## Tuesday,

December 31, 2002



# Part III



# Environmental Protection Agency

40 CFR Parts 51 and 52

Prevention of Significant Deterioration
(PSD) and Nonattainment New Source Review (NSR); Final Rule and Proposed

Rule


### 80186 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 51 and 52

[AD–FRL–7414–5]

RIN 2060–AE11

Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NSR): Baseline Emissions Determination, Actual-to-Future-Actual Methodology, Plantwide Applicability Limitations, Clean Units, Pollution Control Projects

AGENCY : Environmental Protection Agency (EPA).

ACTION : Final rule.

SUMMARY : The EPA is revising regulations governing the New Source Review (NSR) programs mandated by parts C and D of title I of the Clean Air Act (CAA or Act). These revisions include changes in NSR applicability requirements for modifications to allow sources more flexibility to respond to rapidly changing markets and to plan for future investments in pollution control and prevention technologies. Today’s changes reflect EPA’s

consideration of discussions and

recommendations of the Clean Air Act Advisory Committee’s (CAAAC) Subcommittee on NSR, Permits and Toxics, comments filed by the public, and meetings and discussions with interested stakeholders. The changes are intended to provide greater regulatory certainty, administrative flexibility, and permit streamlining, while ensuring the

current level of environmental protection and benefit derived from the program and, in certain respects, resulting in greater environmental protection.

EFFECTIVE DATE : This final rule is effective on March 3, 2003.

ADDRESSES : Docket. Docket No. A–90– 37, containing supporting information used to develop the proposed rule and the final rule, is available for public inspection and copying between 8 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, DC 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 : Ms. Lynn Hutchinson, 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 919–541–5795, or

electronic mail at hutchinson.lynn@epa.gov, for general questions on this rule. For questions on

baseline emissions determination or the actual-to-projected-actual applicability test, contact Mr. Dan DeRoeck, at the same address, telephone 919–541–5593,

or electronic mail at deroeck.dan@epa.gov. For questions on Plantwide Applicability Limitations (PALs), contact Mr. Raj Rao, at the same address, telephone 919–541–5344, or electronic mail at rao.raj@epa.gov. For questions on Clean Units, contact Mr. Juan Santiago, at the same address, telephone 919–541–1084, or electronic mail at santiago.juan@epa.gov. For questions on Pollution Control Projects (PCPs), contact Mr. Dave Svendsgaard, at the same address, telephone 919– 541–2380, or electronic mail at svendsgaard.dave@epa.gov.

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 aNAICS b

Electric Services ............................................................................ 491 221111, 221112, 221113, 221119 , 221121, 221122 Petroleum Refining ........................................................................ 291 32411 Chemical Processes ..................................................................... 281 325181, 32512, 325131, 325182, 21111 2, 325998, 331311,

325188 Natural Gas Transport .................................................................. 492 48621, 22121 Pulp and Paper Mills ..................................................................... 261 32211, 322121, 322122, 32213 Paper Mills .................................................................................... 262 322121, 322122 Automobile Manufacturing ............................................................ 371 336111, 336112, 336712, 336211, 336992, 336322, 336312, 33633, 33634, 33635, 336399, 336212, 336213 Pharmaceuticals ............................................................................ 283 325411, 325412, 325413, 325414

a Standard Industrial Classification

b North American Industry Classification System.

Entities potentially affected by this 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. Overview of Today’s Final Action

A. Background

B. Introduction

C. Overview of Final Actions 1. Determining Whether a Proposed

Modification Results in a Significant

Emissions Increase

2. CMA Exhibit B 3. Plantwide Applicability Limitations (PALs)

4. Clean Units 5. Pollution Control Projects (PCPs) 6. Major NSR Applicability

7. Enforcement 8. Enforceability II. Revisions to the Method for Determining Whether a Proposed Modification Results in a Significant Emissions

Increase

A. Introduction B. What We Proposed and How Today’s

Action Compares C. Baseline Actual Emissions For Existing

Emissions Units Other than EUSGUs D. The Actual-to-projected-actual Applicability Test E. Clarifying Changes to WEPCO

Provisions for EUSGUs F. The ‘‘Hybrid’’ Applicability Test G. Legal Basis for Today’s Action H. Response to Comments and Rationale

for Today’s Actions

III. CMA Exhibit B IV. Plantwide Applicability Limitations (PALs)

A. Introduction B. Relevant Background C. Final Regulations for Actuals PALs D. Rationale for Today’s Final Action on

Actuals PALs

V. Clean Units


### 80187 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

1 In this preamble the term ‘‘ we ’’ refers to EPA

and the term ‘‘ you ’’refers to major stationary sources of air pollution and their owners and operators. All other entities are referred to by their respective names (for example, reviewing authorities.)

A. Introduction B. Summary of 1996 Clean Unit Proposal C. Final Regulations for Clean Units D. Legal Basis for the Clean Unit Test E. Summary of Major Comments and

Responses VI. Pollution Control Projects (PCPs)

A. Description and Purpose of This Action B. What We Proposed and How Today ’ s

Action Compares To It C. Legal Basis for PCP D. Implementation

VII. Listed Hazardous Air Pollutants VIII. Effective Date for Today ’ s Requirements IX. Administrative Requirements

A. Executive Order 12866

—Regulatory

Planning and Review

B. Executive Order 13132

—Federalism

C. Executive Order 13175

—Consultation

and Coordination with Indian Tribal

Governments
D. Executive Order 13045

—Protection of

Children from Environmental Health Risks and Safety Risks

E. Unfunded Mandates Reform Act of 1995 F. Regulatory Flexibility Act (RFA), as

Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq. G. Paperwork Reduction Act H. National Technology Transfer and

Advancement Act of 1995 I. Congressional Review Act J. Executive Order 13211

—Actions

Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use X. Statutory Authority XI. Judicial Review

I. Overview of Today’s Final Action

A. Background

We 1 proposed revisions to the NSR rules in a notice published in the Federal Register on July 23, 1996 (61 FR 38250). On July 24, 1998, we published a notice (63 FR 39857) to solicit further comment on two specific aspects of the proposed revisions. Today ’ s Federal Register action announces EPA ’ s final action on the proposed revisions for baseline emissions determinations, the actual-to-future-actual methodology, actuals PALs, Clean Units, and PCPs.

We have not made final determinations on any other proposed changes to the regulations.

Today ’ s actions finalize these changes to the regulations for both the approval and promulgation of implementation plans and requirements for preparation, adoption, and submittal of implementation plans governing the NSR programs mandated by parts C and D of title I of the Act. We also proposed conforming changes to 40 CFR (Code of Federal Regulations) part 51, appendix S, and part 52.24. Today we have not included the final regulatory language for these regulations. It is our intention to include regulatory changes that conform appendix S and 40 CFR 52.24 to today ’ s final rules in any final regulations that set forth an interim implementation strategy for the 8-hour

ozone standard. We intend to finalize changes to these sections precisely as we have finalized requirements for other parts of the program. Because these are conforming changes and the public has had an opportunity for review and comment, we will not be soliciting

additional comments before we finalize

them.

The major NSR program contained in parts C and D of title I of the Act is a preconstruction review and permitting program applicable to new or modified major stationary sources of air pollutants regulated under the Act. In areas not meeting health-based National Ambient Air Quality Standards (NAAQS) and in ozone transport regions (OTR), the program is implemented under the requirements of part D of title I of the Act. We call this program the

‘‘ nonattainment ’’NSR program. In areas meeting NAAQS ( ‘‘ attainment ’’areas) or

for which there is insufficient information to determine whether they meet the NAAQS ( ‘‘ unclassifiable ’’ areas), the NSR requirements under part C of title I of the Act apply. We call this program the Prevention of Significant Deterioration (PSD) program. Collectively, we also commonly refer to these programs as the major NSR program. These regulations are contained in 40 CFR 51.165, 51.166, 52.21, 52.24, and part 51, appendix S.

The NSR provisions of the Act are a combination of air quality planning and air pollution control technology program requirements for new and modified stationary sources of air pollution. In brief, section 109 of the Act requires us to promulgate primary NAAQS to protect public health and secondary NAAQS to protect public

welfare. Once we have set these standards, States must develop, adopt, and submit to us for approval a State Implementation Plan (SIP) that contains

emission limitations and other control

measures to attain and maintain the NAAQS and to meet the other requirements of section 110(a) of the

Act.

Each SIP is required to contain a preconstruction review program for the construction and modification of any stationary source of air pollution to assure that the NAAQS are achieved and maintained; to protect areas of clean air; to protect Air Quality Related Values (AQRVs) (including visibility) in national parks and other natural areas of special concern; to assure that appropriate emissions controls are applied; to maximize opportunities for economic development consistent with the preservation of clean air resources; and to ensure that any decision to increase air pollution is made only after full public consideration of all the consequences of such a decision.

For newly constructed, ‘‘ greenfield ’’ sources, the determination of whether an activity is subject to the major NSR program is fairly straightforward. The Act, as implemented by our regulations, sets applicability thresholds for major

sources in nonattainment areas [potential to emit (PTE) above 100 tons per year (tpy) of any pollutant subject to regulation under the Act, or smaller amounts, depending on the nonattainment classification] and attainment areas (100 or 250 tpy, depending on the source type). A new

source with a PTE at or above the applicable threshold amount ‘‘ triggers, ’’ or is subject to, major NSR.

The determination of what should be classified as a modification subject to major NSR presents more difficult issues. The modification provisions of the NSR program in parts C and D are

based on the definition of modification in section 111(a)(4) of the Act: the term

‘‘ modification ’’means ‘‘ any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. ’’That definition contemplates that, first, you will determine whether a physical or operational change will occur. If so, then you will proceed to determine whether the physical or operational change will result in an emissions

increase over baseline levels.

The expression ‘‘ any physical change * * * or change in the method of operation ’’ in section 111(a)(4) of the Act is not defined. We have recognized that Congress did not intend to make every activity at a source subject to the major NSR program. As a result, we have previously adopted several exclusions from what may constitute a

‘‘ physical or operational change. ’’For instance, we have specifically recognized that routine maintenance, repair and replacement, and changes in hours of operation or in the production rate are not considered a physical change or change in the method of


### 80188 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

2 See 40 CFR 52.21(b)(2).

3 See 40 CFR 52.21(b)(23).

4 In approximate terms, ‘‘ contemporaneous ’’

emissions increases or decreases are those that have occurred between the date 5 years immediately preceding the proposed physical or operational change and the date that the increase from the change occurs. See, for example, § 52.21(b)(3)(ii).

5 Once a modification is determined to be major, the PSD requirements apply only to those specific pollutants for which there would be a significant net emissions increase. See, for example,
§ 52.21(j)(3) (BACT) and § 52.21(m)(1)(b) (air quality analysis). 6 The regulations define ‘‘ electric utility steam generating units ’’as any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 megawatts (MW) of electrical output to any utility power distribution system for sale. See, for example, § 51.166(b)(30). operation within the definition of major

modification. 2

We have likewise addressed the scope of the statutory definition of modification by excluding all changes

that do not result in a ‘‘ significant ’’ emissions increase from a major

source. 3 This regulatory framework applies the major NSR program at existing sources to only ‘‘ major
modifications ’’at major stationary

sources.

One key attribute of the major NSR program in general is that you may

‘‘ net ’’modifications out of review by coupling proposed emissions increases at your source with contemporaneous emissions reductions. Thus, under regulations we promulgated in 1980, you may modify, or even completely replace, or add, emissions units without obtaining a major NSR permit, so long

as ‘‘ actual emissions ’’do not increase by a significant amount over baseline levels at the plant as a whole.

Applicability of the major NSR program must be determined in advance of construction and is pollutant-specific. In cases involving existing sources, this requires a pollutant-by-pollutant determination of the emissions change, if any, that will result from the physical or operational change. Our 1980 regulations implementing the PSD and nonattainment major NSR programs thus inquire whether the proposed change constitutes a ‘‘ major modification, ’’that is, a physical change or change in the method of operation

‘‘ that would result in a significant net emissions increase of any pollutant subject to regulation under the Act. ’’A

‘‘ net emissions increase ’’ is defined as

the increase in ‘‘ actual emissions ’’from the particular physical or operational change (taking into account the use of emissions control technology and restrictions on hours of operation or rates of production where such controls and restrictions are enforceable), together with your other contemporaneous increases or decreases

in actual emissions. 4 In order to trigger applicability of the major NSR program,

the net emissions increase must be

‘‘ significant. ’’ 5 Before today ’ s changes, our regulations generally defined actual

emissions as ‘‘ the average rate, in tpy, at which the unit actually emitted the pollutant during a 2-year period which precedes the particular date and which is representative of normal source operation. ’’The reviewing authorities will allow use of a different time period

‘‘ upon a determination that it is more representative of normal source operation. ’’We have historically used the 2 years immediately preceding the proposed change to establish a source ’ s actual emissions. However, in some

cases we have allowed use of an earlier period.

With respect to changes at existing sources, a prediction of whether the physical or operational change would result in a significant net increase in your actual emissions following the change was thus necessary. In part, this involved a straightforward and readily predictable engineering judgment

—how would the change affect the emission

factor or emissions rate of the emissions units that are to be changed.

Before today ’ s changes, the regulations provided that when your emissions unit, other than an electric utility steam generating unit (EUSGU),

‘‘ has not begun normal operations, ’’ actual emissions equal the PTE of the unit. When you have not begun normal operations following a change, you must assume that your source will operate at its full capacity year round, that is, at its full emissions potential. This is referred to as the actual-to-potential test. You may avoid the need for an NSR permit by reducing your source ’ s potential emissions through the use ofenforceable restrictions to premodification actual emissions levels plus an amount that is less than

‘‘ significant ’’

.

In 1992, we promulgated revisions to our applicability regulations creating special rules for physical and operational changes at EUSGUs. See 57 FR 32314 (July 21, 1992). 6 In this rule, prompted by litigation involving the Wisconsin Electric Power Company (WEPCO) and commonly referred to as

the ‘‘ WEPCO rule, ’’we adopted an actual-to-future-actual methodology for all changes at EUSGUs except the construction of a new electric generating unit or the replacement of an existing

emissions unit. Under this methodology, the actual annual emissions before the change are compared with the projected actual emissions after the change to determine if a physical or operational change would result in a significant increase in emissions. To ensure that the projection is valid, the rule requires the utility to track its emissions for the next 5 years and provide to the reviewing authority information demonstrating that the physical or operational change did not

result in an emissions increase.

In promulgating the WEPCO rule, we also adopted a presumption that utilities may use as baseline emissions the actual annual emissions from any 2 consecutive years within the 5 years immediately preceding the change.

In attainment areas, once major NSR is triggered, you must, among other things, install best available control technology (BACT) and conduct modeling and monitoring as necessary. If your source is located in a nonattainment area, you must install technology that meets the lowest achievable emissions rate (LAER),

secure emissions reductions to offset any increases above baseline emission levels, and perform other analyses.

B. Introduction

Today ’ s final regulations were proposed as part of a larger regulatory package on July 23, 1996 (61 FR 38250). That package proposed a number of changes to our existing major NSR requirements. (Please refer to the outline of that proposed rulemaking for a complete list of changes that were proposed to our existing regulations.) On July 24, 1998, we published a Federal Register Notice of Availability (NOA) that requested additional comment on three of the proposed changes: determining baseline emissions, actual-to-future-actual methodology, and PALs. Following the 1996 proposals, we held two public hearings and more than 50 stakeholder meetings. Environmental groups, industry, and State, local, and Federal agency representatives participated in these many discussions.

In May 2001, President Bush ’ s National Energy Policy Development Group issued findings and key recommendations for a National Energy Policy. This document included numerous recommendations for action, including a recommendation that the EPA Administrator, in consultation with the Secretary of Energy and other relevant agencies, review NSR regulations, including administrative interpretation and implementation. The recommendation requested that we issue a report to the President on the impact of the regulations on investment


### 80189 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

in new utility and refinery generation capacity, energy efficiency, and environmental protection.

In response, in June 2001, we issued a background paper giving an overview of the NSR program. This paper is

available on the Internet at http:// www.epa.gov/air/nsr-review/ background.html. We solicited public comments on the background paper and

other information relevant to the New Source Review 90-day Review and Report to the President. During our review of the NSR program, we met with more than 100 groups, held four public meetings around the country, and received more than 130,000 written comments. Our report to the President and our recommendations in response to the energy policy were issued on June 13, 2002. A copy of this information is

available at http://www.epa.gov/air/nsrreview/. We expect that our recommendations in response to the energy policy will be reflected in the future in various programs and regulatory actions. Today ’ s actions implement several of those

recommendations.

Today, we are finalizing five actions that we previously proposed in 1996 (three of which were re-noticed in the 1998 NOA). We are not taking final action on any of the remaining issues in the 1996 proposal at this time. We have

not decided what final action we will

take on those issues.

C. Overview of Final Actions

Today we are taking final action on five changes to the NSR program that will reduce burden, maximize operating flexibility, improve environmental quality, provide additional certainty, and promote administrative efficiency.

These elements include baseline actual emissions, actual-to-projected-actual emissions methodology, PALs, Clean Units, and PCPs. We are also codifying our longstanding policy regarding the

calculation of baseline emissions for EUSGUs. In addition, we are responding to comments we received on a proposal to adopt a methodology, developed by the American Chemistry Council (formerly known as the Chemical Manufacturers Association (CMA)) and other industry petitioners, to determine

whether a source has undertaken a modification based on its potential emissions. We are including a new section in today ’ s final rules that outlines how a major modification is determined under the various major NSR applicability options and clarifies where you will find the provisions in our revised rules. Finally, we have

codified a new definition of ‘‘ regulated NSR pollutant ’’that clarifies which pollutants are regulated under the Act for purposes of major NSR.

This section briefly introduces each improvement. Detailed discussions of the improvements are found in sections II through VII of this preamble.

1. Determining Whether a Proposed Modification Results in a Significant

Emissions Increase

Today we are finalizing two changes to our existing major NSR regulations that will affect how you calculate

emissions increases to determine whether physical changes or changes in the method of operation trigger the major NSR requirements. First, we have a new procedure for determining

‘‘ baseline actual emissions. ’’That is, therelevant terminology for calculating prechange emissions for most applications

is now ‘‘ baseline actual emissions ’’
rather than ‘‘ actual emissions. ’’You may use any consecutive 24-month period in the past 10 years to determine your baseline actual emissions. Second, we are supplementing the existing actual-to-potential applicability test with an actual-to-projected-actual applicability test for determining if a physical or operational change at an existing emissions unit will result in an emissions increase. Notwithstanding the new test, you will still have the ability to conduct an actual-to-potential typetest within the new actual-to-projectedactual applicability test. In this case, you will not be subject to recordkeeping requirements that are being established and would otherwise apply as part of the new actual-to-projected actual applicability test.

For EUSGUs, we are making several changes to the existing procedures and are codifying our current policy for calculating the baseline actual emissions. That is, the baseline actual emissions for EUSGUs is the average rate, in tpy, at which that unit actually emitted the pollutant during a 2-year (consecutive 24-month) period within the 5-year period immediately preceding when the owner or operator begins actual construction. We are also retaining the option that allows the use of a different time period if the reviewing authority determines it is more representative of normal source operation.

2. CMA Exhibit B

As described in section I.C.1 above,we have decided to adopt an actual-toprojected-actual methodology, combined with a revised process to determine baseline emissions, to use in determining when sources are

considered to have made a modification and are thereby subject to NSR. We are not adopting the methodology based on potential emissions as discussed in the CMA Exhibit B proposal. See section III of this preamble for a discussion of the comments we received on this proposal and our responses.

3. Plantwide Applicability Limitations

A PAL is a voluntary option that will provide you with the ability to manage facility-wide emissions without triggering major NSR review. We believe that the added flexibility provided under a PAL will facilitate your ability to respond rapidly to changing market conditions while enhancing the environmental protection afforded under the program.

Today we are promulgating a PAL based on plantwide actual emissions. If you keep the emissions from your facility below a plantwide actual emissions cap (that is, an actuals PAL), then these regulations will allow you to avoid the major NSR permitting process when you make alterations to the facility or individual emissions units. In return for this flexibility, you must monitor emissions from all of your

emissions units under the PAL. The benefit to you is that you can alter your facility without first obtaining a Federal NSR permit or going through a netting review. A PAL will allow you to make changes quickly at your facility. If you are willing to undertake the necessary recordkeeping, monitoring, and reporting, a PAL offers you flexibility and regulatory certainty.

4. Clean Units

We are promulgating a new type of applicability test for emissions units that are designated as Clean Units. The new applicability test recognizes that when you go through major NSR review and install BACT or LAER, you may make any changes to the Clean Unit without triggering an additional major NSR review, if the project at a Clean

Unit does not cause the need for a change in the emission limitations or work practice requirements in the permit for the unit that were adopted in conjunction with BACT or LAER and the project would not alter any physical or operational characteristics that

formed the basis for the BACT or LAER determination. If the project causes the need for a change in the emission limitations or work practice requirements in the permit for the unit adopted in conjunction with BACT or LAER or would alter any physical or operational characteristics that formed

the basis for the BACT or LAER determination, you lose Clean Unit status. You may still proceed with the project without triggering major NSR


### 80190 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

review, if the increase is not a significant net emissions increase.
Emissions units that have not been through major NSR may still qualify for Clean Unit status if they demonstrate
that the emissions control level is comparable to BACT or LAER. Clean Unit status will be valid for up to a 10- year period. The new applicability test
does not exclude consideration of physical changes or changes in the method of operation of Clean Units from major NSR, but rather changes the way
emissions increases are calculated for these changes. This new applicability test therefore protects air quality, creates
incentives for sources to install state-ofthe-art controls, provides flexibility for sources, and promotes administrative efficiency.

5. Pollution Control Projects

Today ’ s rule contains a new list of environmentally beneficial technologies that qualify as PCPs for all types of
sources. Installation of a PCP is not subject to the major modification provisions. An owner or operator installing a listed PCP automatically qualifies for the exclusion if there is no adverse air quality impact

—that is, if it
will not cause or contribute to a violation of NAAQS or PSD increment, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by a Federal Land Manager (FLM) and for which information is available to the general public. The PCPs that are not listed in today ’ s rules may also qualify for the PCP Exclusion if the reviewing authority determines on a case-specific
basis that a non-listed PCP is environmentally beneficial when used for a particular application. Also, in the future, we may add to the listed PCPs through a rulemaking that provides for public notice and opportunity for
comment. The PCP Exclusion allows
sources to install emissions controls that are known to be environmentally beneficial. These provisions thus offer flexibility while improving air quality.

6. Major NSR Applicability

We have briefly described the new provisions for baseline actual emissions, actual-to-projected-actual methodology, PALs, and Clean Units. Sections II, IV, and V describe the new provisions in detail. These provisions offer major new changes to NSR applicability, especially regarding how a major modification is determined. The major NSR applicability provisions have developed

over time and therefore have been added to the NSR rules in a piecemeal fashion. In today ’ s final rules we are including a new section that outlines how a major modification is determined under the various major NSR applicability options and clarifies where you will find the provisions in our revised rules. For each applicability option, we describe how a major
modification is determined in detail.

You ’ ll find this new applicability

‘‘ roadmap ’’in §§ 51.165(a)(2), 51.166(a)(7), and 52.21(a)(2). To summarize, the various provisions for major modifications are now as follows.

• Actual-to-projected-actual applicability test for all existingemissions units. (Including an actual-topotential option)

• Actual-to-potential test for any new unit, including EUSGUs.

• The Clean Unit Test for existing
emissions units with Clean Unit status.

• The hybrid test for modifications with multiple types of emissions units. (Used when a physical or operational change affects a combination of more than one type of unit.)

We describe actuals PALs, which are an alternative way of complying with major NSR, in section IV of this preamble. If you have a PAL, as long as you are complying with the PAL requirements, any physical or operational changes are not major

modifications.

We have revised the definition of major modification to clarify what has always been our policy

—that determining whether a major modification has occurred is a two-step process. The new definition of major

modification is ‘‘ 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. ’’ We have also revised the definitions of actual emissions,
emissions unit, net emissions increase,
and construction. We have deleted the

word ‘‘ actual ’’as related to emissions

from the definition of ‘‘ construction. ’’ This change was necessary because of

how the definition of ‘‘ actual

emissions ’’is used in the final rule, but the deletion is not intended to change any meaning in the term ‘‘ construction. ’’
We have added new definitions for baseline actual emissions, projected actual emissions, project, and significant emissions increase. These revisions and additions implement our new provisions for major modifications under the actual-to-projected-actual applicability test, actual-to-potential test, Clean Unit Test, and hybrid test. You will find a complete discussion of the Clean Unit Test, including how modifications to Clean Units are treated, in section V of this preamble. The other

tests are discussed in section II. ‘‘ Actual emissions, ’’as the term has been historically applied, will still be used to determine air quality impacts (for example, compliance with NAAQS, PSD increments, and AQRVs) and to compute the required amount of

emissions offsets.

To further clarify major NSR applicability in one location, we have

moved § 51.166(i)(1) through (3) and § 52.21(i)(1) through (3) into the new applicability sections at § 51.166(a)(7)

and § 52.21(a)(2). These provisions clarify that you must obtain a permit before you begin construction (including for major modifications), that the provisions apply for each regulated NSR pollutant that your source emits, and that the provisions apply to any source located in the area designated as attainment or unclassifiable (for §§ 51.166 and 52.21).

We have also added a new definition for reviewing authority that clarifies who has authority to implement major NSR programs. Reviewing authority means the State air pollution control agency, local agency, other State agency, Indian tribe, or other agency authorized by the Administrator to carry out a permit program under §§ 51.165 and 51.166, or the Administrator in the case of EPA-implemented permit programs

under § 52.21.

7. Enforcement

As noted above, today we are taking final action on five changes to the NSR program that create alternative means of determining NSR applicability for projects that begin actual construction after these provisions become effective in your jurisdiction. If you are subsequently determined not to have met any of the obligations of these new alternatives (for example, failure to meet emissions or applicability limits, properly project emissions, and/or properly implement the PCP Exclusion or Clean Unit Test), you will be subject to any applicable enforcement provisions (including the possibility of

citizens ’suits) under the applicable

sections of the Act. Sanctions for violations of these provisions may include monetary penalties of up to $27,500 per day of violation, as well as the possibility of injunctive relief, which may include the requirement to install air pollution controls.

8. Enforceability

This rule uses several terms related to enforceability of particular provisions. A requirement is ‘‘ legally enforceable ’’if some authority has the right to enforce the restriction. Practical enforceability for a source-specific permit will be


### 80191 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

7 See memorandum, ‘‘ Release of Interim Policy on Federal Enforceability of Limitations on Potential to
Emit, ’’signed by John Seitz and Robert Van Heuvelen, Jan. 22, 1996 at 5

–6 and Attachment 4,

available on the Web as http://www.epa.gov/ rgytgrnj/programs/artd/air/title5/t5memos/ pottoemi.pdf. More detailed guidance on practical enforceability is contained in the memorandum.

8 The Agency has frequently used the term

‘‘ practicably enforceable ’’and ‘‘ practical enforceability, ’’interchangeably. There is no difference in the meaning of these terms.

9 See generally memorandum, ‘‘ Options for Limiting the Potential to Emit (PTE) of a Stationary

Source Under Section 112 and Title V of the Clean
Air Act, ’’signed by John Seitz and Robert Van Heuvelen, Jan. 25, 1995, at 2

– 3. 10 By definition, the modification of an existing source is potentially subject to major NSR only if that existing source is ‘‘ major. ’’In addition, when an existing ‘‘ minor ’’source makes a physical or operational change that by itself is major, that change constitutes a major stationary source that is subject to major NSR. See , for example,
§ 52.21(b)(1)( c).

11 For NSR purposes, the definition of ‘‘ electric utility steam generating unit ’’ means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a steam electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility. See, for example, § 52.21(b)(31). Reference in this notice to utility units is meant to include all emissions units covered by this definition.

12 We promulgated special applicability rules for physical and operational changes at EUSGUs in

1992. See 57 FR 32314 (July 21, 1992). achieved if the permit ’ s provisions specify: (1) A technically-accurate limitation and the portions of the source subject to the limitation; (2) the time period for the limitation (hourly, daily, monthly, and annual limits such as rolling annual limits); and (3) the method to determine compliance, including appropriate monitoring, recordkeeping, and reporting. For rules and general permits that apply to categories of sources, practicable enforceability additionally requires that the provisions: (1) Identify the types or categories of sources that are covered by the rule; (2) where coverage is optional, provide for notice to the permitting authority of the source ’ s election to be covered by the rule; and (3) specify the enforcement consequences relevant to

the rule. 7, 8 ‘‘ Enforceable as a practical

matter ’’will be achieved if a requirement is both legally and practically enforceable.

Note that we continue to require offsets to be federally enforceable.

‘‘ Federal enforceability ’’means that not only is a requirement practically enforceable, as described above, but in addition, ‘‘ EPA must have a direct right

to enforce restrictions and limitations imposed on a source to limit its exposure to Act programs. ’’ 9 Also note that, for computing baseline actual emissions for use in determining major NSR applicability or for establishing a PAL, you must consider ‘‘ legally

enforceable ’’requirements. A requirement will be legally enforceable if the Administrator, State, local or tribal air pollution control agency has the authority to enforce the requirement irrespective of its practical enforceability.

In our existing regulations that are unamended by today ’ s action, the term

‘‘ federally enforceability ’’still appears. In 1995, the court in Chemical Manufacturers Ass’n v. EPA remanded the definition of PTE in the major NSR program to EPA. No. 89

– 1514 (D.C. Cir. Sept. 150 1995). Because the court vacated the requirements in the nationwide rules, the term federal enforceability as it relates to PTE is not in effect (pending final rule making by the Agency) in the Federal rules. The decision, however, did not address the

term ‘‘ federally enforceable ’’as used in SIPs, because that issue was not before

the court.

II. Revisions to the Method for Determining Whether a Proposed Modification Results in a Significant

Emissions Increase

A. Introduction

Today we are finalizing two sets of amendments to our existing major NSR regulations that provide another way in which you may calculate emissions

increases to determine whether certain types of physical changes or changes in the method of operation (physical or operational changes) of an existing emissions unit trigger the major NSR requirements. 10 The first set of amendments relates to the way in which you will determine your baseline actual

emissions for such emissions units in

accordance with a new definition of

‘‘ baseline actual emissions. ’’ See, for example, new § 52.21(b)(48). We will be allowing you to use any consecutive 24- month period during the 10-year period prior to the change to determine your baseline actual emissions for existing emissions units (other than EUSGUs). The second set of amendments replaces the existing actual-to-potential and actual-to-representative-actual-annual emissions applicability tests for existing emissions units (including EUSGUs) with an actual-to-projected-actual applicability test for determining if a physical or operational change will

result in an emissions increase at such units. (Notwithstanding this new test, the actual-to-potential methodology is still available at your option under the new applicability tests.) The newprocedure for determining your prechange baseline actual emissions will not apply to EUSGUs. 11 Instead, for EUSGUs we are retaining the existing procedures for determining the baseline

actual emissions. 12 See, for example, existing § 52.21(b)(33). We are also affirming our current method used for calculating the baseline actual emissions for EUSGUs (allowing any consecutive 2 years in the past 5 years, or another more representative period) by codifying it in the NSR regulations.
See, for example, new § 52.21(b)(48).

For existing emissions units other than EUSGUs, the changes we are making to the method for calculating a

unit ’ s baseline actual emissions will apply only for the following three

purposes.

• For modifications, to determine a

modified unit ’ s pre-change baseline actual emissions as part of the new actual-to-projected-actual applicability

test.

• For netting, to determine the prechange baseline actual emissions of an

emissions unit that underwent a physical or operational change within the contemporaneous period.

• For PALs, to establish the PAL emissions cap.

Today ’ s new procedures for calculating baseline actual emissions and for the actual-to-projected-actual applicability test should not be used when determining a source ’ s actual emissions on a particular date as may be

used for other NSR-related requirements. Such requirements include, but are not limited to, air quality impacts analyses (for example, compliance with NAAQS, PSD increments, and AQRVs) and computing the required amount of emissions offsets. For each of these requirements, the existing definition of ‘‘ actual

emissions ’’continues to apply. This is discussed in greater detail in section

II.D.9.

We believe that these changes will greatly improve the major NSR program by responding to industry concerns with our existing methodology without compromising air quality. One common complaint about the current emissions baseline process is that you have a limited ability to consider the operational fluctuations associated with normal business cycles when establishing baseline actual emissions unless your reviewing authority agrees that another period is ‘‘ more representative of normal source


### 80192 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

13 The definition of ‘‘ actual emissions ’’ requires

that a unit ’ s actual emissions be based on a consecutive 24-month period immediately preceding the particular change. Also, however, it directs the reviewing authority to allow the use of another time period upon a determination that it is more representative. This procedure continues to be appropriate under the pre-existing regulation and for other NSR purposes, such as determining a

source ’ s ambient impact against the PSD increments, and we continue to require its use for such purposes.

14 Note that we plan, in the near future, to issue a Notice of Proposed Rulemaking that will address

the issue of ‘‘ debottlenecking. ’’ In today ’ s rulemaking, we do not intend to change current requirements related to ‘‘ debottlenecking. ’’ Use of

the term ‘‘ changed unit ’’should not be interpreted as a change to those requirements. operation. ’’ 13 By extending the time period from which you may establish your baseline actual emissions, the new procedures should reflect the emissions levels that occur during a normal business cycle, without requiring you to demonstrate to your reviewing authority that another period is ‘‘ more representative of normal source operations. ’’

Commenters also believe that the current methodology requires many changes made to existing equipment to go through major NSR, without taking into account operating history, even when such changes will not result in increased pollution to the environment. Our new applicability requirements

address these commenters ’ concerns and will focus limited resources more effectively.

We are also modifying the way you may determine whether emissions at existing units (including EUSGUs) will increase, by allowing you to use projected actual emissions for purposes

of this determination. Under this approach, in circumstances where there is a reasonable possibility that a project that is not part of a major modification may result in a significant increase of a regulated NSR pollutant, before beginning actual construction, you may choose to make and record a projection of post-change emissions of that pollutant from changed units. 14

To make this projection, you must use

the maximum annual rate at which the changed units are projected to emit the pollutant in any of the 5 calendar years following the time the unit resumes regular operations after the project (or 10 years if the project increases the

unit ’ s design capacity or potential to emit the regulated NSR pollutant). You then use these projections to calculate whether the project will result in a significant emissions increase. In making this calculation, you could exclude any emissions that the unit

could have accommodated before the change and that are unrelated to the project. You could also exclude emissions resulting from increased utilization due to demand growth that

the unit could have accommodated before the change.

With respect to the covered changes, if you use this procedure, you are required to track post-change annual emissions of the units in tpy for the next 5 years (or 10 years if the project

increases the unit ’ s design capacity or potential to emit the regulated NSR pollutant). At the end of each year, if post-change annual emissions exceed the baseline actual emissions by a significant amount, and differ from your projections, you must submit a report to the reviewing authority with that information within 60 days after the end of the year.

Instead of relying on projected actual emissions, you may instead elect to use

the unit ’ s PTE, in tpy. In that case, you need not track or report post-change

emissions.

We are also revising the procedures for projecting future emissions for

EUSGUs to conform with these new procedures and consolidate the EUSGU and non-EUSGU procedures into a single set of provisions. As a result of our 1992 rulemaking, EUSGUs have

available to them a similar set of procedures. We believe the procedures we are implementing for other units represent a sensible refinement of the rules we promulgated in 1992 and that we should make these procedures available to all existing units. We do, however, impose two requirements on EUSGUs beyond those we impose on other units. First, with respect to covered projects, EUSGUs that project post-change emissions will have to submit a copy of their projections to their reviewing authority before beginning actual construction. You will not be required to obtain any kind of determination from the reviewing authority before proceeding with construction. Second, we are requiring that if you project post-change emissions for your EUSGUs, you must send a copy of your tracked emissions to your reviewing authority, without regard to whether these emissions have increased by a significant amount or exceed your projections. The effect of

this consolidation is that we make minor changes to the existing procedures for EUSGUs. For example, you must project emissions for EUSGUs on a 12-month basis, rather than the current approach of projecting average annual emissions for the 2 years immediately following the change. Also, you need only make and report a projection for EUSGUs when there is a reasonable possibility that the given project may result in a significant

emissions increase.

By allowing you to use today ’ s new version of the actual-to-projected-actual applicability test to evaluate modified existing emissions units, we expect that fewer projects will trigger the major NSR permitting requirements. Nonetheless, we believe that the environment will not be adversely affected by these changes and in some respects will benefit from these changes.

The new test will remove disincentives that discourage sources from making the types of changes that improve operating efficiency, implement pollution prevention projects, and result in other environmentally beneficial changes. Moreover, the end result is that State and local reviewing authorities can appropriately focus their limited

resources on those activities that could cause real and significant increases in pollution.

In addition, today ’ s changes provide benefits to the public and the environment through the improved recordkeeping and reporting requirements as discussed above. We believe that these added recordkeeping and reporting measures will provide the information necessary for reviewing authorities to assure that such changes

are made consistent with the CAA requirements. The new rule also does not affect the way in which a source ’ s ambient air quality impacts are evaluated. Altogether, we believe that today ’ s regulatory amendments focus on the types of changes occurring at existing emissions units that are more likely to result in significant contributions to air pollution.

B. What We Proposed and How Today’s Action Compares

1. July 23, 1996 Notice of Proposed Rulemaking (NPRM)

In 1996, we proposed to amend the NSR rules to allow States to use, among other things, a new test as an alternative to the actual-to-potential test for determining the applicability of the NSR requirements when you wish to make modifications at an existing major stationary source. The proposed test was intended to apply exclusively to modifications of existing emissions units at major stationary sources

—not to new emissions units. As described more completely below, the proposed test involved changes to the procedures for calculating an emissions unit ’ s prechange (baseline) actual emissions and post-change (future) actual emissions. The method would have also required you to monitor and report future

emissions from certain modified


### 80193 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

15 This method, as well as the WEPCO amendments as a whole, was limited to modifications of existing EUSGUs and did not apply to the addition of a new emissions unit or the replacement of an existing unit. emissions units, based on the monitoring and reporting requirements adopted under the WEPCO

amendments.

Baseline actual emissions. In our 1996 NPRM, we proposed to change the

definition of baseline emissions from the average annual rate of actual emissions during the 2-year period preceding the date of the modification

to the annual rate associated with the highest level of utilization from any consecutive 12-month period during the 10-year period preceding the date of the modification, adjusted for any more stringent limits that may have been imposed since the end of the 12-month period selected. The proposed method was intended to be used for calculating baseline actual emissions for any existing emissions unit, including EUSGUs, by replacing both the originalmethod (that was part of the actual-topotential test) and the 2-in-5-years method (as adopted under the WEPCO for modified EUSGUs).

As indicated above, the proposed procedure also would have required you to take into account any legally enforceable constraints imposed on the facility since the selected 12-month time frame, and currently in effect. Thus, you would generally have been required to

calculate the modified emissions unit ’ s baseline actual emissions by using the appropriate utilization level from the selected 12-month period, in

combination with the emissions unit ’ s current enforceable emission factors.

Such enforceable emission factors

would have included current Federal and State limits, such as RACT (Reasonably Available Control Technology), MACT (Maximum Achievable Control Technology), BACT, LAER, and New Source Performance Standards (NSPS), as well as enforceable limits resulting from any voluntary reductions you may have taken (for example, for netting, offsets, or Emission Reduction Credits (ERCs)). Also, you would have had to consider any operational constraints that are enforceable, such as production limits, fuel use limits, or limits to the number of hours per day or days per year at which the unit modified, or affected by such modification, could operate.

Finally, we indicated that it was not our intent to extend the 5-year contemporaneous period (for considering creditable emissions increases and decreases as part of the netting calculus), even if we established a 10-year baseline look back period.

Post-change actual emissions. In the 1996 proposal, we proposed to extendthe availability of the actual-to-futureactual emissions method, established under the WEPCO amendments exclusively for EUSGUs, to predict the future actual emissions from any emissions unit undergoing a physical or operational change. Thus, we proposed extending availability of the definition

of ‘‘ representative actual annual

emissions ’’to all emissions units undergoing a physical or operational change. This definition would have provided the basis for you to project an

emissions unit ’ s future actual emissions, excluding any emissions increases caused by demand growth or other independent factors, when determining whether the change at issue will

increase emissions over the baseline

levels. 15

The proposal also retained the WEPCO provision requiring that, for any modified emissions unit using the actual-to-future-actual test, you must submit annually for 5 years after the change sufficient records to demonstrate that the change has not resulted in a significant emissions increase over the baseline levels. As a safeguard, the WEPCO rule also provides that this tracking period could be extended to 10 years when the reviewing authority is concerned that the first 5 years will not be representative of normal source operation. We sought comments on numerous issues, including whether any changes should be made to the 5-year tracking requirement or to the demand growth exclusion in the event that we

decided to broaden use of the actual-tofuture-actual test for modifications to any existing emissions unit.

2. July 24, 1998 Notice of Availability

In 1998, we announced that

comments received on the 1996 proposal and changed circumstances

had caused us to ask whether we should reconsider some of the aspects of the proposed changes to the ‘‘ major
modification ’’ applicability test. The 1998 NOA set forth for public comment an additional applicability test. In brief, the alternative presented for additional comment would have: (1) Retained the

actual-to-future-actual test for EUSGUs and applied it to all source categories; (2) made binding for a 10-year period the emissions levels used in projecting future actual emissions following the modification for all source categories; and (3) eliminated the demand growth exclusion for calculating a modified

emissions unit ’ s future actual emissions.

Consistent with the 1996 NPRM, this alternative methodology would have applied to any existing emissions unit at a major stationary source for which you might plan a non-routine physical or operational change. The methodology would have required you first to

determine which emissions units were being changed, or were affected by the change, then to calculate those units ’
baseline actual emissions based on the highest consecutive 12 months of source operation during the past 10 years, adjusted to reflect current emission

factors.

The second step involved the forecast of future emissions resulting from the physical or operational change. Under

this calculation of future actual emissions, one would not have been allowed to exclude predicted capacity

utilization increases that were due to demand growth. If the difference between the pre-change and post-change actual emissions equaled or exceeded the significant emissions rate defined for a particular pollutant, major NSR would have been triggered (unless you took enforceable limits to keep the increase below significant levels or were otherwise able to net out of review using creditable, contemporaneous emissions increases and decreases occurring at your facility). If the difference between

baseline and future actual emissions did not exceed the applicable significant emissions rate, your facility would not be subject to major NSR, but you would have been required to accept a temporary emissions cap based on the predicted future actual emissions for each affected pollutant at the emissions units being modified or affected by the

modification.

The temporary cap would have

become an enforceable condition of a preconstruction permit. Also, the sole purpose of the temporary cap would have been to make sure that the physical or operational change did not result in a significant emissions increase, and the cap would have applied to those emissions units for at least 10 years after the changes were completed. You would also have been required to supply information annually to demonstrate

that the future actual emissions did not exceed the applicable emissions caps during the 10-year period following the

modification.

3. Summary of Major Changes in the

Final Rule

Today ’ s action amends the existing NSR regulations to provide you with a common applicability test for all existing emissions units

—the actual-toprojected-actual applicability test. This test has changed in some ways from

both the 1996 NPRM and the 1998 NOA. As described in greater detail in sections


### 80194 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

16 We do make use of the term ‘‘ resumes regular operations ’’(as opposed to ‘‘ normal operations ’’ ) in the final rule, but that term has a very different meaning and we are using it for an entirely different purpose. Specifically, we are not using the term for purposes of determining whether a change results in a significant emissions increase. Rather, we use it only to identify the date on which the owner or operator must begin tracking emissions of changed units when using the actual-to-projected-actual

method. 17 The 1980 rulemaking also discussed that

‘‘ reconstruction ’’would have only been applied on a plantwide basis and EPA believed that there would be few instances of plantwide

reconstructions.

18 For simplicity, we state this rule without addressing whether the replacement or reconstruction has resulted in a significant net emissions increase, but under our two-step approach for evaluating whether a change constitutes a major modification, a significant net

emissions increase would of course also be required. We have also retained the term

‘‘ representative of normal operations ’’ in the

context of an EUSGU ’ s option to seek use of a different baseline period, but there the question

whether to seek such use is at the source ’ s option, obviating many of the difficulties with it in other

contexts. II.C and II.D below, the key features of the methodology are as follows.

• If you are an existing emissions unit (other than an EUSGU), you will determine the pre-change (baseline) actual emissions by calculating an average annual emissions rate, in tpy, using any consecutive 24 months during the 10-year period immediately preceding the change. This rate must be adjusted downward to reflect any legally enforceable emission limitations imposed after the selected baseline period.

• We are codifying the ‘‘ 2-in-5-years ’’ presumption for calculating the baseline

actual emissions for EUSGUs.

• If you are an existing emissions unit (including EUSGUs), you will estimate post-change emissions (projected actual emissions), in tpy, to reflect any increase in annual emissions that may result from the proposed change. You should exclude, in calculating any

increase in emissions that results from the particular project, that portion of the

unit ’ s emissions following the project that an existing unit could have accommodated during the baseline period and that is also unrelated to the particular project, including any increased utilization due to product demand growth. You must make the projection before you begin actual construction. When using this method, you must record the projection and

certain other information in

circumstances where there is a reasonable possibility that a change may result in a significant emissions increase. In addition, EUSGUs must send a copy of the projections and other information to your reviewing authority before beginning actual construction.

• If, for a project at an existing emissions unit (other than an EUSGU) at a major stationary source, you elect to project your post-change emissions, we are also requiring you to maintain information on these emissions, for 5 years following a physical or operational change, or in some cases for 10 years depending on the nature of the change. If your annual emissions exceed the baseline actual emissions by a significant amount and also exceed your projection, you must report this information to your reviewing authority within 60 days after the end of the year.

• If you project post-change emissions for EUSGUs, you must report these emissions to your reviewing authority within 60 days after the end of the year without regard to whether

such emissions exceed the baseline actual emissions or projected actual emissions for a period of 5 years (or in some cases 10 years, depending on the nature of the change). • Instead of projecting your postchange emissions, for all existing emissions units you may instead project post-change emissions on the basis of

each unit ’ s post-change PTE. If you use this method, you need not record yourprojections or track or report postchange emissions.

As discussed earlier, our prior regulations provide that when your emissions unit, other than an EUSGU,

‘‘ has not begun normal operations,

‘‘ actual emissions equal the PTE of the

unit. There have been considerable

number issues raised with this approach. For example, using PTE as a measure of post-change emissions automatically attributes all possible emissions increases to the change. There are many cases, however, where this simply is not true. Moreover, when the actual-to-potential test is applied, it is automatically assumed that the emissions unit has not begun normal operations after the change period. In many such cases, however, the changed unit as a practical matter will function essentially as it did before the change. We are, therefore, allowing all existing

emissions units to use an actual-toprojected-actual applicability test. Accordingly, we are generally eliminating the term ‘‘ begun normal operations ’’from the determination of whether a change results in a significant

emissions increase. 16

For essentially the same reasons,

while our 1992 rules did not authorize use of projections in evaluating whether replacement of an existing emissions unit (which we understood to require application of the NSPS 50 percent cost threshold) constitutes a major modification, upon reflection we have decided this exception to theavailability of the actual-to-projectedactual applicability test is also unnecessary. In our 1980 rulemaking, we decided against applying PSD to

‘‘ reconstruction, ’’even of entire sources, on the grounds that, as to existing

sources that would not otherwise be subjected to PSD review as a major modification (i.e. , such source would not cause a significant net emissions increase), changes that had no emission consequences should not be subject to PSD regardless of their magnitude. 17

In addition, we now believe that, as with modified units, the fact that replacement units are replacing similar

units with a record of historical operational data provides sufficient reasons to believe that a projection of

future actual emissions can be sufficiently reliable that an up-front emissions cap based on PTE is unnecessary. In other words, a source replacing a unit should be able to adequately project and track emissions for the replacement unit based, in part, on the operating history of the replaced unit. In contrast, sources adding ‘‘ new ’’ units that do not qualify as replacement units must project that the future emissions of the new unit equal its PTE, effectively applying the ‘‘ actual-topotential ’’test because there is no

relevant historical data that could be

used to establish an actual emissions baseline or projection of future actual

emissions for such new units.

For these reasons, we have eliminated the requirement that replaced or

reconstructed units be evaluated as to whether they constitute major modifications on an actual-to-potential basis. Instead, you may compare an

emission unit ’ s baseline actual emissions with your projected actual emission in measuring whether the replacement or reconstruction has resulted in a significant emissions

increase. You must treat these emissions units as modifications only if the replacement or reconstruction of the unit results in a signficant increase so

measured. 18


### 80195 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

C. Changes to the Procedures for Calculating the Pre-Change Baseline Actual Emissions for Existing Emissions

Units Other Than EUSGUs

1. Under Today ’ s New Requirements, How Should I Calculate the Pre-Change

Baseline Actual Emissions for an Existing Emissions Unit That Is Not an

EUSGU?

When you calculate the baseline actual emissions for an existing emissions unit (other than an EUSGU), you may select any consecutive 24 months of source operation within the past 10 years. Using the relevant source records for that 24-month period, including such information as the utilization rate of the equipment, fuels and raw materials used in the operation of the equipment, and applicable emission factors, you must be able to calculate an average annual emissions rate, in tpy, for each pollutant emitted by the emissions unit that is modified, or is affected by the modification.

The new requirements prohibit you from counting as part of the baseline actual emissions any pollution levels that are not allowed under any legally enforceable limitations and that apply at the time of the project. Therefore, you must identify the most current legally enforceable limits on your emissions unit. If these legally enforceable emission limitations and operating restrictions are more stringent than those that applied during the 24-month period, you must adjust downward the average annual emissions rate that you

calculated from the consecutive 24- month period to reflect these current restrictions. ( See section II.C.5 of this preamble for further discussion of the adjustment that you may need to make.)

In summary, when the average annual emissions rate that you originally calculated is still legally achievable (see discussion below), then your baseline

actual emissions will be the same as the average annual emissions rate calculated from the 24-month period. If it is not, you must adjust it downward

so that it does not reflect emissions that are no longer legally allowed.

2. Can Existing Emissions Units (Other Than EUSGUs) Still Use a ‘‘ More Representative Time Period ’’for Selecting the Baseline Actual

Emissions?

No, under today ’ s new requirements neither you nor your reviewing authority will have the authority to select another period of time from which to calculate your baseline actual

emissions. You must select a 24-month period within the 10-year period before the physical or operational change. 3. From What Point in Time Is the 10-

Year Look Back Measured?

If you believe that you will need either a major or minor NSR permit to proceed with your proposed physical or operational change, then you must use the 10-year period immediately preceding the date on which you submit a complete permit application. If, however, you believe that the physical or operational change(s) you plan to

make will not result in either a significant emissions increase from the project or a significant net emissions increase at your major stationary source (that is, your project will not be a major modification), and you are not otherwise required to obtain a minor NSR permit before making such change, then you must use the 10-year period that immediately precedes the date on which you begin actual construction of the physical or operational change.

4. What if, for an Existing Emissions Unit (Other Than an EUSGU), I Do Not Have Adequate Documentation for Its Operation for the Past 10 Years?

Your ability to use the full 10 years of the look back period will depend upon the availability of relevant data for the consecutive 24-month period you wish to select. The data must adequately describe the operation and associated pollution levels for the emissions units being changed. If you do not have the data necessary to determine the units ’ actual emission factors, utilization rate,

and other relevant information needed to accurately calculate your average annual emissions rate during that period of time, then you must select another consecutive 24-month period within the 10-year look back period for which you have adequate data.

5. For an Existing Unit (Other Than EUSGUs), When Must I Adjust My Calculation of the Pre-Change Baseline

Actual Emissions?

Today ’ s amendments require you to adjust the average annual emissions rate

derived from the selected 24-month period under certain circumstances. Specifically, you must adjust downward this average annual rate if any legally enforceable emission limitations, including but not limited to any State or Federal requirements such as RACT, BACT, LAER, NSPS, and National

Emission Standards for Hazardous Air Pollutants (NESHAP), restrict the

emissions unit ’ s ability to emit a particular pollutant or to operate at levels that existed during the selected 24-month period from which you calculate the average annual emissions rate. For example, assume that during the selected consecutive 24-month period you burned fuel oil and you were subjected to a sulfur limit of 2 percent sulfur (by weight). Today, you are only

allowed to burn fuel oil with a sulfur content of 0.5 percent or less. Consequently, you would be required to adjust your preliminary calculation of

baseline actual emissions for sulfur dioxide (SO 2) (that is, substitute the

lower sulfur limit into the emissions calculation, yielding a 75 percent

reduction in the emissions rate from the initial calculation) to reflect the current restriction allowing only 0.5 percent sulfur in fuel oil. The original average

annual utilization rate would not be adjusted unless a more stringent legally enforceable operational limitation has since been imposed that restricts that

rate.

You must also adjust for legally enforceable emission limitations you may have voluntarily agreed to, such as limits you may have taken in your permit for netting, emissions offsets, or the creation of ERCs. Also, you must adjust your emissions from the 24- month period if a raw material you used during the baseline period is now prohibited. For example, you may have used a paint with a high solvent concentration during a portion of the consecutive 24-month period. Today, you are prohibited from using that particular paint. You must then adjust your emissions rate to reflect the raw

material restriction.

6. How Should I Calculate the Baseline

Actual Emissions for Emissions Units (Other Than EUSGUs) That Use Multiple Fuels or Raw Materials?

For an emissions unit that is capable of burning more than one type of fuel, you must relate the current emission

factors to the fuel or fuels that were actually used during the selected 24- month period. For example, when calculating the baseline actual

emissions for an emissions unit that burned natural gas for a portion of the 24-month period and fuel oil for the remainder, you must retain that fuel apportionment (for example, natural gas to fuel oil ratio), but you must also use the current legally enforceable emission factors for natural gas and fuel oil, respectively, to calculate the baseline actual emissions. If, however, you are no longer allowed or able to use one of those fuel types, then you must make your calculations assuming use of the currently allowed fuel for the entire 24- month period. You must use the same approach for emissions units that use multiple feedstock or raw materials, which may vary in use during the unit ’ s ongoing production process.


### 80196 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

7. How Should I Calculate the Baseline

Actual Emissions for Construction Projects That Involve Multiple Units?

Today ’ s new requirements require that you select the same single consecutive 24-month period within the 10-year look back period to calculate the baseline actual emissions for all existing emissions units that will be changed.
See, for example, new
§ 52.21(b)(48)(ii)( e). The result will be

that the baseline actual emissions for each affected pollutant will be based on the same consecutive 24-month period

as well.

You will have the option to select the single 24-month period that best represents the collective level of operation (and emissions) for your existing emissions units.

If a particular existing emissions unit did not yet exist during the 24-month period you select to calculate the baseline actual emissions, you must

count that emissions unit ’ s emissions rate as zero for that full period of time. If an emissions unit operated for only a portion of the particular 24-month period that you select, you must calculate its average annual emissions rate using an emissions rate of zero for that portion of time when the unit was not in operation.

For new emissions units (a unit that has existed for less than 2 years) that will be changed by the project, the

baseline actual emissions rate is zero if you have not yet begun operation of the unit, and is equal to the unit ’ s PTE once it has begun to operate.

8. Am I Able To Apply Today ’ s Changes for Calculating the Baseline Actual Emissions to Other Major NSR Requirements?

No, as stated in section II.A, you are only allowed to use the new baseline methodology in today ’ s rule for three specific purposes involving existing

emissions units as follows.

• For modifications, to determine a

modified unit ’ s pre-change baseline actual emissions as part of the new actual-to-projected-actual applicability

test

• For netting, to determine the prechange actual emissions of an emissions unit that underwent a physical or operational change within the contemporaneous period. You may select separate baseline periods for each contemporaneous increase or decrease.

• For PALs, to establish the PAL

level.

If you determine that the modification of your source is a major modification, you must revert to using the existing

definition of ‘‘ actual emissions ’’to determine your source ’ s actual emissions on a particular date to satisfy all other NSR permitting requirements, including any air quality analyses (for example, compliance with NAAQS, PSD increments, AQRVs) and the amount of emissions offsets required.

For example, when you must determine your source ’ s compliance with the PSD increments following a major modification, you must still use

the allowable emissions from each emissions unit that is modified, or is affected by the modification. An existing source ’ s contribution to the

amount of increment consumed should

be based on that source ’ s actual emissions rate from the 2 years immediately preceding the date of the change, although the reviewing authority shall allow the use of another 2-year period if it determines that such period is more representative of that

source ’ s normal operation. See, for example, § 52.21(b)(21)(ii).

Also, any determination of the

amount of emissions offset that must be obtained by a major modification subject to the nonattainment NSR requirements under § 51.165(a) should be based on calculations using the existing definitions of ‘‘ actual

emissions ’’and ‘‘ allowable emissions. ’’

See new § 51.165(a)(3)(ii)(H).

D. The Actual-to-Projected-Actual Applicability Test for Physical or Operational Changes to Existing Emissions Units Including EUSGUs

1. How are post-change actual emissions calculated under today ’ s revised rule?

Today, we are amending the major NSR rules to enable you to use an applicability test that is similar to the applicability test that currently appliesto EUSGUs (that is, the actual-torepresentative-actual-annual emissions test). The new test allows you to project the post-change emissions of all modified existing emissions units (including EUSGUs) in the same manner. That is, under today ’ s new provisions for non-routine physical or operational changes to existing emissions units, rather than basing a

unit ’ s post-change emissions on its PTE, you may project an annual rate, in tpy,

that reflects the maximum annual emissions rate that will occur during any one of the 5 (or in some circumstances 10) years immediately after the physical or operational change. The first year begins on the day the emissions unit resumes regular operation following the change and

includes the 12 months after this date. This projection of the unit ’ s annual emissions rate following the change is defined as the ‘‘ projected actual

emissions ’’(see, for example, § 52.21(b)(48)), and will be based on your maximum annual rate in tons per year at which you are projected to emit a regulated NSR pollutant, less any

amount of emissions that could have been accommodated during the selected 24-month baseline period and is not related to the change. Accordingly, you

will calculate the unit ’ s projected actual emissions as the product of: (1) The hourly emissions rate, which is based

on the emissions unit ’ s operational capabilities following the change(s), taking into account legally enforceable restrictions that could affect the hourly emissions rate following the change(s); and (2) the projected level of utilization,

which is based on both the emissions

unit ’ s historical annual utilization rate and available information regarding the

emissions unit ’ s likely post-change capacity utilization. In calculating the projected actual emissions, you should consider both the expected and the highest projections of the business activity that you expect could be

achieved and that are consistent with information your company publishes for business-related purposes such as a stockholder prospectus, or applications

for business loans. From the initial calculation, you may then make the appropriate adjustment to subtract out any portion of the emissions increase

that could have been accommodated during the unit ’ s 24-month baseline period and is unrelated to the change. Once the appropriate subtractions have been made, the final value for the projected actual emissions, in tpy, is the value that you compare to the baseline

actual emissions to determine whether your project will result in a significant

emissions increase.

The adjustment to the projected actual emissions allows you to exclude from your projection only the amount of the

emissions increase that is not related to the physical or operational change(s). In comparing your projected actual

emissions to the units ’baseline actual emissions, you only count emissions

increases that will result from the project. For example, as with the electric utility industry, you may be able to attribute a portion of your emissions increase to a growth in demand for your product if you were able to achieve this higher level of production during the consecutive 24-month period you

selected to establish the baseline actual emissions, and the increased demand for the product is unrelated to the change.

For Clean Units, if a given project can be constructed and operated at a Clean Unit without causing the emissions unit


### 80197 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

19 Your ability to use the full 10 years for calculating any contemporaneous emissions change is contingent upon the availability of valid and

sufficient source information for the selected 24- month period. See, for example, new
§ 52.21(b)(48)(ii)( f ). to lose its Clean Unit status, then no

emissions increase will occur.

For new units, however, you must continue to calculate post-change

emissions on the basis of a unit ’ s PTE.

2. Will My Projection of Projected

Actual Emissions Become an

Enforceable Emission Limitation as Suggested in the 1998 NOA?

No, we did not adopt such a requirement. If you have an existing emissions unit and your project results

in an increase in annual emissions that exceeds the baseline actual emissions by a significant amount, and differs from your projection of post-change emissions that you were required to calculate and maintain records of, then you must report this increase to your reviewing authority within 60 days after the end of the year. Since modified EUSGUs are required to report their post-change annual emissions to the reviewing authority annually, any occurrence of a significant increase will be covered under that report for the affected calendar year. See section II.D.6 of this preamble for a more detailed discussion of the reporting requirements.

3. How Do I Determine How Long My Post-Change Emissions Will Be Tracked To Ensure That My Project Is Not a Major Modification?

Generally, your projected actual emissions must be tracked against your facility ’ s post-change emissions for 5 years following resumption of regular operations whether you are an EUSGU or other type of existing emissions unit. We will presume that any increases that occur after 5 years are not associated with the physical or operational changes. However, you may be required to track emissions for a longer period of time under the following circumstances. If you are an existing emissions unit and one of the effects of your physical or operational change(s) is to increase a

unit ’ s design capacity or PTE, you must track your emissions for a period of 10 years after the completion of the project. This extended period allows for the possibility that you could end up using the increased capacity more than you projected and such use might lead to significant emissions increases.

4. What Are the Reporting and Recordkeeping Requirements for Projects?

Reporting and recordkeeping for a project is required when three criteriaare met: (1) You elect to project postchange emissions rather than use PTE; (2) there is a reasonable possibility that the project will result in a significant emissions increase; and (3) the project will not constitute a major modification. In such circumstances, you must

document and maintain a record of the following information: a description of the project; an identification of

emissions units whose emissions could increase as a result of the project; the

baseline actual emissions for each emissions unit; and your projected actual emissions, including any

emissions excluded as unrelated to the change and the reason for the exclusion. In addition, if your project increase is significant, you must record your netting calculations if you use emissions reductions elsewhere at your major stationary source to conclude that the project is not a major modification. For covered projects, you must record this information before beginning actual construction. If you are an EUSGU, you must also send this information to your reviewing authority before beginning actual construction. Note, however, that if you chose to use potential emissions as your projection of post-change emissions, you are not required to

maintain a record of this decision.

In addition, today ’ s final rules require you to maintain emissions data for all emissions units that are changed by the project. You must maintain this information for 5 years, or 10 years if applicable. The information you must maintain may include continuous emissions monitoring data, operational levels, fuel usage data, source test results, or any other readily available information of sufficient accuracy for the purpose of determining an

emissions unit ’ s post-change emissions.

If you are an EUSGU, you must report this information to your reviewing authority within 60 days after the end of any year in which you are required to generate such information. Other existing units must report to the reviewing authority any increase in the post-change annual emissions rate when that rate: (1) Exceeds the baseline actual emissions by a significant amount, and (2) differs from the projection that was calculated before the change. See, for example, new § 52.21(r)(6)(iii).

In addition to the reporting requirements discussed above, you are also obligated to ensure that the necessary emissions information you are required to maintain is available for examination upon request by the reviewing authority or the general public.

5. How Do Today ’ s Changes Affect the Netting Methodology for Existing Emissions Units (Other Than EUSGUs)?

If your calculations show that a significant emissions increase will result from a modification, you have the option of taking into consideration any contemporaneous emissions changes that may enable you to ‘‘ net out ’’of review, that is, show that the net emissions increase at the major stationary source will not be significant. The contemporaneous time period will not change under the Federal PSD program as a result of today ’ s action. That is, creditable increases and

decreases in emissions that have occurred between the date 5 years before construction of the particular change commences and the date the increase from that change occurs are
contemporaneous. See § 52.21(b)(3)(ii).

States will continue to have some discretion in defining

‘‘ contemporaneous ’’for their own NSR

programs.

Although we are not changing our

definition of ‘‘ contemporaneous, ’’ today ’ s action allows existing emissions units (other than EUSGUs) to calculate

the baseline actual emissions for each contemporaneous event using the 10- year look back period. That is, you can select any consecutive 24-month period during the 10-year period immediately preceding the change occurring in the contemporaneous period to determine

the baseline actual emissions for each creditable emissions change. Generally,

for each emissions unit at which a contemporaneous emissions change has occurred, you should use the 10-year look back period relevant to that change. 19 When evaluating emissions increases from multi-unit modifications,

if more than one emissions unit was changed as part of a single project during the contemporaneous period, you may select a separate consecutive 24-month period to represent each emissions unit that is part of the project. In any case, the calculated baseline

actual emissions for each emissions unit must be adjusted to reflect the most current emission limitations (including operational restrictions) applying to that

unit. ‘‘ Current ’’in the context of a contemporaneous emissions change

refers to limitations on emissions and source operation that existed just prior to the date of the contemporaneous change.

E. Clarifying Changes to WEPCO Provisions for EUSGUs

The method you use to calculate the baseline actual emissions for an existing

EUSGU to determine whether there is a


### 80198 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

20 Letter from John S. Seitz, Director, Office of Air Quality Planning and Standards, to Patrick M. Raher, August 6, 2001. significant emissions increase from a physical or operational change at an EUSGU, and to determine whether a significant net emissions increase will occur at the major stationary source, will not change as a result of today ’ s final rulemaking. The rule provides that for an existing EUSGU you may

calculate the baseline actual emissions as the average annual emissions (tpy) of the emissions unit using any 2-year period out of the 5 years immediately preceding the modification. (This was set out as a presumption in the preamble for the 1992 WEPCO amendments.) This rule recognizes the ordinary variability in demand for electricity. See, for example, new
§ 52.21(b)(21)(ii).

For example, a cold winter or hot summer will result in high levels of demand while a relatively mild year will produce lower demand. By allowing a utility to use any consecutive 2 years within the past 5, the rule recognizes that electricity demand and resultant utility operations fluctuate in response to various factors such as annual variability in climatic or

economic conditions that affect demand, or changes at other plants in the utility system that affect the dispatch of a particular plant. By allowing utilities to use as a baseline any consecutive 2 years in the last 5 years, these types of fluctuations in operations can be more realistically

considered.

The reviewing authority shall allow the use of a different time period upon

a determination that it is more representative of normal source operation.

In an August 6, 2001 letter, 20 we addressed the issue of whether combined cycle gas turbines (the gas turbines and waste heat recovery components) came within the definition

of ‘‘ electric utility steam generating

units ’’for the purpose of determining whether such units are eligible to use

the WEPCO ‘‘ applicability test. ’’The

letter concluded that ‘‘ steam generating

units ’’include not only electric utility plants with boilers, but also plants with combined cycle gas turbines if the combined cycle gas turbine systems supply more than one-third of their potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Consequently, qualifying combined cycle gas turbines must also use the 2- in-5-years baseline method. Finally, today ’ s rules provide the

same method for EUSGUs that will exist for all other existing emissions units to project post-change emissions following a physical or operational change to a unit. In the 1996 proposal, we proposed a range of options for addressing the applicability of changes that are made to existing emissions units, including theoption of extending the actual-to-futureactual test, then available only to utilities, to all source categories. While

we have decided to leave the WEPCO rules intact in most respects, we believe that it is reasonable and appropriate to

establish a consistent method forsources to use for projecting the postchange emissions that will result from a physical or operational change to an existing emissions unit. Therefore, under today ’ s new rules, the current method of basing the projection on the 2 years following the change to an EUSGU is being replaced with the method available to all other existing units, under which you project a unit ’ s post-change emissions as the maximum

annual rate that the unit will emit in any one of the 5 years following resumption of regular operations.

F. The ‘‘ Hybrid ’’ Applicability Test for Projects Affecting Multiple Types of

Emissions Units

1. When Does the Hybrid Applicability Test Apply to You?

The hybrid applicability test applies if you plan a project (or series of related projects) that will affect emissions units of two or more of the following types.

• Existing emissions units

• New emissions units

• Clean Units

2. How Do I Determine Whether My Project Will Result in a Significant Emissions Increase Under the Hybrid

Test?

For the first two types of emissions units listed above that are affected by the project, calculate the emissions

increase as we have discussed previously in this preamble. That is, use the actual-to-projected-actual applicability test for existing units and the actual-to-potential test for new

emissions units.

Clean Units are discussed fully in section V of this preamble. If a given project can be constructed and operated at a Clean Unit without causing the

emissions unit to lose its Clean Unit status, no emissions increase shall be

deemed to occur at that Clean Unit. If a given project would cause the

emissions unit to lose its Clean Unit status, then the increase in emissions

should be calculated as if the emissions

unit is not a Clean Unit. After you calculate the emissions increase for each relevant unit, total the

increases across all the emissions units of all types. If this total emissions increase equals or exceeds the level defined as significant for the regulated NSR pollutant in question, the project will result in a significant emissions increase for that pollutant. You ’ ll find the regulatory language for determining whether a project will result in a significant emissions increase at §§ 51.165(a)(2)(vii)(D), 51.166(a)(7)(vi)( d), and 52.21(a)(2)(vi)( d).

In section II.C.8 of this preamble, we

indicate that the baseline actual

emissions for all units that are not EUSGUs that are changed by a project

must be calculated based on the same consecutive 24-month period within the previous 10 years. The same principle applies under the hybrid test, but it can be slightly more complicated if both

EUSGUs and non-EUSGUs are involved. In this case, you must use the same baseline period for all emissions units affected by the project. This baseline period must be selected so as to meet the requirements for both EUSGUs and non-EUSGUs. Thus, you must select a 2- year period out of the previous 5 years for your baseline period, as required for EUSGUs (and within the requirements for non-EUSGUs). If you wish to use another period that you believe is more representative (as allowed for EUSGUs), the entire period must fall within theprevious 10 years (as required for nonEUSGUs).

3. How Do I Determine the Net Emissions Increase From My Project Under the Hybrid Test?

If you conclude that a significant

emissions increase will result from the proposed project, you have the option of taking into consideration any contemporaneous emissions changes that may enable you to ‘‘ net out ’’of review, that is, show that the net emissions increase at the major stationary source will not be significant. The netting analysis is carried out under the hybrid test just as it is under the other applicability tests. Refer to section II.D.7 of this preamble for a discussion of netting methodology.

G. Legal Basis for Today’s Action

The Act defines modification for the purposes of PSD and nonattainment NSR through cross-reference to the

NSPS definition of ‘‘ modification. ’’The

NSPS definition states that a

modification ‘‘ means any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air


### 80199 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

21 See, for example, WEPCO Rule, 57 FR 32316 ( ‘‘ fundamental distinctions between the technologybased provisions of NSPS and the air quality-based provisions of NSR ’’ ). See also ASARCO Inc. v. EPA, 578 F.2d 319 (D.C. Cir. 1978).

22 The explanation of the applicability test for

‘‘ Clean Units ’’is discussed in section V. 23 ‘‘ Business Cycles in Major Emitting Source

Industries. ’’Eastern Research Group; September 25, 1997. This study examined the business fluctuations for nine source categories described as CAA major emitting sources. Industry business cycles were examined using industry output data

Continued pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. ’’CAA section 111(a)(4), 42 U.S.C. 7411(a)(4). The Act is silent, however, on the issue

of how one is to determine whether a physical or operational change increases the amount of any air pollutant emitted by the source.

Accordingly, EPA is exercising its discretion in interpreting and providing clarity to this issue. We believe that the rules set forth today are ‘‘ a permissible

construction of the statute. ’’ Chevron
U.S.A., Inc. v. NRDC, 467 U.S. 843

–4 (1984). The reviewing court should

defer to it. Id. at 837.

In the NSPS program, we determine

whether there has been an ‘‘ increase in any air pollutant emitted ’’by the source by comparing its maximum hourly

achievable emissions before and after the change. EPA and the courts have recognized, however, that the NSR programs and the NSPS programs have different goals, 21 and thus, we have

utilized different emissions tests in the NSR programs. Prior to today, theregulations applied an actual-to-futureactual applicability test for EUSGUs and an actual-to-potential applicability test for all other emissions units. Today, we are establishing a new applicability test for calculating emissions increases for

‘‘ Clean Units ’’and an actual-toprojected-actual applicability test for all

other emissions units. We believe thatestablishing an actual-to-projectedactual applicability test for all emissions units is a reasonable interpretation of the phrase ‘‘ increase of any pollutant

emitted. ’’ 22

H. Response to Comments and Rationale for Today’s Actions

We received numerous comments on our proposed rule regarding the

calculation of the baseline actual

emissions and the actual-to-futureactual test. Some of the significant comments and our responses to them are provided below. A complete set of comments and our responses can be found in the Technical Support

Document located in the docket for this rulemaking.

1. Why Are We Extending the Look Back Period for Determining the

Baseline Actual Emissions to 10 Years?

Most commenters generally support our proposal to allow owners and operators to use a 10-year look back period to determine the baseline actual emissions for modifications at any existing emissions unit. Commenters have various reasons for supporting or opposing the proposed approach. Many supporters agree that extending the baseline look back period to 10 years would simplify current regulations and provide certainty to sources who

otherwise would have to demonstrate to the reviewing authority that a period other than the 2 years immediately preceding the proposed change was more representative of normal source operation. Some commenters support the proposal because it would prevent the perceived confiscation of underused capacity at sources that have had low utilization rates for an extended period. These commenters agree that a 10-year look back period is more likely to afford

a source a baseline actual emissions

calculation that best reflects representative source operating
conditions and would also account for fluctuations in the business cycle.

Some commenters criticize the proposed 10-year look back period as being too long. These commenters recommend either a 5-year or 2-year look back period. One of these commenters states that the 10-year look back creates the opportunity for a source to increase production to the 10-year maximum, and prevents the State or local air regulators from addressing the increase in emissions. Thus, the

commenter believes that sources would

be allowed to use historic emissions levels that are higher than current levels

to establish the baseline actual

emissions. Some commenters add that the proposed change would not reduce program complexity.

Some commenters believe that instead of extending the period for establishing baseline actual emissions, the test for establishing modifications should be changed. According to the commenters, the problem is not that the current system does not go back far enough to set a fair actual emissions baseline, but that the methodology does not account

for the fact that most emissions units are operating at an activity level much lower than the allowed activity level. The commenters believe that many of the real problems associated with the current major modification applicability

test would be eliminated if the procedure was modified in an equitable

manner.

A commenter also adds that EPA may also want to include provisions that prevent a source from applying the new definition of actual emissions in a way that would retroactively enable the source to reverse a previous major modification determination and to eliminate any emissions reduction previously required for that major

modification.

We continue to believe that it is reasonable and appropriate to adopt the new method for establishing a modified

unit ’ s baseline actual emissions. It is important to understand the difference between the purpose of the new procedure, which uses the 10-year look back, and the existing procedure under the pre-existing definition of ‘‘ actual

emissions ’’at § 52.21(b)(21(ii), which generally requires the use of an average

annual emissions rate based on the 2- year period immediately preceding a particular date. The latter procedure is designed to estimate a source ’ s actual emissions at a particular time and continues to be appropriate for such things as estimating a source ’ s impact on air quality for PSD increment consumption.

On the other hand, the new baseline procedure is specifically designed to

allow a source to consider a full business cycle in determining whether

there will be an emissions increase from a physical or operational change. Generally, a source ’ s operations over a business cycle cover a range of operating (and emissions) levels

—not simply a single level of utilization. The new procedure recognizes that market

fluctuations are a normal occurrence in most industries, and that a source ’ s operating level (and emissions) does not remain constant throughout a source ’ s business cycle. The use of a 24-month period within the past 10 years to establish an average annual rate is intended to adjust for unusually high short-term peaks in utilization.

Consequently, the new procedure ensures that a source seeking to make changes at its facility at a time when utilization may not be at its highest can use a normal business cycle baseline by allowing the source to identify capacity actually used in order to determine an average annual emissions rate from which to calculate any projected actual emissions resulting from the change.

With respect to the commenters ’ general concerns that a 10-year look back period is too long, we sought to better understand what time period best represents an industry ’ s normal business cycle. Therefore, we contracted for a study of several industries in

1997. 23 This study found that, for the


### 80200 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

for the years 1982 to 1994 inclusive, based on the Office of Management and Budget ’ s SIC codes for individual industries (OMB, 1987). industries analyzed, business cycles differ markedly by industry, and may vary greatly both in duration and intensity even within a particular industry. Nevertheless, we concluded from the study that 10 years of data is reasonable to capture an entire industry cycle. Comments from various industries support a conclusion that a 10-year look back period is a fair and representative time frame for encompassing a source ’ s normal business cycle.

We believe that the use of a 10-year look back period will help provide certainty to the process and eliminate the ambiguity and confusion that occurred when an applicant and the reviewing authority disagreed on what time frame provides the period most representative of normal source operation. The new requirements also provide certainty to the look back period, since there is no opportunity to select another period of time outside this 10-year period. (See additional discussion in section II.E.2.) In addition, we have placed certain restrictions on when the full 10-year look back period may be used. ( See section II.E.3.)

With regard to the concern that industry may try to apply the new requirements retroactively to undo current restrictions on existing sources,
we want to reiterate that the new procedures do not apply retroactively to existing NSR permits or changes that sources have made in the past. Prior applicability determinations on major

modifications and the control requirements that currently apply to

sources remain valid and enforceable and have to be adjusted for in the

calculation of baseline actual emissions. However, as part of the transition process for implementing the new provisions, we do intend to allow permit applicants to withdraw any permit applications submitted for review under the part 52 Federal PSDpermit program so that they may reevaluate their projects in light of the new requirements. States may allow for the same type of transition process under their own NSR programs.

Finally, we considered whether we should change the length of the look back period for EUSGUs for establishing the actual emissions baseline period to be consistent with the 10-year look back period we are adopting for other existing emissions units. The data we collected to support the 1992 rule changes show that allowing EUSGUs to use any 2-year period out of the preceding 5 years is a sufficient period of time to capture normal business cycles at an EUSGU. We do not believe that any information received during the public comment period for this final rule adequately supports a different conclusion. Thus, we have decided to retain the 2-in-5-years baseline period for EUSGUs. However, for consistency with the baseline period for other existing emissions units, we have specified that the 2-year period is a consecutive 24-month period.

2. Why Do the New Requirements Not Provide Discretion for the Reviewing Authority To Consider Another Time Period More Representative of Normal Operation for Non-EUSGUs?

Several commenters oppose our proposed elimination of the reviewing authority ’ s discretion to allow a different representative period (outside of the 10-year period), because they argue certain sources (for example, emissions units placed in cold reserve due to reduced demand) require this flexibility. Some commenters say the discretion should be given to the reviewing authority, while other commenters wanted the discretion given directly to source owners and operators.

Instead of the discretion to use an alternate period, one commenter prefers that all sources should be required to show that they have selected a representative period that precedes the most recent 2-year period.

We believe that use of a fixed 10-year look back period provides the desired clarity and certainty to the process of selecting an appropriate utilization/ emissions level that is representative of

a source ’ s normal operation. A bounded 10-year look back provides certainty to the regulated community that may be undermined by an option to allow an unbounded alternative period as well.

3. Why Are We Placing Restrictions on

the Use of a 10-Year Look Back for Setting the Baseline Actual Emissions?

Numerous commenters responded to our concern that many sources might lack accurate records for the full 10-year look back period, and to our request for

comments on the need to condition the full use of the 10-year period upon the accuracy and completeness of available data, as well as the need to establish specific criteria for accuracy, completeness, and recordkeeping when using older data. A number of commenters generally support limiting full use of the 10-year look back period to situations in which adequate emissions and/or capacity utilization

data are available. Some commenters

also recommend that EPA issue minimum criteria to reduce the number of case-by-case determinations and help reviewing authorities avoid debates

with sources on what constitutes

sufficient data.

On the other hand, one commenter recommends that we not adopt a variable look back period based on the quality of the older data because it

would ‘‘ add considerable uncertainty and protracted debate to the

process

.... ’’If, however, we choose to limit the look back period based on the quality of older data, then this commenter and several others prefer provisions allowing for case-by-case decisions by State or local reviewing authorities over specific criteria established by EPA.

Today ’ s amendments condition the full use of the new 10-year look back period on the accuracy and completeness of your records of emissions and capacity utilization, with respect to the 24-month period you select, for any emissions unit that undergoes a physical or operational change. See, for example, new § 52.21(b)(48)( f

). As with all emissions calculations, accuracy and completeness are central elements for applicability determinations. In many cases, sources presently maintain accurate records on emissions and operations for only 3 to 5 years. Thus, we think it is appropriate to limit use of the full 10-year look back period when you do not have adequate data for the time period you wish to select. However, this limitation should be alleviated over time as sources begin to maintain records for longer periods to accommodate the 10-year look back opportunity.

We also agree that adequacy of anygiven data should be left to the case-bycase judgment of individual reviewing authorities. The type of data necessary to determine emissions will vary drastically from source category to source category and from process to process within a source category. At this time, we are not able to issue generic criteria that would apply to all types of

industries.

We are further restricting your use of the 10-year look back for emissions

units that are located in nonattainment areas and OTRs. In such cases, you are precluded from using any portion of the 10-year look back that precedes November 15, 1990

—the date of the

1990 CAA Amendments

—to establish

baseline actual emissions for those

units. This limit on the use of the 10- year look back is consistent the intent of the 1996 NPRM, which was originally proposed to apply to the use of the 10- year look back for any modification of an existing facility in a nonattainment


### 80201 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

area or OTR. See 61 FR 38259 (July 23, 1996). However, because we are now beyond the point where the November 15, 1990 limit is relevant to modifications, we are only applying this limitation in the netting context with respect to emissions units changed within the contemporaneous period.

4. Why Were Changes Made to the Proposed Approach for Establishing Baseline Actual Emissions Using a 10-

Year Look Back?

Commenters raise specific questions about how to use the 10-year look back

to calculate an emissions unit ’ s baseline

actual emissions. Several commenters

are concerned about how the utilization

rate would be considered in the calculation. For example, some commenters support the proposal to allow sources to use their highest capacity achieved during any consecutive 12 months, because it provides improved flexibility in establishing a capacity level that is representative of normal operations. However, other commenters object to using the 12 months with the highest utilization. These commenters argue that the use of production rates can be unworkable because there is not always a clear relationship between production rate and emissions. In addition, reliable records may not be available to determine the highest production rates. As an alternative, commenters suggest using emissions from any 12-month period in the preceding 10 years, adjusted to reflect current rules, or allowing the source to use any 12-month period of its choice.

A related issue raised by commenters is whether to require any current Federal, State, or voluntary limit to be

included in the establishment of the

baseline actual emissions. Some commenters say these provisions would penalize sources that complied with other regulatory requirements or chose to implement pollution prevention programs. Commenters are particularly concerned that sources be given credit for voluntary reductions. However, other commenters support including all

of these factors in the baseline to better represent actual emissions and avoid

inconsistencies between emissions units that have permits and those that do not. Commenters also raise specific questions about how the calculation

would include the effect of other

emission limitations.

As described earlier, we have decided to require the use of a consecutive 24- month period within the 10-year look back instead of the proposed 12-month period to calculate the baseline actual emissions for any emissions unit that undergoes a physical or operational change, or is affected by such change. The longer 24-month period allows you

to reference levels of utilization achieved in the past, but also eliminates the potential problem associated with short-term peaks that do not truly represent the unit ’ s normal operation. In this respect, the use of a 24-monthperiod is consistent with the preexisting approach for calculating actual

emissions.

With respect to commenters ’concerns about being required to use the period of highest utilization, our reference in the proposal preamble to selecting the period of highest utilization was based on our general assumption that the period of maximum utilization also represents the period of highest pollution levels for the unit of concern. However, you are not required to select the period of highest utilization. The

choice of which consecutive 24-month period within the 10-year window to use is up to you. The two restrictions on the selection of the appropriate consecutive 24-month period, as described earlier, are the availability of adequate and complete source records

for the unit of concern and the limit on using dates earlier than November 15, 1990 for contemporaneous emissions changes in nonattainment areas and

OTRs.

We agree with the concerns expressed by some commenters that the baseline

actual emissions calculated from the consecutive 24-month period selected could yield a higher pollution level than a unit is currently allowed to emit. We

do not believe that we should allow a

source to take credit for baseline actual emissions that exceed the current, legally allowable emissions rate. Consequently, the new requirements require you to determine whether any legally enforceable limitations currently exist that would prevent the affected unit from emitting a pollutant at the

levels calculated from the 24-month baseline period. The approach that we have adopted allows you to reference plant capacity that has actually been used, but not pollution levels that are not legally allowed at the time the

modification is to occur. You will be required to make adjustments for voluntary reductions that you may have taken only to the extent that the

reductions resulted from conditions that are legally enforceable limitations. 5. How Does the Change in the Baseline Period Affect Related Requirements Regarding Protection of Air Quality?

a. How Does the Extended Baseline Period Conform With the Special Modification Provisions Under Sections 182(c) and (e) of the Act?

Most commenters feel the proposed extension of the look back period fits within the design and intent of the special modification procedures set forth in sections 182(c) and (e) of the Act, applicable in serious, severe, and

extreme ozone nonattainment areas. However, one commenter representing State and local air pollution control agencies considers the new requirements to be in significant conflict with the special modification procedures contained in those sections

of the Act. The commenter indicates that this conflict could be resolved by deferring to relevant requirements for modifications in serious, severe, and

extreme areas. The commenter adds that while NSR programs are tools to attain and maintain compliance with the NAAQS, they should not be available to undermine specific statutory and SIP requirements designed to resolve nonattainment problems.

We disagree with the commenter ’ s concern that the use of a 10-year look back period to implement sections 182(c) and (e) of the Act for purposes of establishing a modified unit ’ s baseline emissions will undermine any statutory or SIP requirements designed to address nonattainment problems. The two sections establish special procedures for determining whether a proposed modification of a major stationary source of ozone in a serious, severe, or

extreme ozone nonattainment area will be subject to major NSR under part D of

the Act. The Act is silent on the issue

of how one is to determine whether a physical or operational change increases the amount of a pollutant for a changed emissions unit. We believe, therefore, that we have the authority to establish a regulatory procedure for making the required determinations concerning emissions increases resulting from physical or operational changes.

In light of the fact that the 10-year look back period may be used for emissions units (other than EUSGUs) that are involved in contemporaneous emissions changes (for netting purposes), it should be noted that the new requirements prohibit the use of the look back period earlier than November 15, 1990. Consequently, for

emissions units whose contemporaneous emissions changes occurred before November 15, 2000, the consecutive 24-month period selected


### 80202 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

24 Guidance for modeling NAAQS compliance under the PSD program is set forth in EPA ’ s Guideline on Air Quality Models contained in appendix W of 40 CFR part 51. This guidance is incorporated by reference both in the Federal PSD regulations and in the minimum requirements for SIPs under the part 51 PSD regulations. for calculating the baseline actual

emissions relevant to the contemporaneous emissions change cannot include a date prior to November 15, 1990. It should be pointed out, however, that for modifications involving emissions of volatile organic compounds (VOC) in areas classified as

‘‘ extreme, ’’the statutory language is

clear that the increase in emissions resulting from the change is not required to be a significant increase, but

rather that ‘‘ any increase ’’that isprojected using the new actual-toprojected-actual applicability test will trigger the applicable NSR requirements.

b. Will the Longer Look Back Period

Related to the Baseline Actual

Emissions Protect Short-term Increments and NAAQS?

Some commenters express concerns that the opportunity to take credit for

older baseline actual emissions would

result in adverse environmental consequences. One commenter specifically indicates that the proposed

baseline actual emissions determination process, involving a 10-year look back, would allow significant increases in emissions to escape the ambient impact review requirements otherwise required by NSR.

Today ’ s new rule modifies the way your NSR applicability determinations are made for changes made to existing

emissions units. The new rule does not affect the way in which a source ’ s ambient air quality impacts are evaluated. Compliance with the NAAQS is accomplished with air quality dispersion models using maximum allowable emission limitations (or federally enforceable permit limits) combined with operating factors, which consider either design capacity or actual operating factors averaged over the most recent 2 years of operation, from all

modeled sources. 24 In addition, any increase in actual emissions, based on the existing definition of ‘‘ actual
emissions, ’’consumes PSD increment whether it occurs through normal source operation or as a result of a physical or operational change. As mentioned earlier, the existing

definition of ‘‘ actual emissions ’’ continues to apply with regard to all NSR requirements other than the new source applicability tests. See, for example, new § 52.21(b)(21)(i). Thus, we

do not believe there is a basis for concluding that the use of a longer look back period for determining a modified

emissions unit ’ s baseline actual emissions (for purposes of determining whether a physical or operational change will result in a significant emissions increase) will cause any adverse environmental impacts.

6. Why Was the Contemporaneous Period for Netting Not Also Changed to

a 10-Year Look Back Period?

In the 1996 NPRM, we indicated that we were not proposing to extend the 5- year contemporaneous period along with the proposed 10-year look back period associated with the

establishment of baseline actual

emissions. See 61 FR 38259 (July 23, 1996). We did, however, solicit comments on the effect of the differing look back periods and any reasons why these periods should be the same. Commenters responded in a variety of ways to our request, with no clear

consensus as to whether it would be appropriate to establish a uniform look back period. One commenter supports the 10-year contemporaneous period for reasons of consistency. Other

commenters believe that it was

reasonable to use two different time frames. Some commenters support retaining the 5-year contemporaneous period because changing it could have adverse effects on existing permit

determinations. Several commenters support the selection of a different contemporaneous time frame than the existing 5-year period, but they differ in their recommendations for changing it. One suggests giving the source the option of choosing either a 10-year or 5- year contemporaneous period. Another commenter believes that a 1-year period would reduce confusion. Finally, another commenter proposes a 5-year contemporaneous period that would not mandate that 5 consecutive years be

considered.

We do not believe that there is a compelling reason to change the existing 5-year contemporaneous period. The look back periods serve different purposes and need not be the same in order to effectively implement the NSR program objectives. States retain the flexibility in defining a different contemporaneous period under SIP-approved NSR programs, and may use that flexibility to adjust the contemporaneous period if they believe that a different period is more appropriate for their purposes under the new applicability requirements. See, for example, § 51.166(b)(3)(ii). Therefore, under today ’ s new requirements, we have not changed the 5-year contemporaneous period under the Federal PSD program. It should be noted that for purposes of determining the

baseline actual emissions of a contemporaneous change in emissions

from an emissions unit that was an existing unit at the time of the contemporaneous change, the new requirements authorize a source to use the 10-year look back period.

7. Why Was the Demand Growth

Exclusion Retained?

When we proposed to expand the scope of the WEPCO rulemaking to cover modifications at any existing emissions unit, we solicited comment on whether the demand growth exclusion (currently available only to EUSGUs) should also be available to all source categories. In 1998, we noted that there were problems that could arise with the demand growth exclusion. 63

FR 39860

– 39861 (July 24, 1998). Accordingly, we solicited comment on this new position.

Several regulatory agency and environmental commenters support the total elimination of the demand growth

exclusion. These commenters maintain that a facility ’ s post-change emissions increases due to demand growth could

not be disassociated from those that resulted directly from the physical or operational change. These commenters believe the demand growth exclusion

would be difficult to enforce. The demand growth exclusion would, they claim, also be burdensome because it would require projections, estimates, and post-modification evaluations of

increased emissions to determine

whether the increases were the result of

increased demand.

On the other hand, numerous industry commenters oppose eliminating the demand growth provisions, stating that market factors do independently cause emissions increases absent physical and operational changes. These commenters maintain that when projected increased capacity utilization is in response to an independent factor, such as demand growth, the increased utilization cannot be said to result from the change and therefore may rightfully be excluded from the projection of the emissions

unit ’ s future-actual emissions. They further argue that such increases should not be included in post-change

emissions even in the absence of a demand growth exclusion, as the

increases would not be the result of the physical or operational changes that were made. Consequently, these commenters state that the proposed demand growth exclusion simply makes that principle explicit and eliminates

confusion as to how emissions should


### 80203 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

be calculated. The same commenters who support retaining demand growth provisions for utilities also believe theseprovisions should be extended to nonutilities.

Under today ’ s new requirements, you will be allowed to apply the causation provision as originally contained in the

WEPCO amendments. Both the statute and implementing regulations indicate

that there should be a causal link between the proposed change and any post-change increase in emissions, that
is, ‘‘ * * * any physical change or change in the method of operation that

would result in a significant net

emissions increase * * * ’’[emphasis added]. See, for example, existing § 52.21(b)(2)(i). Consequently, under today ’ s new rules, when a projected increase in equipment utilization is in response to a factor such as growth in market demand, you may subtract the

emissions increases from the unit ’ s projected actual emissions if: (1) The unit could have achieved the necessary level of utilization during the consecutive 24-month period you

selected to establish the baseline actual emissions; and (2) the increase is not related to the physical or operational change(s) made to the unit. See for example, new § 52.21(b)(41)(ii)( c).

On the other hand, demand growth can only be excluded to the extent that the physical or operational change is not related to the emissions increase. Thus, even if the operation of an emissions unit to meet a particular level of demand could have been accomplished during the representative baseline period, but the increase is related to the changes made to the unit, then the emissions increases resulting from the increased operation must be attributed to the project, and cannot be subtracted from the projection of projected actual

emissions.

8. Should Increases in Plant Utilization Be Reviewed as Potential Major

Modifications?

Many commenters argue that emissions increases resulting from

increased utilization should not be subjected to review as major modifications. They insist that EPA ’ s policy and rules have always allowed increases in capacity utilization without triggering a modification, and not allowing utilization increases will limit new capacity to new emissions units instead of promoting increased efficiency at existing emissions units. One commenter argues that these sorts of changes do not require any sort of applicability determination and that Congress never anticipated that the NSR program would hamper a source ’ s ability to increase utilization up to the original design capacity.

We believe that an increase in utilization should not trigger the major NSR requirements unless it is related to a physical or operational change. As explained earlier, the CAA only applies the major NSR requirements to

emissions increases that are the result of a physical or operational change. Thus, we do not believe that the major NSR requirements should apply to a

utilization increase unless the increase

is related to the modification. Under today ’ s final rules, you may exclude

emissions related to an increase in utilization if you were able to

accommodate the increase in utilization during the 24-month period you select to establish your baseline actual

emissions and the increased utilization is not related to the change.

9. Why Must You Track Physical or Operational Changes That Increase a

Unit ’ s Design Capacity or Potential To Emit Post-Change Actual Emissions for a Longer Period of Time?

We raised this issue in the 1998 NOA. Several commenters support applying

what we then termed the ‘‘ actual-toenforceable-future-actual ’’test to increases in design capacity or PTE because it would be inappropriate to automatically assume that such increases will affect normal operations,which would require the actual-topotential test. They say that these types

of modifications are common and do not generally increase emissions because they improve efficiency and add control

devices.

One commenter explains that it is not

uncommon for an emissions unit ’ s capacity to be increased so as to speed up normal operations without increasing production, and that projected actual emissions could easily be calculated on the basis of past operating experience. On the other hand, another commenter indicates that it is very expensive to increase design capacity. Therefore, it can be assumed that a company would use the additional capacity as soon as it

becomes available.

Several regulatory agency commenterssupport the use of the actual-topotential test for modifications that increase design capacity or PTE. One of

these commenters stated that such

modifications would alter an emissions

unit ’ s normal operation and make previous actual emissions ‘‘ unreliable

and irrelevant. ’’

We do not believe that every

modification that includes added capacity or an increase in the PTE is

intended for full use of that new capacity or PTE. Such actions could

well be intended to enhance current operations without resulting in increased production or operation. Therefore, under today ’ s new requirements, you are not required to

count the emissions increase that would result from full use of new capacity or PTE if you conclude that: (1) Such capacity or PTE will not be fully utilized, and (2) the emissions increase resulting from that portion of the capacity that will be used will not result in a significant emissions increase from the modification or a significant net

emissions increase at the source. The new requirements include a provision that requires you to monitor the emissions from the project for 10 years following the resumption of regular operation of the emissions units modified. The 10-year period reflects

our determination that this time frame best captures the normal business cycle for industry in general. Thus, in situations where your proposed project will in fact add new capacity or PTE to an existing emissions unit, yet you determine that the objective of the physical or operational change is not to use the increased capacity, your calculation of representative projected actual emissions may reflect this. However, you must maintain adequate information for 10 years following the completion of the project to track the

actual annual emissions from the units associated with the project. This represents a special condition that supersedes the normal 5-year period for the recordkeeping requirements being adopted today. During the 10-year period, you must report to your reviewing authority within 60 days after any year if the annual emissions, in tpy, from the project exceed the baseline actual emissions by a significant amount for the regulated NSR pollutant and if

such emissions differ from the preconstruction projection.

10. Does the Actual-To-Projected-Actual Applicability Test Apply to Netting?

We did not specifically request

comment on this issue in the 1996 proposal. Nonetheless, we received

several comments that assert that use of different methods to compute an

emissions increase and determine a net

emissions increase would result in

‘‘ absurd results ’’and require two separate accounting records. Othercommenters oppose using the actual-tofuture-actual test for netting. One commenter says that the sole purpose of

the actual-to-future-actual test was to

determine if an emissions increase will occur. One commenter says we should go further and revise the definition of


### 80204 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

25 Information supporting these values can be found in the docket for today ’ s rulemaking. ‘‘ contemporaneous ’’to limit it to project activities (vs. plantwide) and reduce

credits for shutdowns and curtailments.

As stated previously, we did not specifically request comment on this issue and we are not promulgating amendments to the netting regulations, on this point, at this time.

11. Should We Impose an Enforceable Projected Actual Emissions Level?

Some commenters on our 1996 proposal support the establishment of

an enforceable limitation on the

modified source ’ s projected future

emissions level. Other commenters support our specific proposal in the 1998 NOA to use the projected actual emissions as a temporary cap for the emissions units involved in the project, that is, an enforceable 10-year emissions

level.

On the other hand, many other commenters oppose the concept, citing various reasons for their opposition.

These included concerns that it would

become a de facto baseline for any additional permitting and create additional enforcement liability, usurp State prerogatives, be inconsistent with the CAA, and require enforceable restrictions for too long. A few State and local air reviewing agencies indicate that they do not have the resources to adequately administer a program that would require permits to be issued for every physical or operational change at a major stationary source.

Today ’ s new requirements follow the 1996 proposal. You will not be required to make the projected actual emissions projection through a permitting action. After considering the comments received, we are concerned that such a requirement may place an unmanageable resource burden on reviewing authorities. We also believe that it is not necessary to make your future projections enforceable in order to adequately enforce the major NSR requirements. The Act provides ample authority to enforce the major NSR requirements if your physical or operational change results in a significant net emissions increase at your major stationary source.

12. Why Are Modified Sources That Are Not Considered Major Modifications Not Required To Submit Annual Reports of Actual Emissions Under the New Requirements?

Several commenters support our proposal to require sources to track post-change emissions for a 5-year period so that there is a factual finding

as to whether emissions from the modified units actually increased. These

commenters believe that the requirement to track emissions is a needed safeguard and that it should not

be too difficult to track various operating parameters. They add that

non-utilities should be able to track emissions as well as utilities. Finally, commenters who oppose the proposed 10-year enforceable limit support retaining the 5-year tracking period in its place.

Many other commenters object to the burden that tracking would impose in the absence of any additional

environmental benefit. Some commenters suggest ways to reduce the burden, such as not requiring sources to report emissions unless there is a problem or reducing the tracking period to 2 or 3 years. Another industry commenter suggests that we require an up-front notification to the reviewingauthority whenever the actual-to-futureactual applicability test is used.

We agree with those commenters who recommend that you should be required to track emissions for a period of time following a modification. Thus, we have retained our proposed requirement to

maintain annual emissions information for a period of 5 years following resumption of regular operations after the change. As discussed previously, we expanded this requirement to 10 years for changes that increase an emissions

unit ’ s capacity or its potential to emit a regulated NSR pollutant. However, although we proposed a requirement for annual emissions reporting, we have

concluded that the combination of the recordkeeping requirements of this rule, along with a requirement to report to the reviewing authority any annual emissions that exceed your baseline actual emissions by a significant amount for the regulated NSR pollutant and differ from your preconstruction projection, is an equally effective way to ensure that a reviewing authority can receive the information necessary to enforce the major NSR requirements. Moreover, your reviewing authority has the authority to request emissions information from you at any time to determine the status of your post-change

emissions.

In response to the concern that these requirements might impose unnecessary burdens, we have also included further limits. First, you are only required to keep records if you elect to use the actual-to-projected-actual applicability test to calculate your emissions increase from the project. Second, you are only required to keep the records if there is a reasonable possibility that your project might result in a significant emissions increase. Finally, you only need keep those records for projects that are not major modifications. We also considered requiring you to submit an up-front notification to your reviewing authority, but concluded that this would result in an unnecessary paperwork burden. (EUSGUs, however, will be required to submit a copy of their projections to reviewing authorities before beginning actual construction.) We anticipate that a large majority of the projects that are not major modifications may nonetheless be required to undergo a permit action through States ’minor NSR permit programs. In such cases, the minor NSR permitting procedures could provide an opportunity to ensure that your reviewing authority agrees with your emission projections. Requiring a separate notification would not provide the reviewing authority with any

additional information in such circumstances. Accordingly, we believe today ’ s requirements provide reviewing agencies with the ability to obtain all the information necessary to ensure compliance.

13. Why Are We Promulgating Different Reporting Requirements for Existing

Emissions Units Than for EUSGUs?

Today we are finalizing slightly different requirements for EUSGUs than other industries. In 2000, boilers and turbines with greater than 25 MWe or 250 mmBTU/hr of generating capacity represented 76 percent of this nation ’ s emissions of nitrogen oxides (NO X) and 85 percent of this nation ’ s emissions of

SO 2 from stationary sources. 25

In view of the disproportionate amount of emissions generated by EUSGUs compared to other industry sectors, we believe that it is appropriate for reviewing authorities to have

information on construction and

modification activities at EUSGUs readily available. Accordingly, we are requiring EUSGUs to provide a copy of their emissions projection to the reviewing authority before beginning actual construction of a project. We arealso requiring them to report their postchange annual emissions for every year they are required to generate them. This approach also makes sense because it

focuses the limited resources of both sources and agencies on the sources that

matter most.

III. CMA Exhibit B

In addition to the proposed changes

based on the 1992 WEPCO amendments ( see section II of this preamble), the 1996 proposal package included alternative regulatory language that would enable you to determine whether


### 80205 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

your facility has undertaken a modification based on the facility ’ s prechange and post-change potential

emissions instead of its actual emissions. This action was part of the settlement of a challenge to our 1980 NSR regulations by CMA and other industry petitioners. The exact language we proposed was set forth in Exhibit B to the Settlement Agreement, which is

contained in the docket for this rulemaking.

Under this method, sources may

calculate emissions increases and

decreases based on the actual emissions

method or the unit ’ s pre-change and post-change potential emissions, measured in terms of hourly emissions (that is, pounds of pollutant per hour).Sources could use this potential-topotential test for NSR applicability, as well as for calculating offsets, netting credits, and other ERCs.

We proposed to make several changes to the NSR regulations. First, we proposed to add the following exclusion

to the definition of ‘‘ major
modification ’’ :

A major modification shall be deemed not to occur if one of the following occurs: (a) there is no significant net increase in the

source ’ s PTE (as calculated in terms of pounds of pollutant emitted per hour); or (b) there is no significant net increase in the

source ’ s actual emissions.

Second, we proposed to delete all

references to ‘‘ actual emissions ’’in the

definition of ‘‘ net emissions increase ’’ and added language indicating that all

references to ‘‘ increase in emissions ’’
and ‘‘ decreases in emissions ’’in the

definition of ‘‘ net emissions increases ’’

‘‘ shall refer to changes in the source ’ s PTE (as calculated in terms of pounds of pollutant emitted per hour) or in its

actual emissions. ’’Third, we proposed to modify the applicability baseline by eliminating the reference to the 2-year baseline period and to a method for determining actual emissions during the representative period. Finally, we proposed to provide express

authorization for sources to use potential emissions in calculating offsets and in creating ERCs.

We also indicated in the preamble for the 1996 proposed rulemaking that if we promulgated the Exhibit B settlement as a final rule, the Exhibit B rules would need to be updated to reflect other rule changes since 1980, as well as relevant provisions of the 1990 Amendments.

Before proposing the Exhibit B language, we did a preliminary analysis of the impact on the NSR program of the Exhibit B changes. These changes would provide maximum flexibility to existing facilities with respect to determining if a significant net emissions increase would result from a physical or operational change. However, we also expressed concern about the environmental consequences associated with the Exhibit B provisions. For one, you could modernize your aging facilities (restoring lost efficiency and reliability while lowering operating costs) without undergoing preconstruction review, while increasing annual pollution levels as long as hourly potential emissions did not change. Also, Exhibit B would allow your facilities to generate netting credits and ERCs for offsets based on potential hourly emissions, even if never actually emitted. This could sanction greater

actual emissions increases to the environment, often from older facilities, without any preconstruction review. In addition, actual emissions increases resulting from unreviewed projects could go largely undocumented until a PSD review is performed by a new or modified facility that ultimately must undergo review. By that time, however,

a violation of an increment could have unknowingly occurred. We were also

concerned that Exhibit B would ultimately stymie major new source growth by allowing unreviewed

increases of emissions from modifications of existing sources to

consume all available increment in PSD

areas.

In our analysis supporting the 1996 proposal, we were unable to reach any conclusions as to the magnitude of any environmental impacts beyond noting that the effects would vary from State to State depending on how much

cumulative difference exists between the unused potential emissions and actual emissions in a given inventory of sources and on the extent to which any unused potential emissions have been

used in attainment demonstrations. However, our analysis did show that typical source operation frequently does

result in actual emissions that are below

allowable emission levels.

We received many comments in response to the 1996 proposal regarding

CMA Exhibit B. Some commenters believe the potential-to-potential test appropriately focuses on the significant emissions changes that could produce an adverse environmental impact.

Several other commenters believe that a potential-to-potential test would be environmentally detrimental. These

commenters believe that CMA Exhibit B represents a substantial weakening of the PSD program with large increases in actual emissions, which in itself could lead to a significant deterioration of air quality. They also express concerns regarding the creation of paper credits and other impacts on the broader air quality planning process. Onecommenter states that the potential-topotential test would conflict with SIPs that are based on actual emissions,

threaten a State ’ s efforts to make reasonable further progress (RFP) demonstrations, and interfere with emission credits relied on by SIPs.

These commenters also cite the following concerns.

• The potential-to-potential test would allow sources to escape the major modification provisions and could virtually eliminate NSR in most

modification cases.

• Once a facility has proceeded without NSR based on actual emissions,

it would be difficult to take an enforcement action years later that would successfully require that facility

to retrofit LAER and obtain offsets retrospectively.

We agree that a potential-to-potential test for major NSR applicability could

lead to unreviewed increases in

emissions that would be detrimental to air quality and could make it difficult to implement the statutory requirements

for state-of-the-art controls.

After consideration, we believe some of the comments in support of Exhibit B have merit. As noted by commenters who supported the CMA Exhibit B proposal, a potential-to-potential test could simplify and improve the NSR process. According to commenters, the CMA Exhibit B approach would have the following benefits.

• Limit the scope of the program to encompass only those significant physical changes that Congress intended

to cover

• Reduce unnecessary NSR costs and delays and improve compliance and

enforcement

• Lower the cost of the NSR process by reducing the complexity of the NSR applicability determinations

• Facilitate applicability decisions at the plant level

The commenters also say that the CMA Exhibit B approach is moreequitable than the existing actual-topotential approach, which results in the capture of a source ’ s unused capacity.These commenters prefer the potentialto-potential test because it would allow utilization increases. This provision is especially useful for sources in cyclical industries where using existing capacity

is critical. Sources in sectors where utilization and demand are closely

related would also benefit.

Our own concerns, coupled with the concerns expressed by some commenters, have caused us to reject the use of the Exhibit B regulatory changes for general purposes of determining whether a proposed


### 80206 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

26 In our 1996 proposal we used the term ‘‘ actual
emissions, ’’while today we are using the term

‘‘ baseline actual emissions. ’’ This change in terminology is consistent with the regulatory changes discussed in section II of today ’ s preamble. Despite this change in terminology, there may be places in this section of the preamble where we still use the phrase ‘‘ actual emissions. ’’In such cases we are either discussing PALs established under the old regulatory provisions, or summarizing and responding to comments received on the 1996 proposal. 27 Under our current NSR program, you can make physical changes or changes in the method of operation without triggering major NSR applicability, provided the individual changes do not result in significant net emissions increases. We have interpreted this requirement to permit you to make unrelated changes that, standing alone, do not result in significant emissions increases and to allow such changes to occur without considering whether other contemporaneous emissions increases render the change significant. Over time you could undertake numerous unrelated projects without triggering major NSR, provided the individual projects did not increase emissions by a significant amount, thus allowing source-wide emissions to increase over time without requiring any emissions controls for these individual projects. For example, a large chemical plant that is located in an ozone attainment area adds a new product line in 2001 and properly avoids PSD (including the BACT requirement) by limiting the VOC emissions increase to 39 tpy. Later, in 2003 the plant adds a different product line and also properly avoids PSD by limiting VOC emissions from the new line to 39 tpy. For this example, two process lines at the same plant with total potential emissions (78 tpy) above the 40 tpy VOC significant level under PSD were properly permitted over a 3-year period without BACT applying to either new product line. physical or operational change would result in a major modification. For the reasons stated above, we do not believe that a potential-to-potential approach is acceptable for major NSR applicability as a general matter. However, we agree with the commenters in part

—some of the benefits of a potential-to-potential approach are desirable. We believe that

in more limited circumstances a

‘‘ potential-to-potential ’’ -like approach would be acceptable. Therefore, we are promulgating two new applicability provisions that capture the benefits of a potential-to-potential approach but still have the necessary safeguards to ensure environmental protection

—PALs, and

the Clean Unit Test.

Today ’ s rules provide for a PAL based on plantwide actual emissions. If you keep the emissions from your facility below a plantwide actual emissions cap, then you need not evaluate whether each change might be subject to the major NSR permitting when you make alterations to the facility or individual

emissions units. The cumulative actual

emissions become the de facto potential emissions for the plant, and you may emit up to the permitted level without going through major NSR, even if you are making changes to the facility. The PAL allows you to make changes quickly by allowing you to alter your facility without first going through major NSR review. It thus limits the number and complexity of NSR applicability determinations, and reduces unnecessary costs and delays. It also allows a plant manager to authorize changes, as long as the emissions remain under the permitted level, without first obtaining reviewing authority review. Furthermore, itprovides an incentive to use state-of-theart controls and install new, lower emitting equipment, which will allow

sources to increase utilization. In return for the flexibility a PAL allows, you must monitor emissions from all of your

emissions units under the PAL. Therefore, the PAL ensures good controls and protection of air quality.

We believe there are other mechanisms for establishing PALs that would achieve beneficial results. For example,

we believe PALs based on allowable emissions would produce flexibility and assure environmental protection, provided affected sources had adequate safeguards. Therefore, we intend in the near future to propose a rule that would adopt PALs based on allowable

emissions.

Analogous to what the PAL does for facilities, the Clean Unit Test sets emission limitations or work practice requirements in conjunction with BACT, LAER, or Clean Unit determinations and identifies any physical or operational characteristics that formed the basis for the BACT, LAER, or Clean Unit determination for a particular unit. The Clean Unit Test recognizes that if you go through major NSR review (including air quality review) and install BACT or LAER or comparable technology, then you may make any subsequent changes to the Clean Unit without triggering an additional major NSR review, as long as there is no need for a change in the emission limitations or work practice requirements in the permit for the unit that were adopted in conjunction with BACT, LAER, or Clean Unit determination or to alter any physical or operational characteristics that formed the basis for the BACT, LAER, or Clean Unit determination. Therefore, for Clean Units, given that the permit is based on a determination that is protective of air quality, the new test would deem there

is no emissions increase as a result of any physical change or change in the method of operation. With these provisions, sources will have improved certainty and flexibility, reduced burden, and opportunity for utilization increases without compromising air quality. Like the PAL, the Clean Unit includes necessary safeguards by requiring enforceable permit terms and

conditions to ensure environmental protection.

IV. Plantwide Applicability Limitations

A. Introduction

Today we are adopting a final rule for a PAL option that is based on the

baseline actual emissions 26 from major stationary sources. A PAL is an optional approach that will provide you, the owners or operators of major stationary sources, with the ability to manage facility-wide emissions without triggering major NSR. We believe the added flexibility of a PAL allows you to respond rapidly to market changes consistent with the goals of the NSR

program.

The final rules we are adopting today also benefit the public and the environment. Reviewing authorities, usually States, can only establish a PAL by using a public process that affords citizens the opportunity to comment upon the proposed PAL. This process is designed to assure local communities that air emissions from your major stationary source will not exceed the facility-wide cap set forth in the permit unless you first meet the major NSR requirements. We believe that a PAL provides a more complete perspective to the public because in setting a PAL, your reviewing authority accounts for all current processes and all emissions units together and reflects the long-term

maximum amount of emissions it would allow from your source. Moreover, to comply with a PAL you must meet monitoring requirements prescribed in the rules that ensure that both your reviewing authority and the public have

sufficient information from which to determine plantwide compliance. Additionally, through the final PAL regulations, we are promoting voluntary improvements in pollution controls by creating an incentive for you to control existing and new emissions units to

maintain a maximum amount of operational flexibility under the PAL. Most importantly, for pollutants subject to a PAL, we are prohibiting serial, small, unrelated emissions increases, 27
which otherwise can occur under our existing regulations.

If you choose to use it, we believe you will benefit from the PAL option because you will have increased operational flexibility and regulatory certainty, a simpler NSR applicability approach, and fewer administrative burdens. To comply with a PAL, you

need to ensure that there are no emissions increases from your major stationary source, as measured against the PAL. For you to do that, there is no need for you to quantify


### 80207 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

28 The term ‘‘ voluntary ’’means that you have the option of entering into a PAL, rather than voluntary compliance with a PAL that is in place. Once you have a permit with PAL requirements, you must comply with the requirements.

29 Results of our study are reported in ‘‘ Evaluation of the Implementation Experience with Innovative

Air Permits. ’’A complete copy of this report is located in the docket for today ’ s rulemaking. contemporaneous emissions increases
and decreases for individual emissions units. Through the PAL we are allowing you to make timely changes to react to market demand and providing you additional certainty regarding the level of emissions at which your source will be required to undergo major NSR. The benefit to you is that you will not have to make numerous applicability decisions using different baselines. Also, in some situations where you

would have been unable to ‘‘ net out ’’a new project in the major NSR program, under a PAL you can begin construction on your new project without obtaining a major NSR permit, which can take from a few months up to 2 years. In addition, because you may make

emissions reductions at emissions units under the PAL to create room for growth at other units, through the PAL we are providing a strong incentive for you to employ innovative control technologies and pollution prevention measures, to create voluntary emissions reductions to facilitate economic expansion.

B. Relevant Background

1. What Is a PAL and How Does a PAL Compare to Other Major NSR Requirements and Netting?

The concept of a PAL is simple. Under the Act, you are not subject to major NSR unless you make a

‘‘ modification, ’’which by definition

cannot occur without an emissions increase. CAA section 111(a)(4). A PAL is a source-wide cap on emissions and is one way of making sure that emissions increases from your major stationary source do not occur.

The existing regulations require

‘‘ major modifications ’’to undergo NSR,

and the existence of a ‘‘ significant net

emissions increase ’’at the facility is a necessary prerequisite to a ‘‘ major
modification. ’’ See, for example,
§§ 52.21(b)(2) & (3); see also Chevron v. Natural Resources Defense Council, 467 U.S. 837, 863

–64 (1984). Under our current system, we determine whether a

‘‘ significant net emissions increase ’’ occurs at your major stationary source by focusing initially on the change to the emissions unit(s) and then broadening the analysis to include other changes within the source. In order to

determine whether there is a

‘‘ significant net emissions increase ’’ under major NSR as revised today, you must establish a pre-change baseline for each change, project the actual level of emissions after the change, calculate the

creditable emissions increases and

decreases that have occurred that are contemporaneous with the change, and determine whether the change would result in a significant net emissions increase. We refer to this applicability

process as ‘‘ netting ’’under the major NSR regulations. Both you and reviewing authorities have maintained that the netting rules are unnecessarily complex and burdensome, and have urged us to craft rules that link NSR applicability to compliance with a predictable source-wide emissions cap. We are responding to that request with the PAL concept. A PAL is a voluntary, 28 source-specific, straightforward, flexible approach to account for changes, including alterations to existing emissions units

and the addition of new emissions units, at your existing major stationary sources. Complying with the PAL

ensures that there are no emissions increases that trigger major NSR. If your emissions of the PAL pollutant remain below the PAL, and you comply with all other PAL requirements, whatever changes occur at your plant will not be subject to major NSR for the PAL pollutant. Our July 23, 1996 proposal contains a thorough discussion of the proposed PAL concept and the background information used to develop the proposal.

2. Why Does EPA Believe That PALs

Will Benefit the Environment?

Over the past several years, we haveallowed use of major stationary sourcewide emissions caps to demonstrate compliance with major NSR in a select number of pilot projects. We recently

reviewed six of these innovative air permitting efforts and found substantial

benefits associated with the implementation of permits containing emissions caps (among other types of permit terms offering greater flexibility than major NSR permitting programs). 29 Specifically, we reviewed on-site

records to track utilization of these flexible permit provisions, to assess how well the permits are working and any emissions reductions achieved, and to determine if there were any economic benefits of the permits.

Overall, we found that significant

environmental benefits occurred for each of the permits reviewed. In particular, the six flexible permits established emissions cap-based frameworks that encouraged emissions reductions and pollution prevention, even though such environmental improvements were not an explicit requirement of the permits. We found that in a cap-based program, sources strive to create enough headroom for future expansions by voluntarily controlling emissions. For instance, one company lowered its actual VOC emissions over threefold in becoming a synthetic minor source (that is, 190 tpy to 56 tpy). Other companies lowered their actual VOC emissions by as much as 3600 tpy by increasing capture, by using voluntary pollution prevention and other voluntary emissions control measures, and by reducing production

rates.

Participants reported that having the ability to make rapid, iterative changes to optimize process performance in ways that minimize emissions, and that

reduce the administrative ‘‘ friction ’’ (time delays and uncertainty) associated with making operational and equipment changes, encourages facilities to make changes that improve yields and reduce per-unit emissions. It is also critical for responding to product development needs and market demand, and for maintaining overall competitiveness.

Reviewing authorities consistently reported that the permits worked well and proved beneficial, and that there

was a reduction in the number of caseby-case permitting actions they needed to undertake. Specifically, we found that flexible permit provisions (for example, emissions caps) are enforceable as a practical matter by using a mixture of mass balance-based equations, CEMS, and parameter monitoring. No emissions cap
exceedances or violations of the monitoring provisions were experienced by any of the pilot sources. In addition, the monitoring and reporting approaches worked well and were generally of higher quality and of more extensive scope than those directly required by individual applicable requirements.

Based on the results of these pilot projects, we believe that PALs will over time tend to shift growth in emissions to cleaner units, because the growth will

have to be accommodated under the PAL cap. Specifically, we expect that PALs will encourage you to undertake such projects as: replacing outdated, dirty emissions units with new, more efficient models; installing voluntary emissions controls; and researching and implementing improvements in process efficiency and use of pollution prevention technologies, so that you can maintain maximum operational flexibility. We also expect that you and the reviewing authority will need to devote substantially fewer resources to


### 80208 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

30 The key determination to be made is whether

an emissions unit is ‘‘ permanently shut down. ’’

This issue is discussed in the Administrator ’ s response to a petition objecting to an operating permit for a facility in Monroe, Louisiana. See Monroe Electric Generating Plant, Petition No. 6

– 99

–2 (Adm ’ r 1999). A copy of this decision is in the docket. In general, we explained in our

‘‘ reactivation policy ’’that whether or not a discussing and reviewing whether major NSR applies to individual changes. Thus, overall, we believe that PALs will prove to be as beneficial to the environment as they are to you and your reviewing authority.

3. What Did We Propose for PALs?

On July 23, 1996, we proposed to amend the NSR regulations to specifically authorize PALs and to clarify the methodology under which you can obtain a PAL. Under the proposal, your reviewing authority could have elected to include provisions in its SIP to allow you to apply for a permit that based your source ’ s major NSR applicability on compliance with a pollutant-specific, source-wide emissions cap. We proposed that a facility ’ s PAL would generally be based

on source-wide ‘‘ actual emissions ’’plus an operating margin of emissions less than a significant emissions increase. We also sought comment on the

circumstances under which it would be appropriate to use something other than actual (for example, ‘‘ allowable ’’ )

emissions to set the PAL.

On July 24, 1998, we published a

notice in the Federal Register seeking

further comment on how the PAL regulations could be reconciled with several environmental and legal

concerns. The notice discussed how the

PAL alternative fits within the Act ’ s requirements for determining if changes at existing sources are subject to major NSR. Today we are adopting final regulations that address the issues and

comments raised in the 1998 notice and the 1996 proposal.

C. Final Regulations for Actuals PALs

Today ’ s action establishes final regulatory provisions for actuals PALs. We are placing these requirements in the major NSR rules for nonattainment

areas at § 51.165(f), and in the PSD regulations (applicable in attainment and unclassifiable areas) at §§ 51.166(w) and 52.21(aa).

The PAL option adopted today provides you with a voluntary alternative for determining NSR applicability. Actuals PALs are rolling 12-month emissions caps (that is, tpy limits) that include all conditions necessary to make the limitation enforceable as a practical matter. Through the regulations, we are allowing PALs on a pollutant-specific basis and are also allowing you to opt

for actuals PALs for more than one pollutant at your existing major stationary sources. You must continue to apply the major NSR applicability provisions to air pollutants at your source for which you have no PAL. This section sets forth the specific requirements for actuals PALs. The section addresses the following items: (1) The process used to establish a PAL and the public participation requirements; (2) how the PAL level is determined; (3) how long a PAL is effective and what happens when a PAL expires; (4) can a PAL be terminated before the end of its effective period; (5) how a PAL is renewed; (6) how a PAL can be increased during the effective period; (7) circumstances that would cause your PAL to be adjusted during the PAL effective period; (8) whether a

PAL can eliminate enforceable emission limitations previously taken to avoid major NSR; (9) the compliance requirements and monitoring, recordkeeping, reporting, and testing (MRRT) requirements that the permit

must contain for emissions units under your PAL; (10) the process for incorporating conditions of the PAL into your title V operating permit; and (11) an example of how an actuals PAL would work under the regulations finalized today.

1. What Are the Permit Application Requirements, What Is the Process Used To Establish a PAL, and What Are the Public Participation Requirements?

Under today ’ s final rules, you must submit a complete application to your reviewing authority requesting a PAL. The application, at a minimum, must include a list of all emissions units, their size (major, significant, or small); the Federal and State applicable requirements, emission limitations and work practice requirements that each emissions unit is subject to; and the

baseline actual emissions for the emissions units at the source (with supporting documentation). The

calculation of baseline actual emissions must include fugitive emissions to the extent they are quantifiable. The reviewing authority must establish a PAL in a federally enforceable permit (for example, a ‘‘ minor ’’NSR construction permit, a major NSR permit, or a SIP-approved operating permit program). To comply with our final regulations, the reviewing authority must provide an opportunity for public participation when issuing a PAL permit. This process must be consistent with the requirements at § 51.161 and include a minimum of a 30-day period for public notice and opportunity for public comment on the proposed permit. Where the PAL is established in a major NSR permit, major NSR public participation procedures apply. When establishing a PAL, you must comply with all applicable requirements of the reviewing authority ’ s minor NSR program, including modeling to ensure the protection of the ambient air quality. Additionally, you must meet all applicable title V operating permit requirements. When adding new emissions units under a PAL, you must comply with the reviewing authority ’ s minor NSR permit requirements for public notice, review, and comment. In contrast, when adding new emissions units that will require an increase in a PAL, you must comply with the reviewing authority ’ s major NSR permit requirements for public notice, review,

and comment.

2. How Is the Level of the PAL

Determined?

We calculate the PAL level for a specific pollutant by summing the

baseline actual emissions of the PAL pollutant for each emissions unit at your existing major stationary source, and then adding an amount equal to the applicable significant level for the PAL pollutant under § 52.21(b)(23) or under the CAA, whichever is lower.

You must first identify all your existing emissions units (greater than 2 years of operating history) and new emissions units (less than 2 years of operating history since construction). When establishing the actuals PAL level, you must calculate the baseline actual emissions from existing emissions units that existed during the 24-month period as described below. The baseline actual emissions will equal the average rate, in tpy, at which your

emissions units emitted the PAL pollutant during a consecutive 24- month period, within the 10-year period immediately preceding the application for a PAL. Consistent with today ’ s final rules, you will have broad discretion to select any consecutive 24-month period in the last 10 years to determine the baseline actual emissions. Only one consecutive 24-month period may be

used to determine the baseline actual emissions for such existing emissions units. For any emissions unit (currently classified as existing or new) that is constructed after the 24-month period, emissions equal to its PTE must be added to the PAL level. Additionally, for any emissions unit that is permanently shut down or

dismantled 30 since the 24-month


### 80209 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

shutdown should be treated as permanent depends on the intention of the owner or operator at the time

of shutdown based on all facts and circumstances. Shutdowns of more than 2 years, or that have

resulted in the removal of the source from the

State ’ s emissions inventory, are presumed to be permanent. In such cases it is up to the facility owner or operator to rebut the presumption. period, its emissions must be subtracted

from the PAL level. Different rules apply for determining baseline actual

emissions for EUSGUs. You should refer

to the definition of baseline actual emissions to determine the specific method for calculating baseline actual emissions for your emissions units. Consistent with today ’ s final rules for determining baseline actual emissions, your baseline actual emissions for an

emissions unit cannot exceed the emission limitation allowed by your permit or newly applicable State or Federal rules (RACT, NSPS, etc.) in effect at the time the reviewing authority sets the PAL. This means that for the purpose of setting the PAL, your

baseline actual emissions for an

emissions unit will include an adjustment downward to reflect currently applicable requirements. Additionally, your reviewing authority shall specify a reduced PAL level(s) (in tpy) in the PAL permit to become effective on the future compliance date(s) of any applicable Federal or State regulatory requirement(s) that the reviewing authority is aware of prior to issuance of the PAL permit. See section II of today ’ s preamble for additional information on determining the baseline actual emissions for your emissions

units.

3. How Long Can a PAL Be Effective and What Happens When a PAL Expires?

Through the final rules, we are requiring that the term of an actual PAL be 10 years. At least 6 months prior to, but not earlier than 18 months from, the expiration date of your PAL, you must submit a complete application either to request renewal or expiration of the PAL. If you meet this application deadline for a permit renewal, the existing PAL will continue as an enforceable requirement until the reviewing authority renews your PAL, even if the reviewing authority fails to

issue a PAL renewal within the specified period of time.

As part of an application to request expiration of the PAL, you must submit a proposed approach for allocating the PAL among your existing emissions units. The reviewing authority will

retain the ultimate discretion to decide

whether and how the allowable emission limitations will be allocated, including whether to establish limits on individual emissions units or groups of emissions units. As under the PAL, your emissions units must comply with their

allowable emission limitations on a 12- month rolling basis. However, the reviewing authority retains the discretion to accept monitoring systems other than CEMS, CPMS, PEMS, etc., from you to demonstrate compliance with these unit-specific limits.

Until the reviewing authority issues the revised permit with allowable emission limitations covering each of your emissions units, your source must comply with a source-wide multi-unit emissions cap equivalent to the PAL level. After a PAL expires, physical or operational changes will no longer be evaluated under the PAL applicability provisions.

Notwithstanding the expiration of the PAL, you must continue to comply with any State or Federal applicable requirements for a specific emissions unit. (BACT, RACT, NSPS, etc.) When the PAL expires, none of the limits established pursuant to §§ 51.166(r)(2), 51.165(a)(5)(ii), or 52.21(r)(4), which the PAL originally eliminated, would return under today ’ s final rules.

4. Can a PAL Be Terminated Before the

End of Its Effective Period?

Today ’ s final rules do not contain specific provisions related to the issue of terminating a PAL. Decisions about

whether a PAL can or should be terminated will be handled between you and your reviewing authority in accordance with the requirements of the applicable permitting program.

5. How Is a PAL Renewed?

As previously discussed, you must submit a complete application to renew a PAL at least 6 months prior to, but not earlier than 18 months from, the expiration date of your PAL. If you submit a complete application to renew the PAL by this deadline, the existing

PAL will continue as an enforceable requirement until the reviewing authority issues the permit with the renewed PAL. As part of your renewal application, you must recalculate and propose your maximum PAL level, taking into account newly applicable requirements and the factors described

below.

Your reviewing authority must review the complete application and issue a proposed permit for public comment consistent with the permitting procedures for issuing the initial PAL. As part of this public process, the reviewing authority must provide a written rationale for its proposed PAL level. If your source ’ s PTE has declined below the PAL level, the reviewing authority must adjust the PAL

downward so that it does not exceed

your source ’ s PTE.

In addition, the reviewing authority may renew the PAL at the same level without consideration of other factors, if

the sum of the baseline actual emissions for all emissions units at your source (as calculated using the definition of

‘‘ baseline actual emissions ’’at §§ 51.165(a)(1)(xii)(B), 51.166(b)(21), and 52.21(b)(21) as amended by today ’ s final rules) plus an amount equal to the significant level is equal to or greater than 80 percent of the PAL level (unless greater than the current PTE of the major stationary source). However, if the baseline actual emissions plus an amount equal to the significant level is less than 80 percent of the PAL level, the reviewing authority may set the PAL

at a level that it determines to be more representative of the source ’ s baseline actual emissions, or that it determines to be appropriate considering air quality needs, advances in control technology, anticipated economic growth in the area, desire to reward or encourage the

source ’ s voluntary emissions reductions, cost effective emissions control alternatives, or other factors as specifically identified by the reviewing authority in its written rationale. For instance, a reviewing authority may

determine that PAL levels are inconsistent with the levels necessary to achieve the NAAQS, or a State may

determine that PAL levels need to be reduced to provide room for new economic growth in the area.

In some circumstances, such as in the example cited below, the reviewing authority may exercise its discretion in deciding that an adjustment is not

warranted. We believe that such discretion is appropriate, based in part on our experience with the pilot projects previously mentioned. In one instance, a participant voluntarily agreed to reduce its actual emissions by 54 percent in exchange for obtaining a source-wide emissions cap. After agreeing to this emissions reduction, the participant further reduced emissions by increasing capture efficiency and incorporating pollution prevention strategies into its operations. Unexpectedly, the participant also

suffered an unusual economic downturn

that caused a decrease in the rate of production and a corresponding

decrease in actual emissions. At the

time of renewal of the source-wide emissions cap, the participant ’ s actual emissions were 10 percent of its actual emissions before committing to the emissions cap. The participant chose not to renew its emissions caps, because renewal required an automatic


### 80210 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

adjustment to its current actual emissions level. Clearly, such a result

contravenes the mutual benefits that operating under a PAL provides, and discourages you from undertaking voluntary reductions. If your source would ordinarily be subject to a downward adjustment, but you believe such an adjustment is not appropriate, you may propose another level. The reviewing authority may approve the level that you propose if it determines, in writing, that the level is reasonably representative of the source ’ s baseline actual emissions. Similarly, the reviewing authority may determine that a lower level best represents the

baseline actual emissions from the

source.

Consistent with the effective period for the initial PAL, all renewed PALs will have a 10-year effective period.

6. How Can a PAL Be Increased During

the Effective Period?

The reviewing authority may allow you to increase a PAL during the effective period if you are adding new emissions units or changing existing emissions units in a way that would cause you to exceed your PAL. However, today ’ s rule only authorizes your reviewing authority to allow such an increase if you would not be able to

maintain emissions below the PAL level even if you assumed application of BACT equivalent controls on all existing major and significant units (emissions units that have a PTE greater than a significant amount (as defined by
§ 52.21(b)(23) or the CAA, whichever is lower). Such units must be adjusted for

current BACT levels of control unless they are currently subject to a BACT or LAER requirement that has been determined within the preceding 10 years, in which case the assumed control level shall be equal to the

emissions unit ’ s existing BACT or LAER control level. The PAL permit must require that the increased PAL level will be effective on the day any emissions unit that is part of the PAL major modification becomes operational and begins to emit the PAL pollutant.

Your proposed new emissions unit(s) and your existing emissions units undergoing a change must go through major NSR permitting, regardless of the magnitude of the proposed emissions increase that would result (for example, no significant level applies). This is because the significant level for the pollutant is incorporated into the PAL. These emissions units must comply with any emissions requirements resulting from the major NSR process (for example, LAER), even though they have also become subject to the PAL program or remain subject to the PAL.

To request a PAL increase, you must submit a complete major NSR permit application. As part of this application, you must demonstrate that the sum of the baseline actual emissions of your small emissions units, plus the sum of the baseline actual emissions from your significant and major emissions units (adjusted for a current BACT level of

control unless the emissions units are currently subject to a BACT or LAER requirement that has been determined within the preceding 10 years, in which

case the assumed control level shall be equal to the emissions unit ’ s existing BACT or LAER control level), plus the

sum of the allowable emissions of the new or modified existing emissions unit(s), exceeds the PAL.

After the reviewing authority has completed the major NSR process, and thereby determined the allowable

emissions for the new or modified emissions unit(s), the reviewing authority will calculate the new PAL as

the sum of the allowable emissions of the new or modified emissions unit(s), plus the sum of the baseline actual emissions of your small emissions units, plus the sum of the baseline actual emissions from significant and major emissions units adjusted for the appropriate BACT level of control as described above. Your reviewing authority must modify the PAL permit

to reflect the increased PAL level pursuant to the public notice requirements of §§ 51.166(w)(5), 51.165(f)(5), or 52.21(aa)(5) of today ’ s final rule.

7. Are There Any Circumstances That Would Cause Your PAL To Be Adjusted During the PAL Effective Period?

During the term of the PAL, at PAL renewal or at title V permit renewal, your reviewing authority may reopen your PAL permit and adjust the PAL level, either upward or downward, as needed by the reviewing authority. While certain activities require mandatory reopening, for others the reviewing authority may reopen at its discretion. The reviewing authority must reopen the permit for the following reasons: (1) To correct typographical/calculation errors made in setting the PAL or to reflect a more

accurate determination of emissions used to establish the PAL; (2) to reduce the PAL if the owner or operator of the major stationary source creates
creditable emissions reductions for use as offsets; or (3) to revise a PAL to

reflect an increase in the PAL.

The reviewing authority may reopen the permit to: (1) Reduce the PAL to reflect newly applicable Federal requirements (for example, NSPS) with compliance dates after the PAL effective date; (2) reduce the PAL consistent with any other requirement that is enforceable as a practical matter, and that the State may impose on the major stationary source under the SIP; or (3) reduce the PAL if the reviewing authority determines that a reduction is necessary to avoid causing or contributing to a NAAQS or PSD increment violation, or to an adverse impact on an AQRV that has been identified for a Federal Class I area by

an FLM and for which information is available to the general public.

While the final rule does not require your reviewing authority to immediately reopen the PAL permit to reflect newly applicable Federal or State regulatory requirements (for example, NSPS, RACT) that become effective during the PAL effective period, it does require the PAL to be adjusted at the time of your title V permit renewal or PAL permit renewal, whichever occurs first. Notwithstanding this requirement, today ’ s final rule provides your reviewing authority discretion to reopen the PAL permit to reduce the PAL to reflect newly applicable Federal or State regulatory requirements before the time we otherwise require.

8. Can a PAL Eliminate Existing

Emission Limitations?

An actuals PAL may eliminate enforceable permit limits you may have previously taken to avoid the applicability of major NSR to new or

modified emissions units. Under the major NSR regulations at §§ 52.21(r)(4), 51.166(r)(2), and 51.165(a)(5)(ii), if you relax these limits, the units become subject to major NSR as if construction had not yet commenced on the source or modification. Should you request a PAL, today ’ s revised regulations allow

the PAL to eliminate annual emissions or operational limits that you previously took at your stationary source to avoid major NSR for the PAL pollutant. This means that you may relax or remove these limits without triggering major

NSR when the PAL becomes effective. Before removing the limits, your reviewing authority should make sure that you are meeting all other regulatory requirements and that the removal of the limits does not adversely impact the NAAQS or PSD increments.

We are not taking a position on whether compliance with requirements contained in a PAL permit could serve to demonstrate compliance with certain pre-existing requirements on individual units. The reviewing authority may assess on a case-by-case basis whether


### 80211 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

any streamlining would be appropriate in the title V permit consistent with part 70 procedures and our existing policies and guidance on permit streamlining.

9. What MRRT (Collectively Referred to

as ‘‘ Monitoring ’’ ) Requirements Must

the Permit Contain for Emissions Units

Under Your PAL?

Each permit must contain enforceable requirements that accurately determine plantwide emissions. A PAL monitoring system must be comprised of one or more of the four general approaches that meet the minimum requirements discussed below, and such monitoring systems must be approved by the reviewing authority. You may also employ an alternative approach if approved by the reviewing authority. Use of monitoring systems that do not meet the minimum requirements approved by the reviewing authority renders the PAL invalid. Any monitoring system authorized for use in the PAL permit must be based on sound science and must conform to generally acceptable scientific procedures for data quality and manipulation.

In return for the increased operational flexibility of a PAL, your permit must

include sufficient data collection requirements to ensure compliance with the PAL at all times. In addition, the PAL permit must contain enforceable provisions that ensure that the monitoring data meet the minimum legal requirements for admissibility in a judicial proceeding to enforce the PAL permit.

This section addresses a number of issues associated with the practical enforceability of PALs and describes concepts that you and reviewing

authorities must follow when establishing your PAL. The issues addressed include the following.

• How do monitoring requirements

for emissions units under a PAL differ

from those for emissions units that are

not under a PAL?

• What are the testing requirements for your emissions units under a PAL?

• What monitoring systems are appropriate to demonstrate compliance with your PAL?

• What information about your proposed data collection systems must be submitted to your reviewing authority for approval?

• What recordkeeping requirements must your permit contain to demonstrate compliance with your

PAL?

• What reporting requirements for your PAL must your permit contain? a. How Do Monitoring Requirements for Emissions Units Under a PAL Differ From Those for Emissions Units That

Are Not Under a PAL?

Typically, when an emission limitation applies on a unit-by-unit basis, the monitoring must be sufficient to provide data that demonstrate that emissions do not exceed the applicable limit for a particular unit. Under this approach, if an emissions unit has to meet an NSPS VOC limit of 9 ppm, the monitoring need only demonstrate that VOC emissions are no higher than 9 ppm but not measure VOC emissions at any precise level below 9 ppm (for example, 7 ppm, 8 ppm).

In contrast, under a VOC emissions actual PAL, the VOC emissions from each emissions unit must be quantified (in tpy), generally each month as the sum of the previous 12 months of VOC emissions. Thus, it becomes necessary to require monitoring that quantifies the

emissions from each emissions unit to

ensure that the annual limit is enforceable as a practical matter. As a result, the monitoring requirements for emissions units under a PAL may be more stringent than for those emissions units not under a PAL. In many instances, your emissions units may have monitoring suitable fordetermining compliance with a unitspecific emission limitation on a periodic basis, in accordance with title V requirements, but that monitoring frequency of data collection may not be appropriate for ongoing emissions quantification for a 12-month rolling total. Thus, even if your emissions

unit ’ s monitoring meets the title V requirements in §§ 70.6(a)(3)(i)(B) or 70.6(c)(1), you must upgrade that monitoring if you request a PAL and the existing monitoring does not meet the minimum requirements of the PAL regulations.

All units operating under a PAL must have sufficient monitoring to accurately determine plantwide emissions for a 12- month rolling total. For example, a source owner or operator with five units must be able, at any time, to quantify

the baseline actual emissions for the past 12 months for each of the five units. That source should, in advance, outline how it plans to monitor each of the units in order to quantify the

emissions. If one of the five units cannot accommodate one of the monitoring options provided in the rule in order to quantify the emissions, then the source owner or operator would be incapable of demonstrating ongoing compliance with

the source ’ s PAL. b. What Are the Testing Requirements for Your Emissions Units Under a PAL?

As part of your PAL application and as directed by your reviewing authority, you must use current emissions or other

current direct measurement data to demonstrate that your monitoring systems accurately determine emissions from each unit subject to a PAL. You

will need to collect such data from all units subject to the PAL, including those that are unregulated at the present time. If you do not have current emissions data, or if your emissions

unit ’ s operation and equipment have changed since collection of that data, you will need to obtain current, accurate data, typically by conducting performance tests or other direct

measurements before submission of your complete permit application to

obtain a PAL.

In addition, you will need to revalidate the data and any correlation to demonstrate that your monitoring systems continue to accurately

determine emissions from each unit subject to a PAL. This re-validation must occur at least once every 5 years

for the life of the PAL. Data must be revalidated through a performance evaluation test or other scientifically valid means that is approved by the reviewing authority.

You must conduct all testing in

accordance with test methods appropriate to your emissions unit and applicable requirements. For example, among the test methods for measuring organic emissions are Methods 18, 25, 25A, and 25B, which can be found in 40 CFR part 60, appendix A. During testing, your emissions unit must operate within the range you wish to operate, so as to provide an accurate quantification of emissions across the entire range. This may require you to perform more than one performance

test.

c. What Monitoring Systems Are Appropriate To Demonstrate Compliance With Your PAL?

The PAL monitoring system must be comprised of one or more of four general approaches: (1) Mass balance for processes, work practices, or emissions sources using coatings or solvents; (2) Continuous Emissions Monitoring System (CEMS); (3) Continuous Parameter Monitoring System (CPMS) or Predictive Emissions Monitoring System (PEMS) with Continuous Emissions Rate Monitoring System (CERMS) or automated data acquisition and handling system (ADHS), as needed; or (4) emission factors. Alternatively, another monitoring approach may be


### 80212 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

used if approved in advance by the reviewing authority. The monitoring approaches mentioned above must meet minimum requirements established by today ’ s rule.

In the mass balance approach, you would consider all of the PAL pollutant contained in or created by any raw material or fuel used in or at your emissions unit to be emitted. Currently, we are limiting this approach to monitoring for processes, work practices, or emissions sources using coatings or solvents. In order to use the mass balance approach, you must

validate the content of the PAL pollutant that is contained in or created by any raw material or fuel used on site. This validation may be accomplished by a regular testing program conducted by the vendor of the materials or by an independent laboratory. In addition, you are required to use the upper limit of any content range in the calculations, unless the reviewing authority determines that there is a site-specific data monitoring system in place at the unit or that there are data to support the use of another content within the range.

If your reviewing authority allows you to use a mass balance approach, then the PAL permit must require you to account for all material containing the PAL pollutant or use of all materials that could create PAL pollutant emissions (through chemical decomposition, by-product formation, etc.). For instance, if you are subject to a VOC PAL and your emissions units do not utilize add-on control devices, you may use a mass balance approach to determine compliance. For example, suppose over 1 month you were using 8 tons of solvent with 25 percent VOCs (as demonstrated using Method 311). You would be required to report and include 2 tons of VOC emissions (since

8 × 0.25 = 2) for that month to compare with the PAL, even though some of the VOCs may not ultimately be emitted. (For example, they could be retained in your emissions unit ’ s product or in a process waste.)

A CEMS, coupled with a CERMS as well as an ADHS (collectively known as a CEMS), may be used to measure and verify the PAL pollutant concentration, volumetric gas flow (if applicable), and PAL pollutant mass emissions discharged to the atmosphere from each emissions unit emitting the PAL pollutant. If your source utilize a CEMS approach, you must ensure that the CEMS meets the applicable Performance Specifications in 40 CFR part 60, appendix B. The CEMS must be capable of data sampling at least once every 15 minutes. In addition, you must be able to convert the data obtained from the CEMS system to a mass emissions rate.

These types of monitoring systems are appropriate for emissions sources subject to respective SO 2 , NO X , carbon monoxide, particulate matter (PM), VOC, total reduced sulfur (TRS), or hydrogen sulfide (H 2 S) regulations.

A CPMS or PEMS coupled with CERMS and ADHS (collectively known as parameter monitoring), may be used

for emissions units as reviewed and approved by your reviewing authority.

To determine emissions, parameter monitoring relies on: (1) Use of physical principles; (2) parameters such as temperature, mass flow, or pressure differential; and (3) performance testing results. Users of parameter monitoring

must show a correlation between predicted and actual emissions across the anticipated operating range of the

unit.

An example is a source owner or operator who determines VOC emissions from an incinerator by multiplying the incinerator efficiency by the amount of VOC-containing material used. Three assumptions are built into the emissions algorithm: (1) The VOC content remains constant; (2) the control device reduction efficiency remains constant over the temperature range established during performance testing; and (3) the unit load remains constant. Checks on these assumptions are established by: ongoing monitoring requirements (for example, combustion chamber temperature and control device load); ongoing emissions testingrequirements (for example, periodic reevaluation of the correlation between combustion chamber temperature and control device efficiency); and ongoing testing of the VOC content of the

material.

Another example of parameter monitoring is an organic emissions condenser. The parameter monitoring design in this case is based on the laws of physics and the physical properties of the material (for example, the lowest condensation temperature of the VOC constituent), the temperature of the condenser, and the maximum material

feed rate.

Some parameter monitoring works by calculating emissions using data from monitored parameters and a neural network system to optimize performance of a unit. By measuring numerous parameters, the network can then automatically analyze current operations, as well as emissions, and make adjustments to optimize performance.

Establishing parameter monitoring is a resource-intensive effort, requiring extensive up-front testing, analysis, and development. Recently, we have developed draft performance specifications for evaluating appropriate, acceptable parameter monitoring accuracy, repeatability, and reproducibility ( e.g. , Performance Specification 16). You and your reviewing authority should review these performance specifications in developing an interim protocol for using parameter monitoring to demonstrate continuous compliance with a PAL. Your approved protocol may require revision as we finalize performance specifications.

Today ’ s rule requires you to revalidate your monitoring systems, including parameter re-certification emissions testing, at least once every 5 years during the PAL permit term. You may conduct such re-validation as part of any other testing required by other non-PAL program requirements, such as title V program requirements.

If a parameter monitoring approach is taken, the owner or operator must use current site-specific data to establish the

emissions correlations between the monitored parameter and the PAL pollutant emissions across the entire range of the operation of the emissions unit. If the owner or operator cannot

establish a correlation for the entire operation range, the reviewing authority shall, at the time of the permit issuance, establish a default value(s) for determining compliance with the PAL based on the highest potential emissions reasonably estimated during the operational times when an emissions

correlation is not available.

Alternatively, the reviewing authority may decide that operation of the emissions unit during periods where

there is no emissions correlation is a violation of the PAL. The PAL permit must include enforceable requirements

if either of these alternatives to the required correlation for parameter monitoring are used.

Emission factors may be used for demonstrating compliance with PALs, so long as the factors are adjusted for the degree of uncertainty or limitations in

the factors ’development. In ascertaining

whether an emission factor is appropriate, you and your reviewing authority should consider the

contribution of emissions from the emissions unit in relation to the PAL, the size of the emissions unit, and the margin of compliance of the emissions unit. In addition, if the emission factor approach is taken, the emissions unit shall operate within the designated range of use for the emission factor.

The owner or operator of a significant

emissions unit that relies on an

emission factor to calculate PAL


### 80213 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

pollutant emissions shall conduct validation testing using other monitoring approaches (if technically practicable) to determine a site-specific
emission factor within 6 months of PAL permit issuance, unless the reviewing authority determines that testing is not required. For example, should you demonstrate to your reviewing authority ’ s satisfaction that the use of your emission factor would yield a result that is protective of the environment, then you may not need to conduct site-specific performance testing. An emissions unit is considered significant if the emissions unit has the potential to emit the PAL pollutant in amounts greater than those listed in § 51.165(a)(1)(x).

In the event you choose to use one or more emission factors for your significant or small emissions units, you bear the burden to prove to the reviewing authority that the emission factors are appropriate and adjusted for any uncertainty in the factors ’ development. By way of example, the
sulfur dioxide emission factor for 2- stroke, lean-burn, natural gas fired reciprocating engines, 5.88 * 10 -4 pounds of sulfur dioxide emitted per million British Thermal Unit (mmBTU) of natural gas combusted, as published

in our Compilation of Air Pollutant

Emission Factors AP

–42, Fifth Edition Volume 1: Stationary Point and Area
Sources, which is found on our Internet
Web site at http://www.epa.gov/ttn/ chief/ap42/index.html, represents an appropriate emission factor.

The reviewing authority may approve other types of monitoring systems that quantify emissions to demonstrate compliance with PALs. Other types of monitoring that may be approved include a Gas Chromatographic (GC) or
a Fourier Transform Infrared Spectroscopy (FTIR) CEMS that relies on extractive techniques, coupled with a CERMS as well as an ADHS, to measure and verify the VOC concentration, volumetric gas flow (if applicable), and VOC mass emissions (in lb/hr) discharged from stacks (that is, non-fugitive emissions) to the atmosphere. For processes, work practices, or emissions sources subject to VOC or organic hazardous air pollutant (HAP) regulations, these types of monitoring systems may be used for each emissions unit emitting VOC.

d. What information about your monitoring system must be submitted to your reviewing authority for approval?

You need to propose a monitoring system as part of your PAL permit application submission to your reviewing authority. The monitoring system proposed must accurately determine plantwide emissions. In your permit application, you must describe how you will collect and transform data from each emissions unit subject to a PAL permit, so that the emissions from each unit can be quantified as a 12- month rolling total. In addition, you need to demonstrate how you can be
assured the data are and remain accurate by describing how you will install, operate, certify, test, calibrate, and maintain the performance of your monitoring system(s) on each emissions unit that will be subject to the PAL.

You will also need to provide calculations for the maximum potential emissions without considering
enforceable emission limitations or operational restrictions for each unit in order to determine emissions during periods when the monitoring system is not in operation or fails to provide data. In lieu of the permit requiring maximum potential emissions during periods when there is no monitoring data, you may propose another alternate monitoring approach as a backup. This backup monitoring, however, must still meet the minimum requirements for the monitoring approaches prescribed in the regulation.

Note that each monitoring system with applicable requirements contained in appendix B of 40 CFR part 60 must be installed, operated, and maintained according to the applicable Performance Specification of 40 CFR part 60, appendix B.

For purposes of determining emissions from an emissions unit, a unit is considered operational not only during periods of normal operation, but also during periods of startup, shutdown, maintenance, and
malfunction ’ even if compliance with a
non-PAL emission limitation is excused during these latter periods. Your reviewing authority may approve different monitoring for various operating conditions (for example, startup, shutdown, low load, or high
load conditions as demonstrated through multiple performance tests) for each emissions unit. You must, however, use one of the accepted monitoring approaches, including alternative monitoring approved by the reviewing authority, for these periods or calculate the emissions during these periods by assuming the highest PTE without considering enforceable emission limitations or operational

restrictions.

In addition, the rule permits the reviewing authority to use the reasonably estimated highest potential emissions for periods when your emissions unit operates outside its parameter range(s) established in the performance test, unless another method is specified in the permit, and include those emissions in the 12- month rolling total in order to demonstrate compliance with the PAL. Alternatively, the reviewing authority may decide that operation outside the range(s) established in the performance

test is a violation of the PAL. The reviewing authority must decide how to

handle emissions when the unit is operating outside the ranges established in the performance tests prior to the issuance of the PAL permit and must include appropriate enforceable conditions in the PAL permit.

For parameter monitoring to be approved by your reviewing authority, your proposed monitoring system must measure the operational parametervalue(s) within the established sitespecific range(s) of operating parameter

values demonstrated in recent performance testing. The monitoring system must then record the associated PAL pollutant mass emissions rate for that period based on the correlations

demonstrated with the current test data.

e. What Recordkeeping Requirements

Must Your Permit Contain To Demonstrate Compliance With Your

PAL?

Your permit must require you to maintain records of your monitoring and testing data that support any compliance certifications, reports, or other compliance demonstrations. This information should contain, but is not necessarily limited to, the following

data.

• The date, place (specific location), and time that testing or measuring

occurs

• The date(s) sample analysis or analyses occur

• The entity that performs the analysis or analyses

• The analytical techniques or

methods used

• The results of the analyses

• Each emissions unit ’ s operating conditions during the testing or monitoring

• A summary of total monthly

emissions for each emissions unit at the major stationary source for each

calendar month

• A copy of any report submitted to the reviewing authority

• A list of the allowable emissions and the date operation began for any new emissions units added to the major stationary source.

You must also record all periods of deviation, including the date and time that a deviation started and stopped and whether the deviation occurred during a period of startup, shutdown, or

malfunction.


### 80214 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

You must retain records of all required testing and monitoring data, as well as supporting information, for at least 5 years from the date of the monitoring sample, measurement, report, or application. Supporting

information includes all calibration and maintenance records and all original strip-chart recordings for continuous monitoring instrumentation, and copies of all required reports. Instead of paper records, you may maintain records on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche, provided that the use of

such alternative media allows for expeditious inspection and review and

does not conflict with other recordkeeping requirements.

You must also retain a copy of the following records for the duration of the PAL effective period plus 5 years: (1) A copy of the PAL permit application and any applications for revisions to the PAL; and (2) each annual certification of compliance pursuant to title V and the data relied on in certifying the compliance.

f. What reporting requirements for your PAL must your permit contain?

You must provide semi-annual monitoring and prompt deviation reports. The terms and conditions of an approved PAL become title V applicable requirements that will be placed in your title V permit. Therefore, the reports required under title V may meet the requirements of the PAL rule, so long as the minimum reporting requirements listed in the regulations are met. You

must submit a semi-annual emissions report to the reviewing authority within 30 days after the end of each reporting period. The reviewing authority will use this report to determine compliance with the conditions of the PAL, including the PAL level.

The compliance period for an actuals

PAL emissions level is a consecutive 12- month period, rolled monthly. Block 12- month periods are not allowed (for example, Jan.-Dec. of each year). The emissions report must include the total

baseline actual emissions of the PAL pollutant for the previous 12 months and compare the previous 12 months ’
total emissions with the PAL level to determine compliance. Additionally, the emissions report must identify: the site; the owner or operator; the applicable PAL; the monitored parameters, the method of calculation with appropriate formulas, any emission factors used, the capture and control

efficiencies used and the calculated emissions; total monthly emissions (tons) and the equations used to compute this value for each of the 12

months before submission of the emissions report (or for all prior months

if the PAL has not been effective for 1 year); total annual emissions (tpy); a PAL compliance statement; a list of any

emissions units added or modified to the site; and information concerning shutdown of any monitoring system, including the method that was used to measure emissions during that period. Finally, in accordance with title V requirements, your permit will require all reports to be certified by your responsible official as true, accurate, and complete.

10. What is the process for incorporating conditions of the PAL into your title V operating permit?

As discussed previously, the reviewing authority establishes a PAL in a federally enforceable permit using its minor NSR construction permit process or the major NSR permit construction process and eventually rolling these requirements into its title V operating permit. The reviewing authorities ’rules for establishing or renewing PALs must include a public participation process prior to permit approval of the PAL. The process must be consistent with the requirements at § 51.161 and include a minimum 30-day period for public notice and opportunity for public comment on the proposed permit. PALs established through the major NSR process are subject to major NSR public participation requirements. When adding a new emissions unit under an established PAL, you must comply with the reviewing authority ’ s minor NSR permit requirements for public notice, review, and comment.

The process for incorporating the

conditions of a PAL into the title V operating permit depends on whether the initial title V permit has already

been issued for the source. If the initial title V permit has not been issued, a PAL created in a minor or major NSR permit would be incorporated during initial issuance of the title V permit. If the initial title V permit has already been issued, the PAL would be incorporated through the appropriate part 70 modification procedures. As discussed later in this preamble, we suggest that you request that your reviewing authority renew your title V permit concurrently with issuance of your PAL in order to align the two processes together and decrease the administrative burden on you and your reviewing authority.

Once a PAL is established, a change at a facility is exempt from major NSR and netting calculations, but could require a title V permit modification, as could any other change. Whether a title V permit modification would be required, and which permit modification process would be used, is governed by the current part 70 rule as implemented by the reviewing authority.

11. What is an example of an actuals

PAL?

The following example is based upon a hypothetical source that wishes to

obtain an actuals PAL under the final regulations adopted today.

A manufacturing plant (a major stationary source) located in a serious

ozone nonattainment area seeks an actuals PAL for VOC in January 2002. The major source threshold for VOC in

a serious ozone nonattainment area is 50 tpy and the significant level for VOC modifications is 25 tpy. The plant has

5 emissions units with a total PTE of 640 tpy of VOC. The PTE for VOC for each of the emissions units at the plant is as follows: (1) Unit A is 335 tpy; (2) unit B is 20 tpy; (3) Unit C is 125 tpy; (4) unit D is 60 tpy; and (5) unit E is 100 tpy. Units A, B, C, and D are existing emissions units with more than 2 years of operating history. Unit E has been in operation for only a year. Unit D was dismantled in year 2000 and is considered permanently shutdown.

For units A, B, C, and D, the source has selected July 1, 1996 to June 30, 1998 (a consecutive 24-month period) to

determine baseline actual emissions. Unit A is subject to a RACT requirement that became effective in year 2000. The

baseline actual emissions for each emissions unit during this period are as follows: unit A, 140 tpy (including RACT adjustment); unit B, 10 tpy; unit C, 90 tpy; and unit D, 20 tpy.

The actuals PAL level for VOC is = 260

+ 100 ¥ 20 + 25 = 365 tpy

WHERE

• 260 tpy = the sum of the baseline

actual emissions for emissions units A

– D (with 2 or more years of operation)

• 100 tpy = the allowable emissions (PTE) of unit E, which was constructed after the 24-month period;

• 20 tpy = baseline actual emissions of unit D, which is permanently shut down since the 24-month period; and

• 25 tpy = significant level for VOC in

a serious nonattainment area.

D. Rationale for Today’s Final Action on

Actuals PALs

We received voluminous comments and suggestions in response to the 1996 NSR proposal, the 1998 NOA, and numerous meetings with interested

stakeholders. This section addresses the more significant comments we received.

For a more detailed discussion of the comments received and our responses,


### 80215 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

please refer to the Technical Support

Document included in the docket for this rulemaking. The comment areas addressed in this section include: (1) How do the PAL regulations meet the major NSR requirements of the Act? (2) Are PALs consistent with the concept of

‘‘ contemporaneity ’ ? (3) Are PALs permissible in serious and severe nonattainment areas? (4) Is it appropriate for a PAL to be based on actual emissions? (5) How should actual emissions be determined in setting the PAL level? (6) Should emissions from

shut down or dismantled units be excluded from a PAL? (7) Should a PAL include a margin for growth? (8) Should PALs be required to expire? (9) Should we require PALs to be adjusted at the time of PAL renewal? (10) Should

certain new emissions units that are added under a PAL be required to meet some level of emissions control? (11) Under what circumstances should you be allowed to increase your PAL and how should we apply the major NSR requirements to that increase? (12) What monitoring requirements are necessary to ensure the enforceability of PALs as a practical matter? (13) Is EPA adopting an approach that allows area-wide PALs? and (14) When should modeling or other types of ambient impact assessments be required for changes occurring under a PAL?

1. How do the PAL regulations meet the major NSR requirements of the Act?

The PAL regulations adopted today meet the requirements of the CAA and are consistent with the Congressional purpose and intent underlying NSR. We believe the PAL regulations constitute a reasonable interpretation of the Act ’ s definition of ‘‘ modification ’’and are permissible under current law.

The definition of ‘‘ modification ’’set forth in section 111(a)(4) of the Act is fundamental to determining major NSR applicability. Pursuant to the Act, the

term modification means ‘‘ any physical change in or change in the method of operation of a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. ’’The statute, however, does not prescribe the methodology for establishing a stationary source ’ s emissions baseline

from which emissions increases are

measured. When a statute is silent or ambiguous with respect to specific issues, the relevant inquiry is whether the agency ’ s interpretation of the statutory provisions is permissible. Chevron U.S.A., Inc. v. NRDC, Inc., 467 U.S. 837, 865 (1984). Accordingly, EPA is exercising its discretion to develop reasonable

alternatives to determine NSR applicability that are consistent with the statutory provisions and Congressional intent underlying the NSR requirements. We believe that the PAL regulations adopted today represent a permissible construction of the Act.

2. Are PALs consistent with the concept

of ‘‘ contemporaneity ’’ ?

In the 1998 NOA, we solicited

comment on whether and how a program that recognizes PALs as an alternate method for determining NSR applicability should address a particular legal concern: the need to have some

‘‘ contemporaneity ’’between an emissions increase and any decrease relied upon to net the increase out of

review. As we discussed in the 1998 notice, the current regulations specify that, to be creditable, emissions

increases and decreases must have

occurred within a ‘‘ contemporaneous ’’ period. Our current regulations governing SIP-approved programs do not specify a precise time frame. However, the Federal PSD rules generally only credit those emissions

increases and decreases that occur within the 5 years preceding a given change. We established these regulatory requirements after the court ’ s decision

in Alabama Power, in which the court interpreted the Act as requiring plantwide bubbling in the PSD program,

but stated that ‘‘ any offset changes claimed by industry must be substantially contemporaneous. ’’636 F.2d 402. In the 1998 notice, we sought comment on whether a PAL program that never required PALs to be periodically updated to reflect current

emissions at the source would allow

sources to make emissions reductions and hold them indefinitely, only to use

them several decades later to offset new increases, and whether such a system would contravene the contemporaneity principle the court announced.

Many commenters, including several regulatory agencies, maintain that PALs

are consistent with the NSR requirements under the Act. These commenters contend that the court gave

EPA the discretion to define contemporaneity. See 636 F.2d 402 ( ‘‘ The Agency has discretion, within reason, to define which changes are substantially contemporaneous. ’’ ). Others contend that changes made under a PAL are not subject to the

Alabama Power ‘‘ contemporaneity ’’ requirement because a change made

under the PAL is either excluded from NSR or alternatively does not exceed the applicable NSR significance threshold. Therefore, they contend that netting is not implicated by such changes. On the other hand, a few commenters assert that PALs conflict with the purpose of

the Act.

We believe that the concept of contemporaneity, as articulated in

Alabama Power and as set forth in the regulations governing the major NSR program, does not apply to PALs. The PAL program differs in certain important respects from our current regulations and from the 1978 regulations at issue in Alabama Power.

The Alabama Power court was not presented with the PAL approach for determining whether there was an

increase in emissions and did not consider whether the principles it set forth in its opinion would apply to such an approach.

Under the 1978 PSD regulations (43 FR 26380), a source was subject to BACT review only if ‘‘ no net increase in emissions of an applicable pollutant would occur at the source, taking into

account all emissions increases and

decreases at the source which would accompany the modification. ’’43 FR
26385. The test for whether a ‘‘ major
modification ’’had occurred required the

source to sum all accumulated increases in potential emissions that had occurred

at the source since issuance of the regulations, or since issuance of the last construction permit, whichever was

more recent. Reductions achieved

elsewhere in the source could not be

taken into account.

In Alabama Power, the D.C. Circuit held that EPA was correct in excluding from BACT review any changes that did

not result in a net increase of a pollutant. 636 F.2d 401. It concluded, however, that EPA had incorrectly excluded contemporaneous decreases

from the calculation of whether a

‘‘ major modification ’’had occurred. Id.

at 402

–03.

The current regulations take contemporaneous decreases into account for all PSD review purposes. Under the current regulations, you look initially at the emissions unit undergoing the change and determine whether there will be a significant

increase at that unit. If there is no significant increase at the unit, the inquiry ends there. While we continue to believe that this is a permissible approach, one drawback to this approach is that it allows a series of small, unrelated emissions increases to occur, which is discussed elsewhere in this preamble. If there will be a significant increase at the unit, then you expand the inquiry to other units at the

source. You take into account contemporaneous increases and


### 80216 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

31 Eastern Research Group Inc. report on

‘‘ Business Cycles in Major Emitting Source

Industries ’’dated September 25, 1997. decreases at the source in determining

whether there will be an increase for the source as a whole. Thus, you must

calculate increases and decreases at

individual units in order to arrive at a net figure for the entire source.

In contrast, under today ’ s PAL regulations, the inquiry begins and ends with the source. Your PAL represents

source-wide baseline actual emissions. As such, it is the reference point for calculating increases in baseline actual emissions. If your source ’ s emissions will equal or exceed the PAL, then there will be an emissions increase at your

source. There is no need to calculate

increases and decreases at individual

units.

Today ’ s PAL regulations constitute a reasonable, though not the only, approach to determining whether there is an emissions increase at your source. While we believe that the principle of contemporaneity continues to be important for purposes of major NSR netting calculations, we do not believe that it is a necessary concept for purposes of PALs. This is because if your source has a PAL, you have accepted a different means of calculating an emissions increase for the PAL pollutant. The only relevant question is whether your source has

reached or exceeded the PAL level.

Even though PALs are a new approach, they do not alter the fundamental question, which is whether

there will be an increase in emissions from your source. For actuals PALs, we

consider whether there will be an

increase in baseline actual emissions.

Because the PAL serves as the baseline for measuring an increase, we have taken steps to ensure that the PAL is reasonably representative of baseline actual emissions. In taking these steps,

we have also ensured that actuals PALs as finalized today are consistent with the concept of contemporaneity, to the extent such a concept has any application in this context. One way of viewing a PAL is to focus on the

increases and decreases at individual emissions units that, taken together, result in the net emissions from your source as a whole. As long as the decreases that have occurred during the

term of the PAL are sufficient to offset any increase that occurs, total emissions for your source will remain below the PAL, and your source will not experience a ‘‘ significant net emissions

increase. ’’Viewed from this perspective,

the term of the PAL constitutes the

‘‘ contemporaneous ’’period. We believe that 10 years is a reasonable contemporaneous period for PALs for the following two reasons. First, we believe that a 10-year period is practical and reasonable both for you and for the reviewing authority. While a logical stopping point may seem to be 5 years in line with the title V permit period, setting a PAL can be a complex and time consuming process, so a 5-year period

would be too short and hence not beneficial either to you or to the reviewing authority. Second, a study conducted by Eastern Research Group,

Inc. 31 supported a 10-year look back to ensure that the normal business cycle would be captured generally for any industry.

In addition, we believe that the PAL renewal provisions ensure that each 10- year term represents a distinct

‘‘ contemporaneous ’’period. The renewal process is designed to prevent

decreases that occurred outside of the current 10-year PAL term from being used to offset increases during that term. At renewal, the reviewing authority

must consider whether decreases have occurred at your source because of compliance with newly applicable requirements. Thus, for example, if the compliance date for a new RACT requirement occurred during the initial term of the PAL, and the reviewing authority has not already adjusted the

PAL downward to account for that requirement, it must do so at renewal. More generally, the reviewing authority is required to evaluate baseline actual emissions and provide a written rationale for public comment if it determines that an adjustment to the PAL is warranted. As part of this process, the reviewing authority must adjust the PAL downward if your

source ’ s current PTE is below the PAL level. We believe that this adjustment is important for air quality planning purposes. Additionally, the reviewing authority may renew the PAL at the same level if your source ’ s baseline actual emissions plus the significant level are equal to or greater than 80 percent of the PAL level without

consideration of other factors. We believe that this level is reasonably representative of the source ’ s baseline actual emissions. If your source ’ s baseline actual emissions plus the significant level are less than 80 percent of the PAL level, the reviewing authority may set the PAL at a level that it determines to be more representative

of the source ’ s baseline actual emissions, or that it determines to be appropriate considering air quality needs, advances in control technology, anticipated economic growth in the area, desire to reward or encourage the source ’ s voluntary emissions reductions, or other factors as specifically identified by the reviewing authority in its written rationale. We recognize that fluctuations in baseline

actual emissions will occur at most sources as part of the normal business cycle. We also recognize that requiring the reviewing authority to adjust the PAL downward if your source ’ s baseline actual emissions do not equal 100 percent of the PAL level could create an incentive for you to maximize your baseline actual emissions. In addition, most sources do not emit at a level just

below the maximum allowable level but rather build in a margin to prevent accidental exceedances. However, the PAL should be reasonably representative of baseline actual

emissions so that it can continue to serve as the baseline for calculating an

emissions increase. We have balanced these competing concerns in adopting a requirement, subject to the provisions noted below, to provide discretion to the reviewing authority to adjust the

PAL level if baseline actual emissions plus the significant level do not equal at least 80 percent of the PAL level.

To maintain flexibility, today ’ s actuals PAL regulations allow the reviewing authority to determine representativeness on a case-by-case basis. If you believe that the new PAL level that the reviewing authority proposes for your source is not representative of your source ’ s baseline actual emissions, you may propose a different level. In addition, any person may propose a different level as being more representative of your source ’ s baseline actual emissions. The reviewing authority may approve a higher or lower level if it determines that it is reasonably representative of

your source ’ s baseline actual emissions.

For example, assume that your source was designed to burn either fuel oil or natural gas, and that your source ’ s permit allowed the use of either fuel. During the initial term of the PAL, you used only natural gas at the source and your source-wide emissions were consistently less than 80 percent of the PAL level. However, due to shifting market conditions, you expected to use fuel oil for a period beginning after PAL renewal. Under these circumstances, the reviewing authority could reasonably determine that a higher level would be more representative of your source ’ s baseline actual emissions.

Similarly, your source might be designed to manufacture several different products, and your permit might allow you to switch from one product to another. During the initial term of the PAL, you might produce a


### 80217 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

product associated with low emissions, resulting in source-wide emissions that were consistently less than 80 percent of the PAL level. However, you might be planning to produce a product that

would cause the source to emit at a higher level following PAL renewal. This is another example of a circumstance in which the reviewing authority could reasonably determine that a higher level was more representative of your source ’ s baseline

actual emissions.

In addition, for SIP planning purposes, the reviewing authority may adjust the PAL level at its discretion based on air quality needs, advances in control technology, anticipated economic growth in the area, or other

relevant factors.

Because of the safeguards described above, we believe that the actuals PAL program as finalized today ensures that the PAL will serve as an appropriate baseline for determining whether there is a significant net ‘‘ increase ’’in overall emissions from the source, and thus whether the source is undergoing a

‘‘ modification. ’’

Moreover, we believe that a PAL approach satisfies Congressional intent to only apply the NSR permit process when industrial changes cause significant net emissions increases to an area and not when changes in plant operations result in no emissions increase from the major stationary

source. See Alabama Power, 636 F.2d

401.

3. Are PALs Permissible in Serious, Severe, and Extreme Ozone

Nonattainment Areas?

In our 1996 proposal, we requested

comment on whether PALs could be implemented in serious and severe

ozone nonattainment areas in a manner
that was consistent with section 182(c)(6) of the Act. Section 182(c)(6) contains special provisions for major stationary sources that increase VOC

emissions in serious or severe ozone
nonattainment areas as a result of a physical change or a change in the method of operation. In some of these areas, the provisions also apply if you

increase NO X emissions. In general, these special provisions change the significant level for VOC emissions in

serious and severe nonattainment areas from 40 tpy to greater than 25 tpy. They also specify that you must go through a major NSR permitting review if you

have a net emissions increase in the aggregate of more than 25 tpy over a period of 5 years.

In addition, we requested comment on whether PALs could be implemented

in extreme ozone nonattainment areas. Section 182(e)(2), which applies in such areas, provides that any physical change or change in the method of operation at

the source that results in ‘‘ any increase ’’ from any discrete operation, unit, or other pollutant-emitting activity at the source, generally must be considered a modification subject to major NSR permit requirements, regardless of any

decreases elsewhere at the source.

A few industry commenters believe

that the ‘‘ accumulation ’’provisions of CAA section 182(c)(6) should make no difference to the acceptability of a PAL

in ‘‘ serious ’’ and ‘‘ severe ’’ozone nonattainment areas. They contend that we have correctly concluded that CAA section 182(c)(6) only applies when net

emissions at the source as a whole

increase above the 25 ton level. Accordingly, any change that triggered CAA section 182(c)(6) would already

have breached the PAL limits. On the other hand, an environmental

commenter states that a PAL in a
serious, severe, or extreme ozone
nonattainment area could be problematic because it could allow for

an increase at an emissions unit in
situations where source-wide emissions

would not exceed the PAL.

We agree with commenters who believe that the PAL approach does not conflict with the provisions of CAA section 182(c)(6). We do not interpret section 182(c)(6) to be a limitation on our ability to authorize PALs in serious

and severe nonattainment areas. This

section directs that when there is an increase meeting certain criteria, it may
not be considered de minimis , but it does not specify the methodology by

which an emissions increase must be calculated. Accordingly, we exercise our discretion in establishing the methodology, and we are doing so today by having the PAL serve as the actuals emissions baseline against which future

emissions increases are measured. Chevron U.S.A., Inc. v. NRDC, Inc., 467 U.S. 837, 865 (1984). If your source ’ s emissions equal or exceed the PAL, it will trigger NSR, whereas maintaining plant emissions below the PAL ensures

that there is no emissions increase. We believe that our interpretation reasonably implements the statutory purpose of the section, given that PAL sources agree to be subject to a plantwide cap that serves as the reference point for determining whether there has been an increase and given that the appropriateness of the PAL level is reviewed at 10-year intervals. Actuals PALs effectively prevent the uncontrolled, unrelated, small, serial emissions increases section 182(c)(6) is designed to address. Because CAA section 182(e)(2) clearly requires consideration of increases at

individual emissions units in extreme
ozone nonattainment areas, PALs are not allowed in such areas, since any increase in emissions from any unit in

those areas constitutes a modification.

4. Is It Appropriate for a PAL to Be

Based on Actual Emissions?

In 1996, we proposed and sought comment on a broad range of alternative approaches for setting PAL emission limitations, including a PAL based on the following: (1) Actual emissions as

defined under the current and then proposed regulations at § 51.166(b)(21)(ii); (2) actual emissions with the addition of an operating margin greater than the applicable significance rate; (3) for new stationary sources, limits established pursuant to a review of the entire facility under PSD; and (4) for nonattainment pollutants (in nonattainment areas), any emissions level completely offset and relied upon in an EPA-approved State attainment demonstration plan. 61 FR 38250, 38256 (July 23, 1996).

We received general support for the PAL concept and for the different approaches we proposed. Some comments express support for a PAL approach based on allowable emissions, and others indicate support for a PAL approach based on actual emissions. Some commenters generally believe that an allowables approach is necessary to ensure increased operating flexibility and capacity utilization. They also assert that an allowables approach would protect air quality management goals, because they claim that air quality planning historically has been based on permitted emissions levels. Other

commenters believe that an actuals approach is preferable because it facilitates more accurate air quality planning and provides a more reliable basis for determining the availability of

offsets.

We have concluded that a major stationary source ’ s compliance with an actuals-based PAL system is a permissible means of assuring that a major stationary source does not have a significant emissions increase. We also conclude that this approach can be implemented in a manner that is consistent with the Act. Thus, in today ’ s action, we are adopting regulations that

authorize States to issue actuals PALs. We plan to address allowables PALs in an upcoming rulemaking.

5. How Should Actual Emissions Be Determined in Setting the PAL Level?

In the 1996 proposal, we requested

comment on whether the definition of


### 80218 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

actual emissions for the purpose of determining the level of the PAL should
be based on the definition of actual emissions in the current major NSR regulations, or whether it should be based on the proposed revisions to the
actual emissions definition contained in that 1996 proposal. The fundamental
difference between these two approaches is that the current NSR regulations would only allow you to look back 5 years to determine the actual emissions (the sum of actual emissions for all emissions units at your major stationary source). The 1996 proposed changes to this definition would allow you to look back 10 years
to determine the actual emissions.

Several commenters prefer a 10-year baseline period for setting PALs based
on actual emissions. A few commenters prefer a 5-year baseline period. One
commenter advocates use of an actual emissions level that is initially based on the previous 2 years but that would
decline over time.

In a separate section of today ’ s final rules, we are finalizing changes to our
definition of baseline actual emissions. Among other changes to the definition, you will be allowed to look back for a period of 10 years to establish the baseline actual emissions (except for EUSGUs). For program consistency and ease of implementation, we believe that the procedure for determining the
baseline actual emissions for establishing your PAL should be the
same as the baseline actual emissions that you will be required to use under the other major NSR program requirements. Accordingly, we are adopting an approach for establishing your actuals PAL that is consistent with

how the baseline actual emissions are

determined for an emissions unit under other requirements of the major NSR

program.

We are, however, including a special

allowance for emissions units that have operated for less than 2 years. Under such circumstances, the emissions unit has not operated long enough to

establish a reliable baseline actual emissions calculation. Therefore, today ’ s rule allows your reviewing authority to consider the allowable

emissions of such emissions units when establishing or renewing the PAL. The

baseline actual emissions of such emissions units would be adjusted to reflect a more representative level of

baseline actual emissions at the time of

the next PAL renewal.

6. Are Emissions From Shut Down or

Dismantled Units Excluded From a

PAL?

We proposed several options to adjust

PAL levels to account for emissions units that are shut down or dismantled before setting a PAL. Several commenters support adjusting the PAL level for permanently shut down or

dismantled units. A few commenters maintain that PAL adjustments are only appropriate for long-term shutdowns. Other commenters oppose allowing adjustments for shutdowns. They

indicate that it would be difficult to implement and that it could penalize sources that were meeting environmental goals.

We agree with commenters that the

baseline actual emissions used in establishing the PAL should exclude

emissions from units that are permanently shut down or dismantled after the 24-month period selected for

establishment of baseline emissions. We believe that excluding such emissions from your PAL level is appropriate for air quality planning purposes. Moreover, the environment has already

seen the benefit of the reduced emissions. We also do not agree with

those commenters who advocate adjusting the PAL only for long-term shutdowns, because it is too difficult to

define and enforce ‘‘ long-term. ’’

As described in section IV.C.2 of this preamble, the PAL level includes

baseline actual emissions from each existing emissions unit and new emissions unit at the source. For any

emissions unit that has been permanently shut down since the 24- month period, its emissions should not be included in calculating the PAL level. Conversely, for an emissions unit that began construction after the 24- month period, the emissions (equal to the potential emissions of that emissions unit) must be included in setting the PAL level.

One shutdown option we considered, but did not adopt, is to exclude emissions from PALs only for units that did not operate at all during the 10-year life of the PAL. Under this option, the PAL would not be adjusted downward if you utilized those emissions from the

shut down or dismantled units elsewhere at your source during the period since the shutdown (for example, by adding new emissions units or capacity, or by increasing capacity utilization at existing emissions units). As we indicated in our proposal, we

believe it would be too difficult to determine whether you have actually

relied on these emissions decreases in undertaking other activities at your source. We did not receive any comments suggesting ways to overcome this identified problem. 7. Does a PAL Include a Reasonable Operating Margin?

In the July 23, 1996 action, we proposed that a PAL for existing sources

be based on source-wide actual emissions, including a reasonable operating margin less than the applicable significant emissions rate. We also requested comment on several other options for establishing a PAL. Several commenters support the option of basing the PAL on source-wide actual emissions plus a reasonable operating margin less than the applicable significance amount. Other commenters believe an operating margin tied to significant levels would be too

restrictive.

Today we are finalizing an option that allows you to include, when setting the initial PAL, an amount that corresponds to the significant level for modifications of the PAL pollutant as specified in the major NSR rules [for example, in the PSD regulations at § 52.21(b)(23)(i)], or as specified in the CAA, whichever is lower. For example, for SO 2 PALs you may add to the PAL baseline level the 40 tpy significant level; for CO PALs you may add 100 tpy to the PAL baseline level. Also, for serious and

severe ozone nonattainment areas the VOC significant level added to the PAL level is 25 tpy. For major sources of

NO X located in serious and severe ozone nonattainment areas, where NO X is regulated as an ozone precursor, you may add to the NO X PAL baseline the

NO X significant level of 25 tpy, and not the 40 tpy NO X significant level specified under PSD. In extreme ozone
nonattainment areas, PALs are not allowed since any increase in emissions

in these areas constitutes a

modification.

While other approaches to providing a reasonable operating margin may be consistent with the CAA, we believe that the approach we are adopting today comports most closely with existing regulatory provisions for major NSR applicability. That is, it assures that the environment sees no significant increases in emissions compared to the baseline actual emissions existing before

the PAL is established.

In our 1998 NOA, we also requested comment on whether we should provide for an operating margin when renewing a PAL. We proposed four possible approaches for maintaining a reasonable operating margin, including an option that would include in the adjusted PAL level an operating cushion equal to 20 percent of the current PAL. In a separate section of the NOA, we also requested


### 80219 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

comment on how PALs should be adjusted for emissions units that have installed good emissions controls.

Many commenters indicate that we must provide for a reasonable operating margin. However, we generally received

unfavorable comments on all the approaches we suggested. Several commenters believe that our suggested approaches do not provide an adequate operating margin. In responding to our request for comment on how to adjust

PALs for emissions units that have installed good emissions controls, many

commenters indicate that it would be inappropriate for EPA to ‘‘ confiscate ’’
such emissions reductions. Such an approach would encourage sources to pollute to maintain higher baseline emissions, and would penalize those sources who would voluntarily reduce

emissions. At least one commenter maintains that both you and the

environment should benefit from these reductions, and thus, you should be allowed to retain a portion of your voluntary emissions reductions.

We agree with some commenters that mandating an adjustment at renewal, based solely on current operations and emissions levels, would discourage the voluntary emissions reductions the PAL is specifically designed to encourage. We agree with commenters that both you and the environment should benefit from your commitment to comply with a PAL. Should you engage in voluntary emissions reductions, we believe you

should be able to retain the accompanying flexibility that encouraged you to make these reductions. At the time of renewal, it may be very difficult for a reviewing authority to distinguish the reason for a decrease in your baseline actual emissions level. It could be because you have aggressively applied emissions controls, or because of a decrease in utilization, a loss of capacity, a desire to maintain a compliance margin, or any of a number of other reasons. Accordingly,

we believe that it would be difficult to advise a reviewing authority to only retain a certain percentage of your

emissions reductions that resulted from applying emissions controls. Therefore, for simplicity, and for what we believe to be a reasonable policy position to encourage you to voluntarily reduce emissions without a fear of a complete loss of operational flexibility, we are allowing your reviewing authority

discretion to renew the PAL at an appropriate level. Hence, your reviewing authority may renew the PAL

at the same level without consideration of other factors, if the baseline actual emissions plus the significant level is equal to or greater than 80 percent of the PAL level. If not, today ’ s rules also allow your reviewing authority to renew

the PAL at a different level if it

determines that level is more representative of baseline actual
emissions. See section II.D.9, ‘‘ Should we require PALs to be adjusted at the time of PAL renewal, ’’for more

information on our rationale for allowing this discretion.

8. Are PALs Required to Expire?

In our 1998 NOA, we announced that we were considering, and requested comment on, an approach that would require PALs to expire after 10 years unless you choose to renew the PAL. We proposed that the PAL term would be 10 years. Several commenters agree with our suggested time frame of 10 years for the term of a PAL. Others support a 5-year period, which would fit with the title V permit review period. Some commenters support a period longer than 10 years.

Today, we are finalizing rules that require a PAL to be effective for a period of 10 years. We believe that a fixed-term PAL provides you with an appropriate time of regulatory certainty and allows a sufficient period of time for planning long-term capital improvements.

We also agree with those commenters who think it is beneficial to align the PAL renewal process with the title V permitting process for your major stationary source. Similar to a PAL permit process, the title V permit process provides the public with a comprehensive review of your source. We believe that aligning the PAL permit with the title V process will allow you and your reviewing authority to consolidate the administrative process for the two permitting actions. It also provides the public with a better understanding of your emissions

characteristics relative to the surrounding community. However, we do not believe that requiring PALS to be reviewed every 5 years, consistent with the title V renewal period, provides industry with a sufficient period of regulatory certainty. We also believe

that while the overall administrative burden for you and the reviewing authority is reduced if you are complying with a PAL, the establishment of a PAL requires an

initial commitment of substantial

resources. Given this initial resource investment, we do not believe that a 5- year fixed term for a PAL provides you or your reviewing authority with an adequate incentive to participate in the PAL system. Thus, in an effort to balance the need for regulatory certainty, the administrative burden, and a desire to align the PAL renewal with the title V permit renewal, we believe a fixed term of 10 years, the equivalent of two title V effective periods (10 years), is most appropriate. You may elect to renew your PAL after 10 years, for a subsequent 10-year period, rather than allow the PAL to expire.

In order to align the PAL renewal process with the title V permitting process, we suggest that you request that the reviewing authorities renew title V permits concurrent with issuance of the initial PAL permit, regardless of how many years are actually left on your title V permit.

9. Are PALs Required To Be Adjusted at

the Time of PAL Renewal?

In 1996, we requested comment on

‘‘ why, how, and when a PAL should be lowered or increased without being subject to major NSR. ’’In 1998, we announced that we were considering an option that required PALs to be renewed

to reflect new current baseline actual emissions. We were also considering requiring a PAL to be adjusted for unused capacity. Under this approach, we would adjust a PAL downward when an emissions unit operates below the capacity level that was used to establish the PAL. In our 1998 NOA, we expressed three reasons why it might be appropriate to require PALs to be periodically adjusted. First, weexpressed concern that the allowable-toallowable applicability system of the PAL would allow you to indefinitely retain the right to pollute at an historical level of actual emissions. Second, we were concerned that a PAL may allow you to retain unused emissions credits

that would otherwise be available for economic growth in the area. And third, we were concerned that a PAL may

interfere with a State ’ s ability to plan for attainment if your actual emissions to the atmosphere are lower during a SIP planning year than in a subsequent year.

Some commenters generally oppose any periodic reviewing or adjustment of a PAL. They believe that such an approach would limit operational flexibility, discourage efficiency improvements, and create disincentives for voluntary reductions. However, other commenters generally support an approach that would require a periodic adjustment to PALs.

We continue to have concerns with an approach that would allow a PAL to be renewed without any evaluation of the appropriateness of the current PAL level. We believe such an approach would be contrary to the Act, and contrary to the court ’ s decision in

WEPCO v. Reilly, 893 F.2d 901, 908 (7th Circ. 1990). In WEPCO, the court


### 80220 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

determined that one statutory purpose of the NSR requirements is ‘‘ to stimulate the advancement of pollution control technology, ’’and that ‘‘ allowing increased production (and pollution) through the extensive replacement of deteriorated generating system ’’without triggering NSR review would create

‘‘ vistas of indefinite immunity from the provisions of * * * PSD. ’’

We believe today ’ s rules avoid this inappropriate outcome, by requiring the reviewing authority to evaluate your

baseline actual emissions at the time of PAL permit renewal.

Although we believe that a periodic review of the level of the PAL may be necessary, and that this may result in an adjustment in your PAL to a level that is representative of your baseline actual emissions, we do not believe that we should mandate an adjustment to the PAL based on only one prescribed methodology. Such an approach could lead to inappropriate results, as discussed below. Instead, we believe that our concerns can be appropriately addressed by providing the States the authority to adjust the PAL based on what is representative of your baseline

actual emissions.

We believe that some discretion in determining what is representative of actual emissions is appropriate, based in part on our experience with the pilot projects previously mentioned. In one instance, a participant voluntarily agreed to reduce its actual emissions by 54 percent in exchange for obtaining a source-wide emissions cap. After agreeing to this emissions reduction, the participant further reduced emissions by increasing capture efficiency and incorporating pollution prevention strategies into its operations. Unexpectedly, the participant also

suffered an unusual economic downturn

that caused a decrease in the rate of production and a corresponding

decrease in actual emissions. At the

time of renewal of the source-wide emissions cap, the participant ’ s actual emissions were 10 percent of its actual emissions before committing to the emissions cap. The participant chose not to renew its emissions caps, because renewal required an automatic adjustment to its current actual emissions level. Clearly, such a result

contravenes the mutual benefits operating under a PAL provides, and discourages you from undertaking voluntary reductions. Accordingly, although today ’ s final rules require the reviewing authority to consider the need for adjusting the PAL when your current baseline actual emissions plus the significant level are less than 80 percent of your PAL level, it also provides the reviewing authority discretion to consider a variety of factors in determining whether the PAL should be adjusted.

We are also providing your reviewing authority discretion to take into account
measures necessary to prevent a violation of a NAAQS or PSD increment, and to prevent an adverse impact on an AQRV in a Federal Class I area. For example, although we remain concerned that a PAL may allow you to

retain unused emissions credits that

would otherwise be available for economic growth in your area, we believe that managing an area ’ s economic growth is the primary responsibility of the State. As such, the State, through your reviewing authority, should have discretion to manage the growth increment for your area. If your State wishes to encourage economic growth, then it may, at its discretion, reduce your PAL for that reason. Conversely, it may decide that encouraging economic growth is not a priority for the area and concurrently

find no other concerns that warrant a downward adjustment in your PAL.

After further reflection, we also believe that it is inappropriate for us to mandate in all cases a prescribed methodology for adjusting PALs based on our concern that a PAL system may

interfere with a State ’ s ability to plan for

attainment. We believe that the concern regarding planning for attainment is not unique to a PAL system. Most importantly, nothing in this rule

reduces the State ’ s discretion in developing plans to attain and maintain NAAQS. Under our major NSR applicability system, you could increase your emissions over your historical actual emissions by increasing utilization or hours of operation. If this occurs, there may be a discrepancy

between the amount the State carries in the emissions inventory and the amount that you emit to the atmosphere. States should be cognizant of these issues and take appropriate measures in their SIP planning procedures to assure that emissions from any major stationary source, including a PAL participant, are properly characterized in the emissions inventory.

And finally, we agree with industry

commenters that if we were to mandate an adjustment because your baseline actual emissions did not equal 100 percent of the PAL level, it would encourage you to increase production and emissions, and such an outcome would be counterproductive. We have accordingly provided your reviewing authority the ability to add a reasonable operating margin to your baseline actual

emissions at the time of renewal. This operating margin was discussed previously in section II.D.7 above

—

‘‘ Should a PAL include a reasonable operating margin? ’’

10. Are Certain New Emissions Units That Are Added Under a PAL Required

To Meet Some Level of Emissions

Control?

We solicited comments on whether we should require you to control

emissions from new emissions units

that are added under an established

PAL. Several commenters believe that BACT or LAER should not be required

for these emissions units. A few commenters favor adding a requirement that BACT or LAER be required on new

emissions units.

We believe that it is unnecessary to mandate a specific control level on new emissions units that you add under an established PAL. After reviewing the performance of a limited number of facilities that are participating in PAL pilot projects, we have concluded that

these facilities ’desire to maintain a large degree of operational flexibility under a PAL system has encouragedthem to voluntarily install state-of-theart controls on new emissions units. (See footnote 26 regarding our study,

‘‘ Evaluation of the Implementation Experience with Innovative Air

Permits. ’’ ) We anticipate similar results as we extend the PAL program more broadly. Alternatively, we believe that you will add emissions controls to existing emissions units if this is a more cost effective approach to controlling your emissions. This is precisely the type of flexibility you should have for managing your total source-wide emissions under a PAL system. Furthermore, this cost effective approach was contemplated and supported by the statements of the court

in Alabama Power. The court concluded that you should be allowed to add new

emissions units if the new emissions

from this unit could be ‘‘ set-off against

decreases ’’from other emissions units at the major stationary source. Accordingly, we do not believe that it is necessary to mandate the installation of

emissions controls on new emissions units if you are able to continue to comply with your PAL even after installing the new emissions unit. If our projections on this matter prove to be incorrect in practice, we will consider revising our regulations in the future to require a specific control level on new and/or existing emissions units.


### 80221 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

11. Under What Circumstances Are You

Allowed To Increase Your PAL and How Are the Major NSR Requirements Applied To That Increase?

We proposed that whenever a PAL is

increased due to the addition of a new unit, or due to a physical or operational change to an existing emissions unit, the

units associated with the increase

would be reviewed for current BACT or current LAER, air quality impacts modeling, and emissions offsets, if applicable. We noted that it may be difficult for a reviewing authority to

determine which emissions units are associated with a physical change or change in method of operation when the

emissions increase is the result of a source-wide production increase. We requested comment on five possible ways to apply the major NSR requirements when emissions increases are not directly associated with a particular change.

Commenters offered various suggestions for addressing emissions

increases above the PAL. Several commenters believe that major NSR should only be applied to the emissions unit primarily responsible for the increase. Among the various commenters, there are a few supporters for each one of the options we proposed. In addition, one commenter suggests

that we add de minimis increase levels; another suggests that we require offsets for each increase. Several industry

commenters believe that we should not apply major NSR when an increase above the PAL is solely due to a production increase. One commenter believes all increases should be subject

to BACT.

After considering the comments received, we agree with the commenters who believe that major NSR should only be applied to the emissions units (either new or modifications of existing units) primarily causing the increase. Accordingly, in the final regulations, we are confirming our proposed requirement that only those emissions units that are part of a PAL major modification would be subject to major

NSR.

As discussed earlier, we believe that a PAL provides you with an incentive to control existing and new emissions units to maximize your operational flexibility under your PAL. We also recognize that there may be valid economic reasons for requesting an upward adjustment in a PAL. We are, however, concerned that if there were no restrictions on your ability to request a PAL increase, you would not have an

incentive to control emissions. Therefore, under today ’ s final rules, before the reviewing authority may approve a mid-term increase in your PAL, you must demonstrate that you are

unable to maintain emissions below your current PAL even with a good faith effort to control emissions from existing

emissions units. To make this demonstration, you must show that even if BACT equivalent control (adjusted for a current BACT level of

control unless the emissions units are currently subject to a BACT or LAER requirement that has been determined within the preceding 10 years, in which

case the assumed control level shall be equal to the emissions unit ’ s existing BACT or LAER control level) were to be applied to all of your significant and major emissions units, the resulting emissions level will exceed your current

PAL when combined with the emissions from both your small emissions units and your new emissions unit ’ s allowable emissions.

12. What Compliance Monitoring, Reporting, Recordkeeping, and Testing (MRRT) Requirements Are Necessary to Ensure the Enforceability of PALs as a

Practical Matter?

The MRRT requirements for PALs are

addressed below. Numerous commenters, generally State agencies and environmental groups, state that adequate monitoring, reporting, and recordkeeping requirements would be necessary to ensure that the PAL limits

were enforceable. Some commenters hold that the monitoring, recordkeeping, and reporting provisions would be too

burdensome and restrictive. Some

believe that PALs would not be viable because of these requirements.

Several commenters request that we clarify the monitoring that is necessary to show compliance with a PAL, especially in relation to the CAM and title V programs. Several commenters prefer that the monitoring requirements be flexible and simple. These commenters urge us not to use CAM, require CEMS, or establish stringent protocols. A few commenters prefer that

we not define what would be enforceable as a practical matter for PAL

limits. Others insisted that the PAL limits must be federally enforceable.

We believe that the PAL must assure

that the source maintains emissions below the PAL level to assure that major NSR does not apply. Therefore, we agree

with the commenters who stated that adequate data collection requirements through means such as monitoring, reporting, and recordkeeping requirements are necessary to ensure
that the PAL limits are enforceable as a practical matter. In fact, we find that not only monitoring, recordkeeping, and reporting requirements, but also emissions testing requirements, for emissions units subject to a PAL differ from other MRRT in one important aspect: actual unit emissions must be measured to provide a 12-month rolling total, and compared against a limit. Currently, many emissions units are required only to have MRRT suitable for initial or spot checks on emissions
concentrations, not emissions quantification. Even emissions units

whose MRRT meets the title V requirements in §§ 70.6(a)(3)(i)(B) or 70.6(c)(1), including those imposed by part 64 (the CAM rule), may need to be upgraded when those units are proposed to become subject to a PAL, because the approved title V MRRT may not be able to count emissions against a cap. While we believe you can obtain data for emissions quantification best through the use of CEMS or PEMS, in today ’ s final rule we are allowing you to propose other types of emissions monitoring quantification systems, depending upon such factors as the size category of the emissions unit and its margin of compliance.

13. Is EPA Adopting an Approach That

Allows Area-Wide PALs?

In 1996, we proposed an option thatwould allow a State to adopt an areawide PAL approach. Under such an approach, all major stationary sources within a given geographic area would have a PAL. Our 1996 proposal

contained little detail on how this would be implemented.

While a few commenters support area-wide PALs, many more oppose them. State agency commenters generally believe they would need time to develop PALs consistent with the approaches provided in the final NSR rule, as well as to develop data management and compliance assurance approaches that would accommodate the PAL approach. Thus, adding the

area-wide PAL at the same time as the source-specific PAL may create several administrative headaches. Industry

commenters maintain that area-wide

PALs would ratchet down emissions and reduce flexibility.

We agree with the many commenters who opposed an area-wide PAL system, believing that the approach would be complex and resource and time intensive. We also perceived little interest in such an approach from the

various stakeholders with whom we have met. Accordingly, we are not including any provisions in our final rules to implement an area-wide PAL system. However, we are not precluding such a program either. If a State currently has or wants to pursue an


### 80222 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

area-wide PAL program, then it must demonstrate that its program is equivalent to or more stringent than our

final rules.

14. When Should Modeling or Other Types of Ambient Impact Assessments Be Required for Changes Occurring

Under a PAL?

In our 1996 proposal, we requested comment on when modeling or other air quality impacts analysis is needed for changes occurring under a PAL to demonstrate protection of NAAQS, increments, and AQRVs.

One environmental commenter recommends modeling or other types of ambient impacts assessment whenever a change in emissions occurred under the

PAL. One commenter recommends that FLMs be consulted whenever changes under the PAL are proposed, to determine whether an impact analysis for adverse impact on AQRVs would be necessary. Several commenters recommend modeling whenever a significant change occurred, but also recommend that EPA define significant change and how the modeling would be conducted. A facility could report the modeled effects of a minor change afterthe change is made (in a quarterly, semiannual, or perhaps annual modeling summary), while more significant changes should be modeled prior to construction. The facility could be given a lot of responsibility in these cases and then held accountable (that is, required to mitigate) should an air quality increment or NAAQS be exceeded.

These commenters also recommend that the impacts evaluation should be

conducted at the time the PAL is

established and that the PAL should clearly define what flexibility the source

is allowed without further review and the types of changes for which additional review will be required. Some commenters generally believe that the proposed regulatory language concerning changes to PALs for air quality reasons was too vague and broad, but only a few of these commenters directly oppose modeling for changes under the PAL. One commenter states that if many changes were to require ambient air quality analysis, the PAL approach would have little if any benefit. The commenter believes that sources ought to discuss up front with permit authorities which emissions shifts might have consequences that would later require additional modeling/monitoring. If questions existed about certain emissions sources under a PAL, PALs could be approved with conditions assuring that certain post-approval modeling analysis be submitted. In today ’ s final rules, we believe we can rely on the reviewing authority ’ s existing programs for addressing air quality issues. Certain changes in effective stack parameters under the PAL would generally be covered by the reviewing authority ’ s minor NSR construction permit program. The reviewing authority would ordinarily request air quality modeling for any changes if it believes that the changes under the PAL may affect the NAAQS

and PSD increments.

V. Clean Units

A. Introduction

In today ’ s final rulemaking, we are promulgating a new type of applicability test for emissions units that are designated as Clean Units. This new applicability test will measure whether an emissions increase occurs, based on whether the physical change or change in the method of operation

affects the Clean Unit status of the unit. This new applicability test provides that when you meet emission limitations based on installing state-of-the-art emissions control technologies (add-on control technology, pollution prevention techniques, or work practices) that are determined to be BACT or LAER, you may make any physical or operational changes to the Clean Unit without triggering major NSR, unless the change causes the need

for a revision in the emission limitations or work practice requirements in the permit for the unit adopted in conjunction with BACT, LAER, or Clean Unit determinations, or would alter any physical or operational characteristics that formed the basis for the BACT, LAER, or Clean Unit determination for a particular unit. Emissions units that have not been through major NSR may also qualify for the Clean Unit applicability test if you demonstrate that

their emission limitations based on their emissions control technology (that is, add-on control technology, pollution prevention technique, or work practice) is comparable to BACT or LAER and you demonstrate that the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public. To be comparable to BACT/LAER, the controls must meet the specific comparability test that we

describe in section V.C.3 of this preamble. That is, you must show that the air pollution control technology (which includes pollution prevention or work practices) is comparable to BACT/ LAER in one of two ways: (1) By comparing your emissions unit ’ s control

level to BACT/LAER determinations for

other similar sources in the RACT/ BACT/LAER Clearinghouse (RBLC); or (2) by making a case-by-case demonstration that your emissions

control is ‘‘ substantially as effective ’’as BACT or LAER.

The Clean Unit applicability test benefits the public and the environment by providing you with an incentive to

install state-of-the-art emissions controls, even if you would not otherwise be required to control

emissions to this level. You will benefit from these final rules because they provide you with increased operational flexibility. Once you have installed

state-of-the-art emissions controls on an

emissions unit and it is considered a Clean Unit, you may make changes to respond rapidly to market demands without having to obtain a preconstruction major NSR permit. Moreover, you and your reviewing authority will benefit from increased administrative efficiency. We believethat once you have installed state-of-theart emissions control, an additional major NSR review will generally not result in any additional emissions controls for a period of years after the original control technology determination is made. In such cases, the major NSR permitting requirements impose a paperwork burden with little

to no additional environmental benefit. The Clean Unit applicability test eliminates this unnecessary

administrative action.

B. Summary of 1996 Clean Unit Proposal

In the 1996 NSR Reform package, we proposed an innovative approach to NSR applicability called the Clean Unit Exclusion. The proposed Clean Unit Exclusion would allow you to modify qualifying emissions units without being subject to the NSR permitting process for a period of 10 years, as long as your maximum hourly emissions rates would not increase. We proposed that your pre-change hourly potential

emissions rate must be established at any time up to 6 months prior to the proposed activity or project.

We proposed three methods by which an emissions unit could qualify for the

Clean Unit Exclusion. One was that the emissions unit went through a major NSR action within the last 10 years and

had an enforceable limit based on BACT

or LAER. The second was if the emissions unit was permitted under a State or local agency minor NSR program within the last 10 years and the minor NSR control technology


### 80223 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

requirements were comparable to BACT or LAER. As part of this second method, we proposed that State and local agencies would submit their minor NSRprograms for certification so that caseby-case determinations for emissions units permitted under a minor NSR program would not be necessary. The third method was a case-by-case

determination that an emission limitation was comparable to BACT or

LAER for that emissions unit. For these units, we proposed that the Clean Unit Exclusion would last for 5 years. We proposed that a determination that a limit was comparable to BACT or LAER

could be based on one of two methods: (1) the average of the BACT or LAER for equivalent sources over a recent period of time (such as 3 years); or (2) the unit ’ s control level is within some percentage (such as 5 or 10) of the most recent, or average of the most recent, BACT or LAER levels for equivalent or similar

sources.

In addition, we asked for public

comment on whether Clean Unit status should apply to emissions units with

limits based on MACT or RACT. Although we did not propose accompanying regulatory language, we suggested that reviewing authorities use the title V permitting process to designate Clean Units.

C. Final Regulations for Clean Units

1. Summary of Final Action

Today ’ s rule provides that your emissions unit qualifies as a Clean Unit, and qualifies to use the Clean Unit applicability test, if it has gone through a major NSR permitting review and is complying with BACT or LAER. Conversely, if your emissions unit has not gone through a major NSR permitting review, you do not automatically qualify for Clean Unit

status. These emissions units must first go through a SIP-approved permitting process that includes a process for determining whether the emissions unit meets the criteria to be designated as a Clean Unit. This process must include public notice and opportunity for public

comment.

To obtain Clean Unit status and qualify for the Clean Unit applicability test using a SIP-approved permitting
process, you must pass a two-part test: (1) The air pollution control technology (which includes pollution prevention or work practices) must be comparable to BACT or LAER; and (2) you must

demonstrate that the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public. You may make a showing that the air pollution control technology (which includes pollution prevention or work practices) is comparable to BACT/LAER in two ways: (1) By comparing your emissions

unit ’ s control level to BACT/LAER

determinations for similar sources in the RBLC; or (2) by making a case-by-case demonstration that your emissions

control is ‘‘ substantially as effective ’’as BACT or LAER.

If your emissions unit automatically qualifies as a Clean Unit because it has been through major NSR permitting, you may use the Clean Unit applicability test for up to 10 years. Today ’ s rules allow you to apply for Clean Unit status for control technologies you have installed in the past if you go through a SIP-approved permitting program that authorizes Clean Units and you qualify

as a Clean Unit. The Clean Unit effective period for emissions units that must go through a SIP-approved permitting process to obtain Clean Unit status is

consistent with the time frame for emissions units that automatically qualify as Clean Units. That is, you may only use the Clean Unit applicability test for a period of 10 years. If you meet the requirements that we describe in section V.C.9 of this preamble, you may re-qualify for Clean Unit status. Upon expiration of Clean Unit status, the Clean Unit applicability test no longer applies to changes at the emissions unit.

It is worth noting that in 1996, we proposed the provisions for Clean Units

as a ‘‘ Clean Unit Exclusion, ’’although we discussed the provisions as a new applicability test. We received criticism

from at least one commenter that our

characterization of the test as an exclusion was inappropriate. We agree with this commenter, and have thus

renamed the test as the Clean Unit applicability test. We believe that this title more appropriately reflects that the test is not whether you are excluded from review under major NSR, but whether using a more appropriate emissions test you trigger major NSR

review.

2. Is Clean Unit Status Available in Both

Attainment and Nonattainment Areas?

You may obtain Clean Unit status regardless of whether you are located in

an attainment area or in a nonattainment area. Our proposed Clean Unit provisions were unclear on how

emissions offsets and other nonattainment area requirements are affected by Clean Unit status. We want to clarify this issue. For sources in

nonattainment areas which went through major NSR permitting while the

area was nonattainment or which have qualified for Clean Unit status showing they are comparable to LAER, the permitted emissions level for the Clean

Unit must have been offset. The emissions reductions resulting from installation of the control technology

that is the basis of an emissions unit ’ s status as a Clean Unit may not be used as offsets; however, emissions reductions below the level that qualified the unit as a Clean Unit may be used as offsets if they are surplus, quantifiable, permanent, and federally enforceable. Furthermore, for emissions units that are designated as Clean Units and that are located in nonattainment areas, RACT and any other requirements for

nonattainment area sources under the SIP will still apply. The only exception to this is that the specific major NSR requirements related to calculating emissions increases from a physical change or change in the method of operation for all other existing sources that we describe in this preamble and codify in today ’ s rules are not applicable to Clean Units, because the Clean Units are subject to an alternative major NSR applicability requirement for calculating emissions increases when changes are made.

As we discuss in detail in section V.C.3 of this preamble, the

‘‘ substantially as effective ’’test for

sources in nonattainment areas must consider only LAER determinations, except that emissions units in nonattainment areas that went through major NSR permitting while the area was designated an attainment area for that regulated NSR pollutant, and that received a permit based on a qualifying air pollution control technology, automatically qualify as Clean Units.

If your emissions unit received Clean

Unit status while the unit was located

in an attainment area and the area ’ s attainment status subsequently changes to nonattainment, your emissions unit
retains Clean Unit status until expiration. However, to re-qualify as a Clean Unit (see section V.C.9), the unit will have to meet the requirements that apply in nonattainment areas.

3. How Do You Qualify As A Clean

Unit?

Any emissions unit permitted through major NSR automatically qualifies as a Clean Unit, provided the BACT/LAER determination results in some degree of emissions control. (We discuss the specific requirements for qualifying

controls in section V.C.4 of this preamble.) These units already meet both the control technology and air quality criteria of the CAA and the NSR


### 80224 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

regulations. We believe that the emission limitations (based on the BACT/LAER determination) and other permit terms and conditions (such as any limits on hours of operation, raw materials, etc., that were used to determine BACT/LAER) are protective of air quality. Although emissions units that have been through major NSR automatically qualify for Clean Unit status, there are specific procedures for establishing and maintaining Clean Unit status. We discuss these procedures in detail in sections V.C.6 through 9 of this preamble.

Your emissions units that have not gone through a major NSR permitting action that resulted in a requirement to comply with BACT or LAER may qualify for Clean Unit status if they are permitted under a SIP-approved permitting program that provides for public notice of the proposed determination and opportunity forpublic comment. You must pass a twopart test to obtain Clean Unit status: (1) The air pollution control technology (which includes pollution prevention or work practices) must be comparable to BACT or LAER; and (2) the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public.

You may show that the air pollution control technology (which includes pollution prevention or work practices) is comparable to BACT/LAER in one of two ways: (1) By comparing your

emissions unit ’ s control level to BACT/

LAER determinations for other similar sources in the RBLC; or (2) by making a case-by-case demonstration that your

emissions control is ‘‘ substantially as

effective ’’as BACT or LAER.

To make a demonstration using the first methodology in a nonattainment area, you must compare your control technology to the best-performing 5

similar sources in the RBLC for which

LAER has been determined within the past 5 years. If the emission limitation that is achieved by your control technology is at least as stringent as any one of the 5 best-performing units, and the emissions unit also passes the air quality test, then the reviewing authority shall presume that it qualifies as a Clean Unit. In attainment areas, you must compare your control technology

to all BACT and LAER decisions that

have been entered into the RBLC in the past 5 years, and for which it is technically feasible to apply the BACT or LAER control to your emissions unit type. If your control technology achieves a level of control that is equal to or better than the average of these determinations, and the emissions unit also passes the air quality test, then the reviewing authority shall presume that your emissions unit qualifies as a Clean

Unit.

After you have submitted your demonstration, the reviewing authority

will also consider other BACT/LAER

determinations that are not included in

the RBLC to determine whether the proposed emissions rate is comparable to BACT/LAER, and incorporate this

information into its determination as appropriate. In addition, the public will have an opportunity to review and comment on the reviewing authority ’ s decision to designate an emissions unit as a Clean Unit. This approach ensures that you are meeting an emissions level comparable to that of BACT or LAER, while providing you flexibility to use the controls that are best suited to your

processes.

We are providing this first methodology as a streamlined methodology for identifying Clean Units. Any unit that meets these qualifications shall be presumed to be a Clean Unit. Conversely, the opposite is not true. The reviewing authority shall not presume that a unit that does not

meet the test is not a Clean Unit. The quality and number of determinations in the RBLC vary by different type of sources. The RBLC may not always identify all the types of control technology strategies that should qualify an emissions unit as a Clean Unit, or it may not provide a representative sample for making an appropriate determination. Therefore, even if you are unable to demonstrate that your emissions unit is a Clean Unit using this methodology, your reviewing authority

shall not allow this outcome to prejudice its decision-making.

Accordingly, we are providing a second option for determining whether you qualify as a Clean Unit. If your

emissions unit does not meet the

emission limitation determined from the analysis of the RBLC described above (as appropriate for the area in which it is located), or if there is insufficient

information in the RBLC to conduct the analysis, then you may still show, on a case-by-case basis, that your emissions

unit will achieve a level of control that

is ‘‘ substantially as effective ’’as BACT or LAER, depending whether your

emissions unit is in an attainment area

or a nonattainment area. In an attainment area, your emissions unit
must achieve a level of control that is

‘‘ substantially as effective ’’as BACT. In a nonattainment area, your emissions
unit must achieve a level of control that is ‘‘ substantially as effective ’’as LAER. The reviewing authority will make a decision on whether a particular air pollution control technology (which includes pollution prevention or work practices) is ‘‘ substantially as effective ’’ as the BACT/LAER technology for a specific source on a case-by-case basis.

We are not promulgating specific requirements or performance criteria for satisfying the ‘‘ substantially as

effective ’’test, because we believe reviewing authorities are in the best position to determine whether in fact a particular air pollution control technology (which includes pollution prevention or work practices) is

‘‘ substantially as effective ’’as the BACT/LAER technology for a specific source. The case-by-case determinations must meet the same air quality test as those units going through a BACT/LAER determination. Moreover, the public has opportunity for public review and

comment on the ‘‘ substantially as

effective ’’decision. With these safeguards, we believe the

‘‘ substantially as effective ’’test will

ensure determinations that meet both the control technology and air quality tests, as well as allow sources to implement the controls that are best suited to their individual processes.

Under the second part of the test to determine whether your unit qualifies for Clean Unit status, you must

demonstrate that the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public. If your emissions unit has already been permitted under minor NSR or another SIP-approved permitting program, you may have already satisfied the second part of this test. If not, consistent with the requirements in sections 165(a)(3) and 173(a) of the CAA, you will be required to show that

the allowable emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has

been identified for a Federal Class I area by an FLM and for which information is available to the general public. For areas that do not already attain the NAAQS, the source would be required

to show that the emissions for the unit have been previously offset.

4. Can an Emissions Unit That Applies No Emissions Control Technology Qualify as a Clean Unit?

In most cases, BACT/LAER will result in significant emissions decreases (such as 90 percent control for many VOC


### 80225 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

32 It is possible that a BACT/LAER analysis will not always result in the requirement of add-on controls at a source. In some situations, a reviewing authority may appropriately determine that the control technology that best represents BACT/LAER is a work practice, or a combination of work practices and add-on controls. As a result, a requirement to use work practices, or a combination of add-on controls and work practices, as an emissions control technology, could qualify an emissions unit for Clean Unit status, provided it

meets the criteria established. coating sources). 32 In some circumstances, however, the outcome of a reviewing authority ’ s BACT or LAER determination may result in an emission limitation that you will meet without using a control technology (add-on control, pollution prevention technique, or work practice). Under today ’ s rules, you will not qualify as a Clean Unit in such circumstances. More specifically, today ’ s rules also require you to make an investment to qualify initially as a Clean Unit. An investment includes any cost which would ordinarily qualify as a capital expense under the Internal

Revenue Service ’ s filing guidelines whether or not you actually choose to capitalize that cost. An investment also includes any cost you incur to change your emissions unit or process to implement a pollution prevention approach, including research expenses, or costs to retool or reformulate your emissions unit or process to accommodate an add-on control, pollution prevention approach, or work practice.

5. When Do the Major NSR Requirements Apply to Clean Units?

Once an emissions unit qualifies as a Clean Unit, it is subject to an alternative major NSR applicability test for calculating emissions increases for subsequent changes. As we discussed in section II of this preamble, we have codified our longstanding policy (for emissions units that are not Clean Units) that a major modification occurs if both of the following result from the modification: (1) A significant emissions increase following the physical or operational change; and (2) a significant net emissions increase from the major stationary source. The major NSR applicability test for Clean Units is a different process.

For Clean Units, you must first determine whether a project causes the need to change the emission limitations or work practice requirements in the permit which were established in conjunction with BACT, LAER, or Clean Unit determinations and any physical or operational characteristics that formed the basis for the BACT, LAER, or Clean Unit determination for a particular unit. If it does, you lose Clean Unit status, and the project is subject to the applicability requirements as if the

emissions unit were never a Clean Unit. If the project does not cause the need to change the emission limitations or work practice requirements in the permit which were established in conjunction with BACT, LAER, or Clean Unit determinations and any physical or operational characteristics that formed the basis for the BACT, LAER, or Clean Unit determination for a particular unit, then you maintain Clean Unit status,

and no emissions increase is deemed to occur from the project for the purposes of major NSR. Once you have lost Clean Unit status, you can only re-qualify for Clean Unit status by going through the process that we describe in section V.C.9 of this preamble.

6. Can You Get Clean Unit Status for Controls That Have Already Been

Installed?

As discussed in section V.C.3, emissions units that have been through major NSR permitting automatically qualify for Clean Unit status. This

includes those emissions units that went through major NSR before promulgation of today ’ s final rules. If an emissions unit automatically qualifies

for Clean Unit status because it went through major NSR, its Clean Unit status

is based on the BACT/LAER controls

that went into service as a result of the major NSR review. That is, Clean Unit

status is based on the BACT/LAER controls regardless of whether the actual process for designating Clean Unit status through title V occurs at some

time after the controls went into service. However, Clean Unit status, and the ability to use the applicability process for Clean Units, does not begin until the

Clean Unit effective date. We discuss the specific procedures for when Clean Unit status starts, when it ends, and how it is designated in sections V.C.7 through 9.

For emissions units that have not been through major NSR, our rules allow your reviewing authority to provide you with Clean Unit status for emissions control that you have already installed and operated. However, our

final rules also limit the time frame under which your reviewing authority is

allowed to make such determinations for Clean Unit status that is granted through a SIP-approved permitting process other than major NSR. Your reviewing authority will only be able to grant Clean Unit status for previously installed emissions controls if they were

installed before the effective date of the program in your area. If the emissions

unit ’ s control technology is installed on or after the date that provisions for the Clean Unit applicability test are effective in your area, you must apply for Clean Unit status from your reviewing authority at the time the control technology is installed. As for emissions units that went through major NSR review, Clean Unit status foremissions units permitted through SIPapproved programs other than major NSR does not begin until the Clean Unit

effective date.

If you are applying for retroactive Clean Unit status, today ’ s final rules allow your reviewing authority to compare your emissions control level to

the BACT or LAER level that would have applied at the time you began construction of your emissions unit. However, in some cases, such a comparability analysis may be difficult for you to demonstrate because of lack

of sufficient information from which your reviewing authority can make a

reasoned determination. If this is the case, then you will have to demonstrate that your emissions controls are comparable to a BACT or LAER limit from a subsequent or current date.

7. When Can I Begin To Use the Clean

Unit Test?

The exact effective date depends on

the circumstances of the individual emissions unit, as explained further below. As a general principle, however,

the effective date for Clean Unit status

can never be before the Clean Unit provision becomes effective in the relevant jurisdiction.

For emissions units that automatically qualify for their original Clean Unit status because they have been throughmajor NSR review, and for units that requalify for Clean Unit status (see section V.C.9) by going through major NSR review and implementing new control technology to meet current-day BACT/ LAER, the effective date is the date the

emissions unit ’ s air pollution control technology is placed into service, or 3 years after the issuance date of the major NSR permit, whichever is earlier. However, the effective date can be no sooner than the date that provisions for the Clean Unit applicability test are approved by the Administrator for incorporation into the SIP and become

effective for the State in which the unit is located. That is, if the source had a major NSR permit and began operating before the Clean Unit provision becomes effective in the relevant jurisdiction, the

effective date is the date the State or local agency begins authorizing Clean Unit status. As we noted earlier, if the emissions unit previously went through major NSR, it automatically qualifies as a Clean Unit. The original Clean Unit

status would be based on the controls


### 80226 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

33 As discussed in section III.E of today ’ s preamble, we believe that 15 years represents a reasonable time period for designating a Clean Unit. However, we proposed and took comment on a 10- year period; therefore, we are finalizing today ’ s rule with a 10-year duration. In a separate Federal Register notice we will be proposing to change this duration to 15 years. that were installed to meet major NSR.

An additional investment at the time the original Clean Unit status becomes effective is not required.

For emissions units that re-qualify for Clean Unit status (see section V.C.9) by going through major NSR using an existing control technology that continues to meet current-day BACT/ LAER, the effective date is the date the new major NSR permit is issued.

If you obtain Clean Unit status from your State or local reviewing authority using a SIP-approved permitting process other than major NSR, the Clean Unit

effective date is the later of the following dates: (1) The date that the State or local agency permit that designates the emissions unit as a Clean Unit is issued; and (2) the date that the

emissions unit ’ s air pollution control measures went into service. That is, if

the controls went into service before the

issuance date of the State or local agency permit that designates the unit as a Clean Unit, the Clean Unit effective date is the date that the permit is issued. As with units that have been through major NSR, additional investment is not required for the limited cases where there is a retroactive designation. If the

issuance date of the State or local agency permit that designates the

emissions unit as a Clean Unit is before

the date the controls went into service (as would likely be the case for a unit

that is new or modified after the State or local agency begins to authorize Clean Unit status), then the effective

date of Clean Unit status is the date the

controls went into service.

8. How Long Does Clean Unit Status

Last?

In most cases, you may use the Clean Unit applicability test for a period of 10

years. 33 As a general principle, the Clean Unit expiration date can never be later than the date that is 10 years after the controls are brought into service.

For emissions units that automatically qualify for their original Clean Unit status because they have been throughmajor NSR review, and for units that requalify for Clean Unit status ( see section V.C.9) by going through major NSR review and implementing new control technology to meet current-day BACT/ LAER, Clean Unit status expires 10 years after the effective date, or the date the equipment went into service, whichever is earlier. However, Clean Unit status expires sooner if, at any time, the owner or operator fails to comply with the provisions for maintaining Clean Unit status that are

included in the final rules.

For emissions units that re-qualify for Clean Unit status ( see section V.C.9) by going through major NSR using an existing control technology that continues to meet current-day BACT/ LAER, Clean Unit status expires 10 years after the effective date. However, as noted above, Clean Unit status expires sooner if, at any time, the owner or operator fails to comply with the provisions for maintaining Clean Unit

status that are included in the final

rules.

The expiration date for Clean Units that have not been through major NSR permitting depends on whether the owner or operator qualifies for Clean

Unit status based on current BACT/LAER, or on BACT/LAER at the time the control technology was installed. If the owner or operator of a previously installed unit demonstrates that the emission limitation achieved by

the emissions unit ’ s control technology is comparable to the BACT/LAER requirements that applied at the time the control technology was installed, then Clean Unit status expires 10 years

from the date that the control technology was installed. For all other emissions units (that is, previously

installed units that are demonstrated to be comparable to current BACT/LAER, new units, and units that re-qualify as Clean Units), Clean Unit status expires 10 years from the effective date of the Clean Unit status. In addition, for all emissions units, Clean Unit status expires any time the owner or operator fails to comply with the provisions for maintaining Clean Unit status that are

included in the final rules.

When your Clean Unit status expires, you are subject to the major NSR applicability test as if your emissions unit is not a Clean Unit. The permitted

emissions levels established for the Clean Unit do not expire.

9. Can I Re-qualify for Clean Unit

Status?

You may re-qualify for Clean Unit status after the status has expired or you have otherwise lost Clean Unit status, if you meet the conditions in our final regulations. As we stated before, we believe that once you have installed state-of-the-art emissions control, an additional major NSR review will generally not result in any additional emissions controls for a period of years after the original control technology determination is made. Also, the period for which any specific air pollution control technology (which includes pollution prevention or work practices)

will continue to achieve the same level of control depends on many factors. As a practical matter, we have established a single time frame of 10 years for Clean Unit status, to provide simplicity in our final rules. However, for reasons we

discuss in detail in section V.E.1 of this preamble, we determined that a reasonable average equipment life for a control technology is generally longer than 10 years. Certainly we want to encourage source owner/operators to

install and maintain state-of-the-art control. We believe this is more likely when you can be assured that you can

retain Clean Unit status for the useful life of the equipment, as long as air quality continues to be assured. The useful life of the equipment may extend beyond the original Clean Unit expiration date. Therefore, we are promulgating final regulations that allow you to apply to re-qualify for

Clean Unit status.

To re-qualify for Clean Unit status, you would generally follow the same process that you used in first qualifying for Clean Unit status. However, we will not necessarily require you to meet an additional investment test to re-qualify

for Clean Unit status for the same controls. That is, unless the controls

used to establish Clean Unit status are no longer BACT/LAER or comparable, there will be no requirement for an investment to re-qualify for Clean Unit

status.

You may re-qualify for Clean Unit status either by going through major NSR or by going through the alternative

Clean Unit Test that we described in section V.C.3 of this preamble: (1) The air pollution control technology (which includes pollution prevention or work practices) must be comparable to BACT or LAER; and (2) the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public. Regardless of which process you used to establish Clean Unitstatus initially, you may choose to requalify for Clean Unit status by going through major NSR or by going through the alternative two-part test.

Once you have submitted an application to re-qualify for Clean Unit status, the reviewing authority will make a determination concerning current BACT/LAER or comparable control technology. For example, suppose you had Clean Unit status for

an emissions unit for which the controls


### 80227 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

went into service June 1, 1996, thepermit application for Clean Unit requalification was submitted December 1, 2004, and the Clean Unit status expires June 1, 2006. In cases where the controls you installed in 1996 are still BACT/LAER or comparable when the reviewing authority makes the determination following your application submittal in 2004, the emissions unit can re-qualify for Clean

Unit status based on the controls installed in 1996 if your emissions unit

still meets all of the criteria for Clean Unit status. That is, in addition to the control technology review, the emissions unit must go through an air quality review and public participation.

A safeguard related to Clean Unit controls is that for re-qualifying for

Clean Unit status when the emissions unit is located in a nonattainment area,

the control determination must be LAER or comparable to LAER. If you previously received Clean Unit status

based on the BACT level of control

while the source was located in an

attainment area and the attainment area becomes a nonattainment area by the time your Clean Unit status expires, the Clean Unit status for re-qualification

must be based on controls that are LAER or comparable to LAER.

The air quality analysis for Clean Unit re-qualifications will be that of the path that you have chosen ’ major NSR, or comparable. As we discuss in detail in section V.C.3 of this preamble, for emissions units qualifying for Clean Unit status through the comparable test, you must show that the allowable

emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that has been identified for a Federal Class I area by an FLM and for

which information is available to the general public.

We believe that the control technology determination, air quality review, and public participationrequirements of the Clean Unit requalification process will ensure that Clean Units will continue to protect airquality throughout the 10-year requalification period. Moreover, any offset or mitigation requirements as a result of a previous major NSR

determination will remain in force.

We expect that in many cases the controls used to initially establish Clean Unit status will still be operating efficiently and the Clean Unit status can

be reestablished for an additional 10 years based on those controls. Suppose, however, you submitted an application to re-qualify for Clean Unit status and the reviewing authority determines that your existing controls do not meet the level of current BACT/LAER or comparable controls. In this case, you must install new or upgraded controls to re-qualify for Clean Unit status. You must go through the control technology determination, air quality review, and public participation requirements of the Clean Unit re-qualification process as

described above.

10. What Terms and Conditions Must the Permit for my Clean Unit Contain?

Major NSR permits contain the

emission limitations based on BACT/ LAER, other permit terms and conditions that the reviewing authority identifies as representative of BACT/ LAER (such as limits on hours of operation), and monitoring, recordkeeping and reporting requirements for the emissions unit. If you are qualifying for Clean Unit status through the major NSR review, your major NSR permit will have such terms and conditions. Likewise, any permit under a SIP-approved permitting process other than major NSR that designates an emissions unit as a CleanUnit must specify: (1) The sourcespecific allowable permit emission limitations, the exceedance of which, in combination with a significant net emissions increase, will trigger major NSR review; (2) other permit terms and conditions that the reviewing authority identifies as representative or comparable to BACT/LAER for your control technology (such as limits on operating parameters, etc.); (3) any

conditions used as the basis for the control technology determinations (hours of operation, limits on raw materials, etc.); and (4) the monitoring, recordkeeping, and reporting requirements necessary to demonstrate

that a ‘‘ clean ’’level of emissions control is being achieved. Additional monitoring, recordkeeping, and reporting may be required to assure compliance under §§ 70.6(a)(3) or 70.6(c)(1) (that is, to assure compliance under title V).

The State and local agency permits establishing Clean Unit status must contain a statement designating the

emissions unit as a Clean Unit. The State or local agency permit must also include general terms and conditions indicating the Clean Unit effective date and expiration date. Suppose the State or local agency permit has an effective date of May 5, 2006, and the controls

will be installed after this date. The SIP permit would state that the effective

date of the Clean Unit status is the date the controls go into service. The permit

would also state that Clean Unit status will expire no later than May 5, 2016. Your title V permit must include the Clean Unit status, as well as the effective and expiration dates of the Clean Unit status. Your title V permit

must also include: the emission limitation(s) that reflect BACT/LAER or comparable control; other permit terms and conditions that the reviewing authority has determined represent BACT/LAER or comparable control (such as limits on hours of operation) and that ensure that air quality is protected; and the monitoring, recordkeeping, and reporting requirements necessary to demonstrate

that a ‘‘ clean ’’level of emissions control is being achieved.

11. How Will my Clean Unit Status be Incorporated Into my Title V Permit?

Clean Unit status and other permit

terms and conditions must be incorporated into the major stationary

source ’ s title V permit in accordance with the provisions of the applicable title V permit program under part 70 or part 71, but no later than when the title V permit is renewed.

The title V permit must also contain the specific dates on which your Clean

Unit status is effective and on which it expires. We are aware that the specific Clean Unit effective and expiration dates will frequently not be determined

at the time that Clean Unit status is established. Therefore, the initial title V permit action that incorporates Clean Unit status and other permit terms and conditions may need to state the Clean Unit effective and expiration dates in general terms. For example, for units that have been through major NSR, the initial title V permit might state that the expiration date is the earlier of the following dates: the date 10 years after (1) the Clean Unit ’ s effective date, or (2) the date the equipment went into service. The permit does not have to include the specific Clean Unit effective and expiration dates where they cannot

be determined at the time of initial incorporation, such as would be the case when the Clean Unit has yet to be constructed. Furthermore, in these instances, we are not requiring that the title V permit be modified to incorporate the specific Clean Unit effective and expiration dates until the next permit renewal, reopening, or modification

after such dates are known.

As soon as the specific Clean Unit effective and expiration dates are known, the source must report them to the reviewing authority. The specific Clean Unit effective and expiration dates must then be incorporated into the title V permit at the first opportunity, such as a modification, revision, reopening, or renewal of the title V


### 80228 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

permit for any reason, whichever comes first, but in no case later than the next renewal. However, it is not necessary to amend the SIP-approved permit to incorporate the specific Clean Unit effective and expiration dates, as long as these dates are incorporated into the title V permit at the next renewal. If you wish to incorporate the Clean Unit effective and expiration dates into the SIP permit, a title V modification would be required.

While the title V permit contains the Clean Unit permit terms and conditions, we want to emphasize that any changes to Clean Unit permit terms and conditions (other than incorporating the specific Clean Unit effective and expiration dates) must first be made through a SIP-approved permitting process that provides for public review and opportunity for comment. Any such changes would be incorporated into the title V permit in the manner described

above.

12. Can a Clean Unit Be Used in a Netting Analysis?

Generally, for an emissions unit that

has Clean Unit status because it has gone through major NSR permitting, you must not include emissions changes at the Clean Unit in a netting analysis, or use them for generating offsets, unless the emissions changes occur and you use them for these purposes before the

effective date of Clean Unit status or after Clean Unit status expires. However, if you reduce emissions from

the Clean Unit below the level that qualified the unit as a Clean Unit, you may generate a credit for the difference between the level that qualified the unit

as a Clean Unit and the new emission limitation, if such reductions are surplus, quantifiable, permanent, and federally enforceable (for the purposes of generating offsets) and enforceable as a practical matter (for purposes of determining creditable net emissions increases and decreases). Such credits may be used for netting or as offsets. We are allowing the credit to be computed

in this manner because the owner or operator has already obtained an actual

emissions-based offset for the emissions up to the Clean Unit emission limitations. By the owner/operator ’ s accepting a federally enforceable emission limitation below this level,

these offsets are now available to create

additional actual emissions reductions.

The final rules are similar for emissions units that are designated as Clean Units in a SIP-approved permitting process other than major

NSR. You must not include emissions changes that occur at such units in a netting analysis, or use them for generating offsets, unless the emissions changes occur and you use them for these purposes before the effective date of the SIP requirements adopted to implement the Clean Units or after Clean Unit status expires. However, if you reduce emissions from the Clean Unit below the level that qualified the unit as a Clean Unit, you may generate

a credit for the difference between the level that qualified the unit as a Clean Unit and the new emission limitation, if such reductions are surplus, quantifiable, permanent, and federally enforceable (for purposes of generating offsets) and enforceable as a practical matter (for purposes of determining

creditable net emissions increases and decreases). Such credits may be used for netting or as offsets.

13. How Does Clean Unit Status Apply When There Are Multiple Pollutants?

Clean Unit status is pollutant-specific and may not be granted for more than one pollutant, except in cases where a group of pollutants is characterized as a single pollutant, such as VOCs. You may, however, qualify for simultaneous Clean Unit status for other pollutants at

those emissions units that are sufficiently controlled to independently qualify as ‘‘ clean ’’for each pollutant. For units applying for Clean Unit status and that do not already have a major NSR permit, the reviewing authority must specify the pollutants for which Clean Unit status applies as part of the permitting process establishing Clean

Unit status.

D. Legal Basis for the Clean Unit Test

As discussed above, the Clean Unit applicability test would provide an

alternative emissions test for determining if a significant increase in emissions has occurred after a physical change or change in the method of operation at units that are designated as

‘‘ clean. ’’We believe that we have the authority to allow these specific types of units to use a different applicability test.

The CAA is silent on whether increases in emissions for purposes of determining whether a physical or operational change constitutes a

modification must be measured in terms of actual emissions, potential emissions, or some other currency. We believe that it is a reasonable interpretation of the CAA to determine applicability of the major NSR program for units qualifying

as Clean Units in terms of the emission limitations or work practice requirements in the permit, and that this interpretation is consistent with the statutory purposes of NSR.

The PSD permitting program has 5 key elements: (1) Control technology review; (2) air quality review; (3) monitoring requirements; (4) information on the source; and (5) procedures for processing applications, including public notice and the opportunity for comment. A new major source or major modification in an attainment area must go through PSD permitting to become a Clean Unit. That process would have had to include the

elements listed above. CAA section 165.

Similarly, the CAA requires new major sources or major modifications

undertaken in nonattainment areas to obtain permits that require them to meet LAER and to obtain offsetting emissions

reductions. CAA section 173. In order to be designated a Clean Unit, a major

source or modification in a

nonattainment area would have had to have gone through major NSR permitting review in the last 10 years.

We believe that units that have undergone minor source permitting in a manner that fulfills the statutory purposes of major NSR

—either because

a State ’ s minor NSR program already contains equivalent provisions or because the existing program is enhanced for the purpose of allowing the reviewing authority to satisfy Clean

Unit criteria

—also will have satisfied the requirements of the CAA in a manner sufficient to justify Clean Unit

status. As we have discussed in section V.C of this preamble, to obtain Clean Unit status through a minor NSR program, that process must include a requirement for public participation. Furthermore, emissions units that aredesignated as Clean Units through SIPapproved minor NSR programs must satisfy an air quality test. You must provide information demonstrating that you will not cause or contribute to a NAAQS or PSD increment violation or adverse impact on an AQRV in a Federal Class I area. If your emissions unit has already been permitted under minor NSR or another SIP-approved permitting program, you may have already satisfied the second part of this test. If not, consistent with the requirements in sections 165(a)(3) and 173(a) of the CAA, you will be required

to show that the allowable emissions will not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that

has been identified for a Federal Class I area by an FLM and for which information is available to the general public. For areas that do not already attain the NAAQS, the source would be required to show that the emissions for the unit have been previously offset, or the reviewing authority will have to

show that these emissions will not


### 80229 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

34 Vatavuk, William, ‘‘ Part II, Factors for Estimating Capital and Operating Costs, ’’ Chemical Engineering, Nov. 3, 1980. interfere with the State ’ s ability to

achieve attainment.

For Clean Units that have emission limitations and/or work practice requirements established through programs that fulfill relevant major NSR statutory requirements, we believe that the alternative way to estimate

emissions increases to evaluate applicability set forth under the Clean Unit Test is appropriate and consistent with Congress ’ s intent. A project at a Clean Unit that would require a revision

to the emission limitations or work practice requirements established through permitting programs that meet the requirements of the Act, or that would alter any physical or operational

characteristics that formed the basis for the permitting action, must go through a new permitting process. The reviewing authority must have already required state-of-the-art pollution control technology (or, through an investment, its pollution prevention or work practice equivalent), conducted the required air quality analyses based on the emissions level in the permit, and provided the public with an appropriate opportunity to comment on that level of emissions and air quality impact. Therefore, we believe that allowing an alternative means of evaluating applicability based on a revised emissions test for this category

of unit is consistent with the CAA.

E. Summary of Major Comments and Responses

Although a few commenters categorically oppose the Clean Unit Test, most commenters support the concept. Practically all commenters oppose some aspect of the test or request that the test be clarified. Below are the major comments and our

responses.
1. How Long Should You Be Eligible for the Clean Unit Applicability Test?

We received numerous comments on

the duration of Clean Unit status. In the proposal, we suggested a 10-year

duration and asked for comments regarding this period. We received comments supporting various lengths of time from 2 to 20 years. Although some commenters support a 10-year duration, other commenters oppose it.

Many commenters believe that 10 years is too short for Clean Unit status. These commenters argue that BACT/ LAER technologies accomplish substantial pollutant removals, and that the cost of a slight increase in pollutant removal is usually significant. These commenters urge us to establish a Clean Unit status duration that comports with the useful life of the control equipment, which would enable you to recover the costs of installing the pollution control technology. They believe that you should be able to recoup the investments in pollution control before being forced to abandon that technology and pay again for newer technology. Some commenters request that a presumptive life of 20 years be awarded to Clean Units, which is approximately how long the control equipment should

be effective.

Some commenters believe that 10 years would be too long, because they

believe that advances in control technology occur more rapidly. A 10- year duration would allow old, less effective technologies to be the basis of immunity from the NSR program. These commenters are particularly concerned about the 10-year duration for BACT/

LAER determinations that were based

on no controls.

We believe that we have discretion to determine the appropriate period for which you should be eligible for the Clean Unit applicability test. As a policy matter, we believe that this time period

should reach a balance between the

unit ’ s useful emissions control equipment life and the time frame in which additional major NSR review is likely to result in no added environmental benefit. As a practical matter, we realize that the ‘‘ ideal ’’time frame will vary by emissions control technology and by pollutant; however, we believe using a single time frame will provide simplicity in our final

rules.

To determine an average life expectancy for a variety of control technologies, we relied on the guidelines for equipment life for 9 commonly used emissions control technologies published in ‘‘ Estimating Costs of Air Pollution Control Systems, Part II, Factors for Estimating Capital and Operating Costs. ’’ 34 Using the average of the low, average, and high values, we determined that a reasonable average equipment life for a control technology is equal to 15 years.

We then looked at the incremental improvement in control technology over

time. We found that the evolution of pollution control equipment over time is dominated by innovation, rather than invention. In other words, the change in design and capacity for any given device type occurs infrequently as a series of marginal improvements over the preceding design. Consequently, the marginal improvement in pollution abatement one can expect between generations of the same type of device is also very small

—too small to justify the cost of an entirely new unit. For example, flue gas desulfurization (FGD)

units have been used in the United States for about 20 years, and were used in Japan and Germany for 10 years before that. During the early 1980 ’ s, a typical FGD system removed about 90 percent of the sulfur from a flue gas stream. Today, modern FGD systems typically average 95 to 99 percent removal efficiency

—less than a 10 percent improvement in 20 years.

We also evaluated, from a cost-per-ton basis, whether the marginal improvement in removal efficiency is too expensive. Again, we considered the FGD example. From an actual NSR

determination for a coal-fired electrical generating unit in the Midwest, the installation of an FGD system in 1985 would have cost $189 million and had a removal efficiency of 90 percent (76,500 tons of sulfur per year). The

identical boiler in 2001 would use an FGD system with a 95 percent efficiency, costing $285 million, and removing 80,750 tpy, an additional 4,250 tons. The additional cost for the improved design for the 2001 installation (including the retrofit and upgrade of existing components and the new cost of larger pumps and other auxiliary equipment) would have been more than $100 million, or greater than $24,000 per ton. Consequently, from an efficiency standpoint, requiring an upgrade on this unit to BACT or LAER

levels would not have been economical.

After reviewing all of this information, we determined that a 15- year period represents a reasonable and appropriate time frame during which you should be allowed to use your permitted allowable emissions to determine whether an increase triggers major NSR review. However, we proposed and took comment on a 10- year duration. Therefore, today we are finalizing a single time frame of 10 years that applies to all types of emissions control technologies and all types of pollutants. Because we believe that 15 years represents a reasonable time frame, we will be proposing a 15-year

duration for Clean Unit status. After considering any public comments on a 15-year duration for Clean Unit status, we may amend today ’ s final regulations.

We believe it is beneficial to allow emissions units using pollution prevention techniques or work practices to qualify for Clean Unit status where

those units meet certain criteria. In some cases (coating operations, for example), pollution preventiontechniques or work practices are stateof-the-art pollution control, and either


### 80230 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

there would not be an improvement in pollution control if the unit were required to install add-on controls or the

incremental cost effectiveness of the

add-on control installation would be too high for it to qualify as BACT. In other cases, the most stringent control is based on add-on control and pollution prevention. Therefore, under many circumstances, we believe that pollution prevention techniques and work practices can be implemented to achieve

a level of emissions reductions comparable to that achieved by BACT/ LAER add-on controls. Also, initiation of a pollution prevention technique or a work practice can require a substantial

investment in research to retool or reformulate your operations. Thus, we

do not believe that a blanket exclusion from Clean Unit status is appropriate for

emissions units that are controlled with pollution control techniques.

Implementation of pollution prevention approaches and work practices usually requires research, followed by some retooling or reformulation of a process line or unit operation. As part of this retooling or reformulation, some equipment has to be purchased up front (for example, sniffers for leak detection and repair operations, improved process control consoles and/or software for recycle streams, initial modeling for combustion optimization systems). This equipment purchase or initial modeling involves a one-time investment; hence, there is an investment associated with pollution prevention or work practice implementation. Researching the application of an approach also qualifies as an investment for these purposes.

We received comment from a number

of commenters who are concerned about

Clean Unit status when BACT/LAER

determinations are based on no control. As these commenters note, ‘‘ no controls ’’does not equate to a wellcontrolled emissions unit. We agree with these commenters, and today ’ s final rules clarify that Clean Unit status can be based on add-on control, pollution prevention techniques, work practices, or a combination of them. We recognize that there are some

circumstances when the outcome of a reviewing authority ’ s BACT or LAER determination may result in an emission limitation that you will meet without using an air pollution control technology (which includes pollution prevention or work practices). We

believe that such emissions units should not qualify as Clean Units, because they fail the very premise under which we established the Clean Unit applicability test. That is, there is no period of time

in which we can reach a balance between the unit ’ s useful emissions control equipment life and the time frame in which additional major NSR review is likely to result in no added

environmental benefit. Source categories that currently have few or no control technology options are likely to be the categories that will experience a rapid advancement in emissions control technology over a short period of time. Accordingly, today ’ s final rules contain

two limitations on use of the Clean Unit applicability test. You may not use the Clean Unit applicability test for any emissions unit that is not using an air pollution control technology (which includes pollution prevention or work practices) and for which you have not

made an investment to control

emissions.

2. Does the Clean Unit Applicability

Test Measure the Increase in Maximum Hourly Potential Emissions?

We proposed that the Clean Unit Test would continue to apply as long as the

emissions unit ’ s maximum hourly potential emissions did not increase. The baseline for the maximum hourly potential emissions rate could be established at any time in the 6 months before the activity or project that

increases emissions. Almost all commenters oppose basing the Clean Unit Test on the hourly PTE, as well as the 6-month period for setting the emissions rate. Some commenters argue that an hourly PTE test is not environmentally protective enough. One

commenter notes that we were inappropriately using the applicability test under the NSPS as the applicability test for major NSR, which should be based on tpy. Many commenters view the hourly PTE test as so restrictive that few sources would take advantage of the

Clean Unit Test. These commenters believe that the hourly emissions rate

obscures the real basis for Clean Unit status, which is the add-on control efficiency.

We agree with the commenters who

maintain that Clean Unit status should

be based on the emissions level achievable through the use of control technologies. As these commenters note,

once an emissions level has been determined based on BACT/LAER, it is unlikely that additional review would result in a more stringent level of control. As a result, we are not finalizing the Clean Unit Test as proposed with the hourly PTE test. Instead, today ’ s final rules for Clean

Units are based on reduction of air pollution through the use of control technology (which includes pollution prevention or work practices) that meet both the following requirements. First, the control technology achieves a

BACT/LAER level of emissions reduction as determined through issuance of a major NSR permit within the past 10 years. However, the emissions unit is not eligible for Clean

Unit status if the BACT/LAER

determination resulted in no requirement to reduce emissions below the level of a standard, uncontrolled, new emissions unit of the same type. Second, the owner or operator made an

investment to install the control technology. For the purpose of this determination, an investment includes expenses to research the application of a pollution prevention technique to the emissions unit or expenses to apply a pollution prevention technique to an

emissions unit.

By adopting this approach, we are allowing the reviewing authority to decide the appropriate emission limitations or work practice requirements that will be used to obtain

and maintain Clean Unit status. If a project at a Clean Unit does not cause the need for a change in the emission limitations or work practice requirements that form the basis for Clean Unit status, the emissions unit

remains a Clean Unit. On the other hand, if the project causes the need for such change to the emission limitations or work practice requirements, the

emissions unit loses Clean Unit status and is subject to the applicability requirements of major NSR.

3. What Kind of Changes Are Allowed

Under Clean Unit Status?

It is not our intention to limit increases in emissions unit capacity aslong as emissions are under the sourcespecific allowable levels and the increase is within the capacity for which you obtained approval when applying for Clean Unit status. Incremental improvements to existing units are acceptable. However, complete changes to emissions units making them into completely different units than were originally permitted are not acceptable. For example, switching to a smaller but more polluting process than originally permitted may trigger stricter BACT/LAER requirements, even at the same annual emissions rate, since higher percentage removal rates and lower costs would be possible at higher

concentrations.

We expect that changes such as, but not limited to, increasing production to permitted levels, reconfiguring the process, changing process chemicals if consistent with the original Clean Unit application, replacing components, replacing catalysts, or adding other controls, or other changes would be


### 80231 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

allowable for Clean Units. In no instances are we authorizing violations of any existing permit conditions or other applicable requirements that may apply to the Clean Unit. You may not

reconstruct a Clean Unit under an existing Clean Unit status.

4. Does the Clean Unit Applicability Test Apply to Units That Have Not Gone Through a Major NSR Permitting

Review?

In 1996, we proposed that reviewing

authorities submit their minor source permit decisions for us to determine

whether the emission limitations were comparable to BACT or LAER. Commenters generally support allowing units permitted through minor NSR programs to qualify for Clean Unit

status. These commenters believe State and local agencies are well-equipped to make control technology

determinations. A few commenters are concerned that control technology

determinations made under minor NSR programs do not always require adequate air quality review or opportunity for public comment and review. They maintain that these program elements are essential for making control technology determinations that are equivalent to

BACT/LAER.

We also received comments on allowing Clean Unit status for emissions units that have not gone through either major or minor NSR, such as those that

decrease emissions to meet other requirements under the Act. These

comments are mixed. A few commenters support this option. Others

believe it makes no sense to extend the

status to units that had not had a recent control technology determination, particularly considering the burden the review would place on reviewing

authorities.

We agree that control technology determinations made by State and local agencies can be comparable to BACT/ LAER, regardless of the purpose for which the control technology decision is made. However, we also agree with

those commenters who believe a thorough analysis is necessary to ensure that air quality is protected. Moreover, we agree that a control technology determination is incomplete unless it has been through public review.

Therefore, today we are promulgating regulations that allow emissions units

that have not had a BACT/LAER determination to qualify for Clean Unitstatus, if they are permitted under a SIPapproved permitting program that provides for public notice of the proposed determination and opportunity for public comment to determine whether you should qualify

as a Clean Unit.

5. Does Clean Unit Status Apply to

Units That Have RACT or MACT

Limits?

A number of commenters maintain

that emission limitations based on

RACT and MACT achieve control comparable to those based on BACT and

LAER. These commenters therefore

believe Clean Unit status should be

available for emissions units with RACT or MACT limits. However, other commenters agree with us that RACT

and MACT limits should not automatically be considered equivalent

to BACT/LAER limits.

We are maintaining our position in the proposal rule that Clean Unit status does not presumptively apply to units

with limits based on RACT or MACT. However, when you believe a specific RACT or MACT limit is comparable to BACT/LAER, you may choose to use a SIP-approved permitting process to try

to obtain Clean Unit status.

6. How Should We Determine Whether a Control Technology Is Comparable to

BACT or LAER?

We proposed two methods for determining that control technology was comparable to BACT/LAER

—average of the level of control for the last 3 years, and percent control. None of the commenters support using the average

emissions rates to determine comparability. The commenters believe that in some cases this approach could lead to skewed results, or that the average control determination can differ substantially from the most recent

determination. The commenters suggested that EPA consider all technologies required to be considered in a BACT/LAER determination, not just

those listed in the RBLC. The commenters also say that it is not acceptable to call an uncontrolled unit

a ‘‘ clean ’’unit, when the Clean Unit Test is meant for companies that have taken the effort and expense to install controls or low emitting equipment. Although a few commenters support using percent control, several commenters oppose it. They maintain that defining control levels based on a certain percentage derived from BACT or LAER for equivalent sources is not simple and would require the frequent collection and maintenance of large quantities of information.

Based on the public comments on our two proposed methods, we have decided to develop a modified version of the proposed averaging method for determining when an air pollution control technology (which includes pollution prevention or work practices) is comparable to BACT/LAER. You can make a showing that the air pollution control technology (which includes pollution prevention or work practices) is comparable to BACT/LAER in one of two ways: (1) by comparing your

emissions unit ’ s control level to BACT/

LAER determinations for other similar sources in the RBLC; or (2) by making a case-by-case demonstration that your

emissions control is ‘‘ substantially as

effective ’’as BACT or LAER.

Under the first approach, we have developed slightly different approaches

for sources located in attainment and

nonattainment areas. For those

emissions units located in attainment areas, the emissions unit ’ s control technology is presumed to be comparable to BACT if it achieves an emission limitation that is equal to or better than the average of the emission limitations achieved by all the sources

for which a BACT or LAER

determination has been made within the preceding 5 years and entered into the RBLC, and for which it is technically feasible to apply the BACT or LAER control technology to the emissions

unit. To address the commenters ’ concerns regarding other BACT/LAER determinations that might not be in the RBLC, we have included a provision that allows the reviewing authority to also compare this presumption to any

additional BACT or LAER determinations of which it is aware, and to consider any information on achieved-in-practice pollution control technologies provided during the public comment period, to determine whether any presumptive determination that the control technology is comparable to

BACT is correct.

For sources in nonattainment areas,
the emissions unit ’ s control technology is presumed to be comparable to LAER

if it achieves an emission limitation that is at least as stringent as any one of the 5 best-performing similar sources for

which a LAER determination has been made within the preceding 5 years, and

for which information has been entered

into the RBLC. As is the case for units in attainment areas, the reviewing authority shall also compare this presumption to any additional LAER determinations of which it is aware, and shall consider any information on achieved-in-practice pollution control technologies provided during the public comment period, to determine whether any presumptive determination that the control technology is comparable to

LAER is correct.

The second approach, the

‘‘ substantially as effective ’’ test, avoids

a ‘‘ one-size-fits-all ’’approach that could


### 80232 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

35 July 1, 1994 memorandum from John S. Seitz, Director, OAQPS, ‘‘ Pollution Control Projects and New Source Review (NSR) Applicability ’’ and

hereinafter referred to as the ‘‘July 1, 1994 policy guidance. ’’ preclude some well-controlled sources from benefitting from the Clean Unit Test simply because there is insufficient information in the RBLC or because they are using an innovative approach to emissions control. This provision will allow you to use alternative controls as long as they achieve comparable control and air quality results. We believe that the reviewing authority is in the best position to judge whether a particular control technology achieves an

emissions control level that is comparable to BACT or LAER for a specific application, as well as to assure that air quality impacts have been accounted for. Thus, rather than requiring the reviewing authority to submit its permit decisions to us for approval as a comparable technology, our final rules allow the reviewing authority the ability to make this determination after the public comment

process.
7. Can Clean Unit Status Be Made Using the Title V Permitting Process?

We proposed that for sources that had not undergone major NSR, Clean Unit status would occur as part of the title V permitting process. Although a few commenters support this concept, several State and local agency commenters strongly disagree. These

commenters believe that title V is an appropriate mechanism for documenting Clean Units, but that the process for certifying sources should be separate from title V to avoid delays in title V permitting.

We agree with these commenters, and today are promulgating provisions that an emissions unit may be designated as a Clean Unit once it has gone through major NSR or another SIP-approved permitting program that provides for public notice and opportunity for comment. This allows the reviewing authority the flexibility to use the permitting process that it believes is most appropriate to make a Clean Unit status determination. However, once

Clean Unit status has been established through a SIP-approved permitting program, it must be incorporated into the title V permit. See section V.C.7 for a discussion of this process.

VI. Pollution Control Projects

A. Description and Purpose of This

Action

Our policy is to promote pollution control and prevention projects whenever possible. Today we are finalizing a rule provision that would exclude from major NSR permitting requirements certain work practices and the installation of qualifying pollution control and pollution prevention projects. With these provisions, we are removing a regulatory disincentive that might otherwise prevent industry from undertaking pollution control and prevention measures that result in a net

environmental benefit. The ‘‘ Pollution Control Project Exclusion ’’(or ‘‘ PCP
Exclusion ’’ ) will allow the installation of certain projects that result in net

overall environmental benefits to avoid the permitting requirements of major

NSR for their collateral emissions increases that exceed the significant level. This action was proposed on July 23, 1996, and closely paralleled our existing policy memorandum 35 which, in effect, enabled a control project

exclusion for EUSGUs which wasimplemented under the electric utilityspecific NSR rule ( see 57 FR 32314,
hereinafter ‘‘ WEPCO PCP Exclusion ’’ ) to apply to all types of sources, and enabled qualifying pollution prevention projects to apply for an exclusion as well. This action will replace both the WEPCO PCP Exclusion and the July 1, 1994 policy guidance with a single, comprehensive NSR exclusion for all types of qualifying PCPs

—including add-on controls, switches to less polluting fuels, work practices, and pollution prevention projects. Morever, this final rule will minimize procedural delays in getting a PCP approved, while ensuring appropriate environmental protection.

We define a PCP as an activity, set of work practices, or project at an existing

emissions unit that reduces emissions of air pollution from the unit. The PCP Exclusion may be sought when a project is installed at an existing source where

it reduces the emissions rate of one air pollutant while causing an increase in emissions of a different, ‘‘ collateral ’’ pollutant. A common example of such a project is installation of a thermal incinerator, which forms NO X as a collateral pollutant while reducing VOC emissions. For evaluating the environmental impact of a collateral emissions increase, the source and reviewing authority will assess the

difference between the emissions unit ’ s post-change actual emissions and its pre-change baseline actual emissions.

This test is discussed in section II of today ’ s preamble. That increase is then weighed against the emissions decrease of the primary pollutant to determine whether the PCP, as a whole, provides

an environmental benefit. The source and reviewing authority also must ensure that the change does not cause or contribute to an air quality violation, that no ERCs are generated (through initial application of the PCP), and that any significant emissions increase of a nonattainment pollutant is accounted for with acceptable offsets or SIP measures. In performing the air quality analysis under this provision, the procedures established for conducting air quality analysis in conjunction with NSR permitting will be used.

This rule excludes the installation of qualifying PCPs

—including add-on control devices, raw material substitutions, work practices, process changes and other pollution prevention strategies

—from the definition of

‘‘ physical or operational change ’’within the definition of major modification in our Federal regulations ( e.g.
, § 52.21). We are also requiring that States adopt

the same exclusion in their NSR

programs.

The decision to make codifying changes to the existing WEPCO PCP Exclusion and the July 1, 1994 policy guidance draws largely from

recommendations of the CAAAC

Subcommittee on NSR Reform. The

members of the Subcommittee included representatives of State and Federal regulatory agencies, Federal natural resource managers, industry, and environmental and public health interest groups. The Subcommittee ’ s recommendations reflected the consensus of this balanced group of

stakeholders.

B. What We Proposed and How Today’s Action Compares To It

Our proposed PCP Exclusion provisions essentially restated the July 1, 1994 policy guidance, and incorporated a ‘‘ primary purpose ’’test as an initial hurdle for candidate PCPs.

The ‘‘ primary purpose ’’test would have limited the exclusion to those projects whose primary function is to reduce air pollution. The proposal, like the previous PCP Exclusion rule and policy guidance, maintained that the exclusion was not applicable to air pollution

controls and emissions associated with

the construction of a new emissions unit, nor to the replacement or reconstruction of an entire existing

emissions unit with a newer or different one. In addition, the fabrication, manufacture, or production of pollution control/prevention equipment and inherently less polluting fuels or raw materials would not, in and of themselves, qualify as a PCP. We also incorporated two safeguards that were taken directly from the WEPCO PCP Exclusion and the July 1, 1994 policy


### 80233 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

guidance. First, the reviewing authority would be required to determine that the

PCP is ‘‘ environmentally beneficial. ’’A second safeguard from our proposal would direct reviewing authorities to evaluate the air quality impacts of a proposed PCP and ensure that it does not cause or contribute to a NAAQS or PSD increment violation, or adversely impact an AQRV (such as visibility) that

has been identified for a Federal Class I area by an FLM and for which information is available to the general public.

We proposed specific add-on control technologies that would be considered presumptively ‘‘ environmentally

beneficial ’’based on their proven history of positive environmental impact. The proposal also allowed for fuel switches to less polluting fuels and substitutions to less potent ozone depleting substances (ODS) to be presumptively environmentally beneficial projects. For other pollution prevention projects and new add-on control technologies to qualify as a PCP, the proposal required the reviewing authority to determine that the project was environmentally beneficial and, additionally for new add-on control devices, that they be ‘‘ demonstrated in practice. ’’

We received comments on every key aspect of the proposed PCP Exclusion. Although most parties support the PCP Exclusion, their suggestions regarding implementation of the exclusion vary considerably. Industry commenters generally desire maximum flexibility, and suggest extending the exclusion to cross-media control projects, limiting

the ‘‘ environmentally beneficial ’’and

‘‘ primary purpose ’’requirements, allowing for the generation of ERCs from PCPs, and broadening which pollution prevention projects qualified. Other commenters, including State agencies and environmental organizations, generally favor a more restrictive approach that involves more agency oversight and creates more enforceable

mechanisms to ensure that the

exclusion would not be abused. All comments are specifically addressed in the Technical Support Document.

Today ’ s rule revises the proposed PCP Exclusion in several ways, including the following.

• Eliminating the ‘‘ primary purpose ’’ requirement.

• Expanding the list of presumptively environmentally beneficial projects to include additional control technologies and strategies.

• Enabling projects that otherwise are

PCPs and result in utilization increases to qualify for the exclusion. • Using an actual-to-projected-actual format for determining emissions changes for all source categories to

demonstrate net environmental benefit supplemented by air quality analysis under certain circumstances, regardless of their projected emissions increases resulting from utilization.

• Clarifying that the replacement, reconstruction, or modification of an existing emissions control technology could qualify for the exclusion.

• Detailing the calculations for determining whether a switch to a different ODS is environmentally

beneficial.

• Changing the visibility component of the air quality analysis to ‘‘ an air quality related value (such as visibility)

that has been identified for a Federal Class I area by a FLM, and for which information is available to the general public ’’

.

• Identifying which fuel switches are presumed ‘‘ inherently less polluting ’’

.

• Enabling work practice standards to qualify for the exclusion.

• Clarifying that modeling for air quality impacts analyses may use projected actual emissions.

• Detailing proper noticing requirements for listed projects to use

this exclusion.

• Describing in detail the process forgranting the PCP Exclusion for nonlisted control technologies and pollution prevention strategies.

• Disqualifying projects that cannot secure acceptable offsetting emissions

reductions or SIP measures for PCPs resulting in a significant net increase of a nonattainment pollutant.

• Disallowing generation of netting

and offset credits from the initial application of PCPs that qualify for this

exclusion.

• Clarifying that non-air pollution impacts will not be considered in the

‘‘ environmentally beneficial ’’
determination.

By today ’ s action we are superseding the PCP regulatory exclusion that applied only to EUSGUs. Today ’ s action covers all types of sources, including EUSGUs. The new, broader PCP Exclusion will ensure equitable treatment of all source categories and remove any disincentive for companies that wish to install pollution control and pollution prevention projects, to the extent allowed by the CAA. Thus, owners or operators of EUSGUs who want a PCP Exclusion may, like any other source category, use the expanded

definition of ‘‘ pollution control project, ’’ which includes the lengthened list of environmentally acceptable control devices. Despite today ’ s rule revisions addressing a broader array of pollution control and pollution prevention projects at a larger variety of sources, we

feel that the rule ’ s procedures are less complex than and are clearer than the WEPCO PCP Exclusion and the July 1, 1994 policy guidance. We are satisfied

that the final PCP Exclusion best achieves the goals of minimizing regulatory burden and reducing procedural delays for projects that

ensure net overall environmental protection.

1. Applicability

a. What types of projects may qualify for the PCP Exclusion? In the WEPCO PCP Exclusion, we

found that installation of add-on emissions control projects, switches to less polluting fuels, and certain clean coal demonstration projects could be
PCPs, ‘‘ unless the project renders the unit less environmentally beneficial. ’’ 57 FR 32319. Today ’ s rule affirms that these types of projects are appropriate candidates for the exclusion, and it expands the types of projects that can qualify to include installation of other control devices that were not previously listed in the regulations, as well as work practice standards and switches to less potent quantities of ODS. Some of the control technologies (for example, oxidation/absorption catalyst and biofiltration) listed in today ’ s revisions
were either not well known or not demonstrated in practice as of the

release of the WEPCO PCP Exclusion and the July 1, 1994 policy guidance exclusion; consequently, today ’ s rule brings the list of approved PCPs up to

date.

We believe that the overall net impact of installing and operating the listed add-on control systems is environmentally beneficial and that such projects are desirable from an environmental perspective. The add-on controls in the approved list historically have been applied to many different

kinds of sources to reduce emissions. They have been consistently used because it is generally understood that,

from an overall environmental perspective, these controls are effective in reducing emissions when they are applied to existing plants in a manner

consistent with standard and reasonable practices. Certain pollution prevention projects

—for example, fuel switches and

low-NO X burners

—are also presumed to be environmentally beneficial when properly applied. Consequently, as part of the exclusion for PCPs, we do not require a case-by-case ‘‘ environmentally

beneficial ’’demonstration for the

‘‘ listed ’’PCPs, as long as they are properly applied and site-specific

factors do not indicate that their


### 80234 Federal Register / Vol. 67, No. 251 / Tuesday, December 31, 2002 / Rules and Regulations

application would be environmentally harmful. Thus, the ‘‘ environmentally

beneficial ’’presumption created by the list may be rebutted. For companies wishing to install and operate non-listed PCPs, however, the process is more rigorous. In these cases, the reviewingauthority first must consider casespecific factors to determine whether the non-listed project results in a net

environmental benefit and then must provide an opportunity for, and respond to, public notice and comment before approving the project as a PCP.

b. Why does the PCP Exclusion not apply to greenfield sources?

Today ’ s rule restricts applicability of the PCP Exclusion to physical changes being made at existing sources. Installing or implementing a project on an existing source is more likely to improve the environment than is the construction of a new source, since one can reasonably expect a PCP to reduce overall emissions, barring a

considerable utilization increase. New sources, however, introduce new emissions to the air without reducing existing emissions, and consequently should be as clean as possible. Furthermore, new emissions units are among the major capital investments in industrial equipment, which are the very types of projects that Congress

intended to address in the NSR provisions when such projects result in

an overall emissions increase from the major stationary source. Thus, when

emissions from a new source exceed the significant level, they are subject to NSR, and all emissions that are generated from the new project should be addressed in the major NSR permit evaluation for the major stationary

source.

c. Does the PCP Exclusion apply to rebuilt or upgraded control devices?

We are clarifying in today ’ s rule that upgrading or replacing existing emissions control equipment with a more effective emissions control project can qualify for the PCP Exclusion. However, the new PCP would have to

result in a level of control more stringent than the original control equipment, in terms of emissions rate or output-based emissions rate, such as upgrading a scrubber to increase removal efficiency. Another example that would qualify is a control device

that achieves an emissions reduction equivalent to that of the original device, but is more energy efficient. An example

of this is the conversion of a thermal oxidizer to a catalytic oxidizer. As long as the catalytic oxidizer achieved emissions control equivalent to that of the thermal oxidizer, it would qualify for a PCP Exclusion since it reduces

energy use.

2. Environmental Benefits

a. What projects do we presume to be environmentally beneficial?

Commenters recommend that we expand the list of presumptively environmentally beneficial projects to

include other add-on control technologies that are commonly used to reduce emissions at major stationary sources. We agree with this recommendation and have expanded the list of presumptively environmentally beneficial PCPs accordingly in today ’ s rule.

We presume the projects listed in Table 2 are environmentally beneficial.

We based our decision to add certain projects to the list on two criteria: (1)

The PCP is ‘‘ demonstrated in practice ’’ ; and (2) its overall effectiveness in reducing emissions of the primary pollutant(s) when balanced against its potential for emissions increases of collateral pollutant(s).



### TABLE 2.—E NVIRONMENTALLY 

### B ENE



### FICIAL 

### P OLLUTION 

### C ONTROL


### P ROJECTS

Control device/PCP Pollutant
controlled

Conventional & advanced flue

gas desulfurization. SO 2

Sorbent injection
Electrostatic precipitators ............ Particulates

and

otherpollutants. Baghouses High efficiency multiclones

Scrubbers Flue gas recirculation ................. NO X Low-NO X burners or combustors Selective non-catalytic reduction Selective catalytic reductionLow emission combustion (for internal combustion engines) oxidation/absorption catalyst

(e.g., SCONO X TM) Regenerative thermal oxidizers .. VOC and

HAP. Catalytic oxidizers

Thermal incinerators Hydrocarbon combustion

flares 36

Condensers

Absorbers & adsorbers

Biofiltration 

### TABLE 2.—E NVIRONMENTALLY 

### B ENE



### FICIAL 

### P OLLUTION 

### C ONTROL


### P ROJECTS

### —Continued

Control device/PCP Pollutant
controlled

Floating roofs (for storage vessels)

36 For the purposes of these rules, ‘‘Hydrocarbon combustion flare’’ means either a flare used to comply with an applicable NSPS or MACT standard (including use of flares during startup, shutdown, or malfunction permitted under such a standard), or a flare that serves
to control emissions from waste streams comprised predominantly of hydrocarbons andcontaining no more than 230 mg/dscm hydrogen sulfide.

Other presumed environmentally

beneficial PCPs include activities or projects undertaken to accommodate: (1) switching to different ODS with a less damaging ozone-depleting effect (factoring in its ozone depletion potential and projected usage); and (2) switching to an inherently less polluting fuel, to be limited to the following.

• Switching from a heavier grade of fuel oil to a lighter fuel oil, or any grade of oil to 0.05 percent sulfur diesel. (that is, from a higher sulfur content #2 fuel, or from #6 fuel, to CA 0.05 percent sulfur #2 diesel)

• Switching from coal, oil, or any solid fuel to natural gas, propane, or gasified coal.

• Switching from coal to wood, excluding construction or demolition waste, chemical or pesticide treated wood, and other forms of ‘‘ unclean ’’
wood

• Switching from coal to #2 fuel oil (0.5 percent maximum sulfur content)

• Switching from high sulfur coal to low sulfur coal (maximum 1.2 percent sulfur content)

We are presuming that the application of a PCP listed above is environmentally beneficial and would be eligible for a PCP Exclusion. This presumption is premised on an understanding that you will design and operate the controls in a manner that is consistent with proper industry, engineering, and reasonable practices, and that you minimize increases in collateral pollutants within the physical configuration and operational standards usually associated

with the emissions control device or strategy. You will be required to certify that this is true in the notification you send your reviewing authority.

As stated before, the

‘‘ environmentally beneficial ’’ determination is a presumption, so it

can be rebutted in cases in which a reviewing authority determines that a particular proposed PCP project would not be environmentally beneficial. Also,