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No. 06-736

In the Supreme Court of the United States

UNITED STATES ENVIRONMENT PROTECTION AGENCY, PETITIONER

v.

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
Assistant Attorney General

THOMAS G. HUNGER
Deputy Solicitor General

JAMES A. FELDMAN
Assistant to the Solicitor
General

THOMAS A. LORENZEN
ANGELINE PURDY
Attorneys
Department of Justice
Washington, D.C. 20530-0001
(202) 514-2217

ROGER R. MARTELLA
Acting General Counsel
Counsel of Record

ELLIOTT B. ZENICK
Assistant General Counsel

JONATHAN C. AVERBACK
Attorney

United States Environmental
Protection Agency
Washington, D.C. 20460

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

V.

ENVIRONMENTAL PROTECTION AGENCY, RESPONDENT

CLEAN AIR IMPLEMENTATION PROJECT, ET AL., INTERVENORS

Argued Feb. 8, 2006.
Decided March 17, 2006.
Rehearing en Banc Denied June 30, 2006

Before: ROGERS, TATEL and BROWN, Circuit Judges.

Opinion for the Court filed by Circuit Judge ROGERS

ROGERS, Circuit Judge.

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 to avoid triggering New Source Review ("NSR"). The court upheld in part and vacated in part the first rule. Id. 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.1 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 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 minimis 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(cc)(2005).2

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." Id. 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. "If a 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, 130 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." Id. 1706. The parties agree that in "[r]eal-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," id. 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 "[r]ead 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, 130-31, 122 S. Ct. 1230, 152 L.Ed.2d 258 (2002); Gonzales, 520 U.S. at 5, 117 S. 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." Id. 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.'" Id. 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." Id.

Although EPA is correct that the meaning of "any" can differ depending upon the statutory setting, see Nixon v. Missouri Mun. League, 541 U.S. 125, 132, 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, 124 S. 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 intended 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," id. at 400. The court further observed that "[i]mplementation of the statute's definition of 'modification' will undoubtedly prove inconvenient and costly to affected industries; but the clear language of the statute unavoidably imposes these costs except for de minimis increases." Id. More recently, in New York I, 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 I, 413 F.3d at 40-42. Likewise, the Seventh Circuit con cluded in WEPCo 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'l Cable & Telecomms. Ass'n v. Brand X Internet Servs., --- 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 I, 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 that, 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 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 world3 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 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., 534 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 I, 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 "[r]eal-world, common-sense usage of the word 'change.'" Id. 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 that the change increase emissions. See 42 U.S.C. § 7411(a)(4).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 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 I, 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 I 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 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." Engine 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.

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 I, 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 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.

 

1 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.

2 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 (cc)(1) through (cc)(3)of this section are met.

40 C.F.R. § 52.21(cc). Paragraph (cc)(1) establishes that the fixed capital cost of the replacement component cannot exceed twenty percent of the replacement value of the process unit. Paragraph (cc)(2) states that the replacement cannot change the basic design parameters of the process unit. Paragraph (cc)(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.

3 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)).

4 The court has no occasion to decide whether part replacements or repairs necessarily constitute a "modification" under the definition taken as a whole.

 

 

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

v.

ENVIRONMENTAL PROTECTION AGENCY,
RESPONDENT

CLEAN AIR IMPLEMENTATION PROJECT, ET AL., INTERVENORS

[Filed On: June 30, 2006]

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

O R D E R

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.

APPENDIX C

RULES AND REGULATIONS
ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51 and 52

[FRL-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 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 a NAICS b

Electric Services .

491

221111,

221112,

221113,

221122,

2211119,

2211121,

Petroleum Refining

291

324110

Industrial Inorganic

Chemicals

281

325181, 325120,
211112, 325998,

325131,

331311,

325182,

25188

Industrial

Organic

Chemicals

286

325110,

325132,

325193,

325192,

325120,

325188,

325199

Miscellaneous Chemical Products

289

325520,

325920,

325910,

325182, 325510

Natural Gas Liquids

132

211112

Natural Gas Transport

492

486210, 221210

Pulp and
Paper Mills

261

322110,

322121,

322122,

322130

Paper Mills

 

262

322121, 322122

Automobile Manu-
facturing

. . 371

336111,

336322,

336350,

336112,

336312,

336399,

336211,

336330

336212

336992,

336340,

336213

Pharmaceuticals

283

325411,

325412,

325413,

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

A. How can I get copies of this document and other related information?

1. Docket

2. Electronic Access

B. Where can I obtain additional information?

II. Background

A. What is the RMRR exclusion?

B. Issues surrounding the RMRR exclusion

C. Process used to develop this rule

D. What we proposed

III. Equipment Replacement Provision

A. Overview and justification for today's final action

B. What is an identical or functionally equivalent replacement and why should such an activity be consid ered RMRR?

C. What cost limit has been placed on the equip ment replacement approach?

D. What will be the basis of applying the 20-per cent threshold?

E. What basic design parameters are being estab lished to qualify for the equipment replacement provi sion?

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?

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

I. General Information

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 Register document electronically through the EPA 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

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 I.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 additional information about EPA's electronic public docket visit EPA Dockets online or see 67 FR 38102, May 31, 2002.

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 TTN'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.

II. Background

A. What Is the RMRR Exclusion?

Title I of the Clean Air Act (CAA) established the New Source Review program5 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.

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.6 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.

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.

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.

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 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 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 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 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.

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 adopt 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 for administering the RMRR provision.

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 until May 2, 2003-120 days following publication in the Federal Register.

Under the "annual maintenance, repair 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 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.

III. 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 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)7 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),8 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 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 rate9 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;10 (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 erally Accepted Accounting Principles (GAAP). The GAAP are the conventions, rules and procedures 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 process 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 rules also set forth a definition 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 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 to 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.

B. What Is 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 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 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 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 I 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-of-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 le gal analysis below.

The following examples of functionally equivalent replacements under today's rule include:11

o 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).

o 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 analog 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.

o 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).

o 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 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 added that, without a clearer understanding of which activities are RMRR, they may be inclined to delay conducting such replacements.

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 source 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 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 when 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 will 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 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.

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 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.

C. What Cost Limit Has Been Placed on the Equipment 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 further 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 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 reviewing authority determines whether the proposed project is a reconstruction.12

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.

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 propriate percentage for electricity producers is 0.1 to 1.0 percent. Another 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 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.

In the WEPCO case, the Court considered an activ ity involving 5 coal-fired units at WEPCO'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 several 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. WEPCO 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 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.13 Thus, the capital cost percentage for the replace ment activities at WEPCO, 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 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 have a 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 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 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 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 tric 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 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- 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 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. 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-specific 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 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 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 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.

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 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 parameters. 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.

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 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 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 manufacturing, 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.

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 ing associated pollution control equipment from the defi nition of the "process unit," except for control 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-NOX 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.

o 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.).

o 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 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.

o 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.

o 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.

o 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 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 ical 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 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 treated 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 each process unit.

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 blanket 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).

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.

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/catc/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 to 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 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 proposed 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 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 oc 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.

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 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 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 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 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 reasonable 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 seq. 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 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 determining, the emissions reductions that will be achieved in the future under the major NSR program. The analyses showed that emissions of SO2 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 SO2 from the power sector are capped by the title IV Acid Rain Program. For NOX, 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 NOX 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 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 SO2 and 2.4 million more tons of NOx 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 unit reached 30 years of operating life would have no appreciable impact on emissions from the power sector, just as EPA's and DOE'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 have to shut down. We do not believe this assumption is accurate. As we have explained, our experience suggests that under the current NSR pro gram, managers of coal-fired electric generating facili ties have available to them a number of actions they can take to avoid triggering major NSR, and in many in stances they will take one of these actions to avoid the high retrofit costs and delays in obtaining a major NSR permit. If necessary, owners or operators can and will limit their activities to those that do not trigger major NSR, and will take enforceable restrictions on fuel use or other actions to avoid major NSR. This results in some decline in efficiency and capacity, as the EPA's base case modeled, but the units would likely remain viable electric generating units for years without trig gering BACT requirements. Thus, we believe our base case represents a far more realistic assessment of what would happen under current major NSR rules than the dramatic BACT reductions presented by these commenters.

Furthermore, while some of the facilities may be modified and subjected to control, nationwide emissions as estimated in the model runs would still rise to the level of the Acid Rain cap for SO2. To the degree these modifications come at facilities that are otherwise pro jected to be controlled because of existing SO2 and NOX requirements, there would be no difference in effect be tween the model runs and alternative scenarios. We agree with the commenter who noted that the recent analysis and the estimated impact on emissions is consis tent with the previous EPA report in 1989. Our recent analysis confirms that efficiency improvements have the potential to result in environmental benefits that offset (or more than offset) emissions increases from improved availability, but that previous major NSR rules discour aged these improvements.

Regarding the applicability of our analysis to non- utility sectors, we continue to believe that our conclu sions are valid for all sectors, and further, that the ef fects from the electric utility industry dominate those from other sectors. We acknowledge that the results for the SO2 cap for utilities cannot be extended to non-utili ties that are not similarly capped. However, our model runs for NOx reflected the absence of a cap, and are therefore valid for other uncapped sectors. Thus in the case of industrial boilers, which behave similarly to utili ties, we would expect to see similar efficiency improve ments and availability improvements occurring in tan dem, resulting in either modest increases or decreases. Because the overall emissions from this sector are sig nificantly smaller than for utilities, the modeled effects for utilities are expected to dominate the analysis.

For other industrial sectors, we do not anticipate that emissions increases will result from equipment re placement activities that qualify as RMRR under today's rule. While some efficiency improvements may result, the overall effect of these improvements will not be to induce greater demand and greater emissions, in con trast to the effect shown by the modeling for utilities (i.e., demand for other industrial sectors depends on independent factors). Indeed, without increased de mand, efficiency improvements that lower emissions per unit of output would result in a decrease in emissions.

A number of commenters raised concerns that EPA had not analyzed the impact of the final rule on indus tries other than for electric utilities. We have, thus, sup ported further efforts to analyze empirically the effects of this rule. This work is included in the Regulatory Im pact Analysis (RIA) for the final rule. Even the experts involved in this analysis emphasize that empirical as sessments of the costs, emissions, and other economic and environmental effects of this rule are extremely difficult to perform, particularly when generalizing be yond the specific industrial sector and type of facility involved. The analysis would have to simulate a great many decisions made by each plant involving routine maintenance under a variety of policy scenarios. There is simply no credible way to make these assessments for the entire economy or for an entire sector. Hence, with the exception of the electric utility industry model, we relied on a case study approach to gain insights as to how this rule affects particular industrial sectors.

A series of case studies were analyzed by an EPA contractor to estimate the overall impact of the final rule on six different industrial sectors (automobile manufac turing, carbon black manufacturing, natural gas trans mission, paper and pulp mills, petroleum refining and pharmaceutical manufacturing). The analysis was de signed to examine effects of the final rule, but it is im portant to note that the case studies were performed prior to decisions on the exact form and content of the final rule. For example, the selection of process units for each of the industries may not be an accurate depic tion concerning how a particular industry's operations should be separated into process units under the final rule. As such, none of these characterizations should be taken as EPA's position on appropriate process units for a given industry. (Information on that subject can be found in Section III.F of the preamble and in the final rule for selected industries.) In addition, in costing out replacement activities in the different industries, the contractor made assumptions regarding which costs needed to be included and how multiple replacement activities should be grouped that may not be consistent with the final rule. Again, these assumptions on the part of the contractor should not be interpreted as EPA's conclusions of how their rules should be applied to such replacement activities in these industries.

Even with these caveats, the case studies provide useful insight into the potential effects of the final ERP. The six industries are significant sources of air pollution emissions and are very diverse in terms of their types of operations, their existing maintenance, repair and re placement strategies, and the range of potential replace ment costs at some of their process units. This diversity is important because the final rule will impact a great many industrial sectors and individual process units which are extremely varied in terms of their mainte nance, repair and replacement strategies. For example, issues related to safety, reliability and availability will vary greatly across these industries. The need to assure that the electricity and natural gas supply is reliable and available is critical to ensuring the safety of the public in the hottest and coldest times of the year, and it is criti cal to the operation of the nation's infrastructure, to the degree they do not have backup power generation, de voted to public health (e.g., drinking water, sewage treatment, food refrigeration, hospitals). Thus, strate gies related to maintenance, repair and replacement at existing facilities are critical to ensure that vital electric utilities and natural gas transmission continue uninter rupted. As we are clarifying what activities fall within the ERP, owners or operators at these facilities will be able to make decisions on when and how to conduct RMRR activities based on engineering judgement.

The case studies conclude that equipment replace ment activities vary widely within these industries for the process units selected. Across the industries, the studies estimated that equipment replacement activities could range in percentage by over an order of magni tude. By establishing a threshold at 20 percent of the replacement cost of the process unit, we believe we have set a reasonable standard that allows most replacements to proceed unimpeded as long as the other safeguards are met. At the same time, under the 20 percent thresh old, the most capital-intensive replacements would be subject to case-by-case review. The data from these case studies clearly indicate that 20 percent would func tion well as the dividing line between those replacement activities that automatically qualify under the ERP and those activities which should be subject to case-by-case review.

The case studies also indicate that replacement activities in these industries should not lead to increased emissions at the sources. Based on the case studies, we believe that replacement with identical or functionally equivalent equipment as the rule requires, will result in equivalent or reduced emissions. The decrease in emis sions would result from efficiency improvements that reduce the amount of air pollution emitted per product produced in the process unit. Therefore, if operating levels do not change, then total emissions will decrease with such identical or functionally equivalent equipment replacements.

The case studies looked at a wide range of projects. We have concluded based on this analysis that replace ment activities do not generally cause changes in operat ing levels at the process unit. Instead, other factors, like economic downturns or increased demand for the product of the process unit, will cause operating levels to fluctuate. Efficiency changes, even when they lead to increases in product output from the same raw material input will not lead to increases in emissions unless an independent factor like increased demand for the prod uct also occurs. We strongly support efficiency improve ments where they can occur as long as the other safe guards in the rule are met.

Our inability to model economy-wide impacts does not mean we cannot characterize the effects of this rule. In qualitative terms, the case studies further support our conclusion that the old case-by-case approach to RMRR is having perverse effects by discouraging pro jects that would improve efficiency. As noted elsewhere, efficiency improvements necessarily imply less pollution holding everything else constant. For example, the case study on the pulp and paper industry finds that:

[A]s [safety, reliability and efficiency] activities begin to be reviewed, those that raise * * * ques tions under the ambiguity of the current rules may be postponed, altered, or simply cancelled. Under the proposed ERP approach, these activities can be tested against a clearer set of criteria, that will allow more activities to be executed.

* * * The new approach provides the regulatory clarity and certainty in making applicability deci sions that is completely absent from the current case-by-case approach. Thus, the manner in which mills will handle the processing of equipment re placement activities, with regard to assessing their air permit applicability assessments, will be able to be streamlined. By definition, a "case-by-case" approach is simply unworkable for a typical pulp and paper mill, which may have thousands of main tenance and repair related work orders involving equipment replacements executed each year, af fecting all areas of mill operations. Clearly, only a small subset of these equipment replacement activ ities can be evaluated using the complicated and vaguely interpreted multi-factor test inherent with the current case-by-case approach. * * * The proposed ERP approach helps by setting criteria for the routineness determinations. Under the pro posed approach, a mill could set up more straight- forward guidelines to be followed throughout an organization that would allow quick and defensible determinations to be made regarding individual maintenance activities.

Based on the analytical work performed by the con tractor for pulp and paper, we expect that, at such facili ties, the power boiler would be the most affected by the ERP, as well as an important or even dominant emis sions source. We would anticipate that this would be true for many of the inorganic and organic chemical subsectors. In fact, we did not pursue an analysis of the chlor-alkali sector, in large part because the power boiler was the most obvious process unit to analyze, and the issues raised overlapped with the pulp and paper analysis. Thus, it is logical that the conclusions from the case studies would generalize to many other sectors.

Beyond the case studies, there is also a great deal of research and experience that allows for some robust findings. Previous research, such as the articles cited below, supports the following findings:

o Enhanced efficiency and less pollution in the short run. Holding everything else constant, when a plant's efficiency increases, pollution must go down. This nation's growing experience with pollution preven tion, efficiency enhancements, voluntary environmental programs, and Environmental Management Systems adoption all reinforce the notion that enhanced plant efficiency translates into less environmental pollution.14 Further, there is an economic incentive to keep plant efficiency high. Proper maintenance and the resulting efficiency enhancements and pollution prevention re duce resource needs and therefore reduce costs.15 By providing the certainty needed to plan and undertake efficiency investments (economically efficient mainte nance) this rule will achieve lower pollution.

o The rule will allow firms to take advantage of pollution prevention opportunities and new, innovative pollution-reducing technologies. As technology ad vances, plants will be able to replace existing compo nents with functionally equivalent components that en hance energy efficiency (and reduce pollution).16 One example of such an opportunity identified by the EPA contractor in one of the case studies is the replacement of spray guns on a topcoat operation in order to improve the quality of the paint job, while also increasing the transfer efficiency, and decreasing coating and associ ated solvent usage. This project could be deemed a physical change and have major NSR applicability rami fications if not for the ERP of the RMRR exclusion. Un der the current case-by-case approach to RMRR, the facility may forego the change to the newer spray gun design if there is a perceived risk that the determination could be questioned. Under the new ERP approach, the change would proceed more definitively as RMRR, and thus the emission reductions could be realized.

o While firms can operate existing plants effi ciently, the rule preserves powerful incentives within the CAA to adopt "leap-frog" technologies and produc tion processes that further reduce costs, increase effici encies and reduce pollution. Because of the CAA re quirements and economic gains associated with im proved efficiency, producers still have an incentive to invest in these clean technologies to replace older facili ties.

In addition, a substantial body of research has ex plored the consequences of environmental regulation that sets more stringent control requirements for new sources. This research explores how differentiated reg ulation can affect firm behavior both on theoretical and empirical grounds. A listing of some of this literature is included in the RIA for the final rule. This literature provides further evidence that the NSR can easily dis tort investment and production decisions against more efficient maintenance and replacement.

Therefore, based on the information evaluated, we affirm the overall conclusion of our analysis-that to day's rule has no practical effect on the environmental benefits of major NSR in the future. We have presented additional, more detailed supporting information in our final RIA and our response to comments document, both of which can be found in the docket for today's action.

K. Consideration of Other Options

In addition to the cost-based approaches that we proposed, we also asked for comment on age-based and capacity-based approaches, and any other viable option for addressing RMRR.

1. Annual Maintenance, Repair and Replacement Allowance

We are not taking action on the proposed Annual Maintenance, Repair and Replacement Allowance option for the RMRR exclusion, and therefore public comments

on this option are not addressed at this time. We will address comments on our proposed Annual Mainte nance, Repair and Replacement Allowance if and when we take final action on that proposal.

2. Capacity-Based Option

As mentioned above, we considered the alternative option of developing an RMRR provision based on the capacity of a process unit. Under such an approach, an owner or operator could undertake any activity that does not increase the capacity of the process unit. Bas ing RMRR on capacity has appeal for several reasons. For starters, an objective of RMRR is to keep a unit operating at capacity and/or availability. In addition, the linkage between capacity and environmental impact is more apparent than that between cost and environ mental impact. Finally, this type of approach might, in principle, be easier to use before beginning actual con struction than some of the cost-based approaches.

Several commenters were concerned with defining the capacity of a process unit. Capacity may be defined based on input or output. Nameplate capacity of a pro cess unit may vary greatly from the capacity at which the process unit may be able to operate. It may be more appropriate in some industries to measure capacity based on input while in others on output. Commenters felt that a capacity-based approach would not be work able at complex manufacturing sources, because "capac ity" as a useful shorthand term for the processing capa bility correlates exactly only with a historical feed or product slate no longer available or made. A number of commenters supported a capacity-based option, gener ally indicating that a capacity-based option would be simpler and less burdensome to use than the other pro posed approaches.

Another large concern of commenters was that a capacity-based approach could prevent facilities from performing activities that make the facilities more effi cient. RMRR provisions need to include some form of the other approaches to account for energy efficiency projects at utilities, which could increase output capacity (i.e., production) without necessarily increasing heat input or fuel consumption. Some commenters noted that maximum hourly emissions is a more appropriate surro gate for a change in capacity, because it is consistent with existing NSPS procedures and with averaging peri ods for ambient air quality monitoring and standards.

We agree that an appropriate capacity-based ap proach would have to be tailored to various types of sources, with capacity based on input for some and on output for others. As an example, in a review of promul gated and proposed Maximum Achievable Control Tech nology standards, six of eleven standards measured ca pacity based on process unit output while five standards based capacity on input. In fact, the NSPS exclusion for increases in production rate at 40 CFR 60.14(e) origi nally was dependent upon the "operating design capac ity" of an affected facility. In proposed revisions to the NSPS program published on October 15, 1974, we state (39 FR 36948):

"The exemption of increases in production rate is no longer dependent upon the "operating design capac ity." This term is not easily defined, and for certain in dustries the "design capacity" bears little relationship to the actual operating capacity of the facility."

We also agree that a capacity-based approach has its limitations, as described by the commenters. We have concluded that the ERP eliminates the need to im plement the capacity based approach. We have decided not to finalize a capacity-based approach.

3. Age-Based Option

Under our proposed age-based approach, any pro cess unit under a specified age could undergo any activ ity that does not increase the capacity of a process unit on a maximum hourly basis without triggering the re quirements of the major NSR program. However, the activities could not constitute reconstruction of the pro cess unit; that is, their cost could not exceed 50 percent of the cost of a replacement process unit. The age of the process unit would likely be in the range of 25-50 years. We also proposed that the owner or operator would have to become a Clean Unit as defined at 40 CFR 51.165(c)(3), 51.166(t)(3), and 52.21(x)(3), once the age of a process unit exceeds the age threshold.

Such an approach would provide an owner or oper ator a clear understanding of RMRR for an extended period of time. It also may provide the owner or opera tor greater flexibility than under the current system for a limited period of time. Like the capacity-based ap proach, this approach would, in principle, allow for a fairly simple preconstruction determination of applica bility.

Very few commenters expressed any interest in developing this type of approach. Their concerns cen tered around defining capacity and establishing the age cut-off (because the useful life of equipment is difficult to establish and may vary greatly). Other concerns raised by commenters were that some of the activities that would be allowed at newer sources do not fit within any ordinary meaning of RMRR and some of the activi ties that would be forbidden at older facilities would come within that meaning, and also that some sources may consciously, and appropriately, engage in aggres sive RMRR as a method of maximizing the life span of its process units, and an age-based approach would dis criminate against them.

One commenter stated that EPA should establish a normal lifetime, tailored to each industry, beyond which industry would need to install BACT or shut down. This type of approach would obviously require a substantial amount of time and analytical effort.

The age of a source alone is not a legitimate rea son to require the addition of pollution control equip ment. Age has no direct bearing on a unit's environmen tal impact; some facilities maintain equipment better than others. We have decided not to promulgate an age- based approach. We have several basic concerns with this approach that we have not been able to reconcile. We also believe that the equipment replacement ap proach largely addresses the commenters' concerns re garding the age-based approach.

Thus, we have decided not to finalize a rule using this approach.

L. Specific List of Excluded Activities

Several commenters supported the development of lists of activities that are considered RMRR; some of these commenters also supported developing lists of activities that do not qualify as RMRR. Commenters suggested various ways in which such lists could fit into the overall RMRR program. We are concerned, how ever, that such a list would have to be implemented through rulemaking, which would require a considerable amount of time, analytical effort, and resources.

A commenter suggested two ways by which we could develop a list of qualifying activities. First, we could review records for ongoing enforcement activity, to identify activities that we have and have not already alleged to be RMRR. There is an ample body of knowl edge for electric power plants. Second, we could iden tify where activities would fall with respect to the cost criteria, then adjust the classification of each activity based on the WEPCO criteria to prepare lists of routine and nonroutine activities.

Some commenters felt that industry-specific lists of routine and nonroutine activities would provide the best interim clarification to major NSR until legislative reform is in place. Other commenters opposed the de velopment of lists of activities that are considered RMRR, contending that such lists would become quickly outdated.

Some commenters requested that certain activities be specifically classified as RMRR. These suggested activities included the following:

o The common practice of changing out the engine core in a combustion turbine when it is due for overhaul (to reduce downtime). The removed engine core is over hauled offline, and is then available to be switched in for the next like-kind engine core that reaches the point of overhaul. Unless the components are upgraded, the heat input remains the same and so does the emissions rate.

o Any change that does not increase the achievable hourly emissions (as determined based on the permit and/or original design parameters) of existing equip ment, processes, and emissions units.

o Certain activities, for example, boiler tuning and maintenance, repair and replacement of air pollution equipment or CEMS should be categorically excluded as RMRR.

o Any activity that is part of a long-term service agreement (primarily gas turbines) should be categori cally excluded from major NSR.

o Any activity involving steam turbine overhaul work should be categorically excluded from major NSR.

Activities such as the above might be RMRR, but we believe there are simply too many activities in too many industries to effectively improve major NSR im plementation through creation of lists. Moreover, lists would be a "snapshot in time" that would need to be re viewed and periodically updated for each industry sec tor. We have consequently decided not to attempt to list activities that are categorically excluded as RMRR.

M. Stand-Alone Exclusion for Energy Efficiency Projects

In the proposal, we acknowledged that certain types of activities that improve energy efficiency would not qualify as RMRR. We solicited comment on whether there was the need for a "stand-alone" exclusion for ac tivities that promote energy efficiency.

Many commenters supported a stand-alone exclu sion from major NSR for energy efficiency projects. With the following safeguards, they favored specifically excluding from the definition of "major modification" activities that promote energy efficiency and/or resource conservation when: (1) The activity results in lower emissions per unit of production or lower energy utiliza tion per unit of production; (2) the percent decrease in emissions or energy utilization per unit of production is greater than the percent increase in maximum hourly emission rates; (3) activity costs do not exceed 50 per cent of the replacement value of the process unit; and (4) the activity does not result in an increase in allowable emissions.

Other commenters pointed out that efficiency up grades will frequently create incentives to further utilize a source and subsequently increase mass emissions. One commenter stated that if activities that result in small efficiency gains can qualify as RMRR, older, dirt ier electric generating units will be better able to out- compete newer, much cleaner plants (that have higher costs due to emission controls).

One commenter stated that EPA is incorrect in stating that energy efficiency projects are being discour aged by major NSR, particularly under the new actual- to-projected-actual applicability test. This commenter added that the only projects that are discouraged by major NSR are ones that increase emissions. This commenter felt that the December 2002 final major NSR rules provide a broad range of major NSR exclusions (including revised baseline determinations, Clean Unit designations, pollution control projects, PALS, and com binations of these provisions, as well as an RMRR exclu sion) under which energy efficiency projects will cer tainly occur.

We strongly support efforts to improve energy effi ciency at existing power plants. These activities reduce the amount of air pollution emitted per unit of electricity generated. We believe that today's ERP supports en ergy efficiency projects and that the actual-to-projected- actual applicability test contained in the December 2002 NSR final rules also should remove impediments to en ergy efficiency projects. Together, these rules will obvi ate the need for a specified RMRR provision for energy efficiency projects. Thus, at this time we are not finaliz ing a provision to categorically exclude energy efficiency projects from major NSR.

N. Legal Basis

1. How Does the NSR Program Address Existing Sources and Why Is Today's Rule Consistent With This Approach?

The core of the NSR program is to require precon struction permits for all new major sources. Congress specifically decided that existing sources generally would not be required to obtain permits. These consid erations are the starting point for understanding its ap plication to "modifications" and the meaning we should give that term.

The NSR program's scope is closely related to the scope of the NSPS program, created seven years earlier in the CAA Amendments of 1970. In section 111 of the CAA, which sets forth the NSPS provisions, Congress applied the New Source Performance Standards to "new sources," secs. 111(b)(1)(B), 111(b)(4). Congress deter mined that as a general matter it would not impose the NSPS standards on existing sources, instead leaving to the State and local permitting authorities the decision of the extent to which to regulate those sources through "State Implementation Plans" designed to implement National Ambient Air Quality Standards (NAAQS). See sec. 110.

Congress followed a similar approach in determin ing the scope of the major NSR program established by the 1977 Amendments to the CAA. As amended, the CAA specifies that State Implementation Plans must contain provisions that require sources to obtain major NSR permits prior to the point of "construction" of a source. Secs. 172(c)(5); 165 (a). By contrast, the CAA generally leaves to State and local permitting authori ties in the first instance the question of the extent, means and timetable for obtaining reductions from ex isting sources needed to comply with National Ambient Air Quality Standards. See secs. 172(c)(1), 161.

NSR's applicability to existing sources to which a "modification" is made is an exception to this basic con cept. This exception likewise finds its roots in the NSPS program's applicability to "modifications" of existing sources. The 1970 CAA made the NSPS program appli cable to modifications through its definition of a "new source," which it defined as "any stationary source, the construction or modification of which is commenced af ter the publication of regulations * * * prescribing a[n applicable] standard of performance * * * ." Section 111(a)(2). Section 111(a)(4), in turn, defined a "modifica tion" as "any physical change in, or change in the method of operation of, a stationary source which in creases the amount of any air pollutant emitted from such source or which results in the emission of any air pollutant not previously emitted."

Congress did not further define the terms "physi cal change" or "change in the method of operation" in the NSPS program. Therefore we issued regulations to clarify their meaning. As early as our 1971 NSPS regu lations, we have made clear that many activities that do not affect the contemplated operation of a unit in a man ner consistent with its original design are not physical or operational changes. Specifically, in our 1971 NSPS regulations, we determined that physical or operational changes do not include:

(1) "Routine maintenance, repair and replace ment" of equipment;

(2) "An increase in the production rate, if such increase does not exceed the operating design ca pacity of the affected facility";

(3) "An increase in the hours of operation"; and

(4) "Use of an alternative fuel or raw material if * * * the affected facility is designed to accommo date such alternative use."

36 FR at 24877 (Dec. 23, 1971). The premise behind characterizing these activities as not being "changes" is that they all contemplate that the plant will continue to be operated in a manner consistent with its original de sign.

The 1977 Amendments to the CAA likewise made the NSR program applicable to "modifications." The original 1977 Amendments did so explicitly only in their provisions dealing with the non-attainment portion of the NSR program, see CAA sec. 171(4). But in "techni cal and conforming" amendments to the 1977 Amend ments, Congress clarified that it intended the same re sult with respect to the prevention of significant deterio ration provisions, see CAA sec. 169(2)(C).

Notably, Congress did not enact a new definition of "modification" in either the original 1977 Amendments or the "technical and conforming amendments." Rather, it incorporated the NSPS definition of "modification" by cross-reference. See CAA sec. 169(2)(C); CAA sec. 171(4). In moving the adoption of those amendments, the sponsor (who was also the sponsor of the original 1977 Clean Air Act Amendments and who indicated that the technical amendments had been approved by all members of the original 1977 Amendments conference committee) stated in a summary and statement of intent that he placed in the Congressional Record that this was a deliberate choice. As that summary explained, Con gress intended the amendment "implement[ed] the [1977 Clean Air Act Amendments] conference agreement to cover "modification" as well as "construction" by defin ing "construction" in part C to conform to usage in other parts of the Act." 123 Cong. Rec. 36331 (Nov. 1, 1977). We have understood this to be a reference to our preex isting rules interpreting the term "modification" in the NSPS context. 49 FR 43211, 43213 (1984); see also 43 FR 26388, 26394, 26397 (June 19, 1978).

The original 1978 NSR rules concerning modifica tions that we promulgated after enactment of the 1977 Amendments generally tracked the NSPS approach by specifying that "routine maintenance, repair and re placement" was not a change; by specifying that changes in hours of operation and rates of production were not a "change'; and by using the same basic approach NSPS used to the question of what constitutes an "increase" (increase to a source's potential to emit, except that the NSR rule used annual potential to emit while the NSPS program used short-term potential to emit). 43 FR 26388 (June 19, 1978). Even after the D.C. Circuit struck down other portions of our 1978 NSR rules in its original per curiam decision in Alabama Power Co. v. Costle, 606 F.2d 1068 (D.C. Cir. 1979), we continued to propose to retain the RMRR provision and the "poten tial to emit" approach to emissions increases in our re vised rules, although to drop the "hours of operation and rate of production" provisions because the "potential to emit" provision made them unnecessary. 44 FR 51924, 51937 (September 5, 1979). In our final 1980 NSR rules, however, issued after the D.C. Circuit's final Alabama Power decision, 635 F.2d 323 (1980), we changed our approach to the definition of "increase" in the NSR con text to specify that a change would trigger NSR if it would result in an increase over "actual annual emis sions." 45 FR 52676 (August 7, 1980). At the same time, and notably, we restored the provisions stating that in creases in hours of operation or production rate were not "changes." Id. at 52704.

It is important to understand what we did-and did not-decide in those final 1980 NSR rules. What we did decide was that as a general proposition, we would better serve the purposes of the NSR program if we used "actual" rather than "potential" emissions as a baseline for determining whether an activity at a new source results in an emissions increase. What we did not decide was that the purposes of the NSR program never allow us to exclude from the definition of "change" any activity at a plant that may increase its actual emissions but does not increase its "potential" emissions. In par ticular, for example, we decided to retain the "hours of operation" and "rate of production" exclusions even though such changes might result in increases in "ac tual" emissions because not having the provisions "would severely and unduly hamper the ability of any company to take advantage of favorable market condi tions." Id. Similarly, we retained the exclusion for "rou tine maintenance, repair and replacement" even though it too can result in emission increases. Yet there is little doubt that increases in hours of operation and rates of production and RMRR arguably could be understood to fall within the statutory definition of modification, since increases in hours of operation and rates of production certainly may be argued to be changes in the "method of operation" of a plant, and RMRR certainly may be ar gued to be a "physical change" to a plant. On balance, however, we rejected that interpretation and deter mined that the definition of modification should not be read so broadly as to encompass hours of operation or production rate increases, at least so long as they are unrelated to a physical change.

In the revisions to the NSR program we announced last December, we reiterated our adherence to the view that as a general matter we should continue to use "ac tual" rather than "potential" emissions in determining what activities constitute "modifications" under NSR. We continue to believe that is correct, but we also be lieve we should amplify our reasons for holding this view and why that view is entirely consistent with the rule we are promulgating today. In determining the scope to give to "modification," we believe it is important to give weight to both aspects of what Congress decided in 1977. Congress decided that generally speaking, existing plants would not be subject to NSR, but that they would be subject to NSR when they made "modifications." It is also important to understand why Congress chose this point at which to impose NSR on existing plants: to avoid the need to impose costly retrofits, but require placement of new control technology at a time when it makes the most sense for it to be installed. See H.R. Rep. No. 294, 95th Cong., 1st Sess. 185, reprinted in 1977 U.S. Code Cong. & Admin. News at 1254; 116 Cong. Rec. 32,918 (Sept. 21, 1970) (remarks of Sen. Cooper). See also WEPCO, 893 F.2d at 909-910; National- Southwire Aluminum Co. v. EPA, 838 F.2d 835, 843 (6th Cir., Boggs, J., dissenting), cert. denied, 488 U.S. 955 (1988). A wholesale exclusion of any activity that restores a plant to its potential to emit from the defini tion of modification is not consistent with this balance, since there are many activities that might have that ef fect but the conduct of which would be an extremely ef fective time for the placement for new control technol ogy.

At the same time, we believe it is also important to give equal weight to the converse proposition that exist ing plants should not have to install new control technol ogy in the ordinary course of their operations. To re quire them to do so would fail to give full effect to Con gress's decision that existing sources generally would not be required to obtain permits. It would also subject these plants and the consumers who rely on them to enormous dislocation and expense. That is why we be lieve we have rightly excluded increases in hours of op eration and rates of production from the definition of "change." That is also why we believe we have rightly excluded "routine maintenance, repair and replacement" of existing plants from that definition.

For similar reasons, we believe today's rule draws an appropriate line of demarcation between replace ments that should not be treated as changes, and those as to which further consideration of the question is ap propriate. Our rule states categorically that the re placement of components with identical or functionally equivalent components that do not exceed 20% of the replacement value of the process unit and does not change its basic design parameters is not a change and is within the RMRR exclusion. On the other hand, the rule contemplates case-by-case evaluation of identical or functionally equivalent equipment replacements that do not have these characteristics.

We believe this approach is consistent with the in tended scope of "modification" under the NSR program. The record of this rulemaking demonstrates that there are substantial categories of replacement activities un dertaken in order to assure the safety, reliability and efficiency of existing plants that, if conducted at the same time, cost less than the 20- percent replacement cost threshold. It also demonstrates that there are sound business reasons why an owner or operator may find it makes sense to conduct some of these activities at the same time.

On the other hand, given the costs and technical problems associated with installing state-of-the-art pol lution controls at existing facilities, we do not believe it plausible that, if faced with the choice of replacing equipment that has a value less than 20 percent of a pro cess unit and having to install those controls, or coming up with another solution-such as repairing the existing equipment or limiting hours of operation so as to be con fident that the activity will not trigger NSR-the owner of a source would elect to replace the equipment if he also has to install the state-of-the-art controls. Rather, we believe he will repair the existing equipment or arti ficially constrain production. Therefore the replacement of that equipment is not, in fact, an opportune time for the installation of such controls. It follows that treating such replacements as an NSR trigger will not lead to the installation of controls. Rather, it will merely create incentives to make a plant less productive than its de sign capacity would allow it to be.

We do not believe it is the policy of the CAA to seek to promote emissions reductions by forcing new limits on hours of operation or rates of production of existing plants. We made that point clear in 1980 when we deter mined that we should retain the hours of operation and rate of production exclusions in the NSR context. To the contrary, as we said in promulgating the 1980 rules, Con gress's decision to exclude existing sources because of the dislocation that covering them would cause can rea sonably be understood as allowing those sources to in crease hours of operation or production up to permitted levels as market conditions dictate. We note that this does not leave such activities outside the scope of the CAA: if a State concludes that resulting air quality con siderations warrant revision to its SIP to add further limitations to a permit, it may exercise its authority to impose them, even in the absence of anything that con stitutes a "change" to an existing plant. But we believe that our 1980 conclusion that increases in hours of oper ation or production at existing plants should not trigger NSR remains the better construction of the CAA. That being the case, we now believe that the fact that such increases may occur after replacement of equipment that does not present an opportune time for the installa tion of controls should change that conclusion.

To summarize: with respect to existing sources, the purpose of the NSR provisions is simply to require the installation of controls at the appropriate and opportune time. The kind of replacements that automatically fall within the equipment replacement provision established today do not represent such an appropriate and oppor tune time. Accordingly, and given that it is consistent with the meaning of "change" to treat this kind of re placement as not being a "change," we believe excluding them on that basis from the definition of "modification" as used in the NSR program is well calculated to serve all of the policies of the NSR provisions of the CAA, and is therefore a legitimate exercise of our discretion under Chevron, U.S.A. Inc. v. NRDC, 467 U.S. 837 (1984), to construe an ambiguous term. Likewise, we believe this approach is consistent with the holding in the WEPCO case, and with some though not all of that case's reason ing.

Today's rule treats the activities excluded from the definition of "change" as a category of "routine mainte nance, repair and replacement". We received many comments as to whether we can and should adopt the ERP as an expansion of the RMRR exclusion. We be lieve it is appropriate to expand the former RMRR ex ception. Before promulgation of today's rule, we inter preted the phrase "routine maintenance, repair and re placement" to be limited to the day-to-day maintenance and repair of equipment and the replacement of rela tively small parts of a plant that frequently require re placement. Today we are expanding the former defini tion of RMRR through this rulemaking to include other activities covered by the 20 percent cost threshold that are needed to facilitate the efficiency, reliability and safety of affected sources.

We believe it is appropriate to add one final note regarding the fact that this approach represents a change from the approach we have taken in the recent past. As the Supreme Court explained in Chevron, where it upheld a considerably more significant shift in the Agency's understanding of Title I of the CAA, to wit, the scope of the term "stationary source," there is noth ing inherently suspect about a change of approach of this type by an expert Agency seeking to interpret a technical statutory term so as best to accommodate com peting interests that Congress has charged the Agency with reconciling.

In section 101 of the CAA, Congress stated that Title I of the CAA has a dual purpose: "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" (emphasis added). This duality is reiterated in the statement of purpose of the PSD provisions and in the House Report accompanying the 1977 Amendments in connection with the non-attain ment provisions. See sec. 160(1) (purposes of the PSD program are, inter alia, "to protect public health and welfare from any actual or potential adverse effect" of air pollution and "to insure that economic growth will continue to occur consistent with the preservation of existing clean air resources"); H.R. Rep. No. 95-294, p. 211 (The "two main purposes" of the non-attainment permitting program are "(1) to allow reasonable eco nomic growth to continue in an area while making rea sonable further progress to assure attainment of the standards by a fixed date; and (2) to allow States greater flexibility for the former purpose than EPA's present interpretative regulations afford").

More specifically, with regard to the question at issue here, Congress directed EPA not to apply NSR preconstruction permitting requirements to existing plants as a general matter, but to apply them to "modifi cations." Both directives are entitled to receive appro priate weight.

In these circumstances, changes in an Agency's understanding informed by greater experience are not only not surprising, they are to be expected. Effectuat ing these underlying Congressional commands requires a careful weighing and accommodation of the competing considerations underlying them. Sensitivity to unin tended consequences, and a willingness to adjust policies in a manner informed by a better understanding of those consequences, are a central element of the responsibili ties of an Agency given such a charge. As the Chevron Court explained:

Our review of the EPA's varying interpretations of the word "source"-both before and after the 1977 Amendments-convinces us that the agency primarily responsible for administering this important legislation has consistently interpreted it flexibly-not in a sterile textual vacuum, but in the context of implementing pol icy decisions in a technical and complex arena. The fact that the agency has from time to time changed its inter pretation of the term "source" does not, as respondents argue, lead us to conclude that no deference should be accorded the agency's interpretation of the statute. An initial agency interpretation is not instantly carved in stone. On the contrary, the agency, to engage in in formed rulemaking, must consider varying interpreta tions and the wisdom of its policy on a continuing basis. Moreover, the fact that the agency has adopted different definitions in different contexts adds force to the argu ment that the definition itself is flexible, particularly since Congress has never indicated any disapproval of a flexible reading of the statute. 467 U.S. at 863-64.

The Court went on to point out:

In these cases the Administrator's interpretation represents a reasonable accommodation of mani festly competing interests and is entitled to defer ence: the regulatory scheme is technical and com plex, the agency considered the matter in a de tailed and reasoned fashion, and the decision in volves reconciling conflicting policies. Congress intended to accommodate both interests, but did not do so itself on the level of specificity presented by these cases. * * *

[A]n agency to which Congress has delegated policymaking responsibilities may, within the limits of that delegation, properly rely upon the incum bent administration's views of wise policy to inform its judgments. While agencies are not directly ac countable to the people, the Chief Executive is, and it is entirely appropriate for this political branch of the Government to make such policy choices -resolving the competing interests which Con gress itself either inadvertently did not resolve, or intentionally left to be resolved by the agency charged with the administration of the statute in light of everyday realities. * * *

We hold that the EPA's definition of the term "source" is a permissible construction of the stat ute which seeks to accommodate progress in reduc ing air pollution with economic growth. 'The Regu lations which the Administrator has adopted pro vide what the agency could allowably view as * * * [an] effective reconciliation of these twofold ends. * * * '

Id. at 865-66 (citations and footnotes omitted). We be lieve the same reasoning applies here, and makes it en tirely appropriate for us to adopt the equipment replace ment provision today.

2. Why Today's Rule Appropriately Implements the Clean Air Act's Definition of Modification

As noted above, the modification provisions of the NSR program in parts C and D of title I of the CAA are based on the definition of modification in section 111(a)(4) of the CAA. The term "modification" means "any physical change in, or change in the method of op eration 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." As we observed in the notice of pro posed rulemaking for this rule, that definition contem plates that you will first determine whether a physical or operational change will occur. If so, then you proceed to determine whether the physical or operational change will result in an emissions increase over baseline levels.

Real-world, common-sense usage of the word "change" in "physical change" and "change in the method of operation" shows that "change" is susceptible to multiple meanings. As we have noted previously, "EPA has always recognized that Congress did not in tend that every activity at an existing facility be consid ered a physical or operational change for purposes of NSR." 57 FR 32,314, 32,319 (July 21, 1992). Conceiv ably, "change" could encompass a range of activities from periodically replacing filters in production machin ery, to once in-a-lifetime anticipated replacement of a component, to complete replacement of a production unit.

For example, all cars must periodically have their oil "changed." When considered from one perspective, this activity does represent a "change" because old oil is removed and new oil is added. From another perspec tive, however, this activity would not be considered a change because it does not alter any significant charac teristic of the car.

More to the point, chemical and pharmaceutical manufacturing operations often are designed, operated, and permitted as "multi-function" facilities. These facil ities have numerous pieces of equipment (such as stor age tanks, reactors, distillation columns, centrifuges, filter dryers, etc.) that can be reconfigured to accommo date a wide variety of products and operating conditions. When switching from product X to product Y, a plant can make substantial "changes" in the types of equip ment used, the processing conditions, and the raw mate rials, reagents, solvents, and other processing materials. In this case, the same basic equipment is used to make a wide variety of end products. But, as long as the facil ity is operated as designed and permitted, we would not consider (and have not considered over the 20+ year life of the NSR program) such changes to be physical or operational "changes" for purposes of administering the NSR program.

Similarly, manufacturing equipment often is built with expendable components. For example, industrial gas turbines, such as those used to drive compressors on natural gas pipelines, regularly need to have compo nents replaced as they wear out due to the high temper ature and pressure conditions inside the turbine. In fact, these gas turbines are built with the knowledge and expectation that such replacements will be needed. In recognition of this fact, under the New Source Perfor mance Standard for gas turbines, 40 CFR part 60, subpart GG, we have concluded that "replacement of stator blades, turbine nozzles, turbine buckets, fuel noz zles, combustion chambers, seals, and shaft packings' are not "changes" for regulatory purposes. See EPA- 450/2-77-017a, background support document for Subpart GG. Such replacements are akin to getting a new set of brakes on a car-not something that happens often, not an activity that is necessarily inexpensive, but plainly an activity that is an expected part of maintain ing and operating the facility and one that does not rep resent an alteration of the affected process unit.

As the preceding examples suggest, identifying activities that are "changes" for NSR purposes-and thus potentially trigger the need for an NSR per mit-requires the exercise of Agency expertise. The application of agency expertise to the interpretation of this statutory term is the classic situation in which an agency is accorded deference under Chevron, U.S.A., Inc. v. NRDC, 467 U.S. 837 (1984).

Historically, we have asserted the power to inter pret the relevant statutory terms. For example, even though both the NSPS and NSR programs incorporate the definition of "modification" from section 111, from the outset EPA has adopted quite disparate readings of the term in our rules. See 57 FR 32314, 32316 (July 21, 1992) (WEPCO rule discussion of how emission in creases are calculated differently for the NSPS and NSR programs). The NSPS program requires a change to result in an increase in the hourly potential to emit of the facility. 40 CFR 60.14(a)-(b). In contrast, under NSR, we require an increase in annual emissions. E.g., 40 CFR 51.165(a)(1)(x). These disparate tests reflect the Agency's view that the statutory term "modification" must be construed with a view to what makes sense in particular statutory context, and are not obvious on their face.

The exclusions from NSR we adopted in 1980 also reflect the exercise of the Chevron discretion. Not only did we adopt the RMRR exclusion at that time, but we also adopted exclusions for increases in the hours of op eration, fuel changes, and raw material changes. Only the RMRR exclusion arguably could be justified as de minimis. For example, by doubling hours of operation, a 500 tpy emitting plant could conceivably double its emissions.17 The extra 500 tpy is far above any level EPA has ever thought justifiable as de minimis. E.g., 40 CFR 51.166(b)(23)(i) (definition of "significant"). Nor is it likely that these other exclusions could be based on some inherent power to adopt categorical exclusions from the CAA's commands. See Alabama Power Com pany v. Costle, 636 F.2d 323, 359 (D.C. Cir. 1980) ("cate gorical exemptions * * * are not favored"). Accord ingly, these other exclusions must be justified as an ex ercise of Chevron discretion.

As noted previously, in 1977 when Congress incor porated by reference into the NSR program the pre- existing NSPS statutory definition of modification, EPA had already adopted and had been administering regula tions and policy under the NSPS program related to the meaning of the term "modification." Our rules and policy provided that certain significant activities did not consti tute physical or operational changes under the NSPS program prior to 1977 (or, for that matter, under the NSPS program as administered today). In addition to the gas turbine example provided above, perhaps the best indication that EPA did not consider the terms "modification" or "change" to cover everything other than de minimis activities is the exclusion for produc tion rate increases under the NSPS program. 40 CFR 60.14(e)(2).

Under this provision, projects valued at millions of dollars can be implemented-with no limitations on the nature of the project-without triggering applicable NSPSs. For example, up to 10 percent of the asset value of affected operations at a kraft pulp mill can be in vested in a project without triggering the applicable NSPS, 40 CFR part 60, subpart BB. The affected facili ties at a kraft pulp mill typically are valued in excess of $100 million. Therefore, an owner or operator can im plement projects costing millions of dollars without trig gering the applicable NSPS. This holds true regardless of the nature of the project-it can be a "like-kind" re placement of the kind addressed by today's rule or it can result in a substantial change in the nature of the opera tion. Thus, under the NSPS program that existed when Congress enacted NSR and incorporated into NSR the applicable NSPS definitions, projects of substantial cost that result in substantial change in affected facilities were not considered "changes." The same is true under the NSPS program as it stands today.

We recognize that the Agency previously has not specifically asserted that our interpretation of "change" and the exclusions from NSR are based on an exercise of Chevron discretion. In some instances, such as in a decision of the EAB, In re Tennessee Valley Authority, 9 E.A.D. 357 (EAB 2000), and in briefs in various enforcement-related cases, we have previously inter preted "change" such that virtually all changes, even trivial ones, are encompassed by the CAA. Thus, we generally interpreted the exclusion as being limited to de minimis circumstances. However, EPA does have the authority to interpret these key terms through rulemaking. Upon further consideration of the history of our actions, the statute, and its legislative history, EPA believes that a different view is permissible, and, for policy reasons discussed above, more appropriate. Therefore, we adopt this view prospectively in today's action.18

The argument that our authority to exclude certain activities from being modifications under new source review can only be based on a de minimis rationale sometimes relies on the word "any" used to modify "physical change" and "change in the method of opera tion," pointing to the word "any" in the definition of "modification" as a signal from Congress that the term "change" must be interpreted as encompassing the broadest possible sense of the term. Such an interpreta tion is not compelled by the language and legislative history of the statute, as demonstrated by the manner in which we have interpreted the word "change" under both the NSPS and the NSR programs.19

Nothing in the appellate case law directly disposes of this issue in a manner that prevents a new interpreta tion today. Two cases, Alabama Power and WEPCO, are relied on by some commenters to assert that EPA must interpret "modification" and "change" expansively and base all exclusions on a de minimis rationale. How ever, in Alabama Power, the issue before the court was the emissions increase portion of the definition of "modi fication." The court would have allowed de minimis in creases in emissions to be excluded from requirements applying to "modifications" under new source review but not emissions increases equal to the thresholds set by statute for new construction. 636 F.2d at 399-400. The court did not have before it the issue of what is a "change" and did not decide this issue.

In WEPCO, both parties advanced the view that the statute was clear on its face. EPA advanced the view that the term "modification" is necessarily broad, and that only de minimis departures are appropriate. WEPCO asserted that the plain meaning of the term "physical change" allowed for the five large scale reha bilitation projects it contemplated at its Port Washing ton plant. The WEPCO court held that the rehabilitation projects at issue were too large to reasonably conclude that they should not be treated as physical changes. The court's holding that the statute did not require the inter pretation advanced by WEPCO does not deny EPA the discretion to decide to adopt a different, reasonable in terpretation of the term "modification."

While the Court in WEPCO decided that the pro jects in that case were physical changes, the decision in WEPCO does not answer the question of where to draw the line between activities that should and should not be considered "changes." Nevertheless, contrary to the suggestions of several commenters, the projects at issue in WEPCO would have cost more than the 20 percent of replacement cost threshold selected today and, barring other applicable exclusions, would have been subject to case-by-case review in the PSD program. See section III.D above.20

Some commenters argued that, to further the pur poses of the statute, any interpretation must result in the eventual elimination of so-called "grandfathered" facilities. We recognize the need to reduce emissions from many existing plants-regardless of whether they are "grandfathered" (because they have never gone through NSR) or whether they have previously gone through NSR but can further reduce their emissions. EPA and States have issued regulations under a variety of statutory provisions to accomplish this goal in the past, and we will continue to do so in the future. We do not believe, however, the modification provisions of the CAA should be interpreted to ensure that all major facil ities eventually trigger NSR. In fact, such an interpre tation cannot be squared with the plain language of the CAA.

An existing source-whether grandfathered or not-triggers NSR only if it makes a physical or opera tional change that results in an emissions increase. Thus, a facility can conceivably continue to operate in definitely without triggering NSR-making as many physical or operational changes as it desires-as long as the changes do not result in emissions increases. This outcome is an unavoidable consequence of the plain stat utory language and is at odds with the notion that Con gress intended that every major source would eventually trigger NSR. Moreover, there is nothing in the legisla tive history of the 1977 Amendments, which created the NSR program, to suggest that Congress intended to force all then-existing sources to go through NSR. To the extent that some members of Congress expressed that view during the debate over the 1990 amendments, such statements are not probative of what Congress meant in 1977. Central Bank of Denver, N.A. v. First Interstate Bank of Denver, N.A., 511 U.S. 164, 185-86 (1994), and cases cited.

In deciding to incorporate by reference the statu tory definition of "modification" in section 111, Con gress's intent cannot have been to preclude us from adopting an interpretation of "modification" or "change" that differs from one that sweeps in all activities at a source. Under the NSPS program, this interpretation did not apply at the time of the 1977 amendments. When the NSPS definition of "modification" was adopted as part of the NSR program in 1977, the Congressional Record explained that this provision, "[i]mplements con ference agreement to cover "modification" as well as "construction" by defining "construction" in part C to conform to usage in other parts of the Act." 123 Cong. Rec. 36331 (Nov. 1, 1977) (emphasis added). Although we do not assert that the NSPS interpretation is the only one we could have adopted for NSR purposes (we followed quite a different interpretation from 1980 until today) at the very least it delineates a zone of discretion within which EPA may operate.

Our interpretation today of physical or operational change in a flexible way furthers the purposes of the statute. As noted above, Congress made it clear that the CAA in general, and the NSR program in particular, should be administered in a manner that protects the environment and promotes the productive capacity of the nation. CAA section 101(b)(1). The Chevron Court recognized Congress' intent and noted that "Congress sought to accommodate the conflict between the eco nomic interest in permitting capital improvements to continue and the environmental interest in improving air quality" when it established the NSR program. Chev ron, 467 U.S. at 851. Generally, we believe that these goals are best accomplished by providing state and local governments with discretion to make decisions as to what emissions reductions are needed in their jurisdic tions to attain and maintain good air quality. See CAA section 101(a)(3).

It is now clear that many power plants and indus trial facilities must substantially reduce their emissions in order to allow States to meet the stringent Federal air quality standards that the Supreme Court upheld in 2002. Under the CAA, Congress designed a number of regulatory programs that will collectively achieve the necessary reductions. Although the NSR program will effectively limit emissions from new and modified sources, it was not designed to achieve emission reduc tions from every existing source.

IV. Administrative Requirements for This Rule A. Executive Order 12866-Regulatory Plan ning and Review

Under Executive Order 12866 [58 FR 51735 (Octo ber 4, 1993)], we must determine whether the regulatory action is "significant" and therefore subject to review by the Office of Management and Budget (OMB) and the requirements of the Executive Order. The Executive Order defines "significant regulatory action" as one that is likely to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competi tion, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;

(2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

(3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs, or the rights and obligations of recipients thereof; or

(4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the prin ciples set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, OMB has notified us that it considers this an "economi cally significant regulatory action" within the meaning of the Executive Order. We have submitted this action to OMB for review. Changes made in response to OMB suggestions or recommendations will be documented in the public record. All written comments from OMB to EPA and any written EPA response to any of those com ments are included in the docket listed at the beginning of this notice under ADDRESSES. In addition, consis tent with Executive Order 12866, we consulted with the State, local and tribal agencies that will be affected by this rule. We have also sought involvement from indus try and public interest groups.

B. Executive Order 13132-Federalism

Executive Order 13132, entitled "Federalism" (64 FR 43255, August 10, 1999), requires us to develop an accountable process to ensure "meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications." "Policies that have federalism implications" are defined in the Executive Order to include regulations that have "substantial direct effects on the States, on the relation ship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government."

This final rule does not have federalism implica tions. Nevertheless, as described in section II.C of this notice, in developing this rule, we consulted with af fected parties and interested stakeholders, including State and local authorities, to enable them to provide timely input in the development of this rule. This rule will not have substantial direct effects on the States, on the relationship between the national government and the State and local programs, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. We expect this rule will result in some expenditures by the States, we expect those expenditures to be limited to $580,000 for the estimated 112 affected reviewing au thorities. This estimate reflects the small increase in burden imposed upon reviewing authorities in order for them to revise their State Implementation Plans (SIP). However, this revision provides sources permitted by the States greater certainty in application of the pro gram, which should in turn reduce the overall burden of the program on State and local authorities. Thus, the requirements of Executive Order 13132 do not apply to this rule.

C. Executive Order 13175-Consultation and Coordination With Indian Tribal Govern ments

Executive Order 13175, entitled "Consultation and Coordination with Indian Tribal Governments" (65 FR 67249, November 6, 2000), requires EPA to develop an accountable process to ensure "meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications." We believe that this rule does not have tribal implications as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply.

The purpose of today's final rule is to add greater flexibility to the existing major NSR regulations. These changes will benefit reviewing authorities and the regu lated community, including any major source owned by a tribal government or located in or near tribal land, by providing increased certainty as to when the require ments of the major NSR program apply. Taken as a whole, today's rule should result in no added burden or compliance costs and should not substantially change the level of environmental performance achieved under the previous rules and guidance.

We anticipate that initially these changes will re sult in a small increase in the burden imposed upon re viewing authorities in order for them to be included in the State's SIP. Nevertheless, these options and revi sions will ultimately provide greater operational flexibil ity to sources permitted by the States, which will in turn reduce the overall burden on the program on State and local authorities by reducing the number of required permit modifications. In comparison, no tribal govern ment currently has an approved Tribal Implementation Plan (TIP) under the CAA to implement the NSR pro gram. The Federal government is currently the NSR reviewing authority in Indian country. Thus, tribal gov ernments should not experience added burden, nor should their laws be affected with respect to implemen tation of this rule. Additionally, although major station ary sources affected by today's rule could be located in or near Indian country and/or be owned or operated by tribal governments, such affected sources would not incur additional costs or compliance burdens as a result of this rule. Instead, the only effect on such sources should be the benefit of the added certainty and flexibil ity provided by the rule.

We recognize the importance of including tribal outreach as part of the rulemaking process. In addition to affording tribes an opportunity to comment on this rule through the proposal, on which two tribes did sub mit comments, we have also alerted tribes of this action through our website and quarterly newsletter. To this point we have not specifically consulted with tribal offi cials on this rule, but we are committed to work with any tribal government to resolve any issues that we may have overlooked in today's rules and that may have an adverse impact in Indian country.

D. Executive Order 13045-Protection of Chil dren From Environmental Health Risks and Safety Risks

Executive Order 13045, "Protection of Children from Environmental Health Risks and Safety Risks" (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be "economically significant" as defined under Executive Order 12866, and (2) concerns an envi ronmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, we must evaluate the environmental health or safety effects of the planned rule on children and explain why the planned regulation is preferable to other potentially effective and reasonable alternatives that we considered.

This rule is not subject to Executive Order 13045, because we do not have reason to believe the environ mental health or safety risks addressed by this action present a disproportionate risk to children. We believe that, based on our analysis of electric utilities, this rule as a whole will result in equal or better environmental protection than currently provided by the existing regu lations, and do so in a more streamlined and effective manner.

E. Paperwork Reduction Act

The information collection requirements in this final rule have been submitted for approval to OMB un der the requirements of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An ICR document has been pre pared by EPA (ICR No. 1230.14), and a copy may be obtained from Susan Auby, U.S. Environmental Protec tion Agency, Office of Environmental Information, Col lection Strategies Division (2822T), 1200 Pennsylvania Avenue, NW., Washington, DC 20460-0001, by e-mail at auby.susan@epa.gov, or by calling (202) 566-1672. A copy may also be downloaded off the Internet at http://www.epa.gov/icr. The information requirements included in ICR No. 1230.14 are not enforceable until OMB approves them.

The information that ICR No. 1230.14 covers is required for the submittal of a complete permit applica tion for the construction or modification of all major new stationary sources of pollutants in attainment and non attainment areas, as well as for applicable minor station ary sources of pollutants. This information collection is necessary for the proper performance of EPA's func tions, has practical utility, and is not unnecessarily du plicative of information we otherwise can reasonably access. We have reduced, to the extent practicable and appropriate, the burden on persons providing the infor mation to or for EPA. In fact, we feel that this rule will result in less burden on industry and reviewing authori ties since it streamlines the process of determining whether a replacement activity is RMRR.

However, according to ICR No. 1230.14, we do an ticipate an initial increase in burden for reviewing au thorities as a result of the rule changes, to account for revising state implementation plans to incorporate these rule changes. As discussed above, we expect those one- time expenditures to be limited to $580,000 for the esti mated 112 affected reviewing authorities. For the num ber of respondent reviewing authorities, the analysis uses the 112 reviewing authorities count used by other permitting ICR's for the one-time tasks (for example, SIP revisions).

Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to re view instructions; develop, acquire, install, and utilize technology and systems for the purpose of responding to the information collection; adjust existing ways to com ply with any previously applicable instructions and re quirements; train personnel to respond to a collection of information; search existing data sources; complete and review the collection of information; and transmit or otherwise disclose the information.

An agency may not conduct or sponsor, and a per son is not required to respond to, a collection of informa tion unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regula tions are listed in 40 CFR part 9 and 48 CFR chapter 15. We will continue to present OMB control numbers in a consolidated table format to be codified in 40 CFR part 9 of the Agency's regulations, and in each CFR volume containing EPA regulations. The table lists the section numbers with reporting and recordkeeping require ments, and the current OMB control numbers. This list ing of the OMB control numbers and their subsequent codification in the CFR satisfy the requirements of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.) and OMB's implementing regulations at 5 CFR part 1320.

F. Regulatory Flexibility Analysis

We determined it is not necessary to prepare a reg ulatory flexibility analysis in connection with this final rule. We have also determined that this rule will not have a significant economic impact on a substantial num ber of small entities. For purposes of assessing the im pacts of today's rule on small entities, small entity is defined as: (1) Any small business employing fewer than 500 employees; (2) a small governmental jurisdiction that is a government of a city, county, town, school dis trict or special district with a population of less than 50,000; and (3) a small organization that is any not-for- profit enterprise which is independently owned and op erated and is not dominant in its field.

After considering the economic impacts of today's rule on small entities, EPA has concluded that this ac tion will not have a significant economic impact on a sub stantial number of small entities. In determining whether a rule has a significant economic impact on a substantial number of small entities, the impact of con cern is any significant adverse economic impact on small entities, since the primary purpose of the regulatory flexibility analyses is to identify and address regulatory alternatives "which minimize any significant economic impact of this rule on small entities." 5 U.S.C. Sections 603 and 604. Thus, an agency may conclude that a rule will not have a significant economic impact on a substan tial number of small entities if the rule relieves regula tory burden, or otherwise has a positive economic effect on all of the small entities subject to the rule. Today's rule will not have a significant economic impact on a sub stantial number of small entities because it will decrease the regulatory burden of the existing regulations and have a positive effect on all small entities subject to the rule. This rule improves operational flexibility for own ers or operators of major stationary sources and clari fies applicable requirements for determining if a change qualifies as a major modification. We have therefore concluded that today's rule will relieve regulatory bur den for all small entities.

G. Unfunded Mandates Reform Act of 1995

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes require ments for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal govern ments and the private sector. Under section 202 of UMRA, we generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with "Federal mandates" that may result in expen ditures to State, local, and tribal governments, in the aggregate, or to the private sector of $100 million or more in any one year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires us to identify and con sider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. More over, section 205 allows us to adopt an alternative other than the least costly, most cost-effective, or least bur densome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted.

Before we establish any regulatory requirements that may significantly or uniquely affect small govern ments, including tribal governments, we must have de veloped under section 203 of the UMRA a small govern ment agency plan. The plan must provide for notifying potentially affected small governments, enabling offi cials of affected small governments to have meaningful and timely input in the development of our regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory require ments.

We believe these rule changes will actually reduce the regulatory burden associated with the major NSR program by improving the operational flexibility of own ers or operators and clarifying the requirements. Be cause the program changes provided in the rule are not expected to result in a significant increase in the expen diture by State, local, and tribal governments, or the private sector, we have not prepared a budgetary impact statement or specifically addressed the selection of the least costly, most cost-effective, or least burdensome alternative. Because small governments will not be sig nificantly or uniquely affected by this rule, we are not required to develop a plan with regard to small govern ments. Therefore, this rule is not subject to the require ments of section 203 of the UMRA.

H. National Technology Transfer and Advance ment Act of 1995

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104-113, section 12(d) (15 U.S.C. 272 note) directs us to use voluntary consensus standards (VCS) in our reg ulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (for example, materials specifica tions, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs us to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable VCS.

Although this rule does involve the use of technical standards, it does not preclude the State, local, and tribal reviewing agencies from using VCS. Today's rule is an improvement of the existing NSR permitting pro gram. As such, it only ensures that promulgated techni cal standards are considered and appropriate controls are installed, prior to the construction of major sources of air emissions. Therefore, we are not considering the use of any VCS in today's rule.

I. Executive Order 13211-Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use

This rule is not a "significant energy action" as de fined in Executive Order 13211, "Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use" (66 FR 28355 (May 22, 2001)) be cause it is not likely to have a significant adverse effect on the supply, distribution or use of energy.

Today's rule improves the ability of sources to maintain the reliability of production facilities, and ef fectively utilize and improve existing capacity.

J. Executive Order 12988-Civil Justice Reform

This final rule does not have any preemptive or retroactive effect. This action meets applicable stan dards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, elimi nate ambiguity, and reduce burden.

V. Effective Date for Today's Requirements

All of these changes will take effect in the Federal PSD program (codified at § 52.21) on December 26, 2003. This means that these rules will apply on Decem ber 26, 2003, in any area without an approved PSD pro gram, for which we are the reviewing authority, or for which we have delegated our authority to issue permits to a State or local reviewing authority.

To be approvable under the SIP, State and local agency programs implementing part C (PSD permit program in § 51.166) or part D (nonattainment NSR permit program in § 51.165) must include today's changes as minimum program elements. State and local agencies should assure that any program changes under § § 51.165 and 51.166 are consistently accounted for in other SIP planning measures. State and local agencies must adopt and submit revisions to their part 51 permit ting programs implementing these minimum program elements no later than October 27, 2006. That is, for both nonattainment and attainment areas, the SIP revi sions must be adopted and submitted within 3 years from today. The CAA does not specify a date for sub mission of SIPs when we revise the PSD and NSR rules. We believe it is appropriate to establish a date analo gous to the date for submission of new SIPs when a NAAQS is promulgated or revised. Under section 110(a)(1) of the CAA, as amended in 1990, that date is 3 years from promulgation or revision of the NAAQS. Ac cordingly, we have established 3 years from today's revi sions as the required date for submission of conforming SIP revisions.

Today's rule revises the Federal PSD program lo cated at 40 CFR 52.21 to include the new equipment replacement provision of the RMRR exclusion. The part 52 regulations governing Federal permitting programs include the Federal PSD rule at 40 CFR 52.21 as well as the various sections of subparts C through DDD of part 52 that incorporate the Federal permitting program by reference for those jurisdictions where EPA applies part 52.21 as a Federal Implementation Plan because such jurisdictions lack an approved SIP to implement the PSD program. Because today's final rule adds addi tional paragraphs to the part 52.21 rules, we will be re vising the references in subparts C through DDD to ap propriately reflect the program that applies. This final action will be taken in a separate Federal Register notice and will not change the effective date of today's final changes.

VI. Statutory Authority

The statutory authority for this action is provided by sections 101, 111, 114, 116, and 301 of the CAA as amended (42 U.S.C. 7401, 7411, 7414, 7416, and 7601). This rulemaking is also subject to section 307(d) of the CAA (42 U.S.C. 7407(d)).

List of Subjects in 40 CFR Parts 51 and 52

Environmental protection, Administrative prac tices and procedures, Air pollution control, Intergovern mental relations.

Dated: August 27, 2003.

Marianne Lamont Horinko,

Acting Administrator.

o For the reasons set out in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows:

PART 51-[AMENDED]

o 1. The authority citation for part 51 continues to read as follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7401-7671q.

Subpart I-[Amended]

o 2. Section 51.165 is amended:

o a. By revising paragraph (a)(1)(v)(C)(1).

o b. By adding paragraphs (a)(1)(xliii) through (xlvi) and paragraph (h).

The revision and additions read as follows:

§ 51.165 Permit requirements.

(a) * * *

(1) * * *

(v) * * *

(C) * * *

(1) Routine maintenance, repair and replacement. Routine maintenance, repair and replacement shall in clude, but not be limited to, any activity(s) that meets the requirements of the equipment replacement provi sions contained in paragraph (h) of this section; * * *.

* * * * *

(xliii)(A) In general, process unit means any collec tion of structures and/or equipment that processes, as sembles, applies, blends, or otherwise uses material in puts to produce or store an intermediate or a completed product. A single stationary source may contain more than one process unit, and a process unit may contain more than one emissions unit.

(B) Pollution control equipment is not part of the process unit, unless it serves a dual function as both pro cess and control equipment. Administrative and ware housing facilities are not part of the process unit.

(C) For replacement cost purposes, components shared between two or more process units are propor tionately allocated based on capacity.

(D) The following list identifies the process units at specific categories of stationary sources.

(1) For a steam electric generating facility, the process unit consists of those portions of the plant that contribute directly to the production of electricity. For example, at a pulverized coal-fired facility, the process unit would generally be the combination of those sys tems from the coal receiving equipment through the emission stack (excluding post-combustion pollution con trols), including the coal handling equipment, pul verizers or coal crushers, feedwater heaters, ash han dling, boiler, burners, turbine-generator set, condenser, cooling tower, water treatment system, air preheaters, and operating control systems. Each separate generat ing unit is a separate process unit.

(2) For a petroleum refinery, there are several categories of process units: those that separate and/or distill petroleum feedstocks; those that change molecu lar structures; petroleum treating processes; auxiliary facilities, such as steam generators and hydrogen pro duction units; and those that load, unload, blend or store intermediate or completed products.

(3) For an incinerator, the process unit would consist of components from the feed pit or refuse pit to the stack, including conveyors, combustion devices, heat exchangers and steam generators, quench tanks, and fans.

(xliv) Functionally equivalent component means a component that serves the same purpose as the replaced component.

(xlv) Fixed capital cost means the capital needed to provide all the depreciable components. "Depreciable components" refers to all components of fixed capital cost and is calculated by subtracting land and working capital from the total capital investment, as defined in paragraph (a)(1)(xlvi) of this section.

(xlvi) Total capital investment means the sum of the following: All costs required to purchase needed pro cess equipment (purchased equipment costs); the costs of labor and materials for installing that equipment (di rect installation costs); the costs of site preparation and buildings; other costs such as engineering, construction and field expenses, fees to contractors, startup and per formance tests, and contingencies (indirect installation costs); land for the process equipment; and working cap ital for the process equipment.

* * * * *

(h) Equipment replacement provision. Without regard to other considerations, routine maintenance, repair and replacement includes, but is not limited to, the replacement 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 require ments in paragraphs (h)(1) through (3) of this section are met.

(1) Capital Cost threshold for Equipment Re placement. (i) For an electric utility steam generating unit, as defined in § 51.165(a)(1)(xx), the fixed capital cost of the replacement component(s) plus the cost of any associated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the replacement value of the process unit, at the time the equipment is replaced. For a process unit that is not an electric utility steam generating unit the fixed capital cost of the replacement component(s) plus the cost of any associated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the replacement value of the process unit, at the time the equipment is replaced.

(ii) In determining the replacement value of the process unit; and, except as otherwise allowed under paragraph (h)(1)(iii) of this section, the owner or opera tor shall determine the replacement value of the process unit on an estimate of the fixed capital cost of construct ing a new process unit, or on the current appraised value of the process unit.

(iii) As an alternative to paragraph (h)(1)(ii) of this section for determining the replacement value of a pro cess unit, an owner or operator may choose to use insur ance value (where the insurance value covers only com plete replacement), investment value adjusted for infla tion, or another accounting procedure if such procedure is based on Generally Accepted Accounting Principles, provided that the owner or operator sends a notice to the reviewing authority. The first time that an owner or operator submits such a notice for a particular process unit, the notice may be submitted at any time, but any subsequent notice for that process unit may be submit ted only at the beginning of the process unit's fiscal year. Unless the owner or operator submits a notice to the reviewing authority, then paragraph (h)(1)(ii) of this section will be used to establish the replacement value of the process unit. Once the owner or operator submits a notice to use an alternative accounting procedure, the owner or operator must continue to use that procedure for the entire fiscal year for that process unit. In subse quent fiscal years, the owner or operator must continue to use this selected procedure unless and until the owner or operator sends another notice to the reviewing au thority selecting another procedure consistent with this paragraph or paragraph (h)(1)(ii) of this section at the beginning of such fiscal year.

(2) Basic design parameters. The replacement does not change the basic design parameter(s) of the process unit to which the activity pertains.

(i) Except as provided in paragraph (h)(2)(iii) of this section, for a process unit at a steam electric gener ating facility, the owner or operator may select as its basic design parameters either maximum hourly heat input and maximum hourly fuel consumption rate or maximum hourly electric output rate and maximum steam flow rate. When establishing fuel consumption specifications in terms of weight or volume, the mini mum fuel quality based on British Thermal Units con tent shall be used for determining the basic design pa rameter(s) for a coal-fired electric utility steam generat ing unit.

(ii) Except as provided in paragraph (h)(2)(iii) of this section, the basic design parameter(s) for any pro cess unit that is not at a steam electric generating facil ity are maximum rate of fuel or heat input, maximum rate of material input, or maximum rate of product out put. Combustion process units will typically use maxi mum rate of fuel input. For sources having multiple end products and raw materials, the owner or operator should consider the primary product or primary raw material when selecting a basic design parameter.

(iii) If the owner or operator believes the basic design parameter(s) in paragraphs (h)(2)(i) and (ii) of this section is not appropriate for a specific industry or type of process unit, the owner or operator may propose to the reviewing authority an alternative basic design parameter(s) for the source's process unit(s). If the re viewing authority approves of the use of an alternative basic design parameter(s), the reviewing authority shall issue a permit that is legally enforceable that records such basic design parameter(s) and requires the owner or operator to comply with such parameter(s).

(iv) The owner or operator shall use credible infor mation, such as results of historic maximum capability tests, design information from the manufacturer, or en gineering calculations, in establishing the magnitude of the basic design parameter(s) specified in paragraphs (h)(2)(i) and (ii) of this section.

(v) If design information is not available for a pro cess unit, then the owner or operator shall determine the process unit's basic design parameter(s) using the maximum value achieved by the process unit in the five- year period immediately preceding the planned activity.

(vi) Efficiency of a process unit is not a basic de sign parameter.

(3) The replacement activity shall not cause the process unit to exceed any emission limitation, or opera tional limitation that has the effect of constraining emis sions, that applies to the process unit and that is legally enforceable.

o 3. Section 51.166 is amended:

o a. By revising paragraph (b)(2)(iii)(a).

o b. By adding paragraphs (b)(53) through (56) and paragraph (y).

The revision and additions read as follows:

§ 51.166 Prevention of significant deterioration of air quality.

(b) * * *

(2) * * *

(iii) * * *

(a) Routine maintenance, repair and replacement. Routine maintenance, repair and replacement shall in clude, but not be limited to, any activity(s) that meets the requirements of the equipment replacement provi sions contained in paragraph (y) of this section; * * *.

* * * * *

(53)(i) In general, process unit means any collec tion of structures and/or equipment that processes, as sembles, applies, blends, or otherwise uses material in puts to produce or store an intermediate or a completed product. A single stationary source may contain more than one process unit, and a process unit may contain more than one emissions unit.

(ii) Pollution control equipment is not part of the process unit, unless it serves a dual function as both pro cess and control equipment. Administrative and ware housing facilities are not part of the process unit.

(iii) For replacement cost purposes, components shared between two or more process units are propor tionately allocated based on capacity.

(iv) The following list identifies the process units at specific categories of stationary sources.

(a) For a steam electric generating facility, the process unit consists of those portions of the plant that contribute directly to the production of electricity. For example, at a pulverized coal-fired facility, the process unit would generally be the combination of those sys tems from the coal receiving equipment through the emission stack (excluding post-combustion pollution con trols), including the coal handling equipment, pul verizers or coal crushers, feedwater heaters, ash handl ing, boiler, burners, turbine-generator set, condenser, cooling tower, water treatment system, air preheaters, and operating control systems. Each separate generat ing unit is a separate process unit.

(b) For a petroleum refinery, there are several categories of process units: those that separate and/or distill petroleum feedstocks; those that change molecu lar structures; petroleum treating processes; auxiliary facilities, such as steam generators and hydrogen pro duction units; and those that load, unload, blend or store intermediate or completed products.

(c) For an incinerator, the process unit would consist of components from the feed pit or refuse pit to the stack, including conveyors, combustion devices, heat exchangers and steam generators, quench tanks, and fans.

(54) Functionally equivalent component means a component that serves the same purpose as the replaced component.

(55) Fixed capital cost means the capital needed to provide all the depreciable components. "Depreciable components" refers to all components of fixed capital cost and is calculated by subtracting land and working capital from the total capital investment, as defined in paragraph (b)(56) of this section.

(56) Total capital investment means the sum of the following: all costs required to purchase needed process equipment (purchased equipment costs); the costs of labor and materials for installing that equipment (direct installation costs); the costs of site preparation and buildings; other costs such as engineering, construction and field expenses, fees to contractors, startup and per formance tests, and contingencies (indirect installation costs); land for the process equipment; and working cap ital for the process equipment.

* * * * *

(y) Equipment replacement provision. Without regard to other considerations, routine maintenance, repair and replacement includes, but is not limited to, the replacement 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 require ments in paragraphs (y)(1) through (3) of this section are met.

(1) Capital Cost threshold for Equipment Replace ment. (i) For an electric utility steam generating unit, as defined in § 51.166(b)(30), the fixed capital cost of the replacement component(s) plus the cost of any asso ciated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the re placement value of the process unit, at the time the equipment is replaced. For a process unit that is not an electric utility steam generating unit the fixed capital cost of the replacement component(s) plus the cost of any associated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the replacement value of the process unit, at the time the equipment is replaced.

(ii) In determining the replacement value of the process unit; and, except as otherwise allowed under paragraph (y)(1)(iii) of this section, the owner or opera tor shall determine the replacement value of the process unit on an estimate of the fixed capital cost of construct ing a new process unit, or on the current appraised value of the process unit.

(iii) As an alternative to paragraph (y)(1)(ii) of this section for determining the replacement value of a pro cess unit, an owner or operator may choose to use insur ance value (where the insurance value covers only com plete replacement), investment value adjusted for infla tion, or another accounting procedure if such procedure is based on Generally Accepted Accounting Principles, provided that the owner or operator sends a notice to the reviewing authority. The first time that an owner or operator submits such a notice for a particular process unit, the notice may be submitted at any time, but any subsequent notice for that process unit may be submit ted only at the beginning of the process unit's fiscal year. Unless the owner or operator submits a notice to the reviewing authority, then paragraph (y)(1)(ii) of this section will be used to establish the replacement value of the process unit. Once the owner or operator submits a notice to use an alternative accounting procedure, the owner or operator must continue to use that procedure for the entire fiscal year for that process unit. In subse quent fiscal years, the owner or operator must continue to use this selected procedure unless and until the owner or operator sends another notice to the reviewing au thority selecting another procedure consistent with this paragraph or paragraph (y)(1)(ii) of this section at the beginning of such fiscal year.

(2) Basic design parameters. The replacement does not change the basic design parameter(s) of the process unit to which the activity pertains.

(i) Except as provided in paragraph (y)(2)(iii) of this section, for a process unit at a steam electric gen erating facility, the owner or operator may select as its basic design parameters either maximum hourly heat input and maximum hourly fuel consumption rate or maximum hourly electric output rate and maximum steam flow rate. When establishing fuel consumption specifications in terms of weight or volume, the mini mum fuel quality based on British Thermal Units con tent shall be used for determining the basic design pa rameter(s) for a coal-fired electric utility steam generat ing unit.

(ii) Except as provided in paragraph (y)(2)(iii) of this section, the basic design parameter(s) for any pro cess unit that is not at a steam electric generating facil ity are maximum rate of fuel or heat input, maximum rate of material input, or maximum rate of product out put. Combustion process units will typically use maxi mum rate of fuel input. For sources having multiple end products and raw materials, the owner or operator should consider the primary product or primary raw material when selecting a basic design parameter.

(iii) If the owner or operator believes the basic design parameter(s) in paragraphs (y)(2)(i) and (ii) of this section is not appropriate for a specific industry or type of process unit, the owner or operator may propose to the reviewing authority an alternative basic design parameter(s) for the source's process unit(s). If the re viewing authority approves of the use of an alternative basic design parameter(s), the reviewing authority shall issue a permit that is legally enforceable that records such basic design parameter(s) and requires the owner or operator to comply with such parameter(s).

(iv) The owner or operator shall use credible infor mation, such as results of historic maximum capability tests, design information from the manufacturer, or en gineering calculations, in establishing the magnitude of the basic design parameter(s) specified in paragraphs (y)(2)(i) and (ii) of this section.

(v) If design information is not available for a pro cess unit, then the owner or operator shall determine the process unit's basic design parameter(s) using the maximum value achieved by the process unit in the five- year period immediately preceding the planned activity.

(vi) Efficiency of a process unit is not a basic de sign parameter.

(3) The replacement activity shall not cause the process unit to exceed any emission limitation, or opera tional limitation that has the effect of constraining emis sions, that applies to the process unit and that is legally enforceable.

PART 52-[AMENDED]

1. The authority citation for part 52 continues to read as follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart A-[Amended]

2. Section 52.21 is amended:

o a. By revising paragraph (b)(2)(iii)(a).

o b. By adding paragraphs (b)(55) through (58) and paragraph (cc).

The revision and additions read as follows:

§ 52.21 Prevention of significant deterioration of air quality.

(b) * * *

(2) * * *

(iii) * * *

(a) Routine maintenance, repair and replacement. Routine maintenance, repair and replacement shall in clude, but not be limited to, any activity(s) that meets the requirements of the equipment replacement provi sions contained in paragraph (cc) of this section;

* * * * *

(55)(i) In general, process unit means any collec tion of structures and/or equipment that processes, as sembles, applies, blends, or otherwise uses material in puts to produce or store an intermediate or a completed product. A single stationary source may contain more than one process unit, and a process unit may contain more than one emissions unit.

(ii) Pollution control equipment is not part of the process unit, unless it serves a dual function as both pro cess and control equipment. Administrative and ware housing facilities are not part of the process unit.

(iii) For replacement cost purposes, components shared between two or more process units are propor tionately allocated based on capacity.

(iv) The following list identifies the process units at specific categories of stationary sources.

(a) For a steam electric generating facility, the pro cess unit consists of those portions of the plant that con tribute directly to the production of electricity. For ex ample, at a pulverized coal-fired facility, the process unit would generally be the combination of those systems from the coal receiving equipment through the emission stack (excluding post-combustion pollution controls), including the coal handling equipment, pulverizers or coal crushers, feedwater heaters, ash handling, boiler, burners, turbine-generator set, condenser, cooling tower, water treatment system, air preheaters, and op erating control systems. Each separate generating unit is a separate process unit.

(b) For a petroleum refinery, there are several cat egories of process units: those that separate and/or dis till petroleum feedstocks; those that change molecular structures; petroleum treating processes; auxiliary facil ities, such as steam generators and hydrogen production units; and those that load, unload, blend or store inter mediate or completed products.

(c) For an incinerator, the process unit would consist of components from the feed pit or refuse pit to the stack, including conveyors, combustion devices, heat exchangers and steam generators, quench tanks, and fans.

(56) Functionally equivalent component means a component that serves the same purpose as the replaced component.

(57) Fixed capital cost means the capital needed to provide all the depreciable components. "Depreciable components" refers to all components of fixed capital cost and is calculated by subtracting land and working capital from the total capital investment, as defined in paragraph (b)(58) of this section.

(58) Total capital investment means the sum of the following: all costs required to purchase needed process equipment (purchased equipment costs); the costs of labor and materials for installing that equipment (direct installation costs); the costs of site preparation and buildings; other costs such as engineering, construction and field expenses, fees to contractors, startup and per formance tests, and contingencies (indirect installation costs); land for the process equipment; and working cap ital for the process equipment.

* * * * *

(cc) Without regard to other considerations, rou tine maintenance, repair and replacement includes, but is not limited to, the replacement 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 (cc)(1) through (3) of this section are met.

(1) Capital cost threshold for equipment replace ment. (i) For an electric utility steam generating unit, as defined in § 52.21(b)(31), the fixed capital cost of the replacement component(s) plus the cost of any asso ciated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the re placement value of the process unit, at the time the equipment is replaced. For a process unit that is not an electric utility steam generating unit the fixed capital cost of the replacement component(s) plus the cost of any associated maintenance and repair activities that are part of the replacement shall not exceed 20 percent of the replacement value of the process unit, at the time the equipment is replaced.

(ii) In determining the replacement value of the process unit; and, except as otherwise allowed under paragraph (cc)(1)(iii) of this section, the owner or opera tor shall determine the replacement value of the process unit on an estimate of the fixed capital cost of construct ing a new process unit, or on the current appraised value of the process unit.

(iii) As an alternative to paragraph (cc)(1)(ii) of this section for determining the replacement value of a process unit, an owner or operator may choose to use insurance value (where the insurance value covers only complete replacement), investment value adjusted for inflation, or another accounting procedure if such proce dure is based on Generally Accepted Accounting Princi ples, provided that the owner or operator sends a notice to the reviewing authority. The first time that an owner or operator submits such a notice for a particular pro cess unit, the notice may be submitted at any time, but any subsequent notice for that process unit may be sub mitted only at the beginning of the process unit's fiscal year. Unless the owner or operator submits a notice to the reviewing authority, then paragraph (cc)(1)(ii) of this section will be used to establish the replacement value of the process unit. Once the owner or operator submits a notice to use an alternative accounting procedure, the owner or operator must continue to use that procedure for the entire fiscal year for that process unit. In subse quent fiscal years, the owner or operator must continue to use this selected procedure unless and until the owner or operator sends another notice to the reviewing au thority selecting another procedure consistent with this paragraph or paragraph (cc)(1)(ii) of this section at the beginning of such fiscal year.

(2) Basic design parameters. The replacement does not change the basic design parameter(s) of the process unit to which the activity pertains.

(i) Except as provided in paragraph (cc)(2)(iii) of this section, for a process unit at a steam electric gener ating facility, the owner or operator may select as its basic design parameters either maximum hourly heat input and maximum hourly fuel consumption rate or maximum hourly electric output rate and maximum steam flow rate. When establishing fuel consumption specifications in terms of weight or volume, the mini mum fuel quality based on British Thermal Units con tent shall be used for determining the basic design para meter(s) for a coal-fired electric utility steam generating unit.

(ii) Except as provided in paragraph (cc)(2)(iii) of this section, the basic design parameter(s) for any pro cess unit that is not at a steam electric generating facil ity are maximum rate of fuel or heat input, maximum rate of material input, or maximum rate of product out put. Combustion process units will typically use maxi mum rate of fuel input. For sources having multiple end products and raw materials, the owner or operator should consider the primary product or primary raw material when selecting a basic design parameter.

(iii) If the owner or operator believes the basic de sign parameter(s) in paragraphs (cc)(2)(i) and (ii) of this section is not appropriate for a specific industry or type of process unit, the owner or operator may propose to the reviewing authority an alternative basic design pa rameter(s) for the source's process unit(s). If the re viewing authority approves of the use of an alternative basic design parameter(s), the reviewing authority shall issue a permit that is legally enforceable that records such basic design parameter(s) and requires the owner or operator to comply with such parameter(s).

(iv) The owner or operator shall use credible in formation, such as results of historic maximum capabil ity tests, design information from the manufacturer, or engineering calculations, in establishing the magnitude of the basic design parameter(s) specified in paragraphs (cc)(2)(i) and (ii) of this section.

(v) If design information is not available for a pro cess unit, then the owner or operator shall determine the process unit's basic design parameter(s) using the maximum value achieved by the process unit in the five- year period immediately preceding the planned activity.

(vi) Efficiency of a process unit is not a basic de sign parameter.

(3) The replacement activity shall not cause the process unit to exceed any emission limitation, or opera tional limitation that has the effect of constraining emis sions, that applies to the process unit and that is legally enforceable.

5 We broadly use the term "New Source Review," or NSR, to encompass both the PSD and the Non-attainment New Source Review program.

6 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.

7 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.

8 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.

9 Actually proposed as "fuel consumption specifications."

10 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.

11 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 circum 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.

12 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.

13 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.

14 By efficiency, we mean unit of input per unit of output, for example, amount of energy needed to produce a specific amount of output. Another example would be the amount of raw material to produce a specific amount of output.

15 A common example illustrates the point well. When one "tunes-up" a car, the automobile gets more miles per gallon, is cleaner burning, and is cheaper to operate.

16 For example, energy efficiency is not a design parameter to determine functional equivalency for defining routine maintenance. Accordingly, a firm could adopt a more efficient "functionally equiva lent" technology without fear of triggering NSR provisions.

17 As discussed below, our regulations provided a comparable exclusion from NSPS at the time of the 1977 Amendments that established the NSR program.

18 We have taken positions in numerous court filings concerning the proper interpretation and usage of key statutory terms, such as "physical change" and "any physical change." These positions were based on permissible constructions of the statute of which the regulated community had fair notice, and correctly reflect the Agency's reason able accommodation of the Clean Air Act's competing policies in light of its experience at the time it adopted the RMRR exclusion in 1980. The Agency has sought, and has obtained, deference for its interpreta tions, and, notwithstanding today's adoption of a revised interpretation of the statute and an expansion of the RMRR exclusion, the Agency shall continue to seek deference for those prior interpretations in ongoing enforcement litigation.

19 We note that the word "any" is simply a modifier that does not change the meaning of the word it modifies. For example, using the term "any" to modify the word "car" does not somehow change or expand the meaning of the word "car." "Any" simply means that, once you have decided what a car is, then all objects meeting the definition are encompassed.

20 We note that decisions recently were rendered in two of the Agency's pending NSR enforcement cases in the utility sector. In both cases, the Agency asserted that the then existing RMRR exclusion should be applied in a narrow fashion such that only de minimis projects should be excluded under that rule. In our case against Ohio Edison in the U.S. District Court for the Southern District of Ohio, the court determined that the disputed projects did not qualify for the existing RMRR exclusion. The Agency sought and received from the court broad deference with regard to the Agency's interpretation of the CAA and the relevant EPA rules. In our case against Duke Energy in the U.S. District Court for the Middle District of North Carolina, the court issued a decision on cross motions for summary judgment. The decision took exception with several legal conclusions reached in the Ohio Edison decision and determined that the then existing RMRR exclusion must be applied from the perspective of what projects are routine within the relevant industrial source category. EPA today is adopting prospectively a new interpretation of the CAA and is finalizing a revision to the RMRR regulation at issue in those cases.

 

APPENDIX D

STATUTORY AND REGULATORY PROVISIONS

INVOLVED

1. 42 U.S.C. 7411 provides, in pertinent part:

§ 7411. Standards of performance for new stationary sources

(a) Definitions

For purposes of this section:

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(4) The 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 pre viously emitted.

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2. 42 U.S.C. 7478 provides:

(a) Existing regulations to remain in effect

Until such time as an applicable implementation plan is in effect for any area, which plan meets the requirements of this part to prevent significant de terioration of air quality with respect to any air pol lutant, applicable regulations under this chapter prior to August 7, 1977, shall remain in effect to prevent significant deterioration of air quality in any such area for any such pollutant except as oth erwise provided in subsection (b) of this section.

(b) Regulations deemed amended; construction commenced after June 1, 1975

If any regulation in effect prior to August 7, 1977, to prevent significant deterioration of air quality would be inconsistent with the requirements of sec tion 7472(a), section 7473(b) or section 7474(a) of this title, then such regulations shall be deemed amended so as to conform with such requirements. In the case of a facility on which construction was commenced (in accordance with the definition of "commenced" in section 7479(2) of this title) after June 1, 1975, and prior to August 7, 1977, the review and permitting of such facility shall be in accor dance with the regulations for the prevention of sig nificant deterioration in effect prior to August 7, 1977.

3. 42 U.S.C. 7479 provides, in pertinent part:

§ 7479. Definitions

For purposes of this part-

* * * * *

(2)(A) * * *

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(C) The term "construction" when used in connec tion with any source or facility, includes the modifi cation (as defined in section 7411(a) of this title) of any source or facility.

4. 42 U.S.C. 7501(4) provides, in pertinent part:

§ 7501. Definitions

For the purpose of this part-

* * * * *

(4) The terms "modifications" and "modified" mean the same as the term "modification" as used in section 7411(a)(4) of this title.

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5. 40 C.F.R. 52.21(b) provides, in pertinent part:

§ 52.21 Prevention of significant deterioration of air quality.

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(b) Definitions. For the purposes of this section:

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(2)(i) Major modification means any physical change in or change in the method of operation of a major stationary source that would result in: a sig nificant emissions increase (as defined in paragraph (b)(40) of this section) of a regulated NSR pollutant (as defined in paragraph (b)(50) of this section); and a significant net emissions increase of that pollutant from the major stationary source.

* * * * *

(iii) A physical change or change in the method of operation shall not include:

(a) Routine maintenance, repair and replacement. Routine maintenance, repair and replacement shall include, but not be limited to, any activity(s) that meets the requirements of the equipment replace ment provisions contained in paragraph (cc) of this section;

NOTE TO PARAGRAPH (b)(2)(iii)(a): By court order on December 24, 2003, the second sentence of this paragraph (b)(2)(iii)(a) is stayed indefinitely. The stayed provisions will become effective immediately if the court terminates the stay. At that time, EPA will publish a document in the FEDERAL REGISTER advising the public of the termination of the stay.

(b) Use of an alternative fuel or raw material by reason of an order under sections 2 (a) and (b) of the Energy Supply and Environmental Coordination Act of 1974 (or any superseding legislation) or by reason of a natural gas curtailment plant pursuant to the Federal Power Act;

(c) Use of an alternative fuel by reason of an order or rule under section 125 of the Act;

(d) Use of an alternative fuel at a steam generat ing unit to the extent that the fuel is generated from municipal solid waste;

(e) Use of an alternative fuel or raw material by a stationary source which:

(1) The source was capable of accommodating be fore January 6, 1975, unless such change would be prohibited under any federally enforceable permit condition which was established after January 6, 1975 pursuant to 40 CFR 52.21 or under regulations approved pursuant to 40 CFR subpart I or 40 CFR 51.166; or

(2) The source is approved to use under any per mit issued under 40 CFR 52.21 or under regulations approved pursuant to 40 CFR 51.166;

(f) An increase in the hours of operation or in the production rate, unless such change would be pro hibited under any federally enforceable permit con dition which was established after January 6, 1975, pursuant to 40 CFR 52.21 or under regulations ap proved pursuant to 40 CFR Subpart I or 40 CFR 51.166.

(g) Any change in ownership at a stationary source.

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6. 40 C.F.R. 60.14(e) provides, in pertinent part:

§ 60.14 Modification.

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(e) The following shall not, by themselves, be con sidered modifications under this part:

(1) Maintenance, repair, and replacement which the Administrator determines to be routine for a source category, subject to the provisions of para graph (c) of this section and § 60.15.

(2) An increase in production rate of an existing facility, if that increase can be accomplished without a capital expenditure on that facility.

(3) An increase in the hours of operation.

(4) Use of an alternative fuel or raw material if, prior to the date any standard under this part be comes applicable to that source type, as provided by § 60.1, the existing facility was designed to accom modate that alternative use. A facility shall be con sidered to be designed to accommodate an alterna tive fuel or raw material if that use could be accom plished under the facility's construction specifica tions as amended prior to the change. Conversion to coal required for energy considerations, as specified in section 111(a)(8) of the Act, shall not be consid ered a modification.

(5) The addition or use of any system or device whose primary function is the reduction of air pol lutants, except when an emission control system is removed or is replaced by a system which the Ad ministrator determines to be less environmentally beneficial.

(6) The relocation or change in ownership of an existing facility.