[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 svendsgaard.dave@epa.gov.
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.
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Industry group SEC a NAICS b
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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
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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 a-and-r-docket@epamail.epa.gov, 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.
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\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
farmer.sandy@epa.gov, 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