[Federal Register Volume 67, Number 251 (Tuesday, December 31, 2002)]
[Proposed Rules]
[Pages 80290-80314]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-31900]



  Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / 
Proposed Rules  

[[Page 80290]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51 and 52

[FRL-7414-6; Docket A-2002-4]
RIN 2060-AK28


Prevention of Significant Deterioration (PSD) and Non-attainment 
New Source Review (NSR): Routine Maintenance, Repair and Replacement

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The EPA is proposing revisions to the regulations governing 
the NSR programs mandated by parts C and D of title I of the Clean Air 
Act (CAA). These proposed changes reflect the EPA's consideration of 
the President's National Energy Policy (NEP), EPA's Report to the 
President on the impact of NSR pursuant to the NEP, and EPA's 
recommended changes to NSR based on the Report findings and discussions 
with various stakeholders including representatives from industry, 
State and local governments, and environmental groups. The proposed 
changes provide a future category of activities that would be 
considered to be routine maintenance, repair and replacement (RMRR) 
under the NSR program. The changes are intended to provide greater 
regulatory certainty without sacrificing the current level of 
environmental protection and benefit derived from the program. We 
believe that these changes will facilitate the safe, efficient, and 
reliable operation of affected facilities.

DATES: Comments. Comments must be received on or before March 3, 2003.
    Public Hearing. If anyone contacts us requesting to speak at a 
public hearing by January 21, 2003, we will hold a public hearing 
approximately 30 days after publication in the Federal Register.

ADDRESSES: Comments. Comments may be submitted electronically, by mail, 
by facsimile, or through hand delivery/courier. Follow the detailed 
instructions as provided in section I.C. of the SUPPLEMENTARY 
INFORMATION section.
    Public Hearing. The public hearing, if requested, will be held at 
the EPA's facilities at 109 TW Alexander Drive, Research Triangle Park, 
NC 27709 or at an alternate facility nearby. The EPA will not hold a 
hearing if one is not requested. Please check EPA's web page at http://www.epa.gov/ttn/nsr/whatsnew.html on January 21, 2003 for the 
announcement of whether the hearing will be held.

FOR FURTHER INFORMATION CONTACT: Mr. Dave Svendsgaard, Information 
Transfer and Program Integration Division (C339-03), U.S. Environmental 
Protection Agency, Research Triangle Park, NC 27711, telephone (919) 
541-2380, or electronic mail at [email protected].

SUPPLEMENTARY INFORMATION:

I. General Information

A. What Are the Regulated Entities?

    Entities potentially affected by this proposed action include 
sources in all industry groups. The majority of sources potentially 
affected are expected to be in the following groups.

----------------------------------------------------------------------------------------------------------------
                Industry group                       SEC a                           NAICS b
----------------------------------------------------------------------------------------------------------------
Electric Services.............................             491  221111, 221112, 221113, 221119, 221121, 221122
Petroleum Refining............................             291  32411
Chemical Processes............................             281  325181, 32512, 325131, 325182, 211112, 325998,
                                                                 331311, 325188
Natural Gas Transport.........................             492  48621, 22121
Pulp and Paper Mills..........................             261  32211, 322121, 322122, 32213
Paper Mills...................................             262  322121, 322122
Automobile Manufacturing......................             371  336111, 336112, 336712, 336211, 336992, 336322,
                                                                 336312, 33633, 33634, 33635, 336399, 336212,
                                                                 336213
Pharmaceuticals...............................             283  325411, 325412, 325413, 325414
----------------------------------------------------------------------------------------------------------------
a Standard Industrial Classification
b North American Industry Classification System. Entities potentially affected by this proposed action also
  would include State, local, and tribal governments that are delegated authority to implement these
  regulations.

B. How Can I Get Copies of This Document and Other Related Information?

    1. Docket. EPA has established an official public docket for this 
action under Docket ID No. A-2002-04. The official public docket 
consists of the documents 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 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

[[Page 80291]]

be available electronically, you may still access any of the publicly 
available docket materials through the docket facility identified in 
section I.B.1. EPA intends to work towards providing electronic access 
to all of the publicly available docket materials through EPA's 
electronic public docket.
    For public commenters, it is important to note that EPA's policy is 
that public comments, whether submitted electronically or in paper, 
will be made available for public viewing in EPA's electronic public 
docket as EPA receives them and without change, unless the comment 
contains copyrighted material, CBI, or other information whose 
disclosure is restricted by statute. When EPA identifies a comment 
containing copyrighted material, EPA will provide a reference to that 
material in the version of the comment that is placed in EPA's 
electronic public docket. The entire printed comment, including the 
copyrighted material, will be available in the public docket.
    Public comments submitted on computer disks that are mailed or 
delivered to the docket will be transferred to EPA's electronic public 
docket. Public comments that are mailed or delivered to the Docket will 
be scanned and placed in EPA's electronic public docket. Where 
practical, physical objects will be photographed, and the photograph 
will be placed in EPA's electronic public docket along with a brief 
description written by the docket staff.
    For additional information about EPA's electronic public docket 
visit EPA Dockets online or see 67 FR 38102, May 31, 2002.

C. How and to Whom Do I Submit Comments?

    You may submit comments electronically, by mail, by facsimile, or 
through hand delivery/courier. To ensure proper receipt by EPA, 
identify the appropriate docket identification number in the subject 
line on the first page of your comment. Please ensure that your 
comments are submitted within the specified comment period. Comments 
received after the close of the comment period will be marked ``late.'' 
EPA is not required to consider these late comments. If you wish to 
submit CBI or information that is otherwise protected by statute, 
please follow the instructions in section I.D. Do not use EPA Dockets 
or e-mail to submit CBI or information protected by statute.
    1. Electronically. If you submit an electronic comment as 
prescribed below, EPA recommends that you include your name, mailing 
address, and an e-mail address or other contact information in the body 
of your comment. Also include this contact information on the outside 
of any disk or CD ROM you submit, and in any cover letter accompanying 
the disk or CD ROM. This ensures that you can be identified as the 
submitter of the comment and allows EPA to contact you in case EPA 
cannot read your comment due to technical difficulties or needs further 
information on the substance of your comment. EPA's policy is that EPA 
will not edit your comment, and any identifying or contact information 
provided in the body of a comment will be included as part of the 
comment that is placed in the official public docket, and made 
available in EPA's electronic public docket. If EPA cannot read your 
comment due to technical difficulties and cannot contact you for 
clarification, EPA may not be able to consider your comment.
    a. EPA Dockets. Your use of EPA's electronic public docket to 
submit comments to EPA electronically is EPA's preferred method for 
receiving comments. Go directly to EPA Dockets at http://www.epa.gov/edocket, and follow the online instructions for submitting comments. To 
access EPA's electronic public docket from the EPA Internet Home Page, 
select ``Information Sources,'' ``Dockets,'' and ``EPA Dockets.'' Once 
in the system, select ``search,'' and then key in Docket ID No. A-2002-
04. The system is an ``anonymous access'' system, which means EPA will 
not know your identity, e-mail address, or other contact information 
unless you provide it in the body of your comment.
    b. E-mail. Comments may be sent by electronic mail (e-mail) to [email protected], Attention Docket ID No. A-2002-04. In 
contrast to EPA's electronic public docket, EPA's e-mail system is not 
an ``anonymous access'' system. If you send an e-mail comment directly 
to the Docket without going through EPA's electronic public docket, 
EPA's e-mail system automatically captures your e-mail address. E-mail 
addresses that are automatically captured by EPA's e-mail system are 
included as part of the comment that is placed in the official public 
docket, and made available in EPA's electronic public docket.
    c. Disk or CD ROM. You may submit comments on a disk or CD ROM that 
you mail to the mailing address identified in section I.C.2. These 
electronic submissions will be accepted in WordPerfect or ASCII file 
format. Avoid the use of special characters and any form of encryption.
    2. By Mail. Send two copies of your comments to: U.S. Environmental 
Protection Agency, EPA West (Air Docket), 1200 Pennsylvania Ave., NW, 
Room: B108, Mail code: 6102T, Washington, DC, 20460, Attention Docket 
ID No. A-2002-04.
    3. By Hand Delivery or Courier. Deliver your comments to: EPA 
Docket Center, (Air Docket), U.S. Environmental Protection Agency, 1301 
Constitution Ave., NW., Room: B108, Mail Code: 6102T, Washington, DC, 
20004., Attention Docket ID No. A-2002-04. Such deliveries are only 
accepted during the Docket's normal hours of operation as identified in 
section I.B.1.
    4. By Facsimile. Fax your comments to the EPA Docket Center at 
(202) 566-1741, Attention Docket ID. No. A-2002-04.

D. How Should I Submit CBI to the Agency?

    Do not submit information that you consider to be CBI 
electronically through EPA's electronic public docket or by e-mail. 
Send or deliver information identified as CBI only to the following 
address: Mr. David Svendsgaard, c/o OAQPS Document Control Officer 
(C339-03), U.S. Environmental Protection Agency, Research Triangle 
Park, NC 27711, Attention Docket ID No. A-2002-04. You may claim 
information that you submit to EPA as CBI by marking any part or all of 
that information as CBI. (If you submit CBI on disk or CD ROM, mark the 
outside of the disk or CD ROM as CBI and then identify electronically 
within the disk or CD ROM the specific information that is CBI). 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR Part 2.
    In addition to one complete version of the comment that includes 
any information claimed as CBI, a copy of the comment that does not 
contain the information claimed as CBI must be submitted for inclusion 
in the public docket and EPA's electronic public docket. If you submit 
the copy that does not contain CBI on disk or CD ROM, mark the outside 
of the disk or CD ROM clearly that it does not contain CBI. Information 
not marked as CBI will be included in the public docket and EPA's 
electronic public docket without prior notice. If you have any 
questions about CBI or the procedures for claiming CBI, please consult 
the person identified in the FOR FURTHER INFORMATION CONTACT section.

[[Page 80292]]

E. What Should I Consider as I Prepare my Comments for EPA?

    You may find the following suggestions helpful for preparing your 
comments.
    [sbull] Explain your views as clearly as possible.
    [sbull] Describe any assumptions that you used.
    [sbull] Provide any technical information and/or data you used that 
support your views.
    [sbull] If you estimate potential burden or costs, explain how you 
arrived at your estimate.
    [sbull] Provide specific examples to illustrate your concerns.
    [sbull] Offer alternatives.
    [sbull] Make sure to submit your comments by the comment period 
deadline identified.
    [sbull] To ensure proper receipt by EPA, identify the appropriate 
docket identification number in the subject line on the first page of 
your response. It would also be helpful if you provided the name, date, 
and Federal Register citation related to your comments.

F. How Can I Find Information About a Possible Public Hearing?

    Persons interested in presenting oral testimony or inquiring as to 
whether a hearing is to be held should contact Ms. Pamela J. Smith, 
Integrated Implementation Group, Information Transfer and Program 
Integration Division (C339-03), U.S. Environmental Protection Agency, 
Research Triangle Park, NC 27711, telephone number (919) 541-0641, at 
least 2 days in advance of the public hearing. Persons interested in 
attending the public hearing should also contact Ms. Smith to verify 
the time, date, and location of the hearing. The public hearing will 
provide interested parties the opportunity to present data, views, or 
arguments concerning these proposed emission standards.

G. Where Can I Obtain Additional Information?

    In addition to being available in the docket, an electronic copy of 
this proposed rule is also available on the WWW through the Technology 
Transfer Network (TTN). Following signature by the EPA Administrator, a 
copy of the proposed 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.

H. How is This Preamble Organized?

    The information presented in this preamble is organized as follows:

I. General Information
    A. What are the regulated entities?
    B. How can I get copies of this document and other related 
information?
    C. How and to whom do I submit comments?
    D. How should I submit CBI to the Agency?
    E. What should I consider as I prepare my comments for EPA?
    F. How can I find information about a possible public hearing?
    G. Where can I obtain additional information?
    H. How is this preamble organized?
II. Purpose
III. Background
    A. How does the process of using the RMRR exclusion currently 
work?
    B. Why is the specification of categories of RMRR activities 
appropriate?
    C. Process Used to Develop This Rule
IV. Overview of Recommended Approaches for RMRR
    A. Annual Maintenance, Repair and Replacement Allowance
    B. Equipment Replacement Provision
V. Legal Basis for Recommended Approaches
VI. Discussion of Issues Under Annual Maintenance, Repair and 
Replacement Allowance Approach
    A. Appropriate Time Period for a Maintenance, Repair and 
Replacement Allowance
    B. Cost Basis
    C. Basis for Annual Allowance--Stationary Source vs Process Unit
    D. Basis for Annual Maintenance, Repair and Replacement 
Allowance Percentage
    E. How to Calculate Costs
    F. Applicability Safeguards
    G. Timing of Determination
VII. Discussion of Issues under the Equipment Replacement Approach
    A. Replacement of Existing Equipment with Identical or 
Functionally Equivalent Equipment
    B. Defining ``Process Unit'' for Evaluating Equipment 
Replacement Cost Percentage
    C. Miscellaneous Issues
    D. Quantitative Analysis
VIII. Other Options Considered
    A. Capacity-Based Option
    B. Age-Based Option
IX. Administrative Requirements for this Proposed Rulemaking
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. Paperwork Reduction Act
F. Regulatory Flexibility Act (RFA), as Amended by the Small 
Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 
U.S.C. 601 et seq.
    G. Unfunded Mandates Reform Act of 1995
    H. National Technology Transfer and Advancement Act of 1995
I. Executive Order 13211--Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
X. Statutory Authority

II. Purpose

    We are proposing a change to the NSR program to provide specific 
categories of activities that EPA will consider RMRR in the future. We 
are seeking comment on all aspects of our proposed approaches to 
specifying categories of RMRR activities under the NSR program, and on 
other options considered. These approaches would be voluntary, in that 
owners or operators could opt to continue using the current procedures 
for determining what activities constitute RMRR at their facilities. 
This proposal seeks public comments in accordance with section 307(d) 
of the CAA and should not be used or cited in any litigation as the 
final position of the Agency.

III. Background

A. How Does the Process of Using the RMRR Exclusion Currently Work?

    Under the changes promulgated today to 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 NSR 
pollutant; and (2) a significant net emissions increase of that 
pollutant from the major stationary source. Owners/operators of major 
stationary sources are required to obtain a major NSR permit prior to 
beginning actual construction of a modification that meets this 
definition. The regulations exclude certain activities from the 
definition of ``major modification.'' One such exclusion is for RMRR 
activities. The regulations do not define this term. (See 40 CFR 
51.165(a)(1)(v)(C)(1), 51.166(b)(2)(iii)(a), 52.21(b)(2)(iii)(a) and 
52.24(f)(5)(iii)(a).)
    Under our current approach, the RMRR exclusion is applied on a 
case-by-case basis. In interpreting this exclusion, we have followed 
certain criteria. The preamble to the 1992 ``WEPCO Rule'' (57 FR 32314) 
and applicability determinations made to date describe our current 
approach to assessing what activities constitute RMRR. These 
applicability determinations are available electronically from the 
Region 7 NSR Policy and Guidance Database (http/://www.epa.gov/Region7/programs/artd/air/nsr/nsrpg.htm).
    To summarize these documents, to determine whether proposed work at 
a facility is routine, EPA makes a case-by-

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case determination by weighing the nature, extent, purpose, frequency, 
and the cost of the work as well as other relevant factors to arrive at 
a common sense finding. WEPCO at 910. None of these factors, in and of 
itself, is conclusive. Instead, a reviewing authority should take 
account of how each of these factors might apply in a particular 
circumstance to arrive at a conclusion considering the project as a 
whole. If an owner or operator is uncertain whether he or she is 
applying the NSR regulations correctly, we encourage the owner or 
operator to consult the appropriate reviewing authority for assistance.

B. Why Is Specification of Categories of RMRR Activities Appropriate?

    There has been some debate over the years as to the case-by-case 
approach and the types of activities that qualify as RMRR under our 
current case-by-case approach. The case-specific approach works well in 
many respects. For example, it is a flexible tool that accommodates the 
broad range of industries and the diversity of activities that are 
potentially subject to the NSR program.
    However, the case-by-case approach has certain drawbacks. Unless an 
owner or operator seeks an applicability determination from his or her 
reviewing authority or from EPA, it can be difficult for the owner or 
operator to know with certainty whether a particular activity 
constitutes RMRR. Applicability determinations can be costly and time 
consuming for reviewing authorities and industry alike. If a source 
proceeds without a determination and is later proven to have made an 
incorrect determination, 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 EPA or 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. 
Finally, the source may install less efficient or less modern equipment 
in order to be more certain that it is within the regulatory bounds, or 
it may agree to limit its hours of operation or capacity. Any of these 
approaches will make the source less productive than it would be 
otherwise. 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 
in which uncertainty about the exclusion for RMRR resulted in delay or 
cancellation of activities that would have maintained and improved the 
reliability, efficiency, and safety of existing energy capacity. 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 current RMRR provision specific categories of activities 
that will be considered to be RMRR in the future. Such categories would 
remove disincentives to undertaking RMRR activities and provide more 
certainty both to source owners and operators who could better plan 
activities at their facilities, and to reviewing authorities who could 
better focus resources on activities outside these RMRR categories. 
Accordingly, the establishment of categories of activities as RMRR is 
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.
    It should be noted that there may be some activities which, while 
fitting within the ambit of the RMRR exclusion could, if implemented, 
violate other applicable CAA requirements. As has always been the case, 
compliance with NSR requirements is not a license to violate any of the 
other applicable CAA requirements such as title V permitting 
requirements.

C. Process Used To Develop This Rule

    In the 1992 ``WEPCO Rule'' preamble, we indicated that we planned 
to issue guidance on the subject of RMRR. In 1994, as part of our 
meetings with the Clean Air Act Advisory Committee, we developed, for 
discussion purposes only, a document on how RMRR could be defined. We 
received a substantial volume of comments on this document. We 
subsequently decided not to include a definition of RMRR in our 1996 
NSR proposed rulemaking.
    In 2001, the President's NEP Report \1\ 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. The release of the report in May 2001 triggered a review of 
the impacts of NSR rules. EPA's Report to the President underscored the 
desirability of specifying certain categories of activities that 
qualify as RMRR. In parallel with this review, we renewed our 
exploration of recommendations for improving the NSR program. 
Recommended improvements suggested during this time represented a 
continuation of discussions on NSR issues that had taken place during 
the 1990's, as well as new ideas.
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    \1\ Reliable, Affordable, and Environmentally Sound Energy for 
America's Future, Report of the National Energy Policy Development 
Group, May 17, 2001.
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    The process of discussing possible improvements to the NSR program 
included significant interagency consultation, including meetings with 
representatives from the DOE, the Department of the Interior, and the 
Office of Management and Budget. Building on what we heard, 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. During 
many of these meetings, we discussed ideas for how to define RMRR in 
order to create more certainty for the industry and reviewing 
authorities. Today's proposed rule is an outgrowth of ideas discussed 
in those meetings.

IV. Overview of Recommended Approaches for RMRR

    Ever since EPA's promulgation of its original Prevention of 
Significant Deterioration (PSD) regulations in 1980, EPA has defined 
``modification'' in its NSR regulations to include common-sense 
exclusions from the ``physical or operational change'' component of the 
definition, including an exclusion for RMRR. Today, we are proposing 
two categories of activities that will in the future be considered RMRR 
activities: activities within an annual maintenance, repair and 
replacement allowance and replacements that meet our equipment 
replacement provision criteria.
    Under the proposal, when an activity falls within either of these 
categories, it would be considered RMRR and a source's owners or 
operators would know that the activity was excluded from NSR without 
regard to other considerations. When an activity did not fall within 
one of these categories, then it still could qualify as routine

[[Page 80294]]

maintenance, repair, and replacement under the case-by-case test.

A. Annual Maintenance, Repair and Replacement Allowance

    First, we are proposing to add new language to the RMRR exclusion 
at 40 CFR 51.165 (a)(1)(v)(C)(1), 40 CFR 51.166 (b)(2)(iii)(a), 40 CFR 
part 51, Appendix S (A)(5)(iii)(a), 40 CFR 52.21(b)(2)(iii)(a), and 40 
CFR 52.24 (f)(5)(iii)(a).This proposal would allow certain activities 
engaged in to promote the safe, reliable and efficient operation of a 
facility-that is, those that involve relatively small capital 
expenditures compared with the replacement cost of the facility--to be 
excluded from NSR provided that total costs did not exceed the annual 
maintenance, repair and replacement allowance. The annual maintenance, 
repair and replacement allowance and the rules for calculation and 
summation of activities under the allowance would be defined in new 
provisions at 40 CFR 51.165(a)(1)(xxxxii), 40 CFR 51.166(b)(53), 40 CFR 
52.21(b)(55), and 40 CFR 52.24(f)(25).
    Under our proposed approach, a calendar year maintenance, repair 
and replacement allowance would be established for each stationary 
source. The owner or operator may elect to use a fiscal year period 
instead of a calendar year if financial records are typically kept for 
a period other than calendar year at a facility.\2\ Although the 
proposal contemplates a one-year allowance, in recognition of the fact 
that maintenance cycles in many industries extend for more than 1 year, 
we also seek comment on whether a stationary source should have the 
option of a multi-year allowance, such as over 5 years.
---------------------------------------------------------------------------

    \2\ A fiscal year period would have to be 12 consecutive months.
---------------------------------------------------------------------------

    Under our 1-year allowance proposal, an owner or operator would sum 
the costs of the relevant activities performed at the stationary source 
during the fiscal or calendar year (from the least expensive to the 
most expensive) to get a yearly cost. For activities taking more than 1 
year to complete, costs associated with those activities would be 
included in the cost calculations for the year that the costs were 
incurred (using an accounting method consistent with that used for 
other purposes by the stationary source). If the total costs for all 
activities undertaken for these purposes came within the annual 
maintenance, repair and replacement allowance, these activities would 
all be considered RMRR activities. Other than documentation of the 
results of this assessment, the owner or operator would not have to do 
anything further with respect to those activities for purposes of major 
NSR.
    Where total yearly costs for all activities undertaken for these 
purposes at a source exceed the annual maintenance, repair and 
replacement allowance, the activities would be reviewed as follows.
    [sbull] The owner or operator would subtract activities from the 
total yearly cost, starting with the most expensive activity, until the 
remainder is less than or equal to the annual maintenance, repair and 
replacement allowance.
    [sbull] The owner or operator would evaluate on a case-by-case 
basis in accordance with EPA's case-by-case test any activities that 
did not come within the allowance and that are not otherwise excluded, 
in order to determine whether they are RMRR. If uncertain about a 
particular activity the owner or operator could seek an applicability 
determination.
    [sbull] If an owner or operator concluded that any such activity 
was not RMRR, he or she would then have to determine whether it 
constitutes a ``major modification'' that requires an NSR permit.
    The annual maintenance, repair and replacement allowance would be 
equal to the product of the replacement cost of the source and a 
specified maintenance, repair and replacement percentage. (See 
Sec. Sec.  51.165(a)(1)(xxxxii), 51.166(b)(53), 52.21(b)(55) and 
52.24(f)(25) of proposed rules.) EPA intends to set this percentage on 
an industry-specific basis. There are several ways in which the 
percentage could be established. One way is to set the threshold so as 
to cover the RMRR capital and non-capital costs that an owner or 
operator incurs to maintain, facilitate, restore, or improve the 
safety, reliability, availability, or efficiency of the source. We are 
also requesting comment on other approaches. For example, we could 
apply a discount factor to the typical costs in order to account for 
variability within an industry. We also ask for comment on how to 
determine typical costs for particular industries. We are considering 
using the Internal Revenue Service ``Annual Asset Guideline Repair 
Allowance Percentages'' (AAGRAP), which we use for an exclusion under 
the New Source Performance Standard (NSPS) program for increases in 
production. We also could rely on industry specific data for choosing 
an appropriate threshold, such as the North American Electric 
Reliability Council Generating Availability Data System (NERC/GADS) 
database or standard industry reference manuals.
    The replacement cost used in the calculation described above would 
be an estimate of the total capital investment necessary to replace the 
stationary source. The accounting procedures used to document 
eligibility under this rule should conform to the accounting procedures 
used for other purposes at a facility. Where several accounting 
procedures are used at a facility (e.g., methods for tax accounting and 
for setting rates often are different), the most appropriate procedures 
should be used for the purpose of determining costs pursuant to this 
regulation.
    EPA also seeks to standardize practices for estimating this 
investment, along the lines described in the EPA Air Pollution Control 
Cost Manual, excluding the costs for installing and maintaining 
pollution control equipment. See section V.E. of this document for 
further information on our recommended approach to calculating costs. 
The control cost manual is available electronically via the internet at 
http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf. We acknowledge that 
this manual is geared toward cost calculations for add-on control 
equipment but believe the basic concepts can be applied to process 
equipment as well. These 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. We seek comment on whether this manual or other reference 
documents or tools provide the best approach for standardizing 
estimation of these costs, whether different methods should be 
provided, and whether provision should be made in the form of a 
requirement or an assurance that if a method is used, we will accept 
it.
    Our recommended approach will contain safeguards to help ensure 
that activities that should be considered a physical change or change 
in the method of operation under the regulations are ineligible for 
exclusion from NSR under the annual maintenance, repair and replacement 
allowance. We are proposing to exclude the following from use of the 
annual allowance.
    [sbull] The construction of a new ``process unit,'' which is a 
collection of structures and/or equipment that uses material inputs to 
produce or store a completed product. See discussion below at section 
VII for further information regarding process units.
    [sbull] The replacement of an entire process unit
    [sbull] Any change that would result in an increase in the source's 
maximum

[[Page 80295]]

achievable hourly emissions rate of any regulated NSR pollutant, or in 
the emission of any regulated NSR pollutant not previously emitted by 
the stationary source.
    If an owner or operator uses the annual maintenance, repair and 
replacement allowance to determine that certain activities at a 
stationary source are RMRR, all relevant activities performed at that 
source must be included in the annual cost calculations unless the 
owner or operator elects to obtain a major NSR permit for the activity. 
In other words, an owner or operator may not select which activities to 
review case-by-case and which to include in the cost calculations when 
using the annual maintenance, repair and replacement allowance to 
determine RMRR activities. This is because, assuming the threshold is 
set to approximate the total amount that an owner or operator would 
typically be expected to spend on RMRR activities (or a discounted 
portion of this value selected to account for variability within an 
industry), the fact that a given activity's cost comes within the 
allowance can only reasonably assure that it is RMRR if all other 
relevant activities also are included. If the owner or operator could 
pick and choose among activities that he or she wished to include in 
the allowance, such an approach might allow the owner or operator to 
include large, atypical activities that do not constitute RMRR within 
the allowance, while applying the case-by-case test to smaller 
activities that quite clearly constitute RMRR under that test. The rule 
that all relevant activities must be included in the calculation and 
that lowest cost activities would be counted first should provide 
sufficient protection against this risk.
    Owners or operators electing to use the annual maintenance, repair 
and replacement allowance to determine RMRR activities will be required 
to submit an annual report to the appropriate reviewing authority 
within 60 days after the end of the year over which activity costs have 
been summed. The report will provide a summary of the estimated 
replacement value of the stationary source, the annual maintenance, 
repair and replacement allowance for the stationary source, a brief 
description of all maintenance, repair and replacement activities 
undertaken at the stationary source, and the costs associated with 
those activities. If the costs of activities in question exceed the 
annual maintenance, repair and replacement allowance for a stationary 
source, the report must identify the activities included within the 
allowance and the activities that fell outside the allowance. The 
procedures set out in 40 CFR part 2 are available for confidential and 
business-sensitive information submitted as part of this report.
    The following provides an example of how the process would work. 
Assume the source's annual maintenance, repair and replacement 
allowance equals $2,000,000. During a given year, the owner or operator 
spends $1,000,000 on running maintenance activities, and implements 
five other discrete maintenance activities at the source with costs as 
follows in Table 1 (none of these activities involves the construction 
of a new process unit, replacement of an existing process unit, or an 
increase in the maximum achievable hourly emissions rate of a regulated 
NSR pollutant or in the emission of any regulated NSR pollutant not 
previously emitted by the stationary source).

      Table 1.--Example Summary of Activities Commenced During Year
------------------------------------------------------------------------
             Change                     Month                Cost
------------------------------------------------------------------------
Activity 1.....................  January............            $200,000
Activity 2.....................  March..............             600,000
Activity 3.....................  April..............             360,000
Activity 4.....................  July...............             150,000
Activity 5.....................  November...........             250,000
------------------------------------------------------------------------

    The sum of costs incurred during the year is $2,560,000, $560,000 
above the annual maintenance, repair and replacement allowance. The 
most expensive activity commencing during the year was the $600,000 
activity commencing in March. The source must evaluate on a case-by-
case basis whether this activity is RMRR. When the cost of Activity 2 
is subtracted from the total annual cost, the remainder is $1,960,000, 
less than the annual maintenance, repair and replacement allowance. The 
remaining activities (Activities 1, 3, 4, and 5) are considered to be 
RMRR.
    We note that this example is framed as if the owner or operator 
would make these calculations for the first time at the end of the 
year. In reality, however, an owner or operator who is considering 
relying on the maintenance, repair and replacement allowance as the 
basis for his or her conclusion that a particular activity is RMRR is 
likely to make these calculations before beginning construction on any 
activity. This is because the owner or operator would know that he or 
she will only be able to rely on the allowance if the costs of the 
activity in question, when added with the costs of other activities to 
assure the safe, efficient, and reliable operation of the plant that 
the owner or operator is planning for the year, will in fact be within 
the allowance.

B. Equipment Replacement Provision

    In addition to our proposed annual maintenance, repair and 
replacement allowance, today we are also soliciting comment on an 
additional approach to be used in the future for those replacement 
activities that should qualify without regard to other considerations 
as RMRR. Specifically, we are soliciting comment on whether replacing 
existing equipment with equipment that serves the same function and 
that does not alter the basic design parameters of a unit should also 
qualify without regard for other considerations for RMRR treatment 
provided the cost of the replacement equipment does not exceed a 
certain percentage of the cost of the process unit to which the 
equipment belongs. While we believe the annual maintenance, repair and 
replacement provisions described above will significantly improve 
implementation of the RMRR exclusion, we recognize that the allowance 
may apply only to a subset of the activities that appropriately fall 
within the exclusion and that are susceptible of being identified as 
categorically constituting RMRR.\3\
---------------------------------------------------------------------------

    \3\ Of course, as noted earlier, the traditional case-by-case 
approach to administering the RMRR exclusion will continue to apply 
to activities that do not qualify under the annual maintenance, 
repair and replacement allowance approach described above, but for 
the reasons noted earlier, we believe that approach would be 
improved on by the identification of activities that may be found to 
constitute RMRR without requiring case-by-case consideration of this 
type.

---------------------------------------------------------------------------

[[Page 80296]]

    Accordingly, today we are soliciting comment on an additional 
approach to be used in the future for determining that certain 
replacement activities whose costs fall below a specified threshold 
qualify as RMRR without regard for other considerations. Under this 
approach, EPA would establish a percentage of the replacement value of 
a process unit as a threshold for applying the equipment replacement 
provision. If the replacement component is functionally equivalent to 
the replaced component, does not change the basic design parameters of 
the process unit, and does not exceed the cost threshold, it would 
constitute RMRR. This approach should enable the owner or operator to 
streamline the RMRR analysis and make this determination more readily 
and should further alleviate some of the problems noted above. We are 
soliciting comment on whether this approach would serve to streamline 
the RMRR determination process for activities that involve the 
replacement of existing equipment with identical new equipment and the 
replacement of existing equipment with functionally equivalent 
equipment. We are also soliciting comment on whether this approach 
should be adopted along with the annual maintenance, repair and 
replacement allowance described above, or whether this approach is 
preferred over the other such that we should only offer the equipment 
replacement provision in the final rule.
    We also solicit comment on what provisions might be needed to 
clarify and facilitate implementation of a combined approach. For 
example, should the costs of activities that qualify as an excluded 
equipment replacement count toward the annual maintenance, repair and 
replacement allowance? And, if so, how should they be counted? We are 
also soliciting comment on whether any other category of activity 
undertaken for these purposes should be excludable by the owner or 
operator from the annual maintenance, repair and replacement allowance. 
For example, activities undertaken to address unanticipated forced 
outages or catastrophic events such as fires or explosions may be the 
kind of unforeseeable expenditure that an owner or operator should not 
have to include because it is not possible to plan for it. Also, the 
absence of an exclusion for such activities might be a disincentive for 
maintaining and ensuring safe operation. If excluded from the 
maintenance, repair and replacement allowance, these activities could 
still qualify for RMRR status under the equipment replacement provision 
of this rule if they meet the criteria for that allowance or under the 
case-by-case analysis.
    Finally, we are soliciting comment on other approaches that might 
be effective in streamlining the RMRR determination process.

V. Legal Basis for Recommended Approaches

    The modification provisions of the NSR program in parts C and D of 
title I of the CAA are based on the broad definition of modification in 
section 111(a)(4) of the CAA. The term ``modification'' means ``any 
physical change in, or change in the method of operation of, a 
stationary source which increases the amount of any air pollutant 
emitted by such source or which results in the emission of any air 
pollutant not previously emitted.'' That definition contemplates that 
you will first determine whether a physical or operational change will 
occur. If so, then you proceed to determine whether the physical or 
operational change will result in an emissions increase over baseline 
levels.
    The expression ``any physical change * * * or change in the method 
of operation'' in section 111(a)(4) of the CAA is not defined. We have 
recognized that Congress did not intend to make every activity at a 
source subject to the major NSR program. As a result, we have 
previously adopted nine exclusions from what may constitute a 
``physical or operational change.'' One of these is an exclusion for 
routine maintenance, repair, and replacement. Today's rulemaking 
proposes two provisions that will improve and help carry out the 
purposes of this exclusion.

VI. Discussion of Issues Under Annual Maintenance, Repair and 
Replacement Allowance Approach

    The following provides a discussion of the key issues we considered 
in developing our preferred approaches to addressing RMRR under the NSR 
program. We are requesting comment on all alternatives considered and 
any other viable alternatives. We are also interested in the impact the 
use of a cost-based approach such as the annual maintenance, repair and 
replacement allowance will have on reviewing authorities, such as the 
need for staff knowledgeable in cost estimation, and are requesting 
comment on this issue.

A. Appropriate Time Period for a Maintenance, Repair and Replacement 
Allowance

    In developing a maintenance, repair and replacement allowance, we 
considered setting an allowance based on either a calendar or fiscal 
year or a multi-year limit. We believe that a limit applied over a 
specified period of time is more appropriate than an activity-based 
limit. We are proposing an annual limit, but we also believe that a 
multi-year limit is worthy of serious consideration as a possible 
option that could be chosen by owners or operators with multi-year 
maintenance cycles.
    Under NSR, to determine applicability, the owner or operator of a 
major source must determine whether an activity performed at a source 
is a physical change or change in the method of operation that results 
in a significant emissions increase and a significant net emissions 
increase. NSR may apply to a single physical change or operational 
change at a single process unit, to several physical or operational 
changes at a single process unit, or to multiple changes across 
multiple process units, each of which changes can vary widely in scope 
and cost. Developing a maintenance, repair and replacement allowance on 
an activity basis would be consistent with this framework. However, the 
variability in the scope of such activities makes it difficult to 
establish an appropriate cost allowance for individual activities based 
on data currently available to us. On the other hand, the majority of 
information that is currently available to us does provide a reasonable 
basis for developing facility-wide, annual maintenance, repair and 
replacement cost estimates. In addition to the difficulty in 
establishing an activity cost limit, maintenance budgets are typically 
set on an annual basis rather than an activity basis, making an annual 
allowance more consistent with industry financial practices.
    In choosing between an annual versus a multi-year limit, there are 
considerations pointing in both directions. The most important argument 
in favor of a multi-year option is that in a number of industries, 
maintenance cycles extend over multiple years. For example, petroleum 
refineries conduct regularly scheduled maintenance, referred to as a 
``turnaround,'' in cycles that can be as long as 8 years depending on 
the type of units and equipment involved and the particulars of the 
unit's operations. During a turnaround, all or part of the refinery is 
shut down, and the owner or operator undertakes numerous

[[Page 80297]]

maintenance, repair and/or replacement activities during the shutdown.
    Similarly, the power generation sector performs regularly scheduled 
maintenance, inspections, and repair on varying cycles, which, 
depending on the equipment involved, can range from 12 months to a 
number of years. Like refineries, power generation facilities must 
conduct much of the inspection, maintenance, repair and replacement 
work when the units are shut down, and to minimize the frequency of 
scheduled outages, the owner or operator will undertake numerous 
activities during a given shutdown to minimize maintenance costs, 
minimize the need for replacement power, and maximize the availability 
of the units. As a result, for industries of this type, the cost of 
maintenance will vary significantly from year to year and may be 
distributed across several years.
    An annual allowance for industries of this type may be unworkable 
if the allowance is set at the average of their maintenance costs 
during their maintenance cycle. But setting the level higher than the 
average runs the risk of sweeping in non-routine activity. In addition, 
an annual allowance might lead owners or operators in such industries 
to engage in more outages than is efficient in order to make sure that 
they were not losing a portion of their allowance. This could increase 
energy costs and reduce energy availability to consumers.
    If a multi-year allowance were used, the same principles of summing 
the costs of activities from least to most costly and excluding the 
most costly activities from the allowance and instead subjecting them 
to case-by-case scrutiny would continue to apply.
    This approach also may have its difficulties. For example, as the 
cycle gets longer, it is harder for owners or operators to project 
their costs for safeguarding the safety, reliability and efficiency of 
their plants farther into the future. This, in turn, may contribute to 
a rule that is more difficult to implement and enforce. If, through the 
after the fact case-by-case review, it is determined that certain 
activities should have been subject to the NSR program, all parties may 
be placed in the difficult situation of implementing a preconstruction 
review program for an activity that was begun or completed 
significantly prior to the applicability determination. This difficulty 
may arise to some extent even with a 1-year allowance period. But 
extending the period beyond 1 year increases both the possibility for 
this occurrence and the potential difficulties of an after-the-fact 
applicability determination for older activities. Thus, while using a 
single year as the time period will reduce the flexibility for some 
owners or operators, we believe it will help to reduce the likelihood 
that an after-the-fact NSR review will be required. For these reasons, 
we are proposing the annual maintenance, repair and replacement 
allowance approach, but will also be giving serious consideration to 
the multi-year approach of up to 5 years. We are requesting comments on 
the approaches discussed above.
    We are also proposing that the time period for the annual 
maintenance, repair and replacement allowance should be a calendar or 
fiscal year. If the owner or operator of a major stationary source uses 
a fiscal year that differs from a calendar year for accounting 
purposes, the proposed rule would allow the stationary source to elect 
to use that fiscal year for purposes of applying the annual 
maintenance, repair and replacement allowance. As proposed, once the 
choice is made, the choice is permanent. (See Sec.  
51.165(a)(1)(xxxxii)(A)(1), Sec.  51.166(b)(53)(i)(a), Sec.  
52.21(b)(55)(i)(a), and Sec.  52.24(f)(25)(i)(a) of proposed rules.) We 
specifically ask for comment on this aspect of the proposal.

B. Cost Basis

    Under our proposal, the replacement cost of a source would be 
multiplied by the maintenance percentage established by rule to 
determine the annual maintenance, repair and replacement allowance. 
(See Sec.  51.165(a)(1)(xxxxii), Sec.  51.166(b)(53), Sec.  
52.21(b)(55), and Sec.  52.24(f)(25) of proposed rules.) In developing 
the proposal, we also considered using an invested cost basis adjusted 
for inflation.
    There can be advantages to using invested cost. The most obvious 
advantage is that knowledge of cost estimation is not necessary, 
because actual cost data would be used. However, complete invested cost 
information may no longer exist for older stationary sources, or it may 
not have been provided to the buyer when a source was purchased. As a 
result, we would still need to provide for an alternative for 
situations where invested cost data were not available.
    In addition, even when adjusted for inflation, there could be 
inequities between facilities if an invested cost basis was used. 
Adjustment for inflation between sources will not likely take into 
account variations in site-specific costs such as land, labor, and 
materials, among others. Use of replacement cost, which takes into 
account site-specific factors to a greater degree, will put all 
regulated entities on a more equitable footing. Moreover, most 
decisions regarding maintenance, repair and replacement are more likely 
to take into consideration the cost of replacement rather than the 
original invested cost.
    We are proposing to use source replacement cost; however, we are 
requesting comment on other potentially appropriate bases for source 
cost, including invested cost, invested cost adjusted for inflation or 
any other viable methodology.

C. Basis for Annual Allowance--Stationary Source vs Process Unit

    We are considering two approaches for administering the annual 
maintenance, repair and replacement allowance--the allowance could be 
established at either an entire stationary source (source) or at the 
process unit level. A comprehensive discussion of the term ``process 
unit,'' along with a proposed definition, is set forth in section VII, 
below. If we opt for the ``process unit'' approach, we would use the 
definition and concepts proposed in section VII. We are proposing the 
stationary source approach but seeking comment on both.
    If the annual maintenance, repair and replacement allowance is 
established for the entire stationary source, the owner or operator 
would only have to track compliance with a single annual maintenance, 
repair and replacement allowance and would have greater flexibility in 
decision making with respect to maintenance, repair and replacement 
activities. It is our understanding that accounting of maintenance 
activities is most often performed at the facility level and, 
consequently, managing the RMRR annual maintenance, repair and 
replacement allowance from a facility-wide standpoint is more 
consistent with current industry practices. In large, complex 
manufacturing facilities such as refineries, several major processes 
are constantly being maintained but larger maintenance activities may 
be rotated throughout the plant during different years to accommodate 
fiscal and operating cycles. Requiring these facilities to divide their 
plants into separate process units for maintenance accounting would 
create disincentives to the source in administering the allowance. A 
source-wide approach also may be more sensible to account for 
situations in which shared services (e.g., electrical distribution, 
wastewater treatment) cannot be attributed to a single process at a 
facility.
    On the other hand, setting the annual maintenance, repair and 
replacement allowance at the source-wide level presents the possibility 
that an owner or

[[Page 80298]]

operator could forego maintenance at some process units and engage in 
activities at others that are not truly RMRR and seek to use the 
maintenance, repair and replacement allowance as a shield for these 
activities. Setting the annual maintenance, repair and replacement 
allowance at the process unit level would help to alleviate this 
concern.
    On balance, however, we are not persuaded that this concern is 
well-founded. If the allowance level is set correctly, the only way an 
owner or operator could attempt the kind of misuse of the allowance 
described above would be to forego maintenance, repair and replacement 
activities at other process units--activities that are important to 
keep those other process units in good working order. It seems unlikely 
that an owner or operator would think that a prudent or sensible 
course.
    Finally, we note that it likely is more difficult to develop 
reliable estimates of what it typically costs an owner or operator to 
maintain a process unit. That being the case, the most likely way a 
process-unit-based allowance would be developed would be by taking the 
numbers that would underlie a source-wide allowance and allocating them 
to process units. This approach could present its own opportunities for 
gaming the system.
    We are proposing to set the annual maintenance, repair and 
replacement allowance at the source-wide level. (See Sec.  
51.165(a)(1)(v)(C)(1), Sec.  51.166(b)(2)(iii)(a), Sec.  
52.21(b)(2)(iii)(a), and Sec.  52.24(f)(5)(iii)(a) of proposed rules.) 
We believe that this approach is, on balance, easier to implement for 
both the reviewing authorities and the industry and is more consistent 
with current industry maintenance and financial practices. We 
specifically request comment on the use of a source-wide limit, a 
process unit limit, or any other means of applying a cost threshold. In 
addition, as noted in section VII, we request comment on our proposed 
definition of process unit.

D. Basis for Annual Maintenance, Repair and Replacement Allowance 
Percentage

    The proposed annual maintenance, repair and replacement allowance 
for each source would be determined by multiplying the replacement cost 
of the source by an annual maintenance, repair and replacement 
allowance percentage specified by rule. (See Sec.  
51.165(a)(1)(xxxxii), Sec.  51.166(b)(53), Sec.  52.21(b)(55), and 
Sec.  52.24(f)(25) of proposed rules.) As stated previously, the goal 
of this portion of the rule is to provide a clear exclusion for the 
activities whose total costs fall below specified thresholds. We intend 
to set these thresholds on an industry-specific basis, and believe the 
following sources of information should be useful in establishing these 
thresholds: the IRS AAGRAP, standard engineering reference manuals, and 
actual industry data available to the EPA.
    The IRS AAGRAP is the value used in an exclusion under the NSPS for 
increases in production. The IRS AAGRAP values provide repair allowance 
percentages for specific industries in order to reflect differing 
maintenance needs. These percentages range from 0.5 percent to 20 
percent of invested cost. For instance, the aerospace industry has an 
AAGRAP value of 7.5 percent, electric utility steam generation has a 
value of 5 percent, and cement plants have a value of 3 percent. There 
is good reason to think that the industry-specific basis and the 
specific percentages are appropriate in the RMRR context. For example, 
the AAGRAP values have been used for over 20 years in the NSPS program, 
so they are time-tested and appear to work well in that context. 
Moreover, because the values were developed in the first instance to 
differentiate between costs that should be capitalized for tax 
accounting purposes and costs that properly should be expensed, the 
values should be well suited to distinguishing maintenance, repair and 
replacement from non-routine activities in the NSR context.
    However, the AAGRAP is based on the invested cost of the facility, 
not the replacement cost, which may or may not require us to make some 
adjustments. Also, there are some industries for which an AAGRAP is not 
available. The policy reasons behind the use of AAGRAP in the tax 
context also may not be the same as those we need to consider in the 
NSR context, notwithstanding the fact that the AAGRAP has been used in 
the NSPS context. Finally, the IRS has moved to other approaches. We 
solicit comment on the extent to which the AAGRAP, or some derivative 
of the AAGRAP, may appropriately be employed if we determine that a 
safe harbor based on replacement cost is preferable.
    There are also standard reference manuals that provide cost 
estimation information that is considered to be up to date. Plant 
Design and Economics for Chemical Engineers, by Peters and Timmerhaus, 
and Perry's Chemical Engineer's Handbook, by Perry and Green, are two 
widely used resources. They provide a range of annual maintenance and 
repair costs from 2 percent to 10 percent of the fixed capital 
investment of the stationary source. These two resources, however, are 
limited to the chemical process industry and may not have broader 
applicability to other industry sectors (although there may be 
comparable resources for other industries). Based on information 
contained in the resources mentioned above, the appropriate annual 
maintenance percentages would be in the range of 0.5 percent to 20 
percent, depending on the industry.
    To the extent that we have data, we intend in the final rule to set 
different percentages for specific industry categories. In selecting 
appropriate industry-specific percentages, it would be helpful if 
further information is made available to us during the public comment 
period for this proposal; therefore, we are requesting that information 
relating to types of maintenance, repair and replacement activities 
undertaken and costs associated with those activities be provided 
during the public comment period on this proposed rule. For example, 
relevant information for the electric utility industry might be 
available from the NERC/GADS database, the Federal Energy Regulatory 
Commission, or the Integrated Environmental Control Model maintained by 
the Energy and Environmental Center at Carnegie-Mellon University. 
Commenters should provide actual source, company or industry 
information, as well as any other data underlying summaries. 
Substantiated claims and estimates will be given greater consideration 
than information not supported by actual data. If there is a lack of 
information with which to set industry specific percentages, we may 
elect to set a default value. We are seeking comment on the appropriate 
default percentage to be used, and/or methods available to determine 
that percentage.

E. How To Calculate Costs

    In order for a cost-based approach to be equitable, all owners or 
operators must include the same categories of expenses in both the 
replacement cost and the cost sought to be covered by the allowance. 
Therefore, we believe it may be appropriate to require that costs be 
calculated using an approach along the lines set out as the elements of 
Total Capital Investment as defined in the EPA Air Pollution Control 
Cost Manual (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

[[Page 80299]]

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.
    We invite comment on whether we should use the manual as the 
mechanism for standardizing these calculations, whether we should use 
other manuals, or whether it might make sense to give sources a range 
of manuals whose approach to this question we believe may be 
appropriate for their circumstances. We also invite comment on whether 
EPA should require use of the manuals identified or simply provide 
assurance that if methods in an identified manual are used, EPA will 
accept them.
    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 would be excluded from the 
cost calculation. For the purposes of this maintenance, repair and 
replacement allowance, we believe that equipment that serves a dual 
purpose of process equipment and control equipment (that is, 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. We ask for comment on this 
point.
    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 (that is, 
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 are also considering whether or not to exclude costs associated 
with the unanticipated shutdown of equipment, due to component failure 
or catastrophic failures such as explosions or fires, from the costs 
that must be included in the allowance. If costs associated with 
unanticipated outages are excluded, these activities would be subjected 
to a case-by-case review of NSR applicability. We request comment on 
whether or not repairs and replacements resulting from the 
unanticipated shutdown of equipment, or of an entire source, should be 
included in the annual maintenance, repair and replacement allowance 
calculations.

F. Applicability Safeguards

    We are proposing to include some safeguards in our rules. There are 
some relatively inexpensive activities that can be undertaken at a 
facility that we believe should not be included within the maintenance, 
repair and replacement allowance because, due to their very nature, 
they may significantly alter the design of the source or they may 
result in significantly greater emissions. Ineligibility for the 
allowance does not mean that the activities will necessarily be subject 
to NSR. These activities will still be eligible for treatment as RMRR 
under a case-by-case review, may qualify for other exclusions, may not 
require a major NSR permit because of emissions limitations in a 
synthetic minor limitation, or may be netted out of NSR applicability. 
We are proposing to include three such safeguards. (See Sec.  
51.165(a)(1)(xxxxii)(B), Sec.  51.166(b)(53)(ii), Sec.  
52.21(b)(55)(ii), and Sec.  52.24(f)(25)(ii) of proposed rules.)
    The first of the safeguards is that no new process unit may be 
added under the annual maintenance, repair and replacement allowance. 
The addition of a new process unit is not maintenance, repair or 
replacement of existing equipment at a stationary source in order to 
ensure continued safe and reliable operation and hence should not 
qualify for the allowance.
    The second safeguard is that an owner or operator may not use the 
maintenance, repair and replacement allowance to replace an entire 
process unit. We do not believe that replacement of an entire process 
unit should qualify for the allowance. Because of their nature, 
wholesale exchanges of a process unit should be subject to greater 
scrutiny in determining NSR applicability than use of the maintenance, 
repair and replacement allowance would entail.
    The third safeguard is not allowing any activity that results in an 
increase in maximum achievable hourly emissions rate of a regulated NSR 
pollutant at the stationary source or in the emission of any regulated 
NSR pollutant not previously emitted to be excluded under the annual 
maintenance, repair and replacement allowance. Such activities are more 
likely to result in possible significant emissions increases and, 
therefore, should not be excluded from NSR on the basis that they fall 
within the maintenance, repair and replacement allowance. We request 
comment on the appropriateness and adequacy of these proposed 
safeguards or any additional safeguards that may be appropriate.

G. Timing of Determination

    Under the annual maintenance, repair and replacement allowance as 
proposed, an owner or operator will sum the costs of maintenance, 
repair and replacement activities from least to most expensive to 
determine which activities are excluded pursuant to the allowance. 
Actual activity costs will not be known until activities are underway 
or completed. We have considered two options for the timing of the 
decision regarding qualification of activities under the annual 
maintenance, repair and replacement allowance when summing activities 
in this manner. The first is to require application of the allowance 
prior to construction based on planned activities and estimated costs. 
The second is to perform an end-of-year reconciliation after the 
activity costs are known.
    If an end-of-year reconciliation is used, actual costs incurred 
would be known. However, if costs exceed the annual maintenance, repair 
and replacement allowance, some activities that have already been 
started or completed will have to be evaluated on a case-by-case basis 
unless already excluded from major NSR on some other basis. If it is 
determined that the activity is not RMRR and does not qualify for 
another exclusion, and it results in a significant emissions increase 
and a significant net emissions increase, and it is consequently 
subject to the requirements of NSR, the owner or operator would be in 
violation of the CAA for failure to obtain the necessary permit prior 
to commencing construction. In addition, if in a nonattainment area, 
the owner or operator could be required to obtain offsets, which may 
not be readily available in the area. The owner or operator may also be 
faced with penalties for constructing without a permit.
    In practice, however, we do not believe this scenario is likely to 
occur. We expect that an owner or operator who intended to rely on the 
annual maintenance, repair and replacement allowance would have planned 
the year's activities accordingly and would be tracking activities 
throughout the year in order to avoid this situation.
    We believe requiring an end-of-year reconciliation strikes a 
reasonable balance, since it will lead owners or operators to make 
preconstruction

[[Page 80300]]

estimates of activities and costs in order to determine qualification 
for the exclusion but will not require them to become involved in 
permitting-type actions with respect to excluded activities. Finally, 
it is not possible for an owner or operator to plan all maintenance, 
repair and replacement needs, so there will be inaccuracies in any 
estimation no matter how diligent an owner or operator may be in 
seeking to plan these activities.
    We have considered two other possible ways to address this 
situation. The first is to allow any unplanned activity to undergo a 
case-by-case determination of RMRR. However, this method might create 
an incentive to omit smaller, less expensive activities from the 
preconstruction estimation in order to avoid a case-by-case review on 
larger activities. The second is to make ineligible for the use of the 
maintenance, repair and replacement allowance any activity that was not 
included in the preconstruction estimation. But that seems 
unreasonable, since as noted above actual activity costs may be 
unintentionally underestimated or omitted, resulting in actual activity 
costs exceeding the annual maintenance, repair and replacement 
estimates.
    After considering the options, we believe that an evaluation based 
on actual data rather than estimates is preferable. Careful planning by 
an owner or operator should reduce the likelihood that the annual 
allowance is exceeded for activities that the owner believes will come 
within the allowance. Moreover, a prudent owner or operator who 
believes his RMRR activities will be close to exceeding the allowance 
will determine whether more costly activities are otherwise excluded, 
evaluate them under the case-by-case test, or seek an applicability 
determination or a permit to assure compliance with NSR requirements. 
Therefore, we are proposing to determine qualification for the 
exclusion through an end-of-year reconciliation. (See Sec.  
51.165(a)(1)(xxxxii)(A)(5), Sec.  51.166(b)(53)(i)(e), Sec.  
52.21(b)(55)(i)(e), and Sec.  52.24(f)(25)(i)(e) of proposed rules).
    One other possible approach to this question would be to sum costs 
in the order they occur, rather than from least expensive to most 
expensive.
    Under that approach, an owner or operator would maintain a running 
total of maintenance, repair and replacement costs and could determine 
before beginning construction on a subsequent activity if there was 
room under the annual maintenance, repair and replacement allowance. 
However, this process might encourage an owner or operator to delay 
less costly activities in order to use the annual maintenance, repair 
and replacement allowance for activities that are both larger and more 
atypical and, therefore, might not qualify for RMRR treatment.
    Maintaining the least expensive to most expensive methodology 
discussed above, we could address the issue through an expedited case-
by-case review of larger activities. An owner or operator would be 
responsible for obtaining a case-by-case determination from the 
reviewing authority for larger activities to ensure that an activity 
would still be considered RMRR if it is later found that the activity 
could not be accommodated under the annual maintenance, repair and 
replacement allowance. This, however, is inconsistent with our intent 
that owners or operators be able to use these provisions without 
obtaining an advance determination from the reviewing authority.
    Finally, rather than establishing an annual cost threshold to 
define what activities fit within the allowance, we could establish a 
threshold per activity. Activities whose costs fell below the threshold 
could proceed as RMRR. Activities with costs above the threshold would 
be ineligible to use the allowance, and thus could only constitute RMRR 
if they either fell within the portion of the RMRR exclusion for 
equipment replacements or constitute RMRR upon an application of the 
case-by-case test. We are proposing a similar approach for replacement 
of equipment with functional equivalents. But we believe that any 
broader activity-based approach would have the undesirable consequence 
of forcing industry and the reviewing authorities to address 
potentially complex questions about how to define whether activities 
are truly separate and hence below the threshold or whether they are 
part of some larger activity that exceeds the threshold.
    To summarize, at this time we are proposing an annual maintenance, 
repair and replacement allowance; to sum activities from least 
expensive to most expensive to determine eligibility; and an end-of-
year review and report. We request comment on each of these aspects of 
the proposal and any additional approaches that commenters wish to 
recommend.

VII. Discussion of Issues Under the Equipment Replacement Approach

    We recognize that there are numerous occasions when, to maintain, 
facilitate, restore, or improve efficiency, reliability, availability, 
or safety within normal facility operations, facilities replace 
existing equipment with either identical equipment or equipment that 
serves the same function. Such replacements may be conducted 
immediately after component failure or they may be conducted 
preventively to assure a source's continued safe, reliable and 
efficient operation. We believe that many such replacements typically 
should be considered RMRR activities. But, allowing replacement of 
equipment with ``functionally equivalent'' or ``identical'' equipment 
to qualify as RMRR, if unbounded, could theoretically allow replacement 
of an entire production line or utility boiler. Thus, there must also 
be some reasonable bound to equipment replacements that qualify.
    The following discussion addresses key considerations in 
determining the appropriate boundary for the types of replacement 
activities that should be excluded under the equipment replacement 
provision of the RMRR exclusion.

A. Replacement of Existing Equipment With Identical or Functionally 
Equivalent Equipment

    One of today's proposals deals with replacing equipment with 
identical or functionally equivalent equipment. This proposal is based 
on our view that most replacements of existing equipment that are 
necessary for the safe, efficient, and reliable operation of 
practically all industrial operations are not of regulatory concern and 
should qualify for the RMRR exclusion. Industrial facilities are 
constructed with the understanding that 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 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

[[Page 80301]]

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. 
For example, when worn out pipes are replaced in a chemical process 
plant, the replacement pipes sometimes are constructed of new or 
different materials to help reduce corrosion, erosion, or chemical 
compatibility problems.
    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 must be installed.
    A good example was presented to us by the forest products industry 
during our review of the NSR program's impacts on the energy sector. A 
company in that sector needed to replace outdated analog controllers at 
a series of six batch digesters. 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. 
The source determined that this activity would not be considered 
routine under today's NSR rules and decided not to proceed with the 
project.
    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 (for example, for 
electric utility steam generating units, this would mean maximum heat 
input and fuel consumption specifications). Efficiency, however, should 
not be considered 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.
    We also note, however, that taken to the extreme, even without a 
change in basic design parameters, an identical or functionally 
equivalent replacement activity can still go beyond the bounds of the 
RMRR exclusion. For example, instead of replacing a pump, what if a 
chemical manufacturing facility replaced an entire production unit? 
Even if the replacement was identical, we likely would not consider the 
activity to be an excluded replacement. Such an activity effectively 
constitutes construction of a new process unit in much the same way the 
construction of an entirely new process unit at an existing stationary 
source could not constitute RMRR. This is not the kind of activity that 
sources typically engage in to maintain their plants, and it is the 
kind of activity that would likely be a logical point for owners or 
operators to install state-of-the-art controls.
    We recognize 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 unit. At the same 
time, we believe it is important to provide some clear parameters for 
making this determination.
    To that end, we are soliciting comment on an equipment replacement 
cost approach based on the NSPS program to determine whether identical 
or functionally equivalent replacement activities constitute RMRR 
without regard to other considerations. Under the NSPS program, a 
project at an existing affected source triggers any applicable NSPS 
when the cost of the project 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. 40 CFR 60.15(b). In essence, such a ``reconstruction'' 
is tantamount to new construction and, therefore, triggers any 
applicable NSPS even if the project would otherwise be excluded.
    We recognize that, in some respects, an equipment replacement cost 
threshold such as the NSPS reconstruction test may be viewed as the 
proper tool to be used in the future for distinguishing between routine 
and non-routine identical and functionally equivalent replacements 
under the NSR program. As noted above, we do not believe it is 
reasonable to exclude from NSR activities that involve the total 
replacement of an existing entire process unit. By extension, it is 
therefore logical and consistent to conclude that activities which, 
based on their cost, effectively constitute replacement of the process 
unit should not qualify as RMRR. Thus, we believe that the 50 percent 
capital replacement threshold used under the NSPS might constitute an 
appropriate limitation on when identical or functionally equivalent 
replacements should qualify as RMRR under the equipment replacement 
provision without regard to other considerations.
    We also recognize, however, that there are other considerations 
pointing in favor of a threshold lower than the 50 percent 
reconstruction threshold that may be appropriate to bound the equipment 
replacement provision. For example, since under NSPS half of the 
capital replacement value of an existing affected facility effectively 
constitutes construction of a new unit, it could be argued that some 
percentage less than the 50 percent reconstruction threshold might be a 
suitable line of demarcation in determining whether identical 
replacements constitute a modification of an existing unit.
    We are soliciting comment on whether the proposed approach is 
workable, whether the capital replacement percentage should be 50 
percent or another lesser percentage, and whether different percentages 
should apply to different industrial groupings or different types of 
industrial processes. For example, it may be appropriate to set a 
higher percentage for process operations that involve heat and 
corrosive compounds. Such processes may require more expensive 
replacements, and a greater degree of maintenance activities than other 
types of processes. In addition, we solicit comment on whether this 
equipment replacement provision should be implemented on a component-
by-component basis, or some other reasoned basis such as applying the 
percentage to components that are replaced collectively over a fixed 
period of time.
    We recognize that there are widely divergent views as to how 
expansive the RMRR exclusion should be. From our perspective, the most 
important thing we can do to improve air quality in the United States 
with respect to stationary sources is to make substantial reductions in 
NOX and SO2 emissions

[[Page 80302]]

from facilities in the utility sector. Our current view, however, is 
that if the rules clearly establish a narrow RMRR exclusion and set out 
to require permits for replacement of larger components or the 
replacement of components with more efficient ones, owners or operators 
will comply with these rules but will find ways to make the 
replacements without having to obtain permits and install state-of-the-
art controls. As a result, such rules will not achieve significant 
reductions in NOX or SO2 on a prospective basis. 
As discussed below, these owners or operators will likely avoid having 
to make such reductions through one of several ways plainly permissible 
under NSR.
    For example, when a power plant operator plans to undertake an 
activity that the operator believes may not qualify as RMRR and is 
assessing compliance alternatives, that operator is faced with three 
options: (1) Proceed with the activity pursuant to an NSR permit, which 
could require more than $100 million to be spent on air pollution 
controls; (2) forego the activity, which likely would result in a 
permanent reduction in capacity or utilization of the facility or might 
reduce efficiency and increase emissions per unit of product 
manufactured or energy produced; or (3) proceed with the activity, but 
take steps to limit future emissions such that the activity would not 
result in a significant net emissions increase.
    We also believe that few owners or operators would choose the first 
option. This option would make economic sense only in circumstances 
where the current capacity and utilization of the facility are so low 
that the major investment in air pollution controls would provide an 
incrementally better payback than the option of investing the same 
money in other assets or in the development of a new power plant.
    We also believe that few owners or operators would elect the second 
option. It makes no sense in most cases for the owners or operators of 
costly power plants to let these assets significantly deteriorate over 
time, because the value of the asset will eventually be lost.
    We believe that most owners or operators would select the third 
option. We note that industry commenters during our review of the 
impact of NSR on the energy sector argued that this option would, over 
time, result in a substantial reduction in the capacity of their 
facilities. For example, the Tennessee Valley Authority reported that, 
over the last 20 years, it would have lost 32 percent of its coal 
system's energy capability if it had capped emissions under a 
``narrow'' routine maintenance exclusion. In similar analyses, Southern 
Company estimated that it would have experienced an energy shortfall of 
57.5 million MW-hr, and First Energy estimated that it would have lost 
39 percent of its coal-fired generating capacity between 1981 and 2000. 
West Associates, the Western System Coordinating Council, and the 
National Rural Electric Cooperative Association reported similar 
results.
    Notwithstanding these assessments, we believe that most owners or 
operators would proceed with activities and take emissions limitations. 
To the extent that such limitations might curtail full utilization of 
the facility, incremental control measures of modest cost would likely 
be taken to recover the ``lost'' utilization. For example, use of a 
slightly lower sulfur coal could produce the marginally lower 
SO2 emissions that would be needed to recapture some 
capacity. Likewise, various types of relatively low-cost combustion or 
process control modifications could be employed to reduce 
NOX emissions.
    Thus, it is not probable that owners or operators would respond to 
a narrow exclusion by installing state-of-the-art controls every time 
they need to replace a major component. At the same time, a narrow RMRR 
exclusion of this type would not allow in many cases the replacement of 
equipment with equipment that improves process efficiency. This would 
cause owners or operators to forego replacements that would improve air 
quality because they would allow greater efficiency.
    For these reasons, a narrow RMRR exclusion that is clearly 
established is not expected to achieve significant reductions in 
historic emissions levels, and might even lead to area wide emissions 
increases. Most facilities would take lawful steps to avoid having to 
obtain an NSR permit that would impose strict limitations, even when 
replacements would be found under this narrow exclusion to be non-
routine.

B. Defining ``Process Unit'' for Evaluating Equipment Replacement Cost 
Percentage

    In this section, we discuss issues related to what collection of 
equipment should be considered in applying the equipment replacement 
approach. We are proposing the term ``process unit'' as the appropriate 
collection. A definition of process unit currently is included in 40 
CFR 63.41. We have built upon that definition to accommodate the 
intended coverage of activities under the equipment replacement 
approach. The purpose of this term is, as best as possible, to align 
implementation of the provision with generally accepted and practical 
understandings of what constitutes a discrete production process. The 
general definition would 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.

    Our primary goal in defining this term is to encompass integrated 
manufacturing operations that produce a completed product rather than 
smaller pieces of such operations.
    To help illustrate these concepts, we developed and have included 
in the proposed rules some industry-specific examples of how this 
definition might be applied. The examples are drawn from a few selected 
industry categories--electric utilities, refineries, cement 
manufacturers, pulp and paper producers, and incinerators. Because of 
the centrality of the ``process unit'' concept to the usefulness of the 
equipment replacement provision, it is our desire to include a version 
of these examples in the final rule to make sure sources have a 
benchmark against which they can evaluate with greater confidence 
whether a particular replacement comes within the equipment replacement 
provision of the RMRR exclusion. We also request comment on whether 
associated pollution control equipment should typically not be 
considered part of the process unit. We are proposing to exclude such 
equipment from the definition.
    [sbull] For a steam electric generating facility, the process unit 
would consist of those portions of the plant that contribute directly 
to the production of electricity. For example, at a pulverized coal-
fired facility, the process unit would generally be the combination of 
those systems from the coal receiving equipment through the emission 
stack, including the coal handling equipment, pulverizers or coal 
crushers, feedwater heaters, boiler, burners, turbine-generator set, 
air preheaters, and operating control systems. Each separate generating 
unit would be considered a separate process unit. Components shared 
between two or more process units would be proportionately allocated 
based on capacity.
    [sbull] For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as boilers and hydrogen production; and 
those that load, unload, blend or store products.

[[Page 80303]]

    [sbull] For a cement plant, the process unit would generally 
consist of the kiln and equipment that supports it, including all 
components that process or store raw materials, preheaters, and 
components that process or store products from the kilns, and 
associated emission stacks.
    [sbull] For a pulp and paper mill, there are several types of 
process units. One is the system that processes wood products, another 
is the digester and its associated heat exchanger, blow tank, pulp 
filter, accumulator, oxidation tower, and evaporators. A third is the 
chemical recovery system, which includes the recovery furnace, lime 
kiln, storage vessels, and associated oxidation processes feeding 
regenerated chemicals to the digester.
    [sbull] For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    We solicit comment on the proposed definition of ``process unit'' 
and whether another approach might be more effective. We also solicit 
comment on the particular process units identified in specific 
industries, whether there are better ways of identifying those process 
units in those industries, and whether other process units should be 
specifically identified as part of the rule.
    Finally, today's proposed approaches for replacement of existing 
equipment with identical or functionally equivalent equipment rely on 
the concept of a process unit, but it is possible that it is not 
appropriate for replacement of non-emitting components because such 
replacements may not have emissions consequences in the first place and 
hence would not warrant scrutiny under NSR. Similarly, it is possible 
that maintenance, repair and replacement activities performed on non-
emitting units should not be included in the activities that would have 
to be accounted for under the annual maintenance, repair and 
replacement allowance provision of the RMRR exclusion. We solicit 
comment on how these various activities should be handled in the 
context of today's proposal, bearing in mind that forthcoming proposed 
NSR rules for future activities involving debottlenecking will 
specifically address changes made at non-emitting units that affect 
emissions at other process units at a stationary source among other 
issues. However, we request comment on limiting today's proposed 
approaches to changes made at emitting units or modifying them so as to 
differentiate between changes made at emitting versus non-emitting 
units.

C. Miscellaneous Issues

    In addition to the issues noted above, we also request comment on 
the following matters. First, we solicit comments on the topic of basic 
design parameters. Our proposal states that maximum heat input and fuel 
consumption specifications (for electric utility steam generating 
units) and maximum material/fuel input specifications (for other types 
of units) are basic design parameters. We solicit comment on whether 
that provides sufficient definition of this term, whether further 
definition is appropriate, or whether there are industry-specific 
considerations that should be taken into account.
    Second, in calculating costs, we propose that owners or operators 
should use the same principles and guidelines as discussed above with 
respect to calculating costs for the maintenance, repair and 
replacement allowance. We request comment on whether these same 
principles and requirements are applicable and workable for the 
equipment replacement provision.
    Third, in addition to soliciting comment on the approaches 
described above, we are also soliciting comment on whether the 
maintenance, repair and replacement allowance and this equipment 
replacement provision should both be adopted or whether just the 
equipment replacement provision is sufficient? In addition, if we 
assume that both approaches are adopted, how should they work together? 
Should an RMRR activity that is excluded under the equipment 
replacement provision also count against your annual maintenance, 
repair and replacement allowance? We are soliciting comment on whether 
to adopt any or all of these approaches and how they might fit 
together.
    Lastly, EPA strongly supports efforts to improve energy efficiency 
at existing power plants. These activities reduce the amount of 
criteria pollutants (SO2 and NOX) emitted per 
unit of electricity generated and also reduce greenhouse gas emissions. 
During our study of the impact of NSR on the energy sector, we received 
information concerning a number of instances where activities that 
would have improved energy efficiency were not implemented because they 
would have resulted in significant annual emission increases that would 
have triggered NSR. Some have commented that any activity that produces 
any improvement in energy efficiency should be exempt from NSR. 
However, given the continuing improvement in materials and design, 
almost any component replacement can be expected to have some 
beneficial impact on the energy efficiency of the unit and, left 
unbounded, this approach could result in the replacement of an entire 
boiler with a new, more efficient boiler without state-of-the-art 
pollution controls. As mentioned above, however, we do not think 
replacement of an entire boiler is properly viewed as routine. We also 
do not believe that the need to install state-of-the-art controls on 
new boilers will deter sources from installing new boilers if they are 
otherwise prepared to do so.
    These issues prompt EPA to solicit comment in several areas. To the 
extent that an activity is the replacement of existing equipment that 
serves the same function as the equipment replaced, does not alter the 
basic design parameters of the process unit, and otherwise meets the 
provisions of our proposed equipment replacement approach, described 
above, it would be excluded from NSR under the proposal. There may, 
however, be rare instances where activities do not involve replacing 
existing equipment, are not otherwise excluded from NSR, and 
nevertheless promote efficiency. Is there a need for a separate 
``stand-alone'' exclusion for such activities? If so, should there be 
other limitations on the scope of such activities? Are there activities 
that result in a minor improvement in efficiency but a very large 
increase in annual emissions? If so, what are the characteristics of 
such activities and how should EPA treat them? Today, we solicit 
comment broadly on the impact of the NSR program on decisions to 
proceed with activities that produce net benefits to human health and 
the environment, including, but not limited, to energy efficiency 
activities. We also solicit comments on the extent to which our 
proposals can promote energy efficiency while preserving the benefits 
of the NSR program.

D. Quantitative Analysis

    We have attempted to analyze quantitatively the possible emissions 
consequences of the range of different approaches to the RMRR exclusion 
described above 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 think the results for the electric utilities accurately 
reflects the trends we would see in other industries. This model and 
technical

[[Page 80304]]

information describing it can be found in the docket. The analysis 
included several relevant scenarios. In the first scenario, we assumed 
that efficiency and capacity of relevant units modestly decrease over 
time. This scenario was intended to reflect the consequences of a new 
rule with a relatively ``narrow'' RMRR exclusion, under which we would 
assume that there would be slow and steady deterioration of relevant 
generating assets. As explained above, we do not actually believe that 
such a trend would occur under such a new RMRR exclusion, because 
plants would take steps to limit emissions and perhaps implement 
incremental controls to recapture lost capacity. Nevertheless, we 
believe that this scenario offers a bounding analysis for seeing 
whether a narrow RMRR exclusion can have significant emissions benefits 
because our model assumes well controlled and highly efficient new 
generating assets rather than recaptured capacity from incrementally 
better controlled existing units.
    In the other scenarios, we assumed that utilization, efficiency, or 
capacity of relevant units modestly increases over time. These 
scenarios were intended to reflect the consequences of a new rule with 
a ``broader'' RMRR exclusion, which would allow facility availability 
and/or output over time without triggering major NSR. These scenarios 
present various combinations of assumptions on possible incremental 
changes to relevant operational parameters and are intended to 
encompass the range of possible operational outcomes that might be 
associated with the proposed RMRR exclusion.
    The IPM analyses of these scenarios proves the point made above, 
that the breadth of the RMRR exclusion would have no practical impact 
on, let alone being the controlling factor in determining, the 
emissions reductions that will be achieved in the future under the 
major NSR program. The analyses show that emissions of SO2 
are essentially the same under all scenarios. This stands to reason 
because nationwide emissions of SO2 from the power sector 
are capped by the title IV Acid Rain Program. For NOX, these 
analyses show 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 if the 
options under consideration are adopted. What these analyses indicate, 
however, is that regardless of which scenario is closest to what comes 
to pass, none of the proposed provisions related to the RMRR exclusion 
will have a significant impact on emissions from the power sector.
    The DOE also attempted to analyze quantitatively the possible 
emissions consequences of the range of different approaches to the RMRR 
exclusion described above. 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 
changes. This analysis concluded that efficiency improvements resulting 
from increased maintenance are expected to decrease emissions, whereas 
availability improvements are expected to increase emissions. In the 
cases represented in this analysis, the impacts of the assumed 
reductions in heat rates tend to dominate the corresponding effects of 
the assumed availability increases.
    Data regarding the emissions reductions that are achieved under 
other CAA programs further illustrate the relative limits of the major 
NSR program as a tool for achieving significant emissions reductions. 
For example, the title IV Acid Rain Program has reduced SO2 
emissions from the electric utility industry by more than 7 million tpy 
and will ultimately result in reductions of approximately 10 million 
tpy. The Tier 2 motor vehicle emissions standards and gasoline sulfur 
control requirements will ultimately achieve NOX reductions 
of 2.8 million tpy. Standards for highway heavy-duty vehicles and 
engines will reduce NOX emissions by 2.6 million tpy. 
Standards for non-road diesel engines are anticipated to reduce 
NOX emissions by about 1.5 million tpy. The NOX 
``SIP call'' will reduce NOX emissions by over 1 million 
tpy. Altogether, these and other similar programs achieve emissions 
reductions that far exceed those attributable to the major NSR program 
and dwarf any possible emissions consequences attributable to future 
promulgation of a rule based on today's proposal.
    A copy of our IPM analysis and the DOE NEMS analysis are included 
in the docket for this rulemaking. We ask for comment on all aspects of 
these analyses and on the policy discussion provided above.

VIII. Other Options Considered

    In addition to the cost-based approaches discussed above, we are 
considering two additional options for addressing RMRR. These options 
are discussed below, and we are requesting comment on these options. We 
are also interested in other possible alternatives.

A. Capacity-Based Option

    We are considering 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 did 
not increase the capacity of the process unit. Such an approach would 
require safeguards similar to those in the proposed cost-based 
approaches in order to ensure that activities that should be subject to 
the NSR program are not inappropriately excluded. These safeguards 
would exclude the construction of a new process unit, the replacement 
of an entire process unit, and activities that result in an increase in 
maximum achievable hourly emissions rate of a regulated NSR pollutant 
from use of the exclusion or the emission of any regulated NSR 
pollutant not previously emitted by the stationary source.
    Basing RMRR on capacity is appealing 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 cost and environmental 
impact. Finally, this type of approach might, in principle, be easier 
to use before beginning actual construction than the cost-based 
approaches.
    The difficulty with using a capacity-based approach is 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. As an example, in a review of promulgated 
and proposed Maximum Achievable Control Technology standards, six of 
eleven standards measured capacity based on unit output while five 
based capacity on input. In fact, the NSPS exclusion for increases in 
production rate at 40 CFR 60.14(e) originally was dependent upon the 
``operating design capacity'' of an affected unit. In proposed 
revisions to the NSPS program published on October 15, 1974, we state 
(39 FR 36948):

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


[[Page 80305]]


    We are requesting comment on this capacity-based option, as well as 
comments on possible methods to address any of the issues relating to 
implementation of such an option.

B. Age-Based Option

    Under an age-based approach, any process unit under a specified age 
could undergo any activity that does not increase the capacity of a 
process unit on a maximum hourly basis without triggering the 
requirements of the major NSR program. However, the activities could 
not constitute reconstruction of the process unit; that is, their cost 
could not exceed 50 percent of the cost of a replacement process unit. 
The age of the process unit would likely be in the range of 25-50 
years. An owner or operator would have to become a Clean Unit as 
defined at 40 CFR 51.165(c)(3), 51.166(t)(3), and 52.21(x)(3), once the 
age of a process unit exceeds the age threshold.
    Such an approach would provide an owner or operator a clear 
understanding of RMRR for an extended period of time. It also may 
provide the owner or operator greater flexibility than under the 
current system for a limited period of time. Like the capacity-based 
approach, this approach would, in principle, allow for a fairly simple 
preconstruction determination of applicability.
    We see several difficulties in developing this type of approach. 
The first is defining capacity. The second is establishing the age cut-
off for the exclusion. The useful life of equipment is difficult to 
establish and may vary greatly. The third is that some of the 
activities that would be allowed at newer sources do not fit within any 
ordinary meaning of RMRR and some of the activities that would be 
forbidden at older facilities would come within that meaning. Fourth, 
some sources may consciously, and appropriately, engage in aggressive 
RMRR as a method of maximizing the life span of its process units, and 
an age-based approach would discriminate against them.
    We are requesting comment on this age-based option, as well as 
comments on possible methods to address the issues raised above with 
respect to this option.

IX. Administrative Requirements for This Proposed Rulemaking

A. Executive Order 12866--Regulatory Planning and Review

    Under Executive Order 12866 [58 FR 51,735 (October 4, 1993)], we 
must determine whether the regulatory action is ``significant'' and 
therefore subject to review by the Office of Management and Budget 
(OMB) and the requirements of the Executive Order. The Executive Order 
defines ``significant regulatory action'' as one that is likely to 
result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs, or the rights and obligations of 
recipients thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, OMB has notified us 
that it considers this an ``economically significant regulatory 
action'' within the meaning of the Executive Order. We have submitted 
this action to OMB for review. Changes made in response to OMB 
suggestions or recommendations will be documented in the public record. 
All written comments from OMB to EPA and any written EPA response to 
any of those comments are included in the docket listed at the 
beginning of this notice under ADDRESSES. In addition, consistent with 
Executive Order 12866, EPA consulted extensively with the State, local 
and tribal agencies that will be affected by this rule. We have also 
sought involvement from industry and public interest groups.

B. Executive Order 13132--Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August 
10, 1999), requires us to develop an accountable process to ensure 
``meaningful and timely input by State and local officials in the 
development of regulatory policies that have federalism implications.'' 
``Policies that have federalism implications'' are defined in the 
Executive Order to include regulations that have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
    This proposed rule does not have federalism implications. 
Nevertheless, in developing this rule, we consulted with affected 
parties and interested stakeholders, including State and local 
authorities, to enable them to provide timely input in the development 
of this rule. A summary of stakeholder involvement appears above in 
section III.C. of today's proposed rule. It will not have substantial 
direct effects on the States, on the relationship between the national 
government and the State and local programs, or on the distribution of 
power and responsibilities among the various levels of government, as 
specified in Executive Order 13132. While this proposed rule will 
result in some expenditures by the States, we expect those expenditures 
to be limited to $580,160 for the estimated 112 affected reviewing 
authorities. This figure includes the small increase in burden imposed 
upon reviewing authorities in order for them to revise the State's 
State Implementation Plan (SIP). However, this revision provides 
sources permitted by the States greater certainty in application of the 
program, which should in turn reduce the overall burden of the program 
on State and local authorities. Thus, the requirements of Executive 
Order 13132 do not apply to this rule.

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

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 6, 2000), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by tribal officials in the development of regulatory 
policies that have tribal implications.'' EPA believes that this 
proposed rule does not have tribal implications as specified in 
Executive Order 13175. Thus, Executive Order 13175 does not apply to 
this rule.
    The purpose of today's proposed rule is to add greater flexibility 
to the existing major NSR regulations. These changes will benefit 
reviewing authorities and the regulated community, including any major 
source owned by a tribal government or located in or near tribal land, 
by providing increased certainty as to when the requirements of the NSR 
program apply. Taken as a whole, today's proposed rule should result in 
no added burden or compliance costs and should not substantially change 
the level of environmental performance achieved under the previous 
rules.
    The EPA anticipates that initially these changes will result in a 
small increase in the burden imposed upon reviewing authorities in 
order for them to be included in the State's SIP. Nevertheless, these 
options and revisions will ultimately provide greater operational 
flexibility to sources

[[Page 80306]]

permitted by the States, which will in turn reduce the overall burden 
on the program on State and local authorities by reducing the number of 
required permit modifications. In comparison, no tribal government 
currently has an approved Tribal Implementation Plan (TIP) under the 
CAA to implement the NSR program. The Federal government is currently 
the NSR reviewing authority in Indian country. Thus, tribal governments 
should not experience added burden, nor should their laws be affected 
with respect to implementation of this rule. Additionally, although 
major stationary sources affected by today's proposed rule could be 
located in or near Indian country and/or be owned or operated by tribal 
governments, such affected sources would not incur additional costs or 
compliance burdens as a result of this rule. Instead, the only effect 
on such sources should be the benefit of the added certainty and 
flexibility provided by the rule.
    The EPA recognizes the importance of including tribal consultation 
as part of the rulemaking process. Nonetheless, to this point we have 
not specifically consulted with tribal officials on this proposed rule. 
We are committed to work with any tribal government to resolve any 
issues that we may have overlooked in today's proposed rules and that 
may have an adverse impact in Indian country. As a result, today we are 
announcing our intention to develop and implement a consultation 
process with tribal governments to ensure that the concerns of tribal 
officials are considered before finalizing this proposed rule. EPA 
specifically solicits additional comment on this proposed rule from 
tribal officials.

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

    Executive Order 13045, ``Protection of Children from Environmental 
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies 
to any rule that (1) is determined to be ``economically significant'' 
as defined under Executive Order 12866, and (2) concerns an 
environmental health or safety risk that EPA has reason to believe may 
have a disproportionate effect on children. If the regulatory action 
meets both criteria, we must evaluate the environmental health or 
safety effects of the planned rule on children and explain why the 
planned regulation is preferable to other potentially effective and 
reasonable alternatives that we considered.
    This proposed rule is not subject to Executive Order 13045, because 
we do not have reason to believe the environmental health or safety 
risks addressed by this action present a disproportionate risk to 
children. We believe that this package as a whole will result in equal 
or better environmental protection than currently provided by the 
existing regulations, and do so in a more streamlined and effective 
manner.

E. Paperwork Reduction Act

    The EPA prepared an Information Collection Request (ICR) document 
(ICR No. 1713.04). You may obtain a copy from Sandy Farmer by mail at 
the U.S. Environmental Protection Agency, Office of Environmental 
Information, Collection Strategies Division (2822), 1200 Pennsylvania 
Avenue, NW., Washington, DC 20460-0001, by e-mail at 
[email protected], or by calling (202) 260-2740. A copy may also be 
downloaded from the internet at http://www.epa.gov/icr.
    The information that ICR No. 1713.04 covers is required for EPA to 
carry out its required oversight function of reviewing preconstruction 
permits and assuring adequate implementation of the program. In order 
to carry out its oversight function, EPA must have available to it 
information on proposed construction and modifications. This 
information collection is necessary for the proper performance of EPA's 
functions, has practical utility, and is not unnecessarily duplicative 
of information we otherwise can reasonably access. We have reduced, to 
the extent practicable and appropriate, the burden on persons providing 
the information to or for EPA. The collection of information is 
authorized under 42 U.S.C. 7401 et seq.
    According to ICR No. 1713.04, the first 3 years of this proposed 
rulemaking will potentially incur a burden of 17,400 hours and 
1,305,000 dollars to affected sources, and 2,906 hours and 107,522 
dollars for the Federal government, and 15,680 hours and 580,160 hours 
for reviewing authorities. These costs are based upon an estimated 
number of 1,450 affected sources.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purpose of responding to the information 
collection; adjust existing ways to comply with any previously 
applicable instructions and requirements; train personnel to respond to 
a collection of information; search existing data sources; complete and 
review the collection of information; and transmit or otherwise 
disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15. We will 
continue to present OMB control numbers in a consolidated table format 
to be codified in 40 CFR part 9 of the Agency's regulations, and in 
each CFR volume containing EPA regulations. The table lists the section 
numbers with reporting and record keeping requirements, and the current 
OMB control numbers. This listing of the OMB control numbers and their 
subsequent codification in the CFR satisfy the requirements of the 
Paperwork Reduction Act (44 U.S.C. 3501 et seq.) and OMB's implementing 
regulations at 5 CFR part 1320.

F. Regulatory Flexibility Act (RFA), as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et 
seq.

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions. For purposes of assessing the impacts of 
today's rule on small entities, small entity is defined as: (1) Any 
small business employing fewer than 500 employees; (2) a small 
governmental jurisdiction that is a government of a city, county, town, 
school district or special district with a population of less than 
50,000; and (3) a small organization that is any not-for-profit 
enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of today's proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. In 
determining whether a rule has a significant economic impact on a 
substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the

[[Page 80307]]

proposed rule on small entities.'' 5 U.S.C. 603 and 604. Thus, an 
agency may certify that a rule will not have a significant economic 
impact on a substantial number of small entities if the rule relieves 
regulatory burden, or otherwise has a positive economic effect on all 
of the small entities subject to the rule. Today's proposed rule will 
not have a significant economic impact on a substantial number of small 
entities because it will decrease the regulatory burden of the existing 
regulations and have a positive effect on all small entities subject to 
the rule. This rule improves operational flexibility for owners and 
operators of major stationary sources and clarifies applicable 
requirements for determining if a change qualifies as a major 
modification. We have therefore concluded that today's proposed rule 
will relieve regulatory burden for all small entities. We continue to 
be interested in the potential impacts of the proposed rule on small 
entities and welcome comments on issues related to such impacts.

G. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of UMRA, we 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires us to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows us to adopt an alternative other than the least 
costly, most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    Before we establish any regulatory requirements that may 
significantly or uniquely affect small governments, including tribal 
governments, we must have developed under section 203 of the UMRA a 
small government agency plan. The plan must provide for notifying 
potentially affected small governments, enabling officials of affected 
small governments to have meaningful and timely input in the 
development of our regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    We believe the proposed rule changes will actually reduce the 
regulatory burden associated with the major NSR program by improving 
the operational flexibility of owners and operators and clarifying the 
requirements. Because the program changes provided in the proposed rule 
are not expected to result in any increases in the expenditure by 
State, local, and tribal governments, or the private sector, we have 
not prepared a budgetary impact statement or specifically addressed the 
selection of the least costly, most cost-effective, or least burdensome 
alternative. Because small governments will not be significantly or 
uniquely affected by this rule, we are not required to develop a plan 
with regard to small governments. Therefore, this proposed rule is not 
subject to the requirements of section 203 of the UMRA.

H. National Technology Transfer and Advancement Act of 1995

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law No. 104-113, section 12(d) (15 U.S.C. 
272 note) directs us to use voluntary consensus standards (VCS) in our 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. VCS are technical standards 
(for example, materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. The NTTAA directs us to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable VCS.
    Although this rule does involve the use of technical standards, it 
does not preclude the State, local, and tribal reviewing agencies from 
using VCS. Today's proposed rulemaking is an improvement of the 
existing NSR permitting program. As such, it only ensures that 
promulgated technical standards are considered and appropriate controls 
are installed, prior to the construction of major sources of air 
emissions. Therefore, we are not considering the use of any VCS in 
today's rulemaking.

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

    This proposed rule is not a ``significant energy action'' as 
defined in Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355 
(May 22, 2001)) because it is not likely to have a significant adverse 
effect on the supply, distribution or use of energy.
    Today's proposed rule improves the ability of sources to maintain 
the reliability of production facilities, and effectively utilize and 
improve existing capacity.

X. Statutory Authority

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

List of Subjects in 40 CFR Parts 51 and 52

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Intergovernmental relations, Reporting and 
recordkeeping requirements.

    Dated: November 22, 2002.
Christine Todd Whitman,
Administrator.

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

PART 51--[AMENDED]

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

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

Subpart I--[Amended]

    2. Section 51.165 is amended:
    a. By revising paragraph (a)(1)(v)(C)(1).
    b. By adding paragraphs (a)(1)(xliii) through (xlvii).
    The revision and additions read as follows:


Sec.  51.165  Permit requirements.

    (a) * * *
    (1) * * *
    (v) * * *
    (C) * * *
    (1) Routine maintenance, repair and replacement, which shall 
include but not be limited to the activities set out in paragraphs 
(a)(1)(v)(C)(1)(i) and (ii) of

[[Page 80308]]

this section. Without regard to other considerations, the activities 
specified in paragraphs (a)(1)(v)(C)(1)(i) and (ii) shall constitute 
routine maintenance, repair and replacement:
    (i) Activities performed at a stationary source in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, whose total cost, 
when added together with the total costs of all previous activities 
performed at the same stationary source in the same year in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, does not exceed that 
stationary source's annual maintenance, repair and replacement 
allowance. ``Annual maintenance, repair and replacement allowance'' is 
defined in paragraph (a)(1)(xliii) of this section. Rules for 
calculation and summation of costs are provided in paragraph 
(a)(1)(xliii)(A) of this section. A stationary source may elect to 
calculate an annual maintenance, repair and replacement allowance for 
either all or none, but not some, of the maintenance, repair, and 
replacement activities performed at the stationary source.
    (ii) The replacement of components of a process unit with identical 
or functionally equivalent components, provided that: The fixed capital 
cost of the components does not exceed [x] \1\ percent of the fixed 
capital cost that would be required to construct an entirely new 
process unit; and the replacement does not change the basic design 
parameters of the process unit. The basic design parameters for 
electric utility steam generating units are maximum heat input and fuel 
consumption specifications. For non-utilities, basic design parameters 
are the maximum fuel or material input specifications to the process 
unit. An improvement in efficiency does not change a process unit's 
basic design parameters. ``Functionally equivalent components'' and 
``fixed capital cost'' are defined in paragraphs (a)(1)(xlv) and 
(a)(1)(xlvi) of this section, respectively.
---------------------------------------------------------------------------

    \1\ EPA has not determined this value.
---------------------------------------------------------------------------

* * * * *
    (xliii) Annual maintenance, repair and replacement allowance means 
a dollar amount calculated according to the following equation: 
(Industry sector percentage) x (replacement cost of the stationary 
source) where ``industry sector percentage'' is drawn from Table 1 of 
this section.

   Table 1 of Sec.   51.165(a)(1)(xliii).--Industry Sector Percentages
------------------------------------------------------------------------
                                                             Industry
                     Industry sector                          sector
                                                            percentage
------------------------------------------------------------------------
Electric Services
Petroleum Refining
Chemical Processes
Natural Gas Transport
Pulp and Paper Mills
Paper Mills
Automobile Manufacturing
Pharmaceuticals
Other
------------------------------------------------------------------------

    (A) A stationary source's annual maintenance costs shall be 
calculated and summed according to the following rules:
    (1) The owner or operator may choose to sum costs over either a 
calendar year or initially specified fiscal year. The initially 
specified fiscal year must remain in use unless other accounting 
procedures at the stationary source subsequently change to a different 
fiscal year.
    (2) Costs incurred for all activities performed at the stationary 
source in order to maintain, facilitate, restore or improve the 
efficiency, reliability, availability or safety of that stationary 
source that are not excluded under paragraph (a)(1)(xliii)(B) of this 
section, or that have not been issued a preconstruction permit, shall 
be tracked chronologically and summed at the end of the year.
    (i) At the end of the year, these costs shall be listed and summed 
in order from least cost to highest cost.
    (ii) All activities prior to the point on the cost-ordered list at 
which the sum of activity costs exceeds the annual maintenance, repair 
and replacement allowance shall automatically qualify as routine 
maintenance, repair, or replacement.
    (3) Costs associated with maintaining or installing pollution 
control equipment shall not be included in the calculation and 
summation of costs for routine maintenance, repair, and replacement. 
Costs shall remain included if they are associated with maintaining or 
installing equipment that serves a dual function as both process and 
control equipment.
    (4) The owner or operator shall provide an annual report to the 
reviewing authority containing complete information on all maintenance, 
repair and replacement costs and process unit replacement cost 
estimates at the stationary source. The report shall be provided within 
60 days after the end of the year over which activity costs have been 
summed.
    (B) An activity otherwise eligible for inclusion in the annual 
maintenance, repair and replacement allowance shall not be eligible to 
be included in the allowance if it:
    (1) Results in an increase in the maximum achievable hourly 
emissions rate of the stationary source of a regulated NSR pollutant, 
or results in emissions of a regulated NSR pollutant not previously 
emitted;
    (2) Constitutes construction of a new process unit; or
    (3) Removes an entire existing process unit and installs a 
different process unit in its place.
    (xliv)(A) In general, 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 stationary source may contain more than one process 
unit.
    (B) The following list identifies the process units at specific 
kinds of stationary sources.
    (1) For a steam electric generating facility, the process unit 
would consist of those portions of the plant which contribute directly 
to the production of electricity. For example, at a pulverized coal-
fired facility, the process unit would generally be the combination of 
those systems from the coal receiving equipment through the emission 
stack, including the coal handling equipment, pulverizers or coal 
crushers, feedwater heaters, boiler, burners, turbine-generator set, 
air preheaters, and operating control systems. Each separate generating 
unit would be considered a separate process unit. Components shared 
between two or more process units would be proportionately allocated 
based on capacity.
    (2) For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as boilers and hydrogen production; and 
those that load, unload, blend or store products.
    (3) For a cement plant, the process unit would generally consist of 
the kiln and equipment that supports it, including all components that 
process or store raw materials, preheaters, and components that process 
or store products from the kilns, and associated emission stacks.
    (4) For a pulp and paper mill, there are several types of process 
units. One is the system that processes wood products, another is the 
digester and its associated heat exchanger, blow tank, pulp filter, 
accumulator, oxidation tower, and evaporators. A third is the

[[Page 80309]]

chemical recovery system, which includes the recovery furnace, lime 
kiln, storage vessels, and associated oxidation processes feeding 
regenerated chemicals to the digester.
    (5) For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    (xlv) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    (xlvi) Fixed capital cost means the capital needed to provide all 
the depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (a)(1)(xlvii) of this section.
    (xlvii) Total capital investment means the sum of the following: 
all costs required to purchase needed process equipment (purchased 
equipment costs); the costs of labor and materials for installing that 
equipment (direct installation costs); the costs of site preparation 
and buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
* * * * *
    3. Section 51.166 is amended:
    a. By revising paragraph (b)(2)(iii)(a).
    b. By adding paragraphs (b)(53) through (57). The revision and 
additions read as follows:


Sec.  51.166  Prevention of significant deterioration of air quality.

* * * * *
    (b) * * *
    (2) * * *
    (iii) * * *
    (a) Routine maintenance, repair and replacement, which shall 
include but not be limited to the activities set out in paragraphs 
(b)(2)(iii)(a)(1) and (2) of this section. Without regard to other 
considerations, the activities specified in paragraphs 
(b)(2)(iii)(a)(1) and (2) shall constitute routine maintenance, repair 
and replacement:
    (1) Activities performed at a stationary source in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, whose total cost, 
when added together with the total costs of all previous activities 
performed at the same stationary source in the same year in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, does not exceed that 
stationary source's annual maintenance, repair and replacement 
allowance. ``Annual maintenance, repair and replacement allowance'' is 
defined in paragraph (b)(53) of this section. Rules for calculation and 
summation of costs are provided in paragraph (b)(53)(i) of this 
section. A stationary source may elect to calculate an annual 
maintenance, repair and replacement allowance for either all or none, 
but not some, of the maintenance, repair, and replacement activities 
performed at the stationary source.
    (2) The replacement of components of a process unit with identical 
or functionally equivalent components, provided that:
    (i) The fixed capital cost of the components does not exceed [x]\1\ 
percent of the fixed capital cost that would be required to construct 
an entirely new process unit; and
---------------------------------------------------------------------------

    \1\ EPA has not determined this value.
---------------------------------------------------------------------------

    (ii) The replacement does not change the basic design parameters of 
the process unit. The basic design parameters for electric utility 
steam generating units are maximum heat input and fuel consumption 
specifications. For non-utilities, basic design parameters are the 
maximum fuel or material input specifications to the process unit. An 
improvement in efficiency does not change a process unit's basic design 
parameters. ``Functionally equivalent components'' and ``fixed capital 
cost'' are defined in paragraphs (b)(55) and (b)(56) of this section.
* * * * *
    (53) Annual maintenance, repair and replacement allowance means a 
dollar amount calculated according to the following equation: (Industry 
sector percentage) x (replacement cost of the stationary source) where 
``industry sector percentage'' is drawn from Table 1 of this section.

      Table 1 of Sec.   51.166(b)(53).--Industry Sector Percentages
------------------------------------------------------------------------
                                                             Industry
                     Industry sector                          sector
                                                            percentage
------------------------------------------------------------------------
Electric Services
Petroleum Refining
Chemical Processes
Natural Gas Transport
Pulp and Paper Mills
Paper Mills
Automobile Manufacturing
Pharmaceuticals
Other
------------------------------------------------------------------------

    (i) A stationary source's annual maintenance costs shall be 
calculated and summed according to the following rules:
    (a) The owner or operator may choose to sum costs over either a 
calendar year or initially specified fiscal year. The initially 
specified fiscal year must remain in use unless other accounting 
procedures at the stationary source subsequently change to a different 
fiscal year.
    (b) Costs incurred for all activities performed at the stationary 
source in order to maintain, facilitate, restore, or improve the 
efficiency, reliability, availability, or safety of that stationary 
source that are not excluded under paragraph (b)(53)(ii) of this 
section, or that have not been issued a preconstruction permit, shall 
be tracked chronologically and summed at the end of the year.
    (1) At the end of the year, these costs shall be listed and summed 
in order from least cost to highest cost.
    (2) All activities prior to the point on the cost-ordered list at 
which the sum of activity costs exceeds the annual maintenance, repair 
and replacement allowance shall automatically qualify as routine 
maintenance, repair, or replacement.
    (c) Costs associated with maintaining or installing pollution 
control equipment shall not be included in the calculation and 
summation of costs for routine maintenance, repair, and replacement. 
Costs shall remain included if they are associated with maintaining or 
installing equipment that serves a dual function as both process and 
control equipment.
    (d) The owner or operator shall provide an annual report to the 
reviewing authority containing complete information on all maintenance, 
repair and replacement costs and process unit replacement cost 
estimates at the stationary source. The report shall be provided within 
60 days after the end of the year over which activity costs have been 
summed.
    (ii) An activity otherwise eligible for inclusion in the annual 
maintenance, repair and replacement allowance shall not be eligible to 
be included in the allowance if it:
    (a) Results in an increase in the maximum achievable hourly 
emissions

[[Page 80310]]

rate of the stationary source of a regulated NSR pollutant, or results 
in emissions of a regulated NSR pollutant not previously emitted;
    (b) Constitutes construction of a new process unit; or
    (c) Removes an entire existing process unit and installs a 
different process unit in its place.
    (54)(i) In general, 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 stationary source may contain more than one process unit.
    (ii) The following list identifies the process units at specific 
kinds of stationary sources.
    (a) For a steam electric generating facility, the process unit 
would consist of those portions of the plant which contribute directly 
to the production of electricity. For example, at a pulverized coal-
fired facility, the process unit would generally be the combination of 
those systems from the coal receiving equipment through the emission 
stack, including the coal handling equipment, pulverizers or coal 
crushers, feedwater heaters, boiler, burners, turbine-generator set, 
air preheaters, and operating control systems. Each separate generating 
unit would be considered a separate process unit. Components shared 
between two or more process units would be proportionately allocated 
based on capacity.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as boilers and hydrogen production; and 
those that load, unload, blend or store products.
    (c) For a cement plant, the process unit would generally consist of 
the kiln and equipment that supports it, including all components that 
process or store raw materials, preheaters, and components that process 
or store products from the kilns, and associated emission stacks.
    (d) For a pulp and paper mill, there are several types of process 
units. One is the system that processes wood products, another is the 
digester and its associated heat exchanger, blow tank, pulp filter, 
accumulator, oxidation tower, and evaporators. A third is the chemical 
recovery system, which includes the recovery furnace, lime kiln, 
storage vessels, and associated oxidation processes feeding regenerated 
chemicals to the digester.
    (e) For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    (55) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    (56) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (b)(57) of this section.
    (57) Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased 
equipment costs); the costs of labor and materials for installing that 
equipment (direct installation costs); the costs of site preparation 
and buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
* * * * *

Appendix S--[Amended]

    4. In Appendix S to Part 51 Section II is amended:
    a. By revising paragraph A.5(iii) (a).
    b. By adding paragraphs A.21 through 25.
    The revision and additions read as follows:

Appendix S to part 51--Emission Offset Interpretative Ruling

* * * * *

II. Initial Screening Analyses and Determination of Applicable 
Requirements

    A. * * *
    5. * * *
    (iii) * * *
    (a) Routine maintenance, repair and replacement, which shall 
include but not be limited to the activities set out in paragraphs A.5 
(iii)(a)(1) and (2) of this section. Without regard to other 
considerations, the activities specified in paragraphs A.5 (iii)(a)(1) 
and (2) shall constitute routine maintenance, repair and replacement:
    (1) Activities performed at a stationary source in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, whose total cost, 
when added together with the total costs of all previous activities 
performed at the same stationary source in the same year in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, does not exceed that 
stationary source's annual maintenance, repair and replacement 
allowance. ``Annual maintenance, repair and replacement allowance'' is 
defined in paragraph A.21 of this section. Rules for calculation and 
summation of costs are provided in paragraph A.21 (i) of this section. 
A stationary source may elect to calculate an annual maintenance, 
repair and replacement allowance for either all or none, but not some, 
of the maintenance, repair, and replacement activities performed at the 
stationary source.
    (2) The replacement of components of a process unit with identical 
or functionally equivalent components, provided that:
    (i) The fixed capital cost of the components does not exceed [x] 
\1\ percent of the fixed capital cost that would be required to 
construct an entirely new process unit; and
---------------------------------------------------------------------------

    \1\ EPA has not determined this value.
---------------------------------------------------------------------------

    (ii) The replacement does not change the basic design parameters of 
the process unit. The basic design parameters for electric utility 
steam generating units are maximum heat input and fuel consumption 
specifications. For non-utilities, basic design parameters are the 
maximum fuel or material input specifications to the process unit. An 
improvement in efficiency does not change a process unit's basic design 
parameters. ``Functionally equivalent components'' and ``fixed capital 
cost'' are defined in paragraphs A.23 and A.24 of this section, 
respectively.
* * * * *
    21. Annual maintenance, repair and replacement allowance means a 
dollar amount calculated according to the following equation: (Industry 
sector percentage) x (replacement cost of the stationary source) where 
``industry sector percentage'' is drawn from Table 1 of this section.

        Table 1. of Section II.A.21.--Industry Sector Percentages
------------------------------------------------------------------------
                                                             Industry
                     Industry sector                          sector
                                                            percentage
------------------------------------------------------------------------
Electric Services
Petroleum Refining
Chemical Processes
Natural Gas Transport
Pulp and Paper Mills
Paper Mills
Automobile Manufacturing
Pharmaceuticals

[[Page 80311]]

 
Other
------------------------------------------------------------------------

    (i) A stationary source's annual maintenance costs shall be 
calculated and summed according to the following rules:
    (a) The owner or operator may choose to sum costs over either a 
calendar year or initially specified fiscal year. The initially 
specified fiscal year must remain in use unless other accounting 
procedures at the stationary source subsequently change to a different 
fiscal year.
    (b) Costs incurred for all activities not performed at the 
stationary source in order to maintain, facilitate, restore or improve 
the efficiency, reliability, availability or safety of that stationary 
source that are not excluded under A.21 (ii) of this section, or that 
have not been issued a preconstruction permit, shall be tracked 
chronologically and summed at the end of the year.
    (1) At the end of the year, these costs shall be listed and summed 
in order from least cost to highest cost.
    (2) All activities prior to the point on the cost-ordered list at 
which the sum of activity costs exceeds the annual maintenance, repair 
and replacement allowance shall automatically qualify as routine 
maintenance, repair, or replacement.
    (c) Costs associated with maintaining or installing pollution 
control equipment shall not be included in the calculation and 
summation of costs for routine maintenance, repair, and replacement. 
Costs shall remain included if they are associated with maintaining or 
installing equipment that serves a dual function as both process and 
control equipment.
    (d) The owner or operator shall provide an annual report to the 
reviewing authority containing complete information on all 
maintenance, repair and replacement costs and process unit 
replacement cost estimates at the stationary source. The report 
shall be provided within 60 days after the end of the year over 
which activity costs have been summed.
    (ii) An activity otherwise eligible for inclusion in the annual 
maintenance, repair and replacement allowance shall not be eligible 
to be included in the allowance if it:
    (a) Results in an increase in the maximum achievable hourly 
emissions rate of the stationary source of a regulated NSR 
pollutant, or results in emissions of a regulated NSR pollutant not 
previously emitted;
    (b) Constitutes construction of a new process unit; or
    (c) Removes an entire existing process unit and installs a 
different process unit in its place.
    22. (i) In general, 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 stationary source may contain more than 
one process unit.
    (ii) The following list identifies the process units at specific 
kinds of stationary sources.
    (a) For a steam electric generating facility, the process unit 
would consist of those portions of the plant which contribute 
directly to the production of electricity. For example, at a 
pulverized coal-fired facility, the process unit would generally be 
the combination of those systems from the coal receiving equipment 
through the emission stack, including the coal handling equipment, 
pulverizers or coal crushers, feedwater heaters, boilers, burners, 
turbine-generator set, air preheaters, and operating control 
systems. Each separate generating unit would be considered a 
separate process unit. Components shared between two or more process 
units would be proportionately allocated based on capacity.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum feedstocks; 
those that change molecular structures; petroleum treating 
processes; auxiliary facilities, such as boilers and hydrogen 
production; and those that load, unload, blend or store products.
    (c) For a cement plant, the process unit would generally consist 
of the kiln and equipment that supports it, including all components 
that process or store raw materials, preheaters, and components that 
process or store products from the kilns, and associated emission 
stacks.
    (d) For a pulp and paper mill, there are several types of 
process units. One is the system that processes wood products, 
another is the digester and its associated heat exchanger, blow 
tank, pulp filter, accumulator, oxidation tower, and evaporators. A 
third is the chemical recovery system, which includes the recovery 
furnace, lime kiln, storage vessels, and associated oxidation 
processes feeding regenerated chemicals to the digester.
    (e) For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    23. Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    24. Fixed capital cost means the capital needed to provide all 
the depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting 
land and working capital from the total capital investment, as 
defined in paragraph A.25 of this section.
    25. Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased 
equipment costs); the costs of labor and materials for installing 
that equipment (direct installation costs); the costs of site 
preparation and buildings; other costs such as engineering, 
construction and field expenses, fees to contractors, startup and 
performance tests, and contingencies (indirect installation costs); 
land for the process equipment; and working capital for the process 
equipment.
* * * * *

PART 52--[AMENDED]

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

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

Subpart A--[Amended]

    2. Section 52.21 is amended:
    a. By revising paragraph (b)(2)(iii)(a).
    b. By adding paragraphs (b)(55) through (59).
    The revision and additions are revised to read as follows:


Sec.  52.21  Prevention of significant deterioration of air quality.

* * * * *
    (b) * * *
    (2) * * *
    (iii) * * *
    (a) Routine maintenance, repair and replacement, which shall 
include but not be limited to the activities set out in paragraphs 
(b)(2)(iii)(a)(1) and (2) of this section. Without regard to other 
considerations, the activities specified in paragraphs 
(b)(2)(iii)(a)(1) and (2) shall constitute routine maintenance, repair 
and replacement:
    (1) Activities performed at a stationary source in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, whose total cost, 
when added together with the total costs of all previous activities 
performed at the same stationary source in the same year in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, does not exceed that 
stationary source's annual maintenance, repair and replacement 
allowance. ``Annual maintenance, repair and replacement allowance'' is 
defined in paragraph (b)(55) of this section. Rules for calculation and 
summation of costs are provided in paragraph (b)(55)(i) of this 
section. A stationary source may elect to calculate an annual 
maintenance, repair and replacement allowance for either all or none, 
but not some, of the maintenance, repair, and replacement activities 
performed at the stationary source.
    (2) The replacement of components of a process unit with identical 
or

[[Page 80312]]

functionally equivalent components, provided that:
    (i) The fixed capital cost of the components does not exceed [x]\1\ 
percent of the fixed capital cost that would be required to construct 
an entirely new process unit; and
---------------------------------------------------------------------------

    \1\ EPA has not determined this value.
---------------------------------------------------------------------------

    (ii) The replacement does not change the basic design parameters of 
the process unit. The basic design parameters for electric utility 
steam generating units are maximum heat input and fuel consumption 
specifications. For non-utilities, basic design parameters are the 
maximum fuel or material input specifications to the process unit. An 
improvement in efficiency does not change a process unit's basic design 
parameters. ``Functionally equivalent components'' and ``fixed capital 
cost'' are defined in paragraphs (b)(57) and (b)(58) of this section.
* * * * *
    (55) Annual maintenance, repair and replacement allowance means a 
dollar amount calculated according to the following equation: (Industry 
sector percentage) x (replacement cost of the stationary source) where 
``industry sector percentage'' is drawn from Table 1 of this section.

      Table 1 of Sec.   52.21(b)(55).--Industry Sector Percentages
------------------------------------------------------------------------
                                                             Industry
                     Industry sector                          sector
                                                            percentage
------------------------------------------------------------------------
Electric Services
Petroleum Refining
Chemical Processes
Natural Gas Transport
Pulp and Paper Mills
Paper Mills
Automobile Manufacturing
Pharmaceuticals
Other
------------------------------------------------------------------------

    (i) A stationary source's annual maintenance costs shall be 
calculated and summed according to the following rules:
    (a) The owner or operator may choose to sum costs over either a 
calendar year or initially specified fiscal year. The initially 
specified fiscal year must remain in use unless other accounting 
procedures at the stationary source subsequently change to a different 
fiscal year.
    (b) Costs incurred for all activities not performed at the 
stationary source in order to maintain, facilitate, restore or improve 
the efficiency, reliability, availability or safety of that stationary 
source that are not excluded under paragraph (b)(55)(ii) of this 
section, or that have not been issued a preconstruction permit, shall 
be tracked chronologically and summed at the end of the year.
    (1) At the end of the year, these costs shall be listed and summed 
in order from least cost to highest cost.
    (2) All activities prior to the point on the cost-ordered list at 
which the sum of activity costs exceeds the annual maintenance, repair 
and replacement allowance shall automatically qualify as routine 
maintenance, repair, or replacement.
    (c) Costs associated with maintaining or installing pollution 
control equipment shall not be included in the calculation and 
summation of costs for routine maintenance, repair, and replacement. 
Costs shall remain included if they are associated with maintaining or 
installing equipment that serves a dual function as both process and 
control equipment.
    (d) The owner or operator shall provide an annual report to the 
reviewing authority containing complete information on all maintenance, 
repair and replacement costs and process unit replacement cost 
estimates at the stationary source. The report shall be provided within 
60 days after the end of the year over which activity costs have been 
summed.
    (ii) An activity otherwise eligible for inclusion in the annual 
maintenance, repair and replacement allowance shall not be eligible to 
be included in the allowance if it:
    (a) Results in an increase in the maximum achievable hourly 
emissions rate of the stationary source of a regulated NSR pollutant, 
or results in emissions of a regulated NSR pollutant not previously 
emitted;
    (b) Constitutes construction of a new process unit; or
    (c) Removes an entire existing process unit and installs a 
different process unit in its place.
    (56) (i) In general, 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 stationary source may contain more than one process 
unit.
    (ii) The following list identifies the process units at specific 
kinds of stationary sources.
    (a) For a steam electric generating facility, the process unit 
would consist of those portions of the plant which contribute directly 
to the production of electricity. For example, at a pulverized coal-
fired facility, the process unit would generally be the combination of 
those systems from the coal receiving equipment through the emission 
stack, including the coal handling equipment, pulverizers or coal 
crushers, feedwater heaters, boiler, burners, turbine-generator set, 
air preheaters, and operating control systems. Each separate generating 
unit would be considered a separate process unit. Components shared 
between two or more process units would be proportionately allocated 
based on capacity.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum feedstocks; 
those that change molecular structures; petroleum treating processes; 
auxiliary facilities, such as boilers and hydrogen production; and 
those that load, unload, blend or store products.
    (c) For a cement plant, the process unit would generally consist of 
the kiln and equipment that supports it, including all components that 
process or store raw materials, preheaters, and components that process 
or store products from the kilns, and associated emission stacks.
    (d) For a pulp and paper mill, there are several types of process 
units. One is the system that processes wood products, another is the 
digester and its associated heat exchanger, blow tank, pulp filter, 
accumulator, oxidation tower, and evaporators. A third is the chemical 
recovery system, which includes the recovery furnace, lime kiln, 
storage vessels, and associated oxidation processes feeding regenerated 
chemicals to the digester.
    (e) For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    (57) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    (58) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (b)(59) of this section.
    (59) Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased 
equipment costs); the costs of labor and materials for installing that 
equipment (direct installation costs); the costs of site preparation 
and buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and

[[Page 80313]]

contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
* * * * *
    3. Section 52.24 is amended:
    a. By revising paragraph (f)(5)(iii)(a).
    b. By adding paragraphs (f)(25) through (29).
    The revision and additions read as follows:


Sec.  52.24  Statutory restriction on new sources.

* * * * *
    (f) * * *
    (5) * * *
    (iii) * * *
    (a) Routine maintenance, repair and replacement, which shall 
include but not be limited to the activities set out in paragraphs 
(f)(5)(iii)(a)(1) and (2) of this section. Without regard to other 
considerations, the activities specified in paragraphs 
(f)(5)(iii)(a)(1) and (2) shall constitute routine maintenance, repair 
and replacement:
    (1) Activities performed at a stationary source in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, whose total cost, 
when added together with the total costs of all previous activities 
performed at the same stationary source in the same year in order to 
maintain, facilitate, restore or improve the efficiency, reliability, 
availability or safety of that stationary source, does not exceed that 
stationary source's annual maintenance, repair and replacement 
allowance. ``Annual maintenance, repair and replacement allowance'' is 
defined in paragraph (f)(25) of this section. Rules for calculation and 
summation of costs are provided in paragraph (f)(25)(i) of this 
section. A stationary source may elect to calculate an annual 
maintenance, repair and replacement allowance for either all or none, 
but not some, of the maintenance, repair, and replacement activities 
performed at the stationary source.
    (2) The replacement of components of a process unit with identical 
or functionally equivalent components, provided that:
    (i) The fixed capital cost of the components does not exceed [x] 
\1\ percent of the fixed capital cost that would be required to 
construct an entirely new process unit; and
---------------------------------------------------------------------------

    \1\ EPA has not determined this value.
---------------------------------------------------------------------------

    (ii) The replacement does not change the basic design parameters of 
the process unit. The basic design parameters for electric utility 
steam generating units are maximum heat input and fuel consumption 
specifications. For non-utilities, basic design parameters are the 
maximum fuel or material input specifications to the process unit. An 
improvement in efficiency does not change a process unit's basic design 
parameters. ``Functionally equivalent components'' and ``fixed capital 
cost'' are defined in paragraphs (f)(27) and (f)(28) of this section, 
respectively.
* * * * *
    (25) Annual maintenance, repair and replacement allowance means a 
dollar amount calculated according to the following equation: (Industry 
sector percentage) x (replacement cost of the stationary source) where 
``industry sector percentage'' is drawn from Table 1 of this section.

      Table 1 of Sec.   52.24(f)(25).--Industry Sector Percentages
------------------------------------------------------------------------
                                                             Industry
                     Industry sector                          sector
                                                            percentage
------------------------------------------------------------------------
Electric Services
Petroleum Refining
Chemical Processes
Natural Gas Transport
Pulp and Paper Mills
Paper Mills
Automobile Manufacturing
Pharmaceuticals
Other
------------------------------------------------------------------------

    (i) A stationary source's annual maintenance costs shall be 
calculated and summed according to the following rules:
    (a) The owner or operator may choose to sum costs over either a 
calendar year or initially specified fiscal year. The initially 
specified fiscal year must remain in use unless other accounting 
procedures at the stationary source subsequently change to a different 
fiscal year.
    (b) Costs incurred for all activities not performed at the 
stationary source in order to maintain, facilitate, restore or improve 
the efficiency, reliability, availability or safety of that stationary 
source that are not excluded under paragraph (f)(25)(ii) of this 
section, or that have not been issued a preconstruction permit, shall 
be tracked chronologically and summed at the end of the year.
    (1) At the end of the year, these costs shall be listed and summed 
in order from least cost to highest cost.
    (2) All activities prior to the point on the cost-ordered list at 
which the sum of activity costs exceeds the annual maintenance, repair 
and replacement allowance shall automatically qualify as routine 
maintenance, repair, or replacement.
    (c) Costs associated with maintaining or installing pollution 
control equipment shall not be included in the calculation and 
summation of costs for routine maintenance, repair, and replacement. 
Costs shall remain included if they are associated with maintaining or 
installing equipment that serves a dual function as both process and 
control equipment.
    (d) The owner or operator shall provide an annual report to the 
reviewing authority containing complete information on all maintenance, 
repair and replacement costs and process unit replacement cost 
estimates at the stationary source. The report shall be provided within 
60 days after the end of the year over which activity costs have been 
summed.
    (ii) An activity otherwise eligible for inclusion in the annual 
maintenance, repair and replacement allowance shall not be eligible to 
be included in the allowance if it:
    (a) Results in an increase in the maximum achievable hourly 
emissions rate of the stationary source of a regulated NSR pollutant, 
or results in emissions of a regulated NSR pollutant not previously 
emitted;
    (b) Constitutes construction of a new process unit; or
    (c) Removes an entire existing process unit and installs a 
different process unit in its place.
    (26) (i) In general, 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 stationary source may contain more than one process 
unit.
    (ii) The following list identifies the process units at specific 
kinds of stationary sources.
    (a) For a steam electric generating facility, the process unit 
would consist of those portions of the plant which contribute directly 
to the production of electricity. For example, at a pulverized coal-
fired facility, the process unit would generally be the combination of 
those systems from the coal receiving equipment through the emission 
stack, including the coal handling equipment, pulverizers or coal 
crushers, feedwater heaters, boiler, burners, turbine-generator set, 
air preheaters, and operating control systems. Each separate generating 
unit would be considered a separate process unit. Components shared 
between two or more process units would be proportionately allocated 
based on capacity.
    (b) For a petroleum refinery, there are several categories of 
process units: those that separate and distill petroleum

[[Page 80314]]

feedstocks; those that change molecular structures; petroleum treating 
processes; auxiliary facilities, such as boilers and hydrogen 
production; and those that load, unload, blend or store products.
    (c) For a cement plant, the process unit would generally consist of 
the kiln and equipment that supports it, including all components that 
process or store raw materials, preheaters, and components that process 
or store products from the kilns, and associated emission stacks.
    (d) For a pulp and paper mill, there are several types of process 
units. One is the system that processes wood products, another is the 
digester and its associated heat exchanger, blow tank, pulp filter, 
accumulator, oxidation tower, and evaporators. A third is the chemical 
recovery system, which includes the recovery furnace, lime kiln, 
storage vessels, and associated oxidation processes feeding regenerated 
chemicals to the digester.
    (e) For an incinerator, the process unit would consist of 
components from the feed pit or refuse pit to the stack, including 
conveyors, combustion devices, heat exchangers and steam generators, 
quench tanks, and fans.
    (27) Functionally equivalent component means a component that 
serves the same purpose as the replaced component.
    (28) Fixed capital cost means the capital needed to provide all the 
depreciable components. ``Depreciable components'' refers to all 
components of fixed capital cost and is calculated by subtracting land 
and working capital from the total capital investment, as defined in 
paragraph (f)(29) of this section.
    (29) Total capital investment means the sum of the following: all 
costs required to purchase needed process equipment (purchased 
equipment costs); the costs of labor and materials for installing that 
equipment (direct installation costs); the costs of site preparation 
and buildings; other costs such as engineering, construction and field 
expenses, fees to contractors, startup and performance tests, and 
contingencies (indirect installation costs); land for the process 
equipment; and working capital for the process equipment.
* * * * *
[FR Doc. 02-31900 Filed 12-30-02; 8:45 am]
BILLING CODE 6560-50-P