Appendix — Utility Air Regulatory Group v. New York (No. 06-750)
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vbreme Court U.S.
06-750 NOV 27 2006
OFFICE OF THE CLERK
No. 06-__
IN THE
Supreme Court of the United States
UTILITY AIR REGULATORY GROUP,
Petitioner,
Vv.
STATE OF NEW YORK, ET AL.,
Respondent.
On Petition for Writ of Certiorari to the
United States Court of Appeals
for the District of Columbia Circuit
APPENDIX TO PETITION
FOR A WRIT OF CERTIORARI
HENRY V. NICKEL
F. WILLIAM BROWNELL
(Counsel of Record)
DAVID S. HARLOW
HUNTON & WILLIAMS LLP
1900 K Street, N.W.
Washington, D.C. 20006
(202) 955-1500
WILSON-EPES PRINTING CO., INC. — (202) 789-0096 -— WASHINGTON, D.C. 20001
APPENDIX TABLE OF CONTENTS
State of New York, et al. v. U.S. Environmental
Protection Agency, 443 F.3d 880 (D.C. 2006)...
Equipment Replacement Rule, 68 Fed. Reg.
61,248, et seg. (October 27, 2003)
Equipment Replacement Rule (on
Reconsideration), 70 Red. Reg. 33,838,
et seq. (June 10, 2005)
Order (Denying Petition for Rehearing)
Order (Denying Petition for
Rehearing en banc)
Judgment 193a
Relevant Statutory Provisions.....................0. 195a
APPENDIX A
UNITED STATES COURT OF APPEALS
For the District of Columbia Circuit
Argued February 8, 2006 Decided March 17, 2006
No. 03-1380
State of New York, ef al.,
Petitioners
V.
Environmental Protection Agency,
Respondent
Clean Air Implementation Project, ez al.,
Intervenors
Consolidated with Nos.
03-1381, 03-1383, 03-1390, 03-1402, 03-1453,
03-1454, 04-1029, 04-1035, 04-1064, 05-1234, 05-1287
J. Jared Snyder, Assistant Attorney General, Attorney
General’s Office of the State of New York, argued the cause
for Government Petitioners. With him on the briefs were
Eliot Spitzer, Attorney General, Peter Lehner and Michael J.
Myers, Assistant Attorneys General, Bill Lockyer, Attorney
General, Attorney General’s Office of the State of California,
Matthew J. Goldman, Deputy Attorney General, Richard
Blumenthal, Attorney General, Attorney General’s Office of
2a
the State of Connecticut, Kimberly Massicotte and Matthew
Levine, Assistant Attorneys General, M. Jane Brady, Attorney
General, Attorney General’s Office of the State of Delaware,
Valerie S. Csizmadia, Deputy Attorney General, Lisa Madi-
gan, Attorney General, Attorney General’s Office of the State
of Illinois, Thomas Davis, Chief, G. Steven Rowe, Attorney
General, Attorney General’s Office of the State of Maine, Ge-
rald D. Reid, Assistant Attorney General, J. Joseph Curran,
Jr., Attorney General, Attorney General’s Office of the State
of Maryland, Kathy M. Kinsey, Assistant Attorney General,
Thomas F. Reilly, Attorney General, Attorney General’s Of
fice of the Commonwealth of Massachusetts, James R.
Milkey, Assistant Attorney General, Kel/y A. Ayotte, Attorney
General, Attorney General’s Office of the State of New
Hampshire, Maureen D. Smith, Senior Assistant Attorney
General, Peter C. Harvey, Attorney General, Attorney Gen
eral’s Office of the State of New Jersey, Stephanie Brand,
Kevin Auerbacher, Jean Reilly, and Ruth Carter, Assistant
Attomeys General, Patricia A. Madrid, Attorney General,
Attomey General’s Office of the State of New Mexico, Tracy
M. Hughes, General Counsel, Robert A .Reiley, Assistant
Counsel, Commonwealth of Pennsylvania, Department of En-
vironmental Protection, Patrick C. Lynch, Attorney General,
Attorney General’s Office of the State of Rhode Island, Tricia
K. Jedele, Special Assistant Attorney General, William H.
Sorrell, Attorney General, Attorney General’s Office of the
State of Vermont, Erick Titrud and Kevin O. Leske, Assistant
Attorneys General, Peggy A, Lautenschlager, Attorney Ger
eral, Attorney General’s Office of the State of Wisconsin,
Thomas L. Dosch, Assistant Attorney General, Robert J.
Spagnoletti, Attorney General, Attorney General’s Office of
the District of Columbia, Edward E. Schwab, Deputy Attor-
ney General, Donna M. Murasky, Senior Litigation Counsel,
Barbara Baird, District Counsel, South Coast Air Quality
Management District, Daniel C. Esty, Christopher P.
McCormack, Christopher G. King, Assistant Corporation
Counsel, City of New York, Kristine Poplawski, Deputy City
3a
Attorney, City and County of San Francisco. John V. Dorsey,
Assistant Attorney General, Attorney General’s Office of the
State of Maryland, William L. Pardee, Assistant Attorney
General, Attorney General’s Office of the Commonwealth of
Massachusetts, Eric Ames and J. Brent Moore, Attorneys,
Attorney General’s Office of the State of New Mexico, and
Lisa S. Gelb, Counsel, City and County of San Francisco, ern
tered appearances.
Howard I. Fox argued the cause for Environmental Pet+
tioners and Intervenor. With him on the brefs were Keri N.
Powell, John D. Walke, Jonathan F. Lewis, Ann B. Weeks,
Leah Walker Casey, and Michael D. Fiorentino. Blair W.
Todt entered an appearance.
Richard E. Ayers was on the brief of amicus curiae Calpine
Corporation in support of petitioners.
Hope M. Babcock was on the brief of amici curiae Amert
can Thoracic Society, et al. in support of environmental petr
tioners.
Victor B. Flatt was on the brief of amici curiae Senator
Hillary Rodham Clinton, et al. in support of petitioners.
Geoffrey M. Klineberg was on the brief of amicus curiae
Atlantic Salmon Federation in support of petitioners.
Angeline Purdy and Cynthia J. Morris, Attorneys, U.S. De-
partment of Justice, argued the cause for respondent. With
them on the brief was John C. Cruden, Deputy Assistant At-
torney General. Michael B. Heister, Attorney, and Carol S.
Holmes, Counsel, U.S. Environmental Protection Agency,
entered appearances.
F. William Brownell argued the cause for Industry Interve-
nors in support of respondent. With him on the brief were
4a
William H. Lewis, Jr., Henry V. Nickel, Makram B. Jaber,
David S. Harlow, Katherine D. Hodge, John L. Wittenborn,
Leslie Sue Ritts, Lorane Hebert, and Charles H. Knauss. Rus-
sell S. Frye entered an appearance.
Judith Williams Jagdmann, Attorney General, Attorney
General’s Office of the Commonwealth of Virginia, William
E. Thro, State Solicitor General, D. Mathias Roussy, Assoc+
ate State Solicitor General, Carl! Josephson, Senior Assistant
Attorney General, Troy King, Attorney General Attorney
General’s Office of the State of Alabama, Robert D. Tam-
bling, Assistant Attorney General, David W. Marquez, Attor-
ney General, Attorney General’s Office of the State of Alaska,
Steven E. Mulder, Assistant Attorney General, Mike Beebe,
Attomey General, Attorney General’s Office of the State of
Arkansas, Teresa Marks, Deputy Attorney General, Lawrence
E. Long, Attorney General, Attorney General’s Office of the
State of South Dakota, Roxanne Giedd, Deputy Attorney
General, Mark L. Shurtleff, Attorney General, Attorney Gen
eral’s Office of the State of Utah, Fred Nelson, Assistant At-
tomey General, Patrick J. Crank, Attorney General, Attorney
General’s Office of the State of Wyoming, Vicci M. Colgan,
Senior Assistant Attomey General, Phill Kline, Attomey Gen
eral, Attorney Gencral’s Office of the State of Kansas, David
W. Davies, Assistant Attorney General, Jeremiah W. (Jay)
Nixon, Attorney General, Attorney General’s Office of the
State of Missouri, James R. Layton, State Solicitor, Jon
Bruning, Attorney General, Attorney General’s Office of the
State of Nebraska, Wayne Stenehjem, Attorney General, At-
torney General's Office of the State of North Dakota, and Ly/e
G. Witham, Assistant Attorney General, were on the brief of
Intervening States. Michael R. O'Donnell, Assistant Attorney
General, Attorney General’s Office of the State of Wyoming,
R. Craig Kneisel, Assistant Attorney General, Attorney Gen
eral’s Office of the State of Alabama, Roger L. Chafee, Senior
Assistant Attorney General, Attorney Gencral’s Office of the
Commonwealth of Virginia, entered appearances.
Sa
Jim Petro, Attorney General, Attorney General’s Office of
the State of Ohio, Henry McMaster, Attorney General, Attor-
ney General’s Office of the State of South Carolina, Steve
Carter, Attorney General, Attorney General’s Office of the
State of Indiana, Thomas M. Fisher, Solicitor General, Valerie
Tachtiris, Deputy Attorney General, and John J. Bursch were
on the brief of amici curiae States of Indiana, Ohio, and South
Carolina in support of respondent. Steven D. Griffin, Assis-
tant Attorney General, Attorney General’s Office of the State
of Indiana, entered an appearance.
Daniel J. Popeo, Paul D. Kamenar, and Paul M. Seby were
on the brief of amicus curiae Washington Legal Foundation in
support of respondent.
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 pollution
to avoid triggering New Source Review (“NSR”). The court
upheld in part and vacated in part the first rule. /d. at 10-11.
We now address the second rule, the Equipment Replacement
Provision (“ERP”), which amends the Routine Maintenance,
Repair, and Replacement 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 exclusion
has historically provided that routine maintenance, repair, and
replacement do not constitute changes triggering NSR. The
- 6a
ERP both defined and expanded that exclusion. EPA ex-
plained:
[The] rule states categorically that the re-
placement of components with identical
or functionally equivalent components
that do not exceed 20% of the replace-
ment 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 Mainte-
nance, 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)(“Reconsideration”). Hence,
the ERP would allow sources to avoid NSR when replacing
equipment under the twenty-percent cap notwithstanding a
resulting increase in emissions. 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 depending upon the
geographic location of the source.' Section 111(a)(4) of the
Act describes when a source is to be considered “modified”:
' NSR consists of two programs: prevention of significant
deterioration (“PSD”) and nonattainment NSR. See New York
1,413 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 preconstruction permit, prove that
the construction will not cause violations of certain air quality
(continued...)
Ta
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 previously emitted.
42 U.S.C. § 7411(a)(4) (emphasis added). Since the inception
of NSR, RMRR has been excluded from the definition 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 fac-
tors 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. 1980), 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 defined
the RMRR exclusion as limited to “de minimis circum-
stances.” 68 Fed. Reg. at 61,272. The ERP provides a bright-
line rule and expands the traditional scope of the RMRR by
standards, and show that their operations are in compliance
with the Best Available Control Technology (“BACT”)
requirements. 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.
8a
exempting certain equipment replacements from NSR. See,
e.g., 40 C.F.R. § 52.21(cc)(2005).°
The government and environmental petitioners contend that
the ERP is contrary to the plain text of the Act because the
statutory definition of “modification” applies unambiguously
to any physical change that increases emissions, necessarily
including the emissionmincreasmg equipment replacements
excused from NSR by the rule. They maintain that the word
se ”
any,” when given its natural meaning, requires that the
* The ERP provides:
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 requirements in
paragraphs (cc)(1) through (cc)(3)of this
section are met.
40 C.F.R. § $2.21 (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 ar. ds 40
C.F.R. §§ 51.165, 51.166, and 52.24, but given the siailarity
of the sections, the court will follow the practice of the parties
in citing only section 52.21.
9a
phrase “physical change” be read broadly, such that EPA’s
attempt to read “physical change” narrowly would relegate 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. National
Resources Defense Council, Inc., 467 U.S. 837 (1984). If
“Congress 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 in-
- tent of Congress.” Jd. at 842-43. Only if the statute is silent
or ambiguous do we defer to the agency’s interpretation, ask-
ing “whether [it] is based on a permissible construction of the
statute.” /d. at 843. “Ifa court, employing traditional tools of
statutory construction, ascertains that Congress had an inten
tion on the precise question at issue, that intention is the law
and must be given effect.” Jd. at 843 n.9.
The petitioners and EPA agree that the phrase “physical
change” is susceptible to multiple meanings, each citing dic-
tionary 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 (1994)); see California Indep.
Sys. Operator Corp. v. FERC, 372 F.3d 395, 400 (D.C. Cir.
2004); Cincinnati Ins. Co. v. Flanders Elec. Motor Serv., Inc.,
40 F.3d 146, 152 (7th Cir. 1994). As the parties point out, the
ordinary meaning of “physical change” includes activities that
“make different in some particular,” “make over to a radically
different form,” or “replace with another or others of the same
kind or class." WEBSTER’S THIRD NEW INTERNA-
TIONAL DICTIONARY 373 (1981). To say that it is
“physical,” in this context, indicates that the change must be
“natural or material,” rather than “mental, moral, spiritual, or
imaginary.” /d. 1706. The parties agree that in “[rjealt world,
commorsense usage,” 68 Fed. Reg. at 61,271, “physical
10a
change” includes equipment replacements. They further agree
that the ERP would excuse from NSR requirements certain
emission increasing activities that EPA has historically con
sidered to be “physical changes.” See id. at 1,270.
The parties’ essential disagreement, then, centers on the ef
fect of Congress’s decision in defining “modification” to in-
sert the word “any” before “physical change.” According to
the petitioners, the word “any” means that the phrase “phys+
cal change” covers any activity at a source that could be com
sidered 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
“susceptible to multiple meanings,” id. at 61,271, “identifying
activities that are ‘changes’ for NSR purposes . . . requires an
exercise of Agency expertise,” “the classic situation in which
an agency is accorded deference under Chevron,” id. at
61,272. Under this approach, once EPA has identified an ac-
tivity as a “physical change,” the word “any” requires that the
activity be subject to NSR. We conclude that the differences
between the parties’ interpretations of the role of the word
“any” are resolved by recognizing that “[rJead naturally, the
word ‘any’ has an expansive meaning, that is, ‘one or some
indiscriminately of whatever kind,” United States v. Gonza-
les, 520 U.S. 1, 5 (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 (2001). Because Congress used the word “any,”
EPA must apply NSR whenever a source conducts an emis-
slomincreasing activity that fits within one of the ordinary
meanings of “physical change.”
In a series of cases, the Supreme Court has drawn upon the
word “any” to give the word it modifies an “expansive mean
ing” when there 1s “no reason to contravene the clause’s obvi-
ous meaning.” Norfolk S. Rwy. Co. v. Kirby, 543 U.S. 14, 31-
32 (2004); see also Dep't of Hous. and Urban Dev. v. Rucker,
$35 U.S. 125, 130-31 (2002); Gonzalez, 520 U.S. at 5. Indeed,
lla
the Court has read the word “any” to signal expansive reach
when construing the Clean Air Act. In Harrison v. PPG In-
dustries, Inc., 446 U.S. 578 (1980), the Court resolved a juris-
dictional dispute under section 307(b)(1) by interpreting the
phrase “any other final action,” which the Court “discern[ed
to have] no uncertainty.” /d. at 588. The Court never sug-
gested that the term “final action” was itself devoid of multt
ple 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.’” Jd. at 589. “[I]n the absence of leg
islative history to the contrary,” the Court held that the statu
tory phrase “must be construed to mean exactly what it says,
namely, any other final action.” /d.
Although EPA is correct that the meaning of “any” can dif
fer depending upon the statutory setting, see Nixon v. Missouri
Mun. League, 541 U.S. 125, 132 (2004), the context of the
Clean Air Act warrants no departure from the word’s custom
ary effect. Unlike Nixon, the question of statutory interpreta-
tion here does not arise in a setting in which the Supreme
Court has required heightened standards of clarity to avoid
upsetting fundamental policies. See id. at 132-33, 140-41
(citing Gregory v. Ashcroft, 501 U.S. 452 (1991)). EPA
points to no “strange and indeterminate results,” id. at 133,
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 Wisconsin
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, 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
12a
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 ‘mod+
fication’ [in section 111(a)(4)] is nowhere limited to phys ical
changes exceeding a certain magnitude.” 636 F.2d at 400.
Although the legislative history indicated that one Senator
intended the term to apply only to “major expansion pro-
gram(s},” id. at 400 n.47, the court observed that “the lan
guage 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.” /d. More recently, in New
York 1, 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 [, 413 F.3d at 40-42. Like-
wise, the Seventh Circuit concluded in WEPCo that the pur-
poses of the 1977 amendments to the Act required an expar
sive 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 dect
sions and to find ambiguity in the phrase “any physical
change” fails for a variety of reasons. Even assuming that the
decisions construing section 111(a)(4) are not “judicial prece-
dent holding that the statute unambiguously forecloses the
agency's interpretation,” Nat'l Cable & Telecomms. Ass'n v.
Brand X Internet Servs., 125 S. Ct. 2688, 2700 (2005), Brand
X, on which EPA principally relies, does not drain those dec+
sions of all precedential value. The fact that previous judicial
interpretations of section I111(a)(4) have all reached the con
13a
clusion that the text must be read broadly supports the pet
tioner’s argument at Chevron step one, particularly because
those decisions — both before and after Chevron — used lan
guage indicating the text was “clear” and “plain.” See New
York I, 413 F.3d at 40; WEPCo, 893 F.2d at 907; Alabama
Power, 636 F.2d at 400.
Even in the absence of such precedent, EPA’s approach to
interpreting “physical change,” as well as a similar approach
by industry intervenors that focuses on the thirty-nine words
following “any,” contravenes several rules of statutory inter-
pretation. EPA’s position is that the word “any” does not af
fect 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
defined category is subject to NSR. To begin, that reading,
contrary to “a cardinal principle of statutory construction,”
would make Congress’s use of the word “any” “insignificant”
if not “superfluous.” 7TRW, 534 U.S. at 31 (quoting Duncan v.
Walker, 533 U.S. 167, 174 (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 appli-
cations covered by a definition before a court could conclude
that Congress had directly spoken regarding a particular ap-
plication, ignoring the fact that a definition, like a general
rule, need not list everything it covers. See NPR 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 osten-
sibly require that the definition of “modification” include a
phrase such as “regardless of size, cost, frequency, effect,” or
other distinguishing characteristic. Only in a Humpty Dumpty
i4a
3 ™ pd
world” would Congress be required to use superfluous words
while an agency could ignore an expansive word that Con-
gress did use. We decline to adopt such a world-view.
In contrast, the petitioners’ approach, by adopting an expan
sive reading of the phrase “any physical change,” gives natu
ral effect to all the words used by Congress and reflects both
their common meanings and Congress’s purpose in enacting
the 1970 and 1977 amendments. See New York J, 413 F.3d at
11-13; WEPCo, 893 F.2d at 909. To mprove pollution com
trol programs in a manner consistent with the balance struck
by Congress in 1977 between “the economic interest in per-
mitting capital improvements to continue and the environ
mental interest in improving air quality,” Chevron, 467 U.S. at
851, Congress defined the phrase “physical change” in terms
of increases in emissions. After using the word “any” to ind+
cate 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 limita-
tion, the court must presume that Congress acted “intention
ally and purposely,” Barnhart v. Sigmon Coal Co., 534 U.S.
438, 452 (2002) (quoting Russello v. United States, 464 US.
16, 23 (1983)), when it did not include others. Cf New York
1,413 F.3d at 39. So construed, each word in the phrase “any
physical change” has a meaning consonant with congressional
intent and the scope of the definitional phrase is limited only
* See TVA v. Hill, 437 U.S. 153, 173 n.18 (1978) (quoting
Through the Looking Glass, in THE COMPLETE WORKS
OF LEWIS CARROLL 196 (1939)).
15a
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 com
sidered a “physical change” in ordinary usage within the an
bit 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
replacements covered by the ERP are “physical changes” un-
der one of the ordinary meanings of the phrase. See 68 Fed.
Reg. at 61,271-72. EPA may not choose to exclude that
“(rjeat world, commonsense usage of the word ‘change.’”
Id. at 61,271. Moreover, a physical change is not the sole
criterion for triggering NSR under the definition of “modift
cation.” 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 his-
torically 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 doc-
trine that, notwithstanding 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
4 The court has no occasion to decide whether part
replacements or repairs necessarily constitute a “modifica-
tion” under the definition taken as a whole.
l6a
360 n.89 (citations omitted). As the Supreme Court has in-
structed, “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 enactments (absent contrary indication) are
deemed to accept.” Wisconsin Dep't of Revenue v. William
Wrigley, Jr., Co., 505 U.S. 214, 231 (1992). Reliance on the
de minimis doctrine invokes congressional intent that agencies
diverge from the plain meaning of a statue only so far as is
necessary to avoid its futile application. Thus, the court in
Alabama Power acknowledged that “EPA does have discre-
tion, 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” administrative and economic bur-
dens by lifting requirements on “minuscule” emission in-
creases. See id. at 405. While the court today expresses no
opinion regarding EPA’s application of the de minimis excep-
tion, given the limits on the scope of the de minimis doctrine,
see Shays, 414 F.3d at 113-14, EPA appropriately has not at-
tempted to justify the ERP as an exercise of de minimis dis-
cretion. As EPA has disclaimed the assertion that its prior
expansive interpretations of “any physical change” were “ab-
surd or futile,” 70 Fed. Reg. at 33,842, it is in no position to
claim that the ERP is necessary to avoid absurdity.
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 “increases” in section 111(a)(4)
is ambiguous, see New York I, 413 F.3d at 23, does not sug-
gest that the phrase “any physical change” is also ambiguous;
unlike the latter, the former is unaccompanied by a qualifier
signaling Congress’s intent. Congress’s use of the word “in-
creases” necessitated further definition regarding rate and
measurement for the term to have any contextual meaning.
No such further definition of “physical change” is required
17a
because Congress’s use of the word “any” indicates the intent
to cover all of the ordinary meanings of the phrase, as evi-
denced by EPA’s decades-long understanding and practice.
Also, because the court in New York J rejected industry’s
contention that Congress ratified the New Source Performance
Standards (“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 rear-
gue their position that “modifications” require an increase in
maximum emission 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 de-
nial 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 matter of his-
torical fact, Congress did not mean what it appears to have
said, or that, as a matter of logic and statutory structure, it al
most 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 pollution — demonstrate
the futility of EPA’s endeavor. EPA cannot show that histor
cal fact prevents a broad reading of “any physical change”
inasmuch as EPA for decades has interpreted that phrase to
mean “virtually all changes, even trivial ones, . . . generally
18a
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 Com
gress requiring NSR for equipment replacements that increase
emissions while allowing replacements that do not increase
emissions to avoid NSR. EPA acknowledges the reasonable-
ness of its past expansive interpretation 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 allow-
ing ERP projects has the potential to lower overall emissions
through increased efficiency even if emissions increase at a
source, the court in New York / rejected EPA’s similar argu-
ment in support of an exemption from NSR for pollution con
trol projects. The court stated that “Congress could reasona-
bly conclude, for example, that tradeoffs between pollutants
are difficult to measure, and thus any significant increase in
emissions of any pollutant should be subject to NSR.” New
York [, 413 F.3d at 41. Absent a showing that the policy de-
manded 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 struc-
ture 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 programs,” as support for its view that
economic and environmental interests can be effectively bal
anced 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.
19a
Accordingly, we hold that the ERP violates section
111(a)(4) of the Clean Air Act in two respects. First, Con
gress’s use of the word “any” in defining a “modification”
means that all types of “physical changes” are covered. Al
though the phrase “physical change” is susceptible 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 results 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,” therefore,
does not include only physical changes that are costly or ma-
jor. Second, Congress defined “modification” in terms of
emission increases, but the ERP would allow equipment re-
placements resulting in nomde minimis emission increases to
avoid NSR. Therefore, because it violates the Act, we vacate
the ERP.
20a
APPENDIX B
Equipment Replacement Rule
68 Fed. Reg. 61,248 (October 27, 2003)
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
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
SUMMARY: The EPA is finalizing revisions to the regula-
tions governing the NSR programs mandated by parts C and
D of title I of the Clean Air Act (CAA). Today's changes re-
flect EPA's incorporation of comments from the proposed rule
for “Pyevention 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 maintenance, re-
pair and replacement (RMRR) exclusion. The changes are in-
tended to provide greater regulatory certainty without
sacrificing the current leyel of environmental protection and
benefit derived from the NSR program. We believe that these
changes will facilitate the safe, cfficient, and reliable
operation of affected facilities.
21a
EFFECTIVE DATE: This final rule is effective on
December 26, 2003.
ADDRESSES: Docket. Docket No. A-2002-04 (Electronic
docket OAR-2002-0068), containing supporting information
used to develop the proposed rule and today'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 Avenue, 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 available in the
docket, an electronic copy of this final rule will also be
available on the WWW through the Technology 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 Integration
Division (C339-03), U.S. EPA Office of Air Quality Planning
and Standards, Research Triangle Park, North Carolina 27711,
telephone 919-541-2380, or _ electronic mail at
svendsgaard.dave@epa.gov , for questions on this rule.
SUPPLEMENTARY INFORMATION:
Regulated Entities
Entities potentially affected by this final action include
sources in all industry groups. The majority of sources
potentially affected are expected to be in the following
groups:
Industry group
NAICS°
I
Petroleum Refining
Industrial Inorganic Chemicals
Industrial Organic Chemicals.........
Miscellaneous Chemical Products...
Natural Gas Liquids...................
Natural Gas Transport
Pulp and Paper Mills..................
SRE Ti nan cdubdeabsoncenueaseatins
Automobile Manufacturing
Pharmaccuticals......................6.
283
221111, 221112,
221113, 221119,
221121, 221122
324110
325181, 325120,
325131, 325182,
211112, 325998,
331311, 325188
325110, 325132,
325192, 325188,
325193, 325120,
325199
325520, 325920,
325910, 325182,
325510
211112
486210, 221210
322110, 322121,
322122, 322130
322121, 322122
336111, 336112,
336211, 336992,
336322; 336312,
336330, 336340,
336350, 336399,
336212, 336213
325411, 325412,
325413, 325414
“Standard Industrial Classification.
°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 organized 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?
I]. Background
A. What is the RMRR exclusion?
B. Issues surrounding the RMRR exclusion
C. Process used to develop this rule
D. What we proposed
II]. 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 considered
RMRR?
C. What cost limit has been placed on the equipment
replacement approach?
D. What will be the basis of applying the 20-percent
threshold?
E. What basic design parameters are being established to
qualify for the equipment replacement provision?
F. What collection of equipment should be considered in
applying the equipment replacement provision and how
should it be defined?
G. Consideration of nonemitting 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
24a
K. Consideration of other options
. Annual Maintenance, repair and replacement allowance
. Capacity-based option
. 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 approach?
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 Coordination
with Indian Tribal Governments
D. Executive Order 13045--Protection of Children from
Environme ntal 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 Advancement Act of
1995
1. Executive Order 1321 1--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
V1. Statutory Authority
1. General Information
A. How Can | 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. 42002-04. The
25a
Official public docket consists of the documents specifically
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 restricted by statute. The official public
docket is the collection of materials that is available for public
viewing at the EPA Docket Center, (Air Docket), U.S.
Environmental 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 am. 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 appropriate 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 official public docket. To the extent
. feasible, publicly available docket materials will be made
26a
available in EPA's electronic public docket. When a document
ts 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 materials through the
docket facility identified in section I.A.1. of this preamble.
The EPA intends to work towards 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 electronic
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 information
and technology exchange in various areas of air pollution
control. If more information regarding the TTN is needed, call
the TTN HELP line at (919) 541-5384.
Il. Background
A. What Is the RMRR Exclusion?
27a
Title I of the Clean Air Act (CAA) established the New
Source Review program’ to help control airborne emissions
from major new stationary sources of pollution. 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 construction of the source. In order to obtain the
permit, the owner or operator must, among other things,
demonstrate that the new source will have state-of-the-art
pollution control devices.
The NSR program does not generally affect existing
sources, but it does apply if they undergo a * modification."
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 program, ‘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 pollutant; and (2) a significant net
emissions increase of that pollutant from the major stationary
' We broadly use the term ‘‘New Source Review," or NSR,
to encompass both the PSD and the Non-attainment New
Source Review program.
28a
source.” The regulations further provide that certain activities
do not constitute 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 provisions
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 multrfactor test for
determining whether a particular 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 context 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 important to
assuring the safe, reable and efficient operation of existing
plants. Specifical/y. some of the case-by-case determinations
we have made particularfy over the past decade, and
particularly in a series of enforcement actions, have been
criticized for giving the exclusion a narrow scope that
disallows replacement of significant plant components with
“ Once a modification is determined to be major, NSR r-
quirements apply only to those specific pollutants for which
there would be a significant net emissions increase.
29a
identical or functionally equivalent components. Critics argue
that the effect is to discourage plant owners or operators from
engaging in replacements 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 uncertairities inherent in the case-
by-case approach.
To elaborate on the uncertainty issues: Unless an owner or
operator seeks an applicability deternyination from his or her
reviewing authority, it can be difficult for the owner or
operator to know with reasonable certainty 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 option, 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 authority 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 consequences. Those consequences could well
include substantial 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
30a
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 applicability
determination. That process, too, is time-consuming and
expensive, albeit typically less so than seeking a permit. This
path presents a potentially significant barrier 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 deteriorated with use
and probably are less advanced and less efficient than current
technology. Foregoing the replacement activities altogether
will recuce 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 operation or
capacity or install less than state-of-the-art air pollution
controls to ensure no increase in emissions. Either of those
courses, howewtr, will also result in loss of plant productivity.
The uncertainties are also problematic for State and local
reviewing authorities. They require those authorities to devote
scarce resources to make complex determinations, including
applicability determinations, and consult with other agencies
to ensure that any determinations are consistent with
determinations made for similar circumstances in_ other
31a’
jurisdictions and/or that other reviewing authorities would
concur with the conclusion.
Industry commenters strongly echoed these concerns,
asserting that the expense and delay associated with NSR
scrutiny, whether or not the activity is ultimately judged to be
subject to major NSR, have caused a number of facilities to
forego needed and beneficial maintenance, repair, and
replacement activities, including ones that would likely have
reduced emissions. In our June 2002 report to the President,
we similarly concluded that the NSR program has impeded or
resulted in the cancellation of projects that would have
maintained and improved the reliability, efficiency, or safety
of existing energy capacity.
We are persuaded that we should change the approach to
the RMRR exclusion that we have been following 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 process 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
components, 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 limitations 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 environmental benefits compared with the
approach we are adopting today and, ndeed, we believe our
32a
new approach may well produce environmental improvements
as compared to the old one.
We are also persuaded that uncertainties surrounding the
scope of the exclusion that are associated with the case-by-
case approach tend to exacerbate the problem 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 replacement in question was RMRR. Such
discouragement results 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 process unit with
identical components or their functional equivalents will come
within the scope of the exclusion, provided the cost of
replacing the component fails below 20 percent of the
replacement value of the process wnit 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 operational limitations.
Our new equipment replacement approach will allow
owners Of 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 determinations. 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 performance.
For example, we anticipate that improved safety and
rchiability will result in more stable process operations and
reduce periods of startup, shutdown, and malfunction and the
increased emissions usually associated with = them.
33a
Accordingly, we believe the rule will promote the central
purpose of Title I 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 productive capacity of its
population." CAA section 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 language 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
accommodation 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 possible 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 environmental protection. Our Report to
the President illustrated the problems associated with our prior
case-by-case approach to identifying RMRR activities and
underscored the advantages of establishing an objective
bright-line approach for administering the RMRR provision.
34a
We held conference calls with various stakcholders 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 improved. 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 approaches. 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 approach.
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_ facilitywide annual
maintenance, repair and replacement allowance and/or an
cquipment replacement cost threshold to determine whether
major NSR requirements were triggered by performing plant
maintenance, repair and replacement 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 approaches as well as any other viable option for
clarifying the term ‘routine maintenance, repair, and
replacement.” 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 cach industrial facility based on an industry-
specific percentage. For the percentage, we considered using
35a
the Internal Revenue Service ‘‘Annual Asset Guideline Repair
Allowance Percentages" (AAGRAP), which for years has
been used as an integral part of an exclusion under the New
Source Performance Standard (NSPS) program. A multt 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 allowance are not
activities that should be subject to greater scrutiny. These
safeguards include: (1) No new wit may be installed; (2) no
unit may be replaced in its entirety; and (3) changes may not
cause an increase in the short-term emission rate of any
regulated NSR pollutant.
Under the ‘equipment replacement provision,” or ERP, we
proposed to streamline the process for determining 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, potentially up to 50 percent of the cost of replacing
the process 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 allowance 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 accordance with current rules.
We solicited comments on all aspects of our RMRR
proposal.
III. Equipment Replacement Provision
36a
A. Overview and Justification for Today's Final Action
Today, we are revising certain provisions of the major NSR
program by finalizing the equipment replacement provision
(ERP) to specify activities that will automatically 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, repair and replacement allowance
approach.
Although many commenters requested that we further
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
replacement of any existing component(s)* of a process unit
with component(s) that are identical or that serve the same
purpose as the replaced component(s); (2) the fixed capital
cost of the rplaced component(s), plus costs of any activities
that are part of the replacement activity (¢.g., labor, contract
services, major equipment rental, and associated repair and
maintenance activities),” does not exceed 20 percent of the
’ For the sake of clarity, we want to be clear that the term
“component” is meant to be applied broadly and read broadly
to include replacements of both large components, such as
economizers, reheaters, etc. at a boiler, as well as small items,
such as screws, washers, gaskets, etc.
* We note that certain ancillary costs incurred during a give
replacement activity should not be part of the replacement
activity, such as replacement power that must be purchased
during the maintenance shutdown of an electric utility.
37a
current replacement value of the process unit; and (3) the
replacement(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 enforceable.
Today's final rule specifies the procedures by which the
owner or operator of a source selects the basic design
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 rate’ as basic design parameters. 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 output--more specifically, maximum hourly
electric output rate or maximum steam flow rate--as an
alternative to the previously proposed input-based parameters.
Likewise, we are retaining our proposed approach of
specifying maximum rate of fuel or material input for other
types of process units, but we also allow you to use maximum
rate of heat input, or maximum rate of product output if you
prefer an output-based basic design parameter. In addition, we
allow you to propose an alternative basic design parameter(s),
if the above options are inappropriate for your process unit.
We are not specifically defining the basis for determining
the replacement value of a new process unit. Instead, the final
rule provides you with the flexibility of using any of the
following: (1) Replacement cost;° (2) invested cost, adjusted
for inflation; (3) the insurance value, where the insurance
value covers complete replacement of the process unit (rather
> Actually proposed as *‘fuel consumption specifications."
° Replacement cost can be either an estimate of the fixed
capital cost of constructing a new process unit or the current
appra:se@ value of the process unit.
38a
than, for example, lost revenue replacement); or (4) another
accounting procedure to establish a replacement value of the
process unit if such accounting procedure is based on
Generally 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 guidelines 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 Accounting 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 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 submitted only at the beginning of the process unit's fiscal
year. You must continue to use the same basis to evaluate any
additional 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 methed. In the absence of providing any
notification to your reviewing authority, you must use option
| 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_ functionally
equivalent replacement. A more detailed discussion of these
requirements and our rationale for this action is contained in
other parts of this preamble section.
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 today's final action
broadens the major NSR program exclusion for equipment
39a
replacements and provides you with additional certainty as to
what equipment replacement activities qualify for the RMRR
exclusion. By adding certainty to the process, we are
rémo ving the disincentives 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
considerations. In many cases, we believe that maintaining
safe, reliable and efficient operations will have the
corresponding 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
_°§ to promote the public health and welfare and the productive
vapacity of its population." CAA section 101.
B. What Is an Identical or Functionally Equivalent
Replacement and Why Should Such an Activity Be Considered
RMRR?
We proposed to exclude the replacement of existing
equipment with identical or functionally equivalent
components. As we observed at the time of our RMRR
proposal, we believe that most identical and functionally
equivalent replacements are necessary for the safe, efficient
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 under the RMRR exclusion. We
believe industrial facilities are constructed with the
understanding that certain equipment failures are common and
ongoing maintenance programs that include _ replacing
components in order to maintain, restore, or enhance the
40a
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 replaced
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 associated 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
replacement. 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 permitting 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 replaced it with a new and improved model, it
docs not scem to us that this changes the fundamental reasons
for treating that replacement as likewise within the scope of
routine matntenance, repair and replacement.”
4la
This is particularly true since technology is constantly
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 equipment reflecting current design
innovations. Even if it is possible to find old-style equipment,
it seems unnecessary and undesirable to generally construe
NSR permitting 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 installed.
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 generating units,
this might mean heat input and: fuel consumption
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 intended to impede industry in
making energy and process efficiency improvements. We
believe such improvements, 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 replacement
of components that are expected to be replaced 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 smailer
components, instead requiring greater scrutiny if the
replacement in question is part of an activity that exceeds 20
percent of the replacement value of the process unit.
Our decisions on these points are derived from reflection 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 believe that application of
42a
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 production 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 replacing
parts or components so as to preserve their ability to produce
at that rate. Rather, we believe Title I of the Clean Air largely
leaves to State and local permitting 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 permitting
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 mult
factor, case-by-case approach we have been using in
identifying RMRR, and particularly from some of our
applications of that test to certain equipment replacements.
We believe, however, that this adjustment in our approach is
fully warranted for the reasons outlined above, and described
more fully in our legal analysis below.
The following examples of functionally equivalent
replacements under today's rule include:’
7 : , :
As discussed in more detail Selow, 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 replacement 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
(continued...)
43a
-- Replacing worn out pipes in a chemical process plant
with pipes that are constructed of different metallurgy (e.g., to
help reduce corrosion, erosion, or chemical compatibility
problems).
-- Replacing an analog controller with a digital controller,
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 presented 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 outdated analog controllers at a series
of six batch digesters. In this case, the original controllers
were no longer manufactured. The new digital controllers,
costing approximately $50,000, are capable of receiving
inputs. 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. |
-- 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 characteristics of the ground
material would be different before and after the replacement).
-- Replacing existing spray paint nozzles with new ones that
might atomize the spray better or have a higher transfer
efficiency because the “‘before" and “after” 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, ai.d other backstop
circumstances. 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.
44a
features of today's rule, but nevertheless cannot qualify for the
RMRR exclusion on the grounds that the equipment is neither
identical nor functionally equivalent. An example of this
would be a chemical processing facility where the owner or
operator makes a physical change that allows the production
of a new end product hat 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 produce 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 replacement
provision will streamline the major NSR_ applicability
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 turbine
customers and found that achreving 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 technology, 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
45a
with the ERP, replacement of all boiler tubes would, in the
commenter's opinion, rightfully be considered routine.
Another 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 allow 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 project is clear. To further
clarify, the commenter made the following points. According
to the commenter, routine maintenance is frequent and follows
a predictable pattern. The commenter characterized routine
maintenance 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 planning and design
work.
One commenter said the proposal will allow emissions
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 prevent replacement
with different equipment; (2) it does not promote efficiency
46a
improvements or application of good air pollution controls;
and (3) it would allow replacements that would significantly
increase emissions. This commenter said replacement of air
pollution controls should trigger best available control
technology (BACT) or lowest achievable emission rate
(LAER) requirements. 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 functionally equivalent
equipment. Primarily their concerns were rooted in the fact
that a functionally equivalent replacement component could
lead to increases in operational 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 generally
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 implement than the current case-by-case
analysis required to determine a replacement falls within the
RMRR exclusion. 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
47a
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 increased emissions. For
pieces of equipment used at industrial facilities, most
manufacturers have well-established procedures for the
inspection and replacement that are part of the regular
maintenance necessary to provide for the equipments 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 process
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 components wear out every year,
while others wear out every 20 years. Nevertheless, both types
of changes should fall within the ERP of the RMRR exclusion
because both allow the facility to operate as designed. By not
imposing a time limitation, the ERP allows replacement
activities to be driven by consideration of economic efficiency
rather than artificial regulatory constraints.
We disagree with commenters who expressed particular
concern about functionally equivalent replacements. We
continue to believe such activities should be encouraged and
should qualify as RMRR. Even though a functionally
48a
equivalent component varies in some respects 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 replacement can result in an increase
in efficiency and, consequently, productivity. In fact, one of
our goals is to promote 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 characteristics of the
process unit.
We note that the two local programs in California that
exclude the replacement of equipment with identical
equipment also allow the replacement of equipment with
functionally cquivalent equipment without considering such
action to be a modification. Due to local air quality
considerations, the local programs establish minimum
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 December 2002
for the RMRR_ equipment replacement provision with
relatively minor changes. We decided to include another
safeguard in addition to those we proposed in order to
appropriately constrain the meaning of the term "functionally
equivalent.” The additional safeguard is that an excluded
replacement activity cannot cause the process unit to exceed
any emission limitation or operational limitation (that has the
effect of constraining emissions) that applics to the process
unit and that is legally enforceable.
Thus, today's final rule allows you to categorize identical
and functionally cquivalent equipment replacements as
RMRR if the fixed capital cost of such replacement plus the
49a
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 parameter 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 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 purpose of this
threshold is to distinguish between those equipment
replacement activities that should automatically qualify as
RMRR without further consideration and those activities that
should undergo case-specific consideration. This concept is
akin to the long-established reconstruction provision under the
NSPS program. For the reasons explained below, we have
decided 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 equipment 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 refrain from equipment
replacements and instead repair existing equipment or find
some other solution.
This is the kind of problem that classically leads agencies to
50a
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 cquipment 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
controls), 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 replacement
activity and one that should be viewed as a physical change
that might constitute a major modification, when the
replacement of cquipment with identical 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 factors, 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.
* 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
(continued...)
S5la
We observed that, in some respects, an equipment
replacement cost threshold set at the NSPS reconstruction test
could be an appropriate approach for distinguishing 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 considerations
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 facility'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 appropriate 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 consistent 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 commonsense
interpretation of the regulations.
They also believed a 50-percent cutoff to be consistent with
triggers further evaluation, not the automatic application of
the NSPS to the source.
Ye ROPE MS ST RE LM Pikes a re ee oe
eo
S2a
-
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; significant changes to a process unit are
necessary before retrofit 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
replacement of an entire process unit over time without
installation of BACT. One commenter said a more appropriate
percentage for electricity producers is 0.1 to 1.0 percent.
Another commenter said the threshold should be 5 percent, |
percent, or even less, as shown by an NSR enforcement case
against the Tennessee Valley Authonty (TVA).
Another commenter believed the 50-percent number 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 commenter said
the cost threshold should be as high a percentage as possible,
SO as not to promote premature replacement 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 materials will
considerably exceed 5 years.
53a
We agree with those commenters who see a relationship
between establishing a threshold for equipment replacements
that we will treat as RMRR under the major 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 bnght line in the
sense that all projects that exceed 50 percent are automatically
considered as reconstruction. Rather, as discussed above, it is
a threshold intended to alert permitting authorities 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 qualifies for the ERP and
above which there is a need for a case-by-case determination.
The major difference between the ERP and the NSPS
reconstruction test is that the ERP deals with modifications,
not reconstructions. This difference weighs in favor of
establishing the equipment 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-percent
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 Company v. Reilly
(*WEPCO’) case, to the extent that it would not automatically
allow the activities performed there to constitute RMRR. See
54a
893 F.2d 901 (7th Cir. 1990). This court decision directly
addressed the question of what Ievel of “‘like kind"
replacement activities qualify as changes under the major
NSR program.
In the WEPCO case, the Court considered an activity
involving 5 coal fired units at WEPCO's Port Washington
plant. Each unit was rated at 80 megawatts of electrical output
capacity. The activity involved the replacement of numerous
major components. The information submitted by WEPCO
showed that the company intended to replace several
components that are essential 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 S.
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 integral components,
including replacement of the air heaters at units 1, 2, 3, and 4.
WEPCO also planned to renovate major mechanical and
electrical auxiliary systems and common plant support
facilities. WEPCO intended to perform the work over a 4-year
period, utilizing successive 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 generating station
that approached this activity in nature, scope and extent. The
Court determined, at our urging, that the changes did
constitute a ‘physical change" under the NSR rules.
In the case of a steam electric gencrating 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 equipment in determining the
55a
replacement cost of the WEPCO process units. WEPCO had
electrostatic precipitators 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 eléctric generating facility, we would likely treat
each boiler unit as belonging to a different process unit.
However, since all of the boilers underwent 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 approximately $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 million.? Thus, the capital cost
percentage for the replacement 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 percent. 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 maintenance, repair and
replacement activities for the electric utility sector.
“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.
56a
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 different industrial sectors (pulp and paper
mills, automobile manufacturing, natural gas transmission,
carbon black manufacturing, pharmaceutical manufacturing,
and petroleum refining). The case studies find that routine
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 activities as a percent of the
process unit mplacement value varies widely. We recognize
that the study addresses specific case examples from only a
part of regulated industry and that the project cost information
is derived from a limited inquiry of industry representatives.
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 industry are similar enough to replacement practices
in other industry that the 20 percent value determined for
utilities, 1s 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 mult factor RMRR test.
Two comment letters (from the Utility Air Regulatory
Group (UARG) and from the American Lung Association
(ALA), et al.) were particularly helpful in understanding the
issues associated with the electric utility sector. The UARG
57a
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 activities at an _ individual process unit
additionally include activities more minor than those
addressed in the document. The UUARG grouped repair and
replacement activities into projeci families; within each
project family were per-component costs ($/kW) for
numerous equipment 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 goups of activities should qualify for the ERP
and be excluded from major NSR without case-specific
review. We also believe that it is reasonably 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 activities
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 distinguishing between activities (and
aggregations of activities) that should not require case-specific
review to be excluded from major NSR and those that do.
The ALA commenters provided with their comments the
results of their analysis of projects at issue in an NSR
enforcement case against Tennessee Valley Authority (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 process unit basis, in year 2001
58a
dollars, from the publicly available record for the case. For all
but one of the challenged 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
maintenance allowance. As noted above, we concluded in our
2002 report to the President that the NSR program--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 problem. Thus, to the extent the activities
addressed by ALA qualify for the ERP, we now believe that
such activities, 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 ts 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 Itkely to be the case with respect to electric 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 equation is similar for industrial boilers.
Notably, those sectors represent a substantial fraction of the
emissions potentially subject to the NSR program. While the
relative 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 technical issues
associated with retrofitting air pollution controls factor
significantly into equipment replacement decisions.
59a
D. What Will Be the Basis of Applying the 20-Percent
Threshold?
In the proposal, we solicited comment on whether
impkmenting the ERP on a per-activity basis or on some
other reasoned basis, such as applying the percentage 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 activities)
basis. Two of the commenters cited longstanding NSR
precedent as the basis of their comments, while two other
commenters elied on NSPS precedent. Another commenter
thought the per-activity approach would be less confusing
than summing ativities over a fxed period of time. Other
commenters believed the equipment replacement threshold
should in fact be applied 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 occur prior to the time
activities are commenced. The major NSR program also
requires applicability to be determined, 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 proposal.
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
60a
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
qualify under the ERP. This situation is largely avoided by the
per-activity approach that we are establishing in today'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 applicability purposes.
Under our current policy of aggregation, two or more
replacement activities that occur at the same time are not
automatically considered a single activity 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 aggregated simply because they occur during the
same maintenance outage and on the same process unit.
Further inquiry into the nature of the activities and their
relationship 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 replacement
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 design parameters
of the process unit. We proposed that maximum heat input
and fuel consumption specifications for EUSGUs and
maximum material/fucl input specifications for other types of
process units are basic design parameters. We solicited
comments on limiting the eligibility of the ERP this way and
on the basic design parameters we proposed.
Several commenters expressed concerns with either the use
of these specific parameters, or the restriction of the regulated
community to only this set of design parameters. Other
6la
commer. ..ntered around an inconsistency in how EPA has
accounte. .or efficiency in the basic design parameter
safe guard. The commenters 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 approach to
handling activities intended to improve an affected process
unit's performance beyond its basic design parameters.
Commenters asserted that these actions would not fall within
the RMRR exclusion. Commenters from the gas transmission
industry concurred 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 parameters are
inconsistent with some industry conventions, and that we
should allow for industry-specific flexibility or specify
additional source category-specific parameters. For example,
for natural gas transmission compressor stations, commenters
explained that brake horsepower is the conventional design
capacity parameter. We received similar comments from other
industries, including cement and surface coaters, who objected
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 parameters 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
62a
several capacities that are a function of the type of crude that
is to be processed, and so a refiner may need to have a set of
basic design parameters for its crude towers. These situations
can be addressed by the source proposing alternative
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 demonstrated it is capable of
achieving, an electric generating unit should have the
flexibility to reference available credible information, such as
results of historic maximum capability tests or engineering
calculations. Results 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 tts “‘pre-activity" configuration, and
this can be compared to a “‘post-activity" heat input value.
Plant operators, where the specified 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 permit limits on amount of production, to
their reviewing authority. For process units having multiple
end products and raw materials, the owner or opcrator should
consider the primary product or primary raw material when
sclecting 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 parameters, as an alternative to using input-based
measures of maximum hourly fuel consumption rate and
63a
maximum hourly heat input. (We are clarifying from the
proposal that the correct parameter is maximum hourly heat
input, 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 accommodate
multiple fuel types: for coal fired units, owners or operators
should consider that the fuel consumption rate will vary
depending on the quality of the coal for a given heat input.
When establishing fuel consumption specifications in terms of
weight or volume, the minimum fuel quality based on BTU
content should be used for coak fired units.
Regardless of whether the source selects a basic design
parameter(s) specified for nor-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 operator 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
efficiency.
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 facility does not have
established design parameters, we believe 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 process unit immediately before the
activity. We have therefore established a 5-year look back
64a
period, consstent 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 desigii parameters 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 replaced. They argued that allowing for
small changes in basic design parameters would add greater
certainty to the ERP because unforescen 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 flexibility in defining basic design parameters for
process units. We were persuaded by commenters who
expressed concerns that the proposed approaches did not
adequately cncompass all affected operations and industry
sectors.
F. What Collection of Equipment Should Be Considered in
Applying the Equipment Replacement Provision and How
Should It Be Defined?
65a
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 accommodate 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 accepted 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 follows:
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 proposed five
industry-specific examples of how this definition of process
unit might be applied.
Some commenters compared the proposal's definition 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.”
66a
Three commenters asserted that pollution contro]
equipment should be included in the process unit definition.
One industry commenter said pollution control equipment is
often integral to the process and may produce an intermediate
product. One environmental commenter believed the proposed
rule was unclear as to whether pollution control equipment is
part of the process 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 emissions (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 Iimited to an emission unit.
Most commenters agreed that the general process unit
definition is sufficicnt. However, a number of commenters
suggested that we revise or eliminate some of the process unit
examples (that is, the industry categoryspecific definitions),
and others were concerned 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 severai industry
representatives 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 process units.
Another commenter suggested that, for electric 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
67a
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 produce “intermediates.”
We acknowledge that, without further explanation, the term
“intermediates” is susceptible 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 shipping 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 ecoat, 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 carefully 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 include all
pollution control equipment in the definition of process unit.
We feel that periodic replacement of components of emissions
control equipment should be encouraged and would rarely
lead to actual emissions increases. 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
68a
the control equipment is an integral component of the process
it should be included. Therefore, we are excluding associated
pollution control equipment from the definition of the
“process unit,” except for control equipment that serves a dual
purpose in the process. We know there are industries where
pollution control equipment 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 duakpurpose 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 nonmemitting 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 applied. The
examples are drawn from three selected industrial processing
cate gories--clectric utilities, refineries, and incinerators. We
proposed each of these detailed 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 recetving 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 facilities, petroleum
refineries; and incinerators in the final rule to provide as much
certainty as possible for facilities in these industries. As noted
above, these definitions also should be useful for those in
other industries who will apply our general definition because
69a
the industry specific definitions provide clear examples of
how we intend the general definition to be interpreted and
applied. During the public comment period on the proposal,
several commenters submitted additional industry specific
definitions and asked w 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 proposed rule. However,
provided below are the process unit definitions that
commenters submitted to us and that we think comport well
with the general definition of process unit promulgated today.
-- For a natural gas compressor station, each compressor
system, together with its proportionate share of common
support equipment is a separate process unit. This would
generally consist of the air inlet system, accessory drive
system, gas producer, fuel delivery system, cooling system,
lube system, power turbine, power shaft, control system,
starting system, exhaust system, and support facilities (e.g.,
auxiliary power generating equipment, heating/cooling
equipment, station and yard pipe, valves, etc.).
-- For a flat glass manufacturing plant, each production line
within a facility should be a separate process unit. Flat glass
production is completed on a continuous 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 production line consists of: the batch house, where
raw materials 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 annealed; and
the cutting and packaging equipment, where the glass is
removed from the line for sale to customers or for additional
processing later.
-- For a fiberglass production facility, each production line is
a separate process unit. Fiberglass is manufactured on a
continuous line where raw materials are melted at one end to
form a continuous strand of fiberglass 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
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melter, forchearth, 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 packaged or wound onto spools
for packaging for sale to customers or for additional later
processing.
-- For the production of precipitated amorphous silica, the
process unit includes, but is not limited to: raw material
storage and handling equipment used for mixing 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 procgss unit
includes all the product packaging, storage, handling, and
transfer equipment.
-- For a chemical manufacturing plant, the process unit would
include all the equipment assembled and connected by pipes
or ducts to process raw materials and to manufacture an
intended primary product and associated byproducts or
intermediates. The process unit can consist of more than one
unit operation. Chemical manufacturing process units may
include, but are not limited to: raw material storage, and air
oxidation reactors and their associated product separators and
recovery devices; reactors and their associated product
separators and recovery devices; distillation units and their
associated 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_ chemical
manufacturing process unit includes pumps, compressors,
agitators, pressure relicf devices, sampling connection
systems, openended valves or lines, valves, connectors,
Instrumentation systems, and process control or dual purpose
air pollution control devices or systems. For a chemical
manufacturing facility, there are several types of process
units: those that separate and distill raw material feedstocks;
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those that change molecular 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 emissions,
such as condensers, recovery devices, and oxidizers, 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 definitions 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 established under the definition
for a steam electric generating facility in today's rule, which
encompasses all equipment 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 electric utilities
having components shared by two or more process units is to
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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 nonemitting
equipment from the ERP. One commenter stated that
triggering the major NSR review process for maintenance
activities is an impediment to continuous improvement
projects for certain products and processes, even if actual
emissions decrease or only nonemitting units on the process
line are affected. Delays or postponements of project
maintenance work adversely affect the reliability, safety and
productivity of operations and cost control efforts. Another
commenter recommended that work at clearly nonemitting
units, specifically including foundation regrouting and repair
and frametop replacement, should be excluded from this rule.
Three commenters believed that nonmemitting units cannot
result in an increase of emissions and thus do not need to be
evaluated under major NSR.
A blanket exclusion for nonmemitting units could create
problems of interpretation because the term ‘‘nomemitting
components” is ambiguous when considering certain
components. Commenters asserted that identifying and
separating out nomemitting 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 fugitive emissions, the pipe
normally is not); and (2) structural supports for a process unit
(separating out the cost of supports fom an investment basis
throughout a facility will be difficult).
Another commenter believed it would be difficult to
separate the costs of emitting and nonemitting equipment
when determining the cost of the process unit. The commenter
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also believed t would be difficult to determine allocation of
shared equipment in the cost analysis.
We are concerned that, if owners or operators were allowed
to strip away all of the nonemitting components from a
process unit definition,. it would create significant ambiguity
in the rule and could result in significant variation in how the
rule is applied to similar sources in different jurisdictions. In
addition, we simply do not think it is practical or logical to
separate ‘‘noremitting" components of a process unit from
“‘emitting" components. We believe that integrated
manufacturing operations (that is, process units) typically
include both types of equiprnent. Separating emitting from
noremitting equipment would create an artificial divide that
contrasts sharply with physical and operational reality.
As noted above, however, we do believe that a distinction
should be made between nor-emitting equipment that is part
of a process unit and nonemitting equipment that is
functionally distinct from the process unit. For example, most
production facilities have buildings or space to house
administrative offices, such as offices for the plant accounting
staff. Such nonemitting 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 prevision, which
is the fixed capital cost that would be required to construct an
entirely new unit. We also discussed for the annual
maintenance, repair and replacement allowance using the
invested cost of a unit as the accounting basis. We proposed
that it would be appropriate to require that costs be calculated
using an approach along the lines set out in the EPA Air
Pollution Control Cost Manual (http://www.epa.gov/tin
/catc/dirl/c_allchs.pdf). Finally, we solicited comment on
whether the costs associated with the unanticipated shutdown
of equipment, due to component failure or catastrophic
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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. However, since we asked for comment
on the accounting approaches 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 replacement 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 associated with
unanticipated shutdown of equipment, we considered the
comments to apply to both the ERP and the annual
maintenance, repair and replacement allowance unless the
commenter specifically noted that the comment should not be
applied to bothof 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 1s 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.
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Many commenters supported an exclusion of costs for
unanticipated shutdowns and failures. They noted that strong
incentives exist to avoid fires, explosions and other
unantic ipated equipment failures because of the risk of human
injury and production interruptions and because of the
expense nvolved in restoring lost capacity. 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 partial or total loss of equipment. When such a
failure occurs 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 elements of the equipment
replacement test. Commenters asserted that replacing a
catastrophically failed turbine or engine is clearly ‘‘routine,"
since companies will always 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 considered as such,
particularly given that the proposed RMRR rule approaches
and the December 2002 final rules already have given the
industry a number of exclusion options. 7
We are allowing sources to determine the applicability of
today's rule on the basis of replacement value, with an option
for sources to notify their reviewing authority 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 obtained than
invested cost. Most manufacturers will have information
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concerning the replacement value of a process unit, because
such costs are commonly used when evaluating various
business scenarios relating to manufacturing costs. Also, use
of replacement value is consistent 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 inflationadjusted
Original investment, insurance 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 categories of
expenses in both the process unit replacement value and the
replacement activitics sought to be excluded. Therefore,
although the final rule does not mandate any particular
approach, we believe it is generally appropriate to calculate
costs using an approach similar to the clements of Total
Capital Investment as defined in the APCCM. While the
manual contains basic concepts that could be used to estimate
total capital investment at a process unit, it is geared toward
cost calculations 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 processes, not
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just emission control equipment. In certain cases, other
manuals might make more sense depending on_ their
circumstances.
Under the APCCM, total capital investment includes 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 equipment 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 foundations and
supports, erecting and handling the equipment, electrical
work, piping, insulation, and painting. Indirect installation
costs include such costs as: engineering 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 activity); startup and performance test costs;
and contingencies.
We believe there may be ment to the comments we
received advocating a categorical exclusion for unanticipated
shutdowns and failures of some kind. When such an outage
occurs, there may be a real urgency to restore the plant b
operation without forcing it to await the results of a permitting
action or applicability determination. In the past, we have
handled these situations with case-by-case consent orders;
however, even that approach may lead to unnecessary delays.
It may specifically be sensible to relaxing the 20 percent cost
threshold limitation for such events because it is unlikely that
sources would incur an outage to avoid controls. We did not
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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 maintained 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 projects covered by
today's rule. For example, companies generally have
comprehensive procedures by which funds are allocated to
both capital and maintenance expense 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. Moreover, additional records must be
maintained in industries 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
natural gas companies that are subject to FERC jurisdiction
must, unless they receive a waiver from the Commission,
comply with extensive accounting and record retention
requirements. They must keep financial information 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 companies. These uniform systems of accounts
include hundreds 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 according 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 companies must keep include, for
public utilitics and licensees, for example, generation and
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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), appraisals and .
valuations made of utility property or investments (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 services performed in connection with construction
of utility plant (6 years after the plant is retired or sold),
general 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 congressional authority. See
Bowen v. Georgetown Univ. Hosp., 488 U.S. 204, 208, 102 L.
Ed. 2d 493, 109 S. Ct. 468 (1988). The CAA contains no such
expressed grant of authority, and we do not intend by our
actions today to create retroactive applicability for today's
rule. 42 U.S.C. 7401 et seg. Today's rule applies only to
conduct that eccurs after the rule's effectjve date.
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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 determinations on major
modifications that result in control requirements in an NSR
permit that currently applics to asource 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 undertake 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 industrics. 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 SOQ2 are essentially the same under all scenarios,
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but that under today'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 represent 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 scenaric 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 op
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