Appendix — Environmental Protection Agency v. New York, 127 S. Ct. 2127 (2007) (No. 06-736)

Supreme Court brief2007

Ask Donna

What actually matters in this document.

Text

Supreme Co

8 Fi as U.S.

06-736 Nov 27 2098

No. OFFICE OF THE cy BRK

In the Supreme Court of the Gnited States

UNITED STATES ENVIRONMENT PROTECTION

AGENCY, PETITIONER.

i Vv.

STATE OF NEW YORK, ET AL.

ON PETITION FOR A WRIT OF CERTIORARI

TO THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

APPENDIX TO THE

PETITION FOR WRIT OF CERTIORARI

PAUL D. CLEMENT

Solicitor General

Counsel of Record

SUE ELLEN WOOLDRIDGE

Rocse ap rsesaide yom ; Assistant Attorney General

cting General Counse THOMAS G. HUNGER

Counsel of Record UD

ELLIOTT B. ZENICK Deputy Solicitor General

Assistant General Counsel JAMESA. FELDMAN _

j CA eh Assistant to the Solicitor

ctu C. Avannacs Geneval

United States Environmental THOMAS A. LORENZEN

Protection Agency ANGELINE PURDY

Washington, D.C. 20460 Attorneys

Department of Justice

Washington, D.C. 20530-0001

(202) 514-2217

TABLE OF CONTENTS

Page

Appendix A (court of appeals opinion, dated Mar. 17,

UTTER TUEUNEG ida svawesceeetcecrpsccces la

Appendix B (court of appeals’ denial of rehearing,

EE, abc vieecescrrecccevsccers 18a

Appendix C (rules and regulations (40 C.F .R. Pts. 51,

UPC EET asa dedcdodccecvccccecceescces 20a

(I)

APPENDIX A

UNITED STATES COURT OF APPEALS

DISTRICT OF COLUMBIA CIRCUIT

Nos. 03-1380, 03-1381, 03-1383, 03-1390,

03-1402, 03-1453, 03-1454, 04-1029,04-1035, 04-1064,

05-1234, 05-1287

STATE OF NEW YORK, ET AL., PETITIONERS

ENVIRONMENTAL PROTECTION AGENCY, RESPONDENT

CLEAN AIR IMPLEMENTATION PROJECT, ET AL.,

INTERVENORS

Argued Feb. 8, 2006.

Decided March 17, 2006.

Rehearing en Bane Denied June 30, 2006

Before: ROGERS, TATEL and BROWN, Circuit Judges.

Opinion for the Court filed by Circuit Judge ROGERS

’ ROGERS, Circuit Judge.

(la)

In New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005)

(“New York I”), the court addressed the first of two

rules promulgated by the Environmental Protection

Agency providing ways for stationary sources of air pol-

lution toe avoid triggering New Source Review (“NSR”).

The court upheld in part and vacated in part the first

rule. /d. at 10-11. We now address the second rule, the

Equipment Replacement Provision (“ERP”), which

amends the Routine Maintenance, Repair, and Replace-

ment Exclusion (““RMRR”) from NSR requirements.

Under section 111(a)(4) of the Clean Air Act, 42 U.S.C.

§ 7411(a)(4), sources that undergo “any physical change”

that increases emissions are required to undergo the

NSR permitting process. See also id. §§ 7501(4),

7479(2)(C)(cross-referencing id. § 7411(a)(4)). The ex-

clusion has historically provided that routine mainte-

nance, repair, and replacement do not constitute

changes triggering NSR. The ERP both defined and

expanded that exclusion. EPA explained:

[The] rule states categorically that the replacement

of components with identical or functionally equiva-

lent components that do not exceed 20% of the re-

placement value of the process unit and does not

change its basic design parameters is not a change

and is within the RMRR exclusion.

Equipment Replacement Provision of the Routine Main-

tenance, Repair and Replacement Exclusion, 68 Fed.

Reg. 61,248, 61,270 (Oct. 27, 2003) (“Final Rule”); see

also 70 Fed. Reg. 33,838 (June 10, 2005) (“Reconsidera-

tion”). Hence, the ERP would allow sources to avoid

NSR when replacing equipment under the twenty-per-

cent cap notwithstanding a resulting increase in emis-

sions. The court stayed the effective date of the ERP on

December 24, 2003. We now vacate the ERP because it

is contrary to the plain language of section 111(a)(4) of

the Act.

The Clean Air Act requires new and modified sources

of pollution to undergo NSR, a permitting process that

imposes specific pollution control requirements depend-

ing upon the geographic location of the source.' Section

111(a)(4) of the Act describes when a source is to be con-

sidered “modified”:

The term “modification” means any physical change

in, or change in the method of operation of, a station-

ary source which increases the amount of any air pol-

lutant emitted by such source or which results in the

emission of any air pollutant not previous emitted.

42 U.S.C. § 7411(a)(4) (emphasis added). Since the in-

ception of NSR, RMRR has been excluded from the de-

finition of “modification.” See 39 Fed. Reg. 42,510,

42,514 (Dec. 5, 1974); 43 Fed. Reg. 26,388, 26,403-04

(June 19, 1978). Heretofore, EPA applied the RMRR

exclusion through “a case-by-case determination by

' NSR consists of two programs: prevention of significant deteriora-

tion (“PSD”) and nonattainment NSR. See New York I, 413 F.3d at 11-

14. New and modified sources in attainment areas, i.e., where air

quality standards have been met, and in unclassifiable areas are

required to follow PSD rules, which means they must obtain a precon-

struction permit, prove that the construction will not cause violations of

certain air quality standards, and show that their operations are in

compliance with the Best Available Control Technology (“BACT”) re-

quirements. See 42 U.S.C. § 7475. In nonattainment areas, i.e., where

air quality standards have not been met, new and modified sources are

required to obtain preconstruction permits, to offset emissions

increases with emissions reductions from other sources in the area, and

to install “lowest achievable emissions rate” technology (“LAER”). See

id. § 7503.

weighing the nature, extent, purpose, frequency, and

cost of the work as well as other factors to arrive at a

common sense finding.” 67 Fed. Reg. 80,290, 80,292-93

(Dec. 31, 2002). Consistent with Alabama Power Co. v.

Costle, 636 F.2d 323 (D.C. Cir. 1979), which recognized

EPA’s discretion to exempt from NSR “some emission

increases on grounds of de minimis or administrative

necessity,” id. at 400, EPA has for over two decades de-

fined the RMRR exclusion as limited to “de manims

circumstances.” 68 Fed. Reg. at 61,272. The ERP pro-

vides a bright-line rule and expands the traditional

scope of the RMRR by exempting certain equipment

replacements from NSR. See, e.g., 40 C.F.R.

§ 52.21(ce)(2005)."

> The ERP provides:

Without regard to other considerations, routine maintenance,

repair and replacement includes, but is not limited to, the replace-

ment of any component of a process unit with an identical or

functionally equivalent component(s), and maintenance and repair

activities that are part of the replacement activity, provided that all

of the requirements in paragraphs (cce)(1) through (cc)(3)of this

section are met.

40 C.F.R. § 52.21(ece). Paragraph (ec)(1) establishes that the fixed

capital cost of the replacement component cannot exceed twenty

percent of the replacement value of the process unit. Paragraph (ce)(2)

states that the replacement cannot change the basic design parameters

of the process unit. Paragraph (ec)(3) requires that the replacement

activity not cause the process unit to exceed any independent, legally

enforceable emission limitation. The ERP also amends 40 C.F.R. §§

51.165, 51.166, and 52.24, but given the similarity of the sections, the

court will follow the practice of the parties in citing only section 52.21.

The government and environmental petitioners con-

tend that the ERP is contrary to the plain text of the Act

because the statutory definition of “modification” ap-

plies unambiguously to any physical change that in-

creases emissions, necessarily including the emission-

increasing equipment replacements excused from NSR

by the rule. They maintain that the word “any,” when

given its natural meaning, requires that the phrase

“physical change” be read broadly, such that EPA’s at-

tempt to read “physical change” narrowly would rele-

gate the word “any” to an insignificant role.

In evaluating the petitioners’ contention, we proceed

under the familiar two-part test of Chevron, U.S.A., Inc.

v. Natural Resources Defense Council, Inc., 467 U.S.

837, 104 S. Ct. 2778, 81 L.Ed.2d 694 (1984). If “Con-

gress has directly spoken to the precise question at issue

. . . that is the end of the matter; for the court, as well

as the agency, must give effect to the unambiguously

expressed intent of Congress.” /d. at 842-43, 104 S. Ct.

2778. Only if the statute is silent or ambiguous do we

defer to the agency’s interpretation, asking “whether [it]

is based on a permissible construction of the statute.”

Id. at 843, 104 S. Ct. 2778. “Ifa court, employing tradi-

tional tools of statutory construction, ascertains that

Congress had an intention on the precise question at

issue, that intention is the law and must be given effect.”

Id. at 843 n. 9, 104 S. Ct. 2778.

The petitioners and EPA agree that the phrase

“physical change” is susceptible to multiple meanings,

each citing dictionary definitions. However, “the sort of

ambiguity giving rise to Chevron deference ‘is a creature

not of definitional possibilities, but of statutory context.’

“American Bar Ass’n v. FTC, 430 F.3d 457, 469 (D.C.

Cir. 2005) (quoting Brown v. Gardner, 513 U.S. 115, 118,

115 S. Ct. 552, 1380 L.Ed.2d 462 (1994)); see California

Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 400

(D.C. Cir. 2004); Cincinnati Ins. Co. v. Flanders Elec.

Motor Serv., Inc., 40 F.3d 146, 152 (7th Cir. 1994). As

the parties point out, the ordinary meaning of “physical

change” includes activities that “make different in some

particular,” “make over to a radically different form,” or

“replace with another or others of the same kind or

class.” WEBSTER’S THIRD NEW INTERNA-

TIONAL DICTIONARY 373 (1981). To say that it is

“physical,” in this context, indicates that the change

must be “natural or material,” rather than “mental,

moral, spiritual, or imaginary.” /d. 1706. The parties

agree that in “[rJeal-world, common-sense usage,” 68

Fed. Reg. at 61,271, “physical change” includes equip-

ment replacements. They further agree that the ERP

would excuse from NSR requirements certain emission-

increasing activities that EPA has historically consid-

ered to be “physical changes.” See id. at 61,270.

The parties’ essential disagreement, then, centers on

the effect of Congress’s decision in defining “modifica-

tion” to insert the word “any” before “physical change.”

According to the petitioners, the word “any” means that

the phrase “physical change” covers any activity at a

source that could be considered a physical change that

increases emissions. According to EPA, “any” does

nothing to resolve ambiguity in the phrase it modifies.

EPA maintains that because “physical change” is “sus-

ceptible to multiple meanings,” 7d. at 61,271, “identify-

ing activities that are ‘changes’ for NSR purposes .. .

requires an exercise of Agency expertise,” “the classic

situation in which an agency is accorded deference un-

der Chevron,” id. at 61,272. Under this approach, once

EPA has identified an activity as a “physical change,”

the word “any” requires that the activity be subject to

NSR. We conclude that the differences between the par-

ties’ interpretations of the role of the word “any” are

resolved by recognizing that “[rJead naturally, the word

‘any’ has an expansive meaning, that is, ‘one or some

indiscriminately of whatever kind,’” United States v.

Gonzales, 520 U.S. 1, 5, 117 S. Ct. 1032, 137 L.Ed.2d 132

(1997), and that courts must give effect to each word of

a statute, see, e.g., TRW, Inc. v. Andrews, 534 U.S. 19,

31, 122 S. Ct. 441, 151 L.Ed.2d 339 (2001). Because Con-

gress used the word “any,” EPA must apply NSR when-

ever a source conducts an emission-increasing activity

that fits within one of the ordinary meanings of “physi-

cal change.”

In a series of cases, the Supreme Court has drawn

upon the word “any” to give the word it modifies an “ex-

pansive meaning” when there is “no reason to contra-

vene the clause’s obvious meaning.” Norfolk S. Rwy. Co.

v. Kirby, 543 U.S. 14, 31-32, 125 S. Ct. 385, 160 L.Ed.2d

283 (2004); see also Dep’t of Hous. and Urban Dev. v.

Rucker, 535 U.S. 125, 180-31, 122 S. Ct. 1230, 152

L.Ed.2d 258 (2002); Gonzales, 520 U.S. at 5, 1175S. Ct.

1032. Indeed, the Court has read the word “any”

to signal expansive reach when construing the

Clean Air Act. In Harrison v. PPG Industries, Inc., 446

U.S. 578, 100 S. Ct. 1889, 64 L.Ed.2d 525 (1980), the

Court resolved a jurisdictional dispute under section

307(b)(1) by interpreting the phrase “any other final

action,” which the Court “discern[ed to have] no uncer-

tainty.” Jd. at 588, 100 S. Ct. 1889. The Court never

suggested that the term “final action” was itself devoid

of multiple meanings depending on the context, but

rather stated that when Congress amended the Act in

1977, “it expanded its ambit to include not simply “other

final action,’ but rather “any other final action.’” /d. at

589, 100 S. Ct. 1889. “[I]n the absence of legislative his-

tory to the contrary;” the Court held that the statutory

phrase “must be construed to mean exactly what it says,

namely, any other final action.” /d.

Although EPA is correct that the meaning of “any”

can differ depending upon the statutory setting, see

Niwxon v. Missouri Mun. League, 541 U.S. 125, 182, 124

S. Ct. 1555, 158 L.Ed.2d 291 (2004), the context of the

Clean Air Act warrants no departure from the word’s

customary effect. Unlike Nixon, the question of statu-

tory interpretation here does not arise in a setting in

which the Supreme Court has required heightened stan-

dards of clarity to avoid upsetting fundamental policies.

See id. at 132-33, 140-41, 124 S. Ct. 1555 (citing Gregory

v. Ashcroft, 501 U.S. 452, 111 S. Ct. 2395, 115 L.Ed.2d

410 (1991)). EPA points to no “strange and indetermi-

nate results,” id. at 133, 124 S. Ct. 1555 that would

emerge from adopting the natural meaning of “any” in

section 111(a)(4) of the Act. Given Congress’s goal in

adopting the 1977 amendments of establishing a balance

between economic and environmental interests, see Wis-

consin Elec. Power Co. v. Reilly, 893 F.2d 901, 909-10

(7th Cir. 1990) (““WEPCo”), it is hardly “farfetched,”

Nixon, 541 U.S. at 138, 1248S. Ct. 1555, for Congress to

have intended NSR to apply to any type of physical

change that increases emissions. In this context, there

is no reason the usual tools of statutory construction

should not apply and hence no reason why “any” should

not mean “any.” Indeed, EPA’s interpretation would

produce a “strange,” if not an “indeterminate,” result: a

law intended to limit increases in air pollution would

allow sources operating below applicable emission limits

to increase significantly the pollution they emit without

government review.

Even without specific reliance on the effect of “any,”

this court has construed the definition of “modification”

broadly. In Alabama Power, the court explained that

“the term ‘modification’ [in section 111(a)(4) ]is nowhere

limited to physical changes exceeding a certain magni-

tude.” 636 F.2d at 400. Although the legislative history

indicated that one Senator intenced the term to apply

only to “major expansion program[s],” id. at 400 n.47,

the court observed that “the language of the statute

clearly did not enact such limit into law,” zd. at 400. The

court further observed that “[iJmplementation of the

statute’s definition of ‘modification’ will undoubtedly

prove inconvenient and costly to affected iridustries; but

the clear language of the statute unavoidably imposes

these costs except for de minimis increases.” Id. More

recently, in New York J, the court looked to the plain

meaning of section 111(a)(4) and the absence of contrary

legislative history in holding that even pollution control

projects constituted “physical changes.” New York J,

413 F.3d at 40-42. Likewise, the Seventh Circuit con-

cluded in WE PCo that the purposes of the 1977 amend-

ments to the Act required an expansive reading of the

plain language of section 111(a)(4). See WEPCo, 893

F.2d at 908-10.

EPA’s attempt to avoid the persuasive force of these

decisions and to find ambiguity in the phrase “any physi-

cal change” fails for a variety of reasons. Even assum-

ing that the decisions construing section 111(a)(4) are

not “judicial precedent holding that the statute unam-

biguously forecloses the agency’s interpretation,” Nat’

Cable & Telecomms. Ass’n v. Brand X Internet Servs.,

10a .

--- U.S. ----, ----, 125 S. Ct. 2688, 2700, 162 L.Ed.2d 820

(2005), Brand X, on which EPA principally relies, does

not drain those decisions of all precedential value. The

fact that previous judicial interpretations of section

111(a)(4) have all reached the conclusion that the text

must be read broadly supports the petitioner’s argument

at Chevron step one, particularly because those

decisions--both before and after Chevron--used language

indicating the text was “clear” and “plain.” See New

York J], 413 F.3d at 40; WEPCo, 893 F.2d at 907; Ala-

bama Power, 636 F.2d at 400.

Even in the absence of such precedent, EPA’s ap-

proach to interpreting “physical change,” as well as a

similar approach by industry intervenors that focuses on

the thirty-nine words following “any,” contravenes sev-

eral rules of statutory interpretation. EPA’s position is

that the word “any” does not affect the expansiveness of

the phrase “physical change”; it only means thax, once

the agency defines “change” as broadly or as narrowly

as it deems appropriate, everything in the agency-de-

fined category is subject to NSR. To begin, that reading,

contrary to “a cardinal principle of statutory construc-

tion,” would make Congress’s use of the word “any” “in-

significant” if not “superfluous.” TRW, 534 U.S. at 31,

122 S. Ct. 441 (quoting Duncan v. Walker, 533 U.S. 167,

174, 121 S. Ct. 2120, 150 L.Ed.2d 251 (2001)). Reading

the definition in this way makes the definition function

as if the word “any” had been excised from section

111(a)(4); there is virtually no role for “any” to play.

Additionally, the approaches of EPA and industry would

require Congress to spell out all the applications cov-

ered by a definition before a court could conclude that

Congress had directly spoken regarding a particular

application, ignoring the fact that a definition, like a

lla

general rule, need not list everything it covers. See Na-

tional Public Radio, Inc. v. FCC, 254 F.3d 226, 229

(D.C. Cir. 2001); see also Shays v. FEC, 414 F.3d 76,

108 (D.C. Cir. 2005). EPA’s approach would ostensibly

require that the definition of “modification” include a

phrase such as “regardless of size, cost, frequency, ef-

fect,” or other distinguishing characteristic. Only in a

Humpty Dumpty world’ would Congress be required to

use superfluous words while an agency could ignore an

expansive word that Congress did use. We decline to

adopt such a world-view.

In contrast, the petitioners’ approach, by adopting an

expansive reading of the phrase “any physical change,”

gives natural effect to all the words used by Congress

and reflects both their common meanings and Con-

gress’s purpose in enacting the 1970 and 1977 amend-

ments. See New York I, 413 F.3d at 11-13; WEPCo, 893

F.2d at 909. To improve pollution control programs in

a manner consistent with the balance struck by Con-

gress in 1977 between “the economic interest in permit-

ting capital improvements to continue and the environ-

mental interest in improving air quality,” Chevron, 467

U.S. at 851, 104 S. Ct. 2778, Congress defined the phrase

“physical change” in terms of increases in emissions.

After using the word “any” to indicate that “physical

change” covered all such activities, and was not left to

agency interpretation, Congress limited the scope of

“any physical change” to changes that “increase [ ] the

amount of any air pollutant emitted by such source or

which result [ ] in the emission of any air pollutant not

* See TVA v. Hill, 437 U.S. 153, 173 n.18, 98 S. Ct. 2279, 57 L.Ed.2d

117 (1978) (quoting Through the Looking Glass, in THE COMPLETE

WORKS OF LEWIS CARROLL 196 (1939)).

12a

previously emitted.” 42 U.S.C. § 7411(a)(4). Thus, only

physical changes that do not result in emission increases

are excused from NSR. Because Congress expressly

included one limitation, the court must presume that

Congress acted “intentionally and purposely,” Barnhart

v. Sigmon Coal Co., 584 U.S. 438, 452, 122 S. Ct. 941, 151

L.Ed.2d 908 (2002) (quoting Russello v. United States,

464 U.S. 16, 23, 104 S. Ct. 296, 78 L.Ed.2d 17 (1983)),

when it did not include others. Cf. New York 1, 413 F.3d

at 39. So construed, each word in the phrase “any physi-

cal change” has a meaning consonant with congressional

intent and the scope of the definitional phrase is limited

only by Congress’s determination that such changes be

linked to emission increases.

The expansiveness of the petitioners’ approach does

not leave the definition of “any physical change” without

limits. The modifier “any” cannot bring an activity that

is never considered a “physical change” in ordinary us-

age within the ambit of NSR. But when Congress places

the word “any” before a phrase with several common

meanings, the statutory phrase encompasses each of

those meanings; the agency may not pick and choose

among them. EPA, through its historical practice and

its words, has acknowledged that the equipment replace-

ments covered by the ERP are “physical changes” under

one of the ordinary meanings of the phrase. See 68

Fed.Reg. at 61,271-72. EPA may not choose to exclude

that “[rJeal-world, common-sense usage of the word

‘change.’” /d. at 61,271. Moreover, a physical change is

not the sole criterion for triggering NSR under the defi-

nition of “modification.” The expansive meaning of “any

physical change” is strictly limited by the requirement

13a

that the change increase emissions. See 42 U.S.C.

§ 7411(a)(4)."

The fact that EPA, through, the RMRR exclusion,

has historically interpreted “any physical change” to

exclude changes of trivial regulatory concern on a de

minimis rationale, see Alabama Power, 636 F.2d at 360-

61, does not demonstrate that the meaning of “physical

change” is ambiguous. Rather, it reflects an agency’s

inherent power to overlook “trifling matters,” id. at 360,

a “principle [that] is a cousin of the doctrine that, not-

withstanding the ‘plain meaning’ of a statute, a court

must look beyond the words to the purpose of the act

where its literal terms lead to ‘absurd or futile results,”

id. at 360 n.89 (citations omitted). As the Supreme

Court has instructed, “the venerable maxim de minimis

non curat lex (‘the law cares not for trifles’) is part of

the established background of legal principles against

which all enactments are adopted, and which all enact-

ments (absent contrary indication) are deemed to ac-

cept.” Wisconsin Dep't of Revenue v. William Wrigley,

Jr., Co., 505 U.S. 214, 231, 112 S. Ct. 2447, 120 L.Ed.2d

174 (1992). Reliance on the de minimis doctrine invokes

congressional intent that agencies diverge from the

plain meaning of a statute only so far as is necessary to

avoid its futile application. Thus, the court in Alabama

Power acknowledged that “EPA does have discretion, in

administering the statute’s ‘modification’ provision, to

exempt from PSD review some emission increases on

grounds of de minimis or administrative necessity.” 636

* The court has no occasion to decide whether part replacements or

repairs necessarily constitute a “modification” under the definition

taken as a whole.

14a

F.2d at 400. As applied, the court explained that de

minimis standards served to alleviate “severe” adminis-

trative and economic burdens by lifting requirements on

“minuscule” emission increases. See id. at 405. While

the court today expresses no opinion regarding EPA’s

application of the de minimis exception, given the limits

on the scope of the de minimis doctrine, see Shays, 414

F.3d at 113-14, EPA appropriately has not attempted to

justify the ERP as an exercise of de minimis discretion.

As EPA has disclaimed the assertion that its prior ex-

pansive interpretations of “any physical change” were

“absurd or futile,” 70 Fed. Reg. at 33,842, it is in no posi-

tion to claim that the ERP is necessary to avoid absur-

dity.

EPA’s remaining arguments also fail to demonstrate

that the phrase “any physical change” is ambiguous.

The fact that the court concluded that the word “in-

creases” in section 111(a)(4) is ambiguous, see New York

1, 413 F.3d at 23, does not suggest that the phrase

“any physical change” is also ambiguous; unlike the

latter, the former is unaccompanied by a qualifier sig-

naling Congress’s intent. Congress’s use of the word

“increases” necessitated further definition regarding

rate and measurement for the term to have any contex-

tual meaning. No such further definition of “physical

change” is required because Congress’s use of the word

“any” indicates the intent to cover all of the ordinary

meanings of the phrase, as evidenced by EPA’s decades-

long understanding and practice. Also, because the

court in New York J rejected industry’s contention that

Congress ratified the New Source Performance Stan-

dards (“NSPS”) regulations on “modification” in the

1977 amendments, see id. at 19-20, EPA’s reliance on its

NSPS regulations to demonstrate the ambiguity of “any

15a

physical change” is unavailing. As discussed, the early

emergence of a RMRR exclusion based on a de minimis

rationale does not blur the clarity of the phrase “any

physical change.” To the extent industry intervenors

rely on the NSPS regime to reargue their position that

“modifications” require an increase in maximum emis-

sion rates, that issue was resolved in New York I, 413

F.3d at 19-20, 40; see also New York v. EPA, 431 F.3d

801, 802-03 (D.C. Cir. 2005) (Williams, J., concurring in

denial of rehearing), and is irrelevant because it does

not address what constitutes a “physical change.”

“Therefore, for EPA to avoid a literal interpretation

at Chevron step one, it must show either that, as a mat-

ter of historical fact, Congress did not mean what it ap-

pears to have said, or that, as a matter of logic and stat-

utory structure, it almost surely could not have

meant it.” Hngine Mfrs. Ass’n v. EPA, 88 F.3d 1075,

1089 (D.C. Cir. 1996). The discussion in New York I, 413

F.3d at 12-13, and WEPCo, 893 F.2d at 909 (quoting

H.R. REP. No. 95-294, at 211, (1977), as reprinted in

1977 U.S.C.C.A.N: 1077, 1290), of Congress’s basic goals

in enacting the 1977 amendments—to intensify the war

against air pollution, to establish a permit program that

struck a balance between economic and environmental

interests, and to stimulate technology to control pollu-

tion—demonstrate the futility of EPA’s endeavor. EPA

cannot show that historical fact prevents a broad read-

ing of “any physical change” inasmuch as EPA for de-

cades has interpreted that phrase to mean “virtually all

changes, even trivial ones, . . . generally interpret[ing]

the [RMRR] exclusion as being limited to de minimis

circumstances.” 68 Fed.Reg. at 61,272.

16a

As for logic, EPA cannot show any incoherence in

Congress requiring NSR for equipment replacements

that increase emissions while allowing replacements that

do not increase emissions to avoid NSR. EPA acknowl-

edges the reasonableness of its past expansive interpre-

tation of “any physical change.” See id.; 70 Fed Reg. at

33,842; Respondent’s Br. at 29. To the extent that EPA

relies on the argument that allowing ERP projects has

the potential to lower overall emissions through in-

creased efficiency even if emissions increase at a source,

the court in New York I rejected EPA’s similar argu-

ment in support of an exemption from NSR for pollution

- control projects. The court stated that “Congress could

reasonably conclude, for example, that tradeoffs be-

tween pollutants are difficult to measure, and thus any

significant increase in emissions of any pollutant should

be subject to NSR.” New York J, 413 F.3d at 41. Absent

a showing that the policy demanded by the text borders

on the irrational, EPA may not “avoid the Congressional

intent clearly expressed in the text simply by asserting

that its preferred approach would be better policy.”

Engine Mfrs., 88 F.3d at 1089.

Likewise, EPA offers no reason to conclude that the

structure of the Act supports the conclusion that “any

physical change” does not mean what it says. EPA does

not address the Act’s structure except in defending the

reasonableness of the ERP as a policy choice. In that

context, EPA points to the Act’s “many other systematic

air programs,” particularly “model market-based pro-

grams,” as support for its view that economic and envi-

ronmental interests can be effectively balanced while

limiting the application of NSR to existing sources. See

70 Fed. Reg. at 33,844. Although EPA might prefer

17a

_market-based methods of controlling pollution, Con-

gress has chosen a different course with NSR.

Accordingly, we hold that the ERP violates section

111(a)(4) of the Clean Air Act in two respects. First,

Congress’s use of the word “any” in defining a “modifi-

cation” means that all types of “physical changes” are

covered. Although the phrase “physical change” is sus-

ceptible to multiple meanings, the word “any” makes

clear that activities within each of the common meanings

of the phrase are subject to NSR when the activity re-

sults in an emission increase. As Congress limited the

broad meaning of “any physical change,” directing that

only changes that increase emissions will trigger NSR,

no other limitation (other than to avoid absurd results)

can be implied. The definition of “modification,” there-

fore, does not include only physical changes that are

costly or major. Second, Congress defined “modifica-

tion” in terms of emission increases, but the ERP would

allow equipment replacements resulting in non-de

minimis emission increases to avoid NSR. Therefore,

because it violates the Act, we vacate the ERP.

18a

APPENDIX B

UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

No. 03-1380

CONSOLIDATED WITH 03-1381, 03-1383, 03-1390,

03-1402, 03-1453, 03-1454, 04-1029, 04-1035,

04-1064, 05-1234, 05-1287

September Term, 2005

STATE OF NEW YORK, ET AL.,

PETITIONERS

ENVIRONMENTAL PROTECTION AGENCY,

RESPONDENT

CLEAN AIR IMPLEMENTATION PROJECT, ET AL.,

INTERVENORS

[Filed On: June 30, 2006]

Before: ROGERS, TATEL, and BROWN, Circuit Judges.

19a

ORDER

Upon consideration of respondent’s petition for re-

hearing filed May 1, 2006, it is

ORDERED that the petition be denied.

PER CURIAM

FOR THE COURT:

MARK J. LANGER, clerk

BY:

MICHAEL C. McGRAIL

Deputy clerk

* Circuit Judge Kavanaugh did not participate in this

matter.

20a

APPENDIX C

RULES AND REGULATIONS

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51 and 52

[F RL-7575-9; RIN 2060-AK28; Electronic Docket

OAR-2002-0068; Legacy Docket A-2002-04 |

Prevention of Significant Deterioration (PSD) and

Non-Attainment New Source

Review (NSR): Equipment Replacement Provision

of the Routine Maintenance,

Repair and Replacement Exclusion

[Monday, October 27, 2003]

AGENCY: Environmental Protection Agency

(EPA).

ACTION: Final rule.

SUMMARY: The EPA is finalizing revisions to the

regulations governing the NSR programs mandated by

parts C and D of title I of the Clean Air Act (CAA). To-

day’s changes reflect EPA’s incorporation of comments

from the proposed rule for “Prevention of Significant

Deterioration (PSD) and Non-attainment New Source

2la

Review (NSR): Routine Maintenance, Repair and

Replacement.” These changes provide a category of

equipment replacement activities that are not subject to

Major NSR requirements under the routine mainte-

nance, repair and replacement (RMRR) exclusion. The

changes are intended to provide greater regulatory cer-

tainty without sacrificing the current level of environ-

mental protection and benefit derived from the NSR

program. We believe that these changes will facilitate

the safe, efficient, and reliable operation of affected fa-

cilities.

EFFECTIVE DATE: This final rule is effective on

December 26, 2003.

ADDRESSES: Docket. Docket No. A-2002-04 (Elec-

tronic docket OAR-2002-0068), containing supporting

information used to develop the proposed rule and to-

day’s final rule, is available for public inspection and

copying between 8:00-a.m. and 4:30 p.m., Monday

through Friday (except government holidays) at the Air

and Radiation Docket and Information Center (6102T),

Room B-108, EPA West Building, 1301 Constitution Av-

enue, NW, Washington, D.C. 20460; telephone (202) 566-

1742, fax (202) 566-1741. A reasonable fee may be

charged for copying docket materials.

Worldwide Web (WWW). In addition to being avail-

able in the docket, an electronic copy of this final rule

will also be available on the WWW through the Technol-

ogy Transfer Network (TTN). Following signature, a

copy of the rule will be posted on the TTN’s policy and

guidance page for newly proposed or promulgated rules:

http://www.epa.gov/ttn/oarpg.

FOR FURTHER INFORMATION CONTACT: Mr. Dave

Svendsgaard, Information Transfer and Program Inte-

gration Division (C339-03), U.S. EPA Office of Air Qual-

ity Planning and Standards, Research Triangle Park,

North Carolina 27711, telephone 919-541- 2380, or elec-

tronic mail at svendsgaard.dave@epa.gov, for questions

on this rule.

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities potentially affected by this final action in-

clude sources in all industry groups. The majority of

sources potentially affected are expected,to be in the

following groups:

Industry group SIC* NAICS"

Electric Servi-

“SPI Ns Senet 491 221111, 221112,221113, 2211119,

221122, 2211121,

Petroleum es

OPS Saws ewes as ce 291 324110

Industrial

Inorganic

ee 281 325181, 325120, 325131, 325182,

211112, 325998, 331311, 25188

Industria]

Organic

Chemicals ........... 286 325110,325132, 325192, 325188,

325193, 325120, 325199

23a

Miscellaneous

Chemical

POGUES oo cc cccccvse 289 325520,325920, 325910, 325182,

325510

Natural Gas

SOE ie eas knees 132 211112

Natural Gas

ey ee 492 486210, 221210 -

Pulp and

Paper Mills ......... 261 322110,322121, 322122, 322130

Paper Mills . ......... 262 322121, 322122

Automobile

Manu-

| re 371 336111, 336112, 336211, 336992,

336322, 336312, 336330 336340,

336350, 336399, 336212 336213

Pharm-

SS a ee 283 325411, 325412, 325418, 325414

FNa Standard Industrial Classification.

FNb North American Industry Classification System.

Entities potentially affected by this final action also

include State, local, and tribal governments that are

delegated authority to implement these regulations.

Outline

The information presented in this preamble is orga-

nized as follows:

I. General Information

24a

How can I get copies of this document and

other related information?

Docket

Electronic Access

. Where can I obtain additional information?

. Background

What is the RMRR exclusion?

. Issues surrounding the RMRR exclusion

Process used to develop this rule

What we proposed

Ill. Equipment Replacement Provision

action

Overview and justification for today’s final

What is an identical or functionally equivalent

replacement and why should such an activity be consid-

ered RMRR?

What cost limit has been placed on the equip-

ment replacement approach?

What will be the basis of applying the 20-per-

cent threshold?

What basic design parameters are being estab-

lished to qualify for the equipment replacement provi-

sion?

25a

F. What collection of equipment should be consid-

ered in applying the equipment replacement provision

and how should it be defined?

G. Consideration of non-emitting units as part of

the process unit

H. What is the accounting basis for the process

unit?

I. Enforcement

1. Compliance assurance

2. General issues

J. Quantitative Analysis

K. Consideration of other options

1. Annual Maintenance, repair and replacement

allowance

2. Capacity-based option

3. Age-based option

L. Specific list of excluded activities

M. Stand-alone exclusion for energy efficiency

projects

N. Legal Basis

1. How does the NSR program address existing

sources and why is today’s rule consistent with this ap-

proach?

26a

2. Why today’s rule appropriately implements the

Clean Air Act’s definition of modification

IV. Administrative Requirements for This Rule

A. Executive Order 12866—Regulatory Planning

and Review

B. Executive Order 13132—Federalism

C. Executive Order 13175—Consultation and Co-

ordination with Indian Tribal Governments

D. Executive Order 13045—Protection of Chil-

dren from Environmental Health Risks and Safety

Risks

E. Paperwork Reduction Act

F. Regulatory Flexibility Analysis

G. Unfunded Mandates Reform Act of 1995

H. National Technology Transfer and Advance-

ment Act of 1995

I. Executive Order 13211—Actions Concerning

Regulations That Significantly Affect Energy Supply,

Distribution, or Use

J. Executive Order 12988—Civil Justice Reform

V. Effective Date for Today’s Requirements

VI. Statutory Authority

1. General Information

27a

A. How Can I Get Copies of This Document and

Other Related Information?

1. Docket. The EPA has established an official public

docket for this action under Docket ID No. A-2002-04.

The official public docket consists of the documents spe-

cifically referenced in this action, any public comments

received, and other information related to this action.

Although a part of the official docket, the public docket

does not include Confidential Business Information

(CBI) or other information whose disclosure is re-

stricted by statute. The official public docket is the col-

lection of materials that is available for public viewing at

the EPA Docket Center, (Air Docket), U.S. Environ-

mental Protection Agency, 1301 Constitution Ave., NW.,

Room: B108, Mail Code: 6102T, Washington, DC, 20004.

The EPA Docket Center Public Reading Room is open

from 8:30 a.m. to 4:30 p.m., Monday through Friday,

excluding legal holidays. The telephone number for the

Reading Room is (202) 566-1742. A reasonable fee may

be charged for copying. |

2. Electronic Access. You may access this Federal

Internet under the “Federal Register” listings at

http://www.epa.gov/fedrgstr/.

An electronic version of the public docket is available

through EPA’s electronic public docket and comment

system, EPA Dockets. You may use EPA Dockets at

http://www.epa.gov/edocket/ to submit or view public

comments, access the index listing of the contents of the

official public docket, and to access those documents in

the public docket that are available electronically. Once

28a

in the system, select “search,” then key in the appropri-

ate docket identification number.

Certain types of information will not be placed in the

EPA Dockets. Information claimed as CBI and other

information whose disclosure is restricted by statute,

which is not included in the official public docket, will

not be available for public viewing in EPA’s electronic

public docket. EPA’s policy is that copyrighted material

will not be placed in EPA’s electronic public docket but

will be available only in printed, paper form in the offi-

cial public docket. To the extent feasible, publicly avail-

able docket materials will be made available in EPA’s

electronic public docket. When a document is selected

from the index list in EPA Dockets, the system will

identify whether the document is available for viewing

in EPA’s electronic public docket. Although not all

docket materials may be available electronically, you

may still access any of the publicly available docket ma-

terials through the docket facility identified in section

1.A.1. of this preamble. The EPA intends to work to-

wards providing electronic access to all of the publicly

available docket materials through EPA’s electronic

public docket.

For additionai infermation about EPA’s electronic

public docket visit EPA Dockets online or see 67 FR

38102, May 31, 2002.

29a =“

B. Where Can I Obtain Additional Information?

In addition to being available in the docket, an elec-

tronic copy of today’s final rule is also available on the

WWW through the Technology Transfer Network

(TTN). Following signature by the EPA Administrator,

a copy of this rule will be posted on the T7'N’s policy and

guidance page for newly proposed or promulgated rules

at http://www.epa.gov/ttn/oarpg. The TTN provides in-

formation and technology exchange in various areas of

air pollution control. If more information regarding the

TTN is needed, call the TTN HELP line at (919) 541-

5384.

Il. Background

A. What Is the RMRR Exclusion?

Title I of the Clean Air Act (CAA) established the

New Source Review program’ to help control airborne

emissions from major new stationary sources of pollu-

tion. Under the program, anyone who seeks to construct

a new stationary source that will be a major source of

regulated pollutants must obtain a permit from State

authorities (or, where a State has not established its own

program, from EPA directly) before beginning construc-

tion of the source. In order to obtain the permit, the

owner or operator must, among other things, demon-

strate that the new source will have state-of-the-art pol-

lution control devices.

' We broadly use the term “New Source Review,” or NSR, to

encompass both the PSD and the Non-attainment New Source Review

program.

30a

The NSR program does not generally affect existing

sources, but it does apply if they undergo a “modifica-

tion.” The NSR provisions of the CAA do not create

their own definition of “modification,” instead borrowing

the definition of the term established by section 111 of

the CAA, which defined the term for purposes of the

New Source Performance Standards (NSPS) program.

That definition states that “{t]he term “modification”

means 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.” Under 40 CFR parts 51 and 52, the

rules we have promulgated to carry out the NSR pro-

gram, “major modification” is similarly defined as any

physical change in or change in the method of operation

of a major stationary source that would result in: (1) A

significant emissions increase of a regulated NSR pollut-

ant; and (2) a significant net emissions increase of that

pollutant from the major stationary source.” The regula-

tions further provide that certain activities do not con-

stitute a “physical change or change in the method of

operation” under the definition of “major modification.”

One category of such activities is routine maintenance,

repair and replacement (RMRR). The regulatory provi-

sions excluding RMRR from the definition of change

constitute the RMRR exclusion.

* Once a modification is determined to be major, NSR requirements

apply only to those specific pollutants for which there would be a

significant net emissions increase.

3la

B. Issues Surrounding the RMRR Exclusion

Until today, the NSR regulations have not further

specified what types of activities are encompassed by

the term RMRR. Heretofore, we have applied the

RMRR exclusion exclusively on a case-by-case basis

using a multi-factor test for determining whether a par-

ticular activity falls within or outside the exclusion. We

have made these case-by-case determinations both in

the context of applicability determinations, where a

source or permitting authority has requested EPA’s

guidance concerning whether a particular activity falls

within the exclusion or requires a permit, and in the con-

text of enforcement actions, where we have challenged

an activity undertaken by a source after the fact and the

source has asserted that the activity was permissible

under the exclusion. S

This case-by-case approach has been praised for its

flexibility, but criticized for hampering activities impor-

tant to assuring the safe, reliable and efficient operation

of existing plants. Specifically, some of the case-by-case

determinations we have made, particularly over the past

decade, and particularly in a series of enforcement ac-

tions, have been criticized for giving the exclusion a nar-

row scope that disallows replacement of significant plant

components with identical or functionally equivalent

components. Critics argue that the effect is to discour-

age plant owners or operators from engaging in replace-

ments that are important to restoring, maintaining and

improving plant safety, reliability, and efficiency. They

further argue that this effect is exacerbated by what

they assert are the uncertainties inherent in the case-

by-case approach.

32a

To elaborate on the uncertainty issues: Unless an

owner or operator seeks an applicability determination

from his or her reviewing authority, it can be difficult

for the owner or operator to know with reasonable cer-

tainty whether a particular activity constitutes RMRR.

This gives the owner or operator five choices, two of

which the owner or operator is not likely to select, and

the other three of which have significant drawbacks for

the productivity of the plant.

First, the owner or operator may simply seek an

NSR permit. That course, however, is likely to be time-

consuming and expensive, since it will likely result in a

requirement to retrofit an existing plant with state-of-

the-art pollution controls which often is very costly and

can present significant technical challenges. Therefore,

an owner or operator is not likely to select this option if

it can be avoided.

Second, the owner or operator may proceed at risk

without a reviewing authority determination. That op-

tion, however, is also not likely to be attractive where a

significant replacement activity is involved, because if

the owner or operator proceeds without a reviewing au-

thority determination and if we later find that he or she

made an incorrect determination on its own, the owner

or operator faces potentially serious enforcement conse-

quences. Those consequences could well include sub-

stantial fines (along with the further consequences of

having been determined to be in violation of the CAA)

and penalties and a requirement to install the state-of-

the-art pollution controls, even though those controls

present technical issues or represent a significant

enough expenditure that they likely would have deterred

SE eT ASS TAREE EEE

33a

the owner or operator from seeking a permit in the first

place. The owner or operator is not likely to take this

risk if he or she believes there is a high probability of

these kinds of consequences and if he or she has other

options.

Third, the owner or operator may seek an applicabil-

ity determination. That process, too, is time-consuming

and expensive, albeit typically less so than seeking a

permit. This path presents a potentially significant bar-

rier to today’s global, quick-to-market industries, such

as computer chips, pharmaceuticals, and autos. This

approach also is likely to result in substantial foregone

activities that would enhance the safety, reliability and

efficiency of the plant while awaiting the applicability

determination.

Fourth, the owner or operator may forego or curtail

replacements that would enhance the safe, reliable, or

efficient operation of its plant, instead opting to repair

existing components even though they are inferior to

current day replacements because they likely have dete-

riorated with use and probably are less advanced and

less efficient than current technology. Foregoing the

replacement activities altogether will reduce plant

safety, reliability and efficiency; curtailing or postponing

them does as well, differing only in the degree of these

effects.

Finally, the owner or operator may curtail the plant’s

productive capacity by replacing components with less

than the best technology in order to be more certain that

the replacement is within the RMRR regulatory bounds,

or he or she may agree to limit the source’s hours of op-

eration or capacity or install less than state-of-the-art

34a

air pollution controls to ensure no increase in emissions.

Either of those courses, however, will also result in loss

of plant productivity.

The uncertainties are also problematic for State and

local reviewing authorities. They require those author-

ities to devote scarce resources to make complex deter-

minations, including applicability determinations, and

consult with other agencies to ensure that any determi-

nations are consistent with determinations made for

similar circumstances in other jurisdictions and/or that

other reviewing authorities would concur with the con-

clusion.

Industry commenters strongly echoed these con-

cerns, asserting that the expense and delay associated

with NSR scrutiny, whether or not the activity is ulti-

mately judged to be subject to major NSR, have caused

a number of facilities to forego needed and beneficial

maintenance, repair, and replacement activities, includ-

ing ones that would likely have reduced emissions. In

our June 2002 report to the President, we similarly con-

cluded that the NSR program has impeded or resulted

in the cancellation of projects that would have main-

tained and improved the reliability, efficiency, or safety

of existing energy capacity.

We are persuaded that we should change the ap-

proach to the RMRR exclusion that we have been follow-

ing for equipment replacements. The approach we have

been taking often has not encompassed the replacement

of existing components with identical or similar new

components that serve the same function, that represent

a small fraction of the value of the process unit of which

35a

they are a part, that do not change the process unit’s

basic design parameters, and that do not cause the pro-

cess unit to exceed any emission limitations. For the

reasons noted above, this approach tends to have the

effect of leading sources to refrain from replacing com-

ponents, to replace them with inferior components, or to

artificially constrain production in other ways. We are

persuaded that none of these outcomes advanced the

central policy of the major NSR program as applied to

existing sources, which is not to cut back on emissions

from existing major stationary sources through limita-

tions on their productive capacity, but rather to ensure

that they will install state-of-the-art pollution controls

at a juncture where it otherwise makes sense to do so.

We also do not believe the outcomes produced by the

approach we have been taking have significant environ-

mental benefits compared with the approach we are

adopting today and, indeed, we believe our new ap-

proach may well produce environmental improvements

as compared to the old one.

We are also persuaded that uncertainties surround-

ing the scope of the exclusion that are associated with

the case-by-case approach tend to exacerbate the prob-

lem outlined above. These uncertainties can discourage

replacements that would promote safety, reliability and

efficiency even in instances where, if the matter were

brought to EPA, we would determine that the replace-

ment in question was RMRR. Such discouragement re-

sults in lost capacity and lost opportunities to improve

energy efficiency and reduce air pollution.

We believe that these problems will be significantly

reduced by the rule we are adopting today. This rule

36a

specifies that the replacement of components of a pro-

cess unit with identical components or their functional

equivalents will come within the scope of the exclusion,

provided the cost of replacing the component falls below

20 percent of the replacement value of the process unit

of which the component is a part, the replacement does

not change the unit’s basic design parameters, and the

unit continues to meet enforceable emission and opera-

tional limitations.

Our new equipment replacement approach will allow

owners or operators to replace components under a

wider variety of circumstances than they have been able

to do under our prior RMRR approach. It also provides

more certainty both to source owners or operators who

will be able better to plan activities at their facilities,

and to reviewing authorities who will be able better to

focus resources on other areas of their environmental

programs rather than on time-consuming RMRR deter-

minations. The effect should be to remove disincentives

to undertaking RMRR activities falling within the rule,

thereby enhancing key operational elements such as

efficiency, safety, reliability, and environmental perfor-

mance. For example, we anticipate that improved safety

and reliability will result in more stable process opera-

tions and reduce periods of startup, shutdown, and mal-

function and the increased emissions usually associated

with them. Accordingly, we believe the rule will pro-

mote the central purpose of Title I of the CAA, “to pro-

tect and enhance the quality of the Nation’s air re-

sources so as to promote the public health and welfare

and the productive capacity of its population.” CAA sec-

tion 101.

TORE EAN TEEN EO

37a

We note that we continue to believe that our prior

narrower and entirely case-by-case approach to the

RMRR exclusion was consistent with the relevant lan-

guage of the CAA and a reasonable effort to effectuate

its policies. At the same time, we also believe that the

final rule’s categorical exclusion of certain replacement

activities and the broader definition of RMRR on which

that exclusion is premised are likewise consistent with

the statute’s language and represent a better accommo-

dation of the statute’s twofold ends. We therefore have

decided to »dopt the final rule.

C. Process Used To Develop This Rule

In the 1992 “WEPCO Rule” preamble, we declared

our intent to issue guidance on the subject of RMRR. In

1994, as an outgrowth of meetings with the Clean Air

Act Advisory Committee, we developed, for discussion

purposes only, a preliminary draft that presented pos-

sible ways of how RMRR could be defined. We received

a substantial volume of comments on this document. We

subsequently decided not to include this preliminary

draft approach in our 1996 NSR proposed rulemaking.

In 2001, the President’s National Energy Policy

directed EPA in consultation with the Department of

Energy (DOE) and other Federal agencies to review the

impact of NSR on investment in new utility and refinery

generation capacity, energy efficiency and environmen-

tal protection. Our Report to the President illustrated

the problems associated with our prior case-by-case ap-

proach to identifying RMRR activities and underscored

the advantages of establishing an objective bright-line

approach fev edministering the RMRR provision.

38a

We held conference calls with various stake-

holders during October 2001 (including representatives

from industry, State and local governments, and

environmental groups) to discuss new ideas that were

raised as to how the RMRR provision might be im-

proved. The proposed RMRR rule reflected many of the

ideas discussed in those meetings. Today’s final rule on

the equipment replacement provision is based on careful

consideration of comments received on the proposed

RMRR rule (67 FR 80920, December 31, 2002), where

we sought comment on all aspects of our proposed ap-

proaches. Today’s rule represents final action on only

one part of what we proposed in December 2002—the

equipment replacement provision. We have decided, for

now, not to take final action on the proposed annual

maintenance, repair and replacement allowance ap-

proach.

D. What We Proposed

The RMRR proposal offered for comment two

cost-based approaches for determining what constitutes

routine maintenance, repair, and replacement. Under

the proposal, facilities could have relied on a facility-

wide annual maintenance, repair and replacement allow-

ance and/or an equipment replacement cost threshold to

determine whether major NSR requirements were trig-

gered by performing plant maintenance, repair and re-

placement activities. The proposal additionally outlined

two options based on the capacity and age of a facility.

We solicited comment on all aspects of the proposed ap-

proaches as well as any other viable option for clarifying

the term “routine maintenance, repair, and replace-

ment.” We took public comment on the proposed rule

39a

until May 2, 2003—-120 days following publication in the

Federal Register.

Under the “annual maintenance, repe‘r and

replacement allowance,” an annual maintenance cost

allowance would be established for each industrial facil-

ity based on an industry-specific percentage. For the

percentage, we considered using the Internal Revenue

Service “Annual Asset Guideline Repair Allowance Per-

centages” (AAGRAP), which for years has been used as

an integral part of an exclusion under the New Source

Performance Standard (NSPS) program. A multi-year

allowance approach, in addition to the annual approach,

was also offered for consideration in the proposal.

Safeguards were proposed to ensure that the

types of activities undertaken under the annual allow-

ance are not activities that should be subject to greater

scrutiny. These safeguards include: (1) No new unit

may be installed; (2) no unit may be replaced in its en-

tirety; and (3) changes may not cause an increase in the

short-term emission rate of any regulated NSR pollut-

ant.

Under the “equipment replacement provision,” or

ERP, we proposed to streamline the process for deter-

mining if major NSR permitting requirements apply to

replacement of existing equipment with identical new

equipment or with functionally equivalent equipment.

Per-replacement-of-component(s) thresholds, poten-

tially up to 50 percent of the cost of replacing the pro-

cess unit, were suggested by the proposal. As long as

the threshold was not exceeded and the basic design

40a

parameters remained unchanged, the activity would be

considered RMRR under this approach.

Under the proposal, all activities that fell within

the annual maintenance, repair and replacement allow-

ance or the equipment replacement threshold and that

met all the other criteria for these provisions would be

considered RMRR without further review. Activities

that were unable to be accommodated under the annual

maintenance, repair and replacement allowance or the

equipment replacement threshold could still qualify for

the RMRR exclusion after a case-by-case review in ac-

cordance with current rules.

We solicited comments on all aspects of our

RMRR proposal.

lil. Equipment Replacement Provision

A. Overview and Justification for Today’s Final

Action

Today, we are revising certain provisions of the ma-

jor NSR program by finalizing the equipment replace-

ment provision (ERP) to specify activities that will auto-

matically qualify for the RMRR exclusion. This rule is

effective on December 26, 2003. At this time, we are not

taking action on our proposed annual maintenance, re-

pair and replacement allowance approach.

Although many commenters requested that we fur-

ther clarify the case-by-case approach for determining

whether an activity is RMRR, we are not taking action

on this suggestion at this time. We are still considering

what, if any, changes should be made to that policy. In

4la

the meantime, the case-by-case approach will remain

available for the owner or operator of a source to use as

an alternative and/or supplement to today’s ERP.

Under today’s rule, an activity (or aggregations of

activities) can qualify for the ERP if: (1) It involves re-

placement of any existing component(s)* of a process

unit with component(s) that are identical or that serve

the same purpose as the replaced component(s); (2) the

fixed capital cost of the replaced component(s), plus

costs of any activities that are part of the replacement

activity (e.g., labor, contract services, major equipment

rental, and associated repair and maintenance activi-

ties),’ does not exceed 20 percent of the current replace-

ment value of the process unit; and (3) the replace-

ment(s) does not alter the basic design parameters of

the process unit or cause the process unit to exceed any

emission limitation or operational limitation (that has

the effect of constraining emissions) that applies to any

component of the process unit and that is legally en-

forceable.

Today’s final rule specifies the procedures by which

the owner or operator of a source selects the basic de-

sign parameters for steam electric generating facilities

* For the sake of clarity, we want to be clear that the term “compo-

nent” is meant to be applied broadly and read broadly to include

replacements of both large components, such as economizers, re-

heaters, etc. at a boiler, as well as small items, such as screws, washers,

gaskets, etc.

* We note that certain ancillary costs incurred during a given

replacement activity should not be part of the replacement activity,

such as replacement power that must be purchased during the main-

tenance shutdown of an electric utility.

42a

and for other types of process units. Specifically, for

steam electric generating facilities, we have clarified our

proposed approach by specifying maximum hourly heat

input and fuel consumption rate’ as basic design param-

eters. We are also allowing owners or operators of

steam electric generating facilities the option to select

a pair of parameters based on the process unit’s out-

put—more specifically, maximum hourly electric output

rate or maximum steam flow rate—as an alternative to

the previously proposed input-based parameters. Like-

wise, we are retaining our proposed approach of specify-

ing maximum rate of fuel or material! input for other

types of process units, but we also allow you to use maxi-

mum rate of heat input, or maximum rate of product

output if you prefer an output-based basic design pa-

rameter. In addition, we allow you to propose an alter-

native basic design parameter(s), if the above options

are inappropriate for your process unit.

We are not specifically defining the basis for deter-

mining the replacement value of a new process unit.

Instead, the final rule provides you with the flexibility of

using any of the following: (1) Replacement cost;° (2)

invested cost, adjusted for inflation; (3) the insurance

value, where the insurance value covers complete re-

placement of the process unit (rather than, for example,

lost revenue replacement); or (4) another accounting

procedure to establish a replacement value of the pro-

cess unit if such accounting procedure is based on Gen-

* Actually proposed as “fue! consumption specifications.”

y proj

“ Replacement cost can be either an estimate of the fixed capital cost

of constructing a new process unit or the current appraised value of the

process unit.

43a

erally Accepted Accounting Principles (GAAP). The

GAAP are the conventions, rules and precedures that

define accepted accounting practice for recording and

reporting financial information, including broad guide-

lines as well as detailed procedures. The basic doctrine

was set forth by the Accounting Principles Board of the

American Institute of Certified Public Accountants,

which was superseded in 1973 by the Financial Account-

ing Standards Board.

If you choose to use options 3 or 4 to determine the

replacement value for a particular process unit, you

must send a notice reflecting your decision to your re-

viewing authority. The first time that an owner or oper-

ator submits such a notice for a particular procéss unit,

the notice may be submitted at any time, but any subse-

quent notice for that process unit may be submitted only

at the beginning of the process unit’s fiscal year. You

must continue to use the same basis to evaluate any ad-

ditional activities that you undertake on that process

unit within that same fiscal year. If you have provided

notice of using either option 3 or 4, then the reviewing

authority will assume that the same method will be used

for subsequent fiscal years unless you send a notice to

them declaring your intent to use another method. In

the absence of providing any notification to your review-

ing authority, you must use option 1 or 2.

The final ruies also set forth a defin.tion of process

unit, specifically delineate the boundary of the process

unit for certain specified industries, and define a func-

tionally equivalent replacement. A more detailed dis-

cussion of these requirements and our rationale for this

BEST AVAILABLE COPY

44a

action is contained in other parts of this preamble sec-

tion.

Today’s final rules are designed to allow you to

engage in activities that facilitate the safe, reliable and

efficient operation of your source. We believe that to-

day’s final action broadens the major NSR program ex-

clusion for equipment replacements and provides you

with additional certainty as to what equipment replace-

ment activities qualify for the RMRR exclusion. By add-

ing certainty to the process, we are removing the disin-

centives te undertaking routine equipment replacements

and promoting proper operational planning to facilitate

safe, reliable and efficient operations. When an activity

qualifies for the ERP, it will be considered RMRR and

excluded from major NSR without regard to other con-

siderations. In many cases, we believe that maintaining

safe, reliable and efficient operations will have the cor-

responding environmental benefit of reducing the

amount of pollution generated per product produced.

The final rules also will reduce the resource burden on

reviewing authorities resulting from implementation of

the existing, case-by-case process for determining

RMRR. In these respects, the final rules are consistent

with the central purpose of the CAA, “to protect and

enhance the quality of the Nation’s air resources so as to

promote the public health and welfare and the produc-

tive capacity of its population.” CAA section 101.

4Sa

B. What /s an Identical or Functionally Equiva-

lent Replacement and Why Should Such an

Activity Be Considered RMRR?

We proposed to exclude the replacement of existing

equipment with identical or functionally equivalent com-

ponents. As we observed at the time of our RMRR pro-

posal, we believe that most identical and functionally

equivalent replacements are necessary for the safe, effi-

cient and reliable operations of virtually all industrial

operations; are not of regulatory concern; will improve

air quality (e.g., by decreasing startup, shutdown, and

malfunctions); and thus should qualify for the ERP un-

der the RMRR exclusion. We believe industrial facili-

ties are constructed with the understanding that certain

equipment failures are common and ongoing mainte-

nance programs that include replacing components in

order to maintain, restore, or enhance the reliability,

safety, and efficiency of a plant are routine. Conversely,

delaying or foregoing maintenance could lead to failure

of the production unit and may create or add to safety

concerns. ,

When such equipment replacement occurs, the re-

placed component is inherent to both the design and

purpose of the process unit, and there is no reason to

believe that such activity will cause the unit to emit

above its original design capacity. Moreover, most of

these replacements are conducted at industrial facilities

to maintain proper operations and to implement good

engineering practices. For example, if a pump associ-

ated with a distillation column fails and is replaced with

an identical new pump, we believe that such a common

activity is and should be considered an excluded replace-

46a

ment. It is not a “change” to the plant, since it merely

maintains the plant as designed. Instead, it is the type

of activity expected to occur to maintain the plant.

Therefore, we think replacements like this properly fall

within the exclusion for “routine maintenance, repair

and replacement.” We also believe treating them in this

fashion is consistent with the basic policies of the CAA:

that existing plants are subject to major NSR permit-

ting requirements only when they engage in an activity

that constitutes an opportune time to install state-of-

the-art pollution control equipment.

We also believe that this principle extends beyond

the replacement of equipment with identical equipment.

When equipment is wearing out or breaks down, it often

is replaced with equipment that serves the same purpose

or function but is different in some respects or improved

in some ways in comparison with the equipment that is

removed. To continue with the example used above, if,

instead of replacing the worn out distillation column

pump with an identical one, the owner or operator re-

placed it with a new and improved model, it does not

seem to us that this changes the fundamental reasons

for treating that replacement as likewise within the

scope of “routine maintenance, repair and replacement.”

This is particularly true since technology is con-

stantly changing and evolving. When equipment of this

sort needs to be replaced, it often is simply not possible

to find the old-style technology. Owners or operators

may have no choice but to purchase and install equip-

ment reflecting current design innovations. Even if it is

possible to find old-style equipment, it seems unneces-

sary and undesirable to generally construe NSR permit-

47a

ting requirements in a manner that is bound to deter

owners or operators from using the best equipment that

suits the given need when replacements must be in-

stalled.

The limiting principle here is that the replacement

equipment must be identical or functionally equivalent

and must not change the basic design parameters of the

affected process unit (e.g., for electric utility steam gen-

erating units, this might mean heat input and fuel con-

sumption specifications). We also believe, however, that

we need not and should not treat efficiency as a basic

design parameter as we do not believe NSR was in-

tended to impede industry in making energy and process

efficiency improvements. We believe such improve-

ments, on balance, will be beneficial both economically

and environmentally. This treatment of efficiency

should address the concern and perception that the NSR

program serves as a barrier to activities undertaken to

facilitate, restore, or improve efficiency, reliability,

availability, or safety of a facility.

Today’s rule does not distinguish between the re-

placement of components that are expected to be re-

placed frequently or periodically and the replacement of

components that may occur on a less frequent or one-

time basis. It likewise does not distinguish between the

replacement of larger and smaller components, instead

requiring greater scrutiny if the replacement in question

is part of an activity that exceeds 20 percent of the re-

placement value of the process unit.

Our decisions on these points are derived from re-

flection on the function of the exclusion in the context of

48a

the CAA. As explained above, and as described more

fully in our legal analysis set forth below, we do not be-

lieve that application of the major NSR program to

“modified” plants is designed to require existing plants

that are continuing to operate in a manner consistent

with their original design to curtail their rate of produc-

tion or hours of operation beyond limitations set forth in

their existing permits. We likewise do not believe that

the program is designed to discourage plants from re-

placing parts or components so as to preserve their abil-

ity to produce at that rate. Rather, we believe Title | of

the Clean Air largely leaves to State and local permit-

ting authorities whether to require adjustments in the

operations of those plants in order to reduce emissions

to the degree needed to attain or maintain national] air

quality standards, and how to weigh the trade-offs such

adjustments may produce in terms of potential economic

impacts and loss of productivity. Instead, we believe the

central function of the application of major NSR. permit-

ting requirements to “modifications” is to assure that

plants install state-oi-the-art pollution controls.

We recognize that on these points, the approach

taken by our final rule thereby differs in some respects

from the multi-factor, case-by-case approach we have

been using in identifying RMRR, and particularly from

some of our applications of that test to certain equip-

ment replacements. We believe, however, that this ad-

justment in our approach is fully warranted for the rea-

sons outlined above, and described more fully in our !e-

gal analysis below.

49a

The following examples of functionally equivalent

replacements under today’s rule include:'

¢ Replacing worn out pipes in a chemical process

plant with pipes that are constructed of different metal-

lurgy (e.g., to help reduce corrosion, erosion, or chemical

compatibility problems).

* Replacing an analog controller with a digital con-

troller, even though a similar analog controller can still

be purchased and even though the new controller would

allow for more precise control. A good example was pre-

sented to us by the forest products industry during our

review of the NSR program’s impacts on the energy

sector. A company in that sector needed to replace out-

dated anaiog controllers at a series of six batch

digesters. In this case, the original controllers were no

longer manufactured. The new digital controllers, cost-

ing approximately $50,000, are capable of receiving in-

puts from the digester vessel temperature, pressure,

and chemical/steam flow. The new controllers would

have more precisely filled and pressurized digesters

with chips, chemicals, and steam, thus bringing a batch

digester on line faster.

’ As discussed in more detail below, although such activities would

be functionally equivalent, they would still need to meet other criteria

to qualify for the ERP. For example, a functionally equivalent re-

placement does not qualify for the ERP if it results in a change to a

basic design parameter of the affected unit. If an activity does not

qualify for RMRR under the ERP, the case-by-case RMRR approach

would still be available to the owner or operator under those cireum-

stances. And, of course, even if the activity does not qualify for the

RMRR exclusion, the activity will not be a modification and, hence, will

not trigger NSR unless it results in a significant emissions increase.

50a

¢ Replacing an existing mill or pulverizer (e.g.,

grinding clinker in a cement factory or coal for a boiler)

with a new one of a different type because both new and

old equipment serve the same purpose (even if the char-

acteristics of the ground material would be different

before and after the replacement).

* Replacing existing spray paint nozzles with new

ones that might atomize the spray better or have a

higher transfer efficiency because the “before” and “af-

ter” nozzles serve the same function.

At the same time, there are numerous activities

that occur at facilities that may fall within the bounds of

the cost threshold percentage, basic design parameters,

and other backstop features of today’s rule, but never-

theless cannot qualify for the RMRR exclusion on the

grounds that the equipment is neither identical nor func-

tionally equivalent. An example of this would be a chem-

ical processing facility where the owner or operator

makes a physical change that allows the production of a

new end product that physically could not have been

manufactured with the previous equipment using the

same raw materials as used before in the same amounts

as before. This would not be a functionally equivalent

replacement activity because the facility is able to pro-

duce an end product after making the change that the

facility was not capable of making before the change.

Consequently, this activity would not qualify as RMRR

under today’s ERP.

Several commenters said the equipment replace-

ment provision will streamline the major NSR applica-

bility analysis. A number of commenters believed the

S5la

ERP would be easier to implement than the proposed

annual maintenance, repair and replacement allowance

approach. One commenter said that allowing identical

replacements to be excluded from major NSR will codify

existing industrial practices, where replacement has no

impact on emissions and would clearly represent

RMRR. |

Many commenters expressed support for the ERP,

but recommended certain changes that they felt needed

to be made to improve the proposal. One commenter

supported the ERP in combination with a capacity-based

option, on the assumption that repair and maintenance

is to be excluded as well as equipment replacement.

One commenter attempted to collect data from tur-

bine customers and found that achieving a level of data

collection necessary for the ERP was far from simple,

because the cost of maintenance activities is affected by

such things as variability in engine model, package tech-

nology, and type of maintenance contract. Another

commenter gave an example of the benefit that the ERP

may provide. Without the ERP, the commenter said the

source is limited to some fraction of boiler tubes allowed

to be replaced at a given time, whereas with the ERP,

replacement of all boiler tubes would, in the com-

menter’s opinion, rightfully be considered routine. An-

other commenter said the ERP will remove regulatory

burdens for types of equipment replacements that are in

their view “routine,” such as, replacement of tubes in

industrial boilers. They addéd that, without a clearer

understanding of which activities are RMRR, they may

be inclined to delay conducting such replacements.

52a

Many other commenters generally opposed any

change to the RMRR exclusion, including one based on

equipment replacement. Some of these commenters

believed the ERP was problematic because it would al-

low a sonrce to replace an entire process unit over time.

Two of the commenters opposed the ERP because they

felt it would create disincentives for the implementation

of Plantwide Applicability Limits (PAL) and Clean Unit

provisions from the recently finalized rule.

One commenter said that from an engineering

standpoint, for a power plant, the difference between

routine maintenance and a major plant refurbishing pro-

ject is clear. To further clarify, the commenter made

the following points. According to the commenter, rou-

tine maintenance is frequent and follows a predictable

pattern. The commenter characterized routine mainte-

nance at power plants as: repair of leaking pipes, pumps,

valves, and fans; cleaning and lubrication of components;

and inspections. The commenter added that permanent

staff do this work either while the plant is operating or

during only brief periods of downtime. The commenter

further expressed that activities that are not routine

require long plant or process unit shutdowns, are done

infrequently, and are major capital projects for which

special funding is set aside as a result of years of plan-

ning and design work.

One commenter said the proposal will allow emis-

sions increases that will be difficult to offset through

other regulations. One commenter objected to the ERP

for a number of reasons: (1) The provision does not pre-

vent replacement with different equipment; (2) it does

not promote efficiency improvements or application of

53a

good air pollution controls; and (3) it would allow re-

placements that would significantly increase emissions.

This commenter said replacement of air pollution con-

trols should trigger best available control technology

(BACT) or lowest achievable emission rate (LAER) re-

quirements. Two local air pollution control agencies in

California noted that they currently already exclude all

replacements with identical equipment from major NSR

wher certain conditions are met.

Commenters generally had similar viewpoints on

allowing both identical and functionally equivalent

equipment replacements to qualify as RMRR. However,

some commenters expressed greater concern related to

excluding the replacement of equipment with function-

ally equivalent equipment. Primarily their concerns

were rooted in the fact that a functionally equivalent

replacement component could lead to increases in opera-

‘tional efficiency or productivity, and these commenters

asserted that these sorts of process enhancements

should not be excluded as RMRR.

We agree with the commenters who felt identical

and functionally equivalent replacement activities gen-

erally should be excluded as RMRR. We also agree with

the commenters who believe that this provision wil!

streamline the major NSR applicability process and will

bring clarity. The provision we are finalizing will allow

a source to make a simple determination as to whether

a replacement piece of equipment qualifies as identical

or functionally equivalent. This type of determination

will be straightforward and easier for the source to im-

plement than the current case-by-case analysis required

to determine a replacement falls within the RMRR ex-

eat wis eae a . @e * ney a ie ; Ya ee a

S4a

clusion. We support the air pollution agencies that have

already excluded these types of changes from NSR.

We disagree with those commenters who believe

that this provision will create disincentives for sources

to accept a PAL or have emission units designated as

Clean Units. A PAL offers a source to bring on entirely

new emissions units with no Federal preconstruction

permit, as long as emissions caps are not exceeded. A

_PAL or a Clean Unit designation allows a source to

make modifications without performing a major NSR

applicability test. These advantages will still be the

driving force for sources to elect to use the PAL or

Clean Unit provisions, and we do not believe this final

rule will significantly detract from their appeal.

We also believe that there is substantial value in

facilitating equipment replacements to a greater degree

than our current approach permits and draws a cleaner

and more easily administered line between equipment

replacements that categorically do not require a permit

and major plant refurbishing which will result in in-

creased emissions. For pieces of equipment used at in-

dustrial facilities, most manufacturers have well-estab-

lished procedures for the inspection and replacement

that are part of the regular maintenance necessary to

provide for the equipment’s safe, efficient and reliable

operation. Some of these replacements are large in

terms of cost and infrequent, but all are necessary to

maintain the safe, efficient and reliable use of the pro-

cess unit. We believe it is important to allow for these

replacements provided that certain safeguards are in

place, as discussed below.

' 55a

We disagree with suggestions from commenters

that the time period between activities, standing alone,

provides an appropriate or clear distinction between

activities that should be permissible under the RMRR

exclusion and those that should not. In fact, some com-

ponents wear out every year, while others wear out ev-

ery 20 years. Nevertheless, both types of changes

should fall within the ERP of the RMRR exclusion be-

cause both allow the facility to operate as designed. By

not imposing a time limitation, the ERP allows replace-

ment activities to be driven by consideration of economic

efficiency rather than artificial regulatory constraints.

We disagree with commenters who expressed parti-

cular concern about functionally equivalent replace-

ments. We continue to believe such activities should be

encouraged and should qualify as RMRR. Even though

a functionally equivalent component varies in some re-

spects from the replaced component, we feel the most

important factor to consider is whether the replacement

will serve the same purpose as the replaced component.

We acknowledge that a functionally equivalent replace-

ment can result in an increase in efficiency and; conse-

quently, productivity. In fact, one of our goals is to pro-

mote such outcomes. However, we believe that the basic

design parameter safeguard is appropriate to assure

that the ERP only automatically excludes from major

NSR functionally equivalent replacements that do not

result in a significant change to the fundamental charac-

teristics of the process unit.

We note that the two local programs in California

that exclude the replacement of equipment with iden-

tical equipment also allow the replacement of equipment

S6a

with functionally equivalent equipment without consid-

ering such action to be a modification. Due to local air

quality considerations, the local programs establish min-

imum pollution control requirements that are imposed

in some circumstances when functionally equivalent

equipment replacements occur. Nothing in today’s rule

would prevent a State or local program from imposing

additional requirements necessary to meet Federal,

State or local air quality goals.

After reviewing the comments on our proposal, we

have decided to promulgate what we proposed in De-

cember 2002 for the RMRR equipment replacement pro-

vision with relatively minor changes. We decided to in-

clude another safeguard in addition to those we pro-

posed in order to appropriately constrain the meaning of

the term “functionally equivalent.” The additional safe-

guard is that an excluded replacement activity cannot

cause the process unit to exceed any emission limitation

or operational limitation (that has the effect of con-

straining emissions) that applies to the process unit and

that is legally enforceable.

Thus, today’s final rule allows you to categorize

identical and functionally equivalent equipment replace-

ments as RMRR if the fixed capital cost of such replace-

ment plus the cost of repair and maintenance activities

that are part of the replacement activity does not exceed

20 percent of the replacement value of the process unit,

and if the replacement does not alter a basic design pa-

rameter of the process unit or cause the process unit to

exceed any emission limitation or operational limitation

(that has the effect of constraining emissions) that ap-

plies to the process unit.

a Se De eee ea see eee ee

S7a

C. What Cost Limit Has Been Placed on the

’ Kquipment Replacement Approach?

The next concept presented in the proposal is the

cost-based limitation on the scope of the ERP. The pur-

pose of this threshold is to distinguish between those

equipment replacement activities that should automati-

cally qualify as RMRR without furt..er consideration

and those activities that should undergo case-specific

consideration. This concept is akin to the long-estab-

lished reconstruction provision under the NSPS pro-

gram. For the reasons explained below, we have de-

cided to establish a 20-percent cost threshold under the

ERP. ,

We believe a similar bright-line rule that would

obviate the need for case-by-case review under our

multi-factor test of appropriate categories of equipment

replacements would be extremely useful in addressing

many of the problems that we have identified with the

current operation of the NSR program. Such a rule

would be particularly useful in avoiding the uncertainty

and delay, and consequent postponed or foregone equip-

ment replacements, that our multi-factor case-by-case

review induces. For example, our RIA indicates that it

takes a year, on average, to obtain a determination

whether a proposed replacement is routine. That kind

of delay obviously creates perverse disincentives to re-

frain from equipment replacements and instead repair

existing equipment or find some other solution. |

This is the kind of problem that classically leads

agencies to fashion bright-line tests to provide greater

regulatory certainty and efficiency. Moreover, because

58a

the kind of disincentives that give rise to this concern

operate largely by economic means, prompting sources

to take one course of action (cut back on productive

equipment replacement) rather than another (replace

the equipment and incur the costs of delay, as well as

potentially the costs of installing state-of-the-art con-

trols), we think a cost-based threshold is a reasonable

basis on which to create such a bright-line rule.

In the proposal, we observed that it may sometimes

be difficult to determine where to draw the line between

an activity that should be treated as an excluded re-

placement activity and one that should be viewed as a

physical change that might constitute a major modifi-

cation, when the replacement of equipment with iden-

tical or functionally equivalent equipment involves a

large portion of an existing process unit. We solicited

comment on a range of equipment replacement cost

thresholds such as one based on the NSPS program.

Under the NSPS program, when the cost of a project at

an existing affected facility exceeds 50 percent of the

fixed capital cost that would be required to construct a

comparable entirely new unit (that is, the current capital

replacement value of the existing affected source), then

the source must notify and provide information to the

permitting authority. After considering a range of fac-

tors, including the cost of the activity, the estimated life

of the facility after the replacements, the extent to

which the replaced equipment causes or contributes to

the emissions from the source, and any economic or

technical limitations on compliance with the NSPS, the

59a

reviewing authority determines whether the proposed

project is a reconstruction.®

We observed that, in some respects, an equipment

replacement cost threshold set at the NSPS reconstruc-

tion test could be an appropriate approach for distin-

guishing between routine and nonroutine identical and

functionally equivalent replacements under the major

NSR program. As under the NSPS program, we do not

believe it is reasonable to exclude from major NSR

those activities that involve the total replacement of an

existing entire process unit.

We also noted, however, that there are other con-

siderations pointing in favor of a threshold lower than

the 50-percent reconstruction threshold that might be

appropriate to bound the ERP. Under NSPS, when a

source undertakes a replacement activity at an existing

affected facility that constitutes half or more of the facil-

ity’s capital replacement value, our rules require a case-

by-case determination as to whether such replacements

constitute construction. We noted that a percentage

threshold lower than 50 percent might be more appro-

priate for determining where we would require case-by-

case consideration of the question whether equipment

replacements constitute a modification of an existing

process unit under major NSR. We solicited comments

on the appropriate level of any percentage.

* In the proposal, it was incorrectly stated that applicability of the

NSPS was triggered if a project exceeded 50 percent of the cost of

replacing the affected facility. As stated in this notice, if an activity

exceeds this cost threshold, that only triggers further evaluation, not

the automatic application of the NSPS to the source.

60a

Many commenters supported the threshold of 50

percent of replacement value as the upper limit on

equipment replacement. They felt this number is con-

sistent with existing regulatory requirements.and would

accord the flexibility originally intended under the CAA

for RMRR activities, while at the same time assuring

that major, nonroutine projects remain subject to major

NSR applicability review, and they felt this number is

consistent with a common-sense interpretation of the

regulations.

They also believed a 50-percent cutoff to be consis-

tent with reconstruction definitions used in many NSPS

and National Emission Standards for Hazardous Air

Pollutants regulations. Some commenters stated that a

50-percent cutoff for the ERP would be valid for the

same reason as for the NSPS reconstruction test; signif-

icant changes to a process unit are necessary before ret-

rofit controls should be considered, provided there is no

increase in emissions.

Many other commenters opposed the 50-percent

replacement value threshold. They believed the capital

replacement percentage should be much less than 50

percent. One commenter suggested as an appropriate

threshold that the sum of equipment replacement costs

for a single process unit over any period of 5 consecutive

years should not exceed 50 percent of the replacement

value of the process unit. Another commenter said the

replacement percentage should not be higher than 25

percent. Another commenter suggested a replacement

percentage of 5 to 10 percent to reduce the risk of re-

placement of an entire process unit over time without

installation of BACT. One commenter said a more ap-

6la

propriate perc . .ge for electricity producers is 0.1 to

1.0 percent. +....ther commenter said the threshold

should be 5 percent, 1 percent, or even less, as shown by

an NSR enforcement case against the Tennessee Valley

Authority (TVA).

Another commenter believed the 50-percent num-

ber has no practical effect in protecting public health

and the environment, and the commenter was not aware

of any projects that have exceeded 50 percent in cost.

While opposed to the ERP in general, one com-

menter said the cost threshold should be as high a per-

centage as possible, so as not to promote premature re-

placement of equipment that is repairable. Another

commenter said the 50- percent number from the NSPS

is archaic and not environmentally protective. This

commenter suggested that the threshold instead be 24

percent. The commenter believed this lower percentage

is appropriate because the lifetime of high-cost materi-

als will considerably exceed 5 years.

We agree with those commenters who see a rela-

tionship between establishing a threshold for equipment

replacements that we will treat as RMRR under the ma-

jor NSR program and the threshold the NSPS program

established for reconstruction. However, we disagree

that these two thresholds should be the same. The

NSPS threshold was intended to identify those activities

that, even though they did not qualify as a modification

under NSPS, nevertheless are of such magnitude that

further consideration should be given as to whether they

are projects tantamount to new construction. The 50-

percent NSPS threshold is not a bright line in the sense

62a

that all projects that exceed 50 percent are automati-

cally considered as reconstruction. Rather, as discussed

above, it is a threshold intended to alert permitting au-

thorities to significant projects and allow case-by-case

decisions based on a series of regulatory factors.

The ERP replicates the NSPS concept in some

ways. It identifies a threshold below which there is no

need for further inquiry into whether an activity quali-

fies for the ERP and above which there is a need for a

case-by-case determination. The major difference be-

tween the ERP and the NSPS reconstruction test is that

the ERP deals with modifications, not reconstructions.

This difference weighs in favor of establishing the equip-

ment replacement threshold at something less than the

reconstruction threshold. It is logical and practical to

conclude, as some of the commenters do, that by using

the word “modification” the CAA intended to capture

activities on a smaller scale than reconstructions. As

noted above, we have set the ERP cost threshold at 20

percent. This value is less than one-half of the 50-per-

cent reconstruction threshold and, therefore, fits well

within this conceptual framework.

A 20-percent cost threshold would be consistent

with the decision of the U.S. Court of Appeals for the

Seventh Circuit in the Wisconsin Electric Power Com-

pany v. Reilly (“WEPCO”) case, to the extent that it

would not automatically allow the activities performed

there to constitute RMRR. See 893 F.2d 901 (7th Cir.

1990). This court decision directly addressed the ques-

tion of what level of “like kind” replacement activities

qualify as changes under the major NSR program.

63a

In the WEPCO case, the Court considered an activ-

ity involving 5 coal-fired units at WEPCOQ’s Port Wash-

ington plant. Each unit was rated at 80 megawatts of

electrical output capacity. The activity involved the re-

placement of numerous major components. The infor-

mation submitted by WEPCO showed that the company

intended to replace several components that are essen-

tial to the operation of the Port Washington plant. In

particular, WEPCO sought to replace the rear steam

drums on the boilers at units 2, 3, 4, and 5. According to

WEPCO, these steam drums were a type of “header” for

the collection and distribution of steam and/or water

within the boilers. WEPCO viewed their replacement as

necessary to continue operation of the units in a safe

condition. In addition, at each of the emissions units,

WEPCO planned to repair or replace severai other inte-

gral components, including replacement of the air heat-

ers at units 1, 2,3, and 4. WEPCO also planned to reno-

vate major mechanical and electrical auxiliary systems

and common plant support facilities. WE PCO intended

to perform the work over a 4-year period, utilizing suc-

cessive 9-month outages at each unit. The cost of the

activity was estimated in 1988 to be $87.5 million. The

Court noted that EPA concluded at the time this activity

was unprecedented in that EPA did not find a single

instance of renovation work at any electric utility gener-

ating station that approached this activity in nature,

scope and extent. The Court determined, at our urging,

that the changes did constitute a “physical change” un-

der the NSR rules. .

In the case of a steam electric generating facility,

the process unit definition provided in today’s rule is

nearly identical to the make-up of the “comparable new

64a

facility” that was used in the NSPS evaluation of the

WEPCO renovation project. However, under our rule

we would not include the cost of pollution control equip-

ment in determining the replacement cost of the

WEPCO process units. WEPCO had electrostatic pre-

cipitators on each of its 5 process units, which our rule

would subtract from the replacement cost. In addition,

the WEPCO evaluation dealt with 5 boilers, each with its

own turbine-generator set; to be consistent with today’s

definition of steam electric generating facility, we would

likely treat each boiler unit as belonging to a different

process unit. However, since all of the boilers under-

went similar renovations, for simplicity we can assume

that all of the process unit-specific activity costs are

equivalent.

Using 1991 dollars, consistent with the timeframe

of the Seventh Circuit Court’s decision, it appears that

the value of the 5 process units at the 400-megawatt

WEPCO Port Washington facility would be approxi-

mately $321 million based on 1991 model plant values

provided by the International Energy Agency. The 1988

project cost of $87.5 million scaled up to 1991 dollars

would have had an adjusted project cost of $92.3 mil-

lion.” Thus, the capital cost percentage for the replace-

ment activities at WE PCO, averaged over its 5 process

units, amounted to 29 percent. Alternatively, using the

project cost of “at least $70.5 million” cited in the 1991

" Using the Chemical Engineering magazine’s Annual Plant Cost

Index (composite), $87.5 million in 1988 dollars is equal in real terms

to (361.3/342.5) multiplied by 87.5 million, or $92.3 million in 1991

dollars.

65a

decision by the Seventh Circuit, and using the same

value for process unit cost, we compute at least 22 per-

cent. The 20-percent threshold is, therefore, beneath the

scope of the activities at issue in the WEPCO case and

hence not inconsistent with that decision.

The 20-percent threshold also is supported by

available data for the electric utility sector. We havea

robust and detailed set of information available on main-

tenance, repair and replacement activities for the elec-

tric utility sector. Information about the electric utility

sector persuades us that we have established the right

ERP threshold for this sector.

Information on other industrial sectors beyond

electric utilities (as well as general economic theory)

further supports our 20 percent bright line test. Case

studies performed by an EPA contractor and included in

Appendix C of our final regulatory impacts analysis

(RIA) estimate the overall impact of the rule on six dif-

ferent industrial sectors (pulp and paper mills, automo-

bile manufacturing, natural gas transmission, carbon

black manufacturing, pharmaceutical manufacturing,

and petroleum refining). The case studies find that rou-

tine equipment replacement activities generally do not

cause emissions increases. The case studies also find

that equipment replacement activities vary widely

within these industries. Likewise, the cost of these ac-

tivities as a percent of the process unit replacement

value varies widely. We recognize that the study ad-

dresses specific case examples from only a part of regu-

lated industry and that the project cost information is

derived from a limited inquiry of industry representa-

tives. We believe, however, that the study provides a

66a

useful scoping assessment that tends to support the

proposition that the 20 percent threshold derived for the

utility industry (which is based on robust industry data)

should be applied to industry as a whole. In short, the

study supports our view that it is reasonable to assume

that equipment replacement activities in the utility in-

dustry are similar enough to replacement practices in

other industry that the 20 percent value determined for

utilities, is appropriate for industry as a whole. This

data indicates that most typical replacement activities

will fall within the 20-percent threshold. At the same

time, the data indicates that some major replacement

activities likely will cross the 20-percent threshold and

will require a case-by-case evaluation under the multi-

factor RMRR test.

Two comment letters (from the Utility Air Regula-

tory Group (UARG) and from the American Lung Asso-

ciation (ALA), et al.) were particularly helpful in under-

standing the issues associated with the electric utility

sector. The UARG provided as an attachment to its

comment letter a document describing major repair and

replacement activities that its members believe must be

undertaken at utility generating stations in order to

keep those facilities operational. The UARG noted that

capital costs incurred for repair and replacement activi-

ties at an individual process unit additionally include

activities more minor than those addressed in the docu-

ment. The UARG grouped repair and replacement ac-

tivities into project families; within each project family

were per-component costs ($/kW) for numerous equip-

ment replacement activities. We have reviewed the list

of projects supplied by UARG and have concluded that

these types of replacement activities are important to

67a

maintaining, facilitating, restoring or improving the

safety, reliability, availability, or efficiency of process

units. Therefore, generally speaking, these types of

individual activities and groups of activities should qual-

ify for the ERP and be excluded from major NSR with-

out case-specific review. We also believe that it is rea-

sonably expected in the electric utility industry for

groups of these activities to be implemented at the same

time. Such groupings should also be excluded without

case-specific review. When we compare the 20-percent

ERP cost percentage to the UARG data, we find that

individual replacement activities would, in fact, qualify

for the ERP and that limited groupings of these activi-

ties would qualify. However, larger groupings of these

activities—groupings that are not usually seen in the

industry—would not qualify for the ERP. This shows

that the 20-percent threshold will be effective in distin-

guishing between activities (and aggregations of activi-

ties) that should not require case-specific review to be

excluded from major NSR and those that do.

The ALA commenters provided with their com-

ments the results of their analysis of projects at issue in

an NSR enforcement case against Tennessee Valley Au-

thority (TVA). As shown in the ALA comment letter,

the Clean Air Task Force and the Natural Resources

Defense Council looked at costs for 14 projects on a pro-

cess unit basis, in year 2001 dollars, from the publicly

available record for the case. For all but one of the chal-

lenged projects, the ALA commenters calculated a cost

of less than 4 percent of process unit replacement cost.

The ALA commenters submitted results of this analysis

with their opposition to a source-wide, 5-percent mainte-

nance allowance. As noted above, we concluded in our

68a

2002 report to the President that the NSR pro-

gram—and the RMRR provision in particular— has in

fact resulted in delay or cancellation of activities that

would have maintained and improved the reliability,

efficiency, and safety of existing energy capacity. The

primary purpose of today’s rule is to rectify this prob-

lem. Thus, to the extent the activities addressed by

ALA qualify for the ERP, we now believe that such ac-

tivities, if conducted in the future, should be*excluded

from major NSR.

A final factor that we believe supports our selection

of a 20 percent threshold is the cost of installing state-

of-the-art controls on existing units. There is obviously

no single answer to the question of at what point that

cost becomes the deciding factor in an owner’s decision

whether to replace a piece of equipment and incur that

cost, since much will depend on the rate of return on the

investment. Nevertheless, we think it is reasonable to

assume that if the cost of the controls is greater than the

cost of the replaced equipment, it is likely to operate as

a substantial deterrent to replacing the equipment at

issue. That is likely to be the case with respect to elec-

trie utilities if we set the threshold below 20 percent,

which represents the approximate cost of retrofitting

existing plants with state-of-the-art controls. The equa-

tion is similar for industrial boilers. Notably, those sec-

tors represent a substantial fraction of the emissions

potentially subject to the NSR program. While the rela-

tive costs of air pollution controls in other industries

vary more widely than the costs for utility and industrial]

boilers, we nevertheless believe that the costs and tech-

nical issues associated with retrofitting air pollution con-

69a

trols factor significantly into equipment replacement

decisions.

D. What Will Be the Basis of Applying the 20-

Percent Threshold?

In the proposal, we solicited comment on whether

implementing the ERP on a per-activity basis or on

some other reasoned basis, such as applying the per-

centage to components that are replaced collectively

over a fixed period of time, may be more workable.

Many commenters stated that the ERP should be

implemented on a per-activity (or aggregation of activi-

ties) basis. Two of the commenters cited longstanding

NSR precedent as the basis of their comments, while

two other commenters relied on NSPS precedent. An-

other commenter thought the per-activity approach

would be less confusing than summing activities over a

fixed period of time. Other commenters believed the

equipment replacement threshold should in fact be ap-

plied on a 5-year rolling average.

We have decided to apply the percentage threshold

on a per-activity (or aggregation of activities) basis.

This is consistent with how major NSR has been.applied

in the past and will continue to apply in the future, with

the exception of those sources which establish a PAL.

The major NSR program is a preconstruction program

that requires applicability to be determined for a given

activity at a facility and, as necessary, permitting to oc-

cur prior to the time activities are commenced. The ma-

jor NSR program also requires applicability to be deter-

mined, in the first instance, based on an assessment only

of the parts of a facility involved in the activity. A per-

70a

activity basis works well with this approach. We are not

going final with a “component-by-component” approach

that we solicited comment on through our RMRR pro-

posal.

There would be obvious problems if we chose any

of the other approaches suggested in the proposal or

suggested by commenters (for example, annual basis or

5-year rolling average). One of the primary concerns

with applying the percentage to activities performed

over a span of time is that we would be restructuring the

major NSR program to operate based on after-the-fact

determinations. This raises the difficult question of

what happens under this type of approach if you learn

after commencement of an activity that it does not qual-

ify under the ERP. This situation is largely avoided by

the per-activity approach that we are establishing in to-

day’s rule. .

It should be noted that activities that are related

must be aggregated under the ERP, in the same way as

they would have to be aggregated for other NSR appli-

cability purposes. Under our current policy of aggrega-

tion, two or more replacement activities that occur at the

same time are not automatically considered a single ac-

tivity solely because they happen at the same time. For

example, a steam turbine rotor replacement project and

a boiler tube replacement project would not be aggre-

gated simply because they occur during the same main-

tenance outage and on the same process unit. Further

inquiry into the nature of the activities and their rela-

tionship to each other is needed before deciding whether

the activities must be aggregated under NSR. Also,

non-replacement activities that are part of a larger re-

Tla

placement activity should be included when calculating

costs for a replacement activity against the capital cost

threshold. .

E. What Basic Design Parameters Are Being

Established To Qualify for the Equipment

Replacement Provision?

In the proposal, equipment replacements were only

eligible for the ERP if they did not change the basic de-

sign parameters of the process unit. We proposed that

maximum heat input and fuel consumption specifications

for EUSGUs and maximum material/fuel input specifica-

tions for other types of process units are basic design

parameters. We solicited comments on limiting the eli-

gibility of the ERP this way and on the basic design pa-

rameters we proposed.

Several commenters expressed concerns with ei-

ther the use of these specific parameters, or the restric-

tion of the regulated community to only this set of de-

sign parameters. Other comments centered around an

inconsistency in how EPA has accounted for efficiency

in the basic design parameter safeguard. The com-

menters stated that, while EPA stated in the proposed

preamble that efficiency is not a basic design parameter,

the basic design parameter safeguard, as proposed, has

the potential to bar equipment replacements that

achieve significant gains in efficiency.

Commenters from all sides supported EPA’s ap-

proach to handling activities intended to improve an af-

fected process unit’s performance beyond its basic de-

sign parameters. Commenters asserted that these ac-

tions would not fall within the RMRR exclusion.

72a

Commenters from the gas transmission industry con-

curred and amplified this concept, stating that an engine

that is “uprated” at the time of overhaul should not be

excluded from major NSR under the RMRR exclusion.

We recognize that the proposed basic design para-

meters are inconsistent with some industry conventions,

and that we should allow for industry-specifie flexibility

or specify additional source category-specific parame-

ters. For example, for natural gas transmission com-

pressor stations, commenters explained that brake

horsepower is the conventional design capacity parame-

ter. We received similar comments from other indus-

tries, including cement and surface coaters, who ob-

jected to limiting their facilities to the proposed basic

design parameters. Accordingly, we have decided to

provide flexibility by providing a menu of choices from

which the owners or operators may select and also by

allowing for owners or operators to propose alternative

basic design parameters to their reviewing authority

which would then be made legally enforceable.

In addition to this flexibility, there may be a need

for additional flexibility in using the basic design param-

eters that are spelled out in today’s rule. For instance

with boilers, maximum steam production rate is often

used by the industry, and it may make sense in some

cases to set the design parameters based on those values

rather than on maximum heat input. Likewise, a crude

oil distillation tower may have several capacities that

are a function of the type of crude that is to be pro-

cessed, and so a refiner may need to have a set of basic

design parameters for its crude towers. These situa-

tions can be addressed by the source proposing alterna-

73a

tive parameters or sets of parameters to their reviewing

authority.

Also, there should be flexibility in how the basic

design parameters are demonstrated when the owner or

operator chooses not to rely on the design information

for its process unit. For example, in order to establish

the heat input value that the process unit has demon-

strated it is capable of achieving, an electric generating

unit should have the flexibility to reference available

credible information, such as results of historic maxi-

mum capability tests or engineering calculations. Re-

sults from tests performed by electric utilities in the

context of providing assurances to generation dispatch

systems and regional or national power pools may be

used to establish the process unit’s maximum heat input.

A review of such data or other available operational data

or design information can reveal the heat input that the

process unit is capable of achieving in its “pre-activity”

configuration, and this can be compared to a “post-activ-

ity” heat input value. Plant operators, where the speci-

fied basic design parameters are inappropriate for the

process, can propose what the measure of performance

will be for these process units, including the use of per-

mit limits on amount of production, to their reviewing

authority. For process units having multiple end prod-

ucts and raw materials, the owner or operator should

consider the primary product or primary raw material

when selecting a basic design parameter. |

Many pieces of equipment are purchased based on

their capacity or output. Consequently, for both utilities

and non-utilities, we have modified the proposed basic

design parameters to include output-based alternatives

74a

in today’s final rule. For utilities, the owner or operator

can select maximum hourly electric output rate and

maximum steam flow rate as its basic design parame-

ters, as an alternative to using input-based measures of

maximum hourly fuel consumption rate and maximum

hourly heat input. (We are clarifying from the proposal

that the correct parameter is maximum hourly heat in-

put, not maximum heat input.) Owners or operators may

set different design parameters for different fuel types

(such as coal or oil) or a combustion device that can ac-

commodate multiple fuel types: for coal-fired units, own-

ers or operators should consider that the fuel consump-

tion rate will vary depending on the quality of the coal

for a given heat input. When establishing fuel consump-

tion specifications in terms of weight or volume, the min-

imum fuel quality based on BTU content should be used

for coal-fired units.

Regardless of whether the source selects a basic

design parameter(s) specified for non-utilities in today’s

rule or gets approval from their reviewing authority to

use an alternative parameter(s) for any type of source,

we have not specified a fixed averaging time period for

the circumstance because we want the owner or opera-

tor to have the flexibility to select an averaging time

that best accommodates their operation. In most cases,

we believe that long term averaging periods (e.g., a 12-

month fixed period) will not be appropriate.

Thus, an equipment replacement that improves a

process unit’s efficiency and thereby enables the unit to

return to its design parameters can qualify as RMRR

even if current actual emissions increase as a result.

For example, if boiler tubes or refractories are replaced

75a

on a boiler process unit, and these activities are beneath

the capital cost threshold and are within the unit’s basic

design parameters, then they would qualify as RMRR

under the ERP even if this improves the unit’s effi-

ciency.

The manufacturer’s design parameters of a process

unit are always acceptable if an owner or operator

chooses to rely on them. In the rare cases where a facil-

ity does not have established design parameters, we be-

lieve that a reasonable look back period should be used

for establishing the pre-activity values for basic design

parameters, rather than taking the condition of the pro-

cess unit immediately before the activity. We have

therefore established a 5-year look back period, consis-

tent with that for the NSPS hourly emissions increase

test, for these situations. 2 7

We were urged by some commenters to incorporate

a de minimis increase level in the basic design parame-

ters that would allow activities to qualify for the ERP

even though the activities would result in a minor

change to the relevant basic design parameters. They

argued that some effects resulting from the replacement

may not be apparent before the equipment has been re-

placed. They argued that allowing for small changes in

basic design parameters would add greater certainty to

the ERP because unforeseen small changes would not

cause an activity to lose the exclusion after the fact.

While we sympathize with the commenter’s concern, we

do not see a ready solution to this problem under the

RMRR exclusion. In fact, we are not persuaded that

those types of changes can be readily justified under the

ERP because it is hard to see how an activity that

76a

causes basic design parameters to change is not “a

change” under NSR.

In sum, we continue to believe that an identical or

functionally equivalent replacement should not qualify

for the ERP if the activity causes the process unit to

exceed its specified basic design parametérs. Without

such a requirement, significant alteration of a process

unit’s fundamental design could be accomplished under

the guise of the ERP. Such an outcome obviously does

not square with the idea that identical or functionally

equivalent replacements are not “changes” under the

major NSR program. Our final rule is different from

the proposal, however, in that it provides greater flexi-

bility in defining basic design parameters for process

units. We were persuaded by commenters who ex-

pressed concerns that the proposed approaches did not

adequately encompass all affected operations and indus-

try sectors.

77a

F. What Collection of Equipment Should Be Con-

sidered in Applying the Equipment Replace-

ment Provision and How Should It Be De-

fined?

In the proposal, we raised the issue of what

collection of equipment should be considered in applying

the threshold under the ERP. We proposed the term

“process unit” as the appropriate collection to accommo-

date the intended coverage of activities under the ERP.

The purpose of this term is, to the extent possible, to

align implementation of the ERP with generally ac-

cepted and practical understandings of what constitutes

a discrete production process. The general definition

that we proposed was based closely on the definition of

process unit contained in 40 CFR 63.41 and read as fol-

lows:

Process unit means any collection of structures

and/or equipment that processes, assembles, applies,

blends, or otherwise uses material inputs to produce or

store a completed product. A single facility may contain

more than one process unit.

To help illustrate these concepts, we further pro-

posed five industry-specific examples of how this defini-

tion of process unit might be applied.

Some commenters compared the proposal’s defini-

tion of “process unit” (“ * * * producing or storing a

completed product * * * ”) to the definition that is

used by section 112(g) and that appears in 40 CFR 63.41

(“ * * * producing or storing an intermediate or final

product * * * ”). One of the commenters supported

the proposed definition. Two commenters said the rule’s

78a

definition should be consistent with that used by section

112(g¢), which they believe is broad enough to encompass

interrelated operations. While supporting the RMRR

proposal’s definition, two commenters recommended

that EPA provide regulatory flexibility by allowing a

facility the option to choose which definition it will use.

One commenter generally supported the proposed

definition of “process unit,” but this commenter believed

that “the delineation of a process unit should be made by

regulated entity rather than explicitly defined in a rule.”

Three commenters asserted that pollution control

equipment should be included in the process unit defini-

tion. One industry commenter said pollution control

equipment is often integral to the process and may pro-

duce an intermediate product. One environmental

commenter believed the proposed rule was unclear as to

whether pollution control equipment is part of the pro-

cess unit.

Several commenters said the proposed definition is

too vague or broad. Another commenter urged EPA to

change the definition of process unit to limit the scope of

what is allowed in the ERP, so that the source of emis-

sions (for example, an entire coal boiler) would not be

allowed to be replaced without major NSR. The

commenter asserted that the replacement unit’s scope

should be limited to an emission unit.

Most commenters agreed that the general process

unit definition is sufficient. However, a number

of commenters suggested that we revise or eliminate

some of the process unit examples (that is, the industry

category-specific definitions), and others were con-

79a

cerned that the proposed definitions do not support the

detailed process unit definition for a specific industry

because the definitions will never capture all possible

elements and configurations.

We received comments from several industry rep-

resentatives suggesting changes to our proposed

industry-specific definitions, and also to request that we

delineate other process unit types explicitly in the rule.

Definitions were submitted for sugar mills, chemical

manufacturing plants, surface coating operations, flat

glass manufacturing, fiberglass i aealalliaalit ad and gas

compressor stations.

One industry commenter agreed with our proposed

approach to proportionately allocate, based on capacity,

the cost of those components shared by two or more pro-

cess units. Another commenter suggested that, for elec-

tric utilities, we allocate the cost of shared equipment

based on a pro rata share of megawatts produced.

We agree with the commenters who favor using a

process unit as the basis for administering the ERP and

including a definition of process unit in the final rule.

We also agree with the commenters who suggested that

the definition of process unit should be consistent with

the definition in 40 CFR 63.41, and we have altered the

final rule definition to include those processes that pro-

duce “intermediates.” We acknowledge that, without

further explanation, the term “intermediates” is suscep-

tible to misinterpretation, which can cause confusion and

lead to less regulatory certainty. Thus, we provide the

following explanation as to how we intend to interpret

today’s rule.

80a

By “intermediates,” we mean the intended product

of an integrated facility operation. For example, for an

automotive manufacturing plant, while the completed

product would be the driveable vehicle ready for ship-

ping to the showroom, an intermediate product could be

the engine or the painted body shell. In this case, we

would not consider smaller production operations, such

as the e-coat, primer surface, or top coat operation, to be

intermediates in the context of our final rule definition

for process unit. Our primary goal in defining this term

“process unit” is to encompass integrated manufacturing

operations that produce a completed product, and those

operations that produce an intermediate as the product

of the process unit. In the case of the automotive paint

shop, series of coating steps together comprise the care-

fully designed and interrelated set of operations, all of

which are needed to provide a coating system that meets

design specifications. The individual operations almost

never are implemented individually and, as a practical

matter, simply would serve no meaningful purpose in the

absence of the others.

We disagree with the commenters who wish to in-

clude all pollution control equipment in the definition of

process unit. We feel that periodic replacement of com-

ponents of emissions control equipment should be en-

couraged and would rarely lead to actual emissions in-

creases. In instances where identical or functionally

equivalent replacement of pollution control equipment

occurs, it is likely you will qualify for a Pollution Control

Project exclusion. We do agree, however, that where

the control equipment is an integral component of the

process it should be included. Therefore, we are exclud-

8la

ing associated pollution control equipment from the defi-

nition of the “process unit,” except for contro] equip-

ment that serves a dual purpose in the process. We

know there are industries where pollution control equip-

ment performs a dual purpose; for example, condensers

- often serve to control emissions of organic air pollutants

while serving as an integral component of the operation

of a fractionation column. A low-NQ, burner is another

example of a dual-purpose component. In such cases, to

provide clarity and simplify administration of the ERP,

our rule provides that dual purpose equipment should be

considered part of the process. We are also clarifying in

today’s rule that administrative buildings (including

warehousing) are not to be included in the process unit,

but other types of non-emitting units that are integral to

the processing equipment should be included.

We also have included in our final rule industry-

specific examples of how this definition might' be ap-

plied. The examples are drawn from three selected in-

dustrial processing categories—electric utilities, refin-

eries, and incinerators. We proposed each of these de-

tailed definitions and received mostly support from

commenters on their accuracy. While we also proposed

detailed definitions for two other industries—pulp and

paper and cement producers—we have decided not to

finalize those definitions after receiving comments from

the relevant industry trade association asserting that

the definitions did not, and could not, capture all of their

industry’s configurations and they believed the generic

process unit definition was sufficient for their industry.

Because of the centrality of the “process unit” concept

to the usefulness of the ERP, it is our desire to include

specific definitions for steam electric generating facili-

ties, petroleum refineries, and incinerators in the final

rule to provide as much certainty as possible for facili-

ties in these industries. As noted above, these defini-

tions also should be useful for those in other industries

who will apply our general definition because the indus-

try specific definitions provide clear examples of how we

intend the general definition to be interpreted and ap-

plied. During the public comment period on the pro-

posal, several commenters submitted additional industry

specific definitions and asked us to put them in the final

rule. We are not finalizing these suggested definitions

at this time, because we did not include them in the pro-

posed rule. However, provided below are the process

unit definitions that commenters submitted to us and

that we think comport well with the general definition of

process unit promulgated today.

¢ For a natural gas compressor station, each com-

pressor system, together with its proportionate share of

common support equipment is a separate process unit.

This would generally consist of the air inlet system, ac-

cessory drive system, gas producer, fuel delivery sys-

tem, cooling system, lube system, power turbine, power

shaft, control system, starting system, exhaust system,

and support facilities (e.g., auxiliary power generating

equipment, heating/cooling equipment, station and yard

pipe, valves, etc.).

* For a flat glass manufacturing plant, each pro-

duction line within a facility should be a separate pro-

cess unit. Flat glass production is completed on a con-

tinuous line where raw materials are added at one end,

a continuous ribbon of glass is formed, and finished

glass is packaged at the other end. The flat glass pro-

duction line consists of: the batch house, where raw ma-

83a

terials are stored and weighed; the furnace and refiner,

where the raw materials are melted; the bath, where the

glass ribbon is formed; the lehr, where the ribbon is an-

nealed; and the cutting and packaging equipment, where

the glass is removed from the line for sale to customers

or for additional processing later.

¢ For a fiberglass production facility, each produc-

tion line is a separate process unit. Fiberglass is manu-

factured on a continuous line where raw materials are

melted at one end to form a continuous strand of fiber-

glass that is packaged at the other end. The fiberglass

production line begins with the batch house, where raw

materials are stored and weighed. In the melter,

forehearth, and refiner, the raw materials are melted

and refined. From the refiner, glass fibers are formed

through controlled bushings. From the bushings, the

continuous strand fibers are either directly cut or pack-

aged or wound onto spools for packaging for sale to cus-

tomers or for additional later processing.

¢ For the production of precipitated amorphous

silica, the process unit includes, but is not limited to: raw

material storage and handling equipment used for mix-

ing sand and other raw materials prior to addition to the

furnace; the furnace itself; the raw material storage and

handling equipment for the cullet dissolving and silica

precipitation process; all dissolving, precipitation, and

filtration tanks and equipment; and drying equipment.

Further, the process unit includes all the product pack-

aging, storage, handling, and transfer equipment.

¢ For a chemical manufacturing plant, the process

unit would include all the equipment assembled and con-

nected by pipes or ducts to process raw materials and to

BEST AVAILABLE COPY

84a

manufacture an intended primary product and associ-

ated byproducts or intermediates. The process unit can

consist of more than one unit operation. Chemical manu-

facturing process units may include, but are not limited

to: raw material storage, and air oxidation reactors and

their associated product separators and recovery de-

vices; reactors and their associated product separators

and recovery devices; distillation units and their associ-

ated distillate receivers and recovery devices; associated

unit operations; associated recovery devices; and any

feed, intermediate and product storage vessels, product

transfer racks, and connected ducts and piping. A chem-

ica] manufacturing process unit includes pumps, com-

pressors, agitators, pressure relief devices, sampling

connection systems, open-ended valves or lines, valves,

connectors, instrumentation systems, and process con-

trol or dual purpose air pollution control devices or sys-

tems. For a chemical manufacturing facility, there are

several types of process units: those that separate and

distill raw material feedstocks; those that change molec-

ular structures through reactions or polymerization;

those that “finish” the reacted or polymerized product,

through compounding, blending, or similar operations;

auxiliary facilities, such as boilers and by-product fuel

production; and those that load, unload, blend, or store

products. Process equipment that acts to control emis-

sions, such as condensers, recovery devices, and oxidiz-

ers, is considered part of the process unit.

We note that we were unable to include some other

process unit definitions submitted by commenters.

While we do not believe that these other proposed de-

finitions were necessarily inconsistent with our general

definition of process unit, we had concerns and questions

85a

with some of these proposed definitions. We believe that

now that this rule is issued, we can more fully evaluate

those other definitions, including communicating with

the leading industry officials, and determine whether we

would approve of their use.

Finally, we have made some slight corrections to

the process unit definitions that we proposed based on

comments we received on the proposed definitions.

There are numerous industries that have industrial

boilers at their facility to provide electricity and steam

to their operations. As a general rule, we would expect

these boilers to be tredted as a separate process unit

from the other unit operations occurring at the facility. _

We would expect the boundaries of the process units for

such boilers to be consistent with the boundaries estab-

lished under the definition for a steam electric generat-

ing facility in today’s rule, which encompasses all equip-

ment from coal handling to the emission stacks.

We also decided to continue to require that owners

or operators who have components shared by two or

more process units to proportionately allocate, based on

capacity, the cost of those components. And we agree

with the commenter that an equitable approach for elec-

tric utilities having components shared by two or more

process units is to allocate the cost of shared equipment

based on the pro rata share of megawatts produced by

eacn process unit.

$6a

G. Consideration of Non-Emitting Units as Part

of the Process Unit

Many commenters supported excluding non-emit-

ting equipment from the ERP. One commenter stated

that triggering the major NSR review process for main-

tenance activities is an impediment to continuous im-

provement projects for certain products and processes,

even if actual emissions decrease or only non-emitting

units on the process line are affected. Delays or post-

ponements of project maintenance work adversely affect

the reliability, safety and productivity of operations and

cost control efforts. Another commenter recommended

that work at clearly non-emitting units, specifically in-

cluding foundation regrouting and repair and frametop

replacement, should be excluded from this rule. Three

commenters believed that non-emitting units cannot

result in an increase of emissions and thus do not need

to be evaluated under major NSR.

A bianket exclusion for non-emitting units could

create problems of interpretation because the term

“non-emitting components” is ambiguous when consider-

ing certain components. Commenters asserted that

identifying and separating out non-emitting components

can be a complex undertaking, and may be contrary to

the goal of a clear and straightforward option. One

commenter provided the following examples: (1) Piping

systems (although pipe connectors are a source of fugi-

tive emissions, the pipe normally is not); and (2) struc-

tural supports for a process unit (separating out the cost

of supports from an investment basis throughout a facil-

ity will be difficult).

87a

Another commenter believed it would be difficult to

separate the costs of emitting and non-emitting equip-

ment when determining the cost of the process unit.

The commenter also believed it would be difficult to de-

termine allocation of shared equipment in the cost anal-

ysis.

We are concerned that, if owners or operators were

allowed to strip away all of the non-emitting components

from a process unit definition, it would create significant

ambiguity in the rule and could result in significant vari-

ation in how the rule is applied to similar sources in dif-

ferent jurisdictions. In addition, we simply do not think

it is practical or logical to separate “non-emitting” com-

ponents of a process unit from “emitting” components.

We believe that integrated manufacturing operations

(that is, process units) typically include both types of

equipment. Separating emitting from non-emitting

equipment would create an artificial divide that con-

trasts sharply with physical and operational reality.

As noted above, however, we do believe that a dis-

tinction should be made between non-emitting equip-

ment that is part of a process unit and non-emitting

equipment that is functionally distinct from the process

unit. For example, most production facilities have build-

ings or space to house administrative offices, such as

offices for the plant accounting staff. Such non-emitting

facilities should not be considered part of any process

unit under today’s rule.

88a

H. What Is the Accounting Basis for the Process

Unit?

In the proposal, the accounting basis for the ERP

discussed was the same as for the NSPS reconstruction

provision, which is the fixed capital cost that would be

required to construct an entirely new unit. We also dis-

cussed for the annual maintenance, repair and replace-

ment allowance using the invested cost of a unit as the

accounting basis. We proposed that it would be appro-

priate to require that costs be calculated using an ap-

proach along the lines set out in the EPA Air Pollution

Control Cost Manual (http://www.epa.gov/

ttn/cate/dir1/c__allchs.pdf). Finally, we solicited com-

ment on whether the costs associated with the unantici-

pated shutdown of equipment, due to component failure

or catastrophic failures such as explosions or fires,

should be included in evaluating costs under the ERP.

In reviewing comments, we recognized that some

commenters appeared to direct their comments on the

accounting methods at the annual maintenance, repair

and replacement allowance, and not necessarily the

ERP. Often, we came to this conclusion simply by the

way the commenters organized their comments, and not

by any specific statements in the comment letter. How-

ever, since we asked for comment on the accounting ap-

proaches as they would be applied to both the annual

maintenance, repair and replacement allowance and the

ERP, we believe that comments that appeared te be

dedicated to the annual maintenance, repair and re-

placement allowance should also apply to our evaluation

of the accounting for the ERP, except in the case where

the commenter specified that their comments on the

89a

proposed accounting methods applied only to the annual

maintenance, repair and replacement allowance or the

ERP. Likewise, for considering whether costs associ-

ated with unanticipated shutdown of equipment, we con-

sidered the comments to apply to both the ERP and the

annual maintenance, repair and replacement allowance

unless the commenter specifically noted that the com-

ment should not be applied to both of the peapenee rule

provisions.

Most commenters asked for flexibility on whether

a facility should use replacement value, invested cost or

insurance valuation as the basis for the calculations.

They felt that all were of equal merit and different ones

would be available at different facilities so EPA should

not prescribe only one type.

Most commenters did not support the sole use of

the EPA Air Pollution Control Cost Manual (APCCM)

to standardize calculations for replacement and repair

costs for RMRR in general. Most commenters felt that

the APCCM is a worthy reference for costing but also

that sources should not be limited to only one manual,

because a single manual is likely to have shortcomings

and not be able to represent every situation.

Many commenters supported an exclusion of costs

for unanticipated shutdowns and failures. They noted

that strong incentives exist to avoid fires, explosions and

other unanticipated equipment failures because of the

risk of human injury and production interruptions and

because of the expense involved in restoring lost capac-

ity. As a result, they contend that a catastrophic event

already penalizes the facility dramatically, but then to

90a

impose the case-by-case analysis would only exacerbate

their troubles. They explained that failures take place

occasionally and can result in a sudden, unplanned par-

tial or total loss of equipment. When such a failure oe-

curs at a natural gas compressor station, the turbine or

engine concerned must be replaced immediately to avoid

a disruption in gas supply. Other facilities may have

similar pressures to maintain their product around the

clock. Such replacement fits easily within most ele-

ments of the equipment replacement test. Commenters

asserted that replacing a catastrophically failed turbine

or engine is clearly “routine,” since companies will al-

ways replace such failures.

Other commenters, however, opposed an exclusion

for unanticipated shutdowns and failures on the grounds

that maintenance activities performed during forced

outages are simply maintenance and should be consid-

ered as such, particularly given that the proposed

RMRR rule approaches and the December 2002 final

rules already have given the industry a number of ex-

clusion options.

We are allowing sources to determine the applica-

bility of today’s rule on the basis of replacement value,

with an option for sources to notify their reviewing au-

thority in writing if they desire to use another option

(for example, invested cost or insurance value where the

insurance value covers only the complete replacement of

the process unit). The equipment replacement cost

should be based on the current replacement value of the

entire process unit at the time of conducting the activity.

9la

Typically, replacement value is more easily ob-

tained than invested cost. Most manufacturers will have

information concerning the replacement value of a pro-

cess unit, because such costs are commonly used when

evaluating various business scenarios relating to manu-

facturing costs. Also, use of replacement value is consis-

tent with the NSPS provisions.

In addition to determining the replacement value

of a process unit, in our final rule we allow for the use of

several other accepted methods in different industries

for estimating such values. Replacement values:are the

estimated value of replacing a unit and can be based on

a current appraisal. In lieu of replacement cost, you can

also use inflation-adjusted original investment, insur-

ance limits if insured for full replacement of the unit, or

other cost estimation techniques currently employed by

the company, as long as the company follows GAAP and

if approved by the reviewing authority.

A dollar-per-kilowatt rate for calculating costs may

be appropriate for utilities. This model is specific to

source and fuel type and is updated periodically. We

allow sources to use insurance valuation methods such

as the Handy-Whitman Index to determine replacement

costs for electric utilities. Other sources to compute

costs include the Nelson Refinery Construction Index

Factors, Solomon Refinery Study, and licensors of the

respective process unit (e.g., Kellogg, UOP).

In order for a cost-based approach to be equitable,

all owners or operators must include the same catego-

ries of expenses in both the process unit replacement

value and the replacement activities sought to be ex-

92a

cluded. Therefore, although the final rule does not man-

date any particular approach, we believe it is generally

appropriate to calculate costs using an approach similar

to the elements of Total Capital Investment as defined

in the APCCM. While the manual contains basic con-

cepts that could be used to estimate total capital invest-

ment at a process unit, it is geared toward cost calcula-

tions for add-on control equipment. On the other hand,

the underlying concepts are taken from work done by

the American Association of Cost Engineers to define

the components of cost calculations for all types of pro-

cesses, not just emission control equipment. In certain

cases, other manuals might make more sense depending

on their circumstances.

Under the APCCM, total capital investment in-

cludes the costs required to purchase equipment, the

costs of labor and materials for installing the equipment

(direct installation costs), costs for site preparation and

buildings, and certain other indirect installation costs.

However, any costs that are part of the installation and

maintenance of pollution control equipment should be

excluded from the cost calculation, per our discussion in

the previous section of this preamble. We believe equip-

ment that serves a dual purpose of process equipment

and control equipment (combustion equipment used to

produce steam and to control hazardous air pollutant

emissions, exhaust conditioning in the semiconductor

industry, etc. should be considered process equipment.

Direct installation costs include costs for founda-

tions and supports, erecting and handling the equip-

ment, electrical work, piping, insulation, and painting.

Indirect installation costs include such costs as: engi-

93a

neering costs; construction and field expenses (costs for

construction supervisory personnel, office personnel,

rental of temporary offices, etc.); contractor fees (for

construction and engineering firms involved in the activ-

ity); startup and performance test costs; and contingen-

cies.

We believe there may be merit to the comments we

received advocating a categorical exclusion for unantici-

pated shutdowns and failures of some kind. When such

an outage occurs, there may be a real urgency to restore

the plant to operation without forcing it to await the re-

sults of a permitting action or applicability determina-

tion. In the past, we have handled these situations with

case-by-case consent orders; however, even that ap-

proach may lead to unnecessary delays. It may specifi-

cally be sensible to relaxing the 20 percent cost thresh-

old limitation for such events because it is unlikely that

sources would incur an outage to avoid controls. We did

not propose such a stand-alone exclusion and hence we

believe we should not act upon it at this time.

I. Enforcement

1. Compliance Assurance

We believe that the records developed and main-

tained in the ordinary course of business will provide the

primary means of assuring compliance with today’s rule.

We know that, as a general rule, companies necessarily

generate and keep records related to the types of pro-

jects covered by today’s rule. For example, companies

generally have comprehensive procedures by which

funds are allocated to both capital and maintenance ex-

pense projects. Many of the records generated by these

94a

_ procedures are needed for tax accounting purposes and,

by law, must be maintained for at least 6 years. More-

over, additional records must be maintained in indus-

tries regulated for other purposes, such as the energy

sector (over 90 percent of which, by capacity, is subject

to FERC regulation). Public utilities, licensees and nat-

ural gas companies that are subject to FERC jurisdic-

tion must, unless they receive a waiver from the Com-

mission, comply with extensive accounting and record

retention requirements. They must keep financial infor-

mation according to uniform systems of accounts that

are set out in 18 CFR part 101 for public utilities and

licensees, and 18 CFR part 201 for natural gas compa-

nies. These uniform systems of accounts include hun-

dreds of specific accounts, including individual accounts

for boiler plant equipment, engines and engine-driven

generators, turbogenerator units, and hundreds of other

asset, liability, cost and property items.

These companies also must retain records accord-

ing to the schedules set forth in 18 CFR part 125 (for

public utilities and licensees) and 18 CFR part 225 (for

natural gas companies). The types of records that com-

panies must keep include, for public utilities and licens-

ees, for example, generation and output logs (records

must be kept for 3 years), load records (3 years), gauge-

reading reports (2 years), maintenance work orders and

job orders showing entries for labor, materials and other

charges in connection with maintenance and other work

pertaining to utility operations (5 years), work order

sheets for construction work in progress (5 years), ap-

praisals and valuations made of utility property or in-

vestments (3 years), engineering records, drawings, and

other supporting data for proposed or as-constructed

9Sa

utility facilities, including detail drawings and records of

engineering studies (must be kept until facilities are

retired), contracts or other agreements relating to ser-

vices performed in connection with construction of util-

ity plant (6 years after the plant is retired or sold), gen-

eral and subsidiary ledgers (10 years), paid and canceled

vouchers, and original bills and invoices for materials,

services, etc. (5 years).

Altogether, these various sources of information

provide more than reasonabie assurance of compliance

with today’s rule. This is particularly true given EPA’s

broad authority to inspect affected facilities and require

submission of compliance related data. Accordingly, we

are not imposing any recordkeeping requirements in

today’s rule.

2. General Issues

Today’s rule provides revisions to the major NSR

program to specify categories of equipment replacement

activities that we will consider RMRR in the future. As

recognized by the U.S. Supreme Court, an agency may

not promulgate retroactive rules absent express con-

gressional authority. See Bowen v. Georgetown Univ.

Hosp., 488 U.S. 204, 208, 102 L. Ed. 2d 493, 109 S. Ct.

468 (1988). The CAA contains no such expressed grant

of authority, and we do not intend by our actions today

to create retroactive applicability for today’s rule. 42

U.S.C. 7401 et seg. Today’s rule applies only to conduct

that occurs after the rule’s effective date.

None of today’s rule revisions apply to any changes

that are the subject of existing enforcement actions that

the Agency has brought and none constitute a defense

96a

thereto. Furthermore, prior applicability determina-

tions on major modifications that result in control re-

quirements in an NSR permit that currently applies to

a source remain valid and enforceable as to that source.

As noted above, today we are changing the scope of

the RMRR exclusion from the major NSR program by

taking final action on the ERP. If you subsequently un-

dertake an activity that does not meet the applicable

provisions of these new alternatives and do not obtain a

preconstruction permit if you are required to do so, you

will be subject to any applicable enforcement provisions

(including the possibility of citizens’ suits) under the

applicable sections of the CAA. Sanctions for violations

of these provisions may include monetary penalties of up

to $27,500 per day of violation, as well as the possibility

of injunctive relief, which may include the requirement

to install air pollution controls.

J. Quantitative Analysis

At proposal, we presented a quantitative analysis

of the possible emissions consequences of the range of

different approaches to the RMRR exclusion to evaluate

if our policy conclusions are correct. Our analysis was

conducted using the Integrated Planning Model (IPM).

This analysis was done for electric utilities because we

have a powerful model to perform such an analysis that

we do not have for other industries. We stated that the

results for electric utilities accurately reflect the trends

we would see in other industries.

The IPM analyses of different scenarios showed

that the breadth of the RMRR exclusion would have no

practical impact on, let alone be the controlling factor in

97a

determining, the emissions reductions that will be

achieved in the future under the major NSR program.

The analyses showed that emissions of SO, are essen-

tially the same under all scenarios, but that under to-

day’s rule these emission levels will be met in a more

economically efficient manner than the base case. This

stands to reason because nationwide emissions of SO,

from the power sector are capped by the title IV Acid

Rain Program. For NQ,, these analyses showed modest

relative decreases in some cases and modest relative

increases in other cases. These predicted changes rep-

resent only a fraction of nationwide NO, emissions from

the power sector, which hover around 4.3 million tons

per year (tpy). At this time, we do not have adequate

information to predict with confidence which modeled

scenario is most likely to occur. What these analyses

indicate, however, is that regardless of which scenario is

closest to what comes to pass, today’s rule will not have

a significant impact, up or down, on emissions from the

power sector. However, we expect the rule to result in

significant improvements in safety, reliability, and other

relevant operational parameters.

The DOE also presented further analysis of the

possible emissions consequences of the range of differ-

ent approaches to the RMRR exclusion. Using the Na-

tional Energy Modeling System (NEMS), a variety of

changes in energy efficiency and availability were evalu-

ated, as well as the effect on emissions resulting from

these regulatory revisions. This analysis concluded that

efficiency improvements resulting from increased main-

tenance, repair and replacement are expected to de-

crease emissions, whereas availability improvements are

expected to increase emissions. In the cases repre-

98a

sented in this analysis, the emissions reductions from

assumed reductions in heat rates tended to dominate the

corresponding effects of the assumed availability in-

creases.

A number of commenters said that the underlying

assumptions EPA used in the IPM analysis were flawed

and resulted in erroneous conclusions regarding the

emission reduction potential of the proposed RMRR

rules. Several commenters stated that EPA’s IPM anal-

ysis incorrectly assumes that no major modifications at

any older units would ever trigger the requirement to

add new pollution controls. In addition, according to

commenters, EPA also erroneously assumed that this

lack of major maintenance, repair and replacement will

have very little impact on the performance of those

power plants, when in reality their emissions would in-

crease significantly. The commenters cited a Clean Air

Task Force analysis for power plants, which estimates

that EPA’s rule revisions will result in at least 7 million

more tons of SO, and 2.4 million more tons of NO, annu-

ally. Some commenters also questioned the appropriate-

ness of using EPA’s analysis for the electric generating

sector to draw conclusions about non-utilities.

One commenter said the IPM and DOE NEMS

analyses correctly demonstrate that EPA’s RMRR pro-

posal will have no appreciable impact on emissions from

the power sector. According to the commenter, this con-

clusion is consistent with EPA’s findings in a 1989 re-

port, “1989 EPA Base Case Forecasts,” which demon-

strated that continuing to allow utilities to undertake

activities including ongoing annual operating and main-

tenance activities and a major refurbishment when the

99a

unit reached 30 years of operating life would have no

appreciable impact on emissions from the power sector,

just as EPA’s and DOEF’s recent analysis confirmed.

One commenter said the proposal lacks any refer-

ence to the gains accomplished by major NSR, the ongo-

ing enforcement actions, settlements reached as a result

of those actions, or the potential gains from the investi-

gations now pending. The commenter argued that EPA’s

reliance on improvements in productive capacity as the

measure of success fails to consider that productive ca-

pacity must be balanced with the interests of health and

welfare. The commenter also noted that a critical part

of EPA’s burden is to consider all the relevant factors

leading to its conclusion that the exclusions are neces-

sary and appropriate and that at the very least this in-

cludes an assessment of the expected effects on emis-

sions, which in turn will determine the public health ben-

efits and costs of the proposed rule. Although data on

emission reductions achieved under the existing pro-

gram are available, we have stated that we cannot pre-

cisely quantify the effects the proposed rule will have on

emissions. Some commenters stated that before promul-

gating a final rule, EPA should provide such a quantita-

tive assessment of the rule.

We disagree with the commenters who believe that

emissions would be significantly higher for electric utili-

ties than are estimated under the IPM model runs.

These commenters’ arguments rely on the assumption

that EPA’s base case is invalid because, if major NSR

rules were left unchanged, eventually all coal-fired utili-

ties would either apply BACT or deteriorate so badly

that they would

This text is long and has been trimmed here. Open the source document for the complete record.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.