Notably, Congress did not enact a new definition of " modification" in either the original 1977 Amendments or the " technical and conforming amendments." Rather, it incorporated the NSPS definition of " modification" by cross reference. See CAA sec. 169( 2)( C); CAA sec. 171( 4). The Conference Report to the bill adding the technical and conforming amendments { check if that is what the citation refers to} indicates that this was a deliberate choice. As the conferees explained, Congress " intended to conform the meaning of the term ` modification' to usage in other parts of the Act." 123 Cong. Rec. H11956 ( daily ed.)( Nov. 1, 1977). We have understood this to be a reference to our preexisting rules interpreting the term " modification" in the NSPS context. 49 Fed. Reg. 43211, 43213 ( 1984) { not sure what the document being cited is}; see also 43 Fed. Reg. 26388, 26394, 26397 ( June 19, 1978).

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

It is important to understand what we did   and did not   decide in those final 1980 NSR rules. What we did decide was that as a general proposition, we would better serve the purposes of the NSR program if we used " actual" rather than " potential" emissions as a baseline for determining whether an activity at a new source results in an emissions increase. What we did not decide was that the purposes of the NSR program never allow us to exclude from the definition of " change" any activity at a plant that may increase its actual emissions but does not increase its " potential" emissions. In particular, for example, we decided to retain the " hours of 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 19 operation" and " rate of production" exclusions even though such changes might result in increases in " actual" emissions because not having the provisions " would severely and unduly hamper the ability of any company to take advantage of favorable market conditions." Id. Similarly, we retained the exclusion for " routine maintenance, repair and replacement" even though it too can result in emission increases. Yet there is little doubt that increases in hours of operation and rates of production and RMRR arguably could be understood to fall within the statutory definition of modification, since increases in hours of operation and rates of production certainly may be argued to be changes in the " method of operation" of a plant, and RMRR certainly may be argued to be a " physical change" to a plant. On balance, however, we rejected that interpretation and determined that the definition of modification should not be read so broadly as to encompass hours of operation or production rate increases, at least so long as they are unrelated to a physical change.

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

At the same time, we believe it is also important to give equal weight to the converse proposition that existing plants should not have to install new control technology in the ordinary course of their operations. To require them to do so would fail to give full effect to Congress's decision that existing sources generally would not be required to obtain permits. It would also subject these plants and the consumers who rely on them to enormous dislocation and expense. That is why we believe we have rightly excluded increases in hours of operation and rates of production from the definition of " change." That is also why we believe we have rightly excluded " routine maintenance, repair and replacement" of existing plants from that definition. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 20 For similar reasons, we believe the final rule draws an appropriate line of demarcation between replacements that should not be treated as changes, and those as to which further consideration of the question is appropriate. Our rule states categorically that the replacement of components with identical or functionally equivalent components or components that does not exceed 20% of the replacement value of the process unit and does not change its basic design parameters is not a change and is within the RMRR exclusion. On the other hand, the rule contemplates case by case evaluation of identical or functionally equivalent equipment replacements that do not have these characteristics.

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

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

We do not believe it is the policy of the CAA to seek to promote emissions reductions by forcing new limits on hours of operation or rates of production of existing plants. We made that point clear in 1980 when we determined that we should retain the hours of operation and rate of production exclusions in the NSR context. To the contrary, as we said in promulgating the 1980 rules, Congress's decision to exclude existing sources because of the dislocation that covering them would cause can reasonably be understood as allowing those sources to increase hours of operation or production up to permitted levels as market conditions dictate. We note that this does not leave such activities outside the scope of the CAA: if a State concludes that resulting air quality considerations warrant revision to its SIP to add further limitations to a permit, it may exercise its authority to impose them, even in the absence of anything that constitutes a " change" to an existing plant. But we believe that our 1980 conclusion that increases in hours of operation or production at existing plants should not trigger NSR remains the better construction of the CAA. That being the case, we now believe that the fact that such increases may occur after 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 21 replacement of equipment that does not present an opportune time for the installation of controls should change that conclusion.

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

The final rule treats the activities excluded from the definition of " change" as a category of " routine maintenance, repair and replacement". We received many comments as to whether we can and should adopt the ERP as an expansion of the RMRR exclusion. We believe it is appropriate to expand the former RMRR exception. Before promulgation of the final rule, we interpreted the phrase " routine maintenance, repair and replacement" to be limited to the dayto day maintenance and repair of equipment and the replacement of relatively small parts of a plant that frequently require replacement. Today we are expanding the former definition of RMRR through this rulemaking to include other activities covered by the 20 percent cost threshold that are needed to facilitate the efficiency, reliability and safety of affected sources.

We believe it is appropriate to add one final note regarding the fact that this approach represents a change from the approach we have taken in the recent past. As the Supreme Court explained in Chevron, where it upheld a considerably more significant shift in the Agency's understanding of Title I of the CAA, to wit, the scope of the term " stationary source," there is nothing inherently suspect about a change of approach of this type by an expert Agency seeking to interpret a technical statutory term so as best to accommodate competing interests that Congress has charged the Agency with reconciling.

In section 101 of the CAA, Congress stated that Title I of the CAA has a dual purpose: " to protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population" ( emphasis added). This duality is reiterated in the statement of purpose of the PSD provisions and in the House Report accompanying the 1977 Amendments in connection with the non attainment provisions. See sec. 160( 1) ( purposes of the PSD program are, inter alia, " to protect public health and welfare from any actual or potential adverse effect" of air pollution and " to insure that economic growth will continue to occur consistent with the preservation of existing clean air resources"); H. R. Rep. No. 95 294, p. 211 ( The " two main purposes" of the non attainment permitting program are "( 1) 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 22 to allow reasonable economic growth to continue in an area while making reasonable further progress to assure attainment of the standards by a fixed date; and ( 2) to allow States greater flexibility for the former purpose than EPA's present interpretative regulations afford").

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

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

Our review of the EPA's varying interpretations of the word " source"  both before and after the 1977 Amendments  convinces us that the agency primarily responsible for administering this important legislation has consistently interpreted it flexibly  not in a sterile textual vacuum, but in the context of implementing policy decisions in a technical and complex arena. The fact that the agency has from time to time changed its interpretation of the term " source" does not, as respondents argue, lead us to conclude that no deference should be accorded the agency's interpretation of the statute. An initial agency interpretation is not instantly carved in stone. On the contrary, the agency, to engage in informed rulemaking, must consider varying interpretations and the wisdom of its policy on a continuing basis. Moreover, the fact that the agency has adopted different definitions in different contexts adds force to the argument that the definition itself is flexible, particularly since Congress has never indicated any disapproval of a flexible reading of the statute. 467 U. S. at 863 64. The Court went on to point out: In these cases the Administrator's interpretation represents a reasonable accommodation of manifestly competing interests and is entitled to deference: the regulatory scheme is technical and complex, the agency considered the matter in a detailed and reasoned fashion, and the decision involves reconciling conflicting policies. Congress intended to accommodate both interests, but did not do so itself on the level of specificity presented by these cases. . . . [ A] n agency to which Congress has delegated policymaking responsibilities may, within the limits of that delegation, properly rely upon the incumbent administration's views of wise policy to inform its judgments. While agencies are not directly accountable to the people, the Chief Executive is, and it is entirely appropriate for this political branch 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 23 of the Government to make such policy choices  resolving the competing interests which Congress itself either inadvertently did not resolve, or intentionally left to be resolved by the agency charged with the administration of the statute in light of everyday realities. . . . We hold that the EPA's definition of the term " source" is a permissible construction of the statute which seeks to accommodate progress in reducing air pollution with economic growth. ` The Regulations which the Administrator has adopted provide what the agency could allowably view as . . . [ an] effective reconciliation of these twofold ends. . . .' Id. at 865 66 ( citations and footnotes omitted). We believe the same reasoning applies here, and makes it entirely appropriate for us to adopt the equipment replacement provision today.

2. Why the final rule appropriately implements the Clean Air Act's definition of modification.

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

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

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

More to the point, chemical and pharmaceutical manufacturing operations often are designed, operated, and permitted as " multi function" facilities. These facilities have numerous pieces of equipment ( such as storage tanks, reactors, distillation columns, centrifuges, filter dryers, etc.) that can be reconfigured to accommodate a wide variety of products and operating conditions. When switching from product X to product Y, a plant can make substantial 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 24 " changes" in the types of equipment used, the processing conditions, and the raw materials, reagents, solvents, and other processing materials. In this case, the same basic equipment is used to make a wide variety of end products. But, as long as the facility is operated as designed and permitted, we would not consider ( and have not considered over the 20+ year life of the NSR program) such changes to be physical or operational " changes" for purposes of administering the NSR program.

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

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

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

The exclusions from NSR we adopted in 1980 also reflect the exercise of the Chevron discretion. Not only did we adopt the RMRR exclusion at that time, but we also adopted exclusions for increases in the hours of operation, fuel changes, and raw material changes. Only the RMRR exclusion arguably could be justified as de minimis. For example, by doubling hours 3  Equipment Replacement 5 As discussed below, our regulations provided a comparable exclusion from NSPS at the time of the 1977 Amendments that established the NSR program.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 25 of operation, a 500 tpy emitting plant could conceivably double its emissions. 5 The extra 500 tpy is far above any level EPA has ever thought justifiable as de minimis. E. g., 40 CFR 51.166( b)( 23)( i) ( definition of " significant"). Nor is it likely that these other exclusions could be based on some inherent power to adopt categorical exclusions from the CAA's commands. See Alabama Power Company v. Costle, 636 F. 2d 323, 359 ( D. C. Cir. 1980) (" categorical exemptions . . . are not favored"). Accordingly, these other exclusions must be justified as an exercise of Chevron discretion.

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

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

We recognize that the Agency previously has not specifically asserted that our interpretation of " change" and the exclusions from NSR are based on an exercise of Chevron discretion. In some instances, such as in a decision of the EAB, In re: Tennessee Valley Authority, 9 E. A. D. 357 ( EAB 2000), and in briefs in various enforcement related cases, we have previously interpreted " change" such that virtually all changes, even trivial ones, are encompassed by the CAA. Thus, we generally interpreted the exclusion as being limited to de 3  Equipment Replacement 6 We have taken positions in numerous court filings concerning the proper interpretation and usage of key statutory terms, such as " physical change" and " any physical change." These positions were based on permissible constructions of the statute of which the regulated community had fair notice, and correctly reflect the Agency's reasonable accommodation of the Clean Air Act's compelling policies in light of its experience at the time it adopted the RMRR exclusion in 1980. The Agency has sought, and has obtained, deference for its interpretations, and, notwithstanding the adoption of a revised interpretation of the statute and an expansion of the RMRR exclusion, the Agency shall continue to seek deference for those prior interpretations in ongoing enforcement litigation.

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

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 26 minimis circumstances. However, EPA does have the authority to interpret these key terms through rulemaking. Upon further consideration of the history of our actions, the statute, and its legislative history, EPA believes that a different view is permissible, and, for policy reasons discussed above, more appropriate. Therefore, we adopt this view prospectively in the final action. 6 The argument that our authority to exclude certain activities from being modifications under new source review can only be based on a de minimis rationale sometimes relies on the word " any" used to modify " physical change" and " change in the method of operation," pointing to the word " any" in the definition of " modification" as a signal from Congress that the term " change" must be interpreted as encompassing the broadest possible sense of the term. Such an interpretation is not compelled by the language and legislative history of the statute, as demonstrated by the manner in which we have interpreted the word " change" under both the NSPS and the NSR programs. 7 Nothing in the appellate case law directly disposes of this issue in a manner that prevents a new interpretation today. Two cases, Alabama Power and WEPCO, are relied on by some commenters to assert that EPA must interpret " modification" and " change" expansively and base all exclusions on a de minimis rationale. However, in Alabama Power, the issue before the court was the emissions increase portion of the definition of " modification." The court would have allowed de minimis increases in emissions to be exclude from requirements applying to " modifications" under new source review but not emissions increases equal to the thresholds set by statute for new construction. 636 F. 2d at 399  400. The court did not have before it the issue of what is a " change" and did not decide this issue. 3  Equipment Replacement 8We note that the U. S. District Court for the Southern District of Ohio recently issued an opinion in the Agency's NSR enforcement case against Ohio Edison. ( cite). The court determined, at our urging, that these projects did not qualify for the existing RMRR exclusion. The Agency asserted in that case that the then existing RMRR exclusion should be applied in a narrow fashion such that only de minimis projects should be excluded under that rule. The Agency sought and received from the court broad deference with regard to the Agency's interpretation of the CAA and the relevant EPA rules. EPA today is adopting prospectively a new interpretation of the CAA and is finalizing a revision to the RMRR regulation.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 27 In WEPCO, both parties advanced the view that the statute was clear on its face. EPA advanced the view that the term " modification" is necessarily broad, and that only de minimis departures are appropriate. WEPCO asserted that the plain meaning of the term " physical change" allowed for the five large scale rehabilitation projects it contemplated at its Port Washington plant. The WEPCO court held that the rehabilitation projects at issue were too large to reasonably conclude that they should not be treated as physical changes. The court's holding that the statute did not require the interpretation advanced by WEPCO does not deny EPA the discretion to decide to adopt a different, reasonable interpretation of the term " modification."

While the Court in WEPCO decided that the projects in that case were physical changes, the decision in WEPCO does not answer the question of where to draw the line between activities that should and should not be considered " changes." Nevertheless, contrary to the suggestions of several commenters, the projects at issue in WEPCO would have cost more than the 20 percent of replacement cost threshold selected today and, barring other applicable exclusions, would have been subject to case by case review in the PSD program. See section III. D above. 8 Some commenters argued that, to further the purposes of the statute, any interpretation must result in the eventual elimination of so called " grandfathered" facilities. We recognize the need to reduce emissions from many existing plants   regardless of whether they are " grandfathered" ( because they have never gone through NSR) or whether they have previously gone through NSR but can further reduce their emissions. EPA and States have issued regulations under a variety of statutory provisions to accomplish this goal in the past, and we will continue to do so in the future. We do not believe, however, the modification provisions of the CAA should be interpreted to ensure that all major facilities eventually trigger NSR. In fact, such an interpretation cannot be squared with the plain language of the CAA.

An existing source   whether grandfathered or not   triggers NSR only if it makes a physical or operational change that results in an emissions increase. Thus, a facility can conceivably continue to operate indefinitely without triggering NSR   making as many physical or operational changes as it desires   as long as the changes do not result in emissions increases. This outcome is an unavoidable consequence of the plain statutory language and is at odds with 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 28 the notion that Congress intended that every major source would eventually trigger NSR. Moreover, there is nothing in the legislative history of the 1977 Amendments, which created the NSR program, to suggest that Congress intended to force all then existing sources to go through NSR. To the extent that some members of Congress expressed that view during the debate over the 1990 amendments, such statements are not probative of what Congress meant in 1977. Central Bank of Denver, N. A. v. First Interstate Bank of Denver, N. A., 511 U. S. 164, 185  86 ( 1994), and cases cited.

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

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

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

Many specific comments were raised with respect to the ERP. These comments are addressed in the following sections. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 29 3.3 Basic Approach for Equipment Replacement Option We solicited comment on whether the ERP should be implemented on a component bycomponent basis or on some other reasoned basis, such as applying the percentage to components that are replaced collectively over a fixed period of time.

3.3.1 Support Proposed Option of Applying Percentage on a Component Basis Numerous industry commenters supported an ERP cost threshold on a component bycomponent basis, as opposed to supporting application of the threshold to an aggregation of ( not necessarily related) replacement activity costs over a fixed time period ( 902, 951, 1050, 1082, 1088, 1096, 1098, 1124, 1129, 1131, 1133, 1134, 1136, 1138, 1159, 1160, 1213, 1245, 1368, 1443, 1446, 1612, 1793, 1794, 1797, 1988).

It should be noted that many of the above enumerated commenters actually expressed their support in terms of a " project by project" basis, noting similarity to the NSPS reconstruction test. We generally grouped together comments supporting either a " component by component" or " project by project" basis, where it was apparent that the commenters were not in support of aggregating costs of ( not necessarily related) activities over a fixed period of time. The meaning of certain comments is ambiguous, given the different terms and commenters' different interpretations of the comparison to the NSPS reconstruction test, and so in some cases we grouped comments by relying on the context in which they were made. Therefore, some comments supporting a projectby project basis in which it was clear by the context that the commenter was referring to a continuous project without limitation to a specific period of time appear in section 3.3.3 ( support for other approach).

One industry commenter ( 1129) felt the need to add that their support on a component bycomponent basis was based on their assumption that the term " component" meant a complete piece of equipment. Another industry commenter ( 902) strongly supported the ERP if applied on a component by component basis or on the basis of aggregating activities on a project level, as opposed to over a one year time period.

Two of the industry commenters ( 1082, 1797) noted that the different components of an electric generating unit can clearly be identified and include such equipment as economizers, reheaters, condensers, waterwall tubes, and feedwater heaters. These commenters believed applying the ERP on a component by component basis would be easiest to administer and would offer fewer opportunities to manipulate the regulations. For example, if the ERP were applied to all replacements taking place within a set period of time ( such as one year), a company could simply spread its replacement projects out over a longer time period to avoid the cost restriction. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 30 One industry commenter ( 1129) believed that applying the percentage to components that are replaced collectively over a fixed period of time would only further complicate the NSR program and would create an administrative nightmare.

One electric industry commenter ( 951) stated that related projects should be combined for evaluation in some cases but unrelated projects should not be combined, even if undertaken in the same outage.

One industry commenter ( 1136) opposed aggregation of costs over any period of time because of the potential for burdensome recordkeeping requirements. The commenter believed that the performance specification safeguard is adequate and no aggregation of costs would then be necessary. The commenter did not believe that EPA's concern about disaggregating projects was realistic, because the utility industry would not remove a generating unit from service multiple times simply to disaggregate projects.

One industry commenter ( 1443) believed that the more activities are aggregated together for a cost determination, the more potential would exist for abuse and enforcement problems.

One industry commenter ( 1160) said it would seem logical and appropriate to aggregate equipment replacement costs if multiple pieces of equipment are replaced as part of the same project. For that reason, the commenter supports a component by component basis.

One State/ local commenter ( 1268) supported a component by component basis for the ERP in that they want it to apply to components rather than to entire pieces of emitting equipment or emissions units.

One industry commenter ( 1794) stated that it has always been recognized under NSPS that the 50 percent threshold applied to one time expenditures to repair a piece of equipment or component of a process, and not to a summation of costs of repairs which occurs over an extended period of time.

3.3.2 Support for Applying Percentage to Components Replaced Collectively Over a Fixed Period of Time One industry commenter ( 1077) supported an annual period for the equipment replacement option. The commenter believed component by component cost tracking would be difficult.

3.3.3 Support for Other Approach While it was not strictly within the intent of our solicitation, some industry commenters ( 920, 921, 1001, 1201, 1202) expressed support of a project basis ( without limitation to a fixed 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 31 period of time) as opposed to a component basis. Two industry commenters ( 920, 921) based their support of a project basis on an interpretation that the NSPS regulations allow a project to extend over a period of time. They provided the example of a superheater replacement project spread over a period of 3 years, with one third of the replacement accomplished in each year. Citing this example, the commenters stated that they did not support the concept of applying a percentage on a component by component basis, because the component by component approach would increase the work effort as well as resulting in frequent requests to the reviewing agency for approvals.

One industry commenter ( 1346) supported a process unit basis as opposed to a component basis. They support a process unit basis over a component basis for the reason that in situations where components are small in cost and size they believe the component would very rarely qualify because the source would always fail the fifty percent ( 50%) test.

One industry commenter ( 1000) suggested that if the final regulation provides a " budget" for equipment replacement, the budget should not be applied on either a component by component basis or an approach related to " components that are replaced collectively over a fixed period of time." The commenter believed that whatever approach is selected should allow the budget sufficient flexibility to reflect unusually maintenance intensive situations, such as for bagasse fired boilers.

Response:

In the proposal, we solicited comment on whether implementing the ERP on a per activity basis or on some other reasoned basis, such as applying the percentage to components that are replaced collectively over a fixed period of time, may be more workable.

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 the 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 32 time is that we would be restructuring the major NSR program to operate based on after the fact determinations. This raises the difficult question of what happens under this type of approach if you learn after commencement of an activity that it does not qualify under the ERP. This situation is largely avoided by the per activity approach that we are establishing in the final 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.

3.4 Definition of Process Unit Comment:

3.4.1 General Definition Several industry commenters ( 841, 896, 902, 951, 1050, 1066, 1078, 1083, 1090, 1091, 1096, 1100, 1124, 1132, 1138, 1159, 1212, 1292, 1465, 1866), a State/ local commenter ( 1240), and a Federal commenter ( 1101) supported the proposed general definition of " process unit," to apply to the equipment replacement cost percentage.

One industry commenter ( 1105) urged EPA to allow flexibility in defining " plant," in order to suit the specific facility and owner circumstances.

Several State/ local commenters ( 1199, 1268, 1361, 1471) said the proposed definition is too vague or broad. One State/ local commenter ( 1206) said the process unit definition is inherently inconsistent. Another State/ local commenter ( 1361) added that the proposed definition is inconsistent with title V of the CAA. Another State/ local commenter ( 1199) urged EPA to change the definition of process unit to limit the scope of what is allowed in the replacement provision, so that the source of emissions ( for example, an entire coal boiler) would not be allowed to be replaced without NSR. The replacement unit's scope should be limited to an emission unit.

One industry commenter ( 1160) found two objections to the proposed definition: ( 1) It is unnecessarily complicated to use a different definition than that which serves as the basis for the maintenance allowance, and for the NSR source definition as a whole; and ( 2) allocating shared 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 33 components and shared capacity would not work well. For these reasons, the commenter recommends using the entire facility as the basis for determining replacement costs.

As an alternative to the proposed definition of process unit, one industry commenter ( 1238) suggested that " process unit" be defined as " any collection of structures and/ or equipment that processes, assembles, applies, blends, or otherwise uses material inputs to produce or store a completed product."

One industry commenter ( 1124) supported the process unit definition on the condition that if NSR is triggered through it, it would be on an emissions unit basis.

Five industry commenters ( 1110, 1124, 1132, 1202, 1866) compared the RMRR proposal's definition of " process unit" ( toward producing or storing a completed product) to the definition that is used by section 112( g) and that appears in 40 CFR 63.41 ( toward producing or storing an intermediate or final product). One of the industry commenters ( 1866) supports the more narrow proposed definition. Two industry commenters ( 1124, 1202) said the RMRR rule's definition should be consistent with that used by section 112( g), broad enough to encompass interrelated operations. While supporting the RMRR proposal's definition, two industry commenters ( 1110, 1132) recommended that EPA provide regulatory flexibility by allowing a facility the option to choose which definition they will use.

Two industry commenters ( 841, 1090) believed the definition of " process unit" is sufficient for a determination without encumbering the rule with an exhaustive, but inevitably incomplete, list of process units throughout the industrial sector. Listing units may confuse rather than clarify.

One industry commenter ( 1100) generally supported the proposed definition of " process unit" ERP, but this commenter believed that " the delineation of a process unit should be made by regulated entity rather than explicitly defined in a rule."

Three industry commenters ( 1129, 1204, 1346) asserted that pollution control equipment should be included in the process unit definition. One industry commenter ( 1346) said pollution control equipment is often integral to the process and may produce an intermediate product. One environmental commenter ( 1150) believed the proposed rule was unclear as to whether pollution control equipment is part of the process unit.

3.4.2 Definition Applied to Specific Industry Categories One industry commenter ( 1137) said some of the examples that are intended to illuminate what a process unit is ( that is, the industry category specific definitions) need to be revised or eliminated. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 34 One State/ local commenter ( 1268) said the definition for pulp and paper mills is incorrect. One industry commenter ( 1465) did not support the detailed process unit definition for pulp and paper mills because the definition does not, and cannot, capture all possible elements and configurations. This commenter said the general process unit definition was sufficient.

One commenter ( 1124) supported the definition of a refinery process unit.

Two industry commenters ( 1138, 1212) provided a detailed description and figures illustrating a natural gas compressor station, and the commenters said each compressor system, together with its proportionate share of common support equipment, would logically be considered a separate process unit. Each engine/ compressor system operates independently. Another industry commenter ( 1367) said the proposed definition for natural gas pipeline compressor stations needed more clarification, or uncertainty regarding the scope and application of the equipment replacement exclusion would remain. This commenter explained that for the midstream segment of this industry, where internal combustion engines operate as components of compressor skid assemblies, and such assemblies can operate alone or in series, the final rule should include a narrative description of the natural gas compression process unit and cited 40 CFR 52.21( b)( 56)( ii). This industry commenter ( 1367) and another industry commenter ( 1096) offered the following clarification: " For facilities operating in the midstream segment of the natural gas industry, the compression process unit consists of those portions of a natural gas compressor station, natural as liquids extraction and production plant, and natural gas processing plant that contain the combination of equipment necessary to compress natural gas for the purpose of establishing and maintaining the process flow and delivery of such gas and liquids. Like kind and functionally equivalent replacement of equipment ( including, but not limited to, internal combustion engines) within the compression process shall qualify as RMRR."

Six industry commenters ( 902, 1082, 1129, 1368, 1399, 1629, 1794) supported the EPA's definition of process unit for a steam electric generating facility. One industry commenter ( 1629) recommended expanding the definition to include pumps, fans, cooling tower, and raw water and wastewater treatment systems. Another industry commenter ( 1794) stated that it was important not to exclude components which serve a dual purpose, such as low NOx burners. Referring to the description for pulverized coal fired facilities, one industry commenter ( 1129) said the ash handling equipment should be added and also said EPA should also clarify that administrative buildings ( including warehousing) are not included in the process unit. Two industry commenters ( 902, 1082) said equipment that does not contribute to the production of electricity should be excluded from the definition of process unit. The commenter gave the examples of water intake systems, cooling water towers, transformers and other downstream electrical equipment.

One industry commenter ( 1126) said the definition of " process unit" for the utility industry should be expanded to include the coal handling system, boiler, turbine, stack, and generator, as well as emission control equipment. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 35 One industry commenter ( 1204) said the incinerator process unit definition should include pollution control equipment, because the pollution control equipment is, like refuse pits, steam generators, and fans, integral to the unit operation at waste to energy facilities.

One industry commenter ( 1238) said the process unit for tire manufacturing facilities should be the entire plant, just like EPA appears to consider a cement plant to be a single process unit.

For the flat glass industry, an industry commenter ( 1066) provided a description of the equipment necessary to produce a finished primary glass product and said 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.

Fiberglass production was described by an industry commenter ( 1066). Fiberglass production is completed 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 melter, forehearth, and refiner, the raw materials are melted and refined. From the refiner, glass fibers are formed through controlled bushings. From the bushings, the continuous strand fibers are either directly cut or packaged or wound onto spools for packaging for sale to customers or for additional later processing.

An industry commenter ( 1066) said a process unit for production of precipitated amorphous silica 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 process unit includes all the product packaging, storage, handling, and transfer equipment.

Two industry commenters ( 1066, 1110) suggested a definition of a complex chemical manufacturing process unit. The definition of a chemical manufacturing process unit could be modeled after the definition of a process unit in the Hazardous Organics NESHAP, suggested one industry commenter ( 1066). A chemical manufacturing 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 36 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 relief devices, sampling connection systems, open ended valves or lines, valves, connectors, instrumentation systems, and control devices or systems. One industry commenter ( 1110) commented that for a chemical manufacturing facility, there are several types of process units: those that separate and distill raw material feedstocks; 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.

The definition of a process unit in coatings manufacturing could be modeled after the Miscellaneous Organics NESHAP, suggested an industry commenter ( 1066). A coatings manufacturing process would include all equipment that collectively functions to product a product or isolated intermediate. It consists of one or more unit operations. A coatings process unit includes any, all, or a combination of raw material storage, reaction, recovery, separation, purification, blending or other activity, operation, manufacture, or treatment. Cleaning operations are part of the process. Nondedicated solvent recovery operations located within a contiguous area within the affected source are considered a single process. A storage tank that is used to accumulate used solvent from multiple batches of a single process for purposes of solvent recovery does not represent the end of the process. Nondedicated formulation operations ( not including mixing, as defined) occurring within a contiguous area are considered a single process that is used to formulate numerous materials and/ or products.

Several sugar industry commenters ( 920, 921, 1123) gave two possible definitions of process unit for their industry. These commenters ( 920, 921, 1123) emphasized that the process unit should cover all of the regulated air emission points at the plant.

For a sugar mill, there are two types of process units. One type of process unit includes all of the portions of the plant that contribute directly to the production of steam. This process unit includes the combination of systems from the bagasse handling system through to the emission stack, including the bagasse handling equipment, feedwater system, combustion air system, boiler, burners, air preheaters, superheaters, flues, stack, and fuel oil storage and piping system. The second type of process unit includes those portions of the plant that contribute directly to the production of refined sugar from raw sugar and the associated packaging and shipping operations. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 37

For a sugar mill, the process unit would consist of all regulated air emission sources at the plant. Excluded air emission sources are all unregulated and insignificant emission units as identified in the facility's title V operating permit.

One industry commenter ( 840) said underground mining equipment should be excluded from the industry specific lists of process units because it contributes very little to ambient air emissions, is heavily regulated with regard to respirable dust, and is a separate process unit.

One industry commenter ( 1129) agreed with EPA's proposal to proportionately allocate, based on capacity, those components shared by two or more process units. For electric utilities, another industry commenter ( 1136) supported allocating the cost of shared equipment based on a pro rata share of megawatts produced.

One industry commenter ( 840) believed underground mining equipment should be exempt from NSR, because it contributes very little to ambient air emissions, is heavily regulated by MSHA with regard to respirable dust, and is a separate process unit that provides ore to this commenter's entire facility ( six surface process units).

Response:

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. The examples were drawn from five selected industry categories   electric utilities, refineries, cement manufacturers, pulp and paper producers, and incinerators.

We agree with the commenters who favor using a process unit as the basis for administering the ERP and including a definition of process unit in the final rule. We also agree with the commenters who suggested that the definition of process unit should be consistent with 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 38 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 the final 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 e coat, primer surface, or top coat operation, to be intermediates in the context of our final rule definition for process unit. Our primary goal in defining this term " process unit" is to encompass integrated manufacturing operations that produce a completed product, and those operations that produce an intermediate as the product of the process unit. In the case of the automotive paint shop, series of coating steps together comprise the 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. See 67 FR 80186. We do agree, however, that where 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 dual purpose component. In such cases, to provide clarity and simplify administration of the ERP, our rule provides that dual purpose equipment should be considered part of the process. We are also clarifying in the final rule that administrative buildings ( including warehousing) are not to be included in the process unit, but other types of nonemitting 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 categories   electric 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 39 definitions for two other industries   pulp and paper and cement producers   we have decided not to finalize those definitions after receiving comments from the relevant industry trade association asserting that the definitions did not, and could not, capture all of their industry's configurations and they believed the generic process unit definition was sufficient for their industry. Because of the centrality of the " process unit" concept to the usefulness of the ERP, it is our desire to include specific definitions for steam electric generating 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 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 us to put them in the final rule. We are not finalizing these suggested definitions at this time, because we did not include them in the 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 in the final rule.

° 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 melter, forehearth, and refiner, the raw materials are melted and refined. From the refiner, glass fibers are formed through controlled bushings. From the bushings, the continuous strand fibers are either directly cut or packaged or wound onto spools for packaging for sale to customers or for additional later processing. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 40 ° 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 process 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 relief devices, sampling connection systems, open ended valves or lines, valves, connectors, instrumentation systems, and control devices or systems. For a chemical manufacturing facility, there are several types of process units: those that separate and distill raw material feedstocks; 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 definition proposal were necessarily inconsistent with our general definition of process unit, we had trouble including them in the final preamble in the absence of responding to concerns and questions that our staff had over these new 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 41 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 the final 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 allocate the cost of shared equipment based on the pro rata share of megawatts produced by each process unit.

3.5 Fixed Capital Cost Percentage Comment:

3.5.1 General Support for Proposal Many industry commenters ( 636, 840, 841, 865, 896, 900, 902, 910, 941, 942, 951, 1013, 1050, 1066, 1077, 1078, 1079, 1082, 1083, 1091, 1096, 1099, 1105, 1110, 1129, 1132, 1133, 1136, 1138, 1149, 1201, 1202, 1204, 1237, 1238, 1246, 1265, 1292, 1301, 1368, 1441, 1446, 1453, 1463, 1465, 1620, 1629, 1792, 1793, 1794, 1799, 1866) supported the proposed threshold of 50 percent of replacement cost as the upper limit on equipment replacement. Two university commenters ( 901, 1477) and a legislative commenter ( 1411) also supported this 50 percent cutoff.

One industry commenter ( 1129) said the proposal is consistent with existing regulatory requirements and would accord the flexibility originally intended under the CAA for routine maintenance projects, while at the same time assuring that major, non routine projects remain subject to NSR applicability review. Another industry commenter ( 1066) believed the proposed approach is consistent with a commonsense interpretation of the regulations and is undoubtedly how many have already interpreted the requirements.

Several industry commenters ( 896, 951, 1110, 1132, 1265, 1453, 1465, 1793) believed a 50 percent cutoff to be consistent with reconstruction definitions used in many NSPS and NESHAP regulations. Two industry commenters ( 1465, 1793) 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.

One industry commenter ( 1866) added that EPA's concerns about an unbounded component replacement provision may be unfounded, because technological advances and obsolescence make it unlikely that replacement projects would eventually replace an entire source. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 42 This commenter said the NSPS reconstruction test, which is discussed as a possible approach to limit the ERP, has a long regulatory history and seems appropriate for differentiating between projects that are routine replacement and projects that are tantamount to creating a new process unit. Another industry commenter ( 951) believed there is no reason to use a lower cutoff.

One industry commenter ( 1204) only supported the 50 percent replacement value threshold if there are not mitigating factors. If a specific, unique, functionally equivalent replacement exceeds the threshold, there should be an available regulatory process to determine the actual environmental effects of the change. If the replacement can be shown to have no impact on emissions and is part of a non emitting portion of the unit, it should be viewed as an exempt replacement. Another industry commenter ( 1078) said the 50 percent cost threshold is reasonable, if it includes only the cost of the component itself and there is no aggregation of independent replacements. One industry commenter ( 1083) said a straightforward methodology for calculating costs is needed. One industry commenter ( 902) made clear that the commenter's support of the 50 percent cost threshold relies on an assurance that NSR applicability will not automatically be triggered when the capital cost exceeds the 50 percent threshold, as long as there is no increase in emissions from the RMRR activity.

One industry commenter ( 1078) said the ERP cost threshold test should be essentially equivalent to the NSPS reconstruction test, based on the proposed definition of process unit.

Two industry commenters ( 1082, 1797) supported the 50 percent replacement value threshold, if replacement project costs are aggregated over a one year period. Another industry commenter ( 1446) supported the 50 percent replacement value threshold if applied to a collection of replacement activities. If instead the percentage is applied on a per component basis, these commenters ( 1082, 1446, 1797) recommended a threshold of 5 percent for the electric generating industry. Two of the commenters ( 1082, 1446) stated that the 5 percent threshold is based on an evaluation of some of the commenters' large routine replacement projects that electric generating units undertake: turbine blades; sections of the waterwall tubes; reheaters; superheaters; and economizers.

3.5.2 Opposition to Proposed Replacement Value Threshold Some commenters opposed any percentage; other commenters believed a 50 percent ERP cost threshold was too high.

Many State/ local commenters ( 946, 1146, 1199, 1206, 1268, 1270, 1361, 1448, 1471, 1622), two industry commenters ( 797, 898), an environmental commenter ( 1150), and two citizen commenters ( 784, 850) opposed the 50 percent replacement value threshold. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 43 Three State/ local commenters ( 1199, 1471, 1622) believed the capital replacement percentage should be much less than 50 percent. One State/ local commenter ( 1622) preferred that the total replacement cost for a single process unit over any period of 5 consecutive years should not exceed 50 percent of the replacement cost of the process unit. One State/ local commenter ( 1270) said the replacement percentage should not be higher than 25 percent. One State/ local commenter ( 1146) suggested a replacement percentage of 5 to 10 percent if the ERP moves forward, to reduce the risk of replacement of an entire unit over time without installation of BACT. One citizen commenter said a more appropriate percentage for electricity producers is 0.1 to 1.0 percent. One State/ local commenter ( 1361) said the threshold should be 5 percent, 1 percent, or even less, as shown by the Tennessee Valley Authority ( TVA) case. One State/ local commenter ( 1268) suggested using a de minimis value, rather than 50 percent, if the ERP is included in the final rule. This commenter said an analogy to NSPS reconstruction is misplaced, because NSPS includes an emissions test as well as the cost threshold.

One State/ local commenter ( 1206) believed the 50 percent number has no practical effect in protecting public health and the environment, and the commenter is not aware of any projects that have exceeded 50 percent in cost. Another State/ local commenter ( 1448) was concerned that, whatever percentage is used for the ERP cost threshold, sources could abuse the ERP by either adding a new process unit or replacing an entire process unit piecemeal over several years. One State/ local commenter stated generally that the cost thresholds were too permissive, but this commenter did not provide any alternatives.

One industry commenter ( 898) believed that EPA did not establish a reasoned basis to support 50 percent as the proper ERP cost threshold. The commenter stated that EPA should have used the WEPCO four factor test that considers the nature and extent, purpose, cost, and frequency of activities in order to establish that the given percentage has any connection to the concept of routine, because otherwise the rule is arbitrary and capricious. The commenter further added that if EPA fails to articulate the ERP cost threshold ( and to articulate six other issues listed by the commenter) before promulgating RMRR rules, the EPA will run afoul of section 553 of the Administrative Procedure Act (" APA").

While opposed to the ERP in general, one industry commenter ( 797) said the cost threshold for the ERP should be as high a percentage as possible, so as not to promote premature replacement of equipment that is repairable.

The environmental commenter ( 1150) opposed the equipment replacement approach in general but added that if EPA is to adopt a cost based exemption, the threshold should be much lower than 50 percent.

One citizen commenter ( 850) said the 50 percent number from the NSPS is archaic and environmentally nonprotective. This commenter suggested that the ERP cost threshold instead be 3  Equipment Replacement 9 In the proposal, it was incorrectly stated that applicability of the NSPS was triggered if a project exceeded 50 percent of the cost of replacing the affected facility. As stated in this notice, if an activity exceeds this cost threshold, that only triggers further evaluation, not the automatic application of the NSPS to the source.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 44 24 percent. The commenter believed this lower percentage is appropriate because the lifetime of high cost materials will considerably exceed 5 years.

Response:

The purpose of the cost based limitation 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. For the reasons explained below, we have decided to establish a 20 percent cost threshold under the ERP.

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 equipment 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. 9 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 45 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.

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 bright 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 893 F. 2d 901 ( 7th Cir. 1990). This court decision directly addressed the question of what level 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 3  Equipment Replacement 10 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.

Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 46 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 5. According to WEPCO, these steam drums were a type of " header" for the collection and distribution of steam and/ or water within the boilers. WEPCO viewed their replacement as necessary to continue operation of the units in a safe condition. In addition, at each of the emissions units, WEPCO planned to repair or replace several other 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 generating facility, the process unit definition provided in the final 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 cost of pollution control equipment in determining the 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 the final definition of steam electric generating facility, we would likely treat each boiler unit as belonging to a different process unit. However, since all of the boilers 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. 10 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. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 47 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. 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 replacement value varies widely. We recognize that the Abt Study addressing 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 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 Abt 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, is appropriate for industry as a whole. This data indicates that most typical replacement activities will fall within the 20 percent threshold. At the same time, the data indicates that some major replacement activities likely will cross the 20 percent threshold and will require a case by case evaluation under the multi factor RMRR test.

Two comment letters ( from the Utility Air 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 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 UARG grouped repair and replacement activities into project 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 48 types of individual activities and groups 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 casespecific 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 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 the final 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. However, we continue to assert that TVA was in violation of applicable law and regulations for their past actions.

Comment:

3.5.3 Whether to Set Different Fixed Capital Cost Percentages for Different Industry Sectors Several sugar industry commenters ( 920, 921, 1123) believed an ERP cost threshold of 50 percent could be appropriate but preferred that EPA establish industry specific thresholds. However, these commenters stated that they did not have adequate data to suggest a specific percentage for their industry.

One State/ local commenter ( 1270) suggested that industry specific considerations should be taken into account in setting the cost threshold. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 49 Two industry commenters ( 1110, 1132) favored applying the 50 percent cutoff to all industries because applying other percentages on an industry or process type basis would unnecessarily complicate the replacement analysis.

One industry commenter ( 897) said the appropriate threshold percentages should be based on industrial standards but added that a facility with special circumstances should have the regulatory means to request an alternate method of calculating this threshold.

3.5.4 Information Provided on RMRR Activities and Costs in Specific Industry Sectors For natural gas transmission, one industry commenter ( 1138) performed an analysis of maintenance and repair costs at eighteen compressor stations under the proposed ERP framework ( see pp. 11 14, 51 52). This commenter's analysis concluded that the proposed 50 percent cost threshold on a process unit basis is appropriate for the natural gas transport industry, if replacement of non emitting units and catastrophically failed units is excluded. Two natural gas industry commenters ( 1096, 1138) asserted that the rule should encourage the practice of offsite maintenance. Both offsite and onsite maintenance should be counted against the 50 percent cost threshold. One of the industry commenters ( 1138) explained that the gas turbines ( internal combustion engines) used at natural gas compressor stations have been designed for offsite maintenance and often cannot be cost effectively maintained onsite. Instead, the manufacturer " changes out" the turbine by removing the components in need of maintenance ( typically the gas producer and power train) and replaces them with components from the manufacturer's inventory. Such change outs take place every 30,000 to 50,000 hours of turbine operation, or every 3 to 5 years. The national pipeline industry undertakes several hundred turbine change outs per year. A change out takes 2 days, where onsite maintenance of a turbine would take 6 weeks and would also increase the overall cost of gas transmission by increasing the need for backup compressor capacity. Further, offsite maintenance allows for verification in test cells that the changed out turbine components meet emission standards before they are returned to the fleet.

Several sugar industry commenters ( 920, 921, 1000, 1123) believed their industry should have a higher replacement percentage than other steam generating units due to the heat and corrosive compounds. The commenters explained that their bagasse fuel ( from sugar cane) has a high sand content, which is extremely corrosive. Moreover, the boilers are idle for several months per year, at which time they are subject to humidity and rain, leading to corrosion of tubes, components, and equipment. One of these commenters ( 1000) noted that boiler tubes, air heater tubes, superheater tubes, refractory, economizer tubes, and induced fan drafts routinely require maintenance or partial replacement. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 50 The environmental commenter ( 1150) asserted that the total project expenditures to upgrade each of the three boilers at the Alcoa Sandow Betterment Project were less than 15 percent of the capital cost of a new unit.

The environmental commenter ( 1150) provided extensive information documenting RMRR costs for utilities, primarily from various court cases and enforcement actions. The commenter ( 1150) noted that the following were not considered routine replacement in court cases: replacement of cyclones; replacement of lower furnace walls ( including headers and footers); replacement of waterwall tubes in front, rear and sidewalls of both furnaces; replacement of burner tube panels and superheater platen elements; replacements with redesigned components.

The environmental commenter ( 1150) stated that the following equipment replacement activities would not increase emissions and would therefore be exempt from major NSR regardless of a routine maintenance exemption: replacement of a pump associated with a distillation column; replacement of a pump associated with a distillation column; replacement of worn out pipes in a chemical process plant; and replacement of controllers at a series of batch digesters.

The environmental commenter ( 1150) stated that by the year 2000, almost 75 percent of power plants were more than 20 years old. The commenter noted that at 20 25 years, various major components of an electric generating unit wear out, a condition referred to as " component end of life." Absent replacement of the components, the decline continues after 20 25 years. The environmental commenter ( 1150) cited the component replacement schedule from Babcock and Wilcox's reference, Steam, Its Generation and Use.

One industry commenter ( 1213) has compiled data from DOE to produce curves that an electric utility owner/ operator could use to select replacement cost for a source based on size and fuel type. ( See Document ID 1215 in the docket.) This commenter also provided a paper describing major repair and replacement projects that are undertaken at utility generating stations in order to keep them operational. ( See Document ID 1221 in the docket.)

One industry commenter ( 1621) noted that re bricking of ovens, furnaces, and some boilers is a periodic maintenance requirement that is necessary to assure good product quality, process control, and fuel efficiency. Minor re bricking may occur on a yearly or bi yearly basis; major rebricking projects may be required every 10 to 15 years.

Response:

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. Information about the electric utility sector persuades us that we have established the right ERP threshold for this sector. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 51 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 replacement value varies widely. We recognize that the Abt Study addressing 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 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 Abt 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, is appropriate for industry as a whole. This data indicates that most typical replacement activities will fall within the 20 percent threshold. At the same time, the data indicates that some major replacement activities likely will cross the 20 percent threshold and will require a case by case evaluation under the multi factor RMRR test.

Two comment letters ( from the Utility Air 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 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 UARG grouped repair and replacement activities into project 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 groups 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 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 52 distinguishing between activities ( and aggregations of activities) that should not require casespecific 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 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 the final 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. However, we continue to assert that TVA was in violation of applicable law and regulations for their past actions.

3.6 Basic Design Parameters Comment:

3.6.1 Generally Supportive Comments <IP_ADDRESS> EUSGUs Several industry commenters ( 1099, 1136, 1213, 1629, 1792) supported the use of maximum heat input and fuel consumption as the appropriate design parameters for electric generating units. One industry commenter ( 1629) added that the final rule should clarify that the correct parameter is maximum hourly heat input. Two industry commenters ( 1099, 1213) requested that EPA provide sufficient flexibility in how the parameters are determined, and one industry commenter ( 1792) requested sufficient flexibility to account for problems that may have been corrected to obtain the true design rate of a unit.

One industry commenter ( 1794) stated that it may not be necessary to specify both the heat input and fuel consumption as design parameters for EUSGUs because fuel consumption is essentially duplicative of the heat input value. Also, the fuel consumption rate for coal fired units will vary depending on the quality of the coal for a given heat input. If EPA decides to retain fuel consumption as a design specification, then the industry commenter recommended that the minimum fuel quality based on Btu content should be used for coal fired units. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 53 One industry commenter ( 1078) stated that the use of the basic design parameters is a reasonable safeguard, but EPA should not include " fuel specifications" for EUSGUs. It is too vague and could encompass almost anything. EPA should either specify fuel consumption rates ( which is redundant with maximum heat input), or fuel type ( such as coal or oil).

One industry commenter ( 1129) said the primary design parameter for EUSGUs is the manufacturer's maximum designed steam flow rating or the maximum historical steam flow, whichever is higher.

One industry commenter ( 1794) recommended that the final rule clarify that the owner can establish the basic design for maximum heat input of an electric generating unit by referencing available credible information, including results of historic maximum capability tests, operating design information, or engineering calculations which may establish the heat input value the unit has demonstrated it is capable of achieving. 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 unit's maximum heat input. A review of such data or other available operational data or design information can reveal the heat input which the unit is capable of achieving in its " pre change" configuration and this can be compared to a " post change" heat input value. This should be a case by case analysis and demonstration, not a simplistic formulaic test.

According to one industry commenter ( 797), replacement of power turbines and combustion units is called for every 30,000 to 50,000 hours of operation. Unless components are upgraded during these replacements, the heat input remains the same and so does the emissions rate. The commenter believes that such replacement should be considered routine maintenance.

<IP_ADDRESS> Miscellaneous general comments on basic design parameters Several industry commenters ( 951, 1066, 1096, 1099, 1112) agreed with the EPA's use of maximum heat input and fuel specifications for basic design parameters. One industry commenter ( 1112) recommended that EPA provide sufficient flexibility for plant owners to determine how basic design parameters are determined.

One industry commenter ( 1100) supported the concept of using basic design parameters within the equipment replacement approach, but recommended further clarification be provided for efficiency improvements. The industry commenter recommended that an equipment replacement that improves a process unit's efficiency by enabling the unit to return to its original design parameters be considered RMRR even if current actual emissions increase as a result. For example, if boiler tubes or refractory are replaced on a boiler, these activities should be RMRR since they return the unit to its original design parameters and improve the unit's efficiency. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 54 Several industry commenters ( 920, 921, 1000, 1123) supported maximum design heat input as the basic design parameter for boilers. These industry commenters ( 920, 921, 1000, 1123) noted that this parameter could also be expressed in terms of maximum design steam production rate, which is how Florida has permitted their bagasse boilers.

One industry commenter ( 1136) supported EPA's use of the term " process unit" to determine if there is a change in a design parameter.

One industry commenter ( 941) said EPA cannot practicably disallow changes in fuel or raw material input specifications for all complex industrial sources. Even where manufacturer's design specifications exist for a unit, they serve to define the unit's guaranteed maximum capacity rather than its actual maximum capacity. Many units routinely and properly operate above their design specifications.

<IP_ADDRESS> Look back period for determining basic design parameters Several industry commenters ( 941, 1050, 1099, 1112, 1123, 1368, 1629) recommended that a reasonable look back period should be used for establishing the pre change values for basic design parameters, not the condition of the process unit immediately before the change. The industry commenters suggested a 5 year look back period, consistent with that for the NSPS hourly emissions increase test.

<IP_ADDRESS> De minimis changes in emissions or basic design parameters One industry commenter ( 941) stated that because the results of RMRR are not always predictable in advance, the final rule should provide that unanticipated and unintended small increases in hourly emission do not disqualify a project from the equipment replacement exclusion.

Two industry commenter ( 858, 896) and one university commenter ( 901) requested that a de minimis change in design parameters be allowed when making equipment changes because some effects resulting from the change may not be apparent before the change is made. One industry commenter ( 896) added that such a change be allowed as long as emissions do not increase above maximum design levels. The university commenter added that such a change be allowed as long as emissions do increase above the permitted maximum hourly emission rates.

<IP_ADDRESS> Develop basic design parameters for specific industries Two industry commenters ( 1138, 1446) supported the basic design parameter approach, but believed that the definition of basic design parameter for non utilities and non fossil fuel burning sources in the proposed rule is too rigid and is inconsistent with the natural gas transport industry conventions. One industry commenter ( 1138) urged EPA to modify the definition to 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 55 allow for industry specific flexibility or specify additional source category specific parameters. For the natural gas transmission compressor stations, the commenter suggested using brake horsepower ( bhp) as the conventional design capacity parameter. All regulated natural gas transmission compressor stations maintain consistent, accurate, and certified records of process unit bhp capacity.

One State/ local commenter ( 1270) stated that while it would take considerable time and effort to develop basic design parameters, there is no other way to implement the proposed option since no two processes are the same.

3.6.2 Opposition to Basic Design Parameters <IP_ADDRESS> General opposition to basic design approach An industrial commenter ( 636) noted that in many cases, the boiler design fuel specification is fabricated to satisfy certain boiler design criteria with inherent operating latitude, and there is no actual fuel which can meet those specifications. Fuel changes should not be considered replacements.

One industry commenter ( 902) was strongly opposed to fully defining specific design parameters in the regulation because published design standards in the rule would quickly become outdated, thereby requiring frequent revisions in the regulation.

One industry commenter ( 1301) stated that requiring equipment replacements to not alter the basic design parameters of a process unit is a nebulous requirement that EPA should carefully consider before going final. For the petroleum refining industry, the commenter was particularly concerned that the concept of material input specifications is a nominal one that has practical value only in the design phase but not in the operations phase.

One industry commenter ( 909) believed that activities intended to improve an affected unit's performance, beyond what would otherwise be reasonably achieved by the equipment absent a specific activity, clearly qualify as actions that extend beyond the reasonable definition of RMRR and should instead be subject to the full scope of NSR. The commenter further stated that the recent revisions to the NSR regulations ( 67 FR 80186) allow for reasonable actions to improve unit performance.

One industry commenter ( 942) opposed the basic design parameter constraints, stating that they would exclude projects that result in efficiency improvements.

One State/ local commenter ( 1012) said that RMRR should not be allowed for changes in basic design parameters. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 56 An industry commenter ( 1238) urged EPA to eliminate the requirement that the new equipment not alter the basic design parameters of the unit. The commenter expressed concern that regulators may use the provision to bar changes that carry out the same function but do so through an improved design from qualifying for RMRR exclusion.

<IP_ADDRESS> Opposition to input parameters; preference for design specifications or emission rate Several industry commenters ( 814, 941, 1013, 1114, 1133, 1204, 1237, 1463) and two university commenters ( 901, 1477) noted that many pieces of equipment are not rated or specified based on " material input" or " fuel input." Instead, EPA should also define " design specifications" because many pieces of equipment are purchased based on their capacity or output. Therefore, EPA should rely on the manufacturer's documented design information to identifying the basic design parameters for any piece of equipment rather than attempting to specify it in the rule. Several of the industry commenters ( 941, 1013, 1114, 1133, 1237) said that a determination should be based on maximum hourly emissions before and after the change, and one industry commenter ( 1463) recommended using annual emissions. One industry commenter ( 941) added that this design based approach is already a condition of the RMRR allowance approach and has been used in other long established CAA programs like NSPS.

One industry commenter ( 1110) believed that the proposal suggests that basic design parameters are limited to the maximum fuel or material input specifications for non utility process units. Another industry commenter ( 1132) urged EPA to remove the basic design parameter requirements in light of other safeguards in the proposed rule. Both industry commenters recommended that an increase in material input should be allowed as long as there is no increase in emissions above maximum achievable levels. Therefore, the safeguard that reads " does not alter the basic design parameters" should be replaced with " should not increase the maximum design emission rate."

In reference to the cement industry, one industry commenter ( 1283) stated that EPA should clarify the definition of basic design parameters. The current definition is ambiguous because maximum fuel and material input specifications have no relevance in this industry. The industry commenter recommended that maximum clinker generation capacity of the kiln system be used as the basic design parameter for the cement industry.

For surface coating operations, one industry commenter ( 1202) stated that there are problems with use of paint input as a basic design parameter. Any replacement of paint guns could affect paint usage and would be viewed as a basic design parameter change. Because maximum input varies with the paint type and characteristics, material input does not represent a basic design parameter for surface coating operations. The industry commenter recommended using transfer 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 57 efficiency and quality of paint job, not material input rates, for the basic design parameters for automobile surface coating.

One State/ local commenter ( 1443) believes that defining the term " basic design parameters" solely based upon maximum heat input and fuel consumption specifications, or maximum material/ fuel input specifications, will, under the guise of " replacement," allow a wide range of changes that should be considered NSR modifications. There are many changes at air emission sources that do not alter maximum heat input and fuel consumption specifications, or maximum material/ fuel input specifications, yet involve significant modifications that are unrelated to routine replacement. The commenter suggested that any equipment modification resulting in a change in the equipment description in the permit should be subject to NSR.

An environmental commenter ( 1150) believed the basic design parameters of maximum heat input and fuel consumption are too narrow and will be difficult to administer. The environmental commenter also believed that changes in heat input or fuel consumption due to equipment replacement are difficult to evaluate. For example, some utilities have claimed that nameplate capacity only represented the manufacturer's guarantee and not the maximum capacity of the unit, thereby justifying an increase to a higher heat input rate. The commenter believed that many other basic design parameters should be included, but did not list these specifically. If EPA decides to retain the ERP, the commenter urged EPA to exclude equipment replacement that changes the basic design parameters of the process unit or results in an increase of total annual emissions.

An industrial commenter ( 1134) stated that for many industries, it is difficult to associate basic design parameters with either hourly emissions or input specifications. However, if EPA includes a basic design parameter test in the final rule, the commenter urged EPA to allow flexibility to plant operators to establish what the measure of performance will be for process units, including the use of permit limits on amount of production.

A State/ local commenter ( 1199) recommended that any design parameter that could affect actual emissions should be considered a basic design parameter which may not be changed without agency approval.

<IP_ADDRESS> Oppose basic design parameter approach because functional equivalence is adequate Several industry commenters ( 1132, 1134, 1292, 1799, 1866, 1868) indicated that the functionally equivalent safeguard is sufficient to assure that replacement components cannot be designed to materially change the process unit. 3  Equipment Replacement Internal and Deliberative Draft August 6, 2003 Do not quote, cite, copy, or distribute 3 58 Two industry commenters ( 1201, 1202) stated that the basic design parameter test introduces substantial confusion into the rule without adding any additional benefit that is not already inherent in the term " functionally equivalent." One of the commenters ( 1202) added that for the automobile surface finishing industry, the test would exclude the precise projects that the equipment replacement approach is designed to cover.