of sulfur dioxide and nitrogen oxides. The 1990 

Amendments require sulfur dioxide emissions from utilities 

to be reduced by approximately 10 million tons annually in 

two phases — the first to take effect in 1995, the second 

in 2000. A total of 111 specific plants are targeted in 

Phase I, and will be required to reduce their S02 emissions 

to specified emissions limits. In Phase II, these plants, 

and almost all others, are subject to even lower S02 

emissions limits. This reduction program is to be 

implemented through a new market-based system under which 

emissions allowances reflecting the required reduction in 

current emissions are allocated to existing utility plants. 

Plant owners, who are required to hold allowances equal to 

their actual emissions, are then free to trade these 

allowances. Thus, the emissions of individual units may 

vary from the initial allocation of allowances, but 

aggregate emissions are always held to the program's overall 

target level. This program will provide powerful incentives 

to sources to undertake pollution control projects. 

Because of these requirements, many of the plants 

subject to Phase I controls must make compliance decisions 

within the next year in order to assure that the complicated 

control equipment that may be necessary to meet Phase I 

standards is in place by the 1995 deadline. In enacting 

title IV, Congress did not suspend any title I requirements 

for this work. However, the massive industry-wide 
P.26 

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undertakings of pollution control projects warrants a 

clarification of the NSR requirements of title I. In 

particular, NSR provisions should not inadvertently bias a 

utility towards or against any means of complying with the 

acid rain provisions. The EPA believes the amendments 

promulgated today and the clarification of its current 

policy under its present NSR regulations provide adequate 

assurances that utilities can undertake title IV pollution 

control projects without uncertainty as to the applicability 

of the various title I new source requirements. 

2. Repowering and CCT Projects 

In title IV of the 1990 Amendments, which creates the 

acid rain program, Congress made changes in the 

applicability of new source requirements to changes 

involving repowering and Clean Coal Technology (CCT) 

projects. 

Section 409 grants an extension of the acid rain 

controls deadline to sources that seek to comply with the 

acid rain reductions by repowering a unit with qualifying 

clean coal technology. Section 402(12) defines repowering 

as: 

[The] 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 
P.27 

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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. 

Notwithstanding the provisions of 

section 409(a), for the purpose of this 

title, the term 'repowering' shall also 

include any oil and/or gas-fired unit 

which has been awarded clean coal 

technology demonstration funding as of 

January 1, 1991, by the Department of 

Energy. 

[see CAA §§ 402(12) and 409(a)]. 

Congress provided that repowering projects that qualify 

for a Phase II compliance extension would also be exempt 

from NSPS requirements, so long as the repowering "does not 

increase actual hourly emissions for any pollutant regulated 

under the Act" [see CAA § 409(d)]. An operator can qualify 

for the 3-year extension of the Phase II emissions 

limitation by demonstrating (by December 31, 1997) to the 

permitting authority that one or more units will be 

repowered with a qualifying clean coal technology to meet 

the title IV restrictions. The operator must provide, no 

later than January 1, 2000, additional documentation of the 

repowering project including a preliminary design and 

engineering effort for the project and a binding contract 

for the majority of the equipment needed, as well as any 

additional information the reviewing authority requires. 
P.28 

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Today's amendments also implement an exemption from new 

source requirements for CCT demonstration projects created 

by Congress in § 415 of title IV of the 1990 Amendments. In 

these provisions, CCT is defined as any technology not in 

widespread use on the date of enactment that achieves 

significant reductions in S02 or nitrogen oxides (NOJ 

emissions associated with burning coal in the generation of 

electricity, process steam, or industrial products [see CAA 

§ 415(a)]. A CCT "demonstration project" is a project 

funded under DOE's CCT program or a similar project funded 

by EPA.11 

Repowering projects that are awarded funding from the 

Department of Energy (DOE) as permanent CCT demonstration 

projects (or similar projects funded by EPA) are exempt from 

NSPS and PSD requirements so long as potential emissions 

(see 40 CFR 52.21(b)(4)) from the unit do not increase as a 

result of the project [see CAA § 415(b)(3)]. These funded 

projects may still be required to comply with the 

nonattainment NSR provisions of title I of the CAA, unless 

they are excluded as pollution control projects. 

11 Section 415(b)(1) defines a CCT project as a 

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 demonstration of 

clean coal technology, or similar projects funded through 

appropriations for the Environmental Protection Agency." 
P.29 

-27-

The installation, operation, cessation, or removal of a 

temporary CCT demonstration project that is operated for 5 

years or less is exempt from NSPS and both PSD and 

nonattainment new source requirements [see CAA 415(b)(2)]. 

However, the facility still must comply with the applicable 

SIP and other requirements necessary to attain and maintain 

the NAAQS. 

Finally, in § 415(c), Congress provided an exemption 

from NSPS and PSD for the reactivation of "very clean units" 

otherwise in compliance with the CAA 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 been 

equipped with pollution controls with a removal efficiency 

of at least 85 percent for sulfur dioxide and 98 percent for 

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

III. Discussion of Final Action on Proposal. 

A. Pollution Control Projects. 

1. Regulatory Changes for Pollution Control Projects. 

a. Background. 

The 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" and confirming the Agency's 

current policy that such projects are not subject to NSR 

unless they render the unit less environmentally beneficial. 
P.30 

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Generally, pollution control projects at existing stationary 

sources are not major modifications subject to NSR 

requirements for the simple reason that they do not result 

in an increase in actual emissions. In addition, EPA has 

always recognized that Congress did not intend that every 

activity at an existing facility be considered a physical or 

operational change for purposes of the NSR.12 

The EPA proposed to adopt 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 primary function is the reduction 

of air pollutants (including the switching to a lesspolluting fuel where the primary purpose of the switch is 

the reduction of air pollutants). Under the proposal, a 

utility pollution control project would not be treated as a 

physical or operational change unless the project renders 

the unit less environmentally beneficial. 

The key to this addition to the list of exclusions from 

the term physical or operational change is EPA's judgment 

that Congress did not intend that pollution control projects 

be considered the type of activity that should trigger NSR. 

The EPA proposed regulatory language to explicate and 

12 For instance, EPA has specifically recognized that 

routine maintenance, repair and replacement, and changes in 

hours of operation or in the production rate are not 

considered a physical change or change in the method of 

operation [see 40 CFR 52.21(b)(2)(iii), 52.24(f)(5)(iii), 

51.165(a)(1)(v)(C)(1), 51.166(b)(2)(iii), and 60.14(e)(1)]. 
P.31 

-29-

formalize its statutory authority to exclude pollution 

control projects under the NSR provisions. In 1977, when 

Congress enacted the NSR provisions of the CAA, it provided 

that the term "modification" in NSR shall have the same 

meaning as the term "modification" under NSPS [see 

§§ 169(2)(c), 171(4)]. At the time, regulations promulgated 

under the NSPS provisions defining "modification," provided 

that the term "modification" does not include: 

The addition or use of any system or 

device whose primary function is the 

reduction of air pollutants, except when 

an emissions control system is removed 

or is replaced by a system which the 

Administrator determines to be less 

environmentally beneficial. 

[see 40 CFR 60.14(e)(5)]. In 1978, EPA noted that "in 

adding § 169(2)(c) to the CAA, Congress indicated that it 

intended to conform the meaning of 'modification' to 'usage 

in other parts of the Act' [see 123 Congr. Rec. H11955, 

11957 (Nov. 1, 1977)" also see 43 FR 26396 (June 19, 1978)]. 

Thus, just as EPA had the statutory authority to exclude 

pollution control projects by regulation from NSPS, the 

statutory authority exists for EPA to explicate by 

regulation an exclusion for pollution control projects from 

parts C and D of title I. 

This exclusion under NSR reflects the existing 

regulatory exclusion for pollution control activities under 

NSPS regulations, and several recent case-specific 

nonapplicability determinations under the NSR programs. The 
P.32 

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NSPS regulatory exclusion contains the proviso that the 

replacement of a pollution control system or device cannot 

be iess "environmentally beneficial" to qualify for the 

exclusion [see 40 CFR 60.15(e)(5)]. With respect to NSR, 

the proposal adopted a similar regulatory exclusion for 

pollution control projects in the PSD and nonattainment 

context. The major difference in the proposed NSR exclusion 

is that it would apply the "not less environmentallybeneficial" test to the addition and use, as well as the 

replacement, of a pollution control system or device. This 

change reflects the distinct air quality component of the 

PSD and nonattainment programs. By focusing on whether a 

pollution control project is a physical or operational 

change within the meaning of the NSR regulations, the 

proposal avoids the need to undertake a quantitative 

emissions increase calculation in every case, as would be 

necessary if such projects were deemed to be physical or 

operational changes. The EPA expects that most, if not all, 

pollution control projects will reduce net actual emissions. 

Nevertheless, the Administrator's authority to consider 

individual pollution control projects provides an adequate 

opportunity to determine that a pollution control project 

would somehow result in an adverse environmental impact and 

thus conclude that the project renders the unit less 

environmentally beneficial, and is therefore a physical or 

operational change that may be subject to NSR. 
P.33 

-31-

As proposed, a pollution control project refers to a 

project undertaken at a utility unit for purposes of 

reducing emissions from such unit. These changes are 

limited to the installation of conventional or innovative 

emissions control equipment, including, but not limited to, 

installation of conventional and advanced flue gas 

desulfurization, sorbent injection for sulfur dioxide (S02) 

and N0X controls, electrostatic precipitators, and projects 

undertaken to accommodate switching to a less polluting 

fuel, including natural gas or coal re-burning, co-firing of 

natural gas and other fuels for the purpose of controlling 

S02 and N0X emissions. 

Likewise, any activity that is necessary to accommodate 

switching to a less polluting fuel is considered to be part 

of the pollution control project. In some instances, this 

may involve changes to the pollution generating equipment 

(e.g., boiler), but only if the changes are necessary to 

maintain the normal operating capability of the unit at the 

time of the project, where the capability would otherwise be 

impaired as a result of the fuel switch. For example, an 

electric utility steam generating unit that switches from a 

higher sulfur bituminous coal to a low-sulfur subbituminous 

coal may need to make certain changes to the boiler in order 

to avoid derating the unit. 

Changes that are intended primarily to restore original 

capacity or to improve the operational efficiency of the 
P.34 

-32-

facility are not considered to be part of a pollution 

control project for purposes of today's rule. Also, the 

source still must comply with all applicable SIP limits and 

requirements, permit conditions and applicable NAAQS or PSD 

increment limits. 

As proposed, this pollution control project exclusion 

did not extend to source categories other than electric 

utility steam generating units. The EPA so limited this 

provision because, in contrast with a general lack of 

experience with other industries, EPA has extensive 

experience in addressing new source applicability issues 

regarding pollution control projects in the utility 

industry. That experience led EPA to conclude that 

pollution control projects in the utility industry are 

generally environmentally beneficial. 

As noted above, generally pollution control projects at 

existing stationary sources are not major modifications 

subject to NSR because they do not usually result in an 

increase in actual emissions, and EPA believes that, in 

general, pollution control projects were not intended by 

Congress to be considered physical or operational changes 

for purposes of NSR. 

The EPA applies its PSD regulations in harmony with its 

NSPS regulations, which exclude most pollution control 

projects [see 40 CFR 60.14(e)(5)]. In 1977, Congress 

incorporated the NSPS definition of modification into the 
P.35 

-33-

PSD and nonattainment statutes [see CAA §§ 111(a)(4), 

169(a)(c), 171(4)]. In addition, the legislative history 

reflects that, as a general matter, Congress intended to 

conform the meaning of "modification" for PSD purposes to 

the usage under the NSPS program [see 123 Cong. Rec. HI1957 

(November 1, 1977)]. The EPA reiterated this view in 1978 

(see 43 FR 26396, June 19, 1978). Subsequently, EPA 

interpreted its NSR regulations to incorporate the NSPS 

pollution control project exclusion.13 The EPA later voiced 

concern about incorporating the precise NSPS pollution 

control language in the NSR context absent explication 

through notice-and-comraent rulemaking largely because of the 

ambient air quality component of NSR that is absent from the 

NSPS program.14 In recent years however, EPA has 

consistently excluded pollution control projects from NSR 

provided that the proposed project would be environmentally 

beneficial, taking into account ambient air quality.15 In 

13 Memorandum from Edward Reich, Director, Stationary 

Source Compliance Division and William F. Pedersen, Acting 

Associate General Counsel, Air, Noise, and Radiation 

Division to Allyn M. Davis, Region IV (April 21, 1983). 

14 See Memorandum from Gerald A. Emison, Director, 

OAQPS, to Regional Division Directors (July 7, 1986). 

15 See Letter, William G. Rosenberg Assistant 

Administrator, EPA, to Andrew Aitken, Vice President, New 

England Power Service Co., March 26, 1991; Letter, Rosenberg 

to Patrick M. McCarter, Senior Vice President, Public 

Service Co. of Colorado, July 23, 1990; Letters, David Kee, 

Director, Air and Radiation Division, EPA Region V, to 

Timothy J. Method, Assistant Commissioner, Indiana Dept. of 

Environmental Management, January 30, 1990 and March 8, 

1990. 
P.36 

-34-

light of the title IV requirements and other provisions of 

the 1990 Amendments, EPA confirms that it will continue to 

consider the overall environmental consequences of pollution 

control projects for NSR applicability. By its nature, a 

determination of whether or not a project renders a unit 

less environmentally beneficial involves case-by-case 

assessment of its net emissions and overall impact on the 

environment. In making such assessments, EPA must consider 

the overall emissions before and after the project, as well 

as any other relevant environmental factors. As a result, 

no single factor can be identified in advance for purposes 

of making this determination. 

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 CAA and EPA's earlier determinations 

regarding such projects. Indeed, several commenters 

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

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." 

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 
P.37 

-35-

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 changes, 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 

authority to create such "exemptions" and disagreed that 

Congress intended to exclude pollution control projects from 

NSR. One commenter stated that the pollution control 
P.38 

-36-

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

of the CAA, 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 particulate matter, and how installation of lowN0X 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, 

suggested specific regulatory changes to the pollution 

control exclusion. For instance, numerous commenters 
P.39 

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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 alterations 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 

primary function is the reduction of air pollutants 

(including the switching to a less-polluting fuel where the 
P.40 

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primary purpose of the switch is the reduction of air 

pollutants). Under the regulations as adopted today, a 

utility undertaking a project qualifying for the pollution 

control project exclusion will not be subject to NSR under 

either PSD or nonattainment. 

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 above, 

pollution control projects at existing stationary sources 

are generally not subject to NSR requirements for the simple 

reason that they do not usually result in an increase in 

actual emissions. In addition, as also noted above, EPA has 

determined that 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. 

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 

a "compelling showing." 
P.41 

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First, as discussed, nothing in today's action 

authorizes any emissions increase that would cause or 

contribute to a violation of the NAAQS, PSD increment or 

visibility limitation.16 Second, the proposed and final 

rule provide an appropriate way of enabling utilities to 

undertake pollution control projects in an expeditious 

manner while protecting air quality. Although a pollution 

control project could theoretically cause a small collateral 

increase in some emissions, it will substantially reduce 

emissions from other pollutants. In recognition of this, 

the rule provides for a case-by-case assessment of the 

pollution control project's net emissions and overall impact 

on the environment. Third, as discussed in the following 

section, the permitting authority can require additional 

modeling under certain circumstances to evaluate the air 

quality impact of a pollution control project, thereby 

helping to assure protection of air quality. The EPA 

16 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 tpy or more is "significant" for 

S02. This does not address the question of whether a 

significant increase in emissions will cause or contribute 

to a violation of the NAAQS, PSD increment or visibility 

limitation. 
P.42 

-40-

considers these safeguards to be adequate to address air 

quality concerns in both attainment and nonattainment areas. 

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 
P.43 

-41-

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 IV's 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) and (g), 413]. 

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, EPA expects that 

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 

CAA. For instance, EPA regulations have long excluded 
P.44 

-42-

emissions increases associated with routine maintenance 

repairs and replacement, 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 as well as the 

relevant statutory provisions, EPA is confident that the 

regulatory clarification 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 
P.45 

-43-

some overlap (i.e., utility compliance projects undertaken 

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 CAA conferees did specifically direct EPA to find 

an administrative resolution of the WEPCO issues (see 

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 proposed pollution control project or physical or 

operational change cannot result in an emissions increase 

that will cause or contribute to a violation of a NAAQS, PSD 

increment, or visibility limitation [see CAA 

§§ 110(a)(2)(c), 165, 169A(b), 173]. The pollution control 

projects exclusion does not authorize any significant net 

increase in emissions that would have this proscribed 
P.46 

-44-

impact. It is possible that a pollution control project, 

while not causing any increase in maximum hourly emissions, 

will cause a significant net increase in actual emissions, 

which in turn could cause or contribute to the violation of 

a NAAQS, increment or visibility limitation. For this 

reason, as proposed, the reviewing authority may require a 

source to perform an air quality impact analysis (modeling) 

whenever 1) it has reason to believe that a 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) it has reason to believe that such an increase would 

cause or contribute to a violation of a NAAQS, increment or 

visibility limitation. If this modeling indicates that this 

increase in emissions will cause or contribute to a 

violation of any ambient standard, PSD increment or 

visibility limitation, the pollution control 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. 
P.47 

-45-

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 

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. An environmental group 

commented that the proposed rule does not provide for 

notification to Federal Land Managers so that they can 

fulfill their responsibilities to protect Class I areas. 
P.48 

-46-

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 

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. 

The 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 
P.49 

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emissions." Nothing in today's rules would authorize 

pollution control projects that result in a violation of a 

NAAQS, PSD increment or visibility limitation. 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, it is not the purpose 

of the NSR program to subject all emissions increases to 

permitting requirements, only increases that result from 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.17 

The government agency commenter is correct that PSD 

permitting requirements are intended to prevent a major new 

source or major modification from causing an adverse impact 

on air quality related values in Class I areas. However, 

the agency ignores the fact that, in general, existing 

17 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. 
P.50 

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facilities that have not been modified are not subject to 

ambient requirements related to air quality related values. 

The EPA believes that today's rule will allow reveiwing 

authorities sufficient flexibility to protect, to the extent 

required under existing law, Class I areas from possible 

adverse impacts from pollution control projects. As noted 

above, pollution control projects reduce emissions of 

targeted pollutants. While emissions of other pollutants 

could in theory increase in a few cases, EPA does not expect 

this to result in significant impacts on Class I areas. 

Where prospective projects may be cause for concern, 

permitting agencies have the authority to require modeling 

to prevent increment or visibility violations, and likewise 

may solicit the views of others in taking any other 

appropriate remedial steps deemed necessary to protect 

Class I areas. In deciding to adopt the rule as proposed, 

EPA emphasizes that all enviornmental impacts, including 

those on Class I areas, can be considered in evaluating 

whether a utility unit is "less environmentally beneficial" 

after controls than it was before controls. Accordingly, 

the final rule allows consideration of all environmental 

impacts — beneficial and adverse — in making a 

determination. 

B. Representative Actual Annual Emissions, 

a. Background. 
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The EPA proposed to revise its methodology for 

calculating emissions increases at electric utility steam 

generating sources. The EPA proposed to compare actual 

emissions before and after changes for all physical or 

operational changes at an existing electric utility steam 

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

replacement of an existing unit. The EPA proposed to 

consider a unit to be replaced if it would constitute a 

reconstructed unit within the meaning of 40 CFR 60.15. 

Since there is no relevant operating history for wholly new 

units and replaced units, it is not possible to reasonably 

project post-change utilization for these units, and hence, 

their future level of "representative annual actual 

emissions." For other changes, past operating history, and 

other relevant information, provides a basis for reasonable 

projections. 

As proposed, the "representative actual annual 

emissions" methodology requires the utility to compare its 

baseline emissions with its future actual emissions to 

determine if the proposed change will increase actual 

emissions. The EPA's existing regulations define baseline 

emissions as "the average rate, in tpy, 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 "shall" allow use of a different time period 
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"upon a determination that it is more representative of 

normal source operation." Id. Although not required by the 

regulations, EPA has historically used the 2 years 

immediately preceding the proposed change to establish the 

baseline [see 45 FR 52676, 52705, 52718 (1980)]. However, 

in some cases it has allowed the use of earlier periods. 

For example, in WEPCO. EPA found the fourth and fifth years 

prior to the modification more representative of WEPCO's 

normal operations since the source's capacity was reduced 

due to physical problems. The EPA proposed to retain this 

regulatory language, but to adopt a new presumption 

regarding its implementation. 

Under the proposed action, the Administrator would 

presume that any 2 consecutive years within the 5 years 

prior to the proposed change is representative of 

normal source operations for a utility. This 

presumption is consistent with the 5-year period for 

"contemporaneous" emissions increases and decreases in 

40 CFR 52.21(b)(3)(i)(b)." Source owners or operators, 

desiring to use other than a 2-year period or a baseline 

period prior to the last 5 years may seek the 

18 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)(1)(b)]. 
P.53 

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Administrator's specific determination that such period is 

more representative of normal operations.19 

The future actual projection is the product of: (l) 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.20 The projection of postchange capacity utilization for applicability purposes 

should be based on a projection of utilization for a period 

after the physical or operational change. Specifically, EPA 

proposed to allow sources to base the projection of 

utilization on the 2 years after the change, or a different 

19 The level of baseline emissions selected must be 

consistent with current assumptions regarding the source's 

emissions that are used under the SIP for planning or 

permitting purposes. Thus, the source may not select a 

level of baseline emissions higher than that used by the 

permitting authority in issuing a PSD or other construction 

permit to a source in the area, if such higher level would 

result in a NAAQS or increment violation, or violate a 

visibility limitation. 

20 In projecting future utilization and emissions 

factors, the permitting authority may consider the company's 

historical operational data, its own representations, 

filings with Federal, State or local regulatory authorities, 

and compliance plans developed under title IV of the 1990 

Amendments. 
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consecutive 2-year period within the 10 years after the 

change, where the Administrator determines that such period 

is more representative of normal source operations. 

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: 

(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 
P.55 

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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 

(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 
P.56 

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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. 

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 CAA, 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 
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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 

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 change 

triggers NSR, EPA should compare actual emissions for the 

current unit to potential emissions from the altered source; 

the future actual test does not guard against artificially 

low estimates made by sources to escape NSR, nor does it 
P.58 

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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. 

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. 
P.59 

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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 

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; 
P.60 

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(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: 

(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 electric utility steam 

generating units where the changes do not involve the 

construction of a new, "greenfield" unit or the replacement 

of an existing one. 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 
P.61 

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added safeguard discussed below, is the most suitable method 

for evaluating emissions changes at such sources. 

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 

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) .

21 

Moreover, EPA is not reading "normal source operations" 

out of the regulation as charged. 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 

21 As discussed, 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.62^ 

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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 

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 
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emissions) for the purpose of avoiding review or that even 

where a forthright estimate is made, the forecast may prove 

inaccurate. The 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. 

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 utilization and/or 

emissions levels at the 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 
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"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.22 Utilities may use continuous emissions 

monitoring data, operational levels, fuel usage data, source 

test results or any other readily available data of 

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 (such as pounds of 

S02 emitted per ton of coal burned), the utility may submit 

annual utilization data, rather than emissions data, as a 

method of tracking post-change emissions. If annual 

utilization data show that the unit increased utilization 

above baseline levels, the permitting authority should 

determine whether the increase resulted from the change. 

Where a causal link exists between the change and the 

increase in utilization, the permitting authority should 

then determine whether emissions have also increased as a 

result of the change. 

22 This is the only substantive change from the 

regulations as proposed. However, EPA has also made minor 

changes to the wording of some of the regulations to address 

problems with clarity and syntax. Since these changes are 

not intended to alter the meaning of the regulations, they 

are not individually discussed in this preamble. 
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Changes that could increase a unit's emissions factor 

typically involve changes to the boiler itself. (Such 

changes do not include activities that qualify as pollution 

control projects under today's rule.) Where these types of 

changes exist, the utilities should submit annual emissions 

data to the permitting authority. 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. 

Appropriate records are to be submitted to the 

permitting agency on an annual basis for a period of 5 years 

from the date the unit begins regular operations (i.e., 

post-change operation after an initial shakedown period). 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 5 years following the change is 

representative of 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 expect that 

documentation of post-change actual annual emissions will 
P.66 

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impose 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 representative 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 NSR 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" 
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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, the issue has an important 

bearing on today's rule because a project that is determined 

to be routine is excluded by EPA regulations from the 

definition of major modifications. For this reason, EPA 

plans to issue guidance on this subject as part of a NSR 

regulatory update package which EPA presently intends to 
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propose by early summer. In the meantime, EPA is today 

clarifying that the determination of whether the repair or 

replacement of a particular item of equipment is "routine" 

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

basis, must be based on the evaluation of whether that type 

of equipment has been repaired or replaced by sources within 

the relevant industrial category. 

C. The Causation Requirement. 

a. Background. 

The NSR regulatory provisions require that the physical 

or operational change "result in" an increase in actual 

emissions in order to consider that change to be a 

modification [see e.g., 40 CFR 52.21(2)(i)]. In other 

words, NSR will not apply unless EPA finds that there is a 

causal link between the proposed change and any post-change 

increase in emissions. The EPA proposed to amend its rules 

to clarify this provision in the context of modifications at 

electric utility steam generating units. 

Under the proposed regulations, any emissions increase 

attributable to a physical or operational change, such as 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 calculation. The proposal clarified that where 

increased operations are in response to independent factors, 

such as system-wide demand growth, which would have occurred 
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and affected the unit's operations even in the absence of 

the physical or operational change, such increases do not 

result from the change and shall be excluded from the 

projection of future actual emissions. Thus, in assessing 

whether the proposed change will result in an increase in 

actual emissions, utilities need not include in their 

projection of post-change utilization that portion of the 

increased rate of utilization, if any, due to factors 

unrelated to the physical or operational change, such as an 

increase in projected capacity utilization due to the rate 

of electricity demand growth for the utility system (of 

which that source is a member) as a whole. 

Under today's rule, during a representative baseline 

period (see supra), the plant must have been able to 

accommodate the projected demand growth physically and 

legally even absent the particular change. Increased 

operations (and resultant increases in actual emissions) 

that could not physically and legally be accommodated during 

the representative baseline period but for the proposed 

physical or operational change should be considered to 

result from the change. 

b. Comments Generally Favoring the EPA Proposal. 

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 
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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 

attributable to system-wide demand growth are already 

excluded under the already-existing exclusion and, 

therefore, the "demand growth exclusion" only applies where 
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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 occurs, 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 emissions 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 exclusion will 

have an adverse effect on local agencies' ability to control 

emissions and that the time of construction of a project 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 
P.72 

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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. 

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 
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increase. The EPA believes that this is a reasonable 

interpretation of the statutory provision in question, and 

of EPA's own regulations, and judicial precedents. 

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 

during the representative baseline period 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 the unit's 

future actual emissions. Conversely, where the increase 

could not have occurred during the representative baseline 

period 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. As discussed, EPA considers emissions increases 

due to increased operations that could not be physically or 

legally accommodated during the representative baseline 

period 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 
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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 postchange emissions calculations. However, EPA in no way 

intends to discourage physical or operational changes that 

increase efficiency or reliability or lower operating costs, 

or improve other operational characteristics of the unit and 

does so by focusing on the effect of any nonroutine changes 

on the operating characteristics of the unit during the 

representative baseline period. The EPA recognizes that 

improvements such as these are desirable for economic 

reasons and to assure a reliable supply of electricity. 

Thus, physical or operational changes that improve 

operational characteristics will be treated in the same 

manner as any other changes. This means that where an 

improvement involves a routine change, it is excluded from 

the NSR definition of "major modification." Alternatively, 

where an improvement is not routine and an emissions 

increase results from the improvement, that portion of the 

emissions increase resulting from the improvement will be 

considered in determining whether the proposed change 

subjects the unit to NSR requirements. 

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, 
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operational levels that a unit could not have achieved 

during the representative baseline period 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 

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 is dependent on the 

individual facts and circumstances of the change at issue. 

EPA declines to create a presumption that every emissions 
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increase that follows a change in efficiency is inextricably 

linked to the efficiency change. 

In calculating demand growth, utilities may consider 

the company's historical operational data, its own 

representations, filings with Federal, State or local 

regulatory authorities, and compliance plans developed under 

title IV of the 1990 Amendments. 

The EPA disagrees with comments that this provision 

could result in major increases in actual emissions going 

unreviewed 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 result 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 

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 
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be consistent with current assumptions regarding the 

source's emissions that are used in the relevant 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). 

D. Repowering. 

a. Background. 

As previously mentioned, title IV of the 1990 

Amendments grants special treatment to utilities that seek 

to comply with the mandated acid rain reductions by 

repowering a unit with qualifying clean coal technology [see 

1990 Amendments §§ 402(12), 409(a)]. Specifically, 

repowering projects that qualify for a Phase II compliance 

extension will also be exempt from NSPS requirements, so 
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long as the repowering "does not increase actual hourly 

emissions for any pollutant regulated under the Act" [see 

§ 409(d)]. The EPA interprets the requirement that the 

repowering not lead to an increase in "actual hourly 

emissions" as an expression of Congressional intent that 

with respect to repowering projects, EPA should use the same 

general approach to determining applicability as it has for 

other physical or operational changes, discussed above. 

Accordingly, EPA proposed rules provided that a repowering 

project which results in an increase over baseline in a 

unit's post-modification hourly emissions will not be 

eligible for this limited NSPS exemption. 

The proposed NSPS exemption applied to repowering of 

existing units at existing sources, so long as the project 

qualifies for the Phase II extension and satisfies the 

"actual hourly emissions" increase test. Because of this 

provision, the reconstruction limitations specified in 

40 CFR 60.15 are not applicable to qualifying repowering 

projects. However, no special treatment can be afforded to 

a new unit which is located at a different site than the 

existing unit it replaces [see CAA § 409(d)]. 

Pursuant to § 409(e), EPA will provide expedited NSR 

processing for repowering projects and will encourage State 

permitting authorities to do the same. 

b. Public Comment. 
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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 

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. 

The EPA notes that this interpretation is currently subject 

to comment as part of the rulemaking implementing the acid 

rain provisions of the 1990 Amendments and EPA may address 

this issue further in the context of that proceeding. 

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, 
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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 * * *a 

The definition thus provides for three major categories 

of repowering technologies: 

(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 CAA (November 15, 1990). 

23 The last sentence in the definition of "repowering" 

in § 402(12) of the CAA refers to a specific CCT project in 

Tallahassee, Florida (Arvah B. Hopkins Station Unit 2 

Circulating Fluidized-Bed Repowering Project) awarded 

November 30, 1990. 
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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 

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:." 
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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 

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) 
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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 

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 
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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 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 significant 

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 
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repowering is reasonable. That proposal is today 

promulgated without change. 

E. Clean Coal Technology Demonstration Projects and Very 

Clean Units 

a. Background. 

The EPA also proposed rules implementing the new CCT 

exemption created by the 1990 Amendments. In this proposal, 

temporary CCT demonstration projects are defined as those 

CCT demonstration projects lasting 5 years or less. 

Title IV gives these projects an exemption from NSPS, PSD 

and nonattainment requirements. Id., § 415(b)(2). However, 

the facility would still be subject to any applicable SIP 

and must comply with any other requirements necessary to 

attain and maintain NAAQS. The EPA proposed to implement 

this provision and clarify that EPA considers the 5 year 

period as starting on the date of startup (as defined in 

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 criteria at the time of conversion. 

Further, EPA proposed that at the end of a temporary 

project, the facility must be returned to pre-demonstration 

conditions and hourly emission rates (or lower). The return 

of the facility to its pre-demonstration physical and 

operational condition would not result in the loss of the 

actual emissions margin between pre-demonstration actual 
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emissions rate and SIP-allowable emissions rates for that 

facility. Rather, the facility would be treated as if the 

temporary demonstration project had never occurred.24 

This proposal did not extend to emissions increases 

that are unrelated to the conduct of temporary demonstration 

projects. The EPA considers emissions increases (above the 

pre-demonstration 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. 

The EPA also proposed to implement an exemption from 

NSPS and PSD requirements for repowering projects which are 

awarded funding from the DOE as permanent CCT demonstration 

projects (or similar projects funded by EPA) so long as 

potential emissions [see 52.21(b)(4)] 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 

24 This would be the case even if there were small 

differences in the post-demonstration physical and 

operational conditions due to a technical inability to 

restore the unit to its precise pre-demonstration condition, 

or due to normal variability in the coal used. Thus, EPA 

would not seek to apply NSPS or NSR because of a postdemonstration emissions increase attributable solely to an 

increase in the hours of operation or production rate of the 

unit (subject to the NSPS limitation that the production 

rate increase must be accomplished without a capital 

expenditure). 
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projects for the purposes of the nonattainment provisions of 

title I of the CAA. 

Finally, the proposal implemented 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 CAA 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 

been equipped with pollution controls with a removal 

efficiency of at least 85 percent for sulfur dioxide and 98 

percent for particulates, and had been equipped with low-NOx 

burners. This exemption appears to have been narrowly 

tailored and is not expected to have widespread 

applicability. 

b. Comments Generally Favoring the EPA Proposal. 

Some commenters specifically mentioned that CCT 

demonstration projects should not be subject to NSR 

provisions. 

c. 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 
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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 

contribute to a violation of NAAQS, PSD increments, or 

visibility standards. 

d. 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. 

f. The EPA Analysis. 
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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 

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)]. The 

NSPS regulations implementing this general definition focus 

on increases in hourly emissions, expressed in kilograms of 

pollutant discharged per hour. To determine if an increase 

in hourly emissions has occurred at a unit, a pre-change 

baseline must be established. 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 
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change. In this calculation, the reviewing authority 

disregards the unit's maximum design capacity.25 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. 

The 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. The proposal retained 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 the proposed revision, while modest, is still 

necessary to avoid the current regulation's undue emphasis 

on the physical condition of the affected facility 

immediately prior to the change. The proposal's more 

.flexible provision enables units to establish a baseline 

that is representative of its physical and operational 

capacity in recent years, while still precluding the use of 

25 [See 39 FR 36,948 col. 1 (proposed rule)]. In 

WEPCO, the utility contended that baseline capacity for the 

purpose of determining whether an increase in emission rate 

occurs for purposes of an NSPS modification is the original 

design capacity of the facility. However, the court 

rejected WEPCO's argument that original design capacity or 

past "representative" capacity, no longer achievable at the 

plant, had to be used for the baseline emissions rate. 
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a baseline tied to original design capacity, which as noted 

above may bear no relationship to the facility's capacity in 

recent years. 

Without this revision, the NSPS regulations may unduly 

burden utilities undertaking physical or operational changes 

in conjunction with the acid rain program. For instance, if 

a unit has broken down and is in need of repairs, the 

utility's baseline will be artificially low. The proposed 

change would allow utilities to demonstrate that an earlier, 

higher capacity was more representative of the unit's 

maximum hourly emissions rate. 

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 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 
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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. 

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 
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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 regarding the scheduling of nonroutine 

repair, replacement, 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 
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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 do not increase above the 

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 
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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 

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, 
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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 tpy. 

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 

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 a presumption that, in the 

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

for emissions of NO from existing coal-fired electric 
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utility steam generating units undergoing a modification is 

the technology required under § 407 of the CAA. 

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 

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 NOx 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. 
P.98 

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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. 

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. Some of the northeastern States expressed 

concerns that such a presumption might interfere with 

efforts to attain the ozone standard. 

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 promulgate the 

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. 
P.99 

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In light of its decision not to adopt a BACT low-N0x 

presumption, EPA will not respond to other objections and 

suggestions raised by commenters.26 

H. Applicability Determinations 

As noted in the proposal, source owners or operators in 

most instances are able to readily ascertain whether NSR 

requirements apply to them. Consequently, in administering 

these requirements, EPA does not require sources to obtain a 

formal applicability determination before proceeding with 

construction. In keeping with that practice, EPA will not 

require utilities to seek applicability determinations under 

either the revised regulations proposed today or the 

interpretations of existing regulations contained in this 

preamble. Utilities in most cases can readily ascertain how 

this notice will affect them. The EPA anticipates, however, 

that questions will arise regarding certain aspects of this 

proposal. Because some instances involve discrete 

judgments, utilities may wish to obtain determinations of 

applicability. The EPA will provide such determinations 

upon request. Such requests should be submitted together 

26 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 N0X control technologies as BACT. 
-98-

with appropriate documentation to the appropriate permitting 

authority. 

Comments regarding applicability determinations have 

previously been addressed in other sections of this 

rulemaking. 

I. Limitation of the Rule 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 CAA 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 particular extent of publicly 

available information, indicate that a revision to the NSR 
p.1 

-99-

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. 
P.2 

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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 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 believe that this rule should be 

expanded at this time but will address this issue in a 
P.3 

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separate rulemaking. Specifically, 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 

v. EPA (D.C. Cir., No. 79-1112). The EPA presently intends 

to propose these NSR revisions by early summer. 

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 CAA-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 
P.4 

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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 for all changes that did not involve 

construction of a new unit or replacement of an existing 

unit. The source population is relatively small and the 

technology in use is relatively uniform. Moreover, utility 

sources are largely regulated by PUC's which evaluate 

anticipated utility growth as part of the regulatory 

oversight process. The fact of Public Utility Commission 

(PUC) review helps 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. 
P.5 

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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. This 

ruling is not a major rule because it will reduce the 

economic costs of meeting the requirements of the CAA. 

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 

certain data to agencies for 5 years following a change and 

for documenting excluded demand growth, 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, 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 
P.6 

-104-

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 CAA (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 

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

Procedures Act, 5 U.S.C. 553(d), for a 30-day waiting period 
P.7 

-105-

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 Amendments, EPA 

considers all of the above requirements to be met. 

Lists of Subjects 

40 CFR part 51 
P.8 

-106-

Administrative procedure and practices, 

Intergovernmental relations, Air pollution control, NSR, 

Clean Coal Technology projects, .Sulfur oxides, Nitrogen 

dioxide, Particulate matter, Carbon monoxide, Hydrocarbons, 

Lead. 
P.9 

-107-

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 1990 

Amendments, Pub. L. No. 101-549, 104 Stat. 2399 (Nov. 15, 

1990); 402, 409, 415 of the CAA as amended, 104 Stat. 2399; 

42 U.S.C. 7401-7642 as amended by the 1990 Amendments, 

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 

1990 Amendments, Pub. L. 101-549, 104 Stat. 2399 (Nov. 15, 

1990; 402, 409, 415 of the CAA as amended, 104 Stat. 2399, 

unless otherwise noted. 
P.10 

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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 1990 

Amendments, Pub. L. No. 101-549, 104 Stat. 2399 (Nov. 15, 

1990); 402, 409, 415 of the CAA 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) * 

(1) * 

(v) * 

* 

* 

* 

* 

* 

* 

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

operation shall not include: 
P.11 

-109-

(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, or 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.12 

-110-

(i) the SIP for the State in which the project is 

located, and 

(ii) other requirements necessary to attain and 

maintain the national ambient air quality standard 

during the project and after it is terminated. 

(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 

submits to the permitting authority, on an annttal basis 
P.13 

-111-

fcflr, a" period of 5 years i"com the date* the unit resumes 

tegular operation, information demonstrating that the 

physical or operational change did Hot result in an 

emissions increase* A longer period, not to exceed 10 

years, may be required by the permitting authority if 

it determines such a period to be more representative 

at norml source post-ohan^ operation*. 

(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 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 

10 years after that change, where the permitting authority 

determines that such period is more representative of normal 
P.M 

-112-

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 could have been 

accommodated during the representative baseline 

period and 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.15 

-113-

(xxii) "Temporary clean coal technology demonstration 

project" means a CTT demonstration project that is operated 

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

SIP for the State in which the project is located and other 

requirements necessary to attain and maintain the national 

ambient air quality standard 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 

qualifying project shall be at least 20 percent of the total 

cost of the demonstration project. 
P.16 

-114-

(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 1990 

Amendments, 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 

(iv) is otherwise in compliance with the requirements 

of the Clean Air Act. 
P.17 

-115-

(xxvi) "Pollution control project" means any activity 

or project at an existing electric utility steam generating 

unit for purposes of reducing emissions from such unit. 

Such activities or projects 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) an activity or project to accommodate switching to 

a fuel which is less polluting than the fuel used prior 

to the activity or project, 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 
P.18 

-116-

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, 

replacement, or use renders the unit less 

environmentally beneficial, or except: 
P.19 

-117-

(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. 

(j) The installation, operation, cessation, or 

removal of a temporary clean coal technology 
-118-

demonstration project, provided that the project 

complies with: 

(i) the State implementation plan for the 

State in which the project is located; and 

P.20 

(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.21 

-119-

(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 the unit resumes 

regular operationr information demonstrating that the 

physical or operational change did not result in an 

emissions increase* A longer period, 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, 

(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 

potential electric output capacity and more than 25 MW 
P.22 

-120-

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 activity or 

project at an existing electric utility steam 

generating unit for purposes of reducing emissions from 

such unit. Such activities or projects 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) an activity or project to accommodate 

switching to a fuel which is less polluting than 

the fuel used prior to the activity or project, 

including but not limited to natural gas or coal 

re-burning, or the co-firing of natural gas and 
P.23 

-121-

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 

representative of normal source operations), 
P.24 

-122-

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 could have been 

accommodated during the representative period and 

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.25 

-123-

(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.26 

-124-

nation ambient air quality standards during and after 

the project is terminated. 

(3 6)(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 DOE. 
P.27 

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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.28 

-126-

(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.29 

-127-

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.30 

-128-

(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, or 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.31 

-129-

(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.32 

-130-

(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 the unit 

resumes tegular operation, information demonstrating 

that the physical or operational change did not result 

in" an"emissions 'increase* A longer period, hot to 

exceed 10s years', may be required by the permitting 

authority if it determines such a period to be more 

representative of normal soured post-change operations! 
P.33 

-131-

(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 activity or 

project at an existing electric utility steam 

generating unit for purposes of reducing emissions from 

such unit. Such activities or projects 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) an activity or project to accommodate 

switching to a fuel which is less polluting than 

the fuel in use prior to the activity or project, 
P.34 

-132-

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 

period within 10 years after that change, where the 
P.35 

-133-

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 could have been 

accommodated during the representative baseline 

period and 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 
P.36 

-134-

electricity demand growth for the utility system 

as a whole. 

(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 

20 percent of the total cost of the demonstration 

project. 

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

means a clean coal technology demonstration project 
P.37 

-135-

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, 

(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 
P.38_ 

-136-

technology demonstration funding as of January 1, 

1991, by the DOE. 

(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 
P.39 

-137-

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. 

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: 

* * * 
P.40 

-138-

(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, or 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: 
P.41 

-139-

(1) the State implementation plan for the State in 

which the project is located, and 

(2) other requirements 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. 

(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 
-140-

andf submits' to' the permitting authority, oa' an annual 

SS S \ S S *• • • . SSSSS S " * \ f . % 

bai'is for "-a period of 5 Years from the date the unit 

s .. v.. * s s s s s^ ^ s s s 

resumes regular operation, information demonstrating 

that the physical or operational change did not iresult 

in an emissions increase* A longer period, not to 

exceed 10 .years, may be" required by the permitting 

authority if £t determines such a period to be mare. 

ss^s'*' - v * .• v •. SSS 

representative of normal source post-change operations. 

(18) "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. 

(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 
P.43 

-141-

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 could have 

been accommodated during the representative baseline 

period and 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 
P.44 

-142-

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 

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. 
P.45 

-143-

(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; 

(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. 
-144-

(24) "Pollution control project" means any activity or 

project at an existing electric utility steam generating 

unit for purposes of reducing emissions from such unit. 

Such activities or projects 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) an activity or project to accommodate switching to 

a fuel which is less polluting than the fuel in use 

prior to the activity or project including, but not 

limited to natural gas or coal re-burning, 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 
P.47 

• . 

'.> 

-145-

appropriations for the Environmental Protection Agency; 

or 

(iv) a permanent clean coal technology demonstration 

project that constitutes a repowering project. 
P.48 

. ft | 

-146-

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.49 

«. 

» 

-147-

"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.50 

t 

-148-

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 
-149-

(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 

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 

Environmental Protection Agency) 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. 
-150-

(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.53 

-151-

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.