Browse by Year
/ 2003
/ October
/ Monday, October 27, 2003
[Federal Register: October 27, 2003 (Volume 68, Number 207)]
[Rules and Regulations]
[Page 61247-61280]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr27oc03-16]
[[Page 61247]]
-----------------------------------------------------------------------
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 51 and 52
Prevention of Significant Deterioration (PSD) and Non-Attainment New
Source Review (NSR): Equipment Replacement Provision of the Routine
Maintenance, Repair and Replacement Exclusion; Final Rule
[[Page 61248]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51 and 52
[FRL-7575-9; RIN 2060-AK28; Electronic Docket OAR-2002-0068; Legacy
Docket A-2002-04]
Prevention of Significant Deterioration (PSD) and Non-Attainment
New Source Review (NSR): Equipment Replacement Provision of the Routine
Maintenance, Repair and Replacement Exclusion
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The EPA is finalizing revisions to the regulations governing
the NSR programs mandated by parts C and D of title I of the Clean Air
Act (CAA). Today's changes reflect EPA's incorporation of comments from
the proposed rule for ``Prevention of Significant Deterioration (PSD)
and Non-attainment New Source Review (NSR): Routine Maintenance, Repair
and Replacement.'' These changes provide a category of equipment
replacement activities that are not subject to Major NSR requirements
under the routine maintenance, repair and replacement (RMRR) exclusion.
The changes are intended to provide greater regulatory certainty
without sacrificing the current level of environmental protection and
benefit derived from the NSR program. We believe that these changes
will facilitate the safe, efficient, and reliable operation of affected
facilities.
EFFECTIVE DATE: This final rule is effective on December 26, 2003.
ADDRESSES: Docket. Docket No. A-2002-04 (Electronic docket OAR-2002-
0068), containing supporting information used to develop the proposed
rule and today's final rule, is available for public inspection and
copying between 8:00 a.m. and 4:30 p.m., Monday through Friday (except
government holidays) at the Air and Radiation Docket and Information
Center (6102T), Room B-108, EPA West Building, 1301 Constitution
Avenue, NW, Washington, D.C. 20460; telephone (202) 566-1742, fax (202)
566-1741. A reasonable fee may be charged for copying docket materials.
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of this final rule will also be available on the WWW
through the Technology Transfer Network (TTN). Following signature, a
copy of the rule will be posted on the TTN's policy and guidance page
for newly proposed or promulgated rules: http://www.epa.gov/ttn/oarpg.
FOR FURTHER INFORMATION CONTACT: Mr. Dave Svendsgaard, Information
Transfer and Program Integration Division (C339-03), U.S. EPA Office of
Air Quality Planning and Standards, Research Triangle Park, North
Carolina 27711, telephone 919-541-2380, or electronic mail at svendsgaard.dave@epa.gov, for questions on this rule.
SUPPLEMENTARY INFORMATION:
Regulated Entities
Entities potentially affected by this final action include sources
in all industry groups. The majority of sources potentially affected
are expected to be in the following groups:
------------------------------------------------------------------------
Industry group SIC \a\ NAICS \b\
------------------------------------------------------------------------
Electric Services................. 491 221111, 221112,
221113, 221119,
221121, 221122
Petroleum Refining................ 291 324110
Industrial Inorganic Chemicals.... 281 325181, 325120,
325131, 325182,
211112, 325998,
331311, 325188
Industrial Organic Chemicals...... 286 325110, 325132,
325192, 325188,
325193, 325120,
325199
Miscellaneous Chemical Products... 289 325520, 325920,
325910, 325182,
325510
Natural Gas Liquids............... 132 211112
Natural Gas Transport............. 492 486210, 221210
Pulp and Paper Mills.............. 261 322110, 322121,
322122, 322130
Paper Mills....................... 262 322121, 322122
Automobile Manufacturing.......... 371 336111, 336112,
336211, 336992,
336322, 336312,
336330, 336340,
336350, 336399,
336212, 336213
Pharmaceuticals................... 283 325411, 325412,
325413, 325414
------------------------------------------------------------------------
\a\ Standard Industrial Classification.
\b\ North American Industry Classification System.
Entities potentially affected by this final action also include State,
local, and tribal governments that are delegated authority to implement
these regulations.
Outline
The information presented in this preamble is organized as follows:
I. General Information
A. How can I get copies of this document and other related
information?
1. Docket
2. Electronic Access
B. Where can I obtain additional information?
II. Background
A. What is the RMRR exclusion?
B. Issues surrounding the RMRR exclusion
C. Process used to develop this rule
D. What we proposed
III. Equipment Replacement Provision
A. Overview and justification for today's final action
B. What is an identical or functionally equivalent replacement
and why should such an activity be considered RMRR?
C. What cost limit has been placed on the equipment replacement
approach?
D. What will be the basis of applying the 20-percent threshold?
E. What basic design parameters are being established to qualify
for the equipment replacement provision?
F. What collection of equipment should be considered in applying
the equipment replacement provision and how should it be defined?
G. Consideration of non-emitting units as part of the process
unit
H. What is the accounting basis for the process unit?
I. Enforcement
1. Compliance assurance
2. General issues
J. Quantitative Analysis
K. Consideration of other options
1. Annual Maintenance, repair and replacement allowance
2. Capacity-based option
3. Age-based option
L. Specific list of excluded activities
M. Stand-alone exclusion for energy efficiency projects
N. Legal Basis
1. How does the NSR program address existing sources and why is
today's rule consistent with this approach?
2. Why today's rule appropriately implements the Clean Air Act's
definition of modification
IV. Administrative Requirements for This Rule
A. Executive Order 12866--Regulatory Planning and Review
[[Page 61249]]
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 Analysis
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
J. Executive Order 12988--Civil Justice Reform
V. Effective Date for Today's Requirements
VI. Statutory Authority
I. General Information
A. How Can I Get Copies of This Document and Other Related Information?
1. Docket. The 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 be available electronically, you
may still access any of the publicly available docket materials through
the docket facility identified in section I.A.1. of this preamble. The
EPA intends to work towards providing electronic access to all of the
publicly available docket materials through EPA's electronic public
docket.
For additional information about EPA's electronic public docket
visit EPA Dockets online or see 67 FR 38102, May 31, 2002.
B. Where Can I Obtain Additional Information?
In addition to being available in the docket, an electronic copy of
today's final rule is also available on the WWW through the Technology
Transfer Network (TTN). Following signature by the EPA Administrator, a
copy of this rule will be posted on the TTN's policy and guidance page
for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg.
The TTN provides information and technology exchange in various
areas of air pollution control. If more information regarding the TTN
is needed, call the TTN HELP line at (919) 541-5384.
II. Background
A. What Is the RMRR Exclusion?
Title I of the Clean Air Act (CAA) established the New Source
Review program \1\ to help control airborne emissions from major new
stationary sources of pollution. Under the program, anyone who seeks to
construct a new stationary source that will be a major source of
regulated pollutants must obtain a permit from State authorities (or,
where a State has not established its own program, from EPA directly)
before beginning construction of the source. In order to obtain the
permit, the owner or operator must, among other things, demonstrate
that the new source will have state-of-the-art pollution control
devices.
---------------------------------------------------------------------------
\1\ We broadly use the term ``New Source Review,'' or NSR, to
encompass both the PSD and the Non-attainment New Source Review
program.
---------------------------------------------------------------------------
The NSR program does not generally affect existing sources, but it
does apply if they undergo a ``modification.'' The NSR provisions of
the CAA do not create their own definition of ``modification,'' instead
borrowing the definition of the term established by section 111 of the
CAA, which defined the term for purposes of the New Source Performance
Standards (NSPS) program. That definition states that ``[t]he term
``modification'' means any physical change in, or change in the method
of operation of, a stationary source which increases the amount of any
air pollutant emitted by such source or which results in the emission
of any air pollutant not previously emitted.'' Under 40 CFR parts 51
and 52, the rules we have promulgated to carry out the NSR program,
``major modification'' is similarly defined as any physical change in
or change in the method of operation of a major stationary source that
would result in: (1) A significant emissions increase of a regulated
NSR pollutant; and (2) a significant net emissions increase of that
pollutant from the major stationary source.\2\ The regulations further
provide that certain activities do not constitute a ``physical change
or change in the method of operation'' under the definition of ``major
modification.'' One category of such activities is routine maintenance,
repair and replacement (RMRR). The regulatory provisions excluding RMRR
from the definition of change constitute the RMRR exclusion.
---------------------------------------------------------------------------
\2\ Once a modification is determined to be major, NSR
requirements apply only to those specific pollutants for which there
would be a significant net emissions increase.
---------------------------------------------------------------------------
B. Issues Surrounding the RMRR Exclusion
Until today, the NSR regulations have not further specified what
types of activities are encompassed by the term RMRR. Heretofore, we
have applied the RMRR exclusion exclusively on a case-by-case basis
using a multi-factor test for determining whether a particular activity
falls within or outside the exclusion. We have made these case-by-case
determinations both in the context of applicability determinations,
where a source or permitting authority has requested EPA's guidance
concerning whether a particular activity falls within the exclusion or
requires a permit, and
[[Page 61250]]
in the context of enforcement actions, where we have challenged an
activity undertaken by a source after the fact and the source has
asserted that the activity was permissible under the exclusion.
This case-by-case approach has been praised for its flexibility,
but criticized for hampering activities important to assuring the safe,
reliable and efficient operation of existing plants. Specifically, some
of the case-by-case determinations we have made, particularly over the
past decade, and particularly in a series of enforcement actions, have
been criticized for giving the exclusion a narrow scope that disallows
replacement of significant plant components with identical or
functionally equivalent components. Critics argue that the effect is to
discourage plant owners or operators from engaging in replacements that
are important to restoring, maintaining and improving plant safety,
reliability, and efficiency. They further argue that this effect is
exacerbated by what they assert are the uncertainties inherent in the
case-by-case approach.
To elaborate on the uncertainty issues: Unless an owner or operator
seeks an applicability determination from his or her reviewing
authority, it can be difficult for the owner or operator to know with
reasonable certainty whether a particular activity constitutes RMRR.
This gives the owner or operator five choices, two of which the owner
or operator is not likely to select, and the other three of which have
significant drawbacks for the productivity of the plant.
First, the owner or operator may simply seek an NSR permit. That
course, however, is likely to be time-consuming and expensive, since it
will likely result in a requirement to retrofit an existing plant with
state-of-the-art pollution controls which often is very costly and can
present significant technical challenges. Therefore, an owner or
operator is not likely to select this option if it can be avoided.
Second, the owner or operator may proceed at risk without a
reviewing authority determination. That option, however, is also not
likely to be attractive where a significant replacement activity is
involved, because if the owner or operator proceeds without a reviewing
authority determination and if we later find that he or she made an
incorrect determination on its own, the owner or operator faces
potentially serious enforcement consequences. Those consequences could
well include substantial fines (along with the further consequences of
having been determined to be in violation of the CAA) and penalties and
a requirement to install the state-of-the-art pollution controls, even
though those controls present technical issues or represent a
significant enough expenditure that they likely would have deterred the
owner or operator from seeking a permit in the first place. The owner
or operator is not likely to take this risk if he or she believes there
is a high probability of these kinds of consequences and if he or she
has other options.
Third, the owner or operator may seek an applicability
determination. That process, too, is time-consuming and expensive,
albeit typically less so than seeking a permit. This path presents a
potentially significant barrier to today's global, quick-to-market
industries, such as computer chips, pharmaceuticals, and autos. This
approach also is likely to result in substantial foregone activities
that would enhance the safety, reliability and efficiency of the plant
while awaiting the applicability determination.
Fourth, the owner or operator may forego or curtail replacements
that would enhance the safe, reliable, or efficient operation of its
plant, instead opting to repair existing components even though they
are inferior to current day replacements because they likely have
deteriorated with use and probably are less advanced and less efficient
than current technology. Foregoing the replacement activities
altogether will reduce plant safety, reliability and efficiency;
curtailing or postponing them does as well, differing only in the
degree of these effects.
Finally, the owner or operator may curtail the plant's productive
capacity by replacing components with less than the best technology in
order to be more certain that the replacement is within the RMRR
regulatory bounds, or he or she may agree to limit the source's hours
of operation or capacity or install less than state-of-the-art air
pollution controls to ensure no increase in emissions. Either of those
courses, however, will also result in loss of plant productivity.
The uncertainties are also problematic for State and local
reviewing authorities. They require those authorities to devote scarce
resources to make complex determinations, including applicability
determinations, and consult with other agencies to ensure that any
determinations are consistent with determinations made for similar
circumstances in other jurisdictions and/or that other reviewing
authorities would concur with the conclusion.
Industry commenters strongly echoed these concerns, asserting that
the expense and delay associated with NSR scrutiny, whether or not the
activity is ultimately judged to be subject to major NSR, have caused a
number of facilities to forego needed and beneficial maintenance,
repair, and replacement activities, including ones that would likely
have reduced emissions. In our June 2002 report to the President, we
similarly concluded that the NSR program has impeded or resulted in the
cancellation of projects that would have maintained and improved the
reliability, efficiency, or safety of existing energy capacity.
We are persuaded that we should change the approach to the RMRR
exclusion that we have been following for equipment replacements. The
approach we have been taking often has not encompassed the replacement
of existing components with identical or similar new components that
serve the same function, that represent a small fraction of the value
of the process unit of which they are a part, that do not change the
process unit's basic design parameters, and that do not cause the
process unit to exceed any emission limitations. For the reasons noted
above, this approach tends to have the effect of leading sources to
refrain from replacing components, to replace them with inferior
components, or to artificially constrain production in other ways. We
are persuaded that none of these outcomes advanced the central policy
of the major NSR program as applied to existing sources, which is not
to cut back on emissions from existing major stationary sources through
limitations on their productive capacity, but rather to ensure that
they will install state-of-the-art pollution controls at a juncture
where it otherwise makes sense to do so. We also do not believe the
outcomes produced by the approach we have been taking have significant
environmental benefits compared with the approach we are adopting today
and, indeed, we believe our new approach may well produce environmental
improvements as compared to the old one.
We are also persuaded that uncertainties surrounding the scope of
the exclusion that are associated with the case-by-case approach tend
to exacerbate the problem outlined above. These uncertainties can
discourage replacements that would promote safety, reliability and
efficiency even in instances where, if the matter were brought to EPA,
we would determine that the replacement in question was RMRR. Such
discouragement results in lost capacity and lost opportunities to
improve energy efficiency and reduce air pollution.
We believe that these problems will be significantly reduced by the
rule we
[[Page 61251]]
are adopting today. This rule specifies that the replacement of
components of a process unit with identical components or their
functional equivalents will come within the scope of the exclusion,
provided the cost of replacing the component falls below 20 percent of
the replacement value of the process unit of which the component is a
part, the replacement does not change the unit's basic design
parameters, and the unit continues to meet enforceable emission and
operational limitations.
Our new equipment replacement approach will allow owners or
operators to replace components under a wider variety of circumstances
than they have been able to do under our prior RMRR approach. It also
provides more certainty both to source owners or operators who will be
able better to plan activities at their facilities, and to reviewing
authorities who will be able better to focus resources on other areas
of their environmental programs rather than on time-consuming RMRR
determinations. The effect should be to remove disincentives to
undertaking RMRR activities falling within the rule, thereby enhancing
key operational elements such as efficiency, safety, reliability, and
environmental performance. For example, we anticipate that improved
safety and reliability will result in more stable process operations
and reduce periods of startup, shutdown, and malfunction and the
increased emissions usually associated with them. Accordingly, we
believe the rule will promote the central purpose of Title I of the
CAA, ``to protect and enhance the quality of the Nation's air resources
so as to promote the public health and welfare and the productive
capacity of its population.'' CAA section 101.
We note that we continue to believe that our prior narrower and
entirely case-by-case approach to the RMRR exclusion was consistent
with the relevant language of the CAA and a reasonable effort to
effectuate its policies. At the same time, we also believe that the
final rule's categorical exclusion of certain replacement activities
and the broader definition of RMRR on which that exclusion is premised
are likewise consistent with the statute's language and represent a
better accommodation of the statute's twofold ends. We therefore have
decided to adopt the final rule.
C. Process Used To Develop This Rule
In the 1992 ``WEPCO Rule'' preamble, we declared our intent to
issue guidance on the subject of RMRR. In 1994, as an outgrowth of
meetings with the Clean Air Act Advisory Committee, we developed, for
discussion purposes only, a preliminary draft that presented possible
ways of how RMRR could be defined. We received a substantial volume of
comments on this document. We subsequently decided not to include this
preliminary draft approach in our 1996 NSR proposed rulemaking.
In 2001, the President's National Energy Policy directed EPA in
consultation with the Department of Energy (DOE) and other Federal
agencies to review the impact of NSR on investment in new utility and
refinery generation capacity, energy efficiency and environmental
protection. Our Report to the President illustrated the problems
associated with our prior case-by-case approach to identifying RMRR
activities and underscored the advantages of establishing an objective
bright-line approach for administering the RMRR provision.
We held conference calls with various stakeholders during October
2001 (including representatives from industry, State and local
governments, and environmental groups) to discuss new ideas that were
raised as to how the RMRR provision might be improved. The proposed
RMRR rule reflected many of the ideas discussed in those meetings.
Today's final rule on the equipment replacement provision is based on
careful consideration of comments received on the proposed RMRR rule
(67 FR 80920, December 31, 2002), where we sought comment on all
aspects of our proposed approaches. Today's rule represents final
action on only one part of what we proposed in December 2002--the
equipment replacement provision. We have decided, for now, not to take
final action on the proposed annual maintenance, repair and replacement
allowance approach.
D. What We Proposed
The RMRR proposal offered for comment two cost-based approaches for
determining what constitutes routine maintenance, repair, and
replacement. Under the proposal, facilities could have relied on a
facility-wide annual maintenance, repair and replacement allowance and/
or an equipment replacement cost threshold to determine whether major
NSR requirements were triggered by performing plant maintenance, repair
and replacement activities. The proposal additionally outlined two
options based on the capacity and age of a facility. We solicited
comment on all aspects of the proposed approaches as well as any other
viable option for clarifying the term ``routine maintenance, repair,
and replacement.'' We took public comment on the proposed rule until
May 2, 2003--120 days following publication in the Federal Register.
Under the ``annual maintenance, repair and replacement allowance,''
an annual maintenance cost allowance would be established for each
industrial facility based on an industry-specific percentage. For the
percentage, we considered using the Internal Revenue Service ``Annual
Asset Guideline Repair Allowance Percentages'' (AAGRAP), which for
years has been used as an integral part of an exclusion under the New
Source Performance Standard (NSPS) program. A multi-year allowance
approach, in addition to the annual approach, was also offered for
consideration in the proposal.
Safeguards were proposed to ensure that the types of activities
undertaken under the annual allowance are not activities that should be
subject to greater scrutiny. These safeguards include: (1) No new unit
may be installed; (2) no unit may be replaced in its entirety; and (3)
changes may not cause an increase in the short-term emission rate of
any regulated NSR pollutant.
Under the ``equipment replacement provision,'' or ERP, we proposed
to streamline the process for determining if major NSR permitting
requirements apply to replacement of existing equipment with identical
new equipment or with functionally equivalent equipment. Per-
replacement-of-component(s) thresholds, potentially up to 50 percent of
the cost of replacing the process unit, were suggested by the proposal.
As long as the threshold was not exceeded and the basic design
parameters remained unchanged, the activity would be considered RMRR
under this approach.
Under the proposal, all activities that fell within the annual
maintenance, repair and replacement allowance or the equipment
replacement threshold and that met all the other criteria for these
provisions would be considered RMRR without further review. Activities
that were unable to be accommodated under the annual maintenance,
repair and replacement allowance or the equipment replacement threshold
could still qualify for the RMRR exclusion after a case-by-case review
in accordance with current rules.
We solicited comments on all aspects of our RMRR proposal.
III. Equipment Replacement Provision
A. Overview and Justification for Today's Final Action
Today, we are revising certain provisions of the major NSR program
by
[[Page 61252]]
finalizing the equipment replacement provision (ERP) to specify
activities that will automatically qualify for the RMRR exclusion. This
rule is effective on December 26, 2003. At this time, we are not taking
action on our proposed annual maintenance, repair and replacement
allowance approach.
Although many commenters requested that we further clarify the
case-by-case approach for determining whether an activity is RMRR, we
are not taking action on this suggestion at this time. We are still
considering what, if any, changes should be made to that policy. In the
meantime, the case-by-case approach will remain available for the owner
or operator of a source to use as an alternative and/or supplement to
today's ERP.
Under today's rule, an activity (or aggregations of activities) can
qualify for the ERP if: (1) It involves replacement of any existing
component(s) \3\ of a process unit with component(s) that are identical
or that serve the same purpose as the replaced component(s); (2) the
fixed capital cost of the replaced component(s), plus costs of any
activities that are part of the replacement activity (e.g., labor,
contract services, major equipment rental, and associated repair and
maintenance activities),\4\ does not exceed 20 percent of the current
replacement value of the process unit; and (3) the replacement(s) does
not alter the basic design parameters of the process unit or cause the
process unit to exceed any emission limitation or operational
limitation (that has the effect of constraining emissions) that applies
to any component of the process unit and that is legally enforceable.
---------------------------------------------------------------------------
\3\ For the sake of clarity, we want to be clear that the term
``component'' is meant to be applied broadly and read broadly to
include replacements of both large components, such as economizers,
reheaters, etc. at a boiler, as well as small items, such as screws,
washers, gaskets, etc.
\4\ We note that certain ancillary costs incurred during a given
replacement activity should not be part of the replacement activity,
such as replacement power that must be purchased during the
maintenance shutdown of an electric utility.
---------------------------------------------------------------------------
Today's final rule specifies the procedures by which the owner or
operator of a source selects the basic design parameters for steam
electric generating facilities and for other types of process units.
Specifically, for steam electric generating facilities, we have
clarified our proposed approach by specifying maximum hourly heat input
and fuel consumption rate \5\ as basic design parameters. We are also
allowing owners or operators of steam electric generating facilities
the option to select a pair of parameters based on the process unit's
output--more specifically, maximum hourly electric output rate or
maximum steam flow rate--as an alternative to the previously proposed
input-based parameters. Likewise, we are retaining our proposed
approach of specifying maximum rate of fuel or material input for other
types of process units, but we also allow you to use maximum rate of
heat input, or maximum rate of product output if you prefer an output-
based basic design parameter. In addition, we allow you to propose an
alternative basic design parameter(s), if the above options are
inappropriate for your process unit.
---------------------------------------------------------------------------
\5\ Actually proposed as ``fuel consumption specifications.''
---------------------------------------------------------------------------
We are not specifically defining the basis for determining the
replacement value of a new process unit. Instead, the final rule
provides you with the flexibility of using any of the following: (1)
Replacement cost; \6\ (2) invested cost, adjusted for inflation; (3)
the insurance value, where the insurance value covers complete
replacement of the process unit (rather than, for example, lost revenue
replacement); or (4) another accounting procedure to establish a
replacement value of the process unit if such accounting procedure is
based on Generally Accepted Accounting Principles (GAAP). The GAAP are
the conventions, rules and procedures that define accepted accounting
practice for recording and reporting financial information, including
broad guidelines as well as detailed procedures. The basic doctrine was
set forth by the Accounting Principles Board of the American Institute
of Certified Public Accountants, which was superseded in 1973 by the
Financial Accounting Standards Board.
---------------------------------------------------------------------------
\6\ Replacement cost can be either an estimate of the fixed
capital cost of constructing a new process unit or the current
appraised value of the process unit.
---------------------------------------------------------------------------
If you choose to use options 3 or 4 to determine the replacement
value for a particular process unit, you must send a notice reflecting
your decision to your reviewing authority. The first time that an owner
or operator submits such a notice for a particular process unit, the
notice may be submitted at any time, but any subsequent notice for that
process unit may be submitted only at the beginning of the process
unit's fiscal year. You must continue to use the same basis to evaluate
any additional activities that you undertake on that process unit
within that same fiscal year. If you have provided notice of using
either option 3 or 4, then the reviewing authority will assume that the
same method will be used for subsequent fiscal years unless you send a
notice to them declaring your intent to use another method. In the
absence of providing any notification to your reviewing authority, you
must use option 1 or 2.
The final rules also set forth a definition of process unit,
specifically delineate the boundary of the process unit for certain
specified industries, and define a functionally equivalent replacement.
A more detailed discussion of these requirements and our rationale for
this action is contained in other parts of this preamble section.
Today's final rules are designed to allow you to engage in
activities that facilitate the safe, reliable and efficient operation
of your source. We believe that today's final action broadens the major
NSR program exclusion for equipment replacements and provides you with
additional certainty as to what equipment replacement activities
qualify for the RMRR exclusion. By adding certainty to the process, we
are removing the disincentives to undertaking routine equipment
replacements and promoting proper operational planning to facilitate
safe, reliable and efficient operations. When an activity qualifies for
the ERP, it will be considered RMRR and excluded from major NSR without
regard to other considerations. In many cases, we believe that
maintaining safe, reliable and efficient operations will have the
corresponding environmental benefit of reducing the amount of pollution
generated per product produced. The final rules also will reduce the
resource burden on reviewing authorities resulting from implementation
of the existing, case-by-case process for determining RMRR. In these
respects, the final rules are consistent with the central purpose of
the CAA, ``to protect and enhance the quality of the Nation's air
resources so as to promote the public health and welfare and the
productive capacity of its population.'' CAA section 101.
B. What Is an Identical or Functionally Equivalent Replacement and Why
Should Such an Activity Be Considered RMRR?
We proposed to exclude the replacement of existing equipment with
identical or functionally equivalent components. As we observed at the
time of our RMRR proposal, we believe that most identical and
functionally equivalent replacements are necessary for the safe,
efficient and reliable operations of virtually all industrial
operations; are not of regulatory concern; will improve air quality
(e.g., by decreasing startup, shutdown, and malfunctions); and thus
should qualify
[[Page 61253]]
for the ERP under the RMRR exclusion. We believe industrial facilities
are constructed with the understanding that certain equipment failures
are common and ongoing maintenance programs that include replacing
components in order to maintain, restore, or enhance the reliability,
safety, and efficiency of a plant are routine. Conversely, delaying or
foregoing maintenance could lead to failure of the production unit and
may create or add to safety concerns.
When such equipment replacement occurs, the replaced component is
inherent to both the design and purpose of the process unit, and there
is no reason to believe that such activity will cause the unit to emit
above its original design capacity. Moreover, most of these
replacements are conducted at industrial facilities to maintain proper
operations and to implement good engineering practices. For example, if
a pump associated with a distillation column fails and is replaced with
an identical new pump, we believe that such a common activity is and
should be considered an excluded replacement. It is not a ``change'' to
the plant, since it merely maintains the plant as designed. Instead, it
is the type of activity expected to occur to maintain the plant.
Therefore, we think replacements like this properly fall within the
exclusion for ``routine maintenance, repair and replacement.'' We also
believe treating them in this fashion is consistent with the basic
policies of the CAA: that existing plants are subject to major NSR
permitting requirements only when they engage in an activity that
constitutes an opportune time to install state-of-the-art pollution
control equipment.
We also believe that this principle extends beyond the replacement
of equipment with identical equipment. When equipment is wearing out or
breaks down, it often is replaced with equipment that serves the same
purpose or function but is different in some respects or improved in
some ways in comparison with the equipment that is removed. To continue
with the example used above, if, instead of replacing the worn out
distillation column pump with an identical one, the owner or operator
replaced it with a new and improved model, it does not seem to us that
this changes the fundamental reasons for treating that replacement as
likewise within the scope of ``routine maintenance, repair and
replacement.''
This is particularly true since technology is constantly changing
and evolving. When equipment of this sort needs to be replaced, it
often is simply not possible to find the old-style technology. Owners
or operators may have no choice but to purchase and install equipment
reflecting current design innovations. Even if it is possible to find
old-style equipment, it seems unnecessary and undesirable to generally
construe NSR permitting requirements in a manner that is bound to deter
owners or operators from using the best equipment that suits the given
need when replacements must be installed.
The limiting principle here is that the replacement equipment must
be identical or functionally equivalent and must not change the basic
design parameters of the affected process unit (e.g., for electric
utility steam generating units, this might mean heat input and fuel
consumption specifications). We also believe, however, that we need not
and should not treat efficiency as a basic design parameter as we do
not believe NSR was intended to impede industry in making energy and
process efficiency improvements. We believe such improvements, on
balance, will be beneficial both economically and environmentally. This
treatment of efficiency should address the concern and perception that
the NSR program serves as a barrier to activities undertaken to
facilitate, restore, or improve efficiency, reliability, availability,
or safety of a facility.
Today's rule does not distinguish between the replacement of
components that are expected to be replaced frequently or periodically
and the replacement of components that may occur on a less frequent or
one-time basis. It likewise does not distinguish between the
replacement of larger and smaller components, instead requiring greater
scrutiny if the replacement in question is part of an activity that
exceeds 20 percent of the replacement value of the process unit.
Our decisions on these points are derived from reflection on the
function of the exclusion in the context of the CAA. As explained
above, and as described more fully in our legal analysis set forth
below, we do not believe that application of the major NSR program to
``modified'' plants is designed to require existing plants that are
continuing to operate in a manner consistent with their original design
to curtail their rate of production or hours of operation beyond
limitations set forth in their existing permits. We likewise do not
believe that the program is designed to discourage plants from
replacing parts or components so as to preserve their ability to
produce at that rate. Rather, we believe Title I of the Clean Air
largely leaves to State and local permitting authorities whether to
require adjustments in the operations of those plants in order to
reduce emissions to the degree needed to attain or maintain national
air quality standards, and how to weigh the trade-offs such adjustments
may produce in terms of potential economic impacts and loss of
productivity. Instead, we believe the central function of the
application of major NSR permitting requirements to ``modifications''
is to assure that plants install state-of-the-art pollution controls.
We recognize that on these points, the approach taken by our final
rule thereby differs in some respects from the multi-factor, case-by-
case approach we have been using in identifying RMRR, and particularly
from some of our applications of that test to certain equipment
replacements. We believe, however, that this adjustment in our approach
is fully warranted for the reasons outlined above, and described more
fully in our legal analysis below.
The following examples of functionally equivalent replacements
under today's rule include:\7\
---------------------------------------------------------------------------
\7\ As discussed in more detail below, although such activities
would be functionally equivalent, they would still need to meet
other criteria to qualify for the ERP. For example, a functionally
equivalent replacement does not qualify for the ERP if it results in
a change to a basic design parameter of the affected unit. If an
activity does not qualify for RMRR under the ERP, the case-by-case
RMRR approach would still be available to the owner or operator
under those circumstances. And, of course, even if the activity does
not qualify for the RMRR exclusion, the activity will not be a
modification and, hence, will not trigger NSR unless it results in a
significant emissions increase.
---------------------------------------------------------------------------
[sbull] Replacing worn out pipes in a chemical process plant with
pipes that are constructed of different metallurgy (e.g., to help
reduce corrosion, erosion, or chemical compatibility problems).
[sbull] Replacing an analog controller with a digital controller,
even though a similar analog controller can still be purchased and even
though the new controller would allow for more precise control. A good
example was presented to us by the forest products industry during our
review of the NSR program's impacts on the energy sector. A company in
that sector needed to replace outdated analog controllers at a series
of six batch digesters. In this case, the original controllers were no
longer manufactured. The new digital controllers, costing approximately
$50,000, are capable of receiving inputs from the digester vessel
temperature, pressure, and chemical/steam flow. The new controllers
would have more precisely filled and pressurized digesters with chips,
chemicals, and steam, thus bringing a batch digester on line faster.
[sbull] Replacing an existing mill or pulverizer (e.g., grinding
clinker in a
[[Page 61254]]
cement factory or coal for a boiler) with a new one of a different type
because both new and old equipment serve the same purpose (even if the
characteristics of the ground material would be different before and
after the replacement).
[sbull] Replacing existing spray paint nozzles with new ones that
might atomize the spray better or have a higher transfer efficiency
because the ``before'' and ``after'' nozzles serve the same function.
At the same time, there are numerous activities that occur at
facilities that may fall within the bounds of the cost threshold
percentage, basic design parameters, and other backstop features of
today's rule, but nevertheless cannot qualify for the RMRR exclusion on
the grounds that the equipment is neither identical nor functionally
equivalent. An example of this would be a chemical processing facility
where the owner or operator makes a physical change that allows the
production of a new end product that physically could not have been
manufactured with the previous equipment using the same raw materials
as used before in the same amounts as before. This would not be a
functionally equivalent replacement activity because the facility is
able to produce an end product after making the change that the
facility was not capable of making before the change. Consequently,
this activity would not qualify as RMRR under today's ERP.
Several commenters said the equipment replacement provision will
streamline the major NSR applicability analysis. A number of commenters
believed the ERP would be easier to implement than the proposed annual
maintenance, repair and replacement allowance approach. One commenter
said that allowing identical replacements to be excluded from major NSR
will codify existing industrial practices, where replacement has no
impact on emissions and would clearly represent RMRR.
Many commenters expressed support for the ERP, but recommended
certain changes that they felt needed to be made to improve the
proposal. One commenter supported the ERP in combination with a
capacity-based option, on the assumption that repair and maintenance is
to be excluded as well as equipment replacement.
One commenter attempted to collect data from turbine customers and
found that achieving a level of data collection necessary for the ERP
was far from simple, because the cost of maintenance activities is
affected by such things as variability in engine model, package
technology, and type of maintenance contract. Another commenter gave an
example of the benefit that the ERP may provide. Without the ERP, the
commenter said the source is limited to some fraction of boiler tubes
allowed to be replaced at a given time, whereas with the ERP,
replacement of all boiler tubes would, in the commenter's opinion,
rightfully be considered routine. Another commenter said the ERP will
remove regulatory burdens for types of equipment replacements that are
in their view ``routine,'' such as replacement of tubes in industrial
boilers. They added that, without a clearer understanding of which
activities are RMRR, they may be inclined to delay conducting such
replacements.
Many other commenters generally opposed any change to the RMRR
exclusion, including one based on equipment replacement. Some of these
commenters believed the ERP was problematic because it would allow a
source to replace an entire process unit over time. Two of the
commenters opposed the ERP because they felt it would create
disincentives for the implementation of Plantwide Applicability Limits
(PAL) and Clean Unit provisions from the recently finalized rule.
One commenter said that from an engineering standpoint, for a power
plant, the difference between routine maintenance and a major plant
refurbishing project is clear. To further clarify, the commenter made
the following points. According to the commenter, routine maintenance
is frequent and follows a predictable pattern. The commenter
characterized routine maintenance at power plants as: repair of leaking
pipes, pumps, valves, and fans; cleaning and lubrication of components;
and inspections. The commenter added that permanent staff do this work
either while the plant is operating or during only brief periods of
downtime. The commenter further expressed that activities that are not
routine require long plant or process unit shutdowns, are done
infrequently, and are major capital projects for which special funding
is set aside as a result of years of planning and design work.
One commenter said the proposal will allow emissions increases that
will be difficult to offset through other regulations. One commenter
objected to the ERP for a number of reasons: (1) The provision does not
prevent replacement with different equipment; (2) it does not promote
efficiency improvements or application of good air pollution controls;
and (3) it would allow replacements that would significantly increase
emissions. This commenter said replacement of air pollution controls
should trigger best available control technology (BACT) or lowest
achievable emission rate (LAER) requirements. Two local air pollution
control agencies in California noted that they currently already
exclude all replacements with identical equipment from major NSR when
certain conditions are met.
Commenters generally had similar viewpoints on allowing both
identical and functionally equivalent equipment replacements to qualify
as RMRR. However, some commenters expressed greater concern related to
excluding the replacement of equipment with functionally equivalent
equipment. Primarily their concerns were rooted in the fact that a
functionally equivalent replacement component could lead to increases
in operational efficiency or productivity, and these commenters
asserted that these sorts of process enhancements should not be
excluded as RMRR.
We agree with the commenters who felt identical and functionally
equivalent replacement activities generally should be excluded as RMRR.
We also agree with the commenters who believe that this provision will
streamline the major NSR applicability process and will bring clarity.
The provision we are finalizing will allow a source to make a simple
determination as to whether a replacement piece of equipment qualifies
as identical or functionally equivalent. This type of determination
will be straightforward and easier for the source to implement than the
current case-by-case analysis required to determine a replacement falls
within the RMRR exclusion. We support the air pollution agencies that
have already excluded these types of changes from NSR.
We disagree with those commenters who believe that this provision
will create disincentives for sources to accept a PAL or have emission
units designated as Clean Units. A PAL offers a source to bring on
entirely new emissions units with no Federal preconstruction permit, as
long as emissions caps are not exceeded. A PAL or a Clean Unit
designation allows a source to make modifications without performing a
major NSR applicability test. These advantages will still be the
driving force for sources to elect to use the PAL or Clean Unit
provisions, and we do not believe this final rule will significantly
detract from their appeal.
We also believe that there is substantial value in facilitating
equipment replacements to a greater degree than our current approach
permits and draws a cleaner and more
[[Page 61255]]
easily administered line between equipment replacements that
categorically do not require a permit and major plant refurbishing
which will result in increased emissions. For pieces of equipment used
at industrial facilities, most manufacturers have well-established
procedures for the inspection and replacement that are part of the
regular maintenance necessary to provide for the equipment's safe,
efficient and reliable operation. Some of these replacements are large
in terms of cost and infrequent, but all are necessary to maintain the
safe, efficient and reliable use of the process unit. We believe it is
important to allow for these replacements provided that certain
safeguards are in place, as discussed below.
We disagree with suggestions from commenters that the time period
between activities, standing alone, provides an appropriate or clear
distinction between activities that should be permissible under the
RMRR exclusion and those that should not. In fact, some components wear
out every year, while others wear out every 20 years. Nevertheless,
both types of changes should fall within the ERP of the RMRR exclusion
because both allow the facility to operate as designed. By not imposing
a time limitation, the ERP allows replacement activities to be driven
by consideration of economic efficiency rather than artificial
regulatory constraints.
We disagree with commenters who expressed particular concern about
functionally equivalent replacements. We continue to believe such
activities should be encouraged and should qualify as RMRR. Even though
a functionally equivalent component varies in some respects from the
replaced component, we feel the most important factor to consider is
whether the replacement will serve the same purpose as the replaced
component. We acknowledge that a functionally equivalent replacement
can result in an increase in efficiency and, consequently,
productivity. In fact, one of our goals is to promote such outcomes.
However, we believe that the basic design parameter safeguard is
appropriate to assure that the ERP only automatically excludes from
major NSR functionally equivalent replacements that do not result in a
significant change to the fundamental characteristics of the process
unit.
We note that the two local programs in California that exclude the
replacement of equipment with identical equipment also allow the
replacement of equipment with functionally equivalent equipment without
considering such action to be a modification. Due to local air quality
considerations, the local programs establish minimum pollution control
requirements that are imposed in some circumstances when functionally
equivalent equipment replacements occur. Nothing in today's rule would
prevent a State or local program from imposing additional requirements
necessary to meet Federal, State or local air quality goals.
After reviewing the comments on our proposal, we have decided to
promulgate what we proposed in December 2002 for the RMRR equipment
replacement provision with relatively minor changes. We decided to
include another safeguard in addition to those we proposed in order to
appropriately constrain the meaning of the term ``functionally
equivalent.'' The additional safeguard is that an excluded replacement
activity cannot cause the process unit to exceed any emission
limitation or operational limitation (that has the effect of
constraining emissions) that applies to the process unit and that is
legally enforceable.
Thus, today's final rule allows you to categorize identical and
functionally equivalent equipment replacements as RMRR if the fixed
capital cost of such replacement plus the cost of repair and
maintenance activities that are part of the replacement activity does
not exceed 20 percent of the replacement value of the process unit, and
if the replacement does not alter a basic design parameter of the
process unit or cause the process unit to exceed any emission
limitation or operational limitation (that has the effect of
constraining emissions) that applies to the process unit.
C. What Cost Limit Has Been Placed on the Equipment Replacement
Approach?
The next concept presented in the proposal is the cost-based
limitation on the scope of the ERP. The purpose of this threshold is to
distinguish between those equipment replacement activities that should
automatically qualify as RMRR without further consideration and those
activities that should undergo case-specific consideration. This
concept is akin to the long-established reconstruction provision under
the NSPS program. For the reasons explained below, we have decided to
establish a 20-percent cost threshold under the ERP.
We believe a similar bright-line rule that would obviate the need
for case-by-case review under our multi-factor test of appropriate
categories of equipment replacements would be extremely useful in
addressing many of the problems that we have identified with the
current operation of the NSR program. Such a rule would be particularly
useful in avoiding the uncertainty and delay, and consequent postponed
or foregone equipment replacements, that our multi-factor case-by-case
review induces. For example, our RIA indicates that it takes a year, on
average, to obtain a determination whether a proposed replacement is
routine. That kind of delay obviously creates perverse disincentives to
refrain from equipment replacements and instead repair existing
equipment or find some other solution.
This is the kind of problem that classically leads agencies to
fashion bright-line tests to provide greater regulatory certainty and
efficiency. Moreover, because the kind of disincentives that give rise
to this concern operate largely by economic means, prompting sources to
take one course of action (cut back on productive equipment
replacement) rather than another (replace the equipment and incur the
costs of delay, as well as potentially the costs of installing state-
of-the-art controls), we think a cost-based threshold is a reasonable
basis on which to create such a bright-line rule.
In the proposal, we observed that it may sometimes be difficult to
determine where to draw the line between an activity that should be
treated as an excluded replacement activity and one that should be
viewed as a physical change that might constitute a major modification,
when the replacement of equipment with identical or functionally
equivalent equipment involves a large portion of an existing process
unit. We solicited comment on a range of equipment replacement cost
thresholds such as one based on the NSPS program. Under the NSPS
program, when the cost of a project at an existing affected facility
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new unit (that is, the current capital
replacement value of the existing affected source), then the source
must notify and provide information to the permitting authority. After
considering a range of factors, including the cost of the activity, the
estimated life of the facility after the replacements, the extent to
which the replaced equipment causes or contributes to the emissions
from the source, and any economic or technical limitations on
compliance with the NSPS, the reviewing authority
[[Page 61256]]
determines whether the proposed project is a reconstruction.\8\
---------------------------------------------------------------------------
\8\ In the proposal, it was incorrectly stated that
applicability of the NSPS was triggered if a project exceeded 50
percent of the cost of replacing the affected facility. As stated in
this notice, if an activity exceeds this cost threshold, that only
triggers further evaluation, not the automatic application of the
NSPS to the source.
---------------------------------------------------------------------------
We observed that, in some respects, an equipment replacement cost
threshold set at the NSPS reconstruction test could be an appropriate
approach for distinguishing between routine and nonroutine identical
and functionally equivalent replacements under the major NSR program.
As under the NSPS program, we do not believe it is reasonable to
exclude from major NSR those activities that involve the total
replacement of an existing entire process unit.
We also noted, however, that there are other considerations
pointing in favor of a threshold lower than the 50-percent
reconstruction threshold that might be appropriate to bound the ERP.
Under NSPS, when a source undertakes a replacement activity at an
existing affected facility that constitutes half or more of the
facility's capital replacement value, our rules require a case-by-case
determination as to whether such replacements constitute construction.
We noted that a percentage threshold lower than 50 percent might be
more appropriate for determining where we would require case-by-case
consideration of the question whether equipment replacements constitute
a modification of an existing process unit under major NSR. We
solicited comments on the appropriate level of any percentage.
Many commenters supported the threshold of 50 percent of
replacement value as the upper limit on equipment replacement. They
felt this number is consistent with existing regulatory requirements
and would accord the flexibility originally intended under the CAA for
RMRR activities, while at the same time assuring that major, nonroutine
projects remain subject to major NSR applicability review, and they
felt this number is consistent with a common-sense interpretation of
the regulations.
They also believed a 50-percent cutoff to be consistent with
reconstruction definitions used in many NSPS and National Emission
Standards for Hazardous Air Pollutants regulations. Some commenters
stated that a 50-percent cutoff for the ERP would be valid for the same
reason as for the NSPS reconstruction test; significant changes to a
process unit are necessary before retrofit controls should be
considered, provided there is no increase in emissions.
Many other commenters opposed the 50-percent replacement value
threshold. They believed the capital replacement percentage should be
much less than 50 percent. One commenter suggested as an appropriate
threshold that the sum of equipment replacement costs for a single
process unit over any period of 5 consecutive years should not exceed
50 percent of the replacement value of the process unit. Another
commenter said the replacement percentage should not be higher than 25
percent. Another commenter suggested a replacement percentage of 5 to
10 percent to reduce the risk of replacement of an entire process unit
over time without installation of BACT. One commenter said a more
appropriate percentage for electricity producers is 0.1 to 1.0 percent.
Another commenter said the threshold should be 5 percent, 1 percent, or
even less, as shown by an NSR enforcement case against the Tennessee
Valley Authority (TVA).
Another commenter believed the 50-percent number has no practical
effect in protecting public health and the environment, and the
commenter was not aware of any projects that have exceeded 50 percent
in cost.
While opposed to the ERP in general, one commenter said the cost
threshold should be as high a percentage as possible, so as not to
promote premature replacement of equipment that is repairable. Another
commenter said the 50-percent number from the NSPS is archaic and not
environmentally protective. This commenter suggested that the threshold
instead be 24 percent. The commenter believed this lower percentage is
appropriate because the lifetime of high-cost materials will
considerably exceed 5 years.
We agree with those commenters who see a relationship between
establishing a threshold for equipment replacements that we will treat
as RMRR under the major NSR program and the threshold the NSPS program
established for reconstruction. However, we disagree that these two
thresholds should be the same. The NSPS threshold was intended to
identify those activities that, even though they did not qualify as a
modification under NSPS, nevertheless are of such magnitude that
further consideration should be given as to whether they are projects
tantamount to new construction. The 50-percent NSPS threshold is not a
bright line in the sense that all projects that exceed 50 percent are
automatically considered as reconstruction. Rather, as discussed above,
it is a threshold intended to alert permitting authorities to
significant projects and allow case-by-case decisions based on a series
of regulatory factors.
The ERP replicates the NSPS concept in some ways. It identifies a
threshold below which there is no need for further inquiry into whether
an activity qualifies for the ERP and above which there is a need for a
case-by-case determination. The major difference between the ERP and
the NSPS reconstruction test is that the ERP deals with modifications,
not reconstructions. This difference weighs in favor of establishing
the equipment replacement threshold at something less than the
reconstruction threshold. It is logical and practical to conclude, as
some of the commenters do, that by using the word ``modification'' the
CAA intended to capture activities on a smaller scale than
reconstructions. As noted above, we have set the ERP cost threshold at
20 percent. This value is less than one-half of the 50-percent
reconstruction threshold and, therefore, fits well within this
conceptual framework.
A 20-percent cost threshold would be consistent with the decision
of the U.S. Court of Appeals for the Seventh Circuit in the Wisconsin
Electric Power Company v. Reilly (``WEPCO'') case, to the extent that
it would not automatically allow the activities performed there to
constitute RMRR. See 893 F.2d 901 (7th Cir. 1990). This court decision
directly addressed the question of what level of ``like kind''
replacement activities qualify as changes under the major NSR program.
In the WEPCO case, the Court considered an activity involving 5
coal-fired units at WEPCO's Port Washington plant. Each unit was rated
at 80 megawatts of electrical output capacity. The activity involved
the replacement of numerous major components. The information submitted
by WEPCO showed that the company intended to replace several components
that are essential to the operation of the Port Washington plant. In
particular, WEPCO sought to replace the rear steam drums on the boilers
at units 2, 3, 4, and 5. According to WEPCO, these steam drums were a
type of ``header'' for the collection and distribution of steam and/or
water within the boilers. WEPCO viewed their replacement as necessary
to continue operation of the units in a safe condition. In addition, at
each of the emissions units, WEPCO planned to repair or replace several
other integral components, including replacement of the air heaters at
units 1, 2, 3, and 4. WEPCO also planned to renovate major mechanical
and electrical auxiliary systems and common plant support facilities.
WEPCO intended to perform
[[Page 61257]]
the work over a 4-year period, utilizing successive 9-month outages at
each unit. The cost of the activity was estimated in 1988 to be $87.5
million. The Court noted that EPA concluded at the time this activity
was unprecedented in that EPA did not find a single instance of
renovation work at any electric utility generating station that
approached this activity in nature, scope and extent. The Court
determined, at our urging, that the changes did constitute a ``physical
change'' under the NSR rules.
In the case of a steam electric generating facility, the process
unit definition provided in today's rule is nearly identical to the
make-up of the ``comparable new facility'' that was used in the NSPS
evaluation of the WEPCO renovation project. However, under our rule we
would not include the cost of pollution control equipment in
determining the replacement cost of the WEPCO process units. WEPCO had
electrostatic precipitators on each of its 5 process units, which our
rule would subtract from the replacement cost. In addition, the WEPCO
evaluation dealt with 5 boilers, each with its own turbine-generator
set; to be consistent with today's definition of steam electric
generating facility, we would likely treat each boiler unit as
belonging to a different process unit. However, since all of the
boilers underwent similar renovations, for simplicity we can assume
that all of the process unit-specific activity costs are equivalent.
Using 1991 dollars, consistent with the timeframe of the Seventh
Circuit Court's decision, it appears that the value of the 5 process
units at the 400-megawatt WEPCO Port Washington facility would be
approximately $321 million based on 1991 model plant values provided by
the International Energy Agency. The 1988 project cost of $87.5 million
scaled up to 1991 dollars would have had an adjusted project cost of
$92.3 million.\9\ Thus, the capital cost percentage for the replacement
activities at WEPCO, averaged over its 5 process units, amounted to 29
percent. Alternatively, using the project cost of ``at least $70.5
million'' cited in the 1991 decision by the Seventh Circuit, and using
the same value for process unit cost, we compute at least 22 percent.
The 20-percent threshold is, therefore, beneath the scope of the
activities at issue in the WEPCO case and hence not inconsistent with
that decision.
---------------------------------------------------------------------------
\9\ Using the Chemical Engineering magazine's Annual Plant Cost
Index (composite), $87.5 million in 1988 dollars is equal in real
terms to (361.3/342.5) multiplied by 87.5 million, or $92.3 million
in 1991 dollars.
---------------------------------------------------------------------------
The 20-percent threshold also is supported by available data for
the electric utility sector. We have a robust and detailed set of
information available on maintenance, repair and replacement activities
for the electric utility sector. Information about the electric utility
sector persuades us that we have established the right ERP threshold
for this sector.
Information on other industrial sectors beyond electric utilities
(as well as general economic theory) further supports our 20 percent
bright line test. Case studies performed by an EPA contractor and
included in Appendix C of our final regulatory impacts analysis (RIA)
estimate the overall impact of the rule on six different industrial
sectors (pulp and paper mills, automobile manufacturing, natural gas
transmission, carbon black manufacturing, pharmaceutical manufacturing,
and petroleum refining). The case studies find that routine equipment
replacement activities generally do not cause emissions increases. The
case studies also find that equipment replacement activities vary
widely within these industries. Likewise, the cost of these activities
as a percent of the process unit replacement value varies widely. We
recognize that the study addresses specific case examples from only a
part of regulated industry and that the project cost information is
derived from a limited inquiry of industry representatives. We believe,
however, that the study provides a useful scoping assessment that tends
to support the proposition that the 20 percent threshold derived for
the utility industry (which is based on robust industry data) should be
applied to industry as a whole. In short, the study supports our view
that it is reasonable to assume that equipment replacement activities
in the utility industry are similar enough to replacement practices in
other industry that the 20 percent value determined for utilities, is
appropriate for industry as a whole. This data indicates that most
typical replacement activities will fall within the 20-percent
threshold. At the same time, the data indicates that some major
replacement activities likely will cross the 20-percent threshold and
will require a case-by-case evaluation under the multi-factor RMRR
test.
Two comment letters (from the Utility Air Regulatory Group (UARG)
and from the American Lung Association (ALA), et al.) were particularly
helpful in understanding the issues associated with the electric
utility sector. The UARG provided as an attachment to its comment
letter a document describing major repair and replacement activities
that its members believe must be undertaken at utility generating
stations in order to keep those facilities operational. The UARG noted
that capital costs incurred for repair and replacement activities at an
individual process unit additionally include activities more minor than
those addressed in the document. The UARG grouped repair and
replacement activities into project families; within each project
family were per-component costs ($/kW) for numerous equipment
replacement activities. We have reviewed the list of projects supplied
by UARG and have concluded that these types of replacement activities
are important to maintaining, facilitating, restoring or improving the
safety, reliability, availability, or efficiency of process units.
Therefore, generally speaking, these types of individual activities and
groups of activities should qualify for the ERP and be excluded from
major NSR without case-specific review. We also believe that it is
reasonably expected in the electric utility industry for groups of
these activities to be implemented at the same time. Such groupings
should also be excluded without case-specific review. When we compare
the 20-percent ERP cost percentage to the UARG data, we find that
individual replacement activities would, in fact, qualify for the ERP
and that limited groupings of these activities would qualify. However,
larger groupings of these activities--groupings that are not usually
seen in the industry--would not qualify for the ERP. This shows that
the 20-percent threshold will be effective in distinguishing between
activities (and aggregations of activities) that should not require
case-specific review to be excluded from major NSR and those that do.
The ALA commenters provided with their comments the results of
their analysis of projects at issue in an NSR enforcement case against
Tennessee Valley Authority (TVA). As shown in the ALA comment letter,
the Clean Air Task Force and the Natural Resources Defense Council
looked at costs for 14 projects on a process unit basis, in year 2001
dollars, from the publicly available record for the case. For all but
one of the challenged projects, the ALA commenters calculated a cost of
less than 4 percent of process unit replacement cost. The ALA
commenters submitted results of this analysis with their opposition to
a source-wide, 5-percent maintenance allowance. As noted above, we
concluded in our 2002 report to the President that the NSR
[[Page 61258]]
program--and the RMRR provision in particular--has in fact resulted in
delay or cancellation of activities that would have maintained and
improved the reliability, efficiency, and safety of existing energy
capacity. The primary purpose of today's rule is to rectify this
problem. Thus, to the extent the activities addressed by ALA qualify
for the ERP, we now believe that such activities, if conducted in the
future, should be excluded from major NSR.
A final factor that we believe supports our selection of a 20
percent threshold is the cost of installing state-of-the-art controls
on existing units. There is obviously no single answer to the question
of at what point that cost becomes the deciding factor in an owner's
decision whether to replace a piece of equipment and incur that cost,
since much will depend on the rate of return on the investment.
Nevertheless, we think it is reasonable to assume that if the cost of
the controls is greater than the cost of the replaced equipment, it is
likely to operate as a substantial deterrent to replacing the equipment
at issue. That is likely to be the case with respect to electric
utilities if we set the threshold below 20 percent, which represents
the approximate cost of retrofitting existing plants with state-of-the-
art controls. The equation is similar for industrial boilers. Notably,
those sectors represent a substantial fraction of the emissions
potentially subject to the NSR program. While the relative costs of air
pollution controls in other industries vary more widely than the costs
for utility and industrial boilers, we nevertheless believe that the
costs and technical issues associated with retrofitting air pollution
controls factor significantly into equipment replacement decisions.
D. What Will Be the Basis of Applying the 20-Percent Threshold?
In the proposal, we solicited comment on whether implementing the
ERP on a per-activity basis or on some other reasoned basis, such as
applying the percentage to components that are replaced collectively
over a fixed period of time, may be more workable.
Many commenters stated that the ERP should be implemented on a per-
activity (or aggregation of activities) basis. Two of the commenters
cited longstanding NSR precedent as the basis of their comments, while
two other commenters relied on NSPS precedent. Another commenter
thought the per-activity approach would be less confusing than summing
activities over a fixed period of time. Other commenters believed the
equipment replacement threshold should in fact be applied on a 5-year
rolling average.
We have decided to apply the percentage threshold on a per-activity
(or aggregation of activities) basis. This is consistent with how major
NSR has been applied in the past and will continue to apply in the
future, with the exception of those sources which establish a PAL. The
major NSR program is a preconstruction program that requires
applicability to be determined for a given activity at a facility and,
as necessary, permitting to occur prior to the time activities are
commenced. The major NSR program also requires applicability to be
determined, in the first instance, based on an assessment only of the
parts of a facility involved in the activity. A per-activity basis
works well with this approach. We are not going final with a
``component-by-component'' approach that we solicited comment on
through our RMRR proposal.
There would be obvious problems if we chose any of the other
approaches suggested in the proposal or suggested by commenters (for
example, annual basis or 5-year rolling average). One of the primary
concerns with applying the percentage to activities performed over a
span of time is that we would be restructuring the major NSR program to
operate based on after-the-fact determinations. This raises the
difficult question of what happens under this type of approach if you
learn after commencement of an activity that it does not qualify under
the ERP. This situation is largely avoided by the per-activity approach
that we are establishing in today's rule.
It should be noted that activities that are related must be
aggregated under the ERP, in the same way as they would have to be
aggregated for other NSR applicability purposes. Under our current
policy of aggregation, two or more replacement activities that occur at
the same time are not automatically considered a single activity solely
because they happen at the same time. For example, a steam turbine
rotor replacement project and a boiler tube replacement project would
not be aggregated simply because they occur during the same maintenance
outage and on the same process unit. Further inquiry into the nature of
the activities and their relationship to each other is needed before
deciding whether the activities must be aggregated under NSR. Also,
non-replacement activities that are part of a larger replacement
activity should be included when calculating costs for a replacement
activity against the capital cost threshold.
E. What Basic Design Parameters Are Being Established To Qualify for
the Equipment Replacement Provision?
In the proposal, equipment replacements were only eligible for the
ERP if they did not change the basic design parameters of the process
unit. We proposed that maximum heat input and fuel consumption
specifications for EUSGUs and maximum material/fuel input
specifications for other types of process units are basic design
parameters. We solicited comments on limiting the eligibility of the
ERP this way and on the basic design parameters we proposed.
Several commenters expressed concerns with either the use of these
specific parameters, or the restriction of the regulated community to
only this set of design parameters. Other comments centered around an
inconsistency in how EPA has accounted for efficiency in the basic
design parameter safeguard. The commenters stated that, while EPA
stated in the proposed preamble that efficiency is not a basic design
parameter, the basic design parameter safeguard, as proposed, has the
potential to bar equipment replacements that achieve significant gains
in efficiency.
Commenters from all sides supported EPA's approach to handling
activities intended to improve an affected process unit's performance
beyond its basic design parameters. Commenters asserted that these
actions would not fall within the RMRR exclusion. Commenters from the
gas transmission industry concurred and amplified this concept, stating
that an engine that is ``uprated'' at the time of overhaul should not
be excluded from major NSR under the RMRR exclusion.
We recognize that the proposed basic design parameters are
inconsistent with some industry conventions, and that we should allow
for industry-specific flexibility or specify additional source
category-specific parameters. For example, for natural gas transmission
compressor stations, commenters explained that brake horsepower is the
conventional design capacity parameter. We received similar comments
from other industries, including cement and surface coaters, who
objected to limiting their facilities to the proposed basic design
parameters. Accordingly, we have decided to provide flexibility by
providing a menu of choices from which the owners or operators may
select and also by allowing for owners or operators to propose
alternative basic design parameters to their reviewing authority which
would then be made legally enforceable.
[[Page 61259]]
In addition to this flexibility, there may be a need for additional
flexibility in using the basic design parameters that are spelled out
in today's rule. For instance with boilers, maximum steam production
rate is often used by the industry, and it may make sense in some cases
to set the design parameters based on those values rather than on
maximum heat input. Likewise, a crude oil distillation tower may have
several capacities that are a function of the type of crude that is to
be processed, and so a refiner may need to have a set of basic design
parameters for its crude towers. These situations can be addressed by
the source proposing alternative parameters or sets of parameters to
their reviewing authority.
Also, there should be flexibility in how the basic design
parameters are demonstrated when the owner or operator chooses not to
rely on the design information for its process unit. For example, in
order to establish the heat input value that the process unit has
demonstrated it is capable of achieving, an electric generating unit
should have the flexibility to reference available credible
information, such as results of historic maximum capability tests or
engineering calculations. Results from tests performed by electric
utilities in the context of providing assurances to generation dispatch
systems and regional or national power pools may be used to establish
the process unit's maximum heat input. A review of such data or other
available operational data or design information can reveal the heat
input that the process unit is capable of achieving in its ``pre-
activity'' configuration, and this can be compared to a ``post-
activity'' heat input value. Plant operators, where the specified basic
design parameters are inappropriate for the process, can propose what
the measure of performance will be for these process units, including
the use of permit limits on amount of production, to their reviewing
authority. For process units having multiple end products and raw
materials, the owner or operator should consider the primary product or
primary raw material when selecting a basic design parameter.
Many pieces of equipment are purchased based on their capacity or
output. Consequently, for both utilities and non-utilities, we have
modified the proposed basic design parameters to include output-based
alternatives in today's final rule. For utilities, the owner or
operator can select maximum hourly electric output rate and maximum
steam flow rate as its basic design parameters, as an alternative to
using input-based measures of maximum hourly fuel consumption rate and
maximum hourly heat input. (We are clarifying from the proposal that
the correct parameter is maximum hourly heat input, not maximum heat
input.) Owners or operators may set different design parameters for
different fuel types (such as coal or oil) or a combustion device that
can accommodate multiple fuel types: for coal-fired units, owners or
operators should consider that the fuel consumption rate will vary
depending on the quality of the coal for a given heat input. When
establishing fuel consumption specifications in terms of weight or
volume, the minimum fuel quality based on BTU content should be used
for coal-fired units.
Regardless of whether the source selects a basic design
parameter(s) specified for non-utilities in today's rule or gets
approval from their reviewing authority to use an alternative
parameter(s) for any type of source, we have not specified a fixed
averaging time period for the circumstance because we want the owner or
operator to have the flexibility to select an averaging time that best
accommodates their operation. In most cases, we believe that long term
averaging periods (e.g., a 12-month fixed period) will not be
appropriate.
Thus, an equipment replacement that improves a process unit's
efficiency and thereby enables the unit to return to its design
parameters can qualify as RMRR even if current actual emissions
increase as a result. For example, if boiler tubes or refractories are
replaced on a boiler process unit, and these activities are beneath the
capital cost threshold and are within the unit's basic design
parameters, then they would qualify as RMRR under the ERP even if this
improves the unit's efficiency.
The manufacturer's design parameters of a process unit are always
acceptable if an owner or operator chooses to rely on them. In the rare
cases where a facility does not have established design parameters, we
believe that a reasonable look back period should be used for
establishing the pre-activity values for basic design parameters,
rather than taking the condition of the process unit immediately before
the activity. We have therefore established a 5-year look back period,
consistent with that for the NSPS hourly emissions increase test, for
these situations.
We were urged by some commenters to incorporate a de minimis
increase level in the basic design parameters that would allow
activities to qualify for the ERP even though the activities would
result in a minor change to the relevant basic design parameters. They
argued that some effects resulting from the replacement may not be
apparent before the equipment has been replaced. They argued that
allowing for small changes in basic design parameters would add greater
certainty to the ERP because unforeseen small changes would not cause
an activity to lose the exclusion after the fact. While we sympathize
with the commenter's concern, we do not see a ready solution to this
problem under the RMRR exclusion. In fact, we are not persuaded that
those types of changes can be readily justified under the ERP because
it is hard to see how an activity that causes basic design parameters
to change is not ``a change'' under NSR.
In sum, we continue to believe that an identical or functionally
equivalent replacement should not qualify for the ERP if the activity
causes the process unit to exceed its specified basic design
parameters. Without such a requirement, significant alteration of a
process unit's fundamental design could be accomplished under the guise
of the ERP. Such an outcome obviously does not square with the idea
that identical or functionally equivalent replacements are not
``changes'' under the major NSR program. Our final rule is different
from the proposal, however, in that it provides greater flexibility in
defining basic design parameters for process units. We were persuaded
by commenters who expressed concerns that the proposed approaches did
not adequately encompass all affected operations and industry sectors.
F. What Collection of Equipment Should Be Considered in Applying the
Equipment Replacement Provision and How Should It Be Defined?
In the proposal, we raised the issue of what collection of
equipment should be considered in applying the threshold under the ERP.
We proposed the term ``process unit'' as the appropriate collection to
accommodate the intended coverage of activities under the ERP. The
purpose of this term is, to the extent possible, to align
implementation of the ERP with generally accepted and practical
understandings of what constitutes a discrete production process. The
general definition that we proposed was based closely on the definition
of process unit contained in 40 CFR 63.41 and read as follows:
Process unit means any collection of structures and/or equipment
that processes, assembles, applies, blends, or otherwise uses
material inputs to produce or store a completed product. A single
facility may contain more than one process unit.
To help illustrate these concepts, we further proposed five industry-
specific
[[Page 61260]]
examples of how this definition of process unit might be applied.
Some commenters compared the proposal's definition of ``process
unit'' (``* * * producing or storing a completed product * * *'') to
the definition that is used by section 112(g) and that appears in 40
CFR 63.41 (`` * * * producing or storing an intermediate or final
product * * *''). One of the commenters supported the proposed
definition. Two commenters said the rule's definition should be
consistent with that used by section 112(g), which they believe is
broad enough to encompass interrelated operations. While supporting the
RMRR proposal's definition, two commenters recommended that EPA provide
regulatory flexibility by allowing a facility the option to choose
which definition it will use.
One commenter generally supported the proposed definition of
``process unit,'' but this commenter believed that ``the delineation of
a process unit should be made by regulated entity rather than
explicitly defined in a rule.''
Three commenters asserted that pollution control equipment should
be included in the process unit definition. One industry commenter said
pollution control equipment is often integral to the process and may
produce an intermediate product. One environmental commenter believed
the proposed rule was unclear as to whether pollution control equipment
is part of the process unit.
Several commenters said the proposed definition is too vague or
broad. Another commenter urged EPA to change the definition of process
unit to limit the scope of what is allowed in the ERP, so that the
source of emissions (for example, an entire coal boiler) would not be
allowed to be replaced without major NSR. The commenter asserted that
the replacement unit's scope should be limited to an emission unit.
Most commenters agreed that the general process unit definition is
sufficient. However, a number of commenters suggested that we revise or
eliminate some of the process unit examples (that is, the industry
category-specific definitions), and others were concerned that the
proposed definitions do not support the detailed process unit
definition for a specific industry because the definitions will never
capture all possible elements and configurations.
We received comments from several industry representatives
suggesting changes to our proposed industry-specific definitions, and
also to request that we delineate other process unit types explicitly
in the rule. Definitions were submitted for sugar mills, chemical
manufacturing plants, surface coating operations, flat glass
manufacturing, fiberglass manufacturing, and gas compressor stations.
One industry commenter agreed with our proposed approach to
proportionately allocate, based on capacity, the cost of those
components shared by two or more process units. Another commenter
suggested that, for electric utilities, we allocate the cost of shared
equipment based on a pro rata share of megawatts produced.
We agree with the commenters who favor using a process unit as the
basis for administering the ERP and including a definition of process
unit in the final rule. We also agree with the commenters who suggested
that the definition of process unit should be consistent with the
definition in 40 CFR 63.41, and we have altered the final rule
definition to include those processes that produce ``intermediates.''
We acknowledge that, without further explanation, the term
``intermediates'' is susceptible to misinterpretation, which can cause
confusion and lead to less regulatory certainty. Thus, we provide the
following explanation as to how we intend to interpret today's rule.
By ``intermediates,'' we mean the intended product of an integrated
facility operation. For example, for an automotive manufacturing plant,
while the completed product would be the driveable vehicle ready for
shipping to the showroom, an intermediate product could be the engine
or the painted body shell. In this case, we would not consider smaller
production operations, such as the e-coat, primer surface, or top coat
operation, to be intermediates in the context of our final rule
definition for process unit. Our primary goal in defining this term
``process unit'' is to encompass integrated manufacturing operations
that produce a completed product, and those operations that produce an
intermediate as the product of the process unit. In the case of the
automotive paint shop, series of coating steps together comprise the
carefully designed and interrelated set of operations, all of which are
needed to provide a coating system that meets design specifications.
The individual operations almost never are implemented individually
and, as a practical matter, simply would serve no meaningful purpose in
the absence of the others.
We disagree with the commenters who wish to include all pollution
control equipment in the definition of process unit. We feel that
periodic replacement of components of emissions control equipment
should be encouraged and would rarely lead to actual emissions
increases. In instances where identical or functionally equivalent
replacement of pollution control equipment occurs, it is likely you
will qualify for a Pollution Control Project exclusion. We do agree,
however, that where the control equipment is an integral component of
the process it should be included. Therefore, we are excluding
associated pollution control equipment from the definition of the
``process unit,'' except for control equipment that serves a dual
purpose in the process. We know there are industries where pollution
control equipment performs a dual purpose; for example, condensers
often serve to control emissions of organic air pollutants while
serving as an integral component of the operation of a fractionation
column. A low-NOX burner is another example of a dual-
purpose component. In such cases, to provide clarity and simplify
administration of the ERP, our rule provides that dual purpose
equipment should be considered part of the process. We are also
clarifying in today's rule that administrative buildings (including
warehousing) are not to be included in the process unit, but other
types of non-emitting units that are integral to the processing
equipment should be included.
We also have included in our final rule industry-specific examples
of how this definition might be applied. The examples are drawn from
three selected industrial processing categories--electric utilities,
refineries, and incinerators. We proposed each of these detailed
definitions and received mostly support from commenters on their
accuracy. While we also proposed detailed definitions for two other
industries--pulp and paper and cement producers--we have decided not to
finalize those definitions after receiving comments from the relevant
industry trade association asserting that the definitions did not, and
could not, capture all of their industry's configurations and they
believed the generic process unit definition was sufficient for their
industry. Because of the centrality of the ``process unit'' concept to
the usefulness of the ERP, it is our desire to include specific
definitions for steam electric generating facilities, petroleum
refineries, and incinerators in the final rule to provide as much
certainty as possible for facilities in these industries. As noted
above, these definitions also should be useful for those in other
industries who
[[Page 61261]]
will apply our general definition because the industry specific
definitions provide clear examples of how we intend the general
definition to be interpreted and applied. During the public comment
period on the proposal, several commenters submitted additional
industry specific definitions and asked us to put them in the final
rule. We are not finalizing these suggested definitions at this time,
because we did not include them in the proposed rule. However, provided
below are the process unit definitions that commenters submitted to us
and that we think comport well with the general definition of process
unit promulgated today.
[sbull] For a natural gas compressor station, each compressor
system, together with its proportionate share of common support
equipment is a separate process unit. This would generally consist of
the air inlet system, accessory drive system, gas producer, fuel
delivery system, cooling system, lube system, power turbine, power
shaft, control system, starting system, exhaust system, and support
facilities (e.g., auxiliary power generating equipment, heating/cooling
equipment, station and yard pipe, valves, etc.).
[sbull] For a flat glass manufacturing plant, each production line
within a facility should be a separate process unit. Flat glass
production is completed on a continuous line where raw materials are
added at one end, a continuous ribbon of glass is formed, and finished
glass is packaged at the other end. The flat glass production line
consists of: the batch house, where raw materials are stored and
weighed; the furnace and refiner, where the raw materials are melted;
the bath, where the glass ribbon is formed; the lehr, where the ribbon
is annealed; and the cutting and packaging equipment, where the glass
is removed from the line for sale to customers or for additional
processing later.
[sbull] For a fiberglass production facility, each production line
is a separate process unit. Fiberglass is manufactured on a continuous
line where raw materials are melted at one end to form a continuous
strand of fiberglass that is packaged at the other end. The fiberglass
production line begins with the batch house, where raw materials are
stored and weighed. In the melter, forehearth, and refiner, the raw
materials are melted and refined. From the refiner, glass fibers are
formed through controlled bushings. From the bushings, the continuous
strand fibers are either directly cut or packaged or wound onto spools
for packaging for sale to customers or for additional later processing.
[sbull] For the production of precipitated amorphous silica, the
process unit includes, but is not limited to: raw material storage and
handling equipment used for mixing sand and other raw materials prior
to addition to the furnace; the furnace itself; the raw material
storage and handling equipment for the cullet dissolving and silica
precipitation process; all dissolving, precipitation, and filtration
tanks and equipment; and drying equipment. Further, the process unit
includes all the product packaging, storage, handling, and transfer
equipment.
[sbull] For a chemical manufacturing plant, the process unit would
include all the equipment assembled and connected by pipes or ducts to
process raw materials and to manufacture an intended primary product
and associated byproducts or intermediates. The process unit can
consist of more than one unit operation. Chemical manufacturing process
units may include, but are not limited to: raw material storage, and
air oxidation reactors and their associated product separators and
recovery devices; reactors and their associated product separators and
recovery devices; distillation units and their associated distillate
receivers and recovery devices; associated unit operations; associated
recovery devices; and any feed, intermediate and product storage
vessels, product transfer racks, and connected ducts and piping. A
chemical manufacturing process unit includes pumps, compressors,
agitators, pressure relief devices, sampling connection systems, open-
ended valves or lines, valves, connectors, instrumentation systems, and
process control or dual purpose air pollution control devices or
systems. For a chemical manufacturing facility, there are several types
of process units: those that separate and distill raw material
feedstocks; those that change molecular structures through reactions or
polymerization; those that ``finish'' the reacted or polymerized
product, through compounding, blending, or similar operations;
auxiliary facilities, such as boilers and by-product fuel production;
and those that load, unload, blend, or store products. Process
equipment that acts to control emissions, such as condensers, recovery
devices, and oxidizers, is considered part of the process unit.
We note that we were unable to include some other process unit
definitions submitted by commenters. While we do not believe that these
other proposed definitions were necessarily inconsistent with our
general definition of process unit, we had concerns and questions with
some of these proposed definitions. We believe that now that this rule
is issued, we can more fully evaluate those other definitions,
including communicating with the leading industry officials, and
determine whether we would approve of their use.
Finally, we have made some slight corrections to the process unit
definitions that we proposed based on comments we received on the
proposed definitions.
There are numerous industries that have industrial boilers at their
facility to provide electricity and steam to their operations. As a
general rule, we would expect these boilers to be treated as a separate
process unit from the other unit operations occurring at the facility.
We would expect the boundaries of the process units for such boilers to
be consistent with the boundaries established under the definition for
a steam electric generating facility in today's rule, which encompasses
all equipment from coal handling to the emission stacks.
We also decided to continue to require that owners or operators who
have components shared by two or more process units to proportionately
allocate, based on capacity, the cost of those components. And we agree
with the commenter that an equitable approach for electric utilities
having components shared by two or more process units is to allocate
the cost of shared equipment based on the pro rata share of megawatts
produced by each process unit.
G. Consideration of Non-Emitting Units as Part of the Process Unit
Many commenters supported excluding non-emitting equipment from the
ERP. One commenter stated that triggering the major NSR review process
for maintenance activities is an impediment to continuous improvement
projects for certain products and processes, even if actual emissions
decrease or only non-emitting units on the process line are affected.
Delays or postponements of project maintenance work adversely affect
the reliability, safety and productivity of operations and cost control
efforts. Another commenter recommended that work at clearly non-
emitting units, specifically including foundation regrouting and repair
and frametop replacement, should be excluded from this rule. Three
commenters believed that non-emitting units cannot result in an
[[Page 61262]]
increase of emissions and thus do not need to be evaluated under major
NSR.
A blanket exclusion for non-emitting units could create problems of
interpretation because the term ``non-emitting components'' is
ambiguous when considering certain components. Commenters asserted that
identifying and separating out non-emitting components can be a complex
undertaking, and may be contrary to the goal of a clear and
straightforward option. One commenter provided the following examples:
(1) Piping systems (although pipe connectors are a source of fugitive
emissions, the pipe normally is not); and (2) structural supports for a
process unit (separating out the cost of supports from an investment
basis throughout a facility will be difficult).
Another commenter believed it would be difficult to separate the
costs of emitting and non-emitting equipment when determining the cost
of the process unit. The commenter also believed it would be difficult
to determine allocation of shared equipment in the cost analysis.
We are concerned that, if owners or operators were allowed to strip
away all of the non-emitting components from a process unit definition,
it would create significant ambiguity in the rule and could result in
significant variation in how the rule is applied to similar sources in
different jurisdictions. In addition, we simply do not think it is
practical or logical to separate ``non-emitting'' components of a
process unit from ``emitting'' components. We believe that integrated
manufacturing operations (that is, process units) typically include
both types of equipment. Separating emitting from non-emitting
equipment would create an artificial divide that contrasts sharply with
physical and operational reality.
As noted above, however, we do believe that a distinction should be
made between non-emitting equipment that is part of a process unit and
non-emitting equipment that is functionally distinct from the process
unit. For example, most production facilities have buildings or space
to house administrative offices, such as offices for the plant
accounting staff. Such non-emitting facilities should not be considered
part of any process unit under today's rule.
H. What Is the Accounting Basis for the Process Unit?
In the proposal, the accounting basis for the ERP discussed was the
same as for the NSPS reconstruction provision, which is the fixed
capital cost that would be required to construct an entirely new unit.
We also discussed for the annual maintenance, repair and replacement
allowance using the invested cost of a unit as the accounting basis. We
proposed that it would be appropriate to require that costs be
calculated using an approach along the lines set out in the EPA Air
Pollution Control Cost Manual (http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf
). Finally, we solicited comment on whether the costs
associated with the unanticipated shutdown of equipment, due to
component failure or catastrophic failures such as explosions or fires,
should be included in evaluating costs under the ERP.
In reviewing comments, we recognized that some commenters appeared
to direct their comments on the accounting methods at the annual
maintenance, repair and replacement allowance, and not necessarily the
ERP. Often, we came to this conclusion simply by the way the commenters
organized their comments, and not by any specific statements in the
comment letter. However, since we asked for comment on the accounting
approaches as they would be applied to both the annual maintenance,
repair and replacement allowance and the ERP, we believe that comments
that appeared to be dedicated to the annual maintenance, repair and
replacement allowance should also apply to our evaluation of the
accounting for the ERP, except in the case where the commenter
specified that their comments on the proposed accounting methods
applied only to the annual maintenance, repair and replacement
allowance or the ERP. Likewise, for considering whether costs
associated with unanticipated shutdown of equipment, we considered the
comments to apply to both the ERP and the annual maintenance, repair
and replacement allowance unless the commenter specifically noted that
the comment should not be applied to both of the proposed rule
provisions.
Most commenters asked for flexibility on whether a facility should
use replacement value, invested cost or insurance valuation as the
basis for the calculations. They felt that all were of equal merit and
different ones would be available at different facilities so EPA should
not prescribe only one type.
Most commenters did not support the sole use of the EPA Air
Pollution Control Cost Manual (APCCM) to standardize calculations for
replacement and repair costs for RMRR in general. Most commenters felt
that the APCCM is a worthy reference for costing but also that sources
should not be limited to only one manual, because a single manual is
likely to have shortcomings and not be able to represent every
situation.
Many commenters supported an exclusion of costs for unanticipated
shutdowns and failures. They noted that strong incentives exist to
avoid fires, explosions and other unanticipated equipment failures
because of the risk of human injury and production interruptions and
because of the expense involved in restoring lost capacity. As a
result, they contend that a catastrophic event already penalizes the
facility dramatically, but then to impose the case-by-case analysis
would only exacerbate their troubles. They explained that failures take
place occasionally and can result in a sudden, unplanned partial or
total loss of equipment. When such a failure occurs at a natural gas
compressor station, the turbine or engine concerned must be replaced
immediately to avoid a disruption in gas supply. Other facilities may
have similar pressures to maintain their product around the clock. Such
replacement fits easily within most elements of the equipment
replacement test. Commenters asserted that replacing a catastrophically
failed turbine or engine is clearly ``routine,'' since companies will
always replace such failures.
Other commenters, however, opposed an exclusion for unanticipated
shutdowns and failures on the grounds that maintenance activities
performed during forced outages are simply maintenance and should be
considered as such, particularly given that the proposed RMRR rule
approaches and the December 2002 final rules already have given the
industry a number of exclusion options.
We are allowing sources to determine the applicability of today's
rule on the basis of replacement value, with an option for sources to
notify their reviewing authority in writing if they desire to use
another option (for example, invested cost or insurance value where the
insurance value covers only the complete replacement of the process
unit). The equipment replacement cost should be based on the current
replacement value of the entire process unit at the time of conducting
the activity.
Typically, replacement value is more easily obtained than invested
cost. Most manufacturers will have information concerning the
replacement value of a process unit, because such costs are commonly
used when evaluating various business scenarios relating to
manufacturing costs. Also, use of replacement value is consistent with
the NSPS provisions.
[[Page 61263]]
In addition to determining the replacement value of a process unit,
in our final rule we allow for the use of several other accepted
methods in different industries for estimating such values. Replacement
values are the estimated value of replacing a unit and can be based on
a current appraisal. In lieu of replacement cost, you can also use
inflation-adjusted original investment, insurance limits if insured for
full replacement of the unit, or other cost estimation techniques
currently employed by the company, as long as the company follows GAAP
and if approved by the reviewing authority.
A dollar-per-kilowatt rate for calculating costs may be appropriate
for utilities. This model is specific to source and fuel type and is
updated periodically. We allow sources to use insurance valuation
methods such as the Handy-Whitman Index to determine replacement costs
for electric utilities. Other sources to compute costs include the
Nelson Refinery Construction Index Factors, Solomon Refinery Study, and
licensors of the respective process unit (e.g., Kellogg, UOP).
In order for a cost-based approach to be equitable, all owners or
operators must include the same categories of expenses in both the
process unit replacement value and the replacement activities sought to
be excluded. Therefore, although the final rule does not mandate any
particular approach, we believe it is generally appropriate to
calculate costs using an approach similar to the elements of Total
Capital Investment as defined in the APCCM. While the manual contains
basic concepts that could be used to estimate total capital investment
at a process unit, it is geared toward cost calculations for add-on
control equipment. On the other hand, the underlying concepts are taken
from work done by the American Association of Cost Engineers to define
the components of cost calculations for all types of processes, not
just emission control equipment. In certain cases, other manuals might
make more sense depending on their circumstances.
Under the APCCM, total capital investment includes the costs
required to purchase equipment, the costs of labor and materials for
installing the equipment (direct installation costs), costs for site
preparation and buildings, and certain other indirect installation
costs. However, any costs that are part of the installation and
maintenance of pollution control equipment should be excluded from the
cost calculation, per our discussion in the previous section of this
preamble. We believe equipment that serves a dual purpose of process
equipment and control equipment (combustion equipment used to produce
steam and to control hazardous air pollutant emissions, exhaust
conditioning in the semiconductor industry, etc. should be considered
process equipment.
Direct installation costs include costs for foundations and
supports, erecting and handling the equipment, electrical work, piping,
insulation, and painting. Indirect installation costs include such
costs as: engineering costs; construction and field expenses (costs for
construction supervisory personnel, office personnel, rental of
temporary offices, etc.); contractor fees (for construction and
engineering firms involved in the activity); startup and performance
test costs; and contingencies.
We believe there may be merit to the comments we received
advocating a categorical exclusion for unanticipated shutdowns and
failures of some kind. When such an outage occurs, there may be a real
urgency to restore the plant to operation without forcing it to await
the results of a permitting action or applicability determination. In
the past, we have handled these situations with case-by-case consent
orders; however, even that approach may lead to unnecessary delays. It
may specifically be sensible to relaxing the 20 percent cost threshold
limitation for such events because it is unlikely that sources would
incur an outage to avoid controls. We did not propose such a stand-
alone exclusion and hence we believe we should not act upon it at this
time.
I. Enforcement
1. Compliance Assurance
We believe that the records developed and maintained in the
ordinary course of business will provide the primary means of assuring
compliance with today's rule. We know that, as a general rule,
companies necessarily generate and keep records related to the types of
projects covered by today's rule. For example, companies generally have
comprehensive procedures by which funds are allocated to both capital
and maintenance expense projects. Many of the records generated by
these procedures are needed for tax accounting purposes and, by law,
must be maintained for at least 6 years. Moreover, additional records
must be maintained in industries regulated for other purposes, such as
the energy sector (over 90 percent of which, by capacity, is subject to
FERC regulation). Public utilities, licensees and natural gas companies
that are subject to FERC jurisdiction must, unless they receive a
waiver from the Commission, comply with extensive accounting and record
retention requirements. They must keep financial information according
to uniform systems of accounts that are set out in 18 CFR part 101 for
public utilities and licensees, and 18 CFR part 201 for natural gas
companies. These uniform systems of accounts include hundreds of
specific accounts, including individual accounts for boiler plant
equipment, engines and engine-driven generators, turbogenerator units,
and hundreds of other asset, liability, cost and property items.
These companies also must retain records according to the schedules
set forth in 18 CFR part 125 (for public utilities and licensees) and
18 CFR part 225 (for natural gas companies). The types of records that
companies must keep include, for public utilities and licensees, for
example, generation and output logs (records must be kept for 3 years),
load records (3 years), gauge-reading reports (2 years), maintenance
work orders and job orders showing entries for labor, materials and
other charges in connection with maintenance and other work pertaining
to utility operations (5 years), work order sheets for construction
work in progress (5 years), appraisals and valuations made of utility
property or investments (3 years), engineering records, drawings, and
other supporting data for proposed or as-constructed utility
facilities, including detail drawings and records of engineering
studies (must be kept until facilities are retired), contracts or other
agreements relating to services performed in connection with
construction of utility plant (6 years after the plant is retired or
sold), general and subsidiary ledgers (10 years), paid and canceled
vouchers, and original bills and invoices for materials, services, etc.
(5 years).
Altogether, these various sources of information provide more than
reasonable assurance of compliance with today's rule. This is
particularly true given EPA's broad authority to inspect affected
facilities and require submission of compliance related data.
Accordingly, we are not imposing any recordkeeping requirements in
today's rule.
2. General Issues
Today's rule provides revisions to the major NSR program to specify
categories of equipment replacement activities that we will consider
RMRR in the future. As recognized by the U.S. Supreme Court, an agency
may not promulgate retroactive rules absent express congressional
authority. See Bowen v. Georgetown Univ. Hosp., 488 U.S. 204,
[[Page 61264]]
208, 102 L. Ed. 2d 493, 109 S. Ct. 468 (1988). The CAA contains no such
expressed grant of authority, and we do not intend by our actions today
to create retroactive applicability for today's rule. 42 U.S.C. 7401 et
seq. Today's rule applies only to conduct that occurs after the rule's
effective date.
None of today's rule revisions apply to any changes that are the
subject of existing enforcement actions that the Agency has brought and
none constitute a defense thereto. Furthermore, prior applicability
determinations on major modifications that result in control
requirements in an NSR permit that currently applies to a source remain
valid and enforceable as to that source.
As noted above, today we are changing the scope of the RMRR
exclusion from the major NSR program by taking final action on the ERP.
If you subsequently undertake an activity that does not meet the
applicable provisions of these new alternatives and do not obtain a
preconstruction permit if you are required to do so, you will be
subject to any applicable enforcement provisions (including the
possibility of citizens' suits) under the applicable sections of the
CAA. Sanctions for violatio |
