Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 i Equipment Replacement Provision Preamble to Final Rule Table of Contents I. General Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 A. How can I get copies of this document and other related information? . . . . . 5 1. Docket . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 2. Electronic Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 B. Where can I obtain additional information? . . . . . . . . . . . . . . . . . . . . . . . . . . 8 II. Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 A. What is the RMRR exclusion? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 B. How has the process of using the RMRR exclusion worked? . . . . . . . . . . . . 9 C. Process Used to Develop This Rule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 D. What We Proposed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 III. Equipment Replacement Provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 A. Overview and Justification for Today's Final Action . . . . . . . . . . . . . . . . . . 16 B. What is an identical or functionally equivalent replacement and why is such an activity RMRR? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 C. What cost limit has been placed on the equipment replacement approach? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 D. What will be the basis of applying the 20 percent threshold? . . . . . . 45 E. What basic design parameters are being established to qualify for the equipment replacement provision? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 F. What collection of equipment should be considered in applying the equipment replacement provision and how should it be defined? . . . . . . 55 G. Consideration of Non emitting Units as Part of the Process Unit . . . . . . . . 66 H. What is the accounting basis for the process unit? . . . . . . . . . . . . . . . . . . . . 69 I. Enforcement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 J. Quantitative Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 K. Consideration of Other Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 1. Annual Maintenance, Repair and Replacement Allowance . . . . . . . . 84 2. Capacity Based Option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 3. Age Based Option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 L. Specific List of Excluded Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 M. Stand alone Exclusion for Energy Efficiency Projects . . . . . . . . . . . . . . . . 91 N. Legal Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 IV. Administrative Requirements for This Rule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 A. Executive Order 12866  Regulatory Planning and Review . . . . . . . . . . . . 106 B. Executive Order 13132  Federalism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 C. Executive Order 13175  Consultation and Coordination with Indian Tribal Governments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 D. Executive Order 13045  Protection of Children from Environmental Health Risks and Safety Risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 E. Regulatory Flexibility Act ( RFA), as Amended by the Small Business Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 ii Regulatory Enforcement Fairness Act of 1996 ( SBREFA), 5 U. S. C. 601 et seq. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112 F. Unfunded Mandates Reform Act of 1995 . . . . . . . . . . . . . . . . . . . . . . . . . 113 G. National Technology Transfer and Advancement Act of 1995 . . . . . . . . . . 115 H. Executive Order 13211  Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use . . . . . . . . . . . 116 I. Executive Order 12988  Civil Justice Reform . . . . . . . . . . . . . . . . . . . . . . 117 V. Effective Date for Today's Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 VI. Statutory Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 1 ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51 and 52 [ FRL 6212 3; Electronic Docket OAR 2002 0068;

Legacy Docket A 2002 04]

Prevention of Significant Deterioration ( PSD) and Nonattainment New Source Review ( NSR): Equipment Replacement Provision of the Routine Maintenance, Repair and Replacement Exclusion AGENCY: Environmental Protection Agency ( EPA).

ACTION: Final Rule.

SUMMARY: The EPA is finalizing revisions to the regulations governing the NSR programs mandated by parts C and D of title I of the Clean Air Act ( CAA). Today's changes reflect EPA's incorporation of comments from the proposed rule for " Prevention of Significant Deterioration ( PSD) and Nonattainment New Source Review ( NSR): Routine Maintenance,

Repair and Replacement" ( 67 FR 80290; December 31, 2002).

These changes provide a category of equipment replacement activities that are exempt from Major NSR requirements under the routine maintenance, repair and replacement ( RMRR)

exclusion. The changes are intended to provide greater regulatory certainty without sacrificing the current level of environmental protection and benefit derived from the NSR Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 2 program. We believe that these changes will facilitate the safe, efficient, and reliable operation of affected facilities.

EFFECTIVE DATE: This final rule is effective on [ INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: Docket. Docket No. A 2002 04 ( Electronic docket OAR 2002 0068), containing supporting information used to develop the proposed rule and today's final rule, is available for public inspection and copying between 8: 00 a. m. and 4: 30 p. m., Monday through Friday ( except government holidays) at the Air and Radiation Docket and Information Center ( 6102T), Room B 108, EPA West Building, 1301 Constitution Avenue, NW, Washington, D. C. 20460; telephone ( 202) 566 1742, fax ( 202) 566 1741. A reasonable fee may be charged for copying docket materials.

Worldwide Web ( WWW). In addition to being available in the docket, an electronic copy of this final rule will also be available on the WWW through the Technology Transfer Network ( TTN). Following signature, a copy of the rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules:

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

FOR FURTHER INFORMATION CONTACT: Mr. Dave Svendsgaard,

Information Transfer and Program Integration Division ( C339 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 3 03), U. S. EPA Office of Air Quality Planning and Standards,

Research Triangle Park, North Carolina 27711, telephone 919

541 2380, or electronic mail at svendsgaard. dave@ epa. gov,

for questions on this rule.

SUPPLEMENTARY INFORMATION Regulated Entities Entities potentially affected by this final action include sources in all industry groups. The majority of sources potentially affected are expected to be in the following groups:

Industry Group SICa NAICSb Electric Services 491 221111, 221112, 221113,

221119, 221121, 221122 Petroleum Refining 291 324110 Industrial Inorganic Chemicals 281 325181, 325120, 325131,

325182, 211112, 325998,

331311, 325188 Industrial Organic Chemicals 286 325110, 325132, 325192,

325188, 325193, 325120,

325199 Miscellaneous Chemical Products 289 325520, 325920, 325910,

325182, 325510 Natural Gas Liquids 132 211112 Natural Gas Transport 492 486210, 221210 Pulp and Paper Mills 261 322110, 322121, 322122,

322130 Paper Mills 262 322121, 322122 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 4 Automobile Manufacturing 371 336111, 336112, 336211,

336992, 336322, 336312,

336330, 336340, 336350,

336399, 336212, 336213 Pharmaceuticals 283 325411, 325412, 325413,

325414 a Standard Industrial Classification b North American Industry Classification System.

Entities potentially affected by this final action also include State, local, and tribal governments that are delegated authority to implement these regulations.

Outline The information presented in this preamble is organized as follows:

I. General Information A. How can I get copies of this document and other related information? 1. Docket 2. Electronic Access B. Where can I obtain additional information? II. Background A. What is the RMRR exclusion? B. Why is the specification of categories of RMRR activities appropriate? C. Process Used to Develop This Rule D. What We Proposed III. Equipment Replacement Provision A. Overview and Justification for Today's Final Action B. What is an identical or functionally equivalent replacement and why is such an activity RMRR? C. What cost limit has been placed on the equipment replacement approach? D. What will be the basis of applying the 20 percent threshold? E. What basic design parameters are being established Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 5 to qualify for the equipment replacement provision? F. What collection of equipment should be considered in applying the equipment replacement provision and how should it be defined? G. Consideration of Non emitting Units as Part of the Process Unit H. What is the accounting basis for the process unit? I. Enforcement J. Quantitative Analysis K. Consideration of Other Options 1. Annual Maintenance, Repair and Replacement Allowance 2. Capacity Based Option 3. Age Based Option L. Specific List of Excluded Activities M. Stand alone Exclusion for Energy Efficiency Projects N. Legal Basis IV. Administrative Requirements for This Rule A. Executive Order 12866  Regulatory Planning and Review B. Executive Order 13132  Federalism C. Executive Order 13175  Consultation and Coordination with Indian Tribal Governments D. Executive Order 13045  Protection of Children from Environmental Health Risks and Safety Risks E. Regulatory Flexibility Act ( RFA), as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 ( SBREFA), 5 U. S. C. 601 et seq. F. Unfunded Mandates Reform Act of 1995 G. National Technology Transfer and Advancement Act of 1995 H. Executive Order 13211  Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. Executive Order 12988  Civil Justice Reform V. Effective Date for Today's Requirements VI. Statutory Authority I. General Information A. How can I get copies of this document and other related information?

1. Docket. EPA has established an official public docket Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 6 for this action under Docket ID No. A 2002 04. The official public docket consists of the documents specifically referenced in this action, any public comments received, and other information related to this action. Although a part of the official docket, the public docket does not include Confidential Business Information ( CBI) or other information whose disclosure is restricted by statute. The official public docket is the collection of materials that is available for public viewing at the EPA Docket Center, ( Air Docket), U. S. Environmental Protection Agency, 1301 Constitution Ave., NW, Room: B108, Mail Code: 6102T,

Washington, DC, 20004. The EPA Docket Center Public Reading Room is open from 8: 30 a. m. to 4: 30 p. m., Monday through Friday, excluding legal holidays. The telephone number for the Reading Room is ( 202) 566 1742. A reasonable fee may be charged for copying.

2. Electronic Access. You may access this Federal Register document electronically through the EPA Internet under the " Federal Register" listings at http:// www. epa. gov/ fedrgstr/.

An electronic version of the public docket is available through EPA's electronic public docket and comment system,

EPA Dockets. You may use EPA Dockets at http:// www. epa. gov/ edocket/ to submit or view public comments, access the index listing of the contents of the Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 7 official public docket, and to access those documents in the public docket that are available electronically. Once in the system, select " search," then key in the appropriate docket identification number.

Certain types of information will not be placed in the EPA Dockets. Information claimed as CBI and other information whose disclosure is restricted by statute, which is not included in the official public docket, will not be available for public viewing in EPA's electronic public docket. EPA's policy is that copyrighted material will not be placed in EPA's electronic public docket but will be available only in printed, paper form in the official public docket. To the extent feasible, publicly available docket materials will be made available in EPA's electronic public docket. When a document is selected from the index list in EPA Dockets, the system will identify whether the document is available for viewing in EPA's electronic public docket.

Although not all docket materials may be available electronically, you may still access any of the publicly available docket materials through the docket facility identified in section I. A. 1. of this preamble. EPA intends to work towards providing electronic access to all of the publicly available docket materials through EPA's electronic public docket.

For additional information about EPA's electronic Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 1 We broadly use the term " New Source Review," or NSR, to encompass both the PSD and the Non attainment New Source Review program.

8 public docket visit EPA Dockets online or see 67 FR 38102,

May 31, 2002.

B. Where can I obtain additional information?

In addition to being available in the docket, an electronic copy of today's final rule is also available on the WWW through the Technology Transfer Network ( TTN).

Following signature by the EPA Administrator, a copy of this rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at http:// www. epa. gov/ ttn/ oarpg. The TTN provides information and technology exchange in various areas of air pollution control. If more information regarding the TTN is needed,

call the TTN HELP line at ( 919) 541 5384.

II. Background A. What is the RMRR exclusion?

Under 40 CFR parts 51 and 52, " major modification" is defined as any physical change in or change in the method of operation of a major stationary source that would result in:

( 1) a significant emissions increase of a regulated NSR1 pollutant or emission of a new pollutant; and ( 2) a significant net emissions increase of that pollutant from Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 2 Once a modification is determined to be major, NSR requirements apply only to those specific pollutants for which there would be a significant net emissions increase.

9 the major stationary source. 2 Owners and operators of major stationary sources are required to obtain major NSR permits prior to beginning actual construction of a modification that meets this definition. The regulations provide that certain activities do not constitute a " physical change or change in the method of operation" under the definition of " major modification." One category of such activities is routine maintenance, repair and replacement ( RMRR). Until today, the NSR regulations have not further specified what types of activities are encompassed by this term.

B. How has the process of using the RMRR exclusion worked?

In the past, the RMRR exclusion has been applied on a case by case basis. This case by case approach has certain drawbacks, however. Unless an owner or operator seeks an applicability determination from his or her reviewing authority, it can be difficult for the owner or operator to know with certainty whether a particular activity constitutes RMRR. In fact, we concluded in our recent report to the President on the impacts of NSR on the energy sector that there have been cases where uncertainty about the interpretation of the exclusion for RMRR resulted in delay or cancellation of activities that would have maintained and improved the reliability, efficiency, and Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 10 safety of existing energy capacity.

Applicability determinations can be costly and time consuming for reviewing authorities and industry alike. If a source proceeds without a reviewing authority determination and is later found to have made an incorrect determination on its own, that source faces potentially serious enforcement consequences. Moreover, under the current case by case approach, State and local reviewing authorities must devote scarce resources to making complex determinations and consult with other agencies to ensure that any determinations are consistent with determinations made for similar circumstances in other jurisdictions and/ or that other reviewing authorities would concur with the conclusion.

On the other hand, if a source foregoes or defers activities that are important to maintaining its plant when the activities in question are in fact within scope of the exclusion, that can have adverse consequences for the source's reliability, efficiency, and safety. Industry commenters strongly echoed these concerns, expressing that the expense and delay associated with NSR scrutiny, whether or not the project is ultimately judged to be subject to major NSR, has caused a number of facilities to forego needed and beneficial maintenance, repair, and replacement Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 11 projects, including ones that would likely have reduced emissions. In our June 2002 report to the President, we similarly concluded that the NSR program has impeded or resulted in the cancellation of projects that would have maintained and improved the reliability, efficiency, or safety of existing energy capacity.

Finally, the source may install less efficient or less modern equipment in order to be more certain that it is within the RMRR regulatory bounds, or it may agree to limit its hours of operation or capacity to ensure no increase in emissions. Any of these approaches could make the source less productive than it would be otherwise. This loss of productivity would not be caused by any legal requirement but rather by the uncertainty of what NSR requirements would potentially apply. Such discouragement results in lost capacity and lost opportunities to improve energy efficiency and reduce air pollution.

We believe that these problems would be significantly reduced by adding to our RMRR provision a clearer, more objective approach which includes specific categories of activities that will be automatically considered to be RMRR in the future. Such categories will remove disincentives to undertaking RMRR activities falling within these categories and provide more certainty both to source owners and operators who could better plan activities at their Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 12 facilities, and to reviewing authorities who could better focus resources on other areas of their environmental programs rather than on time consuming RMRR determinations.

We believe that today's rule will facilitate projects that enhance key operational elements, such as efficiency,

safety, reliability, and environmental performance. We anticipate that improved safety and reliability will result in more stable process operations and reduce periods of startup, shutdown, and malfunction and the increased emissions usually associated with them. Accordingly,

establishing categories of activities that will qualify as RMRR promotes the central purpose of the CAA, " to protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population." CAA section 101.

C. Process Used to Develop This Rule In the 1992 " WEPCO Rule" preamble, we declared our intent to issue guidance on the subject of RMRR. In 1994,

as an outgrowth of meetings with the Clean Air Act Advisory Committee, we developed, for discussion purposes only, a preliminary draft that presented possible ways of how RMRR could be defined. We received a substantial volume of comments on this document. We subsequently decided not to include this preliminary draft approach in our 1996 NSR Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 13 proposed rulemaking. ( 61 FR 38250)

In 2001, the President's National Energy Policy directed EPA in consultation with the Department of Energy ( DOE) and other Federal agencies to review the impact of NSR on investment in new utility and refinery generation capacity, energy efficiency and environmental protection.

Our Report to the President illustrated the problems associated with our prior case by case approach to identifying RMRR activities and underscored the advantages of establishing an objective bright line approach for administering the RMRR provision.

We held conference calls with various stakeholders during October 2001 ( including representatives from industry, State and local governments, and environmental groups) to discuss new ideas that were raised as to how the RMRR provision might be improved. The proposed RMRR rule reflected many of the ideas discussed in those meetings.

Today's final rule on the equipment replacement provision is based on careful consideration of comments received on the proposed RMRR rule, where we sought comment on all aspects of our proposed approaches. Today's rule represents final action on only one part of what we proposed in December 2002   the equipment replacement provision. We have decided, for now, not to take final action on the proposed annual maintenance, repair and replacement allowance approach. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 14 D. What We Proposed The RMRR proposal offered for comment two cost based approaches for determining what constitutes routine maintenance, repair, and replacement. Under the proposal,

facilities could have relied on a facility wide annual maintenance, repair and replacement allowance and/ or an equipment replacement cost threshold to determine whether major NSR requirements were triggered by performing plant maintenance, repair and replacement activities. The proposal additionally outlined two options based on the capacity and age of a facility. EPA solicited comment on all aspects of the proposed approaches as well as any other viable option for clarifying the term " routine maintenance,

repair, and replacement." We took public comment on the proposed rule until May 2, 2003   120 days following publication in the Federal Register.

Under the " annual maintenance, repair and replacement allowance," an annual maintenance cost allowance would be established for each industrial facility based on an industry specific percentage. For the percentage, we considered using the Internal Revenue Service " Annual Asset Guideline Repair Allowance Percentages" ( AAGRAP), which for years has been used as an integral part of an exclusion under the New Source Performance Standard ( NSPS) program. A Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 15 multi year allowance approach, in addition to the annual approach, was also offered for consideration in the proposal.

Safeguards were proposed to ensure that the types of activities undertaken under the annual allowance are not activities that should be subject to greater scrutiny.

These safeguards include: 1) no new unit may be installed;

2) no unit may be replaced in its entirety; and 3) changes may not cause an increase in the short term emission rate of any regulated NSR pollutant.

Under the " equipment replacement provision," or ERP, we proposed to streamline the process for determining if major NSR permitting requirements apply to replacement of existing equipment with identical new equipment or with functionally equivalent equipment. Per activity thresholds, potentially up to 50 percent of the cost of replacing the process unit,

were suggested by the proposal. As long as the threshold was not exceeded and the basic design parameters remained unchanged, the activity would be considered RMRR under this approach.

Under the proposal, all activities that fell within the annual maintenance, repair and replacement allowance or the equipment replacement threshold and that met all the other criteria for these provisions would be considered RMRR without further review. Activities that were unable to be Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 3 We broadly use the term " activities" to mean all maintenance and non maintenance projects conducted at a stationary source, some of which may trigger major NSR.

16 accommodated under the annual maintenance, repair and replacement allowance or the equipment replacement threshold could still qualify for the RMRR exclusion after a case

bycase review in accordance with current rules.

We solicited comments on all aspects of our RMRR proposal.

III. Equipment Replacement Provision A. Overview and Justification for Today's Final Action Today, we are revising certain provisions of the major NSR program by finalizing the equipment replacement provision ( ERP) to specify activities3 that will automatically qualify for the RMRR exclusion. This rule is effective on [ INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. At this time, we are not taking action on our proposed annual maintenance, repair and replacement allowance approach.

Although many commenters requested that we further clarify the case by case approach for determining whether an activity is RMRR, we are not taking action on this suggestion at this time. We are still considering what, if any, changes should be made to that policy. In the meantime, the case by case approach will remain available Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 4 For the sake of clarity, we are choosing to use the term " part," and not " component" as we used in the proposed rule, because " part" is a more inclusive term and reflects that the ERP should be applied broadly to cover replacements of both large components, such as economizers and reheaters for a steam electric generating facility, as well as small items, such as screws, washers, gaskets, etc.

5 We note that certain ancillary costs incurred during a given replacement activity should not be associated with the activity, such as replacement power that must be purchased during the maintenance shutdown of an electric utility.

17 for the owner or operator of a source to use as an alternative and/ or supplement to today's ERP.

Under today's rule, an activity ( or aggregations of activities) can qualify for the ERP if: ( 1) it involves replacement of any existing part( s) 4 of a process unit with part( s) that are identical or that serve the same purpose as the replaced part( s); ( 2) the fixed capital cost of the replaced part( s) plus costs of any associated activities ( e. g., labor, contract services, major equipment rental, and associated repair and maintenance activities) 5 does not exceed 20 percent of the current replacement value of the process unit; and ( 3) the replacement( s) does not alter the basic design parameters of the process unit or cause the process unit to exceed any emission limitation or operational limitation ( that has the effect of constraining emissions) that applies to any part of the process unit and that is legally enforceable.

Today's final rule specifies the procedures by which the owner or operator of a source selects the basic design Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 6 Replacement value can be either an estimate of the fixed capital cost of constructing a new process unit or the current appraised value of the process unit.

18 parameters for EUSGUs and for other types of process units.

Specifically, for EUSGUs, we have clarified our proposed approach by specifying maximum hourly heat input and fuel consumption specifications as basic design parameters. We are also allowing owners or operators of EUSGUs to use the process unit's electric output or steam flow. Likewise, we are retaining our proposed approach of specifying maximum fuel or material input for other types of process units, but we also allow you to specify an alternative basic design parameter, such as an output based one.

We are not specifically defining the basis for determining the replacement value of a new process unit.

Instead, the final rules provide you with the flexibility of using any of the following: ( 1) replacement cost6; ( 2)

invested cost, adjusted for inflation; ( 3) the insurance value, where the insurance value covers complete replacement of the process unit ( rather than, for example, lost revenue replacement); or ( 4) another accounting procedure to establish a replacement value of the process unit if such accounting procedure is based on Generally Accepted Accounting Principles ( GAAP). The GAAP are the conventions,

rules and procedures that define accepted accounting Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 19 practice for recording and reporting financial information,

including broad guidelines as well as detailed procedures.

The basic doctrine was set forth by the Accounting Principles Board of the American Institute of Certified Public Accountants, which was superseded in 1973 by the Financial Accounting Standards Board.

Once you choose to use options 3 or 4 to determine the replacement value of a particular process unit, you must continue to use the same basis to evaluate any additional activities that you undertake on that process unit within that same fiscal year. The reviewing authority will assume that the same method will be used for subsequent fiscal years unless you send a notice to them declaring your intent to use another method. In the absence of providing any notification to your reviewing authority, you must use option 1 or 2.

The final rules also set forth a definition of process unit, specifically delineate the boundary of the process unit for certain specified industries, and define a functionally equivalent replacement. A more detailed discussion of these requirements and our rationale for this action is contained in other parts of this preamble section.

Today's final rules are designed to allow you to engage in activities that facilitate the safe, reliable and efficient operation of your source. We believe that today's Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 20 final action improves the major NSR program by providing you with additional certainty as to what equipment replacement activities qualify for the RMRR exclusion. By adding certainty to the process, we are removing the disincentives to undertaking routine equipment replacements and promoting proper operational planning to facilitate safe, reliable and efficient operations. When an activity qualifies for the ERP, it will be considered RMRR and excluded from major NSR without regard to other considerations. In many cases, we believe that maintaining safe, reliable and efficient operations will have the corresponding environmental benefit of reducing the amount of pollution generated per product produced. The final rules also will reduce the resource burden on reviewing authorities resulting from implementation of the existing, case by case process for determining RMRR. In these respects, the final rules are consistent with the central purpose of the CAA, " to protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population." CAA section 101.

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

We proposed to exempt the replacement of existing equipment with identical or " functionally equivalent" parts. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 21 When such equipment replacement occurs and the replacement is identical, the replacement is inherent to both the original design and purposes of the facility, and ordinarily will not increase emissions. For example, if a pump associated with a distillation column fails and is replaced with an identical new pump, we believe that such a common activity is and should be considered an excluded replacement. We believe that activities like such pump replacements are routine and should not trigger NSR permitting requirements.

We also recognize that this principle extends beyond the replacement of equipment with identical equipment. When equipment is wearing out or breaks down, it often is replaced with equipment that serves the same purpose or function but is different in some respect or improved in some way in comparison to the equipment that is removed.

Moreover, the technology employed in certain types of equipment is constantly changing and evolving. When equipment of this sort needs to be replaced, it often is simply not possible to find the old style technology.

Owners or operators may have no choice but to purchase and install equipment reflecting current design innovations.

Even if it is possible to find old style equipment, owners or operators have obvious incentives for wanting to use the best equipment that suits the given need when replacements Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 22 must be installed.

The limiting principle here is that the replacement equipment must be identical or functionally equivalent and must not change the basic design parameters of the affected process unit ( e. g., for electric utility steam generating units, this would mean maximum heat input and fuel consumption specifications). Efficiency, however, is not a basic design parameter, as NSR should not impede industry in making energy and process efficiency improvements which, on balance, will be beneficial both economically and environmentally. This should address the concern and perception that the NSR program serves as a barrier to activities undertaken to facilitate, restore, or improve efficiency, reliability, availability, or safety of a facility.

Examples of functionally equivalent replacements include:

° Replacing worn out pipes in a chemical process plant with pipes that are constructed of different metallurgy to help reduce corrosion, erosion, or chemical compatibility problems.

° Replacing an analog controller with a digital controller, even though the new controller would allow for more precise control. A good example was presented Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 23 to us by the forest products industry during our review of the NSR program's impacts on the energy sector. A company in that sector needed to replace outdated analog controllers at a series of six batch digesters.

The original controllers were no longer manufactured.

The new digital controllers, costing approximately $ 50,000, are capable of receiving inputs from the digester vessel temperature, pressure, and chemical/ steam flow. The new controllers would have more precisely filled and pressurized digesters with chips, chemicals, and steam, thus bringing a batch digester on line faster.

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

grinding clinker in a cement factory or coal for a boiler) with a new one of a different type because both new and old equipment serve the same purpose ( even if the characteristics of the ground material would be different before and after the replacement).

° Replacing an old economizer in a boiler with a new one that contained different geometry, internal design and/ or metallurgy, even if the replacement improves fuel efficiency, or reduces erosion or plugging due to fly ash. The economizer's function is to do precisely that   help economize by reliably reducing fuel consumption per unit of output. Both new and old Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 7As discussed in more detail below, although such projects would be functionally equivalent, they would still need to meet other criteria to qualify for the ERP. For example, a functionally equivalent replacement does not qualify for the ERP if it results in a change to a basic design parameter of the affected unit. The case by case RMRR approach would still be available under those circumstances.

24 economizers serve that same function. The same logic holds for replacements of, or within, air preheaters and condensers, because these are heat exchangers designed to improve plant efficiency with a given amount of heat input. 7 ° Replacing existing spray paint nozzles with new ones that might atomize the spray better or have a higher transfer efficiency because the " before" and " after"

nozzles serve the same function.

At the same time, there are numerous activities that occur at facilities that may fall within the bounds of the cost threshold percentage, basic design parameters, and other backstop features of today's rule, but nevertheless cannot qualify for the RMRR exclusion on the grounds that the equipment is neither identical nor functionally equivalent. An example of this would include [ INSERT EXAMPLE]. Consequently, this activity would not qualify as RMRR under today's ERP.

As we observed at the time of our RMRR proposal, we believe that most identical and functionally equivalent replacements are necessary for the safe, efficient and Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 25 reliable operations of virtually all industrial operations;

are not of regulatory concern; will improve air quality ( e. g., by decreasing startup, shutdown, and malfunctions);

and thus should qualify for the ERP under the RMRR exclusion. We believe industrial facilities are constructed with the understanding that certain equipment failures are common and ongoing maintenance programs are routine.

Delaying or foregoing maintenance could lead to failure of the production unit and may create or add to safety concerns. When such equipment replacement occurs, the replaced part is inherent to both the original design and purposes of the source, and there is no reason to believe that such activity will cause an emissions increase.

Moreover, most of these replacements are conducted at industrial facilities to maintain proper operations and to implement good engineering practices.

As we also observed at proposal, when equipment is wearing out or breaking down, it often is replaced with equipment that serves the same purpose but is different in some respects or improved in some ways in comparison to the equipment that is removed. Moreover, the technology employed in certain types of equipment is constantly changing and evolving. When equipment of this sort needs to be replaced, it often is simply not possible to find the old style technology. Owners or operators may have no Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 26 choice but to purchase and install equipment reflecting current design innovations. Even if it is possible to find old style equipment, owners or operators have obvious incentives for wanting to use the best equipment that suits the given need when replacements are needed.

Several commenters said the equipment replacement provision will streamline the major NSR applicability analysis. A number of commenters believed the ERP would be easier to implement than the proposed annual maintenance,

repair and replacement allowance approach. One commenter said that allowing identical replacements to be excluded from major NSR will codify existing industrial practices,

where replacement has no impact on emissions and would clearly represent RMRR.

Many commenters expressed conditional support for the ERP, recommending certain changes that they felt needed to be made to improve the proposal. One commenter supported the ERP in combination with a capacity based option, on the assumption that repair and maintenance is to be excluded as well as equipment replacement.

One commenter attempted to collect data from turbine customers and found that achieving a level of data collection necessary for the ERP was far from simple,

because the cost of maintenance activities is affected by Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 27 such things as variability in engine model, package technology, and type of maintenance contract. Another commenter gave an example of the benefit that the ERP may provide. Without the ERP, the commenter said the source is limited to some fraction of boiler tubes allowed to be replaced at a given time, whereas with the ERP, replacement of all boiler tubes would, in the commenter's opinion,

rightfully be considered routine. Another commenter said the ERP will remove regulatory burdens for types of equipment replacements that are in their view " routine,"

such as replacement of tubes in industrial boilers. They added that, without a clearer understanding of which activities are RMRR, they may be inclined to delay conducting such replacements.

Many other commenters generally opposed any kind of RMRR exclusion, including one based on equipment replacement. Some of these commenters believed the ERP was problematic because it would allow a source to replace an entire process unit over time. Two of the commenters opposed the ERP because they felt it would create disincentives for the implementation of Plantwide Applicability Limits ( PAL) and Clean Unit provisions from the recently finalized rule.

One commenter said that from an engineering standpoint,

for a power plant, the difference between routine Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 28 maintenance and a major plant refurbishing project is clear.

According to the commenter, routine maintenance is frequent and follows a predictable pattern. The commenter characterized routine maintenance at power plants as:

repair of leaking pipes, pumps, valves, and fans; cleaning and lubrication of parts; and inspections. The commenter,

added that permanent staff do this work either while the plant is operating or during only brief periods of downtime.

The commenter asserted that activities that are not routine require long plant or process unit shutdowns, are done infrequently, and are major capital projects for which special funding is set aside as a result of years of planning and design work.

One commenter said the proposal will allow emissions increases that will be difficult to offset through other regulations. One commenter objected to the ERP for a number of reasons: ( 1) The provision does not prevent replacement with different equipment; ( 2) it does not promote efficiency improvements or application of good air pollution controls;

and ( 3) it would allow replacements that would significantly increase emissions. This commenter said replacement of air pollution controls should trigger best available control technology ( BACT) or lowest achievable emission rate ( LAER)

requirements. Two local air pollution control agencies in Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 29 California noted that they currently already exempt all replacements with identical equipment from major NSR when certain conditions are met.

Commenters generally had similar viewpoints on allowing both identical and functionally equivalent equipment replacements qualify as RMRR. However, some commenters expressed greater concern related to exempting the replacement of equipment with functionally equivalent equipment. Primarily their concerns were rooted in the fact that a functionally equivalent replacement part could lead to increases in operational efficiency or productivity, and these commenters asserted that these sorts of process enhancements should be not be exempt as RMRR.

We agree with the commenters who felt identical and functionally equivalent replacement activities generally should be exempted as RMRR. We also agree with the commenters who believe that this provision will streamline the major NSR applicability process and will bring clarity.

The provision we are finalizing will allow a source to make a simple determination as to whether a replacement piece of equipment qualifies as identical or functionally equivalent.

This type of determination will be straightforward and easier for the source to implement than the current case

bycase analysis required to determine a replacement falls within the RMRR exclusion. We support the air pollution Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 30 agencies that have already exempted these types of change from NSR.

We disagree with those commenters who believe that this provision will create disincentives for sources to accept a PAL or have emission units designated as Clean Units. A PAL offers a source many incentives related to major NSR: ( 1)

ability to bring on entirely new emissions units with no Federal preconstruction permit, as long as emissions caps are not exceeded; ( 2) ability to make modifications to existing sources without performing a major NSR applicability test; and ( 3) reduced need to keep records or otherwise track for major NSR purposes any maintenance,

repair and replacement activities or modifications at the facilities. A Clean Unit designation offers essentially the same advantages as a PAL, although under a PAL you can bring on new emissions units but you cannot do so with a Clean Unit. These advantages will still be the driving force for sources to elect to use the PAL or Clean Unit provisions,

and we do not believe this final rule will significantly detract from their appeal.

We also believe that there is value in providing a clearer distinction between routine equipment replacement and major plant refurbishing. For pieces of equipment used at industrial facilities, most manufacturers have well Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 31 established procedures for the inspection and replacement that are part of the regular maintenance necessary to provide for the equipment's safe, efficient and reliable operation. Some of these replacements are relatively large in terms of cost and can be infrequent, but all are necessary to maintain the safe, efficient and reliable use of the process unit. We believe it is important to allow for these replacements within certain limits, which are discussed below.

We disagree with suggestions from commenters that the time period between activities, standing alone, provides an appropriate or clear distinction between routine and nonroutine activities. In fact, we think the major NSR applicability provisions impose constraints on capital planning and maintenance processes at industrial facilities.

The effect of the existing provisions, such as the emissions baseline, is to force companies to plan maintenance actions on a relatively short horizon ( either 5 or 10 years,

depending on the emissions baseline). Failure to address maintenance within this horizon creates potentially significant ramifications such as the need to accept permanent limits on your operations. This can force companies to act sooner than needed or to take steps that have no rational relationship to the circumstances, with the result that maintenance actions are dictated by regulatory Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 32 constraints rather than by economic or plant efficiency.

We disagree with commenters who expressed particular concern about functionally equivalent replacements. We continue to believe such activities should be encouraged and should qualify as RMRR. Even though a functionally equivalent part varies in some respects from the replaced part, we feel the important factor to consider is whether the replacement will serve the same purpose as the replaced part. We acknowledge that a functionally equivalent replacement can result in an increase in efficiency and,

consequently, productivity. In fact, one of our goals is to promote such outcomes. However, we believe that the basic design parameter safeguard is appropriate to assure that the ERP only exempts from major NSR functionally equivalent replacements that do not result in a significant change to the fundamental characteristics of the process unit.

Moreover, the two local programs in California that exempt the replacement of equipment with identical equipment also allow the replacement of equipment with functionally equivalent equipment without considering such action to be a modification. However, due to local air quality considerations, the local programs establish minimum pollution control requirements that are imposed in some circumstances when functionally equivalent equipment Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 33 replacements occur. Nothing in today's rule would prevent a State or local program from imposing additional requirements necessary to meet Federal, State or local air quality goals.

After reviewing the comments on our proposal, we have decided to promulgate what we proposed in December 2002 for the RMRR equipment replacement provision with relatively minor changes. We decided that another safeguard, in addition to the proposed safeguards, would provide added certainty by constraining the meaning of " functionally equivalent." The additional safeguard is that an exempted replacement cannot cause a revision of the source's emission limitation in its permit. More specifically, today's rule stipulates that activities that cause the process unit to exceed any emission limitation or operational limitation ( that has the effect of constraining emissions) that applies to any part of the process unit cannot qualify as RMRR under the ERP.

Thus, today's final rule allow you to categorize identical and functionally equivalent equipment replacements as RMRR if the fixed capital cost of such replacement plus the cost of associated activities does not exceed 20 percent of the replacement value of the process unit, and if the replacement does not alter a basic design parameter of the process unit or cause the process unit to exceed any emission limitation or operational limitation ( that has the Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 34 effect of constraining emissions) that applies to the process unit.

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

The next concept presented in the proposal is the costbased limitation on the scope of the ERP. The purpose of this threshold is to distinguish between those equipment replacement activities that should automatically qualify as RMRR without further consideration and those activities that should undergo case specific consideration. This concept is borrowed from, and closely 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.

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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 8In 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.

35 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 project, 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. 8 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.

Finally, we noted that there are other considerations Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 36 pointing in favor of a threshold lower than the 50 percent reconstruction threshold that may be appropriate to bound the ERP. For example, since under NSPS when a source undertakes a replacement activity at 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. It is reasonable to conclude that some percentage lower than the 50 percent reconstruction threshold would be suitable in requiring case by case consideration of the question whether equipment replacements constitute a modification of an existing process unit under major NSR. We solicited comments on the appropriate level of any percentage.

Many commenters supported the threshold of 50 percent of replacement value as the upper limit on equipment replacement. They felt this number is consistent with existing regulatory requirements and would accord the flexibility originally intended under the CAA for RMRR activities, while at the same time assuring that major,

nonroutine projects remain subject to major NSR applicability review, and they felt this number is consistent with a common sense interpretation of the regulations. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 37 They also believed a 50 percent cutoff to be consistent with reconstruction definitions used in many NSPS and National Emission Standards for Hazardous Air Pollutants regulations. Some commenters stated that a 50 percent cutoff for the ERP would be valid for the same reason as for the NSPS reconstruction test; significant changes to a process unit are necessary before retrofit controls should be considered, provided there is no increase in emissions.

Many other commenters opposed the 50 percent replacement value threshold. They believed the capital replacement percentage should be much less than 50 percent.

One commenter preferred that the sum of equipment replacement costs for a single process unit over any period of 5 consecutive years should not exceed 50 percent of the replacement value of the process unit. Another commenter said the replacement percentage should not be higher than 25 percent. Another commenter suggested a replacement percentage of 5 to 10 percent to reduce the risk of replacement of an entire process unit over time without installation of BACT. One commenter said a more appropriate percentage for electricity producers is 0.1 to 1.0 percent.

Another commenter said the threshold should be 5 percent,

1 percent, or even less, as shown by an NSR enforcement case against the Tennessee Valley Authority ( TVA).

Another commenter believed the 50 percent number has no Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 38 practical effect in protecting public health and the environment, and the commenter was not aware of any projects that have exceeded 50 percent in cost.

While opposed to the ERP in general, one commenter said the cost threshold should be as high a percentage as possible, so as not to promote premature replacement of equipment that is repairable. Another commenter said the 50 percent number from the NSPS is archaic and not environmentally protective. This commenter suggested that the threshold instead be 24 percent. The commenter believed this lower percentage is appropriate because the lifetime of high cost materials will considerably exceed 5 years.

We agree with those commenters who see a relationship between establishing a threshold under the major NSR program for the ERP and the threshold established for the NSPS program. However, we disagree that the thresholds for the two programs should be the same. The NSPS threshold was intended to identify those projects that, even though they did not qualify as a modification, nevertheless are of such magnitude that they should be given further consideration as projects possibly 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, Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 39 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 projects 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.

Another relevant consideration in choosing an appropriate ERP cost threshold is the decision of the U. S.

Court of Appeals for the Seventh Circuit in the Wisconsin Electric Power Company ( WEPCO) case. See 893 F. 2d 901 ( 7th Cir. 1990). This decision directly addressed the questions of what level of " like kind" replacement activities qualify Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 40 as changes under the major NSR program.

In the WEPCO case, the Court considered a project involving 5 coal fired units at WEPCO's Port Washington plant. Each unit was rated at 80 megawatts of electrical output capacity. The project involved the replacement of numerous major parts. The information submitted by WEPCO showed that the company intended to replace several parts that are essential to the operation of the Port Washington plant. In particular, the WEPCO would 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. They measure 60 feet long, 50.5 inches in diameter, and 5.25 inches thick, and 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 parts, including replacement of the air heaters at units 1, 2, 3, and 4. The WEPCO also planned to renovate major mechanical and electrical auxiliary systems and common plant support facilities. The WEPCO intended to perform the work over a 4 year period, utilizing successive 9 month outages at each unit. The cost of the project was estimated in 1988 to be $ 87.5 million. The Court Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 41 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 today's rule is nearly identical to the make up of the " comparable new facility" that was used in the NSPS evaluation of the WEPCO renovation project. However, one difference is that the cost of pollution control equipment is not considered in evaluating the changes in WEPCO against the process unit definition in today's rule. The WEPCO had electrostatic precipitators on each of its 5 process units, so this needs to be factored in. In addition, the WEPCO evaluation dealt with 5 boilers, each with its own turbine generator set; to be consistent with today's definition of steam electric generating facility, we would likely treat each boiler unit as belonging to a different process unit. However, since all of the boilers underwent similar renovations, for simplicity we can assume that all of the process unitspecific 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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 9 Using the Chemical Engineering 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. This cost index is found in Chemical Engineering magazine.

10We 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 case included a series of projects with absolute and relative costs well below those at issue in WEPCO. The court determined, again 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 42 million scaled up to 1991 dollars results in an adjusted project cost of $ 92.3 million. 9 Thus, the capital cost percentage for the replacement activities at WEPCO, averaged over its 5 process units, amounts to 29 percent.

Alternatively, using the project cost of " at least $ 70.5 million" as cited in the 1991 decision by the Seventh Circuit, and using the same value for process unit cost, we compute at least 22 percent. The 20 percent threshold is,

therefore, beneath the scope of the projects at issue in the WEPCO case. Therefore, while we recognize that the WEPCO court did not specifically endorse as RMRR all maintenance,

repair and replacement activities falling below the cost percentage in that case, the percentage we are adopting today certainly does not run afoul of the limits established in WEPCO. 10 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 and the relevant EPA rules. As explained fully in Section N below, EPA today is adopting for future purposes a new interpretation of the CAA and is finalizing a revision to the RMRR regulation. The decision in Ohio Edison does not preclude the interpretation and regulation finalized in today's action.

43 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 assures us that we have established the right ERP threshold for this sector.

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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 44 equipment replacement activities. We have reviewed the list of projects supplied by UARG and have concluded that these types of replacement activities are necessary and helpful in maintaining, facilitating, restoring or improving the safety, reliability, availability, or efficiency of process units. Therefore, 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 projects would, in fact, qualify for the ERP and that limited groupings of these projects would qualify. However, larger groupings of these projects   groupings that are not usually seen in the industry   would not qualify for the ERP. This shows that the 20

percent threshold will be effective in distinguishing between activities ( and aggregations of activities) that should not require case specific review to be excluded from major NSR and those that do.

The ALA commenters provided with their comments the results of their analysis of projects at issue in an NSR Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 45 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 sourcewide 5 percent maintenance allowance. As noted above, we concluded in our 2002 report to the President that the NSR program  and the RMRR provision in particular  has in fact resulted in delay or cancellation of activities that would have maintained and improved the reliability, efficiency,

and safety of existing energy capacity. The primary purpose of today's rule is to rectify this problem. Thus, to the extent the projects addressed by ALA qualify for the ERP, we now believe that such projects should be excluded from major NSR.

D. What will be the basis of applying the 20 percent threshold?

In the proposal, we solicited comment on whether implementing the ERP on a per activity basis or on some other reasoned basis, such as applying the percentage to components that are replaced collectively over a fixed Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 46 period of time, may be more workable.

Many commenters stated that the ERP should be implemented on a per activity ( or aggregation of activities)

basis. Two of the commenters cited longstanding NSR precedent as the basis of their comments, while two other commenters relied on NSPS precedent. Another commenter thought the per activity approach would be less confusing than summing activities over a fixed period of time. Other commenters believed the equipment replacement threshold should in fact be applied on a 5 year rolling average.

We have decided to apply the percentage threshold on a per activity ( or aggregation of activities) basis. This is consistent with how major NSR has been applied in the past and will continue to 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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 47 comment on through our RMRR proposal.

There would be obvious problems if we chose any of the other approaches suggested in the proposal or suggested by commenters ( for example, annual basis or 5 year rolling average). One of the primary concerns with applying the percentage to activities performed over a span of time is that we would be restructuring the major NSR program to operate based on after the fact determinations. This raises the difficult question of what happens under this type of approach if you learn after commencement of an activity that it does not qualify under the ERP. This situation is largely avoided by the per activity approach that we are establishing in today's rule.

It should be noted that activities that are related must be aggregated under the ERP, in the same way as they would have to be aggregated for other NSR applicability purposes. Under our current policy of aggregation, two or more replacement activities that occur at the same time are not automatically considered a single project 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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 48 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. [ We think an example needs to be added here]

E. What basic design parameters are being established to qualify for the equipment replacement provision?

In the proposal, equipment replacements were only eligible for the ERP if they did not change the basic design parameters of the process unit. We proposed that maximum heat input and fuel consumption specifications for EUSGUs and maximum material/ fuel input specifications for other types of process units are basic design parameters. We solicited comments on limiting the eligibility of the ERP this way and on the basic design parameters we proposed.

Several commenters expressed concerns with either the use of these specific parameters, or the restriction of the regulated community to only this set of design parameters.

Other comments centered around an inconsistency in how EPA has accounted for efficiency in the basic design parameter safeguard. The commenters stated that, while EPA stated in the proposed preamble that efficiency is not a basic design parameter, the basic design parameter safeguard, as proposed, has the potential to bar equipment replacements Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 49 that achieve significant gains in efficiency.

Commenters from all sides supported EPA's approach to handling activities intended to improve an affected process unit's performance beyond its basic design parameters. In these circumstances, commenters agreed that actions that extend beyond the reasonable definition of RMRR should be subject to the full scope of major NSR. Commenters from the gas transmission industry concurred and amplified this concept, stating that an engine that is " uprated" at the time of overhaul should undergo major NSR.

We recognize that the proposed basic design parameters are inconsistent with some industry conventions, and that we should allow for industry specific flexibility or specify additional source category specific parameters. For example, for natural gas transmission compressor stations,

commenters explained that brake horsepower is the conventional design capacity parameter. We received similar comments from other industries, including cement and surface coaters, who objected to limiting their facilities to the proposed basic design parameters. Accordingly, we have decided to provide flexibility by providing a set of specified choices from which the owners or operators may select and by allowing for owners or operators to propose alternative basic design parameters to their reviewing authority which would then be incorporated in a Federally Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 50 enforceable permit such as a title V operating permit.

In addition to this flexibility, there may be a need for additional flexibility in using the basic design parameters that are spelled out in today's rule. For instance with boilers, maximum steam production rate is often used by the industry, and it may make sense in some cases to set the design parameters based on those values rather than on maximum heat input. Likewise, a crude oil distillation tower may have several capacities that are a function of the type of crude that is to be processed, and so a refiner may need to have a set of basic design parameters for their crude towers. These situations can be addressed by the source proposing alternative parameters or sets of parameters to their reviewing authority.

Also, there should be flexibility in how the basic design parameters are demonstrated. For example, in order to establish the heat input value that the process unit has demonstrated it is capable of achieving, an electric generating unit should have the flexibility to reference available credible information, such as results of historic maximum capability tests, design information from the manufacturer, or engineering calculations. Results from tests performed by electric utilities in the context of providing assurances to generation dispatch systems and Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 51 regional or national power pools may be used to establish the process unit's maximum heat input. A review of such data or other available operational data or design information can reveal the heat input that the process unit is capable of achieving in its " pre activity" configuration,

and this can be compared to a " post activity" heat input value. Plant operators, where the specified basic design parameters are inappropriate for the process, can propose what the measure of performance will be for these process units, including the use of permit limits on amount of production, to their reviewing authority. Likewise, our rules allow flexibility to accommodate sources having multiple end products and raw materials, such that the owner or operator of these sources should select the appropriate parameter for the dominant emission source of the process unit.

Many pieces of equipment are purchased based on their capacity or output. Consequently, for both utilities and non utilities, we have modified the proposed basic design parameters to include output based specifications in today's final rule. Also, for utilities, we added the option of selecting the basic design parameter of maximum design steam flow rating and clarified from the proposal that the correct parameter is maximum hourly heat input. Sources may request that their reviewing authorities specify fuel type ( such as Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 52 coal or oil) when setting basic design parameters at a combustion device that can accommodate multiple fuel types,

and, for coal fired units, they should consider that the fuel consumption rate will vary depending on the quality of the coal for a given heat input. When establishing fuel consumption specifications in terms of rate or volume, the minimum fuel quality based on BTU content should be used for coal fired units.

Regardless of whether the source selects a basic design parameter specified in today's rule or gets approval from their reviewing authority to use an alternative parameter,

our expectation is that the limits established will be consistent with EPA's policy on practically enforceable limitations. Specifically, owners or operators should establish appropriate limits to assure compliance with the terms of their permit ( e. g., avoiding long term limits where the rate is not indicative of the operation of the process unit).

Thus, an equipment replacement that improves a process unit's efficiency by enabling the unit to return to its original design parameters can qualify as RMRR even if current actual emissions increase as a result. For example,

if boiler tubes or refractory are replaced on a boiler process unit, and these activities are beneath the capital Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 53 cost threshold and are within the unit's basic design parameters, then they would qualify as RMRR under the ERP even if this improves the unit's efficiency.

Several commenters supported maximum design heat input as the basic design parameter for boilers. This parameter could also be expressed in terms of maximum design steam production rate, which is consistent with how the Florida Department of Environmental Quality permits bagasse boilers.

In the rare cases where a facility does not have established design parameters, we believe that a reasonable look back period should be used for establishing the preactivity values for basic design parameters, rather than taking the condition of the process unit immediately before the activity. We have therefore established a 5 year look back period, consistent with that for the NSPS hourly emissions increase test, for these situations.

We were urged by some commenters to incorporate a de minimis increase level in the basic design parameters that would allow projects to qualify for the ERP even though the activities would result in a minor change to the relevant basic design parameters. They argued that some effects resulting from the replacement may not be apparent before the equipment has been replaced. They argued that allowing for small changes in basic design parameters would add greater certainty to the ERP because unforeseen small Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 54 changes would not cause an activity to lose the exclusion after the fact. While we sympathize with the commenter's concern we do not believe that de minimis changes can be justified under the ERP. Today's rule is based on the notion that certain replacement activities should not be considered changes under NSR. It is hard for us to say a change has not occurred when an activity causes basic design parameters to change.

In sum, we continue to believe that an identical or functionally equivalent replacement should not qualify for the ERP if the activity causes the process unit to exceed specified basic design parameters. Without such a requirement, significant alteration of a process unit's fundamental design could be accomplished under the guise of the ERP. Such an outcome obviously does not square with the idea that identical or functionally equivalent replacements are not " changes" under the major NSR program. Our final rule is different from the proposal, however, in that it provides greater flexibility in defining basic design parameters for process units. We were persuaded by commenters who expressed concerns that the proposed approaches did not adequately encompass all affected operations and industry sectors.

F. What collection of equipment should be considered in Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 55 applying the equipment replacement provision and how should it be defined?

In the proposal, we raised the issue of what collection of equipment should be considered in applying the threshold under the ERP. We proposed the term " process unit" as the appropriate collection to accommodate the intended coverage of activities under the ERP. The purpose of this term is,

to the extent possible, to align implementation of the ERP with generally accepted and practical understandings of what constitutes a discrete production process. The general definition that we proposed was based closely on the definition of process unit contained in 40 CFR 63.41 and read as follows:

Process unit means any collection of structures and/ or equipment that processes, assembles, applies, blends,

or otherwise uses material inputs to produce or store a completed product. A single facility may contain more than one process unit.

To help illustrate these concepts, we further proposed five industry specific examples of how this definition of process unit might be applied.

Some commenters compared the proposal's definition of " process unit" ("... producing or storing a completed product...") to the definition that is used by section 112( g) and that appears in 40 CFR 63.41 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 56 ("... producing or storing an intermediate or final product..."). One of the commenters supported the more narrow proposed definition. Two commenters said the rule's definition should be consistent with that used by section 112( g), which they believe is broad enough to encompass interrelated operations. While supporting the RMRR proposal's definition, two commenters recommended that EPA provide regulatory flexibility by allowing a facility the option to choose which definition it will use.

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

Three commenters asserted that pollution control equipment should be included in the process unit definition.

One industry commenter said pollution control equipment is often integral to the process and may produce an intermediate product. One environmental commenter believed the proposed rule was unclear as to whether pollution control equipment is part of the process unit.

Several commenters said the proposed definition is too vague or broad. Another commenter added that the proposed definition is inconsistent with title V of the CAA. Another commenter urged EPA to change the definition of process unit Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 57 to limit the scope of what is allowed in the ERP, so that the source of emissions ( for example, an entire coal boiler)

would not be allowed to be replaced without major NSR. The commenter asserted that the replacement unit's scope should be limited to an emission unit.

Most commenters agreed that the general process unit definition is sufficient. However, a number of commenters suggested that we revise or eliminate some of the process unit examples ( that is, the industry category specific definitions), and others were concerned that the proposed definitions do not support the detailed process unit definition for a specific industry because the definitions will never capture all possible elements and configurations.

We received comments from several industry representatives suggesting changes to our proposed industryspecific definitions, and also to request that we delineate other process unit types explicitly in the rule.

Definitions were submitted for sugar mills, chemical manufacturing plants, surface coating operations, flat glass manufacturing, fiberglass manufacturing, and gas compressor stations.

One industry commenter agreed with our proposed approach to proportionately allocate, based on capacity, the cost of those components shared by two or more process units. Another commenter suggested that, for electric Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 58 utilities, we allocate the cost of shared equipment based on a pro rata share of megawatts produced.

We agree with the commenters who favor using a process unit as the basis for administering the ERP and including a definition of process unit in the final rule. We also agree with the commenters who suggested that the definition of process unit should be consistent with the definition in 40 CFR 63.41, and we have altered the final rule definition to include those processes that produce " intermediates." We acknowledge without further explanation that the term " intermediates" is susceptible to misinterpretation, which can cause confusion and lead to less regulatory certainty.

Thus, we provide the following explanation as to how we intend to interpret today's rule.

By " intermediates," we mean the intended product of an integrated facility operation. For example, for an automotive manufacturing plant, while the completed product would be the driveable vehicle ready for shipping to the showroom, an intermediate product could be the engine or the painted body shell. In this case, we would not consider smaller production operations, such as the production of the pistons or wheel well frame, to be an intermediate in the context of our final rule definition for process unit. Our primary goal in defining this term " process unit" is to Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 59 encompass integrated manufacturing operations that produce a completed product, and those operations that produce an intermediate as the product of the process unit.

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 parts 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 part 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 a integral part of the operation of a fractionation column. A low NOx burner is another example of a dual purpose part. In such cases, to provide clarity and simplify administration of the ERP, our rule provides that dual purpose equipment should be considered part of the process. We are also clarifying in today's rule Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 60 that administrative buildings ( including warehousing) are not to be included in the process unit, but other types of non emitting units that are integral to the processing equipment should be included.

We also have included in our final rule industryspecific examples of how this definition might be applied.

The examples are drawn for 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 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, thse defintions also Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 61 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 promulgated today.

° For a natural gas compressor station, each compressor system, together with its proportionate share of common support equipment is a separate process unit. For facilities operating in the midstream segment of the natural gas industry, the gas compression process unit consists of those portions of a natural gas compressor station, natural gas 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. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 62 ° 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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 63 packaged or wound onto spools for packaging for sale to customers or for additional later processing.

° For the production of precipitated amorphous silica,

the process unit includes, but is not limited to: raw material storage and handling equipment used for mixing sand and other raw materials prior to addition to the furnace; the furnace itself; the raw material storage and handling equipment for the cullet dissolving and silica precipitation process; all dissolving,

precipitation, and filtration tanks and equipment; and drying equipment. Further, the 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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 64 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.

° For a coatings facility, the process unit includes any,

all, or a combination of raw material storage,

reaction, recovery, separation, purification, blending or other activity, operation, manufacture, or Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 65 treatment. Cleaning operations are part of the process unit. Nondedicated solvent recovery operations located within a contiguous area within the affected source are considered a single process unit. Nondedicated formulation operations ( not including mixing, as defined) occurring within a contiguous area are considered a single process unit that is used to formulate numerous materials and/ or products.

° At 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.

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 Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 66 boilers at their facility to provide electricity and steam to their operations. As a general rule, we would expect these boilers to be treated as a separate process unit from the other unit operations occurring at the facility. We would expect the boundaries of the process units for such boilers to be consistent with the boundaries established under the definition for a steam electric generating facility in today's rule, which encompasses all equipment from coal handling to the emission stacks.

We also decided to continue to require that owners or operators who have parts shared by two or more process units to proportionately allocate, based on capacity, the cost of those parts. And we agree with the commenter that an equitable approach for electric utilities having parts shared by two or more process units is to allocate the cost of shared equipment based on the pro rata share of megawatts produced by each process unit.

G. Consideration of Non emitting Units as Part of the Process Unit Many commenters supported excluding non emitting equipment from the ERP. One commenter stated that triggering the major NSR review process for maintenance activities is an impediment to continuous improvement projects for certain products and processes, even if actual Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 67 emissions decrease or only non emitting units on the process line are affected. Delays or postponements of project maintenance work adversely affect the reliability, safety and productivity of operations and cost control efforts.

Another commenter recommended that work at clearly nonemitting units, specifically including foundation regrouting and repair and frametop replacement, should be excluded from this rule. Three commenters believed that non emitting units cannot result in an increase of emissions and thus do not need to be evaluated under major NSR.

A blanket exclusion for non emitting units could create problems of interpretation because the term " non emitting components" is ambiguous when considering certain components. Commenters asserted that identifying and separating out non emitting components can be a complex undertaking, and may be contrary to the goal of a clear and straightforward option. One commenter provided the following examples: ( 1) Piping systems ( although pipe connectors are a source of fugitive emissions, the pipe normally is not); and ( 2) structural supports for a process unit ( separating out the cost of supports from an investment basis throughout a facility will be difficult).

Another commenter believed it would be difficult to separate the costs of emitting and non emitting equipment when determining the cost of the process unit. The Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 68 commenter also believed it would be difficult to determine allocation of shared equipment in the cost analysis.

We are concerned that, if owners or operators were allowed to strip away all of the non emitting parts from a process unit definition, it would create significant ambiguity in the rule and could result in significant variation in how the rule is applied to similar sources in different jurisdictions. In addition, we simply do not think it is practical or logical to separate " non emitting"

parts of a process unit from " emitting" parts. We believe that integrated manufacturing operations ( that is, process units) typically include both types of equipment.

Separating emitting from non emitting equipment would create an artificial divide that contrasts sharply with physical and operational reality.

As noted above, however, we do believe that a distinction should be made between non emitting equipment that is part of a process unit and non emitting equipment that is functionally distinct from the process unit. For example, most production facilities have buildings or space to house administrative offices, such as offices for the plant accounting staff. Such non emitting facilities should not be considered part of any process unit under today's rule. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 69 H. What is the accounting basis for the process unit?

In the proposal, the accounting basis for the ERP discussed was the same as for the NSPS reconstruction provision, which is the fixed capital cost that would be required to construct an entirely new unit. We also discussed for the annual maintenance, repair and replacement allowance using the invested cost of a unit as the accounting basis. We proposed that it would be appropriate to require that costs be calculated using an approach along the lines set out in the EPA Air Pollution Control Cost Manual ( http:// www. epa. gov/ ttn/ catc/ dir1/ c_ allchs. pdf).

Finally, we solicited comment on whether the costs associated with the unanticipated shutdown of equipment, due to component failure or catastrophic failures such as explosions or fires, should be included in evaluating costs under the ERP.

In reviewing comments, we recognized that some commenters appeared to direct their comments on the accounting methods at the annual maintenance, repair and replacement allowance, and not necessarily the ERP. Often,

we came to this conclusion simply by the way the commenters organized their comments, and not by any specific statements in the comment letter. However, since we asked for comment on the accounting approaches as they would be applied to both the annual maintenance, repair and replacement Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 70 allowance and the ERP, we believe that comments that appeared to be dedicated to the annual maintenance, repair and replacement allowance should also apply to our evaluation of the accounting for the ERP, except in the case where the commenter specified that their comments on the proposed accounting methods applied only to the Annual MRR allowance or the ERP. Likewise, for considering whether costs associated with unanticipated shutdown of equipment,

we considered the comments to apply to both the ERP and the annual maintenance, repair and replacement allowance unless the commenter specifically noted that the comment should not be applied to both of the proposed rule provisions.

Most commenters asked for flexibility on whether a facility should use replacement value, invested cost or insurance valuation as the basis for the calculations. They felt that all were of equal merit and different ones would be available at different facilities so EPA should not prescribe only one type.

Most commenters did not support the sole use of the EPA Air Pollution Control Cost Manual ( APCCM) to standardize calculations for replacement and repair costs for RMRR in general. Most commenters felt that the APCCM is a worthy reference for costing but also that sources should not be limited to only one manual, because a single manual is Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 71 likely to have shortcomings and not be able to represent every situation.

Many commenters supported an exclusion of costs for unanticipated shutdowns and failures. They noted that strong incentives exist to avoid fires, explosions and other unanticipated equipment failures because of the risk of human injury and production interruptions and because of the expense involved in restoring lost capacity. As a result,

they contend that a catastrophic event already penalizes the facility dramatically, but then to impose the case by case analysis would only exacerbate their troubles. They explained that failures take place occasionally and can result in a sudden, unplanned partial or total loss of equipment. When such a failure occurs at a natural gas compressor station, the turbine or engine concerned must be replaced immediately to avoid a disruption in gas supply.

Other facilities may have similar pressures to maintain their product around the clock. Such replacement fits easily within most elements of the equipment replacement test. Commenters asserted that replacing a catastrophically failed turbine or engine is clearly " routine," since companies will always replace such failures.

Other commenters, however, opposed an exclusion for unanticipated shutdowns and failures on the grounds that maintenance activities performed during forced outages are Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 72 simply maintenance and should be considered as such,

particularly given that the proposed RMRR rule approaches and the December 2002 final rules already have given the industry a number of exclusion options.

We are allowing sources to determine the applicability of today's rule on the basis of replacement value, with an option for sources to notify their reviewing authority in writing if they desire to use another option ( for example,

invested cost or insurance value where the insurance value covers only the complete replacement of the process unit).

The equipment replacement cost should be based on the current replacement value of the entire process unit at the time of conducting the activity.

Typically, replacement value is more easily obtained than invested cost. Most manufacturers will have information concerning the replacement value of a process unit, because such costs are commonly used when evaluating various business scenarios relating to manufacturing costs.

Also, use of replacement value is consistent with the NSPS provisions.

In addition to determining the replacement value of a process unit, in our final rule we allow for the use of several other accepted methods in different industries for estimating such values. Replacement values are the Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 73 estimated value of replacing a unit and can be based on a current appraisal. In lieu of replacement cost, you can also use inflation adjusted original investment, insurance limits if insured for full replacement of the unit, or other cost estimation techniques currently employed by the company, as long as the company follows GAAP and if approved by the reviewing authority.

A dollar per kilowatt rate for calculating costs may be appropriate for utilities. This model is specific to source and fuel type and is updated periodically. We allow sources to use insurance valuation methods such as the Handy Whitman Index to determine replacement costs for electric utilities.

Other sources to compute costs include the Nelson Refinery Construction Index Factors, Solomon Refinery Study, and licensors of the respective process unit ( e. g., Kellogg,

UOP).

In order for a cost based approach to be equitable, all owners or operators must include the same categories of expenses in both the process unit replacement value and the replacement activities sought to be exempted. Therefore,

although the final rule does not mandate any particular approach, we believe it is generally appropriate to calculate costs using an approach similar to the elements of Total Capital Investment as defined in the EPA Air Pollution Control Cost Manual Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 74 ( http:// www. epa. gov/ ttn/ catc/ dir1/ c_ allchs. pdf). While the manual contains basic concepts that could be used to estimate total capital investment at a process unit, it is geared toward cost calculations for add on control equipment. On the other hand, the underlying concepts are taken from work done by the American Association of Cost Engineers to define the components of cost calculations for all types of processes, not just emission control equipment.

In certain cases, other manuals might make more sense depending on their circumstances.

Under the EPA Manual, Total Capital Investment includes the costs required to purchase equipment, the costs of labor and materials for installing the equipment ( direct installation costs), costs for site preparation and buildings, and certain other indirect installation costs.

However, any costs associated with the installation and maintenance of pollution control equipment should be excluded from the cost calculation, as per our discussion in the previous section of this preamble. We believe equipment that serves a dual purpose of process equipment and control equipment ( combustion equipment used to produce steam and to control Hazardous Air Pollutant emissions, exhaust conditioning in the semiconductor industry, etc.) should be considered process equipment. Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 75 Direct installation costs include costs for foundations and supports, erecting and handling the equipment,

electrical work, piping, insulation, and painting. Indirect installation costs include such costs as: engineering costs;

construction and field expenses ( costs for construction supervisory personnel, office personnel, rental of temporary offices, etc.); contractor fees ( for construction and engineering firms involved in the activity); startup and performance test costs; and contingencies.

We agree with commenters who oppose a categorical exclusion for unanticipated shutdowns and failures. Whether an activity is planned or unanticipated, major NSR applicability should function the same way. Therefore,

replacements resulting from unanticipated outages are not excluded from major NSR unless they qualify as RMRR or for another exclusion from major NSR in their applicable rules.

To the degree they exceed the ERP cost threshold,

replacement activities resulting from unanticipated shutdowns or failures should be evaluated on a case by case basis for RMRR. In the case of a catastrophic loss, unless you increase your plant size considerably, it is likely that you would replace your failed equipment with a more efficient and cleaner part, and such replacement would not trigger major NSR because the actual to projected actual applicability test would not result in an emissions Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 76 increase.

I. Enforcement Today's rule provides revisions to the major NSR program to specify categories of equipment replacement activities that EPA will consider RMRR in the future. As recognized by the U. S. Supreme Court, an agency may not promulgate retroactive rules absent express congressional authority. See Bowen v. Georgetown Univ. Hosp., 488 U. S.

204, 208, 102 L. Ed. 2d 493, 109 S. Ct. 468 ( 1988). The Clean Air Act contains no such expressed grant of authority and EPA does not intend by its actions today to create retroactive applicability for today's rule. 42 U. S. C.

§ § 7401 et seq.

None of today's rule revisions apply to any changes that are the subject of existing enforcement actions that the Agency has brought and none constitute a defense thereto. Furthermore, prior applicability determinations on major modifications and the control requirements that currently apply to sources remain valid and enforceable.

As noted above, today we are changing certain exemptions to the major NSR program by taking final action on the ERP. If you are subsequently determined not to have met the applicable provisions of these new alternatives, you will be subject to any applicable enforcement provisions Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 77 ( including the possibility of citizens' suits) under the applicable sections of the Act. Sanctions for violations of these provisions may include monetary penalties of up to $ 27,500 per day of violation, as well as the possibility of injunctive relief, which may include the requirement to install air pollution controls.

J. Quantitative Analysis At proposal, we presented a quantitative analysis of the possible emissions consequences of the range of different approaches to the RMRR exclusion, to evaluate if our policy conclusions are correct. Our analysis was conducted using the Integrated Planning Model ( IPM). This analysis was done for electric utilities because we have a powerful model to perform such an analysis that we do not have for other industries. We stated that the results for electric utilities accurately reflect the trends we would see in other industries.

The IPM analyses of different scenarios showed that the breadth of the RMRR exclusion would have no practical impact on, let alone be the controlling factor in determining, the emissions reductions that will be achieved in the future under the major NSR program. The analyses showed that emissions of SO2 are essentially the same under all scenarios, although certain scenarios under today's rule are more economically efficient than other scenarios. This Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 78 stands to reason because nationwide emissions of SO2 from the power sector are capped by the title IV Acid Rain Program. For NOx, these analyses showed modest relative decreases in some cases and modest relative increases in other cases. These predicted changes represent only a modest fraction of nationwide NOx emissions from the power sector, which hover around 4.3 million tons per year ( tpy).

At this time, we do not have adequate information to predict with confidence which modeled scenario is most likely to occur. What these analyses indicate, however, is that regardless of which scenario is closest to what comes to pass, today's rule will not have a significant impact, up or down, on emissions from the power sector. However, we expect the rule to result in significant improvements in safety, reliability, and other relevant operational parameters.

The DOE also presented further analysis of the possible emissions consequences of the range of different approaches to the RMRR exclusion. Using the National Energy Modeling System ( NEMS), a variety of changes in energy efficiency and availability were evaluated, as well as the effect on emissions resulting from these regulatory revisions. This analysis concluded that efficiency improvements resulting from increased maintenance, repair and replacement are Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 79 expected to decrease emissions, whereas availability improvements are expected to increase emissions. In the cases represented in this analysis, the emissions reductions from assumed reductions in heat rates tended to dominate the corresponding effects of the assumed availability increases.

A number of commenters said that the underlying assumptions EPA used in the IPM analysis were flawed and resulted in erroneous conclusions regarding the emission reduction potential of the proposed RMRR rules. Several commenters stated that EPA's IPM analysis incorrectly assumes that no major modifications at any older units would ever trigger the requirement to add new pollution controls.

In addition, according to commenters, EPA also erroneously assumes that this lack of major maintenance, repair and replacement will have very little impact on the performance of those power plants, when in reality their emissions would increase significantly. The commenters cite a Clean Air Task Force analysis for power plants, which estimates that EPA's rule revisions will result in at least 7 million more tons of SO2 and 2.4 million more tons of NOx annually. Some commenters also questioned the appropriateness of using EPA's analysis for the electric generating sector to draw conclusions about non utilities.

One commenter said the IPM and DOE NEMS analyses correctly demonstrate that EPA's RMRR proposal will have no Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 80 appreciable impact on emissions from the power sector.

According to the commenter, this conclusion is consistent with EPA's findings in a 1989 report, " 1989 EPA Base Case Forecasts," which demonstrated that continuing to allow utilities to undertake activities including ongoing annual operating and maintenance activities and a major refurbishment when the unit reached 30 years of operating life would have no appreciable impact on emissions from the power sector, just as EPA's and DOE's recent analysis confirmed.

One commenter said the proposal lacks any reference to the gains accomplished by major NSR, the ongoing enforcement actions, settlements reached as a result of those actions,

or the potential gains from the investigations now pending.

EPA's reliance on improvements in productive capacity as the measure of success fails to consider that productive capacity must be balanced with the interests of health and welfare. The commenter also noted that critical to EPA's burden to consider all the relevant factors leading to its conclusion that the exemptions are necessary and appropriate is at the very least an assessment of the expected effects on emissions, which in turn will determine the public health benefits and costs of the proposed rule. Although data on emission reductions achieved under the existing program are Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 81 available, EPA has stated that it cannot accurately quantify the effects the proposed rule will have on emissions. Some commenters stated that before promulgating a final rule, EPA should provide such a quantitative assessment of the rule.

We disagree with the commenters who believe that emissions would be significantly higher for electric utilities than are estimated under the IPM model runs.

These commenters' arguments rely on the assumption that EPA's base case is invalid because, if major NSR rules were left unchanged, eventually all coal fired utilities would either apply BACT or deteriorate so badly that they would have to shut down. We do not believe this assumption is accurate. Our experience suggests that under the current NSR program, managers of coal fired electric generating facilities take whatever actions are necessary to avoid triggering major NSR, primarily because of its high retrofit costs and delays. If some maintenance, repair and replacement activities could trigger major NSR, facilities will limit their activities to those projects that do not trigger major NSR, and will take enforceable restrictions on fuel use or other actions to avoid major NSR. This results in some decline in efficiency and capacity, as the EPA's base case modeled, but the units would likely remain viable electric generating units for years without triggering BACT requirements. Thus, we believe our base case represents a Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 82 far more realistic assessment of what would happen under current major NSR rules than the dramatic BACT reductions presented by these commenters.

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

emissions increases from improved availability, but that previous major NSR rules discouraged these improvements.

Regarding the applicability of our analysis to nonutility sectors, we continue to believe that our conclusions are valid for all sectors, and further, that the effects from the electric utility industry dominate those from other sectors. We acknowledge that the results for the SO2 cap for utilities cannot be extended to non utilities that are Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 83 not similarly capped. However, our model runs for NOx reflected the absence of a cap, and are therefore valid for other uncapped sectors. Thus in the case of industrial boilers, which behave similarly to utilities, we would expect to see similar efficiency improvements and availability improvements occurring in tandem, resulting in either modest increases or decreases. Because the overall emissions from this sector are significantly smaller than for utilities, the modeled effects for utilities are expected to dominate the analysis.

Finally, for other industrial sectors, we do not anticipate that emissions increases will result from equipment replacement activities that qualify as RMRR under today's rule. While some efficiency improvements may result, the overall effect of these improvements will not be to induce greater demand and greater emissions, as was shown by the modeling for utilities ( i. e., demand depends on independent factors). Indeed, without increased demand,

efficiency improvements that lower emissions per unit of output would result in a decrease in emissions.

Therefore, we affirm the overall conclusion of our analysis   that today's rule has no practical effect on the environmental benefits of major NSR in the future. We have presented additional, more detailed supporting information in our final RIA and our response to comments document, both Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 84 of which can be found in the docket for today's action.

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

1. Annual Maintenance, Repair and Replacement Allowance We are not taking action on the proposed Annual Maintenance, Repair and Replacement Allowance option for the RMRR exclusion, and therefore public comments on this option are not addressed at this time. We will address comments on our proposed Annual Maintenance, Repair and Replacement Allowance if and when we take final action on that proposal.

2. Capacity Based Option As mentioned above, we considered the alternative option of developing an RMRR provision based on the capacity of a process unit. Under such an approach, an owner or operator could undertake any activity that does not increase the capacity of the process unit. Basing RMRR on capacity has appeal for several reasons. The primary objective of RMRR is to keep a unit operating at capacity and/ or availability. In addition, the linkage between capacity and environmental impact is more apparent than that between cost and environmental impact. Finally, this type of approach Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 85 might, in principle, be easier to use before beginning actual construction than some of the cost based approaches.

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

Another large concern of commenters was that a capacity based approach could prevent facilities from performing activities that make the facilities more efficient. RMRR provisions need to include some form of the other approaches to account for energy efficiency projects at utilities, which could increase output capacity ( i. e.,

production) without necessarily increasing heat input or fuel consumption. Some commenters noted that maximum hourly Internal and Deliberative Draft  Do not quote, cite, copy, or distribute August 19, 2003 86 emissions is a more appropriate surrogate for a change in capacity, because it is consistent with existing NSPS procedures and with averaging periods for ambient air quality monitoring and standards.