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

Federal RegisterDec 31, 2002

Ask Donna

What actually matters in this document.

Text

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

NAICS

Electric Services

491

221111, 221112, 221113, 221119, 221121, 221122

Petroleum Refining

291

32411

Chemical Processes

281

325181, 32512, 325131, 325182, 211112, 325998, 331311, 325188

Natural Gas Transport

492

48621, 22121

Pulp and Paper Mills

261

32211, 322121, 322122, 32213

Paper Mills

262

322121, 322122

Automobile Manufacturing

371

336111, 336112, 336712, 336211, 336992, 336322, 336312, 33633, 33634, 33635, 336399, 336212, 336213

Pharmaceuticals

283

325411, 325412, 325413, 325414

Standard Industrial Classification

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

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

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.

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.)

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

operation within the definition of major modification.

See

40 CFR 52.21(b)(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.

This regulatory framework applies the major NSR program at existing sources to only “major modifications” at major stationary sources.

See

40 CFR 52.21(b)(23).

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.

In order to trigger applicability of the major NSR program, the net emissions increase must be “significant.”

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).

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).

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 of enforceable restrictions to pre-modification 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).

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.

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).

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

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/nsr-review/.

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, the relevant terminology for calculating pre-change 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 type test within the new actual-to-projected-actual 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-to-projected-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

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-of-the-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 existing emissions units. (Including an actual-to-potential 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

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.

“Enforceable as a practical matter” will be achieved if a requirement is both legally and practically enforceable.

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.

The Agency has frequently used the term “practicably enforceable” and “practical enforceability,” interchangeably. There is no difference in the meaning of these terms.

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.”

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.

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.

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

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.

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 new procedure for determining your pre-change baseline actual emissions will not apply to EUSGUs.

Instead, for EUSGUs we are retaining the existing procedures for determining the baseline actual emissions.

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).

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)(

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.

We promulgated special applicability rules for physical and operational changes at EUSGUs in 1992.

See

57 FR 32314 (July 21, 1992).

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 pre-change 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

operation.”

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.”

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.

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.

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.

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 pre-change (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

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 original method (that was part of the actual-to-potential 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 extend the availability of the actual-to-future-actual 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.

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.

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-to-future-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-to-projected-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

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 post-change 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 your projections or track or report post-change 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-to-projected-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.

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.

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 the availability of the actual-to-projected-actual 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.

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.

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-to-potential” 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.

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.

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

) (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.

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)(

). 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 pre-change 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 applies to EUSGUs (that is, the actual-to-representative-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

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 criteria are met: (1) You elect to project post-change 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.

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.

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)(

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

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,

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.

Letter from John S. Seitz, Director, Office of Air Quality Planning and Standards, to Patrick M. Raher, August 6, 2001.

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 the option of extending the actual-to-future-actual 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 for sources to use for projecting the post-change 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)(

), and 52.21(a)(2)(vi)(

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 the previous 10 years (as required for non-EUSGUs).

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

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.

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,

and thus, we have utilized different emissions tests in the NSR programs. Prior to today, the regulations applied an actual-to-future-actual 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-to-projected-actual applicability test for all other emissions units. We believe that establishing an actual-to-projected-actual applicability test for all emissions units is a reasonable interpretation of the phrase “increase of any pollutant emitted.”

See, for example, WEPCO Rule, 57 FR 32316 (“fundamental distinctions between the technology-based provisions of NSPS and the air quality-based provisions of NSR”). See also

ASARCO Inc.

EPA,

578 F.2d 319 (D.C. Cir. 1978).

The explanation of the applicability test for “Clean Units” is discussed in section V.

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-future-actual 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.

This study found that, for the

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.

“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

for the years 1982 to 1994 inclusive, based on the Office of Management and Budget's SIC codes for individual industries (OMB, 1987).

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 PSD permit program so that they may re-evaluate 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)(

). 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 any given data should be left to the case-by-case 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

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-month period is consistent with the pre-existing 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

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 is projected using the new actual-to-projected-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.

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.

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.

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

be calculated. The same commenters who support retaining demand growth provisions for utilities also believe these provisions should be extended to non-utilities.

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)(

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-to-enforceable-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-to-potential 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 commenters support the use of the actual-to-potential 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. Other commenters oppose using the actual-to-future-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

“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 reviewing authority whenever the actual-to-future-actual 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

) and 85 percent of this nation's emissions of SO

from stationary sources.

Information supporting these values can be found in the docket for today's rulemaking.

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 are also requiring them to report their post-change 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

your facility has undertaken a modification based on the facility's pre-change 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-to-potential 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. One commenter states that the potential-to-potential 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 more equitable than the existing actual-to-potential approach, which results in the capture of a source's unused capacity. These commenters prefer the potential-to-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

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, it provides an incentive to use state-of-the-art 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

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.

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.

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,

which otherwise can occur under our existing regulations.

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.

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

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);