Findings of Significant Contribution and Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport

Availability of Related Information

The official record for this rulemaking, as well as the public version, has been established under docket number A-97-43 (including comments and data submitted electronically as described below). A public version of this record, including printed, paper versions of electronic comments, which does not include any information claimed as CBI, is available for inspection from 8 a.m. to 4 p.m., Monday through Friday, excluding legal holidays. The official rulemaking record is located at the address in ADDRESSES at the beginning of this document. Electronic comments can be sent directly to EPA at: A-and-R- Docket@epamail.epa.gov. Electronic comments must be submitted as an ASCII file avoiding the use of special characters and any form of encryption. Comments and data will also be accepted on disks in WordPerfect in 5.1 file format or ASCII file format. All comments and data in electronic form must be identified by the docket number A-97- 43. Electronic comments on this NPR rule may be filed online at many Federal Depository Libraries. The EPA has issued a separate rule on NOX transport entitled, ``Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone'' (see notices included in the docket for this rulemaking). The rulemaking docket for that rule, hereafter referred to as the NOX State implementation plan (SIP) call (NOX SIP call), contains information and analyses that are relied upon in today's proposal on the section 126 petitions. Therefore, EPA is incorporating by reference the entire NOX SIP call record for purposes of the section 126 rulemaking. Documents related to the NOX SIP call rulemaking are available for inspection in Docket No. A-96-56 at the address and times

given above. In addition, the proposed NOX SIP call and associated documents are located at www.epa.gov/ttn/oarpg/ otagsip.html. The EPA is finalizing action on the NOX SIP call concurrently with today's proposal on the section 126 petitions. Additional information relevant to this NPR concerning the Ozone Transport Assessment Group (OTAG) is available on the Agency's Office of Air Quality Planning and Standards' (OAQPS) Technology Transfer Network (TTN) via the web at www.epa.gov/ttn/. If assistance is needed in accessing the system, call the help desk at (919) 541-5384 in Research Triangle Park, NC. Documents related to OTAG can be downloaded directly from OTAG's webpage at www.epa.gov/ttn/otag. The OTAG's technical data are located at www.iceis.mcnc.org/OTAGDC.

For Additional Information

For additional information related to air quality analysis, please contact Carey Jang, Office of Air Quality Planning and Standards; Emissions, Monitoring, and Analysis Division, MD-14, Research Triangle Park, NC 27711, telephone (919) 541-5638. For legal questions, please contact Howard Hoffman, Office of General Counsel, 401 M Street SW, Mc- 2344, Washington, DC, 20460, telephone (202) 260-5892. For questions regarding the NOX cap-and-trade program, please contact Melanie Dean, Office of Atmospheric Programs, Acid Rain Division, MC- 6204J, 401 M Street SW, Washington, DC 20460, telephone (202) 564-9189. For questions regarding regulatory cost analyses for electricity generating sources, please contact Ravi Srivastava, Office of Atmospheric Programs, Acid Rain Division, MC-6204J, 401 M Street SW, Washington, DC 20460, telephone (202) 564-9093. For questions regarding regulatory cost analyses for other stationary sources, please contact Scott Mathias, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, MD-15, Research Triangle Park, NC 27711, telephone (919) 541-5310.

Outline

I. Background A. Summary of Rulemaking B. Ozone Transport, Ozone Transport Commission NOX Memorandum of Understanding (OTC NOX MOU), OTAG, the NOX SIP Call, the Revised Ozone National Ambient Air Quality Standard, and Ozone Effects C. Section 126 D. Summary of Section 126 Petitions 1. Control Remedies Recommended By Petitions 2. Sources Covered By Petitions E. Litigation on Rulemaking Schedule F. Advance Notice of Proposed Rulemaking on Petitions II. EPA's Analytical Approach and Proposed Action on Petitions A. EPA's Proposed Interpretation of Section 126 and Analytical Approach for Determining Whether to Grant or Deny the Petitions 1. The Appropriate Test under Section 126 2. EPA's Analytical Approach for Determining Whether to Grant or Deny the Petitions a. EPA's Interpretation of Significant Contribution under Section 110 b. Applying EPA's Section 110 Interpretation of ``Significant Contribution'' and ``Interference'' under Section 126 c. Emitting ``In Violation of the Prohibition'' in Section 110-- the Decision Whether to Grant or Deny Each Petition B. Weight of Evidence Determination of Named Upwind States C. Cost-Effectiveness of Emissions Reductions 1. What NOX Controls Are Highly Cost Effective 2. Determining the Cost Effectiveness of NOX Controls i. Large EGUs ii. Large Non-EGUs iii. Legal Process Heaters iv. Small Sources v. Summary of Control Measures 3. Other Cost-Related Considerations D. Identifying Sources E. Air Quality Assessment F. Conclusions on Granting or Denying Petitions 1. Technical Determinations 2. Action on Whether to Grant or Deny Each Petition a. Portions of Petitions For Which EPA is Proposing an Affirmative Technical Determination b. Portions of Petitions For Which EPA is Proposing An Negative Technical Determination 3. Requirements for Sources for Which EPA Makes a Section 126(b) Finding III. Federal NOX Budget Trading Program A. Program Summary 1. Purpose of the Federal NOX Budget Trading Program 2. Relationship of Section 126 Remedy to the NOX SIP Call and the FIP B. Federal NOX Budget Trading Program 1. Program Overview 2. Elements of the Federal NOX Budget Trading Program That Are the Same as the State NOX Budget Trading Program a. General Provisions b. Authorized Account Representative c. Permits d. Compliance Certification e. NOX Allowance Tracking System f. Banking g. NOX Allowance Transfers h. Audits 3. Elements of the Federal NOX Budget Trading Program That Differ from the State NOX Budget Trading Program a. General Provisions i. Purpose ii. Definitions iii. Applicability iv. Standard Requirements b. Compliance Certification c. Aggregate NOX Emissions Levels and Allowance Allocations i. Data Sources (1) EGUs (2) Non-EGUs ii. Methodology Used to Determine Controlled Emission Levels (1) Large EGUs (2) Large Non-EGUs iii. Development of Section 126 Trading Program Budget iv. Timing Provisions v. NOX Allowance Allocation Methodology (1) EGUs (2) Non-EGUs (3) Treatment of New Sources d. Compliance Supplement Pool i. Size of Compliance Supplement Pool ii. Distribution of Compliance Supplement Pool to Sources e. Emissions Monitoring and Reporting f. Opt-ins g. Program Administration C. New Source Review IV. Non-ozone Benefits to NOX Reductions V. Administrative Requirements A. Executive Order 12866: Regulatory Impact Analysis B. Impact on Small Entities 1. Regulatory Flexibility 2. Outreach to Small Entity Representatives 3. Potentially Affected Small Entities 4. Panel Findings and EPA Actions a. Exemptions b. Continuous Emissions Monitoring Systems (CEMS) c. Electricity Generating Units d. Industrial Boilers e. EPA Guidance to States on Small Entities C. Unfunded Mandates Reform Act D. Paperwork Reduction Act E. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks 1. Applicability of Executive Order 13045 2. Childrens' Health Protection F. Executive Order 12898: Environmental Justice G. Executive Order 12875: Enhancing the Intergovernmental Partnership H. Executive Order 13084: Consultation and Coordination with Indian Tribal Governments I. National Technology Transfer and Advancement Act

I. Background

A. Summary of Rulemaking

In today's action, EPA is proposing to make a technical determination that certain major stationary sources and source categories identified in the section 126 petitions are significantly contributing to nonattainment in, or interfering with maintenance by, one or more petitioning State with respect to one or more of the national ambient air quality standards for ozone (hereafter

referred to as a positive or affirmative technical determination). On the basis of that proposed affirmative technical determination, EPA is proposing that the petitions naming these sources and source categories be granted or denied at certain later dates pending certain actions by the States and EPA regarding State submittals in response to the final NOX SIP call. The schedule and conditions under which the applicable final findings on the petitions would be triggered are discussed below in Section II.F. The EPA's analysis of significant contribution is discussed in Section II below. Under the 1-hour ozone standard, EPA is proposing to make affirmative technical determinations as to a subset of sources and source categories named in the petitions from Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, and Rhode Island. The source categories for which EPA is proposing this affirmative technical determination of significant contribution are discussed in Section II. The existing sources that are affected by this technical determination are listed in appendix A to proposed part 97. The EPA is also proposing to partially deny the petitions from Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, and Rhode Island because EPA believes some of the sources or source categories named in the petitions are not significantly contributing to nonattainment in the relevant petitioning State with respect to the 1-hour ozone standard. The EPA is proposing to deny the Vermont petition in full with respect to the 1-hour ozone standard because the 1-hour standard no longer applies in that State (See 63 FR 31014). Three of the petitioners, Massachusetts, Pennsylvania, and Vermont, also directed their petitions at the new 8-hour ozone standard. Under the 8-hour ozone standard, EPA is proposing to make a positive technical determination as to a subset of sources named in the petitions from Massachusetts and Pennsylvania. The source categories for which EPA is proposing this affirmative technical determination of significant contribution are discussed in Section II. The existing sources that are affected by this technical determination are listed in appendix A to proposed part 97. The EPA is proposing to deny the Vermont petition in full with respect to the 8-hour ozone standard because Vermont has no current 8-hour ozone nonattainment problems and no future projected nonattainment problems based on available analyses. In aggregate for all petitions and both ozone standards, the sources and source categories that EPA is proposing to find significantly contribute to nonattainment in, or interfere with maintenance by, (hereafter simply contribute significantly to) one or more of the petitioning States are located in the following States: Alabama, Connecticut, Delaware, District of Columbia, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, Tennessee, Virginia, and West Virginia. The combined list of existing sources affected by a positive technical determination with respect to at least one petition, along with proposed emissions limitations in the form of tradable allowance allocations, is located in Appendix A to proposed part 97. The EPA intends to update the list of affected sources on a periodic basis to include new sources in the source categories that are significantly contributing. Some of the sources that EPA is proposing do not significantly contribute to the petitioning States may be located in States that are affected by a separate rulemaking on NOX transport, the NOX SIP call. While emissions from sources in certain States may not be significantly contributing to nonattainment or maintenance problems in any of the eight petitioning States, the sources may be significantly contributing to nonattainment problems in other downwind States. In acting on these section 126 petitions, EPA can only consider the impacts on downwind nonattainment problems in the petitioning States, which are all located in the Northeast. In the NOX SIP call, EPA considered impacts on nonattainment problems throughout the eastern half of the United States. Therefore, a determination that sources in certain States are not significantly contributing for purposes of this action on the section 126 petitions should not be assumed to reflect EPA's conclusions on significant contribution with regard to the NOX SIP call or other transport-related rulemakings. The section 126 petitions varied with regard to the control requirements they recommend for mitigating the interstate transport. While EPA considered the recommendations, section 126 does not limit EPA to the recommended controls in determining an appropriate remedy. In Section III, EPA proposes the emissions limitations that would be necessary to ensure that the affected sources do not or would not emit in violation of the applicable statutory prohibition on significant contribution by upwind States to downwind air quality problems. The control remedy is based on the uniform application of highly cost- effective controls (as determined based on cost per ton of NOX reduced for each type of source). In selecting the control measures, EPA considered the recommendations made by OTAG on July 8, 1997 and the analyses for the NOX SIP call. The EPA considered controls that would effectively minimize emissions while not exceeding a source-categorywide $2000 per ton for reductions of ozone season NOX (in 1990 dollars), on average, for each source category. For electricity generating units larger than 25 MWe, EPA is proposing a control level corresponding to 0.15 lb/mmBtu. For industrial boilers and turbines greater that 250 mmBtu/hr, EPA is proposing a control level corresponding to a 60 percent reduction from an uncontrolled baseline. For small sources and process heaters, EPA is proposing no additional controls. For purposes of this rulemaking, EPA is defining small sources as: (1) Electricity generating boilers and turbines serving a generator 25 MWe or less, and (2) other indirect heat exchangers with a heat input of 250 mmBtu/hr or less. The control requirements are consistent with the assumptions used in developing the final budgets for the NOX SIP call. Further discussion concerning small point sources can be found in Section II of this preamble. The EPA intends to implement the control requirements through a Federal NOX cap-and-trade program, which is described in Section III. The EPA believes a trading program is the most cost- effective approach for achieving emissions reductions from large stationary sources. The proposed trading program is consistent with the model trading rule that EPA is finalizing for purposes of the NOX SIP call, except for changes necessary to account for Federal implementation instead of State implementation. The EPA envisions that there would be a common trading program among section 126 sources and NOX SIP call sources in States that choose to participate in the State trading program, and sources subject to a Federal implementation plan under the NOX SIP call. In accordance with section 126, sources must comply with the control requirements no later than 3 years from a final positive finding on the petitions, on a schedule to be determined by the EPA Administrator. The EPA is proposing that the full 3 years is necessary for compliance. As discussed below, EPA is proposing that the technically meritorious portions of the

petitions be deemed granted or denied at certain later dates, pending certain actions by States and EPA regarding implementation plans required in response to the NOX SIP call. The EPA intends to take final action by April 30, 1999 on the technical determination described above, the decision as to when each portion of the petitions would be deemed granted or denied, and the emissions limitations that would apply to any sources for which a petition is ultimately deemed granted.

B. Ozone Transport, Ozone Transport Commission NOX Memorandum of Understanding (OTC NOX MOU), OTAG, the NOX SIP Call, the Revised Ozone National Ambient Air Quality Standard (NAAQS), and Ozone Effects

Today's action occurs against a background of a major national effort, spanning at least the last 10 years, to analyze and take steps to mitigate the problem of the transport of ozone and its precursors across State boundaries. This effort has grown more intensive in the past several years with the approval of the OTC NOX MOU by 11 of the Northeastern States and the District of Columbia included in the Northeast Ozone Transport Region (OTR), the completion of the OTAG process (described below), and the publication of EPA's proposed NOX SIP call. In addition, on July 18, 1997, EPA issued a revised NAAQS for ozone, for which is determined over an 8-hour period (the 8-hour standard) (62 FR 38856). In establishing the 8-hour standard, EPA is setting the standard at 0.08 parts per million and defines the new standard as a ``concentration-based'' form, specifically the 3-year average of the annual 4th-highest daily maximum 8-hour ozone concentrations. This has resulted in more areas and larger areas with monitoring data indicating nonattainment. Thus, it is even more important to implement regional control strategies to mitigate interstate pollution in order to assist downwind areas in achieving attainment. This new 8-hour standard must now be taken into account, along with the pre-existing 1-hour standard, in resolving transport issues. These issues and events are detailed in the proposed NOX SIP call (62 FR 60318) and familiarity with that notice is assumed for purposes of today's notice. In addition, in many areas of the country, the 1-hour standard has been revoked because the areas are attaining that standard (63 FR 31013; June 5, 1998 and 63 FR 39432, July 22, 1998). A State may petition under section 126 for the both the 1-hour standard, to the extent that it still applies in the petitioning State, and the 8-hour standard. The 1990 CAA set forth many requirements to address nonattainment of the 1-hour ozone NAAQS. Many States have found it difficult to demonstrate attainment of the NAAQS due to the widespread transport of ozone and its precursors. The Environmental Council of the States (ECOS) recommended formation of a national work group to allow for a thoughtful assessment and development of consensus solutions to the problem. This work group, OTAG, was established 3 years ago to undertake an assessment of the regional transport problem in the eastern half of the United States. The OTAG was a collaborative process conducted by representatives from the affected States, EPA, and interested members of the public, including environmental groups and industry, to evaluate the ozone transport problem and develop solutions. The OTAG region included the 37 eastern-most States and the District of Columbia. Through the OTAG process, the States concluded that widespread NOX reductions are needed in order to enable areas to attain and maintain the ozone NAAQS. Based on information generated by OTAG and other available data, EPA determined that certain States in the OTAG region were significantly contributing to nonattainment problems in downwind States. Therefore, EPA issued a proposed NOX SIP call requiring the States to revise their SIPs to include NOX control measures to mitigate the ozone transport. The EPA is finalizing the NOX SIP call in the same timeframe as this proposal on the section 126 petitions. The EPA's response to the section 126 petitions differs from EPA's action in the NOX SIP call rulemaking in several ways. In the NOX SIP call, where EPA concludes that NOX emissions from a State are significantly contributing to nonattainment problems in downwind States, EPA will require the State to submit SIP provisions to prohibit an amount of NOX emissions which represents the significant contribution. The State will have the discretion to select the mix of controls measures for their sources to meet the required statewide NOX reduction reductions. If the State does not make the required SIP submission, EPA is required to promulgate a Federal implementation plan (FIP) within 2 years of the State failure. In the November 7, 1997 NOX SIP call proposal, EPA announced that it intended to expedite the FIP promulgation in order to assure that the downwind States receive the air quality benefits of regional NOX reductions as soon as practicable. Therefore, the EPA is proposing FIPs for all the States affected by the NOX SIP call in conjunction with EPA's issuance of the final NOX SIP call. By comparison, section 126 petitions are limited to addressing emissions from upwind stationary sources and not other sectors of the inventory. If EPA grants the petitions, it is EPA, not the States, that promulgates control requirements for the sources. The control remedy for sources in the section 126 petitions that EPA is proposing in this action is consistent with the control assumptions EPA used for these sources in determining reductions projected to meet the final statewide NOX budgets for States subject to the NOX SIP call. Because the NOX SIP call process overlaps considerably with the section 126 petition process, in that they both address NOX transport in the eastern United States, EPA believes it is important to coordinate the two actions as much as possible. As discussed below, EPA and the petitioning States developed a proposed consent decree on the rulemaking schedule for the petitions that takes into consideration the NOX SIP call rulemaking. All of the States that submitted section 126 petitions are included in the OTR and participated in the OTAG process. In addition, all of the upwind sources identified in the petitions are located in the OTAG region. All eight petitions rely, in part, on the OTAG analyses for technical justification. The OTAG process concluded in June 1997 prior to the promulgation of the new 8-hour ozone standard and, therefore, the OTAG analyses focused on the 1-hour standard. All the petitions request relief under the 1-hour standard. Three of the petitions also request relief under the new 8-hour standard. In acting on the section 126 petitions, EPA believes that it can only consider 8-hour nonattainment problems for the petitioning States that expressly requested relief under that standard. Under the NOX SIP call, EPA considered both 1-hour and 8-hour nonattainment problems throughout the OTAG region. Ground-level ozone, the main harmful ingredient in smog, is produced in complex chemical reactions when its precursors, volatile organic compounds (VOCs) and NOX, react in the presence of sunlight. The chemical reactions that create ozone take place while the pollutants are being blown through the air by the wind, which means that ozone can be more severe many miles away from the source of emissions than it is at the source.

At ground level, ozone can cause a variety of ill effects to human health, crops and trees. Specifically, ground-level ozone induces the following health effects: • Decreased lung function, primarily in children active outdoors, • Increased respiratory symptoms, particularly in highly sensitive individuals, • Hospital admissions and emergency room visits for respiratory causes, among children and adults with pre-existing respiratory disease such as asthma, • Inflammation of the lung, • Possible long-term damage to the lungs. The new 8-hour primary ambient air quality standard will provide increased protection to the public from these health effects. Each year, ground-level ozone above background is also responsible for several hundred million dollars worth of agricultural crop yield loss. It is estimated that full compliance of the newly promulgated ozone NAAQS will result in about $500 million of prevented crop yield loss. Ozone also causes noticeable foliar damage in many crops, trees, and ornamental plants (i.e., grass, flowers, shrubs, and trees) and causes reduced growth in plants. Studies indicate that current ambient levels of ozone are responsible for damage to forests and ecosystems (including habitat for native animal species).

C. Section 126

Subsection (a) of section 126 requires, among other things, that SIPs require major proposed new (or modified) stationary sources to notify nearby States for which the air pollution levels may be affected by the fact that such sources have been permitted to commence construction. Subsection (b) provides:

Any State or political subdivision may petition the Administrator for a finding that any major source or group of stationary sources emits or would emit any air pollutant in violation of the prohibition of section 110(a)(2)(D)(ii) * * * or this section.

Subsection (c) of section 126 states that--

[I]t shall be a violation of this section and the applicable implementation plan in such State [in which the source is located or intends to locate]-- (1) For any major proposed new (or modified) source with respect to which a finding has been made under subsection (b) of this section to be constructed or to operate in violation of the prohibition of section 110(a)(2)(D)(ii) * * * or this section, or (2) For any major existing source to operate more than three months after such finding has been made with respect to it.

However, subsection (c) further provides that EPA may permit the continued operation of such major existing sources beyond the 3-month period, if such sources comply with EPA-promulgated emissions limits within 3 years of the date of the finding. Section 110(a)(2)(D) provides the requirement that a SIP contain adequate provisions--

(i) Prohibiting, consistent with the provisions of this title, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will-- (I) Contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to [any] national * * * ambient air quality standard, or (II) interfere with measures required to be included in the applicable implementation plan for any other State under part C to prevent significant deterioration of air quality or to protect visibility. (ii) Insuring compliance with the applicable requirements of sections 126 and 115 (relating to interstate and international pollution abatement) * * *

As explained in detail in Section II.A., below, it is EPA's view that, with respect to existing stationary sources, sections 126(b)-(c) and 110(a)(2)(D), read together, authorize a downwind State to petition EPA for a finding that major stationary sources or groups of sources upwind of the State emit in violation of the prohibition of section 110(a)(2)(D)(i) because, among other reasons, their emissions contribute significantly to nonattainment, or interfere with maintenance, of a NAAQS in the State. If EPA grants the requested finding, the existing sources must shut down in 3 months unless EPA directly regulates the sources by establishing emissions limitations and a compliance period extending beyond 3 months but no later than 3 years from the finding. In accordance with section 302(j) of the CAA, the term major stationary source means ``any stationary facility or source which directly emits, or has the potential to emit, one hundred tons per year or more of any air pollutant. * * *'' For the purpose of this rulemaking the relevant pollutant is NOX emissions. The EPA acknowledges that others have urged different readings of sections 126(b)-(c) and 110(a)(2)(D) and EPA solicits comments thereon in this rulemaking, as described in Section II.A.1., below.

D. Summary of Section 126 Petitions

The petitions vary as to the type and geographic location of the source categories identified as significant contributors. All the petitions identified source categories; some petitions also provided lists of sources within the specified categories. The source categories include electric generating plants, fossil fuel-fired boilers and other indirect heat exchangers, and certain other related stationary sources that emit NOX. All the petitions target sources in the Midwest; some also target sources in the South and Northeast. The geographic area covered by each petition is shown in Figure 2. The EPA requests comment from the petitioning States as to whether EPA has correctly interpreted the geographic scope of their petitions. The petitions also vary as to the level of controls they recommend be applied to the sources to mitigate the transport problem. Several recommend EPA establish a 0.15 lb/mmBtu NOX emission limitation and several recommend that controls be implemented through a cap-and-trade program. The petitions are described in greater detail below. All of the petitions rely, in part, on OTAG analyses for technical support. In addition, the States submitted a variety of other technical analyses which include computerized urban airshed modeling, wind trajectory analyses, results of a transport study by the Northeast States for Coordinated Air Use Management, and culpability analyses. Table I-1 shows, by petitioner, the named source categories, the named geographic areas, and the requested remedy sought by the petitioning States. The named source categories are worded as they appear in the petitions. A map of the OTAG Subregions is provided in part 52, appendix F, Figure 1.

Table I-1.--EPA's Summary of Section 126 Petitions ---------------------------------------------------------------------------------------------------------------- State Named source categories Named States Requested remedy ---------------------------------------------------------------------------------------------------------------- CT................... Fossil fuel-fired boilers or Sources in OTAG Subregions Establish, at a minimum, other indirect heat 2, 6, and 7 and portion of emission limitations and a exchangers with a maximum OTR extending west and schedule of compliance gross heat input rate of 250 south of CT. Includes all consistent with the OTC NOX mmBtu/hr or greater and or parts of IN, KY, MI, NC, MOU, and a cap-and-trade electric utility generating OH, TN, VA, WV. And OTR program. Does not request facilities with a rated States DC, DE, MD, NJ, NY, remedy for OTR States output of 15 MW or greater. PA. because of OTC NOX MOU. ME................... Electric utilities and steam- Sources within 600 miles of Establish compliance generating units with a heat Maine's ozone nonattainmen schedule and emissions input capacity of 250 mmBtu/ t areas. Includes all or limitation of 0.15 lb/mmBtu hr or greater. parts of NC, OH, VA, WV, for electric utilities and and OTR States CT, DE, DC, the OTC NOX MOU level of MD, MA, NJ, NY, NH, PA, RI, control for steam VT. generating units, in a multi-state cap-and-trade NOX market system. MA................... Electricity generating Sources in region within 3 Establish emissions plants.. counties on either side of limitation of 0.15 lb/mmBtu the Ohio River in IN, KY, or 1.5 lb/MWh and a OH, WV. compliance schedule. NH................... Fossil fuel-fired indirect Sources in OTR States and Establish compliance heat exchange combustion OTAG Subregions 1 through schedule and emission units and fossil fuel-fired 7. Includes all or parts of limitations no less electric generating IL, IN, IA, KY, MI, MO, NC, stringent than: (a) Phase facilities which emit ten OH, TN, VA, WV, WI. Also III OTC NOX MOU reductions; tons of NOX or more per day. OTR States CT, DE, DC, MD, and/or (b) 85% reductions MA, ME, NJ, NY, PA, RI, VT. from projected 2007 baseline; and/or (c) An emission rate of 0.15 lb/ mmBtu. NY................... Fossil fuel-fired boilers or Sources in OTAG Subregions 2 Establish, at a minimum, indirect heat exchangers 6, and 7 and portion of OTR emission limitations and a with a maximum heat input extending west and south of schedule of compliance rate of 250 mmBtu/hr or NY. Includes all or parts consistent with the OTC NOX greater and electric utility of IN, KY, MI, NC, OH, TN, MOU, and a cap-and-trade generating facilities with a VA, WV. And OTR States DC, program. Does not request rated output of 15 MW or DE, MD, NJ, PA. remedy for OTR States greater. because of OTC NOX MOU. PA................... Fossil fuel-fired indirect AL, AR, GA, IL, IN, IA, KY, Establish emission heat exchange combustion LA, MI, MN, MS, MO, NC, OH, limitations and a units with a maximum rated SC, TN, VA, WV, WI. compliance schedule for a heat input capacity of 250 cap-and-trade program mmBtu/hr or greater, and requiring: (a) seasonal fossil fuel-fired electric reductions of the less generating facilities rated stringent of 55% from 1990 at 15 MW or greater. baseline levels, or 0.20 lb/ mmBtu, beginning by May 1999; (b) if necessary, seasonal reductions of the less stringent of 75% from 1990 baseline levels, or 0.15 lb/mmBtu, beginning by May 2003; (c) such additional reductions as necessary beginning in 2005. RI................... Electricity generating plants Sources in region within 3 Establish emissions counties on either side of limitation of 0.15 lb/mmBtu Ohio River in IN, KY, OH, or 1.5 lb/MWh and a WV. compliance schedule. VT................... Fossil fuel-fired electric Sources located within a Establish emissions utility generating geographic area extending limitation of 0.15 lb/mmBtu facilities with a maximum 1000 miles southwest from or 1.5 lb/MWh and a gross heat input rate of 250 Bennington, VT. Includes compliance schedule. Does mmBtu/hr or greater and all or parts of IL, IN, KY, not request remedy for OTR potentially other MI, NC, OH, TN, VA, WV. States because of OTC NOX unidentified major sources. Also AL GA, IA, MO, SC, WI. MOU. Also OTR States CT, DE, DC, MD, MA, NJ, NY, PA. ----------------------------------------------------------------------------------------------------------------

1. Control Remedies Recommended by Petitions The petitions vary regarding the remedy requested. Several of these petitions reference the OTC NOX MOU, with regard to control levels, affected sources, or compliance deadlines. All of the petitioning States were signatories on the OTC NOX MOU. The OTC NOX MOU commits these States (and the 4 other signatory parties--New Jersey, Maryland, Delaware, and the District of Columbia) to reductions in ozone season NOX emissions from large utility and industrial combustion sources through implementation of a phased-in regionwide cap-and-trade program. Specifically, affected sources in the OTR are fossil fuel-fired boilers and other indirect heat exchangers with a maximum rated heat input capacity of 250 mmBtu/ hr or greater, and electric generating facilities with a rated output of 15 megawatts (MW) or greater. The OTC NOX MOU established emissions reduction requirements for these sources in the OTR, creating emissions budgets for 1999 (Phase II) and 2003 (Phase III). (Phase I required the installation of reasonably available control technology (RACT) by May 1995.) The requirements vary across three control zones in the region: an inner zone ranging from the District of Columbia metropolitan area northeast to southeastern New Hampshire (covering all contiguous moderate and above nonattainment areas), an outer zone ranging out from the inner zone to western Pennsylvania, and a northern zone which includes much of northern New York and northern New England (including most of New Hampshire). For Phase II of the OTC NOX MOU, which begins in 1999, sources in the inner zone are subject to emissions reduction requirements based on the less stringent of an emission rate of 0.20 pounds NOX per million British thermal units of heat input (lb/mmBtu), or a 65 percent reduction from 1990 NOX levels; sources in the outer zone are subject to emissions reduction requirements based on the less stringent of a 0.20 lb/mmBtu rate, or a 55 percent reduction from 1990 NOX levels; and

sources in the northern zone must adopt RACT. The Phase III requirements, which may be altered by a ``mid-course correction'' based on new information such as refined air quality modeling, establish emissions reduction requirements based on the lesser of a 0.15 lb/mmBtu rate, or a 75 percent reduction from 1990 levels for sources in both the inner and outer zones. Northern zone sources would face emissions reduction requirements based on the lesser of a 0.20 lb/mmBtu rate, or a 55 percent reduction from 1990 levels. In both Phase II and III in all three zones, electric generating facilities less than 250 mmBtu/hr but above 15 MW are subject only to a capping of emissions at 1990 levels for purposes of budget calculation. However, individual States determine specific allocations for each source from their overall budget based on independent allocation formulas, and thus the allocation for these sources will not necessarily reflect this level. Though all of the petitions request that EPA impose controls in terms of various emissions limitations, four of the eight petitions-- New York, Connecticut, Pennsylvania, and Maine--also request that a trading program with a cap, or emissions budget, be established to implement these controls. Massachusetts, Rhode Island, and Vermont request that limitations be established for all named sources at 0.15 lb/mmBtu, which is the level of control for electric generating facilities used to calculate the budget in the proposed NOX SIP call. Maine requests an emission limitation of 0.15 lb/mmBtu for named electric utilities, but the OTC NOX MOU level of control for named steam generating units. New Hampshire requests emission limitations no less stringent than the Phase III OTC NOX MOU reductions, and/or 85 percent reductions from the projected 2007 baseline, and/or an emission rate of 0.15 lb/mmBtu. New York, Connecticut and Pennsylvania all request that emissions limitations consistent with the OTC NOX MOU be imposed on named sources, but Pennsylvania and Connecticut specify the outer zone requirements; New York does not specify a zone. The level of reduction requested for 2003 in these three petitions specifying basic OTC NOX MOU requirements appears to be less stringent than that in the petitions requesting 0.15 lb/mmBtu, since the remedy requested would allow sources the option to implement the less stringent of a percentage reduction or an emission rate. In terms of smaller sources named by these three States, Pennsylvania's petition appears to seek somewhat more reductions than the OTC NOX MOU by requiring the same emission level for electric generating facilities less than 250 mmBtu/hr and greater than 15MW as for larger units. Both Connecticut and New York appear to be aligned with the OTC NOX MOU in seeking only a capping of emissions at 1990 levels for these smaller sources. New York, Connecticut and Pennsylvania recommend a date for the implementation by sources of control requirements: the OTC NOX MOU schedule of compliance, including its phased-in controls and implementation dates of 1999 and 2003. The remaining States request that EPA establish a schedule of compliance requiring sources to comply with emission limitations as expeditiously as practicable. 2. Sources Covered by Petitions The petitions vary somewhat regarding the universe of sources they name as significant contributors to their ozone problem. Three of the petitioning States--New York, Connecticut, and Pennsylvania--name the same universe of sources covered by the OTC NOX MOU. New Hampshire names fossil fuel-fired indirect heat exchangers and electric generating facilities as well, but uses a tonnage applicability cut-off to include only sources that emit ten tons or more of NOX per day. Massachusetts and Rhode Island name ``electricity generating plants'' as the universe requiring controls, without naming a specific size cutoff. Finally, Vermont names fossil fuel-fired electric generating facilities of 250 mmBtu or greater. All of the section 126 petitions, except Pennsylvania's, Massachusetts' and Rhode Island's, named some States in the OTR as significant contributors. However, only New Hampshire and Maine requested relief beyond OTC NOX MOU requirements from sources in the OTR. The geographic scope of each petition is discussed in Section II. Section 126 allows States to petition EPA for a finding against sources and groups of sources that ``emit'' or ``would emit'' pollution that significantly contributes to nonattainment problems in the petitioning State. Thus, a finding could potentially apply not only to existing sources within a particular source category, but also to sources that would be built in the future. The EPA believes the current section 126 petitions are ambiguous as to whether the requested findings are intended to encompass new sources. All of the petitions describe the requested finding as against source categories that ``are emitting'' significantly contributing levels of NOX. This suggests that perhaps the petitions are only intended to address existing sources. In addition, four petitions (Massachusetts, New Hampshire, New York, and Rhode Island) provide lists of sources in the targeted source categories and do not indicate that future sources should be added. However, it is notable that, in defining the universe of covered sources, all of the petitions identified specific source categories rather than just identifying specific sources. If emissions from the existing sources in the named source categories are of concern to the petitioning States, then it follows that emissions from new sources of the same type would also be of concern because they would increase the amount of emissions emitted by the category as a whole. The recommended control remedies in the petitions may provide the best insight into whether the petitions are to cover new sources. As discussed above, all of the petitioning States are signatories on the OTC NOX MOU. The OTC NOX MOU outlines a cap-and- trade control program designed to reduce NOX transport from certain groups of stationary sources in the OTR that are generally the same types of sources as covered by the petitions. The OTC NOX MOU program does include controls on both existing and new sources. The Connecticut, New Hampshire, New York, and Pennsylvania petitions all request the section 126 control remedy to be consistent with the OTC NOX MOU. Maine also requests that a control remedy be implemented through a cap-and-trade program. Further, five of the eight petitions request that EPA make a section 126 finding against sources in other OTR States, in addition to sources outside the OTR. It does not seem reasonable that any of the petitioning States would determine that both existing and new sources should be controlled for transport purposes within the OTR through the OTC NOX MOU, while recommending that outside the OTR only existing sources of the same type would need to be controlled for transport. Based on the above information, EPA is proposing to interpret all eight section 126 petitions to cover both existing and new sources. Therefore, if any final findings are triggered for source categories in a particular geographic area, new sources in those source categories locating in that area would also be subject to the section 126 control remedy. If any of the petitioning States disagrees with this interpretation as to its petition, EPA requests that the State

submit clarifying comments on this issue.

E. Litigation on Rulemaking Schedule

Section 126(b) requires EPA to make the requested finding, or deny the petition, within 60 days of receipt. It also requires EPA to provide a public hearing for the petition. In addition, EPA's action under section 126 is subject to the procedural requirements of section 307(d) of the CAA. One of these requirements is notice-and-comment rulemaking. Section 307(d) provides for a time extension, under certain circumstances, for rulemakings subject to that provision. Specifically, it allows statutory deadlines that require promulgation in less than 6 months from proposal to be extended to not more than 6 months from proposal to afford the public and the Agency adequate opportunity to carry out the purposes of section 307(d). In three notices dated October 22, 1997 (62 FR 55769), November 20, 1997 (62 FR 6194), and January 2, 1998 (63 FR 26), EPA ultimately extended the deadline for its requirement to take action on the eight petitions to December 18, 1997. On February 25, 1998, the eight petitioning States filed a complaint in the U.S. District Court for the Southern District of New York to compel EPA to take action on the States' section 126 petitions. State of Connecticut v. Browner, No. 98-1376. The EPA and the eight States filed a proposed consent decree that would establish a schedule for EPA to act on the petitions. Pursuant to CAA section 113(g), the EPA solicited comments on the proposed consent decree, by notice dated March 5, 1998 (63 FR 10874). The comment period closed April 6, 1998. On August 21, 1998, after considering the comments received in the section 113(g) process, EPA requested the Court to enter a slightly modified version of the consent decree. Pending the Court's action on that request, EPA is continuing to follow the schedule in the proposed consent decree. The schedule recommended in the proposed consent decree would require EPA to take final action on at least the technical merits of the petitions by April 30, 1999. The recommendation would further permit EPA to structure the final action it would take by April 30, 1999 so as to defer the granting or denial of the petitions to certain later dates extending to as late as May 1, 2000. The section 126 rulemaking schedule is described in more detail in Section II.A.2. of this notice.

F. Advance Notice of Proposed Rulemaking on Petitions

In accordance with the schedule in the proposed consent decree, on April 30, 1998, EPA published in the Federal Register (63 FR 24058) an advance notice of proposed rulemaking (ANPR) on the section 126 petitions. The ANPR provided EPA's preliminary identification of source categories named in the petitions that significantly contribute to nonattainment problems in the petitioning States, provided EPA's preliminary assessment of the types of recommended emissions limitations and compliance schedules, provided EPA's preliminary assessment of the remedy the Agency would propose for approvable petitions, discussed legal and policy issues raised under section 126, and outlined the rulemaking schedule for the petitions. The ANPR solicited comment on all of the issues and preliminary assessments. The EPA received approximately 50 comments on the ANPR from industry, States, and environmental groups. These comments covered the full spectrum of issues discussed in the ANPR and were carefully considered in the development of today's proposal. The EPA appreciates the efforts by the commenters to provide early, thoughtful input on this rulemaking. The EPA will respond to the ANPR comments, if any response is appropriate, when EPA responds to comments on this proposal. After reading this proposal, if any commenters on the ANPR believe their comments are still relevant, there is no need to resubmit the comments in full. Instead, commenters may simply submit a letter requesting that EPA consider their ANPR comments for purposes of today's proposal action. This proposal supersedes any preliminary positions taken in the ANPR.

II. EPA's Analytical Approach and Proposed Action on Petitions

A. EPA's Proposed Interpretation of Section 126 and Analytical Approach for Determining Whether to Grant or Deny the Petitions

1. The Appropriate Test Under Section 126 Section 126(b) provides that a State may petition EPA for a finding that specified sources or groups of sources in other States emit or would emit air pollutants ``in violation of the prohibition of section 110(a)(2)(D)(ii) of this title or this section.'' \1\ Section 110 (a)(2)(D) provides the requirement that a SIP:

\1\ The cross-reference to section 110(a)(2)(D)(ii) is repeated 3 times in section 126(b). The EPA will refer to these cross- references in the singular. ---------------------------------------------------------------------------

Contain adequate provisions: (i) prohibiting, consistent with the provisions of this title, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will-- (I) contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to (any) national ambient air quality standard, or (II) interfere with measures required to be included in the applicable implementation plan for any other State under part C to prevent significant deterioration of air quality or to protect visibility, (ii) insuring compliance with the applicable requirements of sections 126 and 115 (relating to interstate and international pollution abatement). * * * * * One issue is whether the cross-reference in section 126(b) to section 110(a)(2)(D)(ii) is valid, or instead should be considered to be a scrivener's error and be read to refer to section 110(a)(2)(D)(i). The EPA has offered the latter view in general and preliminary guidance. See, e.g., 62 FR 55769 (Oct. 22, 1997) and 63 FR 24058 (Apr. 30, 1998). Some have argued that section 126(b) should be read literally and that this reading would require EPA to deny the 8 petitions on grounds that section 126 allows a State to file a petition with EPA only to force other States to meet the requirements of section 126 itself (i.e., the requirement in section 126(a) that SIPs include provisions to require new and modified major stationary sources to give preconstruction notification to nearby States under certain circumstances). \2\ ---------------------------------------------------------------------------

\2\ See Letter from Henry V. Nickel, et al., Counsel for the Utility Air Regulatory Group, to Carol M. Browner, Administrator, U.S. EPA, November 21, 1997 (UARG Letter); Letter from Betty D. Montgomery, Attorney General of Ohio et. al., to Richard Wilson, Acting Assistant Administrator for Air & Radiation, U.S. EPA, November 5, 1997 (letters included in the docket to this rulemaking). ---------------------------------------------------------------------------

In the alternative, some have argued that, if in fact there is a scrivener's error, the proper cross-reference should be to section 110(a)(2)(D)(i)(II), and not section 110(a)(2)(d)(i)(I). UARG letter. The effect of this reading would be to limit section 126 petitions to cases in which the upwind sources are adversely affecting clean areas under the prevention of significant deterioration requirements of part C of title I of the CAA, or visibility. The EPA believes that there is a scrivener's error in section 126. Furthermore, EPA disagrees that the scrivener's error is a misreference to section 110(a)(2)(D)(i)(II). In this

proposed action, EPA takes the position that the reference in section 126(b) to section 110(a)(2)(D)(ii) is a drafting error and that Congress intended to reference section 110(a)(2)(D)(i). The merit of this statutory interpretation is apparent on several levels. First, the reference to ``the prohibition of section 110(a)(2)(D)(ii)'' is ambiguous at best, and arguably nonsensical, since section 110(a)(2)(D)(ii) contains no prohibition, yet 110(a)(2)(D)(i) does. Second, the statutory cross reference contained in section 126(b), if taken on its face, would render section 126(b) largely meaningless. Finally, the legislative history of the CAA Amendments supports this interpretation. The EPA's interpretation is consistent with the reading of the CAA prior to the 1990 Amendments and Congress expressed no indication that it meant to substantively revise this provision of the statute at the time it administratively renumbered the provision. The EPA also does not believe that the reference to section 110(a)(2)(D)(ii) is a mistaken cross-reference to section 110(a)(2)(D)(i)(II). Such a cross-reference would limit the availability of section 126 to the prevention of significant deterioration and visibility provisions of section 110(a)(2)(D)(i), a severe limitation for which there is no indication in the legislative history. Section 126(b) authorizes the EPA to find that any major source or group of stationary sources emits or would emit any air pollutant ``in violation of the prohibition of section (a)(2)(D)(ii) of this title or this section'' (emphasis added). However, section 110(a)(2)(D)(ii) contains no prohibition. Rather, it provides that SIPs must ``contain adequate provisions insuring compliance with'' statutory sections relating to interstate and international pollution abatement. By contrast, section 110(a)(2)(D)(i)--the provision that EPA believes Congress intended to cross-reference in section 126(b)--does contain a prohibition. It requires that SIPs contain adequate provisions ``prohibiting'' any source or other type of emissions activity within the State from emitting any air pollutant in amounts that, among other things, will contribute significantly to nonattainment in, or interfere with maintenance by, another State with respect to the NAAQS. Thus, the textual interplay between sections 126(b) and 110(a)(2)(D) provides strong evidence that the CAA contains ``a simple scrivener's error, a mistake made by someone unfamiliar with the law's object and design.'' In re Chateaugay Corp., 89 F.3d 942, 954 (2d Cir. 1996) (holding that courts are empowered to correct an erroneous statutory cross-reference that inadvertently results from legislative changes (quoting United States Nat'l Bank v. Independent Ins. Agents, 508 U.S. 439, 462 (1993)); see also, United States v. Gibson, 770 F.2d 306, 308 (2d Cir. 1985) (per curiam) (correcting ambiguity in criminal fraud statute that resulted from the error of a scrivener in using the word `and' rather than `or' when codifying the statute). As further support, reading section 126(b) as cross-referencing section 110(a)(2)(D)(ii) essentially renders that provision redundant and meaningless. Section 126 allows a party to petition EPA with respect to a ``violation of the prohibition in section 110(a)(2)(D)(ii) or this section.'' Section 110(a)(2)(D)(ii) cross-references back to section 126, as well as to section 115. To the extent section 110(a)(2)(D)(ii) cross-references back to section 126, the statute is redundant. Reading the two provisions together, section 126 would provide an opportunity for parties to file a petition claiming that a SIP violates the prohibition of section 110(a)(2)(D)(ii) (i.e., section 126) or this section (i.e., section 126). Moreover, to the extent section 110(a)(2)(D)(ii) references section 115, the provision is meaningless. There is no relief that can be provided under section 126. Sections 126 and 115 create separate processes for different parties to petition the Agency for a finding that SIP is inadequate. Under section 115, the Administrator may issue a SIP Call to a State based on a request by an international agency or the Secretary of State that an air pollutant or pollutants emitted in the United States ``cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare in a foreign country.'' In contrast, only ``States'' or ``political subdivisions''--entities under the jurisdiction of the United States-- may request relief under section 126. If Congress intended States or political subdivisions in the United States with the opportunity to seek relief for pollution transported to foreign countries, Congress could have provided so in a much clearer fashion in section 115. It is highly doubtful that Congress would have used such a cryptic reference to grant political entities within the United States the power to address pollution being transported out of the country from other States. Finally, EPA's interpretation that there is a scrivener's error and that the reference should be to section 110(a)(2)(D)(i), fits with the legislative history on this provision. Courts ``recognize that during the drafting process an error may creep in,'' and that ``statutes are not drafted with mathematical precision, and should be construed with some insight into Congress' purpose at the time of the enactment.'' In re Chateaugay Corp., 89 F.3d at 953. Here, the legislative history, as set forth in the Senate Report and the House Conference Report regarding the 1990 CAA Amendments, provides additional, persuasive evidence that section 126(b)'s cross-reference to section 110(a)(2)(D)(ii) is erroneous. See Pierpont v. Barnes, 94 F.3d 813, 817 (2d Cir. 1996) (committee reports are ``particularly good indicator(s) of congressional intent,'') cert. denied, 117 S. Ct. 1691 (1997). To start, the Senate Report observes that the CAA, prior to the 1990 amendments, allowed section 126 to be used only for violations of section 110(a)(2)(E)(i), which ``relate(d) to the preparation of SIP(s).'' S. Rep. No. 101-228, 101st Cong., 2d Sess. 75 (1989), reprinted in 1990 U.S.C.C.A.N. 3385, 3461. Thus, under section 126(b)'s pre-1990 version, ``a State being injured by another State's pollution (could) file a complaint about the offending State's SIP, but not the pollution itself.'' Id. at 76, 1990 U.S.C.C.A.N. 3385, 3462. Notably, the Senate Report makes no mention of changing section 126(b)'s cross- reference to section 110(a)(2)(E)(i)-- nor would it, since section 110(a)(2)(E)(i) had defined the SIP violation historically redressable under section 126(b). Because the amendments simply revised the text of former section 110(a)(2)(E)(i) and then renumbered it as section 110(a)(2)(D)(i), compare 42 U.S.C.A. 7410(a)(2)(E)(i) (1990) with 42 U.S.C.A. 7410(a)(2)(D)(i) (1995), \3\ there is substantial reason to believe that section 126(b)'s current cross-reference to section 110(a)(2)(D)(ii) is mistaken. ---------------------------------------------------------------------------

\3\ The 1990 CAA Amendments revised section 110(a)(2)(D) by dropping certain provisions not relevant here, and incorporating other provisions previously contained in section 110(a)(2)(E). See CAA Amendments of 1990, Pub. L. 101-549, 101(b), 104 Stat. 2404(1990); S. Rep. No. 101-228, 101st Cong., 2d Sess. 20 (1989), reprinted in 1990 U.S.C.C.A.N. 3385, 3406. ---------------------------------------------------------------------------

Indeed, ``[w]hen Congress revises and renumbers existing laws, a court should not infer any legislative aim to change the law's effect unless such intention is clearly expressed.'' In re Chateaugay Corp., 89 F.3d at 953 (citing Finley v. United States, 490 U.S. 545, 554 (1989)). Far from expressing a clear intent to effectuate the fundamental change in law that would result from section 126(b)'s new cross-reference to section 110(a)(2)(D)(ii), the legislative history for the 1990 CAA Amendments actually

demonstrates a contrary purpose. According to the House Conference Report, these amendments sought to ``enhance the enforcement authority of the Federal government under the CAA, ``including ``EPA enforcement authority regarding violations of State Implementation Plans.'' H. Rep. No. 101-952, 101st Cong. 2d Sess. 347 (1990), reprinted in, 1990 U.S.C.C.A.N. 3385, 3879. As noted above, however, the ambiguous change in section 126(b)'s cross-reference would apparently divest the EPA of its former jurisdiction to redress--via the section 126 petition process--SIP violations regarding interstate pollution. See 42 U.S.C.A. 7426(b) (1990) (authorizing EPA to adjudicate petitions alleging violations of SIP requirements that are now substantially incorporated into section 110(a)(2)(D)(i)). Given the lack of any legislative history that would support such a significant shift in policy, and considering Congress' stated desire to enhance the EPA's SIP enforcement authority, this contradictory result is highly suspect. See In re Chateaugay Corp., 89 F.3d at 953 (``where it appears plain that an error in drafting has occurred, so that a literal construction would make a dramatic change in long-standing law, it is both sensible and permissible for judges to consider, in conjunction with other factors, Congress' complete silence on the literal effect of the change.'') \4\ ---------------------------------------------------------------------------

\4\ The Senate Report also expresses a congressional desire to promote the EPA's enforcement activity, not to constrain it. As the Senate committee observed, prior to 1990, the CAA ``allow(ed) a State to file a petition with the Administrator complaining of interstate air pollution (in violation of section 110(a)(2)(E)(i)), but not to file a lawsuit for violation of section 126. The amendment to section 304, (however,) allow(ed) a State, and citizens, to sue in Federal district court for violation of section 126.'' S. Rep. No. 101-228, 101st Cong., 2d Sess. 76 (1989), reprinted in 1990 U.S.C.C.A.N. 3385,3462. That Congress created a judicial mechanism by which to compel the EPA to respond to section 126 petitions is instructive. Because this legislative action is clearly inconsistent with any construction of the CAA that divests the EPA of its authority to enforce the very SIP requirements formerly contained in section 110(a)(2)(E)(i), it casts serious doubt upon the validity of section 126(b)'s amended cross-reference to section 110(a)(2)(D)(ii). ---------------------------------------------------------------------------

The EPA believes that its proposed interpretation is permissible because it resolves the ambiguity in the interplay between sections 126 and 110(a)(2)(D) in a manner that harmonizes and gives meaning to all of their provisions and reasonably accommodates the purposes of the provisions. See Chevron, U.S.A., Inc. v. Natural Resources Defense Council, 467 U.S. 837, 844 (1984). 2. EPA's Analytical Approach for Determining Whether To Grant or Deny the Petitions a. EPA's Interpretation of Significant Contribution under Section 110. The EPA's final NOX SIP call rule sets forth EPA's interpretations of section 110(a)(2)(D)(i)(I) in the context of regional transport of ozone. The EPA proposes and is seeking comment on retaining and employing those interpretations for purposes of determining, under section 126(b), whether any of the sources and source categories named in the petitions ``emits or would emit any air pollutant in violation of the prohibition'' of section 110(a)(2)(D)(i)(I). For purposes of this proposal, EPA incorporates into the proposal, by reference, the explanation of those interpretations, as well as all of the supporting rationale and technical support for them. See, especially, Section II of the preamble to the final NOX SIP call rule. Each of these steps is discussed in the remainder of Section II of this notice. b. Applying EPA's Section 110 Interpretation of ``Significant Contribution'' and ``Interference'' under Section 126. The EPA proposes to apply its interpretation of section 110(a)(2)(D)(i)(I) to determine which if any NOX sources or source categories named in the section 126 petitions ``emits or would emit any air pollutant in violation of the prohibition'' in section 110(a)(2)(D)(i)(I). The EPA believes that its interpretations in the context of section 110 apply with relative ease to its decision under section 126, with one additional step noted below. First, in acting on the section 126 petitions, EPA proposes to use the linkages it drew in the NOX SIP call rulemaking between specific upwind States and nonattainment and maintenance problems in specific downwind States. The EPA is seeking comment on and will carefully evaluate these linkages, and in particular, the linkages EPA has made between some of the more distant States, such as the linkages made between Alabama and Pennsylvania and Missouri and Pennsylvania. In the next step, EPA determines which of that ``covered'' upwind State's major stationary NOX sources that are named in the downwind State's petition may emit in violation of the prohibition in section 110(a)(2)(D)(i) because they emit in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the petitioning State. For this, EPA proposes to use its analysis of highly cost-effective measures in the NOX SIP call rule to determine which of the covered upwind States' major stationary NOX sources named in the petitions emit NOX in amounts that contribute significantly. Thus, if EPA identified highly cost-effective measures for a particular source category in the NOX SIP call, then EPA proposes in this notice to make an affirmative ``technical determination''--i.e., a finding that any source in that category located in a covered upwind State emits in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, the petitioning State(s) linked to that upwind State. This methodology applies both to a petition that names sources in the entire contributing upwind State and to a petition that names sources in only a small portion of an upwind contributing State. As described more fully in the NOX SIP call rulemaking, the only viable solution to ozone nonattainment is to apply pollution- reduction measures to a large collection of sources in many States, each one of which by itself may produce a small or perhaps immeasurable impact on the nonattainment problem for a particular area. Under this collective contribution approach, if EPA determines that the full set of NOX sources in an upwind State significantly contributes to nonattainment in, or interferes with maintenance by, a particular downwind State, then any NOX sources in the upwind State that can apply highly cost-effective control measures must be considered part of the solution to those downwind problems and therefore contributes to downwind nonattainment. c. Emitting ``In Violation of the Prohibition'' in Section 110--the Decision Whether to Grant or Deny Each Petition. As noted above, the test under EPA's interpretation of section 126 is whether the sources named in the petitions emit in violation of the section 110(a)(2)(D)(i) prohibition. That prohibition, however, by the terms of section 110(a)(2)(D)(i), should be included in SIP provisions. The EPA has now issued its NOX SIP call rule under that section, and has set forth a track that upwind States must follow to satisfy its terms. Under the NOX SIP call, EPA has given the covered States until September 1999 to submit SIPs satisfying the rule, and has specified that those SIPs must prohibit the NOX emissions that contribute significantly by a date no later than May 1, 2003. By that rule, EPA has established emissions budgets for each State, which reflect elimination of the significant contribution of NOX emissions within

the State. The EPA has further established by rule May 1, 2003 as the final date by which all measures to meet that budget must be implemented. In addition, EPA has proposed a FIP that could be promulgated if a State fails to respond adequately to the NOX SIP call. Section 126 calls for relief where EPA finds that sources are emitting ``in violation of the prohibition'' of section 110(a)(2)(D)(i). The EPA believes that it is sensible to interpret this language in light of the ongoing action of both States and EPA. Thus, so long as EPA and States (and ultimately the sources the State determines to regulate) are on track to meet the goals of the NOX SIP call, EPA believes it is appropriate to determine that sources are not emitting in violation of the prohibition in section 110(a)(2)(D)(i) for purposes of section 126(b). States and EPA will be on track if States timely submit a complete and approvable SIP and EPA acts promptly to approve the plan. In the alternative, if a State fails to submit in a timely manner a complete or approvable plan, efforts will be on track so long as EPA promulgates a FIP. The EPA further believes this approach is sensible because an alternative interpretation, which would result in a section 126 remedy going into effect despite timely action by States and EPA in response to the NOX SIP call, would lead to unnecessary and duplicative efforts. Such an approach would not only waste Agency resources, but could ultimately undermine efforts to reduce interstate transport by adding confusion to the process. Based on this interpretation of the language in section 126, EPA has considered an alternative form of final action on the section 126 petitions that takes into account whether the State and/or EPA is on track to institute a satisfactory plan in response to the NOX SIP call rule. As described in Section I above, the proposed consent decree would require EPA to take a final action on the section 126 petitions by April 30, 1999. In formulating the proposed consent decree, EPA developed an alternative approach that it believes would harmonize the section 126 and 110 actions. Specifically, paragraph 5.b. and c. state that:

b. Unless EPA takes the final action described in paragraph 6, as to each individual petition, EPA's final action will be to-- (i) Grant the requested finding, in whole or part; and/or (ii) Deny the petition, in whole or part. c. Unless EPA denies a petition in whole, its final action will include promulgation of a remedy under CAA section 126(c) for sources to the extent that a requested finding is granted with respect to those sources.

Then paragraph 6 states:

6. EPA shall be deemed to have complied with the requirements of Paragraph 5(a) if it instead takes a final action by April 30, 1999, that-- a. makes an affirmative determination concerning the technical components of the ``contribute significantly to nonattainment'' or ``interfere with maintenance'' tests under CAA section 110(a)(2)(D)(i), 42 U.S.C. section 7410(a)(2)(D)(i); b. further provides that: (i) If EPA does not issue a proposed approval of the relevant Upwind State's SIP revision (submitted in response to the NOX SIP call) by November 30, 1999, then the finding will be deemed to be granted as of November 30, 1999, without any further action by EPA; (ii) If EPA issues a proposed approval of said SIP revision by November 30, 1999, but does not issue a final approval of said SIP revision by May 1, 2000, then the finding will be deemed to be granted as of May 1, 2000, without any further action by EPA; (iii) If EPA issues a final approval of said SIP revision by May 1, 2000, EPA must take any and all further actions, if necessary to complete its action under section 126, no later than May 1, 2000; and c. Promulgates a remedy under CAA section 126(c) for sources to the extent that an affirmative determination is made with respect to those sources.

The EPA believes that the alternative form of final action set forth in Paragraph 6 of the proposed decree best harmonizes sections 110(a)(2)(D)(i)(I) and 126. The EPA believes that sources in an upwind State should not be considered to be emitting an air pollutant in violation of the section 110 prohibition, and hence EPA should not grant a petition naming such sources, if the State is adhering to the NOX SIP call rule's schedule for submission of an approvable SIP revision, and EPA is acting speedily to approve the SIP--or, failing that, if EPA has promulgated a FIP for the State. After all, if EPA's rule provides a particular path for the development of a plan calling on sources to reduce interstate pollution by May 1, 2003, and under that rule either the upwind State or EPA is moving forward to develop, take action on or promulgate a satisfactory plan meeting that rule and achieving attainment as expeditiously as practicable, it would be difficult to conclude that an affected source in the upwind State ``emits or would emit in violation'' of the prohibition that the plan is not yet required to contain.5 ---------------------------------------------------------------------------

\5\ Moreover there does appear to be tension between section 110(a)(2)(D), which does not establish the timing as to when the SIP prohibition needs to be effective against sources (i.e., when sources need to implement controls to reduce emissions) and the timing in section 126, which requires implementation no later than 3 years following a section 126(b) determination. The EPA does not believe that Congress intended section 126 to be used to shorten timeframes for action that EPA has previously determined are approvable for purposes of eliminating significant contribution to nonattainment areas in other States. ---------------------------------------------------------------------------

For these reasons, EPA proposes to follow the alternative described in Paragraph 6 of the proposed decree. Thus, EPA proposes to structure its final action to contain: (1) A series of ``technical determinations'' as to which sources in which States named in the petitions would emit in violation of the section 110 prohibition if the State or EPA were to fall off track in putting a timely and satisfactory plan in place; (2) determinations that the petitions will automatically be deemed granted or denied on the basis of the events set forth in Paragraph 6; and (3) the remedial requirements that will apply to the sources receiving affirmative technical determinations if a petition naming those sources is ultimately deemed granted. The EPA believes that the timeframes and triggers in Paragraph 6 are reasonable and feasible, and the Agency intends to execute them timely. For States that make a timely SIP submission, EPA believes it is feasible for the Agency to issue a proposed rule within 60 days of the submission deadline. Under the CAA, EPA is provided 60 days--but no more than 6 months--in which to affirmatively determine whether a submission is complete. If EPA does not make an affirmative completeness determination, the submission is deemed complete. Once a submission is affirmatively found to be or is deemed complete, the CAA then provides EPA with 12 months to approve or disapprove the submission. Thus, at maximum, the CAA provides EPA with 18 months to approve or disapprove a SIP submission. The EPA is proposing a 7-month period to act on submissions in response to the NOX SIP call. While this period is shorter than the maximum period contemplated under the CAA, EPA believes that it is feasible and appropriate in the present circumstances. The EPA anticipates that the EPA Regional Offices will be working with States as States draft rules in response to the NOX SIP call and will be well prepared to issue a proposed determination within 60 days of the required submission date. Further, in light of EPA's work with the States in development of their plans, the 5-month period between proposal and final action should allow the Agency ample time to review any comments and to

prepare a final action. An additional benefit of this schedule for EPA action is that it will provide sources with certainty about the applicable requirements well before the latest implementation date that is permitted by the NOX SIP call. Moreover, if the State fails to submit an approvable plan, EPA will be well positioned to promulgate a FIP for the State, based on the FIP proposal that the Agency is issuing separately. It is important to achieve the NOX reductions necessary to protect public health and to attain the NAAQS as expeditiously as practicable. Therefore, where a State or EPA has failed to meet a deadline it will be critical to have the section 126 remedy go into effect as soon as possible thereafter in order to ensure that the NOX emission reductions are achieved as soon as practicable, which in the NOX SIP call EPA has determined to be May 1, 2003. The schedule EPA has proposed to enter into is intended to ensure that either the FIP or the 126 remedy goes into effect in order to achieve the NOX emission reductions by May 1, 2003.

B. Weight of Evidence Determination of Named Upwind States

As discussed above, in acting on the section 126 petitions EPA proposes to rely on the conclusions it drew in the final NOX SIP call rulemaking to determine whether the emissions in named upwind States contribute significantly to the 1-hour and 8-hour nonattainment and maintenance problems in the petitioning States. To evaluate the air quality impacts in the final NOX SIP call rulemaking, EPA used a weight-of-evidence approach involving three sets of modeling information: The State-by-State UAM-V zero-out modeling, the CAMx source apportionment modeling, and the OTAG subregional modeling and other information such as emission density and transport distance.6 A number of ``metrics'' (i.e., measures of ozone contributions) were used to assess the air quality effects from several perspectives of contribution from sources in various upwind States. The technical details of the modeling information and metrics are described in the final NOX SIP call rulemaking. The named upwind States which are linked as containing sources that are significant contributors to each petitioning State in the final NOX SIP call rulemaking are listed in Tables II-1 for the 1- hour NAAQS and Table II-2 for the 8-hour NAAQS. The information that EPA relied on in making these significance linkages is provided in the final NOX SIP call rulemaking. All of the information that is contained in the docket of the NOX SIP call rulemaking is incorporated by reference into this proposal. The EPA concluded from all of this information that the following 20 jurisdictions contain sources that make a significant contribution to nonattainment in, or interfere with maintenance by, one or more petitioning States under the 1-hour and/or the 8-hour NAAQS:

Alabama Connecticut Delaware District of Columbia Illinois Indiana Kentucky Maryland Massachusetts Michigan Missouri New Jersey New York North Carolina Ohio Pennsylvania Rhode Island Tennessee Virginia West Virginia

Table II-1.--Named Upwind States which Contain Sources that Contribute Significantly to 1-Hr Nonattainment in Petitioning States ------------------------------------------------------------------------ Petitioning State (nonattainment area) Named upwind States ------------------------------------------------------------------------ New York..................... DE, DC, IN, KY, MD, MI, NC, NJ, OH, PA, VA, WV. Connecticut.................. DE, DC, IN,* KY,* MD, MI,, NC,, NJ, NY, OH, PA, VA, WV. Pennsylvania................. NC, OH, VA, WV. Massachusetts................ OH, WV. Rhode Island................. OH, WV. Maine........................ CT, DE, DC, MD, MA, NJ, NY, PA, RI. New Hampshire................ CT, DE,* DC,* MA, MD,* NJ, NY, PA, RI, VA.* Vermont...................... None. ------------------------------------------ Total.................... CT, DE, DC, IN, KY, MA, MD, MI, NC, NJ, NY, OH, PA, RI, VA, WV. ------------------------------------------------------------------------ *Upwind States marked with an asterisk are included in the table because they contribute to an interstate nonattainment area that includes part of the petitioning State. Part of New Hampshire is included in the Boston/Portsmouth nonattainment area; part of Connecticut is included in the New York City nonattainment area.

Table II-2. Named Upwind States which Contain Sources that Contribute Significantly to 8-Hr Nonattainment in Petitioning States ------------------------------------------------------------------------ Petitioning State Named upwind States ------------------------------------------------------------------------ Pennsylvania................. AL, IL, IN, KY, MI, MO, NC, OH, TN, VA, WV. Massachusetts................ OH, WV. Vermont...................... None. ------------------------------------------ Total.................... AL, IL, IN, KY, MI, MO, NC, OH, TN, VA, WV. ------------------------------------------------------------------------

The EPA also concluded that sources in the following 11 States do not make a significant contribution to nonattainment in, or interfere with maintenance by, any of the petitioning States under the 1-hour and/or the 8-hour NAAQS: ---------------------------------------------------------------------------

\6\ The UAM-V is the Variable-grid Urban Airshed Model. The CAMx is the Comprehensive Air Quality Model With Extensions.

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

Arkansas Georgia Iowa Louisiana Maine Minnesota Mississippi New Hampshire South Carolina Wisconsin Vermont

As discussed below, in Section II.F., EPA does not have the same level of information available regarding the named States of Maine, New Hampshire, and Vermont as it has for the other States named in petitions. Therefore, EPA intends to conduct further analyses on these three States. If the additional analyses show that sources in any of these States significantly contribute to a relevant petitioning State, EPA will issue a supplemental notice of proposed rulemaking based on the new information.

C. Cost Effectiveness of Emissions Reductions

As described in Section II.A, above, the second prong of the significant-contribution interpretation that EPA applied in the NOX SIP call rule, and that EPA proposes to apply for purposes of this proposal, is the extent to which ``highly cost- effective'' NOX control measures are available for the types of stationary sources named in the petitions.7. ---------------------------------------------------------------------------

\7\ As discussed in this section, the highly cost-effective NOX controls happen to apply only to major stationary sources. Under section 126, EPA can make a finding for ``any major source or group of stationary sources.'' In other words, even if not all sources subject to this action were major, they would be part of a group of stationary sources that contribute significantly to nonattainment and hence could potentially be subject to finding. ---------------------------------------------------------------------------

As in the NOX SIP call rule, the EPA proposes to select these highly cost-effective measures by examining the technological feasibility, administrative feasibility and cost-per-ton-reduced of various multistate ozone season NOX control measures and determining what measures feasibly achieve the greatest NOX reductions and are among the most reasonable in light of other actions taken by EPA and States to control NOX.\7\ ---------------------------------------------------------------------------

\7\ As discussed in this section, the highly cost-effective NOX controls happen to apply only to major stationary sources. Under section 126, EPA can make a finding for ``any major source or group of stationary sources.'' In other words, even if not all sources subject to this action were major, they would be part of a group of stationary sources that contribute significantly to nonattainment and hence could potentially be subject to a finding. ---------------------------------------------------------------------------

1. What NOX Controls Are Highly Cost Effective The first step in the cost-effectiveness process was to identify the types of sources named in the various petitions. The petitioning States have identified the source categories that they believe significantly impact their ability to achieve attainment of the ozone standard. These categories are listed in Table I-1 earlier in this notice. The EPA has determined that the named source categories can be combined into one general category--fossil fuel-fired indirect heat exchangers. This term applies to boilers and turbines used for the production of steam, electricity, and in some cases mechanical work, and to process heaters. To assure equity among the various subcategories of such sources and the industries they represent, EPA considered the cost effectiveness of controls for each subcategory separately throughout the affected 20-jurisdiction region described in Section II.B above. Sources are combined into a common subcategory if they serve the same general industry (e.g., boilers and turbines that are used by the electricity generation industry are combined in the same subcategory). The EPA believes that this categorization better reflects the industrial sectors served. Thereby, the EPA split the population of indirect heat exchanges into four subcategories, consistent with the approach EPA took in the final NOX SIP call: (1) A subcategory of boilers and turbines serving generators greater than 25 MWe that produce electricity for sale to the grid (``large EGUs''); (2) a subcategory of boilers and turbines with a heat input greater than 250 mmBtu/hr that exclusively generate steam and/or mechanical work (e.g., provide energy to an industrial pump), or produce electricity for internal use only and not for sale (``large non-EGUs''); (3) a subcategory of process heaters with a heat input greater than 250 mmBtu/hr (``large process heaters''); and (4) a subcategory of smaller indirect heat exchangers, i.e., all such sources not included in the first three subcategories (``small sources''). As mentioned above, in evaluating the cost effectiveness of NOX controls for indirect heat exchangers, the EPA has taken the same approach as that taken in the final NOX SIP call. See generally, Section II.D of the preamble to the final NOX SIP call rule. In short, for each subcategory, the amounts of emissions that cause subcategories in the covered upwind States to contribute significantly to a petitioning State's nonattainment were determined based on the application of NOX controls that achieve the greatest feasible emissions reduction while still falling within a cost-per-ton-reduced range that EPA considers to be highly cost effective. The NOX controls for this rulemaking were considered highly cost effective for the purposes of reducing ozone transport to the extent they achieve the greatest feasible emissions reduction but still cost no more than $2,000 per ton of ozone season NOX emissions removed (in 1990 dollars), on average, for each subcategory. The discussion below further describes the basis for this cost amount and the techniques used for each subcategory. The EPA believes that certain controls that cost more than $2,000 per ton of NOX reduced are reasonably cost effective in reducing ozone transport or in achieving attainment with the ozone NAAQS in specific nonattainment areas; however, EPA proposes to base the significant- contribution determination on only highly cost-effective reductions. In addition, as discussed further below, in determining whether to assume reductions from the small source subcategory, EPA considered administrative efficiency in evaluating this subcategory. More specifically, to determine what level of control can be considered highly cost effective, EPA considered other recently undertaken or planned NOX control measures. Table II-3 provides a reference list of measures that EPA and States have undertaken to reduce NOX and their average annual costs per ton of NOX reduced. These measures cost up to $2,000 per ton. With few exceptions, the average cost effectiveness of these measures is representative of the average cost effectiveness of the types of controls EPA and States have needed to adopt most recently, since their previous planning efforts have already taken advantage of opportunities for even cheaper controls. The measures listed in Table II-3 generally represent the average costs (i.e., middle of the range of costs) that the nation has been willing to bear recently to reduce NOX. The EPA believes that the cost effectiveness of measures that it or States have adopted, or proposed to adopt, forms a good reference point for determining which of the available additional NOX control measures are among the most cost-effective measures that can be implemented by the sources considered in today's action.

Table II-3.--Average Cost Effectiveness of NOX Control Measures Recently Undertaken For Stationary Sources [1990 $] ------------------------------------------------------------------------ Control measure Cost per ton of NOX removed ------------------------------------------------------------------------ NOX RACT.................................. 150-1,300. Final NOX SIP call........................ Up to 2,000. State Implementation of the Ozone 950-1,600. Transport Commission Memorandum of Understanding. New Source Performance Standards for 1,290. Fossil Steam Electric Generation Units. New Source Performance Standards for 1,790. Industrial Boilers. ------------------------------------------------------------------------

The EPA notes that there are also a number of less expensive measures recently undertaken by the Agency to reduce NOX emission levels that do not appear in Table II-3. These actions include the title IV NOX reduction program. Though these actions are very cost effective, the Agency is focusing on what other measures exist, at a potentially higher (though still not the highest reasonable) cost-effectiveness value, that can further reduce NOX emissions. Table II-3 is thereby useful as a reference of the next higher level of NOX reduction cost effectiveness that the Agency considers among the most reasonable to undertake. As a result, the Agency proposes that NOX controls that can feasibly be achieved and have an average subcategory-specific cost effectiveness less than $2,000 per ton of NOX removed be considered highly cost effective. The subcategories that EPA proposes to control are those major stationary sources in the named categories for which EPA finds that these highly cost-effective controls are available. 2. Determining the Cost Effectiveness of NOX Controls In an effort to determine what, if any, highly cost-effective mix of controls is available for each subcategory (i.e., large EGUs, large non-EGUs, large process heaters, and small sources) the Agency considered the average cost effectiveness of alternative levels of controls for each subcategory as described in the final NOX SIP call. That analysis is summarized here. The average cost effectiveness of the controls was calculated from a baseline level that included all currently applicable Federal or State NOX control measures for each subcategory. The baseline did not include Phase II and Phase III of the OTC NOX MOU since those measures are not federally required and they have not yet been adopted by all the involved States; 8 if the MOU were included in the baseline, the overall costs would be lower. In determining the cost of NOX reductions from large EGUs, EPA assumed an emissions trading system. As discussed in the final NOX SIP call, EPA evaluated and compared the likely air quality impacts both with and without a multistate NOX emissions trading system for electricity generating sources. This analysis shows that a multistate trading program causes no significant adverse air quality impacts. Because such a program would result in significant cost savings, EPA's cost-effectiveness determination for large electricity generating boilers and turbines (i.e., the majority of the core group of sources in the trading program) assumes sources will participate in a multistate trading program.9 For non-EGU sources, EPA used a least cost method which is equivalent to an assumption of an intrastate trading program. Inclusion of these sources in a multistate trading program would provide further cost savings. ---------------------------------------------------------------------------

\8\ However, in the Regulatory Analysis of the final NOX SIP call, EPA evaluates the economic impact of including the MOU in the baseline for the electric power industry. \9\ The EPA envisions sources in States that are covered by (1) the section 110 NOX SIP call, (2) the section 110 FIP, or (3) section 126, to be able to trade among each other. ---------------------------------------------------------------------------

Table II-4 summarizes the control options investigated for each subcategory covered by the petitions and the resulting average, multistate cost effectiveness as presented in EPA's final NOX SIP call. Note that these cost figures are obtained by performing the analysis over the 23-jurisdiction NOX SIP call area. The values will be only slightly different for the States covered by this action; those differences are insignificant for purposes of identifying highly cost-effective controls. Additionally, the cost effectiveness analysis included a consideration of each subcategory's growth, including new sources. Thus, the control levels arrived at are cost-effective for new sources also.

Table II-4.--Average Cost Effectiveness of Options Analyzed \10\ [1990 dollars in 2007] ---------------------------------------------------------------------------------------------------------------- Average cost- Average cost- effectiveness ($/ effectiveness ($/ Subcategory ozone season ton) ozone season ton) Average cost-effectiveness ($/ozone season for each control for each control ton) for each control option option option ---------------------------------------------------------------------------------------------------------------- Large EGUs.................... 0.20 lb/mmBtu.... 0.15 lb/mmBtu.... 0.12 lb/mmBtu. $1,263........... $1,468........... $1,760. Large Non-EGUs................ 50% reduction.... 60% reduction.... 70% reduction. $1,235........... $1,477........... $2,155. Process Heaters............... $3,000/ton $4,000/ton $5,000/ton maximum per source. maximum per maximum per $2,891. source. source. $2,859........... $2,891........... ---------------------------------------------------------------------------------------------------------------- \10\ The cost-effectiveness values in Table II-4 are multistate averages. In the case of large EGUs the cost- effectiveness values represent reductions beyond those required by title IV or title I RACT, where applicable. For large non-EGUs and process heaters, the cost-effectiveness values represent reductions from uncontrolled levels.

The following discussion explains the controls determined by EPA to be highly cost-effective for each subcategory. i. Large EGUs. For large EGUs, the control level was determined by applying a uniform NOX emissions rate across the 20 jurisdictions potentially subject to section 126 findings. The cost- effectiveness for each control level was determined using the Integrated Planning Model (IPM). Details regarding the methodologies used can be found in the Regulatory Impact Analysis of the NOX SIP call rulemaking. Table II-4 summarizes the control levels and resulting cost effectiveness of three levels analyzed. A regionwide level of 0.20 lb/mmBtu was rejected because though it resulted in an average cost effectiveness of less than $2,000 per ton, the air quality benefits were less than those for the 0.15 lb/mmBtu level which was also less than $2,000 per ton. The results suggest that a multistate level of 0.15 lb/mmBtu should be assumed when determining the emission levels for this subcategory. This control level has an average cost-effectiveness of $1,468 per ozone season ton removed.11 This amount is consistent with the range for cost-effectiveness that EPA has derived from recently adopted (or proposed to be adopted) control measures. ---------------------------------------------------------------------------

\11\ It should be noted that in the final NOX SIP call EPA also investigated the regionwide cost-effectiveness of NOX reductions if each State individually met the budget component for large electricity generating boilers and turbines (i.e., through intra-state trading). In the case of the 0.15 lb/ mmBtu strategy intra-State trading resulted in a regionwide cost- effectiveness of $1,499/ton compared to $1,468/ton for regionwide trading. ---------------------------------------------------------------------------

The EPA acknowledges that a control level of 0.12 lb/mmBtu, which carries a cost effectiveness of $1,760 per ozone season ton removed, appears to be within the upper range of cost effectiveness. However, for reasons explained in Section II.D. of the final NOX SIP call, the EPA is proposing in the section 126 action not to base the EGU control level on 0.12 lb/mmBtu. Therefore, EPA proposes to retain and apply here its determination from the NOX SIP call rulemaking that it is highly cost effective to control emissions from large EGUs to a control level corresponding to 0.15 lb/mmBtu. ii. Large Non-EGUs. The EPA determined a highly cost-effective control level for large non-EGUs by applying a uniform percent reduction multistate in increments of 10 percent. Details regarding the methodologies used are in the Regulatory Impact Analysis. Table II-4 summarizes the control levels and resulting cost effectiveness for non- EGUs. For large non-EGUs, the cost-effectiveness determination includes estimates of the additional emissions monitoring costs that sources would incur in order to participate in a trading program. Some non-EGUs already monitor their emissions. In the proposed NOX SIP call, EPA had not included monitoring costs in the cost-effectiveness determination because such costs could not be estimated at that time. Since then, EPA has evaluated monitoring system costs. These costs are defined in terms of dollars per ton of NOX removed so that they can be combined with the cost-effectiveness figures related to control costs. Monitoring costs varied from about $150 to $400 per ton of NOX removed, depending on the type of subcategory. The EPA, therefore, proposes to retain and apply here its determination from the NOX SIP call rulemaking that for large non-EGUs a control level corresponding to 60 percent reduction from baseline levels is highly cost effective (this percent reduction corresponds to a multistate control level of about 0.17 lb/mmBtu). iii. Large Process Heaters. For large process heaters, the control level was determined by applying various cost-effectiveness thresholds, because trading was not assumed to be readily available for this subcategory. Details regarding the methodologies used are in the Regulatory Impact Analysis. Table II-4 summarizes the control levels and resulting cost effectiveness for each option under this subcategory. The EPA determined that controlling process heaters, though reasonably cost effective, is not highly cost effective. Thus EPA proposes that these sources do not emit in amounts that significantly contribute to petitioning States' nonattainment or maintenance problems. iv. Small Sources. For the subcategory of small sources, EPA is proposing to determine that no additional control measures or levels of control are highly cost effective and feasible to mandate. For the purposes of this rulemaking, EPA considers the following sizes of point sources to be small: (1) Electricity generating boilers and turbines serving a generator 25 MWe or less, and (2) other indirect heat exchangers with a heat input of 250 mmBtu/hr or less. In the NOX SIP call, EPA found that the collective emissions from small sources were relatively small (in the context of that rulemaking) and the administrative burden, to the permitting authority and to regulated entities, of controlling such sources was likely to be considerable. In today's action, for the same reasons as described in the final NOX SIP call, EPA proposes that these sources do not emit in amounts that significantly contribute to petitioning States' nonattainment or maintenance problems. Further discussion concerning small point sources may be found in the final NOX SIP call preamble. v. Summary of Control Measures. Table II-5 summarizes the controls that are assumed for each subcategory. More detailed discussions of the controls assumed are contained in the sections that describe each sector.

Table II-5.--Summary of Feasible, Highly Cost-Effective NOX Control Measures ------------------------------------------------------------------------ Subcategory Control measures ------------------------------------------------------------------------ Large EGUs........................ State-by-State ozone season emissions level (in tons) based on applying a NOX emission rate of 0.15 lb/mmBtu on all applicable sources. Large Non-EGUs.................... State-by-State ozone season emissions level (in tons) based on applying a 60 percent reduction from uncontrolled emissions on all applicable sources. Large Process Heaters............. No additional controls highly cost effective. Small Sources..................... No additional controls highly cost effective. ------------------------------------------------------------------------

3. Other Cost-Related Considerations The EPA has addressed other cost-related considerations as described in Section II.D of the final NOX SIP call notice. The EPA proposes to rely on that analysis in this rulemaking.

D. Identifying Sources

As discussed previously, all of the petitions named specific upwind source categories as significantly contributing

to nonattainment in, or interfering with maintenance by, the petitioning State. Four petitioning States (Massachusetts, New Hampshire, New York, and Rhode Island) also attempted to identify the existing sources in the targeted source categories. However, the petitioners cautioned EPA that the lists might not be complete and that any omissions were unintentional. In addition, the EPA has received several comments from sources on the State lists saying that they do not meet the source category definitions provided in the petitions. In order to identify and verify the sources in the named source categories for the geographic areas covered by each petition, EPA used the most up-to-date emission inventory available. These data sources are described in Section III of this notice. The existing sources in the source categories for which EPA is making an affirmative technical determination are listed in Appendix A to proposed part 97. The EPA seeks comment on whether it has identified correctly the sources covered by the petitions.

E. Air Quality Assessment

In the final NOX SIP Call rulemaking, EPA evaluated the ozone benefits in the petitioning States of NOX controls proposed in today's action. The EPA believes that the results of that modeling analysis are valid for the purpose of this proposed rulemaking, as well. The EPA performed the modeling for the 23 jurisdictions covered in the NOX SIP Call to confirm that those States collectively contribute significantly to downwind nonattainment. The collective contribution of all the upwind States is one factor that went into EPA's decision that each individual upwind State contributes significantly to downwind nonattainment. The ozone benefits determined in the final NOX SIP Call were based on air quality modeling of the emissions scenarios described below. Each emissions scenario was modeled by EPA using UAM-V run for all four of the OTAG episodes (i.e., July 1-11, 1988; July 13-21, 1991; July 20-30, 1993; and July 7-18, 1995). In brief, the emissions scenarios include a 2007 Base Case and a control scenario designed to evaluate the effects of NOX controls on nonattainment in downwind States, including each of the petitioning States. The Base Case scenario accounts for growth in emissions and reductions associated with Clean Air Act mandated controls and additional Federal measures. In the control strategy scenario, NOX emissions from utility and non-utility sources were reduced by applying controls, very similar to those in today's proposal, to all such sources in the 23 jurisdictions which EPA has found, in the NOX SIP Call, contain emissions which make a significant contribution to nonattainment in downwind areas. The details on the development of these two emissions scenarios are described in the final NOX SIP Call rulemaking. The EPA recognizes that the amount of emissions reduction in the modeled strategy is not identical to the amount of emissions reduction in today's proposal. This is because of differences in (a) the underlying emissions inventories and (b) the level of emissions controls applied to individual sources. However, the overall effect of these differences on the percent emissions reductions is small. Specifically, the difference in the total NOX emission reductions for the 20 jurisdictions covered by today's proposal between what was assumed in the modeling compared to what is being proposed today is only 3 percent. The EPA also recognizes that there are three additional upwind States (i.e., Georgia, South Carolina, and Wisconsin) which are controlled in the modeled strategy that are not covered by today's proposal. These three States were covered in the NOX SIP Call because of their contributions to States other than the petitioning States. Since EPA believes that emissions from sources in these States do not contribute significantly to nonattainment in any of the petitioning States, it is reasonable to assume that emissions reductions in these States will not have any appreciable impact on nonattainment in any of the petitioning States. The EPA believes that the differences between today's proposal and what was modeled, as described above, are relatively small, and thus, the overall conclusions on air quality benefits from the modeled strategy are applicable to the controls in today's proposal. The EPA used a number of ``metrics'' (i.e., measures of ozone contribution or impact) to evaluate the air quality benefits in the petitioning States of the proposed NOX controls. The technical details of the air quality modeling information and metrics are described in the final NOX SIP call rulemaking. The results of this modeling indicate that the proposed NOX controls applied to the sources in the upwind States proposed as making a significant contribution to nonattainment in one or more of the petitioning States will provide substantial ozone benefits in each of the petitioning States.

F. Conclusions on Granting or Denying the Petitions

The EPA is proposing action on the petitions based on the outcome of the multi-step process described in the preceding sections. The EPA's proposed action consists of three components: (1) Technical determinations of which upwind sources or source categories named in each petition significantly contribute to nonattainment or interfere with maintenance of the relevant ozone standard in each petitioning State; (2) action specifying when a finding that such sources emit or would emit in violation of the section 110(a)(2)(D)(i)(I) prohibition will be deemed made or not made (or made but subsequently withdrawn) and, thus, when a petition for such a finding will be deemed granted or denied (or granted but subsequently denied) for purposes of section 126(b); and (3) the specific emissions-reduction requirements that will apply when such a finding is deemed made. Each of these proposed actions is described in more detail below. Under EPA's proposed action, certain types of new and existing sources in 20 upwind States are potentially subject to a section 126(b) finding and therefore to the requirements set forth in this proposal. 1. Technical Determinations First, EPA proposes to make affirmative and negative technical determinations as to which of the new (or modified 12) or existing major sources or groups of stationary sources named in each petition emit or would emit NOX in amounts that will contribute significantly to nonattainment of the 1-hour or 8-hour standard in (or interfere with maintenance of the 8-hour standard by) each respective petitioning State. The regulatory text accompanying today's proposal sets forth each of those proposed technical determinations for sources named in each petition. ---------------------------------------------------------------------------

\12\ Whenever the word ``new'' is used in relation to sources affected by this proposed rule, it includes both new and modified sources. ---------------------------------------------------------------------------

In short, for each petition, with respect to each ozone standard, EPA proposes to make affirmative technical determinations of significant contribution (or interference) for those large EGU and non- EGU sources for which highly cost-effective controls are available (as described in Section II.C.), to the extent those sources are located in one of the ``Named Upwind States'' corresponding to that petition in Tables II-1 and II-2. Thus, to illustrate, for the petition from New York, EPA proposes to find that large EGUs and non-EGUs

of the types described in Section II.C. that are located in the named portions of Delaware, the District of Columbia, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, and West Virginia emit NOX in amounts that contribute significantly to nonattainment of the 1-hour standard in New York. By contrast, EPA proposes to find that such sources located in Tennessee, which New York also named in its petition, do not emit NOX in amounts that have that effect on New York. The result is that EPA proposes to find that the large EGUs and non-EGUs in at least some upwind States named in every petition except Vermont's contribute significantly to nonattainment of at least one of the standards (or interfere with maintenance of the 8-hour standard) in the petitioning State. The EPA refers the reader to the regulatory text for a full description of each of the proposed technical determinations for each petition. The EPA notes that the Agency is not proposing to make affirmative technical determinations as to any sources located in Vermont, New Hampshire, or Maine. That is because, based on the more limited modeling and other assessments that EPA has done thus far with respect to those States, EPA is not yet prepared to conclude that sources in any of those States do contribute significantly to nonattainment (or interfere with maintenance) of an ozone standard in any downwind State named in one of those three States in its petition.13 However, EPA is continuing to study the impacts of sources in those States on downwind States, so that it can make final decisions based on the fuller set of information available today for other States. If EPA believes, after completing its assessments, that large EGU or non-EGU sources in any of those three States do contribute significantly to downwind air quality problems in any of the States that name them in their petitions, EPA will issue a supplemental notice of proposed rulemaking based on those results. ---------------------------------------------------------------------------

\13\ Maine's petition named sources in Vermont and New Hampshire and New Hampshire's petition named sources in Maine and Vermont. ---------------------------------------------------------------------------

Appendix A to proposed part 97 lists all existing sources for which EPA proposes to make an affirmative technical determination linking those sources to at least one petitioning State. These are the existing sources that could receive a positive section 126(b) finding, depending on the circumstances described in the next section. 2. Action on Whether To Grant or Deny Each Petition a. Portions of Petitions for Which EPA Is Proposing an Affirmative Technical Determination. For the reasons described in Section II.A.2.c., EPA proposes to issue the type of final action on the petitions described in that section. Under that approach, EPA's final action for sources that EPA is proposing an affirmative technical determination would provide that a finding that certain sources emit or would emit in violation of the prohibition in section 110(a)(2)(D)(i)(I) would be deemed made as of certain specified dates if certain events do not occur by those dates. More specifically, a finding that new or existing sources, for which EPA has made an affirmative technical determination, do emit in violation of section 110(a)(2)(D)(i)(I) would be deemed made: • As of November 30, 1999, if by such date EPA does not issue either a proposed approval, under section 110(k) of the CAA, of a State implementation plan revision submitted by such State to comply with the requirements of section 110(a)(2)(D)(i)(I) of the CAA; or final Federal implementation plan meeting such requirements for such State in which the affected sources are or will be located, • As of May 1, 2000, if by November 30, 1999, EPA takes the action described above for such State, but, by May 1, 2000, EPA does not approve or promulgate implementation plan provisions meeting such requirements for such State. The EPA also proposes to find, as described earlier, that any such finding as to any such major source or group of stationary sources would be considered a finding under section 126(b) and, therefore, would trigger the remedial requirements of the final rule. At such time as a finding is deemed made, EPA intends to publish a notice in the Federal Register announcing the source categories and locations affected by the finding. Furthermore, EPA proposes that as to any portion of a petition for which EPA has made an affirmative technical determination (as described above) that portion of the petition shall be deemed denied as of May 1, 2000, if a section 126(b) finding has not been deemed to have been made by that date. In other words, if EPA has taken final action putting into place an implementation plan meeting the requirements of section 110(a)(2)(D)(i)(I) by May 1, 2000, any outstanding portions of petitions will be deemed denied by that date. In addition, after a section 126(b) finding has been deemed made as to sources or groups of stationary sources in an upwind State, that finding will be deemed withdrawn, and the corresponding part of the relevant petition(s) denied, if the Administrator either approves a SIP or promulgates a FIP which complies with the requirements of section 110(a)(2)(D)(i)(I) for such upwind State. This would minimize any overlap between an effective section 126(b) finding, on one hand, and the application of satisfactory SIP or FIP provisions, on the other. b. Portions of Petitions for Which EPA Is Proposing a Negative Technical Determination. Consistent with this overall approach, EPA proposes that the sources for which EPA would make a negative technical determination (as described above) do not or would not emit in violation of the section 110(a)(2)(D)(i)(I) prohibition. As a result, EPA proposes to deny each aspect of each petition relating to such sources. For example, EPA proposes to deny New York's petition as to sources in any State (or portion of a State) named in New York's petition that is outside the large EGU and non-EGU categories described in Section II.C., as well as any named sources of any type in Tennessee. Another example is that EPA proposes today to deny Vermont's section 126 petition in its entirety, because EPA proposes to find that no sources named in Vermont's petition, in any of the upwind States that the petition names, contribute significantly to nonattainment of either the 1-hour or the 8-hour standard, nor interfere with maintenance of the 8-hour standard, in Vermont. 3. Requirements for Sources for Which EPA Makes a Section 126(b) Finding The EPA proposes in Section III, below, the requirements that would apply to any new or existing major source or group of stationary sources for which a section 126(b) finding is ultimately made under the approach just described. Section 126(c) states, in relevant part, that:

it shall be a violation of this section and the applicable implementation plan in such State (1) for any major proposed new (or modified) source with respect to which a finding has been made under subsection (b) to be constructed or to operate in violation of this section and the prohibition of section 110(a)(2)(D)([i]) or this section or (2) for any major existing source to operate more than three months after such finding has been made with respect to it.

The Administrator may permit the continued operation of a source referred to in paragraph (2) beyond the expiration of such three-month period if

such source complies with such emission limitations and compliance schedules (containing increments of progress) as may be provided by the Administrator to bring about compliance with the requirements contained in section 110(a)(2)(D)([i]) as expeditiously as practicable, but in no case later than three years after the date of such finding. The remedial requirements that EPA proposes to apply to sources for which a section 126(b) finding is ultimately made would satisfy the requirements just quoted. First, EPA proposes to find that new sources for which a section 126(b) finding is ultimately made must comply with the requirements described in Section III to ensure that they do not emit in violation of the section 110(a)(2)(D)(i) prohibition. Second, the program EPA is proposing serves as the alternative set of requirements that the Administrator may apply for the purpose of allowing existing sources subject to a section 126(b) finding to operate for more than three months after the finding is made. Consistent with section 126(c), the compliance period in EPA's proposed program extends no further than three years from the making of the finding. To the extent a finding is deemed made as of November 30, 1999, compliance will be required by November 30, 2002. But since the program EPA is proposing would require actual emissions reductions only in the ozone season, actual reductions will not need to occur until May 1, 2003, the start of the first ozone season after the November 30, 2002, compliance date. Thus, compliance by November 30, 2002 would not require actual reductions until May 1, 2003. As described in Section V.A.1 of the final NOX SIP call, EPA believes that compliance by the ozone season beginning May 1, 2003 is feasible. Section III of this notice describes the proposed section 126 control requirements in greater detail.

III. Federal NOX Budget Trading Program

A. Program Summary

1. Purpose of the Federal NOX Budget Trading Program Under section 126(c), EPA proposes to implement the Federal NOX Budget Trading Program, a capped market-based system for certain combustion sources in covered upwind States to bring sources covered by any final section 126 finding into compliance. This type of program is a proven method for achieving the highly cost-effective emissions reductions described above while providing sources compliance flexibility. (See SNPR for NOX SIP call at 63 FR 25918-19, discussing OTAG's conclusions concerning advantages of market-based systems). The Federal NOX Budget Trading Program would be triggered automatically if EPA makes a final finding as to any sources under section 126, as described in Section II.F. Participation in the Federal program would be mandatory for all sources affected by a triggering of this section 126 remedy. It would also be mandatory for all sources required to reduce emissions by the promulgated FIP, with the exception of cement kilns and internal combustion engines. The EPA would like to clarify that the use of the term ``budget'' in the context of the Federal NOX Budget Trading Program does not mean that there is an aggregate emissions level that is enforceable for the purposes of the section 126 remedy. Rather, the term refers to the aggregate emission levels in each State for units required to participate in the Federal NOX Budget Trading Program as a section 126 remedy or as part of a FIP. The aggregation of sources allocations is initially only for purposes of determining the total amount available for allocation and and should not be construed to represent a separate requirement for sources in the program for purposes of any section 126 remedy. The Federal NOX Budget Trading Rule is proposed in a new Part 97 in Title 40 of the Code of Federal Regulations. Because EPA is proposing to implement the Federal NOX Budget Trading Program both in response to the section 126 petitions and as part of a FIP if necessary; EPA intends to finalize part 97 in whichever of these actions is finalized first. (The EPA expects part 97 will be finalized in the section 126 rulemaking because final action on the remedy portion of section 126 is required by April 30, 1999 under the proposed consent decree discussed above.) In finalizing part 97, EPA intends to respond to the comments it receives regarding part 97 through both the proposed section 126 remedy and the proposed FIP. Therefore, commenters who have identical comments in both rulemakings may submit their comments to one docket and merely reference such comments in their submission to the other docket. However, to the extent comments on part 97 are solely related to how it would be applied through a triggering of the section 126 remedy, commenters should submit such comments to the docket for this proposed section 126 remedy. 2. Relationship of the Section 126 Remedy to the NOX SIP Call and the FIP. The sources or groups of sources identified in the section 126 petitions are also sources for which EPA recommends States adopt emission limitations and control strategies in response to the NOX SIP call. The NOX SIP call establishes an emissions budget for all sources of NOX emissions in all States determined by EPA to significantly contribute to nonattainment or interfere with maintenance of the ozone NAAQS in any other jurisdiction. The FIP sets specific stationary source rules to decrease NOX emissions and meet the NOX SIP call budget. The section 126 proposed action, on the other hand, is limited to major stationary sources or groups of stationary sources that are named in the section 126 petitions and that EPA finds emit or would emit in violation of the prohibition in section 110(a)(2)(D)(i) relative to a petitioning State. Despite this difference in the scope of the proposed section 126 action and the proposed FIP or final NOX SIP call, all three actions are aimed at reducing the transport of ozone by controlling emissions from sources in a given State that are found to be contributing significantly to nonattainment or maintenance problems in another State. The EPA has promulgated the State NOX Budget Trading Program, a cap-and-trade program for large combustion sources, to assist States in meeting their obligations under the final NOX SIP call. The EPA believes that this State NOX Budget Trading Program--if selected by States to meet their SIP call obligations--could be coordinated and integrated with the Federal NOX Budget Trading Program promulgated in a section 126 rule or a FIP, in order to address the transport problem on a regional scale. Integration is possible because, as noted above, both the NOX SIP call, the corresponding FIP, and the section 126 petitions seek to mitigate the ozone transport problem by reducing emissions from upwind sources that hinder attainment or maintenance of the ozone NAAQS downwind. Further, the sources covered in the State NOX Budget Trading Program under the NOX SIP call include a majority of the sources named by petitioning States, and are identical in size and categorization to sources for which EPA proposes issue rules in the section 126 and FIP proposed actions. In order to be eligible to participate in a cap-and-trade program, the EPA

believes that there are two principal criteria that sources must meet, as stated in the supplemental notice for the proposed NOX SIP call (62 FR 25923). The first criterion requires that sources be able to account accurately and consistently for all of their emissions in order to maintain emissions within a cap. The second criterion is the ability to identify a responsible party for each regulated source who would be accountable for demonstrating and ensuring compliance with the program's provisions. Assuming that these criteria are met, and consistent control levels are used in setting emission requirements for the covered sources, EPA supports the establishment of a common trading program among sources subject to a trading program under the NOX SIP call, a section 126 remedy, or a FIP among sources subject to a trading program under the NOX SIP call, a section 126 remedy or a FIP. The resulting multi-state trading program could include all sources in States found to be significantly contributing to nonattainment or interfering with maintenance of the ozone standard in another State. Under this common trading program, sources subject to the Federal NOX Budget Trading Program under the section 126 rulemaking or the FIP, and sources in States choosing to participate in the State NOX Budget Trading Program in response to the NOX SIP call, could trade with one another under a NOX cap across participating States. The EPA's analyses in conjunction with the NOX SIP call exhibit that implementation of a single trading program with a uniform control level results in no significant changes in location of emissions reductions as compared to a non-trading scenario. Therefore, the common trading program will achieve the intended emissions reductions while providing flexibility and cost savings to the covered sources. Integration of the trading programs reduces the possibility of inconsistent or conflicting deadlines or requirements, increases the potential cost savings for sources, and streamlines program administration. Inconsistency could hamper the sources' ability to plan and achieve the needed reductions as cost-effectively as possible. In addition, if a State subsequently elects to submit a SIP including a trading program after EPA has already established a Federal NOX Budget Trading Program under a FIP or section 126 remedy, disruptions to sources that would shift from regulation under a FIP or section 126 remedy to regulation under a SIP would be minimized. Because sources may be included in the common trading program through one of three possible mechanisms, the sources included in the trading program for purposes of the NOX SIP call may vary from sources included for purposes of the section 126 remedy. The EPA does not foresee this to be problematic since sources would face consistent control requirements regardless of which rulemaking includes the sources in the common trading program. That the requirements would be consistent follows from the similar nature of the rulemakings and the comparable level of control which EPA has determined to be cost- effective for each source category across all three actions. The EPA proposes in part 97 to establish the geographic boundaries of the common trading program as those States submitting SIPs in response to the final NOX SIP call or subject to FIPs and/or the sources in States for which EPA makes a finding for the section 126 petitions. The EPA would administer this common trading program in collaboration with affected States. The EPA is proposing a Federal NOX Budget Trading Program as part of the FIP or section 126 remedy which mirrors, to the extent feasible, the State NOX Budget Trading Program (set forth in part 96) which is the model trading program that is available for States to adopt in response to the NOX SIP call. While EPA is proposing to keep the programs as similar as possible, there are several differences which are more fully described below. These differences arise primarily from the need for Federal implementation of the program rather than State implementation. For example, EPA must determine the NOX allowance allocations for each unit in the Federal NOX Budget Trading Program, rather than simply provide an example that States may use to determine allocations, as is the case in the State NOX Budget Trading Program.

B. Federal NOX Budget Trading Program

1. Program Overview In part 97, the EPA proposes a cap-and-trade program as an aggregate remedy for the section 126 petitions which it today proposes to determine are technically valid. Four of the eight petitioning States (New York, Connecticut, Pennsylvania, and Maine) requested that EPA establish such a trading program to implement the required reductions. The EPA has authority under section 126 to require sources or groups of sources for which a finding of significant contribution is made to comply with a cap-and-trade program. Section 126(c) provides that such sources or groups of sources may continue to operate if they comply ``with such emission limitations and compliance schedules (containing increments of progress) as may be provided by the Administrator to bring about compliance'' with section 110(a)(2)(D). Under section 302, an ``emission limitation'' is ``a requirement * * * which limits the quantity, rate, or concentration of emission of air pollutants on a continuous basis.'' In fact, title IV of the CAA refers to the allowance requirements of the Acid Rain SO2 cap-and- trade program as ``emission limitations.'' 42 U.S.C. 7651c(a). Under a cap-and-trade program, the Administrator sets an emission limitation and compliance schedule for each unit subject to the program. The emission limitation for each unit is the requirement that the quantity of the unit's emissions during a specified period (here, the tonnage of NOX emissions during the ozone season) cannot exceed the amount authorized by the allowances (here, NOX allowances, each authorizing one ton of emissions) that the unit holds. Allowances are allocated to units subject to the program, and the total number of allowances allocated to all such units for each control period is fixed or capped at a specified level. The compliance schedule is set by establishing a deadline by which units must begin to comply with the requirement to hold allowances sufficient to cover emissions. In essence, for purposes of complying with section 126, EPA would be translating emission limits into allowance requirements. Since under section 126 EPA has the authority to establish emission limits, and allowance requirements are equivalent to emission limits, EPA has the authority to promulgate allowance requirements and allocate allowances for purposes of section 126. Since a cap-and-trade program is a compliance mechanism which enables sources to make cost-effective decisions to meet their allowance requirements, which are equivalent to emission limits, EPA believes it has the authority under section 126(c) to adopt a cap-and-trade program as a cost effective means of implementing the requirements of sections 126 and 110(a)(2)(D). Sources potentially subject to the emission limitations and compliance schedule in the Federal NOX Budget Trading Program for the purposes of the section 126 petitions are those sources named by petitioning States and found by EPA to be emitting in violation of the prohibition in a petitioning State. The

section 126 remedy will apply to these sources in States for which a finding is triggered by the terms of today's proposed rule. For the reasons discussed in Section II, these sources include any fossil fuel- fired unit (boiler, turbine, or combined cycle) that serves a generator with a nameplate capacity greater than 25 MWe, and any fossil fuel- fired unit (boiler, turbine, or combined cycle) that has a maximum design heat input of greater than 250 mmBtu/hr, located in any of the following twenty States: Alabama, Connecticut, Delaware, District of Columbia, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, Tennessee, Virginia, and West Virginia. The EPA requests comment as to whether additional stationary sources that emit to a stack, can monitor NOX mass emissions, and are located in a State where a finding is made under section 126, but are not named in a petition, should be able to voluntarily participate in the trading program. In today's notice, EPA proposes providing these individual stationary sources the opportunity to opt in to enable further cost savings from the Federal NOX Budget Trading Program. These opt-in provisions would be very similar to the opt-in provisions allowed under the State NOX Budget Trading Program in part 96 (see Section III.B.3.e for explanation). The NOX allowances--each allowance representing a limited authorization to emit one ton of NOX--would be the currency used in the trading program. A fixed number of NOX allowances would be allocated to sources for each ozone season equal to the total amount of the aggregate emissions permitted among the sources in each State included in the Federal NOX Budget Trading Program for purposes of the section 126 remedy. The EPA has included in today's proposal several alternative methodologies that EPA could use to allocate NOX allowances to units. Appendix A proposed part 97 sets forth the allocation for each unit based on the proposed methodologies. The control period for the trading program (i.e., the period during which a source must hold sufficient NOX allowances to cover emissions) would extend from May 1 through September 30, which is the same as the control period under the NOX SIP call and the FIP proposal. The EPA's proposed trading program remedy is based on the application of a uniform control level to the covered universe of sources. Based on analyses done in connection with the proposed NOX SIP call (63 FR 25921) and the final NOX SIP call, EPA maintains that trading could occur across States included in a NOX Budget Trading Program without restrictions, other than the requirement to comply with existing emission limits under title I and title IV of the CAA, as well as any other State limitations. Under today's proposed rule, sources in the Federal NOX Budget Trading Program would be required to monitor and report their emissions in accordance with relevant portions of 40 CFR part 75. The EPA has promulgated revisions to part 75 that establish NOX mass monitoring requirements and provide greater flexibility to regulated sources. Consistent and accurate monitoring of emissions is necessary for accountability regarding compliance with the requirement to hold NOX allowances and to ensure that a ton of emissions attributed to one source in one State is equivalent to a ton attributed to another source in the same or another State. Under today's proposed rule, EPA would be responsible for all aspects of program implementation, with the exception of permitting. Permitting would be handled by States in accordance with the requirements of the proposed rule. As further explained in Section III.B.2.c., the Federal NOX Budget Trading Program does not require a new or separate permit. If a source already has in place a federally enforceable permit, either title V or non-title V, the source's trading program obligations must be incorporated into this permit; if a source does not have a federally enforceable permit, the federally-enforceable NOX Budget Trading Rule applies to the source on its own accord. As discussed herein, EPA proposes to make the Federal and State NOX Budget Trading Programs as similar as possible and has modeled proposed part 97 after part 96 just finalized. The EPA notes that discussion of the evolution of the NOX Budget Trading Program is set forth in the supplemental notice of the proposed NOX SIP call rule at 63 FR 25921-23 and in the final NOX SIP call rule. 2. Elements of the Federal NOX Budget Trading Program That Are the Same as the State NOX Budget Trading Program Under part 97, as proposed, the following sections would be virtually identical to the corresponding sections in part 96, which sets forth the State NOX Budget Trading Program. The EPA proposes to retain and rely on the analyses and considerations undertaken in the NOX SIP call process to determine these program elements. Moreover, the provisions in part 97 would be numbered in the same sequence as the corresponding provisions in part 96, so that, for example, Sec. 97.2 and Sec. 96.2 or Sec. 97.81 and Sec. 96.81 would address the same subject matter. The major differences between the part 97 sections listed below and their corresponding part 96 sections would be the renumbering of cross references to other regulatory provisions so that a section in part 97 would reference the appropriate section in that part, as opposed to the section in part 96. More detailed information on the rationale for the part 96 provisions themselves can be found in the preamble accompanying the proposed part 96 (63 FR 25917-43) and the final part 96.

Subpart A--Federal NOX Budget Trading Program General Provisions

Sec. 97.3 Measurements, abbreviations, and acronyms. 97.5 Retired unit exemption. 97.7 Computation of time.

Subpart B--Authorized Account Representative for NOX Budget Sources

97.10 Authorization and responsibilities of the NOX authorized account representative. 97.11 Alternate NOX authorized account representative. 97.12 Changing the NOX authorized account representative and alternate NOX authorized account representative; changes in the owners and operators. 97.13 Account certificate of representation. 97.14 Objections concerning the NOX authorized account representative.

Subpart C--Permits

97.20 General NOX Budget permit requirements. 97.21 Submission of NOX Budget permit applications. 97.22 Information requirements for NOX Budget permit applications. 97.23 NOX Budget permit contents. 97.24 Effective date of initial NOX Budget permit. 97.25 NOX Budget permit revisions.

Subpart D--Compliance Certification

97.30 Compliance certification report.

Subpart F--NOX Allowance Tracking System

97.50 NOX Allowance Tracking System accounts. 97.51 Establishment of accounts. 97.52 NOX Allowance Tracking System responsibilities of NOX authorized account representative. 97.53 Recordation of NOX allowance allocations. 97.54 Compliance. 97.55 Banking. 97.56 Account error. 97.57 Closing of general accounts.

Subpart G--NOX Allowance Transfers

97.60 Scope and submission of NOX allowance transfers. 97.61 EPA recordation. 97.62 Notification.

The EPA requests comment on whether any of the part 97 provisions listed above should differ substantively from the corresponding provisions in part 96. If a commenter believes substantive differences in the rules are appropriate, the commenter should describe the favored changes and explain why these changes are appropriate. a. General Provisions. For part 97, EPA is proposing to use the same measurements, abbreviations, and acronyms, the same retired unit exemption, and the same provisions for computation of time as those that apply in part 96, with cross references to the appropriate sections in part 97, rather than to sections in part 96. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25923-27) and final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. b. Authorized Account Representative. The NOX Authorized Account Representative (NOX AAR) is the individual who is authorized to represent the owners and operators of each NOX Budget unit at a NOX Budget source in matters pertaining to the NOX Budget Trading Program. Subpart B of part 97 addresses, among other things, the process for designating and changing the NOX AAR and the responsibilities of the NOX AAR and alternate NOX AAR. These provisions are the same as those in part 96, with cross references to the appropriate sections of part 97. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25927) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. c. Permits. The regulations governing State permitting under title V define an ``applicable requirement,'' which must be reflected in a title V operating permit, as including ``[a]ny standard or other requirement provided for in the applicable implementation plan approved or promulgated by EPA through rulemaking under title I of the CAA that implements the relevant requirements of the CAA, including any revisions to that plan promulgated in part 52 of this chapter.'' 40 CFR 70.2. Since today's proposed rule is being promulgated under title I (i.e., under section 126), the requirements of this rule are applicable requirements under Sec. 70.2 and must be reflected in the title V operating permit of NOX Budget sources required to have such a permit. The EPA believes that the majority of NOX Budget sources will be required to have a title V permit. Further, all State and local air permitting authorities currently have EPA-approved title V operating permits programs. These State and local agencies would be the permitting authorities for the majority of NOX Budget sources with title V permits, for which the trading program requirements would be applicable requirements. For any sources that do not have a title V permit, such a permit is not required. If a source has a federally enforceable non-title V permit, the trading program requirements must also be incorporated into this permit. If a source does not have a federally enforceable permit, the requirements of the Federal NOX Budget Trading Rule would be federally enforceable without the federally enforceable permit. Subpart C of part 97 addresses, among other things, the administration of a permit, permit applications, permit contents, effective date, and permit revisions. These provisions are the same as those in part 96, with cross references to the appropriate sections in part 97. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25927-29) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. d. Compliance Certification. The NOX AAR must certify at the end of each control period that the unit was in compliance with the emissions limitation and other requirements of the Federal NOX Budget Trading Program. Proposed Sec. 97.30 sets forth the same provisions for compliance certification reports as those in part 96, with cross references to the appropriate sections in part 97. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25929) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. e. NOX Allowance Tracking System. The NOX Allowance Tracking System is an automated system used to track NOX allowances held by NOX Budget units under the NOX Budget Trading Program, as well as those allowances held by other organizations and individuals. Subpart F of part 97 addresses, among other things, NOX allowance tracking system accounts, the account responsibilities of the NOX AAR, the recordation of NOX allowance allocations, the compliance process, account error, and account closing. These provisions are the same as those in part 96, with cross references to the appropriate sections in part 97. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25933-37) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. f. Banking. The EPA proposes to include banking as a feature in the Federal NOX Budget Trading Program for the reasons set forth in the final NOX SIP call. Proposed Sec. 97.55 sets forth the same provisions for banking and the management of banked allowances as specified in part 96. In accordance with these provisions, NOX allowances held by units subject to the Federal NOX Budget Trading Program may be banked for future use starting in 2003 (except as noted in Section III.B.3.e.ii. of this preamble). However, as in the State NOX Budget Trading Program, the Federal NOX Budget Trading Program contains a flow control mechanism to limit the variability associated with banking. This mechanism allows unlimited banking by units subject to the Federal NOX Budget Trading Program, but discourages the ``excessive'' use of banked allowances by establishing a discount rate on the use of banked allowances over a certain level. Proposed part Sec. 97.55 establishes a flow control mechanism which applies a 2-for-1 discount ratio to the use of banked allowances above a certain level when the total number of banked allowances in the program exceeds 10 percent of the allowable NOX emissions for all sources covered by the Federal trading program. This flow control mechanism, along with the overall banking provisions, is proposed for the reasons set forth in both the proposed NOX SIP call (63 FR 25934-37) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. g. NOX Allowance Transfers. Subpart G of part 97 addresses, among other things, submission, recordation, and notification of transfers of NOX allowances under the NOX Budget Trading Program. These provisions are the same as those in part 96, with cross references to the appropriate sections in part 97. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25937-38) and the final NOX SIP call, and in order to minimize

differences between the Federal and State NOX Budget Trading Programs. h. Audits. While program audits are not explicitly required by today's rule, EPA intends to perform the same types of audits discussed concerning the proposed NOX SIP call (63 FR 25942) and the final NOX SIP call. 3. Elements of the Federal NOX Budget Trading Program That Differ From the State NOX Budget Trading Program The EPA proposes that the following sections in part 97 incorporate certain differences from the corresponding sections in part 96 to provide for Federal implementation of the NOX Budget Trading Program.

Subpart A--Federal NOX Budget Trading Program General Provisions

Sec. 97.1 Purpose. Sec. 97.2 Definitions. Sec. 97.4 Applicability. Sec. 97.6 Standard Requirements.

Subpart D--Compliance Certification

Sec. 97.31 Administrator's action on compliance certifications.

Subpart E--NOX Allowance Allocations

Sec. 97.40 Trading program budget. Sec. 97.41 Timing requirements for NOX allowance allocations. Sec. 97.42 NOX allowance allocations.

Subpart H--Monitoring and Reporting

Sec. 97.70 General requirements. Sec. 97.71 Initial certification and recertification procedures. Sec. 97.72 Out of control periods. Sec. 97.73 Notifications. Sec. 97.74 Recordkeeping and reporting. Sec. 97.75 Petitions. Sec. 97.76 Additional requirements to provide data for allocations purposes.

Subpart I--Individual Unit Opt-Ins

Sec. 97.80 Applicability. Sec. 97.81 General. Sec. 97.82 NOX authorized account representative. Sec. 97.83 Applying for NOX Budget opt-in permit. Sec. 97.84 Opt-in process. Sec. 97.85 NOX Budget opt-in permit contents. Sec. 97.86 Withdrawal from NOX Budget Trading Program. Sec. 97.87 Change in regulatory status. Sec. 97.88 NOX allowance allocations to opt-in units. a. General Provisions. i. Purpose. Proposed Sec. 97.1 explains that proposed part 97 sets forth the provisions for the Federal NOX Budget Trading Program addressing interstate transport of ozone and NOX. As discussed above, this program would be activated either under section 126 or under a FIP. ii. Definitions. For part 97, EPA is proposing to use the same definitions as those that apply in part 96, with cross references to the appropriate sections in part 97, with three exceptions. First, the definition of the term ``NOX Budget Trading Program'' would be altered to reflect the fact that the Federal trading program is established pursuant to part 52, as opposed to part 51.121, as is the case with the State NOX Budget Trading Program under part 96. Secondly, the definition for the term ``State'' would be altered to reference only those States that would be covered by any final section 126 or FIP action, and to reflect the fact that the Federal trading program would be promulgated for a State, as opposed to adopted by the State as is the case with the State NOX Budget Trading Program. Last, the term ``State trading program budget'' would be replaced with the term ``trading program budget''. For purposes of the FIP, the trading program budget would be the aggregated budget for all sources affected by the requirements to participate in the trading program in a given State under the FIP. For purposes of the section 126 action, the trading program budget would be referred to as the ``section 126 trading program budget for the State''. The term ``section 126 trading program budget for the State'' is used to clarify the fact that the budget for the Federal NOX Budget Trading Program is not aggregated to a State level for the purposes of the section 126 action except for the allocation calculation, since the focus in the remedy is sources rather than States. The following example illustrates the approach taken concerning the unchanged definitions: the term ``NOX Budget Unit'' is defined under part 97 as ``a unit that is subject to the NOX Budget Trading Program emissions limitation under Sec. 97.4 and Sec. 97.80'', while that term has the same definition under part 96 except that appropriate sections in part 96 are referenced (63 FR 25923). iii. Applicability. For the reasons discussed above, EPA proposes in part 97 that the Federal NOX Budget Trading Program for purposes of the section 126 remedy would apply to any fossil fuel-fired unit (boiler, combustion turbine, or combined cycle) that serves a generator with a nameplate capacity greater than 25 MWe, and any fossil fuel-fired unit (boiler, combustion turbine, or combined cycle) that has a maximum design heat input of greater than 250 mmBtu/hr, located in any of the following twenty States: Alabama, Connecticut, Delaware, District of Columbia, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, Tennessee, Virginia, and West Virginia. The remedy will apply to these sources in those States for which EPA makes a final finding granting a section 126 petition under the triggers included in the proposed rule. These are the same source categories included in the core group applicability for the voluntary State NOX Budget Trading Program, only in a more narrow range of States. In the NOX SIP call, EPA offered States the option of allowing units with a very low federally enforceable permit limitation (i.e., 25 tons per season) to be exempt from the trading program, even though they were above the applicability threshold (63 FR 25926). The EPA proposes to include this provision in the Federal NOX Budget Trading Program and solicits comment on the appropriateness of such inclusion. iv. Standard Requirements. Under the Federal NOX Budget Trading Program, the NOX Budget units and their owners, operators, and NOX AARs must meet certain standard requirements that incorporate the full range of program requirements by referencing other sections of the NOX Budget Trading Rule. These provisions are the same as the related provisions in part 96, with cross references to the appropriate sections of part 97, except that the Administrator, rather than the permitting authority, would allocate NOX allowances under the Federal NOX Budget Trading Program. This reflects the fact that the NOX Budget Trading Program would be Federally run, rather than run by the State as under the NOX SIP call. b. Compliance Certification. Proposed Sec. 97.31 is the same as Sec. 96.31 except that the Administrator has the sole responsibility for reviewing and auditing compliance certifications and other submissions under the Federal NOX Budget Trading Program. This reflects the fact that the part 97 NOX Budget Trading Program would be federally run rather than run by the State as under the NOX SIP call. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25929) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. c. Aggregate NOX Emissions Levels and Allowance Allocations. This section discusses the calculation of State specific aggregate emission levels and the methodology and timing for issuance of NOX Budget unit allocations. The EPA calculated the State specific aggregate emission levels that would remain after the application of reasonable and highly cost-effective

NOX controls to upwind sources which contribute significantly to nonattainment or maintenance problems in downwind States. These aggregate emission levels for each State for which a finding under section 126 may be triggered are listed in appendix C of today's notice for both EGUs and non-EGUs. Section II.C of this preamble describes the controls that were assumed for each subcategory of sources. In determining what controls to assume in calculation of the proposed emissions level for each subcategory, EPA used the cost- effectiveness rationale also described in Section II.C. The EPA also calculated individual unit allocations based on the State specific aggregate emission levels described in this section. Subpart E of today's proposed Federal NOX Budget Trading Rule addresses the allocation of NOX allowances to NOX budget units for purposes of the section 126 remedy. As in the allocation-related provisions in part 96, part 97 includes provisions for the timing of allocation issuance, the methodology for issuing allocations, and the allocations for new sources. However, in part 97, the Administrator, rather than the State, will determine the allocations. i. Data Sources. (1) EGUs. The EGU data base developed for this analysis consists of both utility EGUs and non-utility EGUs. The non- utility EGUs include independent power producers (IPPs) and non-utility generators (NUGs). Eight data sources were used to develop the base year EGU data: (1) EPA's Acid Rain Data Base (ARDB) (Pechan, 1997c); (2) EPA's 2007 Integrated Planning Model (IPM) Year 2007; (3) EPA's Emission Tracking System/Continuous Emissions Monitoring System (ETS/ CEM) (EPA, 1997b); (4) DOE's Form EIA-860 (DOE, 1995a); (5) DOE's Form EIA-767 (DOE, 1995b); (6) EPA's National Emissions Trends Data Base (NET) (EPA, 1997c); (7) DOE's Form EIA-867 (DOE, 1995c); (8) the OTAG Emission Inventory (Pechan, 1997a); and (9) incorporation of comments to the proposed NOX SIP call NPR dated November 7, 1997. More details regarding these data sources can be found in the technical support document (TSD) of EPA's NOX SIP call. (2) Non-EGUs. The starting point for the non-EGU data base was the 1990 OTAG Inventory. This inventory was prepared with 1990 State ozone SIP emission inventories supplemented with either State inventory data, if available, or EPA's National Emission Trends (NET) data if State data were not available. This inventory was further refined by the incorporation of comments to the proposed NOX SIP call NPR dated November 7, 1997. All records with utility SCCs (first 3 digits 101 or 201) were removed from the 1990 OTAG Inventory because it was assumed that emissions from these sources would be accounted for in the EGU component of the inventory. More details regarding these data sources can be found in the TSD of EPA's NOX SIP call. ii. Methodology Used To Determine Controlled Emission Levels. Section II of this preamble identifies the two subcategories that EPA proposes to control (i.e., large EGUs and large non-EGUs) and the emission levels that are highly cost-effective to achieve (i.e., 0.15 lb/mmBtu for EGUs and 60 percent reduction from uncontrolled levels for non-EGUs) in response to the section 126 petitions. This section describes the methodology used in determining each of these subcategory's emissions level on a State-by-State basis. (1) Large EGUs. For reasons explained in the final NOX SIP call, EPA is proposing to calculate each State's summer season large EGU emissions level using a specific NOX emission rate and the projected summer season utilization of the year 2007. Specifically, EPA proposes calculating each State's large EGU NOX emissions level by multiplying: (1) Each State's summer activity level in mmBtu (EPA selected the higher of each State's overall 1995 or 1996 summer utilization), by (2) each State's projected growth between 1996 and 2007 (using the IPM model), by (3) a NOX rate of 0.15 lb/mmBtu. The resulting figure, in lbs, was divided by 2000 (lbs per ton) to determine tons. In general, new units built to meet economic growth are lower emitting than the older units they augment or replace. Thus, though the industry's fuel utilization may increase over time, the industry's average NOX rate may decrease as newer, cleaner units are built and operated, and total emissions may or may not increase. The EPA proposes to incorporate growth in industrial activity when determining the large EGU emissions level, and thus accommodate new sources into the section 126 remedy. Specifically, EPA projects each State's projected change in utilization from current levels to the year 2007 and sets an emissions level based on that future year's utilization. This approach directly accommodates industrial growth. Additionally, this was the type of approach taken in the final NOX SIP call in determining various State emissions levels. Thus, EPA is proposing to use this type of approach for addressing activity growth and, as described below, using the IPM growth projections. Appendix C of proposed part 97 of this notice presents the resulting proposed large EGU emissions level per State along with each State's projected growth from 1996 to 2007. (2) Large Non-EGUs. For reasons explained in the final NOX SIP call, EPA is proposing to calculate each State's summer season large non-EGU emissions level by reducing each State's uncontrolled non-EGU NOX emissions levels (in tons) by 60 percent and assuming growth through the year 2007. Appendix C of proposed part 97 presents the resulting large non-EGU emissions level and projected growth rate for each State. iii. Development of Section 126 Trading Program Budget. Proposed Sec. 97.40 provides that the section 126 trading program budget for each State would equal the sum of the aggregate emission levels for large electric generating units and large non-electric generating units in each State calculated as discussed in Section III.B.3.c.ii of this preamble. Under section 126, the Administrator determines the ``emission limitations and compliance schedules'' with which NOX Budget units under Sec. 97.4 must comply. In the Federal NOX Budget Trading Program being proposed for the section 126 remedy, these NOX ``emission limitations'' take the form of NOX ``allowance allocations'' and are assigned based on the aggregate emission levels for the subcategories in the trading program. The approach to issuing allocations under a section 126 action is similar to that under the NOX SIP call, with the exception that under Sec. 96.40, the State permitting authority, rather than the Administrator, determines, through the SIP, the total amount of allowable NOX emissions apportioned to NOX Budget units. iv. Timing Provisions. Proposed Sec. 97.41 sets forth the provisions for when the Administrator will issue allocations of NOX allowances to NOX Budget units. Under the Federal NOX Budget Trading Program, the Administrator (rather than the State permitting authority) determines the NOX allowance allocations, as well as records them in the NOX Allowance Tracking System. Thus, proposed Sec. 97.41 does not provide, or set deadlines, for the permitting authority's submission of allocations to EPA. However, as discussed in the final NOX SIP call, EPA believes it is important to issue the allocations at least a couple years into the future to provide some predictability for sources in their control planning and build confidence in the market. Therefore, under part 97, the Administrator will issue NOX allowances in EPA's NOX Allowance

Tracking System (NATS) by April 1 of every year for the control period that is three years later. For example, EPA would issue the allocations for the 2003 control period by April 1, 2000, for those sources for which a finding has been triggered under section 126 at this time. For those sources for which a finding is not triggered by April 1, 2000, but for which a final finding is automatically triggered on May 1, 2000, EPA would issue the allocations for the 2003 control period to NATS as soon as practicable in the year 2000, consistent with the allocations finalized with this rulemaking. In both cases, EPA would issue the allocations for the 2004 control period by April 1, 2001, etc. so that the allocations are always known three years in advance. These provisions are consistent with the minimum timing requirements specified in the final NOX SIP call rulemaking. As stated in the previous paragraph, EPA will issue allocations in the NATS on an annual basis three years prior to the relevant control period. However, EPA proposes to use the same allocations for the first three years of the program (based upon one of the proposed methodologies described below), unless a State replaces the section 126 action with its own allocations in an approved SIP. The EPA proposes constant allocations for the first three control periods to provide more consistency and certainty and to build market confidence during the start-up phase of the program. Therefore, while the Agency will not record the allocations in unit accounts until April 1 of the year three years preceding each relevant control period, the allocations for 2004 and 2005 will be the same as the allocations for the 2003 control period. However, if a State, as part of an approved SIP, submits allocations for the 2004 control period to EPA prior to April 1, 2001, or for the 2005 control period prior to April 1, 2002, the State's allocations will replace the allocations EPA planned to issue for the relevant control season. By issuing allocations into accounts one year at a time, EPA is providing States the ability to replace a section 126 action with an approved SIP while still ensuring that sources receive allocations at least three years prior to the relevant control season. After the initial three year period, EPA may update its allocations on an annual basis three years prior to the relevant control season. As discussed in the final NOX SIP call, updating allocations on an annual basis (three years ahead) is intended to allow the allocation system to accommodate changes in market conditions. The EPA is proposing these part 97 provisions for the reasons set forth in the final NOX SIP call concerning part 96 and in order to minimize differences between the Federal and State NOX Budget Trading Programs. v. NOX Allowance Allocation Methodology. The EPA proposes that part 97 include the methodology that the Administrator will use for allocating NOX allowances to NOX Budget units. While in part 96 the Agency lays out an optional allocation methodology that may be used by a State permitting authority for issuing allocations, part 97 will prescribe the methodology that the Administrator would use. (1) EGUs. The EPA requests comment on three separate methodologies that the Administrator could use for the initial allocation period (the control periods in 2003 through 2005) for electricity generating units. In whichever of these methodologies the Agency finalizes, the total number of allowances issued would equal the portion of the section 126 trading program budget in each State attributed to large electricity generating units (calculated as described in Section III.B.3.c.ii of this preamble by multiplying a specified emission rate by a State's summer activity level projected to 2007). The first option is to allocate allowances based on the product of an emission rate in pounds of NOX/mmBtu and the mmBtus of energy utilized for all units in the Federal NOX Budget Trading Program; the proposed part 97 describes this approach. The second option is to allocate allowances to fossil-fuel-fired electric generating units in the Federal NOX Budget Trading Program based on the product of an emission rate in pounds of NOX/kWh and the kWh of electricity generated. A third option considered by EPA would allocate allowances to all large electric generating units, regardless of fuel type, in the States affected by the section 126 rulemaking based on their electricity generated. For the second and third options, EPA would use a surrogate for electricity generation data where electricity generation data is not available. The EPA solicits comment on these three methodologies. With regard to the allocation methodology to be used by the Administrator for the control periods starting in 2006, EPA requests comment on the same three general methodologies mentioned in the previous paragraph. To facilitate the use of the second and third approaches for the control periods in 2006 and thereafter, EPA proposes to work with stakeholders to design a system based on electricity generation that could be used after the initial allocation period. The EPA plans to propose an allocation system based on electricity generation in 1999 and finalize the approach in 2000. Appropriate data could then be measured and collected at NOX Budget units during the control periods in the years 2001 and 2002. When it becomes available, this approach could be incorporated into part 97 if the Agency decides to allocate allowances based on electricity generation. For whichever of these three allocation methods the Agency selects, EPA proposes to use the average of the data for the two highest control periods for the years 1995, 1996, and 1997 in determining an electric generating unit's allocation for the control periods in 2003, 2004, and 2005. This approach using data from 1995, 1996, and 1997 differs slightly from the way the aggregate emission level was calculated for the EGU subcategory. As explained in Section III.B.3.c.ii of this preamble, EPA calculated the aggregate emission level based upon the greater of the State heat input data from 1995 or 1996. However, the Agency believes it is useful to base the first three years of allocations to individual units on operating data reflecting the average of the highest of two out of the three most recent years. In this way, the initial allocations better represent the operation of particular units. Once several years of allocations have been built into the system, the Agency believes it is possible to move to an annually updating allocation system that calculates allocations based on operating data from a single year. Using data from a single year as a basis for allocations enables the Agency to develop an updating allocation system that can reflect changes in utilization or electricity generation. By this time, the trading market should be more established and companies will have several years of experience with the program. Therefore, companies will better be able to accommodate variations in single year allocations through the trading market and company-wide compliance strategies. Therefore, after the initial period of allocations, EPA would use data measured during the control period of the year that is four years before the year for which allocations are being calculated. Furthermore, for reasons discussed in the final NOX SIP call, EPA proposes the establishment of an allocation set-aside account for new units (units that commence operation during or after the period on which general NOX allowance allocations are based) to be used in whichever allocation methodology EPA adopts equaling 5 percent of the section

126 trading program budget in each State in 2003, 2004, and 2005 and 2 percent of the section 126 trading program budget in each State in the subsequent years. The Agency believes that if a new source set-aside is employed, it should be large enough to provide allocations to all new units entering the Federal trading program. Based on analyses EPA conducted using the Integrated Planning Model (IPM) and on the Agency's proposal to reallocate by April 1, 2003 for the control period in 2006, 5 percent appears to be a reasonable portion of NOX allowances to set-aside for new units in the initial three years of the program and 2 percent for the subsequent years. However, while 5 percent (and 2 percent) may be an appropriate region-wide average, an individual State may experience either more or less growth in new sources during the relevant time period. The EPA calculated the State-specific aggregate emission levels for each subcategory using State-specific growth rates (see the rulemaking docket). Therefore, EPA solicits comment on using State-specific growth rates to determine the appropriate size of a State new source set- aside. Additionally, the 5 percent (and 2 percent) numbers were calculated based upon estimated growth in utilization by new sources and therefore may be more appropriate when the first proposed allocation methodology is employed. The EPA solicits comment on the use of a different percentage for the set-aside if the Agency adopts an electricity generation-based allocation system. Using each of the three allocation methodologies on which EPA solicits comment, the Agency has calculated unit specific allocations. Two of the three sets of unit-specific allocations are in appendix A of proposed part 97, the third set is included in the rulemaking docket. The EPA is providing these unit specific allocations to solicit comment on the underlying data used in these allocations and the methodologies employed in determining the allocations. The Agency will select and describe a set of allocations for all sources potentially subject to the section 126 rulemaking in the final notice. The EPA would issue the finalized set of the 2003 control period allocations in the NATS by April 1, 2000 for those sources for which a finding has been triggered under section 126 at this time. For those sources for which a finding is not triggered by April 1, 2000, but for which a final finding is automatically triggered on May 1, 2000, EPA would issue the allocations for the 2003 control period to NATS as soon as practicable in the year 2000, consistent with the allocations finalized with this rulemaking. For the first allocation approach in part 97, EPA determined initial unadjusted allocations to existing electric generating NOX Budget units by multiplying a NOX emission rate of 0.15 lb/mmBtu by the units' historical heat input calculated by taking the average of the heat input for the two highest control periods for the years 1995, 1996, and 1997. The Agency used the heat input data reported to EPA in quarterly reports during ozone season for utilities affected under the Acid Rain Program. For non-utility electricity generators, EPA used heat input information reported to EIA on EIA Form 867. After determining the initial unadjusted unit allocations, EPA adjusted the allocation for each unit upward or downward to match the portion of the section 126 trading program budget in the State attributed to large electricity generating units. Then, the Agency adjusted the allocation for each unit in the State proportionately so that the total allocations equaled 95 percent of the portion of the section 126 trading program budget in the State attributed to large electricity generating units. This created a new source set-aside of 5 percent. For the second allocation approach, EPA multiplied the unit heat input in mmBtu and the generator heat rate 14 associated with the generation for that unit, in Btu/kWh, to determine each unit's associated historical electrical generation in kWh.15 For non-utility electricity generators, EPA used heat input from OTAG's database (1995 data) and the average heat rate values found below in Table III-1. The Agency used this indirect approach to calculate electrical output because EPA did not have access to unit-specific generation data for non-utility electricity generators. The EPA used average heat rate values for generators for which heat rates were not publicly available, as shown in the table below. ---------------------------------------------------------------------------

\14\ Utilities report their generator-specific heat rates to EIA on EIA Form 860. \15\ The EPA used the average generation for the ozone season during the highest two of the years from 1995 through 1997, similar to the approach with heat input.

Table III-1.--Average Utility Generator Heat Rates ------------------------------------------------------------------------ Average Unit and fuel type Generator size (MW) heat rate (Btu/kWh) ------------------------------------------------------------------------ Combustion Turbine (gas or No. 2 fuel 50 14250 oil/diesel). >50 13200 Combined Cycle Turbine (gas or No. 2 100 11100 fuel oil/diesel). >100 8500 Oil-or Gas-fired Steam Boiler......... 400 10600 >400 10000 Coal-fired Boiler..................... 500 10400 >500 9800 ------------------------------------------------------------------------

Some units are cogenerators, which are electrical generators that divert part of their steam to provide steam output, rather than to generate electricity. The Agency calculated output from cogenerating units as described in the previous paragraph. That approach assumes that heat input is converted into electricity at a particular efficiency. The EPA's proposed approach does not account for the fact that steam generation is generally more efficient than electricity generation. The EPA encourages commenters to provide the Agency electrical output data and steam output data to determine the efficiency of cogenerating units. To determine the individual unit allocations, EPA determined the total electricity generation from all affected electricity generating units within each State as estimated in the previous paragraphs and calculated each unit's share of the total State electricity generation. Each unit was then assigned an allocation based upon its share of electricity generation. For example, if the Agency calculated that a unit contributed 0.4 percent of a State's total electricity generation, then it would receive 0.4 percent of the section 126 trading program budget in the State attributed to large fossil-fuel-fired electricity generating units. After determining the initial unadjusted allocation, the Agency adjusted the allocation for each unit proportionately so that the total allocation equaled 95% of the portion of the section 126 trading program budget for the State attributed to large fossil-fuel- fired electricity generating units (to create the new source set- aside). The EPA is also proposing a third allocation approach which would provide allowances to all electricity generators in the applicable region regardless of the energy source. For fossil fuel-fired power plants, EPA used the approach described above in determining the electrical generation

from individual combustion units. For nuclear power plants and hydroelectric plants, EPA used electrical generation reported by utilities to EIA on EIA Form 759. The Agency was unable to find data for all plants. The Agency solicits comment on these methods for determining electricity generation data. The EPA also requests comment on the data itself and solicits any additional information for the plants for which EPA has not found data. The Agency determined the initial unadjusted allocations in the same manner as described for the electricity generation-based allocations to fossil-fuel-fired units only. That is, the Agency determined the total electricity generation within each State, calculated each unit's share of the total electricity generation, and calculated an allocation based upon that share of the section 126 trading program budget for the State attributed to large electricity generating units. The Agency then adjusted the allocation for each unit proportionately so that the total allocation equaled 95 percent of the portion of the section 126 trading program budget for the State attributed to large electricity generating units. For each of these three allocation methodologies, the Agency solicits comment on the data used to determine the allocations. Electricity generators, and utilities in particular, already report many of these data to Federal or State government agencies. The necessary data and their sources include: 1. For each plant: a. Plant name--as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state environmental agency b. ORISPL number, if available (or other unique identification number for the plant, if no ORISPL number exists)--as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state environmental agency iii. State postal abbreviation and county FIPS code as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state environmental agency iv. Monitoring locations at the plant (e.g., stacks or fuel pipes where monitoring equipment would be located) for existing monitoring equipment, as reported to U.S. EPA, or to the state environmental agency 2. For each unit (boiler or combustion turbine) at the plant: a. An identification designation (e.g., 1, CT2) as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state environmental agency b. A description of each unit (e.g. combustion turbine, coal-fired wet-bottom boiler) as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the State environmental agency or state utility commission c. Fuel or energy source used--as reported to the U.S. Energy Information Administration (EIA) or to the state utility commission d. Heat input (mmBtu) in May 1 through September 30 of 1995, 1996 and 1997 as reported to U.S. EPA and EIA; e. Estimated historical NOX mass emissions in May 1 through September 30 of 1995, 1996 and 1997 (as reported to the U.S. EPA or the state environmental agency). 3. For each electrical generator at the plant: a. Generation identification designation--as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state utility commission b. Nameplate capacity in MWe-as reported to U.S. EPA and EIA; if not currently reporting to Federal government, then as reported to the state utility commission. c. Electrical generation (MWh)in May 1 through September 30 of 1995, 1996 and 1997--as reported to EIA; 4. For each steam turbines at the plant that is used to generate steam output instead or in addition to electricity: a. An identification designation b. Capacity, in mmBtu/hr output rate c. Steam output (mmBtu) (not used for electrical generation) in May 1 through September 30 of 1995, 1996 and 1997 The Agency believes these data are needed both to determine the output of each source and to establish a unique identity for each source and its units. The EPA requests comment on the specific data as well as the type of data supporting the proposed allocations under part 97. (2) Non-EGUs. For any allocation methodology adopted, the total number of allocations issued to non-electric generating units would equal the portion (less the 5 percent set-aside discussed below) of the section 126 trading program budget for each State attributed to large non-electricity generating units (calculated as described in Section III.B.3.c.ii of this preamble by reducing each State's uncontrolled non-EGU NOX emissions level by 60 percent and assuming activity growth through 2007). At this time, the Agency proposes to use heat input as the basis for determining allocations for large non- electricity generating units in the Federal NOX Budget Trading Program. The EPA proposes this basis for both the initial allocation period of 2003 through 2005 and for subsequent years of the program. This differs from the method used to determine the aggregate emission level for non-electric generating units (a percentage reduction from historical emissions) because at the time the aggregate level was determined (during the SIP call proposal process), heat input data for individual units was not available. Distributing allocations on a heat-input basis provides a fuel-neutral method of allocating to the units in the trading program similar to the allocation approaches proposed for the electric generating units. Heat-input-based allocations also allow for reallocating in the future (to accommodate new units) whereas allocations based upon a specific percentage reduction do not. Heat input data is now available for use in developing allocations, and the Agency solicits comment on the data as well as the use of heat input in developing allocations. At this time, the Agency is not aware of any databases on steam output information for industrial boilers. Therefore, for combustion sources other than electrical generators, EPA finds that it is most appropriate to base allocations upon heat input. However, EPA requests comment on any methods for distributing allowances on an output basis to non-electricity generating units. Comments should address the availability, quality, and appropriateness of the data for regulatory purposes and/or methods to obtain such data. For the non-electricity generating units subject to the Federal trading program, EPA proposes to use 1995 heat input data in the allocation calculation for the control periods in 2003, 2004, and 2005. The 1995 data are the most recent data the Agency knows are currently available for non-electricity generating units. After this initial period of allocations, as with the electric generating units, the Agency will use data measured during the control period of the year that is four years before the year for which allocations are being calculated. As was done for electricity generating units, the Agency has calculated unit specific allocations for large non-electricity generating units. These unit specific allocations are provided in Appendix A of proposed part 97. The EPA solicits comment on the underlying data used in these allocations and the methodology employed in determining the allocations. The Agency plans to describe a set of allocations in the final notice. The EPA would issue the final allocations for the control period in

2003 by placing them in the NATS by April 1, 2000 for those sources for which a finding has been triggered under section 126 at this time. For those sources for which a finding is not triggered by April 1, 2000, but for which a final finding is automatically trigger on May 1, 2000, EPA would issue the allocations for the 2000 control period to NATS as soon as practicable in the year 2000, consistent with the allocations finalized with this rulemaking. For the non-electricity generating unit allocations proposed in today's notice, EPA determined initial unadjusted allocations to existing non-electric generating NOX Budget units by multiplying a NOX emission rate of 0.17 lb/mmBtu (the average emission rate for existing non-electricity generating budget units after controls are in place) by the units' historical heat input (described above as 1995 control season data). After determining the initial unadjusted unit allocations, EPA adjusted the allocation for each unit upward or downward to match the portion of the section 126 trading program budget for the State attributed to large non-electricity generating units. Then, the Agency adjusted the allocation for each unit in the State proportionately so that the total allocations equaled 95 percent of the portion of the section 126 trading program budget for the State attributed to large non-electricity generating units. The Agency proposes to set-aside 5 percent of the non-electricity generating unit allocations to be consistent with the allocation for electricity generating units. The EPA solicits comment on this approach and the proposed size of the set-aside. (3) Treatment of New Sources. As discussed in previous sections, the Agency has proposed in part 97 a set-aside for new sources consistent with the provisions of part 96. New electricity generating units and non-electricity generating units required to participate in the Federal NOX Budget Trading Program will have access to this set-aside. In 2003, 2004, and 2005, each State set-aside would initially hold NOX allowances equal to 5 percent of the NOX allowances in the section 126 trading program budget in the State. Starting in 2006, each State set-aside would originally hold 2 percent of the NOX allowances in the section 126 trading program budget in the State. At the end of each relevant control period, EPA will return any allowances remaining in the account on a pro-rata basis to the units that had received an original allocation that had been adjusted to create the new source set-aside in the State. The NOX allowances in the allocation set-aside would be available to any unit that would otherwise be eligible for an allocation in a control period but did not receive one because the unit commenced operation during or after the period on which the NOX allowance allocations for existing units were based. To receive NOX allowances from the allocation set-aside, the NOX Authorized Account Representative for a unit would submit a NOX allowance request to the Administrator. The request could be for no more than 5 consecutive control periods, starting with the control period during which the unit is projected to commence operation and ending with the control period preceding the control period for which it has sufficient data to receive an allocation with existing budget units. For the sixth year or later (and possibly earlier), there would be sufficient operating data for the unit to be incorporated into the NOX allowance allocations with existing NOX Budget units. The NOX allowance request would need to be submitted prior to May 1 of the first control period for which NOX allowances are requested and after the date on which the State issues a permit to construct the new unit. Consistent with part 96, the allowances would be issued to new units on a first-come first-served basis. For the first allocation approach proposed for electric generating units, allowances to new electric generation units would be issued at a rate of 0.15 lb/mmBtu multiplied by the unit's maximum design heat input. Following each control period, the unit would be subject to a reduced utilization calculation. EPA would deduct NOX allowances following each control period based on the unit's actual utilization. Because the allocation for a new unit from the set-aside is based on maximum design heat input, this procedure adjusts the allocation by actual heat input for the control period of the allocation. This adjustment is a surrogate for the use of actual utilization in a prior baseline period which is the approach used for allocating NOX allowances to existing units. For new non-electric generating units, allowances would be issued at the average emission rate (e.g., .17 lbs/mmBtu) for existing budget units (after controls are in place) multiplied by the budget unit's maximum design heat input. Following each control period, the source would be subject to a reduced utilization calculation similar to that described above for electric generating units. For the second and third allocation approaches proposed for electric generating units, allowances to new electric generating units would be issued at the average emission rate (in lbs/kWh) for existing budget units (after controls are put in place) multiplied by the maximum design electrical generation derived from operation of the new budget unit. Following each control period, the budget unit would be subject to a reduced utilization calculation similar to that described above under the first approach. d. Compliance Supplement Pool. This notice proposes to establish Federal emissions limits for sources found to significantly contribute to ozone nonattainment problems in a petitioning State. These sources would be required to comply with the emissions limits by May 1, 2003. As discussed in the final NOX SIP call and the technical support document ``Feasibility of Installing NOX Control Technologies By May 2003,'' EPA believes that this compliance date is a feasible and reasonable deadline. However, EPA received comments for the NOX SIP call expressing concern that some sources may encounter unexpected problems installing controls by this deadline that, in turn, could cause unacceptable risk for a source and its associated industry. Commenters explicitly expressed concern related to the electricity industry, stating that the deadline could adversely impact the reliability of the electricity supply. In the NOX SIP call, EPA addressed these compliance concerns by providing additional flexibility for sources to comply with the requirements. The EPA is proposing that similar flexibility mechanisms be provided in part 97. First, EPA is proposing that part 97 include banking provisions as discussed in Section III.B.2.h. Second, EPA is proposing that part 97 include a compliance supplement pool that may be used by sources to cover excess emissions during the 2003 and 2004 ozone seasons that are unable to meet the compliance deadline. The proposed part 97 includes a separate compliance supplement pool that would be available to the sources in each State identified in this proposal. i. Size of the Compliance Supplement Pool. The EPA proposes to use the same compliance supplement pools on a State-by-State basis as were included in the final NOX SIP call. The justification for the size of the State pools is included in the final NOX SIP call. Table III-2 shows the compliance supplement pool that would be

available to sources in each State identified in this proposal.

Table III-2. Compliance Supplement Pools (Tons of NOX) ------------------------------------------------------------------------ Compliance State supplement pool ------------------------------------------------------------------------ Alabama.................................................... 10,361 Connecticut................................................ 559 Delaware................................................... 417 District of Columbia....................................... 0 Illinois................................................... 17,455 Indiana.................................................... 19,738 Kentucky................................................... 13,018 Maryland................................................... 3,662 Massachusetts.............................................. 285 Michigan................................................... 15,359 Missouri................................................... 10,469 New Jersey................................................. 1,722 New York................................................... 1,831 North Carolina............................................. 10,624 Ohio....................................................... 22,947 Pennsylvania............................................... 13,716 Rhode Island............................................... 0 Tennessee.................................................. 12,093 Virginia................................................... 6,108 West Virginia.............................................. 16,937 ------------------------------------------------------------------------

ii. Distribution of the Compliance Supplement Pool to Sources. In the final NOX SIP call, EPA provides States with two options for distributing the pool to sources. One option is for a State to distribute some or all of the pool to sources that generate early reductions during ozone seasons prior to May 1, 2003. The second option is for a State to run a public process to provide tons to sources that demonstrate a need for a compliance extension. Tons that are not distributed by a State prior to May 1, 2003 will be retired by EPA. A State wishing to use the compliance supplement pool under the NOX SIP call may divide the pool and make some of it available to sources through both options, or may use only one of the options for distributing the pool to sources prior to May 1, 2003. Based on these options, EPA is soliciting comment on a number of approaches for distributing the pool to sources under part 97. First, EPA solicits comment as to whether the compliance supplement pool should be distributed by EPA to sources or distributed by EPA to the States that have sources included in this proposal. If the pools were distributed to States, the States would then be able to distribute the pool to sources. Part 97 is primarily designed to be implemented and administered directly by EPA. For this reason, it may be most efficient for EPA to retain the responsibility of distributing the pool to sources. However, it may be possible to provide more flexibility in the use of the pool for different sources if States were provided the distribution responsibility. Second, provided that EPA decides to retain the responsibility of distributing the pool to sources, EPA solicits comment on two options for distribution. First, EPA solicits comment on distributing the compliance supplement pool only for early reductions. Under this option, the Agency would distribute allowances from the compliance supplement pool based upon the optional methodology the Agency laid out in the final NOX SIP call. Using that methodology, the Agency could issue early reduction credits for the 2001 and 2002 ozone season to units that have installed part 75 monitoring by the 2000 control season, have reduced their emission rate in 2001 or 2002 relative to their rate in 2000 by at least 20 percent, and are operating in the year(s) in which they are applying for early reduction credits at an emission rate below 0.25 lb/mmBtu. Provided it meets all of these criteria, a unit could request early reduction credits equal to the difference between 0.25 lb/mmBtu and the unit's actual emissions rate multiplied by the unit's actual heat input for the applicable control period. The Agency laid out the reasons for adopting each of these criteria for early reduction credits in the final NOX SIP call. Part 97 currently describes this option. Under this option, if the tons of NOX in the State's compliance supplement pool exceeds the number of valid early reduction credit requests in that State, the Agency would issue one allowance for each ton of early reduction credit requested. Any allowances remaining in the compliance supplement pool after all valid requests have been granted would be retired by the Agency. If, however, the amount of valid requests are more than the size of the State's pool, the Agency would reduce the amount in the credit requests on a pro-rata basis so that the requests equal the size of the State's pool. After the requests have been reduced, the Agency would then issue allowances based on the remaining size of each credit request. With this option, sources in States in the Ozone Transport Commission (OTC) that are subject to this section 126 action would be allowed to bring their banked allowances into the Federal NOX Budget Trading Program as early reduction credits provided the sum of the banked allowances in any State does not exceed the size of the State's compliance supplement pool. As is the case under this option for States outside of the OTC, any remaining credits in the compliance supplement pool would be retired. If the NOX Budget units in an OTC State hold banked allowances from the OTC program in excess of the amount of credits in the State's pool, the Agency would reduce the amount of allowances eligible for early reduction credit on a pro rata basis. The Agency solicits comment on the methodology for issuing early reduction credits in this option as well as the approach that limits the use of the compliance supplement pool to early reduction credits. Specifically, the Agency solicits comment on alternative methods for calculating early reduction credits. In addition, EPA solicits comment on the approach specified for integration with the OTC Program. The Agency also solicits comment on a second option for distribution of the compliance supplement pool. Under this second option, the Agency proposes that a portion of the compliance supplement pool be given out as early reduction credits and the remaining portion be reserved for sources that demonstrate a need for the compliance supplement. As described in the preamble to the final NOX SIP call, sources would be responsible for demonstrating to the Agency and the public achieving compliance by May 1, 2003 would create undue risk either to its own operation or associated industry. The administrator of the compliance supplement pool would provide the public an opportunity to comment on the validity of the need for this ``direct distribution'' of the compliance supplement. Under this option, the Agency would grant early reduction credits using the method described in the first option (or some variation of that approach) before allowing sources access to the direct distribution credits from the compliance supplement pool. The Agency proposes to address OTC banked allowances held by sources subject to a section 126 action as suggested in the first option. To ensure that the compliance supplement is only provided to sources that truly need a compliance extension, the remaining credits in the compliance supplement pool would be given out to an owner or operator of a source that demonstrates the following: • The process of achieving compliance by May 1, 2003 would create undue risk for the source or its associated industry. For electric generating units, the demonstration should show that installing controls would create unacceptable risks for the reliability of the electricity supply during the time of installation. This demonstration would include a showing that it was not feasible to import electricity from other systems during the

time of installation. Non-electricity generating sources may also be eligible for the compliance supplement based on a demonstration of risk comparable to that described for the electricity industry. • It was not possible to compensate for delayed compliance by generating early reduction credits at the source or by acquiring credits generated by other sources. • It was not possible to acquire allowances or credits for the 2003 ozone season from sources that will make reductions beyond required levels during the 2003 ozone season. The Agency solicits comment on this option that distributes the compliance supplement pool both through early reduction credits as well as direct distribution. Specifically, the Agency requests comment on the number of credits to reserve for direct distribution, the methodology used for direct distribution, and options for public review of the direct distribution. The Agency also solicits comment on the appropriate administrator of the direct distribution. Under any of the options described above, the Agency proposes that NOX allowances issued from the compliance supplement pool would only be available for sources to use for compliance in the 2003 or 2004 control periods. Any NOX allowance issued from the compliance supplement pool that is not used for compliance in 2003, would be considered to be ``banked'' for the 2004 control period. The Agency proposes to retire any NOX allowance issued from the compliance supplement pool that is not used in either the 2003 or 2004 control period at the end of the 2004 true-up period for the reasons cited in the preamble to the final NOX SIP call. e. Emissions Monitoring and Reporting. Subpart H of today's proposed rule addresses monitoring and reporting requirements including, among other things, general requirements, initial certification and recertification procedures, out of control periods, notifications, recordkeeping and reporting, and petitions. These provisions are essentially the same as the monitoring-related provisions of part 96, with cross references to the appropriate sections of part 97. The differences between the provisions reflect the fact that administration of the monitoring requirements is overseen by EPA, rather than by EPA and the permitting authority as is the case in the State NOX Budget Trading Program. As a result, for example, monitoring certification applications are submitted to the Administrator and the appropriate EPA Regional Office in addition to the permitting authority, and the Administrator, not the permitting authority, will act on the applications. Further, the Administrator handles all audit decertifications and all petitions for alternatives to the monitoring requirements. Another difference is that in the State NOX Budget Trading Program, EPA included heat input monitoring requirements that States might choose to adopt if they were basing their allocation methodologies on heat input. The proposed Federal NOX Budget Trading Program bases its allocation approach on heat input. Therefore, EPA has included the heat input monitoring and reporting requirements in proposed part 97. Note that as explained in Section III.3.c.5 of the preamble, EPA is taking comment on three different allocation methodologies. Depending on the methodology chosen, monitoring and reporting requirements would vary. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25938-40) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. In particular, for the reasons set forth in the NOX SIP call, EPA proposes that NOX Budget units be required to meet the monitoring and reporting requirements in a new subpart H of 40 CFR part 75, the Acid Rain Program regulations (63 FR 25938-40). The EPA has promulgated these revisions part 75 to establish NOX mass monitoring requirements and provide greater flexibility to regulated sources in conjunction with the final NOX SIP call rule. f. Opt-ins. Subpart I of today's proposed rule addresses the opt-in process and procedures applicable to operating units that are not NOX Budget units under Sec. 97.4, but are located in a State that is included in the Federal NOX Budget Trading Program and wish to voluntarily enter (i.e., opt into) the trading program. The opt-in provisions can further reduce the cost of achieving NOX reductions by allowing these units to join the NOX Budget Trading Program and make incremental, lower cost reductions, freeing NOX allowances for use by other NOX Budget units. There are potentially individual sources not included in the trading program that may emit significant amounts of NOX and are able to achieve cost-effective reductions; allowing these sources to join the program would reduce the overall cost of compliance for the program. The EPA proposes in subpart I to allow individual combustion sources that are located in a State for which a section 126 remedy in promulgated, vent to a stack, and can monitor NOX mass emissions, the opportunity to opt-in to the Federal program for purposes of the section 126 remedy. The EPA solicits comment on the appropriateness of these opt-in provisions. Subpart I addresses, among other things, the applicability requirements, allocations, procedures for applying for a NOX Budget opt-in permit, the process of reviewing and approving or denying the permit, contents of the permit, procedures for withdrawing as a NOX Budget opt-in source, and changes in regulatory status. The provisions of this subpart are similar to the opt-in provisions in part 96, with cross references to the appropriate sections in part 97, though the Administrator plays a greater role than in part 96 with regard to actions on opt-in permits, allocations, and other related opt-in submissions. For example, under the Federal trading program, NOX budget opt-in permit applications are submitted to both the Administrator and the permitting authority, but only the Administrator may determine whether the unit qualifies as a NOX Budget opt-in source. Furthermore the Administrator, rather than the permitting authority, allocates allowances to sources in the Federal NOX Budget Trading Program. The EPA is proposing these part 97 provisions for the reasons set forth both in the proposed NOX SIP call (63 FR 25940-42) and the final NOX SIP call, and in order to minimize differences between the Federal and State NOX Budget Trading Programs. g. Program administration. As discussed above, the Federal NOX Budget Trading Program would be run by EPA. The EPA would identify the units covered by the program, determine and record the NOX allowance allocations, receive and review monitoring plans and monitoring certification applications, and take the lead in enforcement. As discussed above, States would still be responsible for permitting.

C. New Source Review

As discussed in the proposed and final NOX SIP call, the EPA believes that nonattainment New Source Review (NSR) offset requirements of the CAA can be met using the mechanism of the State NOX Budget Trading Program under part 96. However, because the Agency is continuing to evaluate a number of complex issues involved with integrating NSR and the trading program, it will not be providing guidance at this time. The EPA intends

to provide such guidance as soon as possible. At that time, the EPA will also address integrating NSR with the trading program under part 97.

IV. Non-Ozone Benefits to NOX Reductions

In addition to contributing to attainment of the ozone NAAQS, decreases of NOX emissions will also likely help improve the environment in several important ways. On a national scale, decreases in NOX emissions will also decrease acid deposition, nitrates in drinking water, excessive nitrogen loadings to aquatic and terrestrial ecosystems, and ambient concentrations of nitrogen dioxide, particulate matter, and toxics. On a global scale, decreases in NOX emissions will, to some degree, reduce greenhouse gases and stratospheric ozone depletion. Thus, management of NOX emissions is important to both air quality and watershed protection on national and global scales. In its July 8, 1997 final recommendations, OTAG stated that it ``recognizes that NOX controls for ozone reductions purposes have collateral public health and environmental benefits, including reductions in acid deposition, eutrophication, nitrification, fine particle pollution, and regional haze.'' These and other public health and environmental benefits associated with decreases in NOX emissions are summarized below.16 ---------------------------------------------------------------------------

\16\ U.S. Environmental Protection Agency, ``Nitrogen Oxides: Impacts on Public Health and the Environment,'' EPA-452/R-97-002, August 1997. ---------------------------------------------------------------------------

Acid Deposition: Sulfur dioxide and NOX are the two key air pollutants that cause acid deposition (wet and dry particles and gases) and result in the adverse effects on aquatic and terrestrial ecosystems, materials, visibility, and public health. Nitric acid deposition plays a dominant role in the acid pulses associated with the fish kills observed during the springtime melt of the snowpack in sensitive watersheds and recently has also been identified as a major contributor to chronic acidification of certain sensitive surface waters. Drinking Water Nitrate: High levels of nitrate in drinking water is a health hazard, especially for infants. Atmospheric nitrogen deposition in sensitive watersheds can increase stream water nitrate concentrations; the added nitrate can remain in the water and be transported long distances downstream. Eutrophication: NOX emissions contribute directly to the widespread accelerated eutrophication of United States coastal waters and estuaries. Atmospheric nitrogen deposition onto surface waters and deposition to watershed and subsequent transport into the tidal waters has been documented to contribute from 12 to 44 percent of the total nitrogen loadings to United States coastal water bodies. Nitrogen is the nutrient limiting growth of algae in most coastal waters and estuaries. Thus, addition of nitrogen results in accelerated algae and aquatic plant growth causing adverse ecological effects and economic impacts that range from nuisance algal blooms to oxygen depletion and fish kills. Global Warming: Nitrous oxide (N2O) is a greenhouse gas. Anthropogenic N2O emissions in the United States contribute about 2 percent of the greenhouse effect, relative to total United States anthropogenic emissions of greenhouse gases. In addition, emissions of NOX lead to the formation of tropospheric ozone, which is another greenhouse gas. Nitrogen Dioxide (NO2): Exposure to NO2 is associated with a variety of acute and chronic health effects. The health effects of most concern at ambient or near-ambient concentrations of NO2 include mild changes in airway responsiveness and pulmonary function in individuals with pre-existing respiratory illnesses and increases in respiratory illnesses in children. Currently, all areas of the United States monitoring NO2 are below EPA's threshold for health effects. Nitrogen Saturation of Terrestrial Ecosystems: Nitrogen accumulates in watersheds with high atmospheric nitrogen deposition. Because most North American terrestrial ecosystems are nitrogen limited, nitrogen deposition often has a fertilizing effect, accelerating plant growth. Although this effect is often considered beneficial, nitrogen deposition is causing important adverse changes in some terrestrial ecosystems, including shifts in plant species composition and decreases in species diversity or undesirable nitrate leaching to surface and ground water and decreased plant growth. Particulate Matter (PM): NOX compounds react with other compounds in the atmosphere to form nitrate particles and acid aerosols. Because of their small size nitrate particles have a relatively long atmospheric lifetime; these small particles can also penetrate deeply into the lungs. The PM has a wide range of adverse health effects. Stratospheric Ozone Depletion: A layer of ozone located in the upper atmosphere (stratosphere) protects people, plants, and animals on the surface of the earth (troposphere) from excessive ultraviolet radiation. The N2O, which is very stable in the troposphere, slowly migrates to the stratosphere. In the stratosphere, solar radiation breaks it into nitric oxide (NO) and nitrogen (N). The NO reacts with ozone to form NO2 and molecular oxygen. Thus, decreasing N2O emissions would result in some decrease in the depletion of stratospheric ozone. Toxic Products: Airborne particles derived from NOX emissions react in the atmosphere to form various nitrogen containing compounds, some of which may be mutagenic. Examples of transformation products thought to contribute to increased mutagenicity include the nitrate radical, peroxyacetyl nitrates, nitroarenes, and nitrosamines. Visibility and Regional Haze: The NOX emissions lead to the formation of compounds that can interfere with the transmission of light, limiting visual range and color discrimination. Most visibility and regional haze problems can be traced to airborne particles in the atmosphere that include carbon compounds, nitrate and sulfate aerosols, and soil dust. The major cause of visibility impairment in the eastern United States is sulfates, while in the West the other particle types play a greater role. Justification for Rulemaking: While EPA believes the information is important for the public to understand and, thus, needs to be described as part of the rulemaking and RIA, there should be no misunderstanding as to the legal basis for the rulemaking, which is described in Section I, Background, of this notice and does not depend on the non-ozone benefits. The non-ozone benefits did not affect the method in which EPA determined significant contribution nor the proposed control requirements.

V. Administrative Requirements

A. Executive Order 12866: Regulatory Impact Analysis

Under Executive Order 12866 (58 FR 51735, October 4, 1993), the Agency must determine whether a regulatory action is ``significant'' and therefore subject to Office of Management and Budget (OMB) review and the requirements of the Executive Order. The Order defines ``significant regulatory action'' as one that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;

(2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; (3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. The EPA believes that this action is a ``significant regulatory action'' because it raises novel legal and policy issues arising from the Agency's obligation to respond to the section 126 petitions, and because the action could have an annual effect on the economy of more than $100 million. As a result, the proposed rulemaking was submitted to OMB for review, and EPA has prepared a RIA titled ``Regulatory Impact Analysis of Proposed CAA Section 126 Petitions for NOX, September 1998.'' This RIA assesses the costs, benefits, and economic impacts associated with Federally-imposed requirements to mitigate NOX emissions from sources contributing to downwind nonattainment of the ozone NAAQS. Any written comments from OMB to EPA and any written EPA response to those comments are included in the docket. The docket is available for public inspection at the EPA's Air Docket Section, which is listed in the ADDRESSES section of this preamble. The RIA is available in hard copy by contacting the EPA Library at the address under ``Availability of Related Information'' and in electronic form as discussed above in that same section. The RIA for the section 126 petitions addresses the costs and benefits associated with reducing emissions at sources affected under the petitions in the broader context of those sources potentially affected by the final NOX SIP call and its associated FIP. There is a high likelihood that sources named in the section 126 petitions will also be controlled under SIPs that will be revised to meet final NOX budgets. In the event that States fail to submit approvable SIPs, FIPs will be enacted. Therefore, from the perspective of a regulatory analysis that is focused on the year 2007, the sources named in section 126 petitions will be complying with either State or Federal regulations of generally equivalent stringency. The RIA for the NOX SIP call concludes that the national annual cost of possible State actions to comply with the NOX SIP call are approximately $1.7 billion (1990 dollars). The sources named in the section 126 petitions will bear some portion of that total cost. The associated benefits, in terms of improvements in health, visibility, and ecosystem protection, that EPA has quantified and monetized range from $1.1 billion to $4.2 billion, with EPA's best estimate being $3.4 billion. Due to practical analytical limitations, the EPA is not able to quantify and/or monetize all potential benefits of the NOX SIP call action.

B. Impact on Small Entities

1. Regulatory Flexibility The Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA), provides that whenever an agency is required to publish a general notice of proposed rulemaking, it must prepare and make available an initial regulatory flexibility analysis, unless it certifies that the proposed rule, if promulgated, will not have ``a significant economic impact on a substantial number of small entities.'' In the process of developing this rulemaking, EPA worked with SBA and OMB and obtained input from small businesses, small governmental jurisdictions, and small organizations. On June 23, 1998, EPA's Small Business Advocacy Chairperson convened a Small Business Advocacy Review Panel under section 609(b) of the RFA as amended by SBREFA. In addition to its chairperson, the Panel consists of EPA's Director of the Office of Air Quality Planning and Standards within the Office of Air and Radiation, the Administrator of the Office of Information and Regulatory Affairs within the OMB, and the Chief Counsel for Advocacy of the SBA. As described below, this Panel conducted an outreach effort and completed a report on the section 126 proposal. The report provides background information on the proposed rule being developed and the types of small entities that would be subject to the proposed rule, describes efforts to obtain the advice and recommendations of representatives of those small entities, summarizes the comments that have been received to date from those representatives, and presents the findings and recommendations of the Panel; the completed report, comments of the small entity representatives, and other information are contained in the docket for this rulemaking. It is important to note that the Panel's findings and discussion are based on the information available at the time this report was drafted. The EPA is continuing to conduct analyses relevant to the proposed rule, and additional information may be developed or obtained during the remainder of the rule development process. The Panel makes its report at a preliminary stage of rule development and its report should be considered in that light. At the same time, the report provides the Panel and the Agency with an opportunity to identify and explore potential ways of shaping the proposed rule to minimize the burden of the rule on small entities while achieving the rule's statutory purposes. Any options the Panel identifies for reducing the rule's regulatory impact on small entities may require further analysis and/or data collection to ensure that the options are practicable, enforceable, environmentally sound and consistent with the statute authorizing the proposed rule. 2. Outreach to Small Entity Representatives In consultation with the SBA, EPA invited small entity representatives to participate in its outreach efforts on this proposal. The EPA, OMB, and SBA held an initial outreach meeting with a group of small-entity representatives in Washington, DC, on April 14, 1998. The purpose of this meeting was to familiarize the small-entity representatives with the substance of the rulemaking and the kinds of sources being considered for regulation, and to solicit comment on these topics. Subsequent to the meeting, the representatives submitted follow-up comments in writing. The primary outreach was accomplished by a meeting with the small-entity representatives in Washington, D.C. on August 4, 1998. The purpose of this meeting was to present the results of EPA's analysis on small-entity impacts, and to solicit comment on this analysis and on suggestions for impact mitigation. Subsequent to the meeting, the representatives submitted follow-up comments in writing. To define small entities, EPA used the SBA industry-specific criteria published in 13 CFR part 121. The SBA size standards have been established for each type of economic activity under the Standard Industrial Classification (SIC) System. Due to their NOX- emitting properties, the following industries have the potential to be affected by the section 126 rulemaking:

SIC Codes in Division D: Manufacturing

2611--Pulp mills 2819--Industrial Inorganic Materials 2821--Plastics Materials, Synthetic Resins, and Nonvulcanizable Elastomers 2869--Industrial Organic Chemicals 3312--Steel Works, Blast Furnaces, and Rolling Mills 3511--Steam, Gas, and Hydraulic Turbines

3519--Stationary Internal Combustion Engines 3585--Air-Conditioning and Warm-Air Heating Equipment and Commercial and Industrial Refrigeration Equipment

SIC Codes in Division E: Transportation, Communications, Electric, Gas, and Sanitary Services

SIC Major Group 49: Electric, Gas, and Sanitary Services, including:

4911--Electric Utilities 4922--Natural Gas Transmission 4931--Electric and other Gas Services 4961--Steam and Air Conditioning Supply 3. Potentially Affected Small Entities The primary topic of Panel discussion was the applicability of the section 126 rule to the various categories of NOX-emitting sources, the costs the rule would impose, and the possibility of further reducing rule applicability. Secondary topics included emissions monitoring and other potentially duplicative Federal rules. These discussions are summarized below. The section 126 rulemaking is potentially applicable to all NOX-emitting entities named in one or more of the section 126 petitions. Since this is a subset of the entities covered by the FIP proposal, any impacts from the section 126 rule will be a subset of the FIP impacts, and the FIP proposal represents the worst case that could result if all eight section 126 petitions were granted. Therefore, EPA has applied its limited time and resources to developing estimates of impact based on the FIP proposal, with the knowledge that it represents the worst case in terms of impact on small entities. The EPA estimates that the total number of such entities named in the section 126 petitions is approximately 5200, of which about 1200 are small entities. The EPA is considering reducing this applicability based on several factors including input from this Panel, considerations of overall cost effectiveness, and administrative efficiency. Specifically, EPA is proposing to exempt a number of sources from being subject to this regulation based on factors such as low relative emissions and lack of specific source information. These factors are discussed in detail elsewhere in this notice. Additional sources are being considered for exemption because they may not be highly cost effective to control, with EPA considering an average cost effectiveness of $2000 per ton of NOX removed as the upper limit for highly cost-effective reductions. If EPA takes final action as proposed today with this reduced- applicability approach, the section 126 rulemaking will apply only to the following types of sources: Large electric generating units (EGUs), industrial boilers, and combustion turbines. The stringency levels of control EPA currently intends to propose for these types of sources is as follows: For EGUs, an emission rate of 0.15 pounds of NOX per million BTU and for industrial boilers and combustion turbines, an emission reduction of 60 percent. At these stringency levels, the estimated number of small entities that would be affected is as follows:

Electric Generating Units--114 small entities Industrial Boilers and/or Combustion Turbines--31 small entities

The EPA has further estimated that, of these affected small entities, the following would experience compliance costs equal or greater to 1 percent of their estimated revenues:

Electric Generating Units--32 small entities Industrial Boilers and Combustion Turbines--7 small entities

Of these, EPA estimates that about 18 small entities with electric generating units and 4 small entities with industrial boilers or turbines would experience costs greater than 3 percent of their estimated revenues. Focusing the rule on this limited group of sources would constitute a reduction of over 85 percent in the number of small entities potentially affected by the rule: out of 1200 potentially-affected small entities, over 1000 would be exempted, with only 145 small entities remaining. The Panel received written comments from three small-entity representatives strongly endorsing these exemptions. 4. Panel Findings and EPA Actions a. Exemptions. The Panel agreed with the general approach EPA is proposing to define the scope of the rule. The Panel recommended that the exemptions noted above be included in the proposal, and further recommended that the applicability of EPA's proposed rule be limited to the sources shown in that section. As discussed earlier in this notice, EPA is proposing to limit applicability as recommended by the Panel. Furthermore, as described below, the Panel considered it appropriate to explore additional options for reducing the impact of the rule. Several of the small entity representatives suggested that EPA exempt all small entities from this rulemaking. Although EPA does not feel that a blanket, across-the-board exemption could be supported, EPA is receptive to proposals for further exemptions, up to and including exempting all small entities if that could be shown to be appropriate. As recommended by the Panel, EPA solicits comment on additional types of small-entity exemptions and the rational bases on which such exemptions could be made, such as disproportionate ability to bear costs and administrative burden. b. Continuous Emissions Monitoring Systems (CEMS). The Panel received both written and oral comments to the effect that CEMS would be prohibitively costly for many industrial boilers, representing a significant part of the cost of the rule. The OMB and SBA share the commenters' concern for the potentially high cost of CEMS requirements. The EPA believes that it is necessary for all sources in the trading program to be subject to accurate and consistent monitoring requirements designed to demonstrate compliance with a mass emission limitation, and therefore intends to require all large units to monitor NOX mass emissions using CEMS (including units opting-in to the trading program). In the proposed section 126 rule, all affected sources are included in the trading program. However, EPA does believe that it is appropriate to provide lower cost monitoring options for units with low NOX mass emissions, and therefore intends to allow non-CEMS alternatives for units that have emissions of less than 50 tons per year of NOX. This cutoff will provide relief for boilers large enough to be covered by the rule, but that run for a smaller number of hours each year, including any such boilers owned by small entities. c. Electric Generating Units. The next area considered by the Panel was electric generating units (EGUs). The EPA's analysis shows that slightly more than 30 EGUs may experience costs above 1 percent of revenues, and that 18 of these might exceed 3 percent. From comments made by small utilities, the Panel suspects that many of these high- cost-to-revenue situations may involve peaking units, which run only a small percentage of the time and thus may be inefficient to control. To address this problem, the Panel recommended that EPA solicit comment on whether to allow electric generating units to obtain a Federally- enforceable NOX emission tonnage limit (e.g., 25 tons during the ozone season) and thereby obtain an exemption. The EPA solicits comment on the necessity for and appropriateness of such an option. d. Industrial Boilers. Individual Panel members conceived of other potential ways to mitigate impact on small entities, such as raising the size cutoff for small entities and/or lessening the required percentage reduction in NOX emissions required from small entities. The SBA encouraged the Agency to

conduct analyses to determine the impact of 40 percent reduction being applied solely to small entities and 60 percent solely to large entities, and the resulting effect on control levels for sources regulated in the proposal. The EPA solicits comment on whether requirements should be reduced on small-entity-owned industrial boilers by some combination of raising the size cutoff and/or lessening the required reduction; which, if any, of these options is preferable; the necessity and appropriateness of any such option; the appropriate level (e.g., 40 percent reduction instead of 60 percent); and information to support any comments submitted. e. EPA Guidance to States on Small Entities. Finally, the Panel noted that several small entity representatives expressed concern that regardless of the sensitivity to small-entity concerns EPA shows in the (FIP or) section 126 rulemaking, the States may nevertheless see fit to target small entities in their SIPs. To help address this problem, the Panel recommended that, subsequent to the FIP and section 126 proposals, EPA issue guidance that conveys to the States the kinds of options and alternatives EPA has considered in addressing small-entity concerns, explain the rationale behind these kinds of options, and recommended that the States consider adopting similar alternatives in their SIPs. The EPA intends to address this issue as it develops implementation guidance for the States to use in developing SIPs.

C. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.L. 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, 2 U.S.C. 1532, EPA generally must prepare a written statement, including a cost-benefit analysis, for any proposed or final rule that ``includes any Federal mandate that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more ... in any one year.'' A ``Federal mandate'' is defined under section 421(6), 2 U.S.C. 658(6), to include a ``Federal intergovernmental mandate'' and a ``Federal private sector mandate.'' A ``Federal intergovernmental mandate,'' in turn, is defined to include a regulation that ``would impose an enforceable duty upon State, local, or tribal governments,'' section 421(5)(A)(i), 2 U.S.C. 658(5)(A)(i), except for, among other things, a duty that is ``a condition of Federal assistance,'' section 421(5)(A)(i)(I). A ``Federal private sector mandate'' includes a regulation that ``would impose an enforceable duty upon the private sector,'' with certain exceptions, section 421(7)(A), 2 U.S.C. 658(7)(A). The EPA is taking the position that the requirements of UMRA apply because this action could result in the establishment of enforceable mandates directly applicable to sources (including sources owned by State and local governments) that would result in costs greater than $100 million in any one year. The UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least-costly, most cost-effective or least-burdensome alternative that achieves the objectives of the rule. The EPA's UMRA analysis, ``Unfunded Mandates Reform Act Analysis For the Proposed Section 126 Petitions Under the Clean Air Act Amendments Title I,'' is contained in the docket for this action and is summarized below. This UMRA analysis examines the impacts of the proposed section 126 rulemaking on both EGUs and non-EGUs that are owned by State, local, and tribal governments, as well as sources owned by private entities. This proposal potentially affects 65 EGUs that are owned by one State and 24 municipalities (Massachusetts owns 6 units, and the municipalities own the remaining 59 units). In addition, 7 non-EGUs owned by 2 States and 5 municipalities are potentially affected. The EPA has not identified any units on Tribal lands that would be subject to the proposed requirements. The overall costs are dominated by the 65 EGUs and are about $30 million per year. Their cost impacts are only slightly higher than their production share, in comparison to all units in the region. Under section 203 of UMRA, 2 U.S.C. 1533, before EPA establishes any regulatory requirements ``that might significantly or uniquely affect small governments,'' EPA must have developed a small government agency plan. The plan must provide for notifying potentially affected small governments; enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates; and informing, educating, and advising small governments on compliance with the regulatory requirements. The proposed requirements do not distinguish EGUs based on ownership, either for those units that are included within the scope of the proposed rule or for those units that are exempted by the generating capacity cut-off. Consequently, the proposed rule has no requirements that uniquely affect small governments that own or operate EGUs within the affected region. With respect to the significance of the rule's provisions, EPA's UMRA analysis (cited above) demonstrates that the economic impact of the rule will not significantly affect State or municipal EGUs or non-EGUs, either in terms of total cost incurred and the impact of the costs on revenue, or increased cost of electricity to consumers. Therefore, development of a small government plan under section 203 of the Act is not required. Under section 204 of UMRA, 2 U.S.C. 1534, if an agency proposes a rule that contains a ``significant Federal intergovernmental mandate'', the agency must develop a process to permit elected officials of State, local, and tribal governments to provide input into the development of the proposal.'' In order to fulfill UMRA requirements that publicly- elected officials be given meaningful and timely input in the process of regulatory development, EPA has sent letters to five national associations whose members include elected officials. The letters provide background information, request the associations to notify their membership of the proposed rulemaking, and encourage interested parties to comment on the proposed actions by sending comments during the public comment period and presenting testimony at the public hearing on the proposal. Any comments will be taken into consideration as the action moves toward final rulemaking. In addition, during the NOX SIP call, EPA provided direct notification to potentially affected State and municipally-owned utilities as part of the public comment and hearing process attendant to proposal of the NOX SIP call and supplemental notice of proposed rulemaking. These procedures helped ensure that small governments had an opportunity to give timely input and obtain information on compliance. The EPA provided the 26 State and municipality-owned utilities and appropriate elected officials with a brief summary of the proposal and the estimated impacts. The public rulemaking also elicited numerous comments from State and municipal utilities and groups representing utility interests. Furthermore, for the section 126 rulemaking, EPA published an ANPR that served to provide notice of the Agency's intention to propose emissions limits and to solicit early input on the proposal. This process helped to ensure

that small governments had an opportunity to give timely input and obtain information on compliance.

D. Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for approval to the OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information Collection Request (ICR) document has been prepared by EPA (ICR No. 1889.01) and a copy may be obtained from Sandy Farmer, OPPE Regulatory Information Division, US Environmental Protection Agency (2137), 401 M St., SW, Washington, DC 20460 or by calling (202) 260-2740. The EPA believes that it is essential that sources for whom findings are made under section 126 of the CAA demonstrate that they are achieving their required reductions. This is achieved through the monitoring and reporting of emissions. Accurate and consistent monitoring of emissions also facilitates the trading program which helps ensure that emission reductions are achieved in the most cost affective way possible. Respondents/Affected Entities: Large fossil fuel boilers, turbines and combined cycle units which are included in the section 126 proposal. Number of Respondents: 2011. Frequency of Response:

--Emissions reports quarterly for some units, twice during ozone season for others --Test notifications and allowance transfers on an infrequent basis --Compliance certifications on an annual basis

Estimated Annual Hour Burden per Respondent: 107. Estitmated Annual Cost per Respondent: $7,943. Estimated Total Annual Hour Burden: 216,671. Estimated Total Annualized Cost: $13,859,599.

Note that these are an average estimate for the first three years of the program. The EPA estimates lower costs in the first two years of the program because less units will be participating at that time. The units that will be participating at that time are units that are applying for early reduction credits. The EPA also estimates that the highest compliance costs will occur in 2002, when the majority of the units that have to install and certify new monitors to comply with the program will do so. The EPA believes that the year 2003 will be more representative of the actual ongoing costs of the program. At that time EPA estimates a burden of 179 hours per source and a cost of $27,670 per source. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations are listed in 40 CFR part 9 and 48 CFR ch. 15. Comments are requested on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including through the use of automated collection techniques to the Director, Office of Policy, Regulatory Information Division, US Environmental Protection Agency (2137), 401 M St., SW, Washington, DC 20460; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th St., NW, Washington, DC 20503, marked ``Attention: Desk Officer for EPA.'' Comments are requested by December 7, 1998. Please include the ICR number in any correspondence.

E. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks

1. Applicability of Executive Order 13045 The Executive Order 13045 applies to any rule that EPA determines (1) ``economically significant'' as defined under Executive Order 12866, and (2) the environmental health or safety risk addressed by the rule has a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children; and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. This proposed rule is not subject to Executive Order 13045, entitled ``Protection of Children from Environmental Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997), because it does not involve decisions on environmental health risks or safety risks that may disproportionately affect children. 2. Children's Health Protection In accordance with section 5(501), the Agency has evaluated the environmental health or safety effects of the rule on children, and found that the rule does not separately address any age groups. However, in conjunction with the final NOX SIP call rulemaking, the Agency has conducted a general analysis of the potential changes in ozone and PM levels experienced by children as a result of the NOX SIP call; these findings are presented in the RIA. The findings include population-weighted exposure characterizations for projected 2007 ozone and PM concentrations. The population data includes a census-derived subdivision for the under 18 group.

F. Executive Order 12898: Environmental Justice

Executive Order 12848 requires that each Federal agency make achieving environmental justice part of its mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of its programs, policies, and activities on minorities and low-income populations. In conjunction with the final NOX SIP call rulemaking, the Agency has conducted a general analysis of the potential changes in ozone and PM levels that may be experienced by minority and low-income populations as a result of the NOX SIP call; these findings are presented in the RIA. The findings include population-weighted exposure characterizations for projected ozone concentrations and PM concentrations. The population data includes census-derived subdivisions for whites and non-whites, and for low-income groups.

G. Executive Order 12875: Enhancing the Intergovernmental Partnership

Under Executive Order 12875, EPA may not issue a regulation that is not required by statute and that creates a mandate upon a State, local or tribal government, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by those governments or EPA consults with those governments. If the mandate is unfunded, EPA must provide to the Office of Management and Budget a description of the extent of EPA's prior consultation with

representatives of affected State, local and tribal governments, the nature of their concerns, copies of any written communications from the governments, and a statement supporting the need to issue the regulation. In addition, Executive Order 12875 requires EPA to develop an effective process permitting elected officials and other representatives of State, local and tribal governments ``to provide meaningful and timely input in the development of regulatory proposals containing significant unfunded mandates.'' The EPA has concluded that this rule may create a mandate on State and local governments and that the Federal government will not provide the funds necessary to pay the direct costs incurred by the State and local governments in complying with the mandate. In order to provide meaningful and timely input in the development of this regulatory action, EPA has sent letters to five national associations whose members include elected officials. The letters provide background information, request the associations to notify their membership of the proposed rulemaking, and encourage interested parties to comment on the proposed actions by sending comments during the public comment period and presenting testimony at the public hearing on the proposal. Any comments will be taken into consideration as the action moves toward final rulemaking. Furthermore, for the section 126 rulemaking, EPA published an ANPR that served to provide notice of the Agency's intention to propose emissions limits and to solicit early input on the proposal. This process helped to ensure that small governments had an opportunity to give timely input and obtain information on compliance.

H. Executive Order 13084: Consultation and Coordination With Indian Tribal Governments

Under Executive Order 13084, EPA may not issue a regulation that is not required by statute, that significantly or uniquely affects the communities of Indian tribal governments, and that imposes substantial direct compliance costs on those communities, unless the government provides the funds necessary to pay the direct compliance costs incurred by the tribal governments. If the mandate is unfunded, EPA must provide to the Office of Management and Budget, in a separately identified section of the preamble to the rule, a description of the extent of EPA's prior consultation with representatives of affected tribal governments, a summary of the nature of their concerns, and a statement supporting the need to issue the regulation. In addition, Executive Order 13084 requires EPA to develop an effective process permitting elected and other representatives of Indian tribal governments ``to provide meaningful and timely input in the development of regulatory policies on matters that significantly or uniquely affect their communities.'' Today's rule does not significantly or uniquely affect the communities of Indian tribal governments and, in any event, will not impose substantial direct compliance costs on such communities. The EPA is not aware of sources located on tribal lands that could be subject to the requirements EPA is proposing in this notice. Accordingly, the requirements of section 3(b) of Executive Order 13084 do not apply.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Pub L. 104-113, Sec. 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This proposed rulemaking would require all sources that participate in the trading program under proposed part 97 to meet the applicable monitoring requirements of part 75. Part 75 already incorporates a number of voluntary consensus standards. In addition, EPA's proposed revisions to part 75 proposed to add two more voluntary consensus standards to the rule (see 63 FR at 28116-17, discussing ASTM D5373-93 ``Standard Methods for Instrumental Determination of Carbon, Hydrogen and Nitrogen in laboratory samples of Coal and Coke,'' and API Section 2 ``Conventional Pipe Provers'' from Chapter 4 of the Manual of Petroleum Measurement Standards, October 1988 edition). The EPA's proposed part 75 revisions also requested comments on the inclusion of additional voluntary consensus standards. The EPA has recently finalized revisions to part 75 addressing some of the topics raised in EPA's proposed revisions to part 75. As part of this rule finalization, EPA incorporated two new voluntary consensus standards: (1) American Petroleum Institute (API) Petroleum Measurement Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, December 1994; Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997); Section 2, Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, September 1995; Section 3, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, March 1997; and (2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed October 1992), for Sec. 75.19. The EPA intends to finalize other revisions to part 75 and address comments related to additional voluntary consensus standards at that time. This proposed rulemaking involves environmental monitoring or measurement. Sources that participate in the trading program would be required to meet the monitoring requirements under part 75. Consistent with the Agency's Performance Based Measurement System (PBMS), part 75 sets forth performance criteria that allow the use of alternative methods to the ones set forth in part 75. The PBMS approach is intended to be more flexible and cost effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. The EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified, however, any alternative methods must be approved in advance before they may be used under part 75. The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially applicable voluntary consensus standards and to explain why such standards should be used in this regulation.

List of Subjects

40 CFR Part 52

Environmental protection, Air pollution control, Emissions trading, Nitrogen oxides, Ozone transport, Reporting and recordkeeping requirements.

40 CFR Part 97

Environmental protection, Air pollution control, Emissions trading, Nitrogen oxides, Ozone transport, Reporting and recordkeeping requirements.

Dated: September 24, 1998. Carol M. Browner, Administrator.

For the reasons set forth in the preamble, parts 52 and 97 of chapter I of title 40 of the Code of Federal Regulations are proposed to be amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

Authority: 42 U.S.C. 7401-7671q.

Subpart A--General Provisions

2. Subpart A is amended to add Sec. 52.34 to read as follows:

Sec. 52.34 Action on petitions submitted under section 126 relating to emissions of nitrogen oxides.

(a) Purpose and applicability. Paragraphs (b) through (i) of this section set forth EPA's affirmative and negative technical determinations regarding whether, with respect to the national ambient air quality standards (NAAQS) for ozone, certain new and existing sources of emissions of nitrogen oxides (``NOX'') in certain States emit NOX in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more States that submitted petitions in 1997 addressing such NOX emissions under section 126 of the Clean Air Act. (As used in this section, the term new source includes modified sources, as well.) The States that submitted such petitions are Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, and Vermont (each of which, hereinafter in this section, may be referred to also as a ``petitioning State''). Paragraph (j) of this section sets forth EPA's decisions about whether to grant or deny each of those petitions, and paragraph (k) of this section sets forth the emissions- reduction requirements that will apply to the affected NOX sources to the extent any of the petitions is granted. Appendix A of part 97 of this chapter contains a list of the existing NOX sources that as of date of signature are covered by the affirmative technical determinations described herein, and that would be required to meet such pollution-control requirements to the extent a petition covering such sources is granted. (b) Technical determinations relating to impacts on ozone levels in Connecticut.--(1) Affirmative technical determinations with respect to the 1-hour ozone standard in Connecticut. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of Connecticut with respect to the 1-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (b)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Connecticut. (2) States or portions of states that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in Connecticut. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) Delaware. (ii) District of Columbia. (iii) Portion of Indiana located in OTAG Subregions 2 and 6, as shown in appendix F, Figure F-2 of this part. (iv) Portion of Kentucky located in OTAG Subregion 6, as shown in appendix F, Figure F-2 of this part. (v) Maryland. (vi) Portion of Michigan located in OTAG Subregion 2, as shown in appendix F, Figure F-2 of this part. (vii) Portion of North Carolina located in OTAG Subregion 7, as shown in appendix F, Figure F-2 of this part. (viii) New Jersey. (ix) Portion of New York extending west and south of Connecticut, as shown in appendix F, Figure F-2 of this part. (x) Ohio. (xi) Pennsylvania. (xii) Virginia. (xiii) West Virginia. (3) Negative technical determinations with respect to the 1-hour ozone standard in Connecticut. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (b)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of Connecticut, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (b)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Connecticut; but (iii) Is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Connecticut. The States or portions thereof described in paragraph (b)(3) of this section are: (i) Portion of Tennessee located in OTAG Subregion 6, as shown in appendix F, Figure F-2. (c) Technical determinations relating to impacts on ozone levels in Maine.--(1) Affirmative technical determinations with respect to the 1- hour ozone standard in Maine. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of Maine, with respect to the 1-hour NAAQS for ozone if it is or will be: (I) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (c)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Maine. (2) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in Maine. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) Connecticut. (ii) Delaware. (iii) District of Columbia. (iv) Maryland.

(v) Massachusetts. (vi) New Jersey. (vii) New York. (viii) Pennsylvania. (ix) Rhode Island. (3) Negative technical determinations with respect to the 1-hour ozone standard in Maine. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (c)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of Maine, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources that does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (c)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Maine; but (iii) Is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Maine. The States or portions thereof described in paragraph (c)(3) of this section are: (i) Portion of North Carolina within a 600 mile radius of Maine's ozone nonattainment areas, as shown in appendix F, Figure F-3 of this part. (ii) New Hampshire. (iii) Portion of Ohio within a 600 mile radius of Maine's ozone nonattainment areas, as shown in appendix F, Figure F-3 of this part. (iv) Vermont. (v) Portion of Virginia within a 600 mile radius of Maine's ozone nonattainment areas, as shown in appendix F, Figure F-3 of this part. (vi) Portion of West Virginia within a 600 mile radius of Maine's ozone nonattainment areas, as shown in appendix F, Figure F-3 of this part. (d) Technical determinations relating to impacts on ozone levels in Massachusetts.--(1) Affirmative technical determinations with respect to the 1-hour ozone standard in Massachusetts. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOx in amounts that contribute significantly to nonattainment in the State of Massachusetts, with respect to the 1-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (d)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Massachusetts. (2) States or portions of states that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in Massachusetts. The States or portions of States that contain sources for which EPA is making an affirmative technical determination are: (i) All counties in Ohio located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (ii) All counties in West Virginia located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (3) Negative technical determinations with respect to the 1-hour ozone standard in Massachusetts. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (d)(4) of this section does not or would not emit NOx in amounts that contribute significantly to nonattainment in the State of Massachusetts, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOx in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (d)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Massachusetts; but (iii) is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Massachusetts. The States or portions thereof described in paragraph (d)(3) of this section are: (i) All counties in Kentucky located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (ii) All counties in Indiana located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (5) Affirmative technical determinations with respect to the 8-hour ozone standard in Massachusetts. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOx in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the State of Massachusetts, with respect to the 8-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (d)(6) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Massachusetts. (6) States or portions of states that contain sources for which EPA is making an affirmative technical determination with respect to the 8- hour ozone standard in Massachusetts. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) All counties in Ohio located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (ii) All counties in West Virginia located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (7) Negative technical determinations with respect to the 8-hour ozone standard in Massachusetts. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (d)(8) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the State of Massachusetts, with respect to the 8-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it is or will be: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (d)(6) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Massachusetts; but

(iii) is not in a category of sources described in 40 CFR 97.4. (8) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 8-hour ozone standard in Massachusetts. The States or portions thereof described in paragraph (d)(7) of this section are: (i) All counties in Indiana located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (ii) All counties in Kentucky located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-4 of this part. (e) Technical determinations relating to impacts on ozone levels in New Hampshire.--(1) Affirmative technical determinations with respect to the 1-hour ozone standard in New Hampshire. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of New Hampshire, with respect to the 1-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (e)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of New Hampshire. (2) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in New Hampshire. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) Connecticut. (ii) Delaware. (iii) District of Columbia. (iv) Maryland. (v) Massachusetts. (vi) New Jersey. (vii) New York. (viii) Pennsylvania. (ix) Rhode Island. (x) Virginia. (3) Negative technical determinations with respect to the 1-hour ozone standard in New Hampshire. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (e)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of New Hampshire, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (e)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of New Hampshire; but (iii) is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in New Hampshire. The States or portions thereof described in paragraph (e)(3) of this section are: (i) Illinois. (ii) Indiana. (iii) Portion of Iowa within OTAG Subregion 1, as shown in appendix F, Figure F-5 of this part. (iv) Kentucky. (v) Maine. (vi) Portion of Michigan within OTAG Subregions 1 and 2, as shown in appendix F, Figure F-5 of this part. (vii) Portion of Missouri within OTAG Subregion 5, as shown in appendix F, Figure F-5 of this part. (viii) North Carolina. (ix) Ohio. (x) Tennessee. (xi) West Virginia. (xii) Portion of Wisconsin within OTAG Subregion 1, as shown in appendix F, Figure F-5 of this part. (xiii) Vermont. (f) Technical determinations relating to impacts on ozone levels in the State of New York.--(1) Affirmative technical determinations with respect to the 1-hour ozone standard in the State of New York. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of New York, with respect to the 1-hour NAAQS for ozone: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (f)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of New York. (2) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in the State of New York. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) Delaware. (ii) District of Columbia. (iii) Portion of Indiana located in OTAG Subregions 2 and 6, as shown in appendix F, Figure F-6 of this part. (iv) Portion of Kentucky located in OTAG Subregion 6, as shown in appendix F, Figure F-6 of this part. (v) Maryland. (vi) Portion of Michigan located in OTAG Subregion 2, as shown in appendix F, Figure F-6 of this part. (vii) Portion of North Carolina located in OTAG Subregions 6 and 7, as shown in appendix F, Figure F-6 of this part. (viii) New Jersey. (ix) Ohio. (x) Pennsylvania. (xi) Virginia. (xii) West Virginia. (3) Negative technical determinations with respect to the 1-hour ozone standard in the State of New York. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (f)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of New York, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (f)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of New York; but (iii) Is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in the State of New York. The States or portions thereof described in paragraph (f)(3) of this section are: (i) Portion of Tennessee located in OTAG Subregion 6, as shown in appendix F, Figure F-6 of this part. (g) Technical determinations relating to impacts on ozone levels in Pennsylvania.--(1) Affirmative

technical determinations with respect to the 1-hour ozone standard in Pennsylvania. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of Pennsylvania, with respect to the 1-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (g)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Pennsylvania. (2) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in Pennsylvania. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) North Carolina. (ii) Ohio. (iii) Virginia. (iv) West Virginia. (3) Negative technical determinations with respect to the 1-hour ozone standard in Pennsylvania. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (g)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of Pennsylvania, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (g)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Pennsylvania; but (iii) Is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Pennsylvania. The States or portions thereof described in paragraph (g)(3) of this section are: (i) Alabama. (ii) Arkansas. (iii) Georgia. (iv) Illinois. (v) Indiana (vi) Iowa. (vii) Kentucky. (viii) Louisiana. (ix) Michigan. (x) Minnesota. (xi) Mississippi. (xii) Missouri. (xiii) South Carolina. (xiv) Tennessee. (xv) Wisconsin. (5) Affirmative technical determinations with respect to the 8-hour ozone standard in Pennsylvania. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the State of Pennsylvania, with respect to the 8-hour NAAQS for ozone: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (g)(6) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Pennsylvania. (6) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 8- hour ozone standard in Pennsylvania. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) Alabama. (ii) Illinois. (iii) Indiana. (iv) Kentucky. (v) Michigan. (vi) Missouri. (vii) North Carolina. (viii) Ohio. (ix) Tennessee. (x) Virginia. (xi) West Virginia. (7) Negative technical determinations with respect to the 8-hour ozone standard in Pennsylvania. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (g)(8) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the State of Pennsylvania, with respect to the 8-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (g)(6) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Pennsylvania; but (iii) Is not in a category of sources described in 40 CFR 97.4. (8) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 8-hour ozone standard in Pennsylvania. The States or portions thereof described in paragraph (g)(7) of this section are: (i) Arkansas. (ii) Georgia. (iii) Iowa. (iv) Louisiana. (v) Minnesota. (vi) Mississippi. (vii) South Carolina. (viii) Wisconsin. (h) Technical determinations relating to impacts on ozone levels in Rhode Island.--(1) Affirmative technical determinations with respect to the 1-hour ozone standard in Rhode Island. The Administrator of EPA finds that any existing or new major source or group of stationary sources emits or would emit NOX in amounts that contribute significantly to nonattainment in the State of Rhode Island, with respect to the 1-hour NAAQS for ozone if it is or will be: (i) In a category of sources described in 40 CFR 97.4; (ii) Located in one of the States (or portions thereof) listed in paragraph (h)(2) of this section; and (iii) Within one of the ``Named Source Categories'' listed in the portion of Table F-1 in appendix F of this part describing the sources covered by the petition of the State of Rhode Island. (2) States or portions of States that contain sources for which EPA is making an affirmative technical determination with respect to the 1- hour ozone standard in Rhode Island. The States, or portions of States, that contain sources for which EPA is making an affirmative technical determination are: (i) All counties in Ohio located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-8 of this part. (ii) All counties in West Virginia located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-8 of this part. (3) Negative technical determinations with respect to the 1-hour ozone

standard in Rhode Island. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (h)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of Rhode Island, with respect to the 1-hour NAAQS for ozone. The Administrator also finds that any existing or new major source or group of stationary sources does not or would not emit NOX in such amounts if it: (i) Is or will be located in one of the States (or portions thereof) listed in paragraph (h)(2) of this section; and (ii) Is or will be within one of the ``Named Source Categories'' listed in the portion of Table F-1 in Appendix F of this part describing the sources covered by the petition of the State of Rhode Island; but (iii) Is not in a category of sources described in 40 CFR 97.4. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Rhode Island. The States or portions thereof described in paragraph (h)(3) of this section are: (i) All counties in Kentucky located within a 3-county-wide band of the Ohio River, as shown in appendix F, Figure F-8 of this part. (ii) All counties in Indiana located within a 3-county wide-band of the Ohio River, as shown in appendix F, Figure F-8 of this part. (i) Technical determinations relating to impacts on ozone levels in Vermont.--(1) Negative technical determinations with respect to the 1- hour ozone standard in Vermont. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (i)(2) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in the State of Vermont, with respect to the 1-hour NAAQS for ozone. (2) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 1-hour ozone standard in Vermont. The States or portions thereof described in paragraph (i)(1) of this section are: (i) Portion of Alabama within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (ii) Portion of Connecticut within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (iii) Delaware. (iv) District of Columbia. (v) Portion of Georgia within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (vi) Illinois. (vii) Indiana. (viii) Portion of Iowa within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (ix) Kentucky. (x) Maryland. (xi) Portion of Massachusetts within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xii) Portion of Michigan within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xiii) Portion of Missouri within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xiv) New Jersey. (xv) Portion of New York within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xvi) North Carolina. (xvii) Ohio. (xviii) Pennsylvania. (xix) South Carolina. (xx) Portion of Tennessee within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xxi) Virginia. (xxii) West Virginia. (xxiii) Portion of Wisconsin within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (3) Negative technical determinations with respect to the 8-hour ozone standard in Vermont. The Administrator of EPA finds that any existing or new major source or group of stationary sources that is or will be located in one of the States (or portions thereof) listed in paragraph (i)(4) of this section does not or would not emit NOX in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, the State of Vermont, with respect to the 8-hour NAAQS for ozone. (4) States or portions of States that contain no sources for which EPA is making an affirmative technical determination with respect to the 8-hour ozone standard in Vermont. The States or portions thereof described in paragraph (i)(3) of this section are: (i) Portion of Alabama within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (ii) Portion of Connecticut within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (iii) Delaware. (iv) District of Columbia. (v) Portion of Georgia within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (vi) Illinois. (vii) Indiana. (viii) Portion of Iowa within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (ix) Kentucky. (x) Maryland. (xi) Portion of Massachusetts within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xii) Portion of Michigan within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xiii) Portion of Missouri within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xiv) New Jersey. (xv) Portion of New York within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xvi) North Carolina. (xvii) Ohio. (xviii) Pennsylvania. (xix) South Carolina. (xx) Portion of Tennessee within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (xxi) Virginia. (xxii) West Virginia. (xxiii) Portion of Wisconsin within 1000 miles southwest from Bennington, VT, as shown in appendix F, Figure F-9 of this part. (j) Action on petitions for section 126(b) findings. (1) For each existing or new major source or group of stationary sources for which the Administrator has made an affirmative technical determination as described in paragraphs (b) through (i) of this section as to impacts on nonattainment or maintenance of a particular NAAQS for ozone in a particular petitioning State, a finding of the Administrator that each such major source or group of stationary sources emits or would emit NOX in violation of the prohibition of Clean Air Act section 110(a)(2)(D)(i)(I) with the respect to nonattainment or maintenance of such standard in such petitioning State will be deemed to be made:

(i) As of November 30, 1999, if by such date EPA does not issue either: (A) A proposed approval, under section 110(k) of the Clean Air Act, of a State implementation plan revision submitted by such State to comply with the requirements of section 110(a)(2)(D)(i)(I) of the Clean Air Act; or (B) A final Federal implementation plan meeting such requirements for such State. (ii) As of May 1, 2000, if by November 30, 1999, EPA takes the action described in paragraph (j)(1)(i) of this section for such State, but, by May 1, 2000, EPA does not approve or promulgate implementation plan provisions meeting such requirements for such State. (2) The making of any such finding as to any such major source or group of stationary sources shall be considered to be the making of a finding under subsection (b) of section 126 of the Clean Air Act as to such major source or group of stationary sources. Each aspect of a petition as to which the Administrator has made an affirmative technical determination (as described in paragraphs (b) through (i) of this section) shall be deemed denied as of May 1, 2000, if a section 126(b) finding has not been deemed to have been made by that date. Notwithstanding any other provision of this paragraph or section, after such a finding has been deemed to be made under this paragraph as to a particular major source or group of stationary sources in a particular State, such finding will be deemed to be withdrawn, and the corresponding part of the relevant petition(s) denied, if the Administrator issues a final action putting in place implementation plan provisions that comply with the requirements of section 110(a)(2)(D)(i)(I) of the Clean Air Act for such State. (3) For each new or existing major source or group of stationary sources for which the Administrator has made a negative technical determination in any of paragraphs (b) through (i) of this section as to impacts on a particular petitioning State with respect to a particular NAAQS for ozone, the Administrator hereby denies the petition of such petitioning State and determines that such new or existing major source or group of stationary sources does not emit or would not emit in violation of the prohibition in Clean Air Act section 110(a)(2)(D)(i)(I) with respect to impacts on nonattainment or maintenance of such standard in such petitioning State. (k) The provisions of part 97 of this chapter apply to the owner or operator of any new or existing major source, or other source within any group of stationary sources, as to which the Administrator makes a finding under section 126(b) of the Clean Air Act pursuant to the provisions of paragraph (j) of this section. 3. Appendix F is added to part 52 to read as follows:

Appendix F to This Part--Clean Air Act Section 126 Petitions From Eight Northeastern States: Named Source Categories and Geographic Coverage

The table and figures in this appendix are cross-referenced in Sec. 52.34.

Table F-1.--Named Source Categories in Section 126 Petitions ------------------------------------------------------------------------ Petitioning State Named source categories ------------------------------------------------------------------------ Connecticut.................. Fossil fuel-fired boilers or other indirect heat exchangers with a maximum gross heat input rate of 250 mmBtu/hr or greater and electric utility generating facilities with a rated output of 15 MW or greater. Maine........................ Electric utilities and steam-generating units with a heat input capacity of 250 mmBtu/hr or greater. Massachusetts................ Electricity generating plants. New Hampshire................ Fossil fuel-fired indirect heat exchange combustion units and fossil fuel-fired electric generating facilities which emit ten tons of NOX or more per day. New York..................... Fossil fuel-fired boilers or indirect heat exchangers with a maximum heat input rate of 250 mmBtu/hr or greater and electric utility generating facilities with a rated output of 15 MW or greater. Pennsylvania................. Fossil fuel-fired indirect heat exchange combustion units with a maximum rated heat input capacity of 250 mmBtu/hr or greater, and fossil fuel-fired electric generating facilities rated at 15 MW or greater. Rhode Island................. Electricity generating plants. Vermont...................... Fossil fuel-fired electric utility generating facilities with a maximum gross heat input rate of 250 mmBtu/hr or greater and potentially other unidentified major sources. ------------------------------------------------------------------------

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PART 97--FEDERAL NOX BUDGET TRADING PROGRAM

4. Part 97 is added to read as follows:

Subpart A--Federal NOX Budget Trading Program General Provisions

Sec. 97.1 Purpose. 97.2 Definitions. 97.3 Measurements, abbreviations, and acronyms. 97.4 Applicability. 97.5 Retired unit exemption. 97.6 Standard requirements. 97.7 Computation of time.

Subpart B--NOX Authorized Account Representative for NOX Budget Sources

97.10 Authorization and responsibilities of the NOX authorized account representative. 97.11 Alternate NOX authorized account representative. 97.12 Changing the NOX authorized account representative, and the alternate NOX authorized account representative; changes in the owners and operators. 97.13 Account certificate of representation. 97.14 Objections concerning the NOX authorized account representative.

Subpart C--Permits

97.20 General NOX budget trading program permit requirements. 97.21 NOX Budget permit applications. 97.22 Information requirements for NOX Budget permit applications. 97.23 NOX Budget permit contents. 97.24 Effective date of initial NOX Budget permit. 97.25 NOX Budget permit revisions.

Subpart D--Compliance Certification

97.30 Compliance certification report. 97.31 Administrator's action on compliance certifications.

Subpart E--NOX Allowance Allocations

97.40 Trading program budget. 97.41 Timing requirements for NOX allowance allocations. 97.42 NOX allowance allocations.

Subpart F--NOX Allowance Tracking System

97.50 NOX Allowance Tracking System accounts. 97.51 Establishment of accounts. 97.52 NOX Allowance Tracking System responsibilities of NOX authorized account representative. 97.53 Recordation of NOX allowance allocations. 97.54 Compliance. 97.55 Banking. 97.56 Account error. 97.57 Closing of general accounts.

Subpart G--NOX Allowance Transfers

97.60 Submission of NOX allowance transfers. 97.61 EPA recordation. 97.62 Notification.

Subpart H--Monitoring and Reporting

97.70 General requirements. 97.71 Initial certification and recertification procedures. 97.72 Out of control periods. 97.73 Notifications. 97.74 Recordkeeping and reporting. 97.75 Petitions. 97.76 Additional requirements to provide heat data imput.

Subpart I--Individual Unit Opt-ins

97.80 Applicability. 97.81 General. 97.82 Applying for NOX authorized account representative. 97.83 Applying for NOX Budget opt-in permit. 97.84 Opt-in process. 97.85 NOX Budget opt-in permit contents. 97.86 Withdrawal from NOX Budget Trading Program. 97.87 Change in regulatory status. 97.88 NOX allowance allocations to opt-in units. Appendix A to Part 97--NOX Allowance Allocation Tables for Affected Sources Under Section 126 of the Act Appendix B to Part 97--NOX Allowance Allocation Tables for Affected Sources Under Section 110 of the Act in Georgia, South Carolina, and Wisconsin Appendix C to Part 97--State-By-State Maximum Summer NOX Emission Levels and Allocation Aggregates

Authority: 42 U.S.C. 7401, 7403, 7410, and 7601.

Subpart A--Federal NOX Budget Trading Program General Provisions

Sec. 97.1 Purpose.

This part establishes general provisions and the applicability, permitting, allowance, excess emissions, monitoring, and opt-in provisions for the federal NOX Budget Trading Program, under section 110(c) or section 126 of the Act, as a means of mitigating the interstate transport of ozone and nitrogen oxides, an ozone precursor. The owner or operator of a unit, or any other person, shall comply with

requirements of this part as a matter of federal law only if such compliance is required by Sec. 52.34 or Sec. 52.35 of this chapter.

Sec. 97.2 Definitions.

The terms used in this part shall have the meanings set forth in this section as follows: Account certificate of representation means the completed and signed submission required by subpart B of this part for certifying the designation of a NOX authorized account representative for a NOX Budget source or a group of identified NOX Budget sources who is authorized to represent the owners and operators of such source or sources and of the NOX Budget units at such source or sources with regard to matters under the NOX Budget Trading Program. Account number means the identification number given by the Administrator to each NOX Allowance Tracking System account. Acid Rain emissions limitation means, as defined in Sec. 72.2 of this chapter, a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program under title IV of the Clean Air Act. Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's duly authorized representative. Allocate or allocation means the determination by the permitting authority or the Administrator of the number of NOX allowances to be initially credited to a NOX Budget unit or an allocation set-aside. Automated data acquisition and handling system or DAHS means that component of the CEMS, or other emissions monitoring system approved for use under subpart H of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart H of this part. Boiler means an enclosed fossil or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium. Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq., as amended by Pub. L. No. 101-549 (November 15, 1990). Combined cycle system means a system comprised of one or more combustion turbines, heat recovery steam generators, and steam turbines configured to improve overall efficiency of electricity generation or steam production. Combustion turbine means an enclosed fossil or other fuel-fired device that is comprised of a compressor, a combustor, and a turbine, and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine. Commence commercial operation means, with regard to a unit that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation. Except as provided in Sec. 97.5, for a unit that is a NOX Budget unit under Sec. 97.4 on the date the unit commences commercial operation, such date shall remain the unit's date of commencement of commercial operation even if the unit is subsequently modified, reconstructed, or repowered. Except as provided in Sec. 97.5 or subpart I of this part, for a unit that is not a NOX Budget unit under Sec. 97.4 on the date the unit commences commercial operation, the date the unit becomes a NOX Budget unit under Sec. 97.4 shall be the unit's date of commencement of commercial operation. Commence operation means to have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit's combustion chamber. Except as provided in Sec. 97.5, for a unit that is a NOX Budget unit under Sec. 97.4 on the date of commencement of operation, such date shall remain the unit's date of commencement of operation even if the unit is subsequently modified, reconstructed, or repowered. Except as provided in Sec. 97.5 or subpart I of this part, for a unit that is not a NOX Budget unit under Sec. 97.4 on the date of commencement of operation, the date the unit becomes a NOX Budget unit under Sec. 97.4 shall be the unit's date of commencement of operation. Common stack means a single flue through which emissions from two or more units are exhausted. Compliance certification means a submission to the permitting authority or the Administrator, as appropriate, that is required under subpart D of this part to report a NOX Budget source's or a NOX Budget unit's compliance or noncompliance with this part and that is signed by the NOX authorized account representative in accordance with subpart B of this part. Compliance account means a NOX Allowance Tracking System account, established by the Administrator for a NOX Budget unit under subpart F of this part, in which the NOX allowance allocations for the unit are initially recorded and in which are held NOX allowances available for use by the unit for a control period for the purpose of meeting the unit's NOX Budget emissions limitation. Continuous emission monitoring system or CEMS means the equipment required under subpart H of this part to sample, analyze, measure, and provide, by readings taken at least once every 15 minutes of the measured parameters, a permanent record of nitrogen oxides emissions, expressed in tons per hour for nitrogen oxides. The following systems are component parts included, consistent with part 75 of this chapter, in a continuous emission monitoring system: (1) Flow monitor; (2) Nitrogen oxides pollutant concentration monitors; (3) Diluent gas monitor (oxygen or carbon dioxide) when such monitoring is required by subpart H of this part; (4) A continuous moisture monitor when such monitoring is required by subpart H of this part; and (5) An automated data acquisition and handling system. Control period means the period beginning May 1 of a year and ending on September 30 of the same year, inclusive. Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the NOX authorized account representative and as determined by the Administrator in accordance with subpart H of this part. Energy Information Administration means the Energy Information Administration of the United States Department of Energy. Excess emissions means any tonnage of nitrogen oxides emitted by a NOX Budget unit during a control period that exceeds the NOX Budget emissions limitation for the unit. Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material. Fossil fuel-fired means, with regard to a unit: (1)The combustion of fossil fuel, alone or in combination with any other fuel, where fossil fuel actually combusted comprises more than 50 percent of the annual heat input on a Btu basis during any year starting in 1995 or, if a unit had no heat input starting in 1995, during the last year of operation of the unit prior to 1995; or (2)The combustion of fossil fuel, alone or in combination with any other fuel,

where fossil fuel is projected to comprise more than 50 percent of the annual heat input on a Btu basis during any year; provided that the unit shall be ``fossil fuel-fired'' as of the date, during such year, on which the unit begins combusting fossil fuel. General account means a NOX Allowance Tracking System account, established under subpart F of this part, that is not a compliance account or an overdraft account. Generator means a device that produces electricity. Heat input means the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) and the fuel feed rate into a combustion device (in mass of fuel/time), as measured, recorded, and reported to the Administrator by the NOX authorized account representative and as determined by the Administrator in accordance with subpart H of this part, and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources. Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy from any specified unit and pays its proportional amount of such unit's total costs, pursuant to a contract: (1) For the life of the unit; (2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or (3) For a period equal to or greater than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period. Maximum design heat input means the ability of a unit to combust a stated maximum amount of fuel per hour on a steady state basis, as determined by the physical design and physical characteristics of the unit. Maximum potential hourly heat input means an hourly heat input used for reporting purposes when a unit lacks certified monitors to report heat input. If the unit intends to use appendix D of part 75 of this chapter to report heat input, this value should be calculated, in accordance with part 75 of this chapter, using the maximum fuel flow rate and the maximum gross calorific value. If the unit intends to use a flow monitor and a diluent gas monitor, this value should be reported, in accordance with part 75 of this chapter, using the maximum potential flowrate and either the maximum carbon dioxide concentration (in percent CO2) or the minimum oxygen concentration (in percent O2). Maximum potential NOX emission rate means the emission rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with section 3 of appendix F of part 75 of this chapter, using the maximum potential nitrogen oxides concentration as defined in section 2 of appendix A of part 75 of this chapter, and either the maximum oxygen concentration (in percent O2) or the minimum carbon dioxide concentration (in percent CO2), under all operating conditions of the unit except for unit start up, shutdown, and upsets. Maximum rated hourly heat input means a unit specific maximum hourly heat input (mmBtu) which is the higher of the manufacturers maximum rated hourly heat input or the highest observed hourly heat input. Monitoring system means any monitoring system that meets the requirements of subpart H of this part, including a continuous emissions monitoring system, an excepted monitoring system, or an alternative monitoring system. Most stringent State or Federal NOX emissions limitation means, with regard to a NOX Budget opt-in source, the lowest NOX emissions limitation (in terms of lb/mmBtu) that is applicable to the unit under State or Federal law, regardless of the averaging period to which the emissions limitation applies. Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings as measured in accordance with the United States Department of Energy standards. Non-title V permit means a federally enforceable permit administered by the permitting authority pursuant to the Clean Air Act and regulatory authority under the Clean Air Act, other than title V of the Clean Air Act and part 70 or 71 of this chapter. NOX allowance means an authorization by the permitting authority or the Administrator under the NOX Budget Trading Program to emit up to one ton of nitrogen oxides during the control period of the specified year or of any year thereafter. NOX allowance deduction or deduct NOX allowances means the permanent withdrawal of NOX allowances by the Administrator from a NOX Allowance Tracking System compliance account or overdraft account to account for the number of tons of NOX emissions from a NOX Budget unit for a control period, determined in accordance with subparts H and F of this part, or for any other allowance surrender obligation under this part. NOX allowances held or hold NOX allowances means the NOX allowances recorded by the Administrator, or submitted to the Administrator for recordation, in accordance with subparts F and G of this part, in a NOX Allowance Tracking System account. NOX Allowance Tracking System means the system by which the Administrator records allocations, deductions, and transfers of NOX allowances under the NOX Budget Trading Program. NOX Allowance Tracking System account means an account in the NOX Allowance Tracking System established by the Administrator for purposes of recording the allocation, holding, transferring, or deducting of NOX allowances. NOX allowance transfer deadline means midnight of November 30 or, if November 30 is not a business day, midnight of the first business day thereafter and is the deadline by which NOX allowances may be submitted for recordation in a NOX Budget unit's compliance account, or the overdraft account of the source where the unit is located, in order to meet the unit's NOX Budget emissions limitation for the control period immediately preceding such deadline. NOX authorized account representative means, for a NOX Budget source or NOX Budget unit at the source, the natural person who is authorized by the owners and operators of the source and all NOX Budget units at the source, in accordance with subpart B of this part, to represent and legally bind each owner and operator in matters pertaining to the NOX Budget Trading Program or, for a general account, the natural person who is authorized, in accordance with subpart F of this part, to transfer or otherwise dispose of NOX allowances held in the general account. NOX Budget emissions limitation means, for a NOX budget unit, the tonnage equivalent of the NOX allowances available for compliance deduction for the unit under Sec. 97.54 (a) and (b) in a control period adjusted by deductions of such NOX allowances to account for actual utilization under Sec. 97.42(e) for the control period, or to account for excess emissions for a prior control period under Sec. 97.54(d) or to account for withdrawal from the NOX budget trading program or for a change

in regulatory states, of a NOX budget opt-in source under Sec. 97.86 or Sec. 97.88. NOX Budget opt-in permit means a NOX Budget permit covering a NOX Budget opt-in source. NOX Budget opt-in source means a unit that has been elected to become a NOX Budget unit under the NOX Budget Trading Program and whose NOX budget opt-in permit has been issued and is in effect under subpart I of this part. NOX Budget permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under this part, including any permit revisions, specifying the NOX Budget Trading Program requirements applicable to a NOX Budget source, to each NOX Budget unit at the NOX Budget source, and to the owners and operators and the NOX authorized account representative of the NOX Budget source and each NOX Budget unit. NOX Budget source means a source that includes one or more NOX Budget units. NOX Budget Trading Program means a multi-state nitrogen oxides air pollution control and emission reduction program established in accordance with this part and pursuant to Sec. 52.34 or Sec. 52.35 of this chapter, as a means of mitigating the interstate transport of ozone and nitrogen oxides, an ozone precursor. NOX Budget unit means a unit that is subject to the NOX Budget Trading Program emissions limitation under Sec. 97.4 or Sec. 97.80. Operating means, with regard to a unit under Secs. 97.22(d)(2) and 97.80, having documented heat input for more than 876 hours in the 6 months immediately preceding the submission of an application for an initial NOX Budget permit under Sec. 97.83(a). Operator means any person who operates, controls, or supervises a NOX Budget unit, a NOX Budget source, or unit for which an application for a NOX Budget opt-in permit under Sec. 97.83 is submitted and not denied or withdrawn and shall include, but not be limited to, any holding company, utility system, or plant manager of such a unit or source. Opt-in means to be elected to become a NOX Budget unit under the NOX Budget Trading Program through a final, effective NOX Budget opt-in permit under subpart I of this part. Overdraft account means the NOX Allowance Tracking System account, established by the Administrator under subpart F of this part, for each NOX Budget source where there are two or more NOX Budget units. Owner means any of the following persons: (1) Any holder of any portion of the legal or equitable title in a NOX Budget unit or in a unit for which an application for a NOX Budget opt-in permit under Sec. 97.83 submitted and not denied or withdrawn; or (2) Any holder of a leasehold interest in a NOX Budget unit or in a unit for which an application for a NOX Budget opt-in permit under Sec. 97.83 is submitted and not denied or withdrawn; or (3) Any purchaser of power from a NOX Budget unit or from a unit for which an application for a NOX Budget opt-in permit under Sec. 97.83 is submitted and not denied or withdrawn under a life-of-the-unit, firm power contractual arrangement. However, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based, either directly or indirectly, upon the revenues or income from the NOX Budget unit or the unit for which an application for a NOX Budget opt-in permit under Sec. 97.83 is submitted and not denied or withdrawn; or (4) With respect to any general account, any person who has an ownership interest with respect to the NOX allowances held in the general account and who is subject to the binding agreement for the NOX authorized account representative to represent that person's ownership interest with respect to NOX allowances. Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the NOX Budget Trading Program in accordance with subpart C of this part. Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in writing or by authorized electronic transmission), as indicated in an official correspondence log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business. Recordation, record, or recorded means, with regard to NOX allowances, the movement of NOX allowances by the Administrator from one NOX Allowance Tracking System account to another, for purposes of allocation, transfer, or deduction. Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in appendix A of part 60 of this chapter. Serial number means, when referring to NOX allowances, the unique identification number assigned to each NOX allowance by the Administrator, under Sec. 97.53(c). Source means any governmental, institutional, commercial, or industrial structure, installation, plant, building, or facility that emits or has the potential to emit any regulated air pollutant under the Clean Air Act. For purposes of section 502(c) of the Clean Air Act, a ``source,'' including a ``source'' with multiple units, shall be considered a single ``facility.'' State means one of the 48 contiguous States and the District of Columbia specified in Sec. 52.34 or Sec. 52.35 of this chapter, or any non-federal authority in or including such States or the District of Columbia (including local agencies, and Statewide agencies) or any eligible Indian tribe in an area of such State or the District of Columbia, for which the NOX Budget Trading Program is promulgated pursuant to Sec. 52.34 or Sec. 52.35 of this chapter. Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation: (1) In person; (2) By United States Postal Service; or (3) By other means of dispatch or transmission and delivery. Compliance with any ``submission,'' ``service,'' or ``mailing'' deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt. Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter. Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter. Ton or tonnage means any ``short ton'' (i.e., 2,000 pounds). For the purpose of determining compliance with the NOX Budget emissions limitation, total tons for a control period shall be calculated as the sum of all recorded hourly emissions (or the tonnage equivalent of the recorded hourly emissions rates) in accordance with subpart H of this part, with any remaining fraction of a ton equal to or greater than 0.50 ton deemed to equal one ton and any fraction of a ton less than 0.50 ton deemed to equal zero tons. Trading program budget means the total number of NOX tons apportioned to all NOX Budget units in a State in

accordance with the NOX Budget Trading Program, under section 110(c) or section 126 of the Act, for use in a given control period. For purposes of the NOX Budget Trading Program under section 110(c), the trading program budget is the sum of the aggregate emission levels for large EGUs and large non-EGUs in a State set forth for each State in appendix C of this part. For purposes of the NOX Budget Trading Program under section 126, the trading program budget is the ``126 trading program budget for the State'', and is determined in the same manner and is also set forth in appendix C of this part. Unit means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system. Unit load means the total (i.e., gross) output of a unit in any control period (or other specified time period) produced by combusting a given heat input of fuel, expressed in terms of: (1) The total electrical generation (MWe) produced by the unit, including generation for use within the plant; or (2) In the case of a unit that uses heat input for purposes other than electrical generation, the total steam in pounds of steam per hour produced by the unit, including steam for use by the unit. Unit operating day means a calendar day in which a unit combusts any fuel. Unit operating hour or hour of unit operation means any hour (or fraction of an hour) during which a unit combusts any fuel. Utilization means the heat input (expressed in mmBtu/time) for a unit. The unit's total heat input for the control period in each year will be determined in accordance with part 75 of this chapter if the NOX Budget unit was otherwise subject to the requirements of part 75 of this chapter for the year, or will be based on the best available data reported to the Administrator for the unit if the unit was not otherwise subject to the requirements of part 75 of this chapter for the year.

Sec. 97.3 Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this part are defined as follows:

Btu--British thermal unit. hr--hour. Kwh--kilowatt hour. lb--pounds. mmBtu--million Btu. MWe--megawatt electrical. ton--2000 pounds CO2--carbon dioxide. NOX--nitrogen oxides. O2--oxygen.

Sec. 97.4 Applicability.

(a) The following units in a State shall be NOX Budget units, and any source that includes one or more such units shall be a NOX Budget source, subject to the requirements of this part: (1) Any unit that, any time on or after January 1, 1995, serves a generator with a nameplate capacity greater than 25 MWe and sells any amount of electricity; or (2) Any unit that is not a unit under paragraph (a) of this section and that has a maximum design heat input greater than 250 mmBtu/hr. (b) Notwithstanding paragraph (a) of this section, a unit under paragraph (a)(1) or (a)(2) of this section that has a federally enforceable permit that includes a NOX emission limitation restricting NOX emissions during a control period to 25 tons or less shall not be subject to the requirements of this part for any year in which the control period is covered by such emission limitation in the unit's federally enforceable permit. However, if such emission limitation is removed from the unit's federally enforceable permit or otherwise becomes no longer applicable to any control period starting in 2003 or if the unit does not comply with such emission limitation during any control period starting in 2003, the unit shall be subject to the requirements of this part and shall be treated as commencing operation and, if the unit is covered by paragraph (a)(1) of this section, commencing commercial operation on September 30 of the control period for which the emission limitation is no longer applicable or during which the unit does not comply with the emission limitation. The permitting authority that issues the federally enforceable permit with such emission limitation will provide the Administrator written notification of each unit under paragraph (a)(1) or (a)(2) of this section for which the permitting authority issued such a permit. A unit subject to a federally enforceable permit with such emission limitation shall be subject to the following requirements: (1) The unit shall keep on site records demonstrating that conditions of the permit were met, including restrictions on operating time. (2) The unit shall report hours of operation during the control period to the permitting authority by November 1 of each year in which the unit is subject to a federally enforceable permit with such emission limitation. (3) The unit shall determine the appropriate restrictions on its operating time by dividing 25 tons by the unit's maximum potential hourly NOX mass emissions where the unit's maximum potential hourly NOX mass emissions would be determined by multiplying the highest default emission rates otherwise applicable under Sec. 75.19 of this chapter by the maximum rated hourly heat input of the unit.

Sec. 97.5 Retired unit exemption.

(a) This section applies to any NOX Budget unit, other than a NOX Budget opt-in source, that is permanently retired. (b)(1) Any NOX Budget unit, other than a NOX Budget opt-in source, that is permanently retired shall be exempt from the NOX Budget Trading Program, except for the provisions of this section, Secs. 97.2, 97.3, 97.4, 97.7 and subparts E, F, and G of this part. (2) The exemption under paragraph (b)(1) of this section shall become effective the day on which the unit is permanently retired. Within 30 days of permanent retirement, the NOX authorized account representative (authorized in accordance with subpart B of this part) shall submit a statement to the permitting authority otherwise responsible for administering any NOX Budget permit for the unit. A copy of the statement shall be submitted to the Administrator. The statement shall state (in a format prescribed by the permitting authority) that the unit is permanently retired and will comply with the requirements of paragraph (c) of this section. (3) After receipt of the notice under paragraph (b)(2) of this section, the permitting authority will amend any permit covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (b)(1) and (c) of this section. (c) Special provisions. (1) A unit exempt under this section shall not emit any nitrogen oxides, starting on the date that the exemption takes effect. The owners and operators of the unit will be allocated allowances in accordance with subpart E of this part. (2)(i) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the NOX authorized account representative of the source submits a complete NOX Budget permit application under Sec. 97.22 for the unit not less than 18 months (or such lesser time provided under the permitting authority for final action on a permit application) prior to the later of May 1, 2003 or the date on which the unit is to first resume operation.

(ii) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a non-title V permit shall not resume operation unless the NOX authorized account representative of the source submits a complete NOX Budget permit application under Sec. 97.22 for the unit not less than 18 months (or such lesser time provided under the permitting authority for final action on a permit application) prior to the later of May 1, 2003 or the date on which the unit is to first resume operation. (3) The owners and operators and, to the extent applicable, the NOX authorized account representative of a unit exempt under this section shall comply with the requirements of the NOX Budget Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) A unit that is exempt under this section is not eligible to be a NOX Budget opt-in source under subpart I of this part. (5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (6) Loss of exemption. (i) On the earlier of the following dates, a unit exempt under paragraph (b) of this section shall lose its exemption: (A) The date on which the NOX authorized account representative submits a NOX Budget permit application under paragraph (c)(2) of this section; or (B) The date on which the NOX authorized account representative is required under paragraph (c)(2) of this section to submit a NOX Budget permit application. (ii) For the purpose of applying monitoring requirements under subpart H of this part, a unit that loses its exemption under this section shall be treated as a unit that commences operation or commercial operation on the first date on which the unit resumes operation.

Sec. 97.6 Standard requirements.

(a) Permit requirements. (1) The NOX authorized account representative of each NOX Budget source required to have a federally enforceable permit and each NOX Budget unit required to have a federally enforceable permit at the source shall: (i) Submit to the permitting authority a complete NOX Budget permit application under Sec. 97.22 in accordance with the deadlines specified in Sec. 97.21(b) and (c); (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a NOX Budget permit application and issue or deny a NOX Budget permit. (2) The owners and operators of each NOX Budget source required to have a federally enforceable permit and each NOX Budget unit required to have a federally enforceable permit at the source shall have a NOX Budget permit issued by the permitting authority and operate the unit in compliance with such NOX Budget permit. (3) The owners and operators of a NOX Budget source that is not otherwise required to have a federally enforceable permit are not required to submit a NOX Budget permit application, and to have a NOX Budget permit, under subpart C of this part for such NOX Budget source. (b) Monitoring requirements. (1) The owners and operators and, to the extent applicable, the NOX authorized account representative of each NOX Budget source and each NOX Budget unit at the source shall comply with the monitoring requirements of subpart H of this part. (2) The emissions measurements recorded and reported in accordance with subpart H of this part shall be used to determine compliance by the unit with the NOX Budget emissions limitation under paragraph (c) of this section. (c) Nitrogen oxides requirements. (1) The owners and operators of each NOX Budget source and each NOX Budget unit at the source shall hold NOX allowances available for compliance deductions under Sec. 97.54, as of the NOX allowance transfer deadline, in the unit's compliance account and the source's overdraft account in an amount not less than the total NOX emissions for the control period from the unit, as determined in accordance with subpart H of this part, plus any amount necessary to account for actual utilization under Sec. 97.42(e) for the control period. (2) Each ton of nitrogen oxides emitted in excess of the NOX Budget emissions limitation shall constitute a separate violation of this part, the Clean Air Act, and applicable State law. (3) A NOX Budget unit shall be subject to the requirements under paragraph (c)(1) of this section starting on the later of May 1, 2003 or the date on which the unit commences operation. (4) NOX allowances shall be held in, deducted from, or transferred among NOX Allowance Tracking System accounts in accordance with subparts E, F, G, and I of this part. (5) A NOX allowance shall not be deducted, in order to comply with the requirements under paragraph (c)(1) of this section, for a control period in a year prior to the year for which the NOX allowance was allocated. (6) A NOX allowance allocated by the permitting authority or the Administrator under the NOX Budget Trading Program is a limited authorization to emit one ton of nitrogen oxides in accordance with the NOX Budget Trading Program. No provision of the NOX Budget Trading Program, the NOX Budget permit application, the NOX Budget permit, or an exemption under Sec. 97.5 and no provision of law shall be construed to limit the authority of the United States or the State to terminate or limit such authorization. (7) A NOX allowance allocated by the Administrator under the NOX Budget Trading Program does not constitute a property right. (8) Upon recordation by the Administrator under subpart F, G, or I of this part, every allocation, transfer, or deduction of a NOX allowance to or from a NOX Budget unit's compliance account or the overdraft account of the source where the unit is located is deemed to amend automatically, and become a part of, any NOX Budget permit of the NOX Budget unit by operation of law without any further review. (d) Excess emissions requirements. (1) The owners and operators of a NOX Budget unit that has excess emissions in any control period shall: (i) Surrender the NOX allowances required for deduction under Sec. 97.54(d)(1); and (ii) Pay any fine, penalty, or assessment or comply with any other remedy imposed under Sec. 97.54(d)(3). (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the NOX Budget source and each NOX Budget unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the permitting authority or the Administrator. (i) The account certificate of representation for the NOX authorized account representative for the source

and each NOX Budget unit at the source and all documents that demonstrate the truth of the statements in the account certificate of representation, in accordance with Sec. 97.13; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new account certificate of representation changing the NOX authorized account representative. (ii) All emissions monitoring information, in accordance with subpart H of this part; provided that to the extent that subpart H of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the NOX Budget Trading Program. (iv) Copies of all documents used to complete a NOX Budget permit application and any other submission under the NOX Budget Trading Program or to demonstrate compliance with the requirements of the NOX Budget Trading Program. (2) The NOX authorized account representative of a NOX Budget source and each NOX Budget unit at the source shall submit the reports and compliance certifications required under the NOX Budget Trading Program, including those under subparts D, H, or I of this part. (f) Liability. (1) Any person who knowingly violates any requirement or prohibition of the NOX Budget Trading Program, a NOX Budget permit, or an exemption under Sec. 97.5 shall be subject to enforcement pursuant to applicable State or Federal law. (2) Any person who knowingly makes a false material statement in any record, submission, or report under the NOX Budget Trading Program shall be subject to criminal enforcement pursuant to the applicable State or Federal law. (3) No permit revision shall excuse any violation of the requirements of the NOX Budget Trading Program that occurs prior to the date that the revision takes effect. (4) Each NOX Budget source and each NOX Budget unit shall meet the requirements of the NOX Budget Trading Program. (5) Any provision of the NOX Budget Trading Program that applies to a NOX Budget source (including a provision applicable to the NOX authorized account representative of a NOX Budget source) shall also apply to the owners and operators of such source and of the NOX Budget units at the source. (6) Any provision of the NOX Budget Trading Program that applies to a NOX Budget unit (including a provision applicable to the NOX authorized account representative of a NOX budget unit) shall also apply to the owners and operators of such unit. Except with regard to the requirements applicable to units with a common stack under subpart H of this part, the owners and operators and the NOX authorized account representative of one NOX Budget unit shall not be liable for any violation by any other NOX Budget unit of which they are not owners or operators or the NOX authorized account representative and that is located at a source of which they are not owners or operators or the NOX authorized account representative. (g) Effect on other authorities. No provision of the NOX Budget Trading Program, a NOX Budget permit application, a NOX Budget permit, or an exemption under Sec. 97.5 shall be construed as exempting or excluding the owners and operators and, to the extent applicable, the NOX authorized account representative of a NOX Budget source or NOX Budget unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

Sec. 97.7 Computation of time.

(a) Unless otherwise stated, any time period scheduled, under the NOX Budget Trading Program, to begin on the occurrence of an act or event shall begin on the day the act or event occurs. (b) Unless otherwise stated, any time period scheduled, under the NOX Budget Trading Program, to begin before the occurrence of an act or event shall be computed so that the period ends the day before the act or event occurs. (c) Unless otherwise stated, if the final day of any time period, under the NOX Budget Trading Program, falls on a weekend or a State or Federal holiday, the time period shall be extended to the next business day.

Subpart B--NOX Authorized Account Representative for NOX Budget Sources

Sec. 97.10 Authorization and responsibilities of the NOX authorized account representative.

(a) Except as provided under Sec. 97.11, each NOX Budget source, including all NOX Budget units at the source, shall have one and only one NOX authorized account representative, with regard to all matters under the NOX Budget Trading Program concerning the source or any NOX Budget unit at the source. (b) The NOX authorized account representative of the NOX Budget source shall be selected by an agreement binding on the owners and operators of the source and all NOX Budget units at the source. (c) Upon receipt by the Administrator of a complete account certificate of representation under Sec. 97.13, the NOX authorized account representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the NOX Budget source represented and each NOX Budget unit at the source in all matters pertaining to the NOX Budget Trading Program, not withstanding any agreement between the NOX authorized account representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the NOX authorized account representative by the permitting authority, the Administrator, or a court regarding the source or unit. (d) No NOX Budget permit shall be issued, and no NOX Allowance Tracking System account shall be established for a NOX Budget unit at a source, until the Administrator has received a complete account certificate of representation under Sec. 97.13 for a NOX authorized account representative of the source and the NOX Budget units at the source. (e)(1) Each submission under the NOX Budget Trading Program shall be submitted, signed, and certified by the NOX authorized account representative for each NOX Budget source on behalf of which the submission is made. Each such submission shall include the following certification statement by the NOX authorized account representative: ``I am authorized to make this submission on behalf of the owners and operators of the NOX Budget sources or NOX Budget units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.'' (2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a NOX Budget source or a

NOX Budget unit only if the submission has been made, signed, and certified in accordance with paragraph (e)(1) of this section.

Sec. 97.11 Alternate NOX authorized account representative.

(a) An account certificate of representation may designate one and only one alternate NOX authorized account representative who may act on behalf of the NOX authorized account representative. The agreement by which the alternate NOX authorized account representative is selected shall include a procedure for authorizing the alternate NOX authorized account representative to act in lieu of the NOX authorized account representative. (b) Upon receipt by the Administrator of a complete account certificate of representation under Sec. 97.13, any representation, action, inaction, or submission by the alternate NOX authorized account representative shall be deemed to be a representation, action, inaction, or submission by the NOX authorized account representative. (c) Except in this section and Secs. 97.10(a), 97.12, 97.13, and 97.51, whenever the term ``NOX authorized account representative'' is used in this part, the term shall be construed to include the alternate NOX authorized account representative.

Sec. 97.12 Changing the NOX authorized account representative and the alternate NOX authorized account representative; changes in the owners and operators.

(a) Changing the NOX authorized account representative. The NOX authorized account representative may be changed at any time upon receipt by the Administrator of a superseding complete account certificate of representation under Sec. 97.13. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous NOX authorized account representative prior to the time and date when the Administrator receives the superseding account certificate of representation shall be binding on the new NOX authorized account representative and the owners and operators of the NOX Budget source and the NOX Budget units at the source. (b) Changing the alternate NOX authorized account representative. The alternate NOX authorized account representative may be changed at any time upon receipt by the Administrator of a superseding complete account certificate of representation under Sec. 97.13. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate NOX authorized account representative prior to the time and date when the Administrator receives the superseding account certificate of representation shall be binding on the new alternate NOX authorized account representative and the owners and operators of the NOX Budget source and the NOX Budget units at the source. (c) Changes in the owners and operators. (1) In the event a new owner or operator of a NOX Budget source or a NOX Budget unit is not included in the list of owners and operators submitted in the account certificate of representation, such new owner or operator shall be deemed to be subject to and bound by the account certificate of representation, the representations, actions, inactions, and submissions of the NOX authorized account representative and any alternate NOX authorized account representative of the source or unit, and the decisions, orders, actions, and inactions of the permitting authority or the Administrator, as if the new owner or operator were included in such list. (2) Within 30 days following any change in the owners and operators of a NOX Budget source or a NOX Budget unit, including the addition of a new owner or operator, the NOX authorized account representative or alternate NOX authorized account representative shall submit a revision to the account certificate of representation amending the list of owners and operators to include the change.

Sec. 97.13 Account certificate of representation.

(a) A complete account certificate of representation for a NOX authorized account representative or an alternate NOX authorized account representative shall include the following elements in a format prescribed by the Administrator: (1) Identification of the NOX Budget source and each NOX Budget unit at the source for which the account certificate of representation is submitted. (2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the NOX authorized account representative and any alternate NOX authorized account representative. (3) A list of the owners and operators of the NOX Budget source and of each NOX Budget unit at the source. (4) The following certification statement by the NOX authorized account representative and any alternate NOX authorized account representative: ``I certify that I was selected as the NOX authorized account representative or alternate NOX authorized account representative, as applicable, by an agreement binding on the owners and operators of the NOX Budget source and each NOX Budget unit at the source. I certify that I have all the necessary authority to carry out my duties and responsibilities under the NOX Budget Trading Program on behalf of the owners and operators of the NOX Budget source and of each NOX Budget unit at the source and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions and by any decision or order issued to me by the permitting authority, the Administrator, or a court regarding the source or unit.'' (5) The signature of the NOX authorized account representative and any alternate NOX authorized account representative and the dates signed. (b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the account certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

Sec. 97.14 Objections concerning the NOX authorized account representative.

(a) Once a complete account certificate of representation under Sec. 97.13 has been submitted and received, the permitting authority and the Administrator will rely on the account certificate of representation unless and until a superseding complete account certificate of representation under Sec. 97.13 is received by the Administrator. (b) Except as provided in Sec. 97.12(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission of the NOX authorized account representative shall affect any representation, action, inaction, or submission of the NOX authorized account representative or the finality of any decision or order by the permitting authority or the Administrator under the NOX Budget Trading Program. (c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any NOX authorized account representative, including private legal disputes

concerning the proceeds of NOX allowance transfers.

Subpart C--Permits

Sec. 97.20 General NOX budget trading program permit requirements.

(a) For each NOX Budget source required to have a federally enforceable permit, such permit shall include a NOX Budget permit administered by the permitting authority. (1) For NOX Budget sources required to have a title V operating permit, the NOX Budget portion of the title V permit shall be administered in accordance with the permitting authority's title V operating permits regulations promulgated under part 70 or 71 of this chapter, except as provided otherwise by this subpart or subpart I of this part. The applicable provisions of such title V operating permits regulations shall include, but are not limited to, those provisions addressing operating permit applications, operating permit application shield, operating permit duration, operating permit shield, operating permit issuance, operating permit revision and reopening, public participation, State review, and review by the Administrator. (2) For NOX Budget sources required to have a non-title V permit, the NOX Budget portion of the non-title V permit shall be administered in accordance with the permitting authority's regulations promulgated to administer non-title V permits, except as provided otherwise by this subpart or subpart I of this part. The applicable provisions of such non-title V permits regulations may include, but are not limited to, provisions addressing permit applications, permit application shield, permit duration, permit shield, permit issuance, permit revision and reopening, public participation, State review, and review by the Administrator. (b) Each NOX Budget permit (including a draft or proposed NOX Budget permit, if applicable) shall contain all applicable NOX Budget Trading Program requirements and shall be a complete and segregable portion of the permit under paragraph (a) of this section.

Sec. 97.21 NOX Budget permit applications.

(a) Duty to apply. The NOX authorized account representative of any NOX Budget source required to have a federally enforceable permit shall submit to the permitting authority a complete NOX Budget permit application under Sec. 97.22 by the applicable deadline in paragraph (b) of this section. (b)(1) For NOX Budget sources required to have a title V operating permit: (i) For any source, with one or more NOX Budget units under Sec. 97.4 that commence operation before January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 covering such NOX Budget units to the permitting authority at least 18 months (or such lesser time provided under the permitting authority's title V operating permits regulations for final action on a permit application) before May 1, 2003. (ii) For any source, with any NOX Budget unit under Sec. 97.4 that commences operation on or after January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 covering such NOX Budget unit to the permitting authority at least 18 months (or such lesser time provided under the permitting authority's title V operating permits regulations for final action on a permit application) before the later of May 1, 2003 or the date on which the NOX Budget unit commences operation. (2) For NOX Budget sources required to have a non-title V permit: (i) For any source, with one or more NOX Budget units under Sec. 97.4 that commence operation before January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 covering such NOX Budget units to the permitting authority at least 18 months (or such lesser time provided under the permitting authority's non-title V permits regulations for final action on a permit application) before May 1, 2003. (ii) For any source, with any NOX Budget unit under Sec. 97.4 that commences operation on or after January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 covering such NOX Budget unit to the permitting authority at least 18 months (or such lesser time provided under the permitting authority's non-title V permits regulations for final action on a permit application) before the later of May 1, 2003 or the date on which the NOX Budget unit commences operation. (c) Duty to Reapply. (1) For a NOX Budget source required to have a title V operating permit, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 for the NOX Budget source covering the NOX Budget units at the source in accordance with the permitting authority's title V operating permits regulations addressing operating permit renewal. (2) For a NOX Budget source required to have a non-title V permit, the NOX authorized account representative shall submit a complete NOX Budget permit application under Sec. 97.22 for the NOX Budget source covering the NOX Budget units at the source in accordance with the permitting authority's non-title V permits regulations addressing permit renewal.

Sec. 97.22 Information requirements for NOX Budget permit applications.

A complete NOX Budget permit application shall include the following elements concerning the NOX Budget source for which the application is submitted, in a format prescribed by the permitting authority: (a) Identification of the NOX Budget source, including plant name and the ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration, if applicable; (b) Identification of each NOX Budget unit at the NOX Budget source and whether it is a NOX Budget unit under Sec. 97.4 or under subpart I of this part; (c) The standard requirements under Sec. 97.6; and (d) For each NOX Budget opt-in unit at the NOX Budget source, the following certification statements by the NOX authorized account representative: (1) ``I certify that each unit for which this permit application is submitted under subpart I of this part is not a NOX Budget unit under 40 CFR 97.4 and is not covered by a retired unit exemption under 40 CFR 97.5 that is in effect.'' (2) If the application is for an initial NOX Budget opt- in permit, ``I certify that each unit for which this permit application is submitted under subpart I is currently operating, as that term is defined under 40 CFR 97.2.''

Sec. 97.23 NOX Budget permit contents.

(a) Each NOX Budget permit (including any draft or proposed NOX Budget permit, if applicable) will contain, in a format prescribed by the permitting authority, all elements required for a complete NOX Budget permit application under Sec. 97.22 as approved or adjusted by the permitting authority. (b) Each NOX Budget permit is deemed to incorporate automatically the definitions of terms under Sec. 97.2 and, upon recordation by the Administrator under subparts F, G, or I of this part, every allocation, transfer, or deduction of a NOX allowance to or from the compliance accounts of the NOX Budget

units covered by the permit or the overdraft account of the NOX Budget source covered by the permit.

Sec. 97.24 Effective date of initial NOX Budget permit.

The initial NOX Budget permit covering a NOX Budget unit for which a complete NOX Budget permit application is timely submitted under Sec. 97.21(b) shall become effective by the later of: (a) May 1, 2003; (b) May 1 of the year in which the NOX Budget unit commences operation, if the unit commences operation on or before May 1 of that year; (c) The date on which the NOX Budget unit commences operation, if the unit commences operation during a control period; or (d) May 1 of the year following the year in which the NOX Budget unit commences operation, if the unit commences operation on or after October 1 of the year.

Sec. 97.25 NOX Budget permit revisions.

(a) For a NOX Budget source with a title V operating permit, except as provided in Sec. 97.23(b), the permitting authority will revise the NOX Budget permit, as necessary, in accordance with the permitting authority's title V operating permits regulations addressing permit revisions. (b) For a NOX Budget source with a non-title V permit, except as provided in Sec. 97.23(b), the permitting authority will revise the NOX Budget permit, as necessary, in accordance with the permitting authority's non-title V permits regulations addressing permit revisions.

Subpart D--Compliance Certification

Sec. 97.30 Compliance certification report.

(a) Applicability and deadline. For each control period in which one or more NOX Budget units at a source are subject to the NOX Budget emissions limitation, the NOX authorized account representative of the source shall submit to the permitting authority and the Administrator by November 30 of that year, a compliance certification report for each source covering all such units. (b) Contents of report. The NOX authorized account representative shall include in the compliance certification report under paragraph (a) of this section the following elements, in a format prescribed by the Administrator, concerning each unit at the source and subject to the NOX Budget emissions limitation for the control period covered by the report: (1) Identification of each NOX Budget unit; (2) At the NOX authorized account representative's option, the serial numbers of the NOX allowances that are to be deducted from each unit's compliance account under Sec. 97.54 for the control period; (3) At the NOX authorized account representative's option, for units sharing a common stack and having NOX emissions that are not monitored separately or apportioned in accordance with subpart H of this part, the percentage of allowances that is to be deducted from each unit's compliance account under Sec. 97.54(e); and (4) The compliance certification under paragraph (c) of this section. (c) Compliance certification. In the compliance certification report under paragraph (a) of this section, the NOX authorized account representative shall certify, based on reasonable inquiry of those persons with primary responsibility for operating the source and the NOX Budget units at the source in compliance with the NOX Budget Trading Program, whether each NOX Budget unit for which the compliance certification is submitted was operated during the calendar year covered by the report in compliance with the requirements of the NOX Budget Trading Program applicable to the unit, including: (1) Whether the unit was operated in compliance with the NOX Budget emissions limitation; (2) Whether the monitoring plan that governs the unit has been maintained to reflect the actual operation and monitoring of the unit, and contains all information necessary to attribute NOX emissions to the unit, in accordance with subpart H of this part; (3) Whether all the NOX emissions from the unit, or a group of units (including the unit) using a common stack, were monitored or accounted for through the missing data procedures and reported in the quarterly monitoring reports, including whether conditional data were reported in the quarterly reports in accordance with subpart H of this part. If conditional data were reported, the owner or operator shall indicate whether the status of all conditional data has been resolved and all necessary quarterly report resubmissions has been made; (4) Whether the facts that form the basis for certification under subpart H of this part of each monitor at the unit or a group of units (including the unit) using a common stack, or for using an excepted monitoring method or alternative monitoring method approved under subpart H of this part, if any, has changed; and (5) If a change is required to be reported under paragraph (c)(4) of this section, specify the nature of the change, the reason for the change, when the change occurred, and how the unit's compliance status was determined subsequent to the change, including what method was used to determine emissions when a change mandated the need for monitor recertification.

Sec. 97.31 Administrator's action on compliance certifications.

(a) The Administrator may review and conduct independent audits concerning any compliance certification or any other submission under the NOX Budget Trading Program and make appropriate adjustments of the information in the compliance certifications or other submissions. (b) The Administrator may deduct NOX allowances from or transfer NOX allowances to a unit's compliance account or a source's overdraft account based on the information in the compliance certifications or other submissions, as adjusted under paragraph (a) of this section.

Subpart E--NOX Allowance Allocations

Sec. 97.40 Trading program budget.

The trading program budget allocated by the Administrator for a State under Sec. 97.42 for a control period will equal the sum of the aggregate emission levels for large electric generating units in the State and large non-electric generating units in the State as defined under Appendix C of this part.

Sec. 97.41 Timing requirements for NOX allowance allocations.

(a) By the following dates, the Administrator will determine the NOX allowance allocations in accordance with Sec. 97.42 for the control period in the year that is three years after the year of the applicable deadline under this paragraph (a): (i) For the purposes of the NOX Budget Trading Program under section 110(c) of the Act, by April 1, 2000 and April 1 of the following two years (ii) For the purposes of the NOX Budget Trading Program under 126 of the Act, by April 1, 2000 and April 1 of the following two years for those sources for which a finding, under Sec. 52.34(j) of this chapter, of NOX emissions in violation of section 110(a)(2)(D)(I)(I) of the Act is made by April 1, 2000; or as soon as practicable in the year 2000 and April 1 of the following two years for those sources for which such a finding is not made by April 1, 2000, but is made at a later date. (b) By April 1, 2003 and April 1 of each year thereafter, the Administrator

will determine the NOX allowance allocations, in accordance with Sec. 97.42, for the control period in the year that is three years after the year of the applicable deadline under this paragraph (b). (c) By April 1, 2004 and April 1 of each year thereafter, the Administrator will determine the NOX allowance allocations, in accordance with Sec. 97.42, for any NOX allowances remaining in the allocation set-aside for the prior control period.

Sec. 97.42 NOX allowance allocations.

(a)(1) The heat input (in mmBtu) used for calculating NOX allowance allocations for each NOX Budget unit under Sec. 97.4 will be: (i) For a NOX allowance allocation under Sec. 97.41(a), the average of the two highest amounts of the unit's heat input for the control periods in 1995, 1996, and 1997 if the unit is under Sec. 97.4(a)(1) or the control period in 1995 if the unit is under Sec. 97.4(a)(2); and (ii) For a NOX allowance allocation under Sec. 97.41(b), the unit's heat input for the control period in the year that is four years before the year for which the NOX allocation is being calculated. (2) The unit's total heat input for the control period in each year specified under paragraph (a)(1) of this section will be determined in accordance with part 75 of this chapter if the NOX Budget unit was otherwise subject to the requirements of part 75 of this chapter for the year, or will be based on the best available data reported to the Administrator for the unit if the unit was not otherwise subject to the requirements of part 75 of this chapter for the year. (b) For each control period under Sec. 97.41, the Administrator will allocate to all NOX Budget units under Sec. 97.4(a)(1) in the State that commenced operation before May 1 of the period used to calculate heat input under paragraph (a)(1) of this section, a total number of NOX allowances equal to 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission levels for large electric generating units in the State as defined under appendix C of this part in accordance with the following procedures: (1) The Administrator will allocate NOX allowances to each NOX Budget unit under Sec. 97.4(a)(1) in an amount equaling 0.15 lb/mmBtu multiplied by the heat input determined under paragraph (a) of this section, rounded to the nearest whole NOX allowance as appropriate. (2) If the initial total number of NOX allowances allocated to all NOX Budget units under Sec. 97.4(a)(1) in the State for a control period under paragraph (b)(1) of this section does not equal 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission level for large electric generating units in the State as defined under Appendix C of this part, the Administrator will adjust the total number of NOX allowances allocated to all such NOX Budget units for the control period under paragraph (b)(1) of this section so that the total number of NOX allowances allocated equals 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of such aggregate emission level. This adjustment will be made by: multiplying each unit's allocation by 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission level for large electric generating units in the State as defined under Appendix C of this part divided by the total number of NOX allowances allocated under paragraph (b)(1) of this section, and rounding to the nearest whole NOX allowance as appropriate. (c) For each control period under Sec. 97.41, the Administrator will allocate to all NOX Budget units under Sec. 97.4(a)(2) in the State that commenced operation before May 1 of the period used to calculate heat input under paragraph (a)(1) of this section, a total number of NOX allowances equal to 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission level for large non-electric generating units in the State as defined under Appendix C of this part in accordance with the following procedures: (1) The Administrator will allocate NOX allowances to each NOX Budget unit under Sec. 97.4(a)(2) in an amount equaling 0.17 lb/mmBtu multiplied by the heat input determined under paragraph (a) of this section, rounded to the nearest whole NOX allowance as appropriate. (2) If the initial total number of NOX allowances allocated to all NOX Budget units under Sec. 97.4(a)(2) in the State for a control period under paragraph (c)(1) of this section does not equal 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission levels for large non-electric generating units in the State as defined under appendix C of this part, the Administrator will adjust the total number of NOX allowances allocated to all such NOX Budget units for the control period under paragraph (a)(1) of this section so that the total number of NOX allowances allocated equals 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of such aggregate emission level for large non-electric generating units in the State. This adjustment will be made by: multiplying each unit's allocation by 95 percent in 2003, 2004, and 2005, or 98 percent thereafter, of the aggregate emission levels for large non-electric generating units in the State as defined under Appendix C of this part divided by the total number of NOX allowances allocated under paragraph (c)(1) of this section, and rounding to the nearest whole NOX allowance as appropriate. (d) For each control period under Sec. 97.41, the Administrator will allocate NOX allowances to NOX Budget units under Sec. 97.4 in the State that commenced operation, or are projected to commerce operation, on or after May 1 of the period used to calculate heat input under paragraph (a)(1) of this section, in accordance with the following procedures: (1) The Administrator will establish one allocation set-aside for each control period. Each allocation set-aside will be allocated NOX allowances equal to 5 percent in 2003, 2004, and 2005, or 2 percent thereafter, of the tons of NOX emissions in the trading program budget in the State under Sec. 97.40, rounded to the nearest whole NOX allowance as appropriate. (2) The NOX authorized account representative of a NOX Budget unit under paragraph (d) of this section may submit to the Administrator a request, in writing or in a format specified by the Administrator, to be allocated NOX allowances for no more than five consecutive control periods under Sec. 97.41, starting with the control period during which the NOX Budget unit commenced, or is projected to commence, operation and ending with the control season preceding the control period for which it will receive an allocation under paragraph (b) or (c) of this section. The NOX allowance allocation request must be submitted prior to May 1 of the first control period for which the NOX allowance allocation is requested and after the date on which the State permitting authority issues a permit to construct the NOX Budget unit. (3) In a NOX allowance allocation request under paragraph (d)(2) of this section, the NOX authorized account representative for units under Sec. 97.4(a)(1) may request for a control period NOX allowances in an amount that does not exceed 0.15 lb/mmBtu multiplied by the NOX Budget unit's maximum design heat input (in mmBtu/hr) multiplied by the number of hours remaining in the control period starting with the first day in the control period on which the unit operated or is projected to operate.

(4) In a NOX allowance allocation request under paragraph (d)(2) of this section, the NOX authorized account representative for units under Sec. 97.4(a)(2) may request for a control period NOX allowances in an amount that does not exceed 0.17 lb/mmBtu multiplied by the NOX Budget unit's maximum design heat input (in mmBtu/hr) multiplied by the number of hours remaining in the control period starting with the first day in the control period on which the unit operated or is projected to operate. (5) The Administrator will review, and allocate NOX allowances pursuant to, each NOX allowance allocation request under paragraph (d)(2) of this section in the order that the request is received by the Administrator. (i) Upon receipt of the NOX allowance allocation request, the Administrator will determine whether, and will make any necessary adjustments to the request to ensure that, for units under Sec. 97.4(a)(1), the control period and the number of allowances specified are consistent with the requirements of paragraphs (d)(2) and (3) of this section and, for units under Sec. 97.4(a)(2), the control period and the number of allowances specified are consistent with the requirements of paragraphs(d)(2) and (4) of this section. (ii) If the allocation set-aside for the control period for which NOX allowances are requested has an amount of NOX allowances not less than the number requested (as adjusted under paragraph (d)(5)(i) of this section), the permitting authority or the Administrator will allocate the amount of the NOX allowances requested (as adjusted under paragraph (d)(5)(i) of this section) to the NOX Budget unit. (iii) If the allocation set-aside for the control period for which NOX allowances are requested has a smaller amount of NOX allowances than the number requested (as adjusted under paragraph (d)(4)(i) of this section), the Administrator will deny in part the request and allocate only the remaining number of NOX allowances in the allocation set-aside to the NOX Budget unit. (iv) Once an allocation set-aside for a control period has been depleted of all NOX allowances, the Administrator will deny, and will not allocate any NOX allowances pursuant to, any NOX allowance allocation request under which NOX allowances have not already been allocated for the control period. (6) Within 60 days of receipt of a NOX allowance allocation request, the Administrator will take appropriate action under paragraph (d)(5) of this section and notify the NOX authorized account representative that submitted the request of the number of NOX allowances (if any) allocated for the control period to the NOX Budget unit. (e) For a NOX Budget unit that is allocated NOX allowances under paragraph (d) of this section for a control period, the Administrator will deduct NOX allowances under Sec. 97.54(b) or (e) to account for the actual utilization of the unit during the control period. The Administrator will calculate the number of NOX allowances to be deducted to account for the unit's actual utilization using the following formulas and rounding to the nearest whole NOX allowance as appropriate, provided that the number of NOX allowances to be deducted shall be zero if the number calculated is less than zero:

NOX allowances deducted for actual utilization for units under Sec. 97.4(a)(1) = (Unit's NOX allowances allocated for control period)-(Unit's actual control period utilization x 0.15 lb/mmBtu); and NOX allowances deducted for actual utilization for units under Sec. 97.4(a)(2)= (Unit's NOX allowances allocated for control period)-(Unit's actual control period utilization x 0.17 lb/mmBtu), Where:

``Unit's NOX allowances allocated for control period'' is the number of NOX allowances allocated to the unit for the control period under paragraph (d) of this section; and, ``Unit's actual control period utilization'' is the utilization (in mmBtu), as defined in Sec. 97.2, of the unit during the control period.

(f) After making the deductions for compliance under Sec. 97.54(b) or (e) for a control period, the Administrator will determine whether any NOX allowances remain in the allocation set-aside for the control period. The Administrator will allocate any such NOX allowances to the NOX Budget units in the State using the following formula and rounding to the nearest whole NOX allowance as appropriate:

Unit's share of NOX allowances remaining in allocation set-aside = Total NOX allowances remaining in allocation set-aside x (Unit's NOX allowance allocation (trading program budget excluding allocation set-aside) Where: Total NOX allowances remaining in allocation set-aside'' is the total number of NOX allowances remaining in the allocation set-aside for the control period to which the allocation set-aside applies; ``Unit's NOX allowance allocation'' is the number of NOX allowances allocated under paragraph (b) or (c) of this section to the unit for the control period to which the allocation set-aside applies; and ``Trading program budget excluding allocation set-aside'' is the trading program budget under Sec. 97.40 for the control period to which the allocation set-aside applies multiplied by 95 percent if the control period is in 2003, 2004, or 2005 or 98 percent if the control period is in any year thereafter, rounded to the nearest whole allowance as appropriate.

Subpart F--NOX Allowance Tracking System

Sec. 97.50 NOX Allowance Tracking System accounts.

(a) Nature and function of compliance accounts and overdraft accounts. Consistent with Sec. 97.51(a), the Administrator will establish one compliance account for each NOX Budget unit and one overdraft account for each source with one or more NOX Budget units. Allocations of NOX allowances pursuant to subpart E of this part or Sec. 97.88, and deductions or transfers of NOX allowances pursuant to Sec. 97.31, Sec. 96.54, Sec. 96.56, subpart G of this part, or subpart I of this part will be recorded in the compliance accounts or overdraft accounts in accordance with this subpart. (b) Nature and function of general accounts. Consistent with Sec. 97.51(b), the Administrator will establish, upon request, a general account for any person. Transfers of allowances pursuant to subpart G of this part will be recorded in the general account in accordance with this subpart.

Sec. 97.51 Establishment of accounts.

(a) Compliance accounts and overdraft accounts. Upon receipt of a complete account certificate of representation under Sec. 97.13, the Administrator will establish: (1) A compliance account for each NOX Budget unit for which the account certificate of representation was submitted; and (2) An overdraft account for each source for which the account certificate of representation was submitted and that has two or more NOX Budget units. (b) General accounts. (1) Any person may apply to open a general account for the purpose of holding and transferring allowances. A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator: (i) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the NOX authorized account representative and any alternate NOX authorized account representative;

(ii) At the option of the NOX authorized account representative, organization name and type of organization; (iii) A list of all persons subject to a binding agreement for the NOX authorized account representative and any alternate NOX authorized account representative to represent their ownership interest with respect to the allowances held in the general account; (iv) The following certification statement by the NOX authorized account representative and any alternate NOX authorized account representative: ``I certify that I was selected as the NOX authorized account representative or the NOX alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to allowances held in the general account. I certify that I have all the necessary authority to carry out my duties and responsibilities under the NOX Budget Trading Program on behalf of such persons and that each such person shall be fully bound by my representations, actions, inactions, or submissions and by any order or decision issued to me by the Administrator or a court regarding the general account.'' (v) The signature of the NOX authorized account representative and any alternate NOX authorized account representative and the dates signed. (vi) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the account certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted. (2) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section: (i) The Administrator will establish a general account for the person or persons for whom the application is submitted. (ii) The NOX authorized account representative and any alternate NOX authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to NOX allowances held in the general account in all matters pertaining to the NOX Budget Trading Program, not withstanding any agreement between the NOX authorized account representative or any alternate NOX authorized account representative and such person. Any such person shall be bound by any order or decision issued to the NOX authorized account representative or any alternate NOX authorized account representative by the Administrator or a court regarding the general account. (iii) Each submission concerning the general account shall be submitted, signed, and certified by the NOX authorized account representative or any alternate NOX authorized account representative for the persons having an ownership interest with respect to NOX allowances held in the general account. Each such submission shall include the following certification statement by the NOX authorized account representative or any alternate NOX authorizing account representative: ``I am authorized to make this submission on behalf of the persons having an ownership interest with respect to the NOX allowances held in the general account. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.'' (iv) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(iii) of this section. (3)(i) An application for a general account may designate one and only one NOX authorized account representative and one and only one alternate NOX authorized account representative who may act on behalf of the NOX authorized account representative. The agreement by which the alternate NOX authorized account representative is selected shall include a procedure for authorizing the alternate NOX authorized account representative to act in lieu of the NOX authorized account representative. (ii) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section, any representation, action, inaction, or submission by any alternate NOX authorized account representative shall be deemed to be a representation, action, inaction, or submission by the NOX authorized account representative. (4)(i) The NOX authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous NOX authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new NOX authorized account representative and the persons with an ownership interest with respect to the allowances in the general account. (ii) The alternate NOX authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate NOX authorized account representative prior to the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate NOX authorized account representative and the persons with an ownership interest with respect to the allowances in the general account. (iii)(A) In the event a new person having an ownership interest with respect to NOX allowances in the general account is not included in the list of such persons in the account certificate of representation, such new person shall be deemed to be subject to and bound by the account certificate of representation, the representation, actions, inactions, and submissions of the NOX authorized account representative and any alternate NOX authorized account representative of the source or unit, and the decisions, orders, actions, and inactions of the Administrator, as if the new person were included in such list. (B) Within 30 days following any change in the persons having an ownership interest with respect to NOX allowances in the general account, including the addition of persons, the NOX authorized account representative or any alternate NOX authorized account representative shall submit a revision to the application for a general account amending the list of persons having an ownership interest with respect to the NOX allowances in the general account to include the change. (5)(i) Once a complete application for a general account under paragraph (b)(1)

of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator. (ii) Except as provided in paragraph (b)(4) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the NOX authorized account representative or any alternative NOX authorized account representative for a general account shall affect any representation, action, inaction, or submission of the NOX authorized account representative or any alternative NOX authorized account representative or the finality of any decision or order by the Administrator under the NOX Budget Trading Program. (iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the NOX authorized account representative or any alternative NOX authorized account representative for a general account, including private legal disputes concerning the proceeds of NOX allowance transfers. (c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.

Sec. 97.52 NOX Allowance Tracking System responsibilities of NOX authorized account representative.

(a) Following the establishment of a NOX Allowance Tracking System account, all submissions to the Administrator pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of NOX allowances in the account, shall be made only by the NOX authorized account representative for the account. (b) Authorized account representative identification. The Administrator will assign a unique identifying number to each NOX authorized account representative.

Sec. 97.53 Recordation of NOX allowance allocations.

(a) The Administrator will record the NOX allowances for 2003 in the NOX Budget units' compliance accounts and the allocation set-asides, as allocated under subpart E of this part. The Administrator will also record the NOX allowances allocated under Sec. 97.88(a)(1) for each NOX Budget opt-in source in its compliance account. (b) Each year, after the Administrator has made all deductions from a NOX Budget unit's compliance account and the overdraft account pursuant to Sec. 97.54, the Administrator will record NOX allowances, as allocated to the unit under subpart E of this part or under Sec. 97.88(a)(2), in the compliance account for the year after the last year for which allowances were previously allocated to the compliance account. Each year, the Administrator will also record NOX allowances, as allocated under subpart E of this part, in the allocation set-aside for the year after the last year for which allowances were previously allocated to an allocation set-aside. (c) Serial numbers for allocated NOX allowances. When allocating NOX allowances to and recording them in an account, the Administrator will assign each NOX allowance a unique identification number that will include digits identifying the year for which the NOX allowance is allocated.

Sec. 97.54 Compliance.

(a) NOX allowance transfer deadline. The NOX allowances are available to be deducted for compliance with a unit's NOX Budget emissions limitation for a control period in a given year only if the NOX allowances: (1) Were allocated for a control period in a prior year or the same year; and (2) Are held in the unit's compliance account, or the overdraft account of the source where the unit is located, as of the NOX allowance transfer deadline for that control period or are transferred into the compliance account or overdraft account by a NOX allowance transfer correctly submitted for recordation under Sec. 97.60 by the NOX allowance transfer deadline for that control period. (b) Deductions for compliance. (1) Following the recordation, in accordance with Sec. 97.61, of NOX allowance transfers submitted for recordation in the unit's compliance account or the overdraft account of the source where the unit is located by the NOX allowance transfer deadline for a control period, the Administrator will deduct NOX allowances available under paragraph (a) of this section to cover the unit's NOX emissions (as determined in accordance with subpart H of this part), or to account for actual utilization under Sec. 97.42 (e), for the control period: (i) From the compliance account; and (ii) Only if no more NOX allowances available under paragraph (a) of this section remain in the compliance account, from the overdraft account. In deducting allowances for units at the source from the overdraft account, the Administrator will begin with the unit having the compliance account with the lowest NOX Allowance Tracking System account number and end with the unit having the compliance account with the highest NOX Allowance Tracking System account number (with account numbers sorted beginning with the left-most character and ending with the right-most character and the letter characters assigned values in alphabetical order and less than all numeric characters). (2) The Administrator will deduct NOX allowances first under paragraph (b)(1)(i) of this section and then under paragraph (b)(1)(ii) of this section: (i) Until the number of NOX allowances deducted for the control period equals the number of tons of NOX emissions, determined in accordance with subpart H of this part, from the unit for the control period for which compliance is being determined, plus the number of NOX allowances required for deduction to account for actual utilization under Sec. 97.42(e) for the control period; or (ii) Until no more NOX allowances available under paragraph (a) of this section remain in the respective account. (c)(1) Identification of NOX allowances by serial number. The NOX authorized account representative for each compliance account may identify by serial number the NOX allowances to be deducted from the unit's compliance account under paragraph (b), (d), or (e) of this section. Such identification shall be made in the compliance certification report submitted in accordance with Sec. 97.30. (2) First-in, first-out. The Administrator will deduct NOX allowances for a control period from the compliance account, in the absence of an identification or in the case of a partial identification of NOX allowances by serial number under paragraph (c)(1) of this section, or the overdraft account on a first-in, first-out (FIFO) accounting basis in the following order: (i) Those NOX allowances that were allocated for the control period to the unit under subpart E or I of this part; (ii) Those NOX allowances that were allocated for the control period to any unit and transferred and recorded in the account pursuant to subpart G of this part, in order of their date of recordation; (iii) Those NOX allowances that were allocated for a prior control period to the unit under subpart E or I of this part; and (iv) Those NOX allowances that were allocated for a prior control period to

any unit and transferred and recorded in the account pursuant to subpart G of this part, in order of their date of recordation. (d) Deductions for excess emissions. (1) After making the deductions for compliance under paragraph (b) of this section, the Administrator will deduct from the unit's compliance account or the overdraft account of the source where the unit is located a number of NOX allowances, allocated for a control period after the control period in which the unit has excess emissions, equal to three times the number of the unit's excess emissions. (2) If the compliance account or overdraft account does not contain sufficient NOX allowances, the Administrator will deduct the required number of NOX allowances, regardless of the control period for which they were allocated, whenever NOX allowances are recorded in either account. (3) Any allowance deduction required under paragraph (d) of this section shall not affect the liability of the owners and operators of the NOX Budget unit for any fine, penalty, or assessment, or their obligation to comply with any other remedy, for the same violation, as ordered under the Clean Air Act or applicable State law. The following guidelines will be followed in assessing fines, penalties or other obligations: (i) For purposes of determining the number of days of violation, if a NOX Budget unit has excess emissions for a control period, each day in the control period (153 days) constitutes a day in violation unless the owners and operators of the unit demonstrate that a lesser number of days should be considered. (ii) Each ton of excess emissions is a separate violation. (e) Deductions for units sharing a common stack. In the case of units sharing a common stack and having emissions that are not separately monitored or apportioned in accordance with subpart H of this part: (1) The NOX authorized account representative of the units may identify the percentage of NOX allowances to be deducted from each such unit's compliance account to cover the unit's share of NOX emissions from the common stack for a control period. Such identification shall be made in the compliance certification report submitted in accordance with Sec. 97.30. (2) Notwithstanding paragraph (b)(2)(i) of this section, the Administrator will deduct NOX allowances for each such unit until the number of NOX allowances deducted equals the units identified percentage (under paragraph (e)(1) of this section) of the number of tons of NOX emissions, as determined in accordance with subpart H of this part, from the common stack for the control period for which compliance is being determined, use the number of allowances required to account for actual utilization under Sec. 97.42(e) for the control period or, if no percentage is identified, an equal percentage for each such unit. (f) The Administrator will record in the appropriate compliance account or overdraft account all deductions from such an account pursuant to paragraphs (b), (d), or (e) of this section.

Sec. 97.55 Banking.

(a) NOX allowances may be banked for future use or transfer in a compliance account, an overdraft account, or a general account, as follows: (1) Any NOX allowance that is held in a compliance account, an overdraft account, or a general account will remain in such account unless and until the NOX allowance is deducted or transferred under Sec. 97.31, Sec. 97.54, or Sec. 97.56, subpart G of this part, or subpart I of this part. (2) The Administrator will designate, as a ``banked'' NOX allowance, any NOX allowance that remains in a compliance account, an overdraft account, or a general account after the Administrator has made all deductions for a given control period from the compliance account or overdraft account pursuant to Sec. 97.54. (b) Each year starting in 2004, after the Administrator has completed the designation of banked NOX allowances under paragraph (a)(2) of this section and before May 1 of the year, the Administrator will determine the extent to which banked NOX allowances may be used for compliance in the control period for the current year, as follows: (1) The Administrator will determine the total number of banked NOX allowances held in compliance accounts, overdraft accounts, or general accounts. (2) If the total number of banked NOX allowances determined, under paragraph (b)(1) of this section, to be held in compliance accounts, overdraft accounts, or general accounts is less than or equal to 10% of the sum of the State trading program budgets for the control period for the States in which NOX Budget units are located, any banked NOX allowance may be deducted for compliance in accordance with Sec. 97.54. (3) If the total number of banked NOX allowances determined, under paragraph (b)(1) of this section, to be held in compliance accounts, overdraft accounts, or general accounts exceeds 10% of the sum of the State trading program budgets for the control period for the States in which NOX Budget units are located, any banked allowance may be deducted for compliance in accordance with Sec. 97.54, except as follows: (i) The Administrator will determine the following ratio: 0.10 multiplied by the sum of the State trading program budgets for the control period for the States in which NOX Budget units are located and divided by the total number of banked NOX allowances determined, under paragraph (b)(1) of this section, to be held in compliance accounts, overdraft accounts, or general accounts. (ii) The Administrator will multiply the number of banked NOX allowances in each compliance account or overdraft account. The resulting product is the number of banked NOX allowances in the account that may be deducted for compliance in accordance with Sec. 97.54. Any banked NOX allowances in excess of the resulting product may be deducted for compliance in accordance with Sec. 97.54, except that, if such NOX allowances are used to make a deduction, two such NOX allowances must be deducted for each deduction of one NOX allowance required under Sec. 97.54. (c) Any NOX Budget unit may reduce its NOX emission rate in the 2001 or 2002 control period, the owner or operator of the unit may request early reduction credits, and the permitting authority may allocate NOX allowances in 2003 to the unit in accordance with the following requirements. (1) Each NOX Budget unit for which the owner or operator requests any early reduction credits under paragraph (c)(4) of this section shall monitor NOX emissions in accordance with subpart H of this part starting in the 2000 control period and for each control period for which such early reduction credits are requested. The unit's monitoring system availability shall be not less than 90 percent during the 2000 control period, and the unit must be in full compliance with any applicable State or Federal emissions or emissions related requirements. (2) NOX emission rate and heat input under paragraphs (c)(3) through (5) of this section shall be determined in accordance with subpart H of this part. (3) Each NOX Budget unit for which the owner or operator requests any early reduction credits under paragraph (c)(4) of this section shall reduce its NOX emission rate, for each control period for which early reduction credits are requested, to less than both 0.25 lb/

mmBtu and 80 percent of the unit's NOX emission rate in the 2000 control period. (4) The NOX authorized account representative of a NOX Budget unit that meets the requirements of paragraphs (c)(1)and (3) of this section may submit to the permitting authority a request for early reduction credits for the unit based on NOX emission rate reductions made by the unit in the control period for 2001 or 2002 in accordance with paragraph (3) of this section. (i) In the early reduction credit request, the NOX authorized account may request early reduction credits for such control period in an amount equal to the unit's heat input for such control period multiplied by the difference between 0.25 lb/mmBtu and the unit's NOX emission rate for such control period, divided by 2000 lb/ton, and rounded to the nearest ton. (ii) The early reduction credit request must be submitted, in a format specified by the permitting authority, by October 31 of the year in which the NOX emission rate reductions on which the request is based are made or such later date approved by the permitting authority. (5) The permitting authority will allocate NOX allowances, to NOX Budget units meeting the requirements of paragraphs (c)(1) and (3) of this section and covered by early reduction requests meeting the requirements of paragraph (c)(4)(ii) of this section, in accordance with the following procedures: (i) Upon receipt of each early reduction credit request, the permitting authority will accept the request only if the requirements of paragraphs (c)(1), (3), and (4)(ii) of this section are met and, if the request is accepted, will make any necessary adjustments to the request to ensure that the amount of the early reduction credits requested meets the requirement of paragraphs (c)(2) and (4) of this section. (ii) If the State's compliance supplement pool has an amount of NOX allowances not less than the number of early reduction credits in all accepted early reduction credit requests for 2001 and 2002 (as adjusted under paragraph (c)(5)(i) of this section), the permitting authority will allocate to each NOX Budget unit covered by such accepted requests one allowance for each early reduction credit requested (as adjusted under paragraph (c)(5)(i) of this section). (iii) If the State's compliance supplement pool has a smaller amount of NOX allowances than the number of early reduction credits in all accepted early reduction credit requests for 2001 and 2002 (as adjusted under paragraph (c)(5)(i) of this section), the permitting authority will allocate NOX allowances to each NOX Budget unit covered by such accepted requests according to the following formula:

Unit's allocated early reduction credits = [(Unit's adjusted early reduction credits)/(Total adjusted early reduction credits requested by all units)] x (Available NOX allowances from the State's compliance supplement pool)

Where:

``Unit's adjusted early reduction credits'' is the number of early reduction credits for the unit for 2001 and 2002 in accepted early reduction credit requests, as adjusted under paragraph (c)(5)(i) of this section. ``Total adjusted early reduction credits requested by all units'' is the number of early reduction credits for all units for 2001 and 2002 in accepted early reduction credit requests, as adjusted under paragraph (c)(5)(i) of this section. ``Available NOX allowances from the State's compliance supplement pool'' is the number of NOX allowances in the State's compliance supplement pool and available for early reduction credits for 2001 and 2002.

(6) By May 1, 2003, the permitting authority will submit to the Administrator the allocations of NOX allowances determined under paragraph (c)(5) of this section. The Administrator will record such allocations to the extent that they are consistent with the requirements of paragraphs (c)(1) through (5) of this section. (7) NOX allowances recorded under paragraph (c)(6) of this section may be deducted for compliance under Sec. 97.54 for the control periods in 2003 or 2004. Notwithstanding paragraph (a) of this section, the Administrator will deduct as retired any NOX allowance that is recorded under paragraph (c)(6) of this section and is not deducted for compliance in accordance with Sec. 97.54 for the control period in 2003 or 2004. (8) NOX allowances recorded under paragraph (c)(6) of this section are treated as banked allowances in 2004 for the purposes of paragraphs (a) and (b) of this section.

Sec. 97.56 Account error.

The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any NOX Allowance Tracking System account. Within 10 business days of making such correction, the Administrator will notify the NOX authorized account representative for the account.

Sec. 97.57 Closing of general accounts.

(a) The NOX authorized account representative of a general account may instruct the Administrator to close the account by submitting a statement requesting deletion of the account from the NOX Allowance Tracking System and by correctly submitting for recordation under Sec. 97.60 an allowance transfer of all NOX allowances in the account to one or more other NOX Allowance Tracking System accounts. (b) If a general account shows no activity for a period of a year or more and does not contain any NOX allowances, the Administrator may notify the NOX authorized account representative for the account that the account will be closed and deleted from the NOX Allowance Tracking System following 20 business days after the notice is sent. The account will be closed after the 20-day period unless before the end of the 20-day period the Administrator receives a correctly submitted transfer of NOX allowances into the account under Sec. 97.60 or a statement submitted by the NOX authorized account representative demonstrating to the satisfaction of the Administrator good cause as to why the account should not be closed.

Subpart G--NOX Allowance Transfers

Sec. 97.60 Submission of NOX allowance transfers.

The NOX authorized account representatives seeking recordation of a NOX allowance transfer shall submit the transfer to the Administrator. To be considered correctly submitted, the NOX allowance transfer shall include the following elements in a format specified by the Administrator: (a) The numbers identifying both the transferror and transferee accounts; (b) A specification by serial number of each NOX allowance to be transferred; and (c) The printed name and signature of the NOX authorized account representative of the transferror account and the date signed.

Sec. 97.61 EPA recordation.

(a) Within 5 business days of receiving a NOX allowance transfer, except as provided in paragraph (b) of this section, the Administrator will record a NOX allowance transfer by moving each NOX allowance from the transferror account to the transferee account as specified by the request, provided that: (1) The transfer is correctly submitted under Sec. 97.60; (2) The transferror account includes each NOX allowance identified by serial number in the transfer; and (3) The transfer meets all other requirements of this part. (b) A NOX allowance transfer that is submitted for recordation following the NOX allowance transfer deadline and

that includes any NOX allowances allocated for a control period prior to or the same as the control period to which the NOX allowance transfer deadline applies will not be recorded until after completion of the process of recordation of NOX allowance allocations in Sec. 97.53(b). (c) Where a NOX allowance transfer submitted for recordation fails to meet the requirements of paragraph (a) of this section, the Administrator will not record such transfer.

Sec. 97.62 Notification.

(a) Notification of recordation. Within 5 business days of recordation of a NOX allowance transfer under Sec. 97.61, the Administrator will notify each party to the transfer. Notice will be given to the NOX authorized account representatives of both the transferror and transferee accounts. (b) Notification of non-recordation. Within 10 business days of receipt of a NOX allowance transfer that fails to meet the requirements of Sec. 97.61(a) the NOX authorized account representatives of both accounts subject to the transfer of: (1) A decision not to record the transfer, and (2) The reasons for such non-recordation. (c) Nothing in this section shall preclude the submission of a NOX allowance transfer for recordation following notification of non-recordation.

Subpart H--Monitoring and Reporting

Sec. 97.70 General Requirements.

The owners and operators, and to the extent applicable, the NOX authorized account representative of a NOX Budget unit, shall comply with the monitoring and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in Sec. 97.2 and in Sec. 72.2 of this chapter shall apply, and the terms ``affected unit,'' ``designated representative,'' and ``continuous emission monitoring system'' (or ``CEMS'') in part 75 of this chapter shall be replaced by the terms ``NOX Budget unit,'' ``NOX authorized account representative,'' and ``continuous emission monitoring system'' (or ``CEMS''), respectively, as defined in Sec. 97.2. (a) Requirements for installation, certification, and data accounting. The owner or operator of each NOX Budget unit must meet the following requirements. These provisions also apply to a unit for which an application for a NOX Budget opt-in permit is submitted and not denied or withdrawn, as provided in subpart I of this part: (1) Install all monitoring systems required under this subpart for monitoring NOX mass. This includes all systems required to monitor NOX emission rate, NOX concentration, heat input, and flow, in accordance with Secs. 75.72 and 75.76. (2) Install all monitoring systems for monitoring heat input, if required under Sec. 97.76 for developing NOX allowance allocations. (3) Successfully complete all certification tests required under Sec. 97.71 and meet all other provisions of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraphs (a) (1) and (2) of this section. (4) Record, and report data from the monitoring systems under paragraphs (a) (1) and (2) of this section. (b) Compliance dates. The owner or operator must meet the requirements of paragraphs (a)(1) through (a)(3) of this section on or before the following dates and must record and report data on and after the following dates: (1) NOX Budget units for which the owner or operator intends to apply for early reduction credits under Sec. 97.55(d) must comply with the requirements of this subpart by May 1, 2000. (2) Except for NOX Budget units under paragraph (b)(1) of this section, NOX Budget units under Sec. 97.4 that commence operation before January 1, 2002, must comply with the requirements of this subpart by May 1, 2002. (3) NOX Budget units under Sec. 97.4 that commence operation on or after January 1, 2002 and that report on an annual basis under Sec. 97.74(d) must comply with the requirements of this subpart by the later of the following dates: (i) May 1, 2002; or (ii) the earlier of: (A) 180 days after the date on which the unit commences operation or, (B) For units under Sec. 97.4(a)(1), 90 days after the date on which the unit commences commercial operation. (4) NOX Budget units under Sec. 97.4 that commence operation on or after January 1, 2002 and that report on a control season basis under Sec. 97.74(d) must comply with the requirements of this subpart by the later of the following dates: (i) the earlier of: (A) 180 days after the date on which the unit commences operation or, (B) for units under Sec. 97.4(a)(1), 90 days after the date on which the unit commences commercial operation. (ii) However, if the applicable deadline under paragraph (b)(4)(i) of this section does not occur during a control period, May 1; immediately following the date determined in accordance with paragraph (b)(4)(i) of this section. (5) For a NOX Budget unit with a new stack or flue for which construction is completed after the applicable deadline under paragraph (b)(1), (b)(2) or (b)(3) of this section or subpart I of this part: (i) 90 days after the date on which emissions first exit to the atmosphere through the new stack or flue (ii) However, if the unit reports on a control season basis under Sec. 97.74(d) and the applicable deadline under paragraph (b)(5)(i) of this section does not occur during the control period, May 1 immediately following the applicable deadline in paragraph (b)(5)(i) of this section. (6) For a unit for which an application for a NOX Budget opt-in permit is submitted and not denied or withdrawn, the compliance dates specified under subpart I of this part. (c) Reporting data prior to initial certification. (1) The owner or operator of a NOX Budget unit that misses the certification deadline under paragraph (b)(1) of this section is not eligible to apply for early reduction credits. The owner or operator of the unit becomes subject to the certification deadline under paragraph (b)(2) of this section. (2) The owner or operator of a NOX Budget under paragraphs (b)(3) or (b)(4) of this section must determine, record and report NOX mass, heat input (if required for purposes of allocations) and any other values required to determine NOX Mass (e.g. NOX emission rate and heat input or NOX concentration and stack flow) using the provisions of Sec. 75.70(g) of this chapter, from the date and hour that the unit starts operating until all required certification tests are successfully completed. (d) Prohibitions. (1) No owner or operator of a NOX Budget unit or a non-NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained prior written approval in accordance with Sec. 97.75. (2) No owner or operator of a NOX Budget unit or a non- NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall operate the unit so as to discharge, or allow to be discharged, NOX emissions to the atmosphere without accounting for all such emissions in accordance with the applicable provisions of this subpart and part 75 of this chapter

except as provided for in Sec. 75.74 of this chapter. (3) No owner or operator of a NOX Budget unit or a non- NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NOX mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing, or maintenance is performed in accordance with the applicable provisions of this subpart and part 75 of this chapter except as provided for in Sec. 75.74 of this chapter. (4) No owner or operator of a NOX Budget unit or a non- NOX Budget unit monitored under Sec. 75.72(b)(2)(ii) shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved emission monitoring system under this subpart, except under any one of the following circumstances: (i) During the period that the unit is covered by a retired unit exemption under Sec. 97.5 that is in effect; (ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the permitting authority for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or (iii) The NOX authorized account representative submits notification of the date of certification testing of a replacement monitoring system in accordance with Sec. 97.71(b)(2).

Sec. 97.71 Initial certification and recertification procedures.

(a) The owner or operator of a NOX Budget unit that is subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures of part 75 of this chapter, except that: (1) If, prior to January 1, 1998, the Administrator approved a petition under Sec. 75.17 (a) or (b) of this chapter for apportioning the NOX emission rate measured in a common stack or a petition under Sec. 75.66 of this chapter for an alternative to a requirement in Sec. 75.17 of this chapter, the NOX authorized account representative shall resubmit the petition to the Administrator under Sec. 97.75(a) to determine if the approval applies under the NOX Budget Trading Program. (2) For any additional CEMS required under the common stack provisions in Sec. 75.72 of this chapter, or for any NOX concentration CEMS used under the provisions of Sec. 75.71(a)(2) of this chapter, the owner or operator shall meet the requirements of paragraph (b) of this section. (b) The owner or operator of a NOX Budget unit that is not subject to an Acid Rain emissions limitation shall comply with the following initial certification and recertification procedures, except that the owner or operator of a unit that qualifies to use the low mass emissions excepted monitoring methodology under Sec. 75.19 shall also meet the requirements of paragraph (c) of this section and the owner or operator of a unit that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall also meet the requirements of paragraph (d) of this section. The owner or operator of a NOX Budget unit that is subject to an Acid Rain emissions limitation, but requires additional CEMS under the common stack provisions in Sec. 75.72 of this chapter, or that uses a NOX concentration CEMS under Sec. 75.71(a)(2) of this chapter also shall comply with the following initial certification and recertification procedures. (1) Requirements for initial certification. The owner or operator shall ensure that each monitoring system required by subpart H of part 75 of this chapter (which includes the automated data acquisition and handling system) successfully completes all of the initial certification testing required under Sec. 75.20 of this chapter. The owner or operator shall ensure that all applicable certification tests are successfully completed by the deadlines specified in Sec. 97.70(b). In addition, whenever the owner or operator installs a monitoring system in order to meet the requirements of this part in a location where no such monitoring system was previously installed, initial certification according to Sec. 75.20 is required. (2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in a certified monitoring system that the Administrator determines significantly affects the ability of the system to accurately measure or record NOX mass emissions or heat input or to meet the requirements of Sec. 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system according to Sec. 75.20(b) of this chapter. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit's operation that the Administrator determines to significantly change the flow or concentration profile, the owner or operator shall recertify the continuous emissions monitoring system according to Sec. 75.20(b) of this chapter. Examples of changes which require recertification include: Replacement of the analyzer, change in location or orientation of the sampling probe or site, or changing of flow rate monitor polynomial coefficients. (3) Certification approval process for initial certifications and recertification. (i) Notification of certification. The NOX authorized account representative shall submit to the Administrator, the appropriate EPA Regional Office and the permitting authority a written notice of the dates of certification in accordance with Sec. 97.73. (ii) Certification application. The NOX authorized account representative shall submit to the Administrator, the appropriate EPA Regional Office and the permitting authority a certification application for each monitoring system required under subpart H of part 75 of this chapter. A complete certification application shall include the information specified in subpart H of part 75 of this chapter. (iii) Except for units using the low mass emission excepted methodology under Sec. 75.19 of this chapter, the provisional certification date for a monitor shall be determined using the procedures set forth in Sec. 75.20(a)(3) of this chapter. A provisionally certified monitor may be used under the NOX Budget Trading Program for a period not to exceed 120 days after receipt by the Administrator of the complete certification application for the monitoring system or component thereof under paragraph (b)(3)(ii) of this section. Data measured and recorded by the provisionally certified monitoring system or component thereof, in accordance with the requirements of part 75 of this chapter, will be considered valid quality-assured data (retroactive to the date and time of provisional certification), provided that the Administrator does not invalidate the provisional certification by issuing a notice of disapproval within 120 days of receipt of the complete certification application by the Administrator. (iv) Certification application formal approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (b)(3)(ii) of this section. In the event the Administrator does not issue

such a notice within such 120-day period, each monitoring system which meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the NOX Budget Trading Program. (A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt. (B) Incomplete application notice. A certification application will be considered complete when all of the applicable information required to be submitted under paragraph (b)(3)(ii) of this section has been received by the Administrator. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the NOX authorized account representative must submit the additional information required to complete the certification application. If the NOX authorized account representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (b)(3)(iv)(C) of this section. (C) Disapproval notice. If the certification application shows that any monitoring system or component thereof does not meet the performance requirements of this part, or if the certification application is incomplete and the requirement for disapproval under paragraph (b)(3)(iv)(B) of this section has been met, the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system or component thereof shall not be considered valid quality-assured data beginning with the date and hour of provisional certification. The owner or operator shall follow the procedures for loss of certification in paragraph (b)(3)(v) of this section for each monitoring system or component thereof which is disapproved for initial certification. (D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with Sec. 97.72(b). (v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (b)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (b)(3)(iv)(D) of this section, then: (A) The owner or operator shall substitute the following values, for each hour of unit operation during the period of invalid data beginning with the date and hour of provisional certification and continuing until the time, date, and hour specified under Sec. 75.20(a)(5)(i) of this chapter: (1) For units using or intending to monitor for NOX emission rate and heat input or for units using the low mass emission excepted methodology under Sec. 75.19 of this chapter, the maximum potential NOX emission rate and the maximum potential hourly heat input of the unit. (2) For units intending to monitor for NOX mass emissions using a NOX pollutant concentration monitor and a flow monitor, the maximum potential concentration of NOX and the maximum potential flow rate of the unit under section 2.1 of appendix A of part 75 of this chapter; (B) The NOX authorized account representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (b)(3)(i) and (ii) of this section; and (C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval. (c) Initial certification and recertification procedures for low mass emission units using the excepted methodologies under Sec. 75.19 of this chapter. The owner or operator of a gas-fired or oil-fired unit using the low mass emissions excepted methodology under Sec. 75.19 of this chapter shall meet the applicable general operating requirements of Sec. 75.10 of this chapter, the applicable requirements of Sec. 75.19 of this chapter, and the applicable certification requirements of Sec. 97.71 of this chapter, except that the excepted methodology shall be deemed provisionally certified for use under the NOX Budget Trading Program, as of the following dates: (i) For units that are reporting on an annual basis under Sec. 97.74(d) (A) For a unit that has commences operation before its compliance deadline under Sec. 97.71(b), from January 1 of the year following submission of the certification application for approval to use the low mass emissions excepted methodology under Sec. 75.19 of this chapter until the completion of the period for the Administrator's review; or (B) For a unit that commences operation after its compliance deadline under Sec. 97.71(b), the date of submission of the certificaation application for approval to use the low mass emissions excepted methodology under Sec. 75.19 of this chapter until the completion of the period for the Administrator's review, or (ii) For units that are reporting on a control period basis under Sec. 97.74(b)(3)(ii) of this part: (A) For a unit that commenced operation before its compliance deadline under Sec. 97.71(b), where the certification application is submitted before May 1, from May 1 of the year of the submission of the certification application for approval to use the low mass emissions excepted methodology under Sec. 75.19 of this chapter until the completion of the period for the Administrator's review; or (B) For a unit that commenced operation before its compliance deadline under Sec. 97.71(b), where the certification application is submitted after May 1, from May 1 of the year following submission of the certification application for approval to use the low mass emissions excepted methodology under Sec. 75.19 of this chapter until the completion of the period for the Administrator's review; or (C) For a unit that commences operation after its compliance deadline under Sec. 97.71(b), where the unit commences operation before May 1, from May 1 of the year that the unit commenced operation, until the completion of the period for the Administrator's review. (D) For a unit that has not operated after its compliance deadline under Sec. 97.71(b), where the certification application is submitted after May 1, but before October 1st, from the date of submission of a certification application for approval to use the low mass emissions excepted methodology under Sec. 75.19 of this chapter until the completion of the period for the Administrator's review. (d) Certification/recertification procedures for alternative monitoring systems. The NOX authorized account representative representing the owner or operator of each unit applying to monitor using an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall apply for certification to the administrator prior to use of the system under the NOX Trading Program. The NOX authorized account representative shall apply for recertification following a replacement, modification or change according to the procedures in paragraph (b) of this

section. The owner or operator of an alternative monitoring system shall comply with the notification and application requirements for certification according to the procedures specified in paragraph (b)(3) of this section and Sec. 75.20(f) of this chapter.

Sec. 97.72 Out of control periods.

(a) Whenever any monitoring system fails to meet the quality assurance requirements of appendix B of part 75 of this chapter, data shall be substituted using the applicable procedures in subpart D, appendix D, or appendix E of part 75 of this chapter. (b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any system or component should not have been certified or recertified because it did not meet a particular performance specification or other requirement under Sec. 97.71 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such system or component. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the system or component. The data measured and recorded by the system or component shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests. The owner or operator shall follow the initial certification or recertification procedures in Sec. 97.71 for each disapproved system.

Sec. 97.73 Notifications.

(a) The NOX authorized account representative for a NOX Budget unit shall submit written notice to the permitting authority, the appropriate EPA Regional Office and the Administrator in accordance with Sec. 75.61 of this chapter. (b) For any unit that does not have an acid rain emissions limitation, the permitting authority may waive the requirements to notify the permitting authority in paragraph (a) of this section and the notification requirements in Sec. 97.71(b)(2)(i).

Sec. 97.74 Recordkeeping and reporting.

(a) General provisions. (1) The NOX authorized account representative shall comply with all recordkeeping and reporting requirements in this section and with the requirements of Sec. 97.10(e). (2) If the NOX authorized account representative for a NOX Budget unit subject to an Acid Rain Emission limitation who signed and certified any submission that is made under subpart F or G of part 75 of this chapter and which includes data and information required under this subpart or subpart H of part 75 of this chapter is not the same person as the designated representative or the alternative designated representative for the unit under part 72 of this chapter, the submission must also be signed by the designated representative or the alternative designated representative. (b) Monitoring plans. (1) The owner or operator of a unit subject to an Acid Rain emissions limitation shall comply with requirements of Sec. 75.62 of this chapter, except that the monitoring plan shall also include all of the information required by subpart H of part 75 of this chapter. (2) The owner or operator of a unit that is not subject to an Acid Rain emissions limitation shall comply with requirements of Sec. 75.62 of this chapter, except that the monitoring plan is only required to include the information required by subpart H of part 75 of this chapter. (c) Certification applications. The NOX authorized account representative shall submit an application to the permitting authority, the appropriate EPA Regional Office and the Administrator within 45 days after completing all initial certification or recertification tests required under Sec. 97.71 including the information required under subpart H of part 75 of this chapter. (d) Quarterly reports. The NOX authorized account representative shall submit quarterly reports, as follows: (1) If a unit is subject to an Acid Rain emission limitation or if the owner or operator of the NOX budget unit chooses to meet the annual reporting requirements of this subpart H, the NOX authorized account representative shall submit a quarterly report for each calendar quarter beginning with: (i) For units that elect to comply with the early reduction credit provisions under Sec. 97.55, the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii). Data shall be reported from the date and hour corresponding to the date and hour of provisional certification ; or (ii) For units commencing operation prior to May 1, 2002 that are not required to certify monitors by May 1, 2000 under Sec. 97.70(b)(1), the earlier of the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii) or, if the certification tests are not completed by May 1, 2002, the partial calender quarter from May 1, 2002 through June 30, 2002. Data shall be recorded and reported from the earlier of the date and hour corresponding to the date and hour of provisional certification or the first hour on May 1, 2002; or (iii) For a unit that commences operation after May 1, 2002, the calendar quarter in which the unit commences operation, Data shall be reported from the date and hour corresponding to when the unit commenced operation. (2) If a NOX budget unit is not subject to an Acid Rain emission limitation, then the NOX authorized account representative shall either: (i) Meet all of the requirements of part 75 of this chapter related to monitoring and reporting NOX mass emissions during the entire year and meet the reporting deadlines specified in paragraph (d)(1) of this section; or (ii) submit quarterly reports only for the periods from the earlier of May 1 or the date and hour that the owner or operator successfully completes all of the recertification tests required under Sec. 75.74(d)(3) through September 30 of each year in accordance with the provisions of Sec. 75.74(b) of this chapter. The NOX authorized account representative shall submit a quarterly report for each calendar quarter, beginning with: (A) For units that elect to comply with the early reduction credit provisions under Sec. 97.55, the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii). Data shall be reported from the date and hour corresponding to the date and hour of provisional certification; or (B) For units commencing operation prior to May 1, 2002 that are not required to certify monitors by May 1, 2000 under Sec. 97.70(b)(1), the earlier of the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii), or if the certification tests are not completed by May 1, 2002, the partial calender quarter from May 1, 2002 through June 30, 2002. Data shall be reported from the earlier of the date and hour corresponding to the date and hour of provisional certification or the first hour of May 1, 2002; or (C) For units that commence operation after May 1, 2002 during the

control period, the calender quarter in which the unit commences operation. Data shall be reported from the date and hour corresponding to when the unit commenced operation; or (D) For units that commence operation after May 1, 2002 and before May 1 of the year in which the unit commences operation, the earlier of the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii) or, if the certification tests are not completed by May 1 of the year in which the unit commences operation, May 1 of the year in which the unit commences operation. Data shall be reported from the earlier of the date and hour corresponding to the date and hour of provisional certification or the first hour of May 1 of the year after the unit commences operation. (E) For units that commence operation after May 1, 2002 and after September 30 of the year in which the unit commences operation, the earlier of the calender quarter that includes the date of initial provisional certification under Sec. 97.71(b)(3)(iii) or, if the certification tests are not completed by May 1 of the year after the unit commences operation, May 1 of the year after the unit commences operation. Data shall be reported from the earlier of the date and hour corresponding to the date and hour of provisional certification or the first hour of May 1 of the year after the unit commences operation. (3) The NOX authorized account representative shall submit each quarterly report to the Administrator within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in subpart H of part 75 of this chapter and Sec. 75.64 of this chapter. (i) For units subject to an Acid Rain Emissions limitation, quarterly reports shall include all of the data and information required in subpart H of part 75 of this chapter for each NOX Budget unit (or group of units using a common stack) as well as information required in subpart G of part 75 of this chapter. (ii) For units not subject to an Acid Rain Emissions limitation, quarterly reports are only required to include all of the data and information required in subpart H of part 75 of this chapter for each NOX Budget unit (or group of units using a common stack). (4) Compliance certification. The NOX authorized account representative shall submit to the Administrator a compliance certification in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit's emissions are correctly and fully monitored. The certification shall state that: (i) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and (ii) For a unit with add-on NOX emission controls and for all hours where data are substituted in accordance with Sec. 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the monitoring plan and the substitute values do not systematically underestimate NOX emissions; and (iii) For a unit that is reporting on a control period basis under Sec. 97.74(d) the NOX emission rate and NOX concentration values substituted for missing data under subpart D of part 75 of this chapter are calculated using only values from a control period and do not systematically underestimate NOX emissions.

Sec. 97.75 Petitions

(a) The NOX authorized account representative of a NOX Budget unit may submit a petition under Sec. 75.66 of this chapter to the Administrator requesting approval to apply an alternative to any requirement of this subpart. (b) Application of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that the petition is approved by the Administrator.

Sec. 97.76 Additional requirements to provide heat input data.

(a) The owner or operator of a unit that elects to monitor and report NOX Mass emissions using a NOX concentration system and a flow system shall also monitor and report heat input at the unit level using the procedures set forth in part 75 of this chapter. (b) The owner or operator of a unit that monitor and report NOX Mass emissions using a NOX concentration system and a flow system shall also monitor and report heat input at the unit level using the procedures set forth in part 75 of this chapter for any source that is applying for early reduction credits under Sec. 97.55.

Subpart I--Individual Opt-Ins

Sec. 97.80 Applicability.

A unit that is in the State, is not a NOX Budget unit under Sec. 97.4, vents all of its emissions to a stack, and is operating, may qualify, under this subpart, to become a NOX Budget opt-in source. A unit that is a NOX Budget unit, is covered by a retired unit exemption under Sec. 97.5 that is in effect, or is not operating is not eligible to become a NOX Budget opt-in source.

Sec. 97.81 General.

Except otherwise as provided in this part, a NOX Budget opt-in source shall be treated as a NOX Budget unit for purposes of applying subparts A through H of this part.

Sec. 97.82 NOX authorized account representative.

A unit for which an application for a NOX Budget opt-in permit is submitted, or a NOX Budget opt-in source, located at the same source as one or more NOX Budget units, shall have the same NOX authorized account representative as such NOX Budget units.

Sec. 97.83 Applying for NOX Budget opt-in permit.

(a) Applying for initial NOX Budget opt-in permit. In order to apply for an initial NOX Budget opt-in permit, the NOX authorized account representative of a unit qualified under Sec. 97.80 may submit to the Administrator and the permitting authority at any time, except as provided under Sec. 97.86(g): (1) A complete NOX Budget permit application under Sec. 97.22; (2) A monitoring plan submitted in accordance with subpart H of this part; and (3) A complete account certificate of representation under Sec. 97.13, if no NOX authorized account representative has been previously designated for the unit. (b) Duty to reapply. The NOX authorized account representative of a NOX Budget opt-in source shall submit to the Administrator and permitting authority a complete NOX Budget permit application under Sec. 97.22 to renew the NOX Budget opt-in permit in accordance with Sec. 97.21(c) and, if applicable, an updated monitoring plan in accordance with subpart H of this part.

Sec. 97.84 Opt-in process.

The permitting authority will issue or deny a NOX Budget opt-in permit for a unit for which an initial application for a NOX Budget opt-in permit under Sec. 97.83 is submitted, in accordance with Sec. 97.20 and the following: (a) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan accompanying the initial application for a NOX Budget opt-in permit under Sec. 97.83. A monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that

the NOX emissions rate and heat input of the unit are monitored and reported in accordance with subpart H of this part. A determination of sufficiency shall not be construed as acceptance or approval of the unit's monitoring plan. (b) If the Administrator determines that the unit's monitoring plan is sufficient under paragraph (a) of this section and after completion of monitoring system certification under subpart H of this part, the NOX emissions rate and the heat input of the unit shall be monitored and reported in accordance with subpart H of this part for one full control period during which monitoring system availability is not less than 90 percent and during which the unit is in full compliance with any applicable State or Federal emissions or emissions- related requirements. Solely for purposes of applying the requirements in the prior sentence, the unit shall be treated as a ``NOX Budget unit'' prior to issuance of a NOX Budget opt-in permit covering the unit. (c) Based on the information monitored and reported under paragraph (b) of this section, the unit's baseline heat rate shall be calculated as the unit's total heat input (in mmBtu) for the control period and the unit's baseline NOX emissions rate shall be calculated as the unit's total NOX mass emissions (in lb) for the control period divided by the unit's baseline heat rate. (d) After calculating the baseline heat input and the baseline NOX emissions rate for the unit under paragraph (c) of this section, the Administrator will provide this information to the permitting authority so the permitting authority can serve a draft NOX Budget opt-in permit on the NOX authorized account representative of the unit. (e) Confirmation of intention to opt-in. Within 20 days after the issuance of the draft NOX Budget opt-in permit, the NOX authorized account representative of the unit must submit to the Administrator and the permitting authority a confirmation of the intention to opt in the unit or a withdrawal of the application for a NOX Budget opt-in permit under Sec. 97.83. The permitting authority will treat the failure to make a timely submission as a withdrawal of the NOX Budget opt-in permit application. (f) Issuance of draft NOX Budget opt-in permit. If the NOX authorized account representative confirms the intention to opt in the unit under paragraph (e) of this section, the permitting authority will issue the draft NOX Budget opt-in permit in accordance with Sec. 97.20. (g) Not withstanding paragraphs (a) through (f) of this section, if at any time before issuance of a draft NOX Budget opt-in permit for the unit, the Administrator or the permitting authority determines that the unit does not qualify as a NOX Budget opt-in source under Sec. 97.80, the permitting authority will issue a draft denial of a NOX Budget opt-in permit for the unit in accordance with Sec. 97.20. (h) Withdrawal of application for NOX Budget opt-in permit. A NOX authorized account representative of a unit may withdraw its application for a NOX Budget opt-in permit under Sec. 97.83 at any time prior to the issuance of the final NOX Budget opt-in permit. Once the application for a NOX Budget opt-in permit is withdrawn, a NOX authorized account representative wanting to reapply must submit a new application for a NOX Budget permit under Sec. 97.83. (i) Effective date. The effective date of the initial NOX Budget opt-in permit shall be May 1 of the first control period starting after the issuance of the initial NOX Budget opt-in permit by the permitting authority. The unit shall be a NOX Budget opt-in source and a NOX Budget unit as of the effective date of the initial NOX Budget opt-in permit.

Sec. 97.85 NOX Budget opt-in permit contents.

(a) Each NOX Budget opt-in permit (including any draft or proposed NOX Budget opt-in permit, if applicable) will contain all elements required for a complete NOX Budget opt- in permit application under Sec. 97.22 as approved or adjusted by the Administrator or the permitting authority. (b) Each NOX Budget opt-in permit is deemed to incorporate automatically the definitions of terms under Sec. 97.2 and, upon recordation by the Administrator under subpart F, G, or I of this part, every allocation, transfer, or deduction of NOX allowances to or from the compliance accounts of each NOX Budget opt-in source covered by the NOX Budget opt-in permit or the overdraft account of the NOX Budget source where the NOX Budget opt-in source is located.

Sec. 97.86 Withdrawal from NOX Budget Trading Program.

(a) Requesting withdrawal. To withdraw from the NOX Budget Trading Program, the NOX authorized account representative of a NOX Budget opt-in source shall submit to the Administrator and the permitting authority a request to withdraw effective as of a specified date prior to May 1 or after September 30. The submission shall be made no later than 90 days prior to the requested effective date of withdrawal. (b) Conditions for withdrawal. Before a NOX Budget opt- in source covered by a request under paragraph (a) of this section may withdraw from the NOX Budget Trading Program and the NOX Budget opt-in permit may be terminated under paragraph (e) of this section, the following conditions must be met: (1) For the control period immediately before the withdrawal is to be effective, the NOX authorized account representative must submit or must have submitted to the Administrator and the permitting authority an annual compliance certification report in accordance with Sec. 97.30. (2) If the NOX Budget opt-in source has excess emissions for the control period immediately before the withdrawal is to be effective, the Administrator will deduct or has deducted from the NOX Budget opt-in source's compliance account, or the overdraft account of the NOX Budget source where the NOX Budget opt-in source is located, the full amount required under Sec. 97.54(d) for the control period. (3) After the requirements for withdrawal under paragraphs (b)(1) and (2) of this section are met, the Administrator will deduct from the NOX Budget opt-in source's compliance account, or the overdraft account of the NOX Budget source where the NOX Budget opt-in source is located, NOX allowances equal in number to and allocated for the same or a prior control period as any NOX allowances allocated to that source under Sec. 97.88 for any control period for which the withdrawal is to be effective. The Administrator will close the NOX Budget opt-in source's compliance account and will establish, and transfer any remaining allowances to, a new general account for the owners and operators of the NOX Budget opt-in source. The NOX authorized account representative for the NOX Budget opt-in source shall become the NOX authorized account representative for the general account. (c) A NOX Budget opt-in source that withdraws from the NOX Budget Trading Program shall comply with all requirements under the NOX Budget Trading Program concerning all years for which such NOX Budget opt-in source was a NOX Budget opt-in source, even if such requirements arise or must be complied with after the withdrawal takes effect. (d) Notification. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full amount of NOX allowances required), the Administrator will issue a notification to the

permitting authority and the NOX authorized account representative of the NOX Budget opt-in source of the acceptance of the withdrawal of the NOX Budget opt-in source as of a specified effective date that is after such requirements have been met and that is prior to May 1 or after September 30. (2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a notification to the permitting authority and the NOX authorized account representative of the NOX Budget opt-in source that the NOX Budget opt-in source's request to withdraw is denied. If the NOX Budget opt-in source's request to withdraw is denied, the NOX Budget opt-in source shall remain subject to the requirements for a NOX Budget opt-in source. (e) Permit amendment. After the Administrator issues a notification under paragraph (d)(1) of this section that the requirements for withdrawal have been met, the permitting authority will revise the NOX Budget permit covering the NOX Budget opt-in source to terminate the NOX Budget opt-in permit as of the effective date specified under paragraph (d)(1) of this section. A NOX Budget opt-in source shall continue to be a NOX Budget opt-in source until the effective date of the termination. (f) Reapplication upon failure to meet conditions of withdrawal. If the Administrator denies the NOX Budget opt-in source's request to withdraw, the NOX authorized account representative may submit another request to withdraw in accordance with paragraphs (a) and (b) of this section. (g) Ability to return to the NOX Budget Trading Program. Once a NOX Budget opt-in source withdraws from the NOX Budget Trading Program and its NOX Budget opt-in permit is terminated under this section, the NOX authority account representative may not submit another application for a NOX Budget opt-in permit under Sec. 97.83 for the unit prior to the date that is 4 years after the date on which the terminated NOX Budget opt-in permit became effective.

Sec. 97.87 Change in regulatory status.

(a) Notification. When a NOX Budget opt-in source becomes a NOX Budget unit under Sec. 97.4, the NOX authorized account representative shall notify in writing the permitting authority and the Administrator of such change in the NOX Budget opt-in source's regulatory status, within 30 days of such change. (b) Permitting authority's and Administrator's action. (1)(i) When the NOX Budget opt-in source becomes a NOX Budget unit under Sec. 97.4, the permitting authority will revise the NOX Budget opt-in source's NOX Budget opt-in permit to meet the requirements of a NOX Budget permit under Sec. 97.23 as of an effective date that is the date on which such NOX Budget opt-in source becomes a NOX Budget unit under Sec. 97.4. (ii)(A) The Administrator will deduct from the compliance account for the NOX Budget unit under paragraph (b)(1)(i) of this section, or the overdraft account of the NOX Budget source where the unit is located, NOX allowances equal in number to and allocated for the same or a prior control period as: (1) Any NOX allowances allocated to the NOX Budget unit (as a NOX Budget opt-in source) under Sec. 97.88 for any control period after the last control period during which the unit's NOX Budget opt-in permit was effective; and (2) If the effective date of the NOX Budget permit revision under paragraph (b)(1)(i) of this section is during a control period, the NOX allowances allocated to the NOX Budget unit (as a NOX Budget opt-in source) under Sec. 97.88 for the control period multiplied by the ratio of the number of days, in the control period, starting with the effective date of the permit revision under paragraph (b)(1)(i) of this section, divided by the total number of days in the control period. (B) The NOX authorized account representative shall ensure that the compliance account of the NOX Budget unit under paragraph (b)(1)(i) of this section, or the overdraft account of the NOX Budget source where the unit is located, includes the NOX allowances necessary for completion of the deduction under paragraph (b)(1)(ii)(A) of this section. If the compliance account or overdraft account does not contain sufficient NOX allowances, the Administrator will deduct the required number of NOX allowances, regardless of the control period for which they were allocated, whenever NOX allowances are recorded in either account. (iii) (A) For every control period during which the NOX Budget permit revised under paragraph (b)(1)(i) of this section is effective, the NOX Budget unit under paragraph (b)(1)(i) of this section will be treated, solely for purposes of NOX allowance allocations under Sec. 97.42, as a unit that commenced operation on the effective date of the NOX Budget permit revision under paragraph (b)(1)(i) of this section and will be allocated NOX allowances under Sec. 97.42. (B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if the effective date of the NOX Budget permit revision under paragraph (b)(1)(i) of this section is during a control period, the following number of NOX allowances will be allocated to the NOX Budget unit under paragraph (b)(1)(i) of this section under Sec. 97.42 for the control period: the number of NOX allowances otherwise allocated to the NOX Budget unit under Sec. 97.42 for the control period multiplied by the ratio of the number of days, in the control period, starting with the effective date of the permit revision under paragraph (b)(1)(i) of this section, divided by the total number of days in the control period. (2)(i) When the NOX authorized account representative of a NOX Budget opt-in source does not renew its NOX Budget opt-in permit under Sec. 97.83(b), the Administrator will deduct from the NOX Budget opt-in unit's compliance account, or the overdraft account of the NOX Budget source where the NOX Budget opt-in source is located, NOX allowances equal in number to and allocated for the same or a prior control period as any NOX allowances allocated to the NOX Budget opt-in source under Sec. 97.88 for any control period after the last control period for which the NOX Budget opt-in permit is effective. The NOX authorized account representative shall ensure that the NOX Budget opt- in source's compliance account or the overdraft account of the NOX Budget source where the NOX Budget opt-in source is located includes the NOX allowances necessary for completion of such deduction. If the compliance account or overdraft account does not contain sufficient NOX allowances, the Administrator will deduct the required number of NOX allowances, regardless of the control period for which they were allocated, whenever NOX allowances are recorded in either account. (ii) After the deduction under paragraph (b)(2)(i) of this section is completed, the Administrator will close the NOX Budget opt-in source's compliance account. If any NOX allowances remain in the compliance account after completion of such deduction and any deduction under Sec. 97.54, the Administrator will close the NOX Budget opt-in source's compliance account and will establish, and transfer any remaining allowances to, a new general account for the owners and operators of the NOX Budget opt- in source. The NOX authorized account representative for the NOX Budget opt-in source shall become the NOX authorized account representative for the general account.

Sec. 97.88 NOX allowance allocations to opt-in units.

(a) NOX allowance allocation. (1) By December 31 immediately before the first control period for which the NOX Budget opt-in permit is effective, the Administrator will allocate NOX allowances to the NOX Budget opt-in source for the control period in accordance with paragraph (b) of this section. (2) By no later than December 31, after the first control period for which the NOX Budget opt-in permit is in effect, and December 31 of each year thereafter, the Administrator will allocate NOX allowances to the NOX Budget opt-in source for the next control period, in accordance with paragraph (b) of this section. (b) For each control period for which the NOX Budget opt-in source has an approved NOX Budget opt-in permit, the NOX Budget opt-in source will be allocated NOX allowances in accordance with the following procedures: (1) The heat input (in mmBtu) used for calculating NOX allowance allocations will be the lesser of: (i) The NOX Budget opt-in source's baseline heat input determined pursuant to Sec. 97.84(c); or (ii) The NOX Budget opt-in source's heat input, as determined in accordance with subpart H of this part, for the control period in the year prior to the year of the control period for which the NOX allocations are being calculated. (2) The Administrator will allocate NOX allowances to the NOX Budget opt-in source in an amount equaling the heat input (in mmBtu) determined under paragraph (b)(1) of this section multiplied by the lesser of: (i) The NOX Budget opt-in source's baseline NOX emissions rate (in lb/mmBtu) determined pursuant to Sec. 97.84(c); or (ii) The most stringent State or Federal NOX emissions limitation applicable to the NOX Budget opt-in source during the control period.

Appendix A to Part 97--NOX Allowance Allocation Tables for Affected Sources Under Section 126 of the Act

Table A.1--Allocations to Fossil Fuel-Fired EGUs by mmBtu and MWh -------------------------------------------------------------------------------------------------------------------------------------------------------- Unit Unit average of average of two highest two highest Unit Unit State Plant ID Point ID Plant of 1995, of 1995, allocations allocations 1996, or 1996, or by HI by MWh 1997, 1997, summer HI summer MWh -------------------------------------------------------------------------------------------------------------------------------------------------------- AL........................ 3 1 BARRY....................... 4,444,705 452,203 336 333 AL........................ 3 2 BARRY....................... 4,457,926 453,456 337 334 AL........................ 3 3 BARRY....................... 7,758,632 798,049 587 587 AL........................ 3 4 BARRY....................... 12,886,737 1,375,025 975 1,012 AL........................ 3 5 BARRY....................... 25,069,820 2,649,527 1,897 1,950 AL........................ 56 **4 CHARLES R LOWMAN............ 903,512 68,448 68 50 AL........................ 56 1 CHARLES R LOWMAN............ 2,337,265 205,745 177 151 AL........................ 56 2 CHARLES R LOWMAN............ 8,251,949 786,199 625 578 AL........................ 56 3 CHARLES R LOWMAN............ 7,476,176 712,220 566 524 AL........................ 5 110 CHICKASAW................... 293,278 27,668 22 20 AL........................ 47 1 COLBERT..................... 5,401,036 528,115 409 389 AL........................ 47 2 COLBERT..................... 5,586,222 546,223 423 402 AL........................ 47 3 COLBERT..................... 5,294,661 517,714 401 381 AL........................ 47 4 COLBERT..................... 5,512,314 538,996 417 397 AL........................ 47 5 COLBERT..................... 13,750,384 1,387,106 1,041 1,021 AL........................ 26 1 E C GASTON.................. 7,187,848 760,699 544 560 AL........................ 26 2 E C GASTON.................. 7,037,596 752,765 533 554 AL........................ 26 3 E C GASTON.................. 7,568,867 809,591 573 596 AL........................ 26 4 E C GASTON.................. 7,279,128 767,031 551 564 AL........................ 26 5 E C GASTON.................. 24,100,992 2,589,277 1,824 1,905 AL........................ 7 1 GADSDEN..................... 1,915,860 162,803 145 120 AL........................ 7 2 GADSDEN..................... 1,777,783 151,069 135 111 AL........................ 8 10 GORGAS...................... 24,048,187 2,517,344 1,820 1,852 AL........................ 8 6 GORGAS...................... 3,271,407 292,953 248 216 AL........................ 8 7 GORGAS...................... 3,320,557 302,034 251 222 AL........................ 8 8 GORGAS...................... 6,100,623 624,488 462 460 AL........................ 8 9 GORGAS...................... 6,382,810 673,576 483 496 AL........................ 10 1 GREENE COUNTY............... 8,730,961 907,867 661 668 AL........................ 10 2 GREENE COUNTY............... 7,752,706 806,146 587 593 AL........................ 6002 1 JAMES H MILLER JR........... 20,389,071 2,160,317 1,543 1,590 AL........................ 6002 2 JAMES H MILLER JR........... 20,467,280 2,168,604 1,549 1,596 AL........................ 6002 3 JAMES H MILLER JR........... 22,363,879 2,369,557 1,693 1,744 AL........................ 6002 4 JAMES H MILLER JR........... 24,810,536 2,628,792 1,878 1,934 AL........................ 7063 **1 MCINTOSH-CAES............... 113,793 24,911 9 18 AL........................ 533 **4 MCWILLIAMS.................. 1,130,929 133,050 86 98 AL........................ 52140 1 UNION CAMP CORPORATION--.... 43,647 3,307 3 2 AL........................ 50 1 WIDOWS CREEK................ 3,220,389 295,992 244 218 AL........................ 50 2 WIDOWS CREEK................ 3,004,746 276,171 227 203 AL........................ 50 3 WIDOWS CREEK................ 2,954,318 271,537 224 200 AL........................ 50 4 WIDOWS CREEK................ 3,135,926 288,228 237 212 AL........................ 50 5 WIDOWS CREEK................ 2,946,352 278,352 223 205 AL........................ 50 6 WIDOWS CREEK................ 3,048,563 288,008 231 212 AL........................ 50 7 WIDOWS CREEK................ 14,708,106 1,494,422 1,113 1,100 AL........................ 50 8 WIDOWS CREEK................ 14,313,089 1,445,913 1,083 1,064 CT........................ 10675 AB__mes AES THAMES.................. 4,630,651 436,854 172 160 CT........................ 568 BHB1 BRIDGEPORT HARBOR........... 614,787 60,445 23 22 CT........................ 568 BHB2 BRIDGEPORT HARBOR........... 1,964,426 198,187 73 73 CT........................ 568 BHB3 BRIDGEPORT HARBOR........... 11,910,460 1,235,525 442 454 CT........................ 50498 CW__na) CAPITOL DISTRICT (AETNA).... 626,274 56,421 23 21 CT........................ 544 7 DEVON....................... 3,341,227 340,420 124 125

CT........................ 544 8 DEVON....................... 3,257,953 331,059 121 122 CT........................ 10567 CW__CH DEXTER CORP. CH............. 474,019 42,704 18 16 CT........................ 569 EB 13 ENGLISH..................... 56,957 3,997 2 1 CT........................ 569 EB 14 ENGLISH..................... 86,982 6,104 3 2 CT........................ 50736 ST__rd) EXETER ENERGY (OXFORD)...... 412,978 38,960 15 14 CT........................ 562 1 MIDDLETOWN.................. 452,331 43,059 17 16 CT........................ 562 2 MIDDLETOWN.................. 2,247,666 231,766 83 85 CT........................ 562 3 MIDDLETOWN.................. 4,056,337 450,955 150 166 CT........................ 562 4 MIDDLETOWN.................. 5,882,211 543,090 218 199 CT........................ 546 5 MONTVILLE................... 1,584,160 158,131 59 58 CT........................ 546 6 MONTVILLE................... 5,312,085 485,344 197 178 CT........................ 6156 NHB1 NEW HAVEN HARBOR............ 10,881,332 1,160,923 404 426 CT........................ 548 1 NORWALK HARBOR.............. 3,099,297 322,005 115 118 CT........................ 548 2 NORWALK HARBOR.............. 3,631,682 379,407 135 139 CT........................ n46 CW__rd) O'BRIEN (HARTFORD).......... 673,659 60,690 25 22 DC........................ 603 15 BENNING..................... 605,207 53,487 89 90 DC........................ 603 16 BENNING..................... 730,757 63,296 107 106 DE........................ 592 B4 DELAWARE CITY............... 546,523 51,559 50 46 DE........................ 52193 ST__1 DELAWARE CITY............... 293,747 27,712 27 25 DE........................ 52193 ST__2 DELAWARE CITY............... 293,747 27,712 27 25 DE........................ 52193 ST__3 DELAWARE CITY............... 494,793 46,679 45 42 DE........................ 593 3 EDGE MOOR................... 2,775,531 268,375 252 241 DE........................ 593 4 EDGE MOOR................... 4,421,018 453,252 401 407 DE........................ 593 5 EDGE MOOR................... 6,515,159 712,351 591 640 DE........................ 7153 **3 HAY ROAD.................... 2,014,002 171,609 183 154 DE........................ 7153 --1 HAY ROAD.................... 156,053 11,822 14 11 DE........................ 7153 --2 HAY ROAD.................... 156,053 11,822 14 11 DE........................ 7153 --4 HAY ROAD.................... 1,056,415 124,284 96 112 DE........................ 594 1 INDIAN RIVER................ 2,118,931 214,271 192 193 DE........................ 594 2 INDIAN RIVER................ 2,201,388 218,804 200 197 DE........................ 594 3 INDIAN RIVER................ 4,022,311 435,315 365 391 DE........................ 594 4 INDIAN RIVER................ 8,277,718 804,521 751 723 DE........................ 599 3 MCKEE RUN................... 1,156,067 103,627 105 93 DE........................ 7318 --1 VAN SANT STATION............ 53,745 3,772 5 3 IL........................ 54780 ST__TS) ABBOTT (7 UNITS)............ 109,017 10,285 8 7 IL........................ ........... ............................. BABCOCK & WILCOX CO 45,900 3,221 3 2 COGENERATION FA. IL........................ 889 1 BALDWIN..................... 15,218,756 1,493,792 1,074 1,056 IL........................ 889 2 BALDWIN..................... 15,201,447 1,513,184 1,072 1,070 IL........................ 889 3 BALDWIN..................... 16,459,376 1,782,282 1,161 1,260 IL........................ ........... ............................. BALDWIN POWER PLANT......... 3,366 236 0 0 IL........................ ........... ............................. BREESE MUNICIPAL POWER PLANT 6,579 462 0 0 IL........................ ........... ............................. BUSHNELL MUNICIPAL ELECTRIC 306 21 0 0 LIGHT &. IL........................ ........... ............................. BUSHNELL MUNICIPAL ELECTRIC 306 21 0 0 LIGHT &. IL........................ ........... ............................. CALUMET PEAKING UNITS....... 306 21 0 0 IL........................ ........... ............................. CARLYLE MUNICIPAL ELECTRIC 306 21 0 0 PLANT. IL........................ ........... ............................. CARLYLE MUNICIPAL ELECTRIC 918 64 0 0 PLANT. IL........................ ........... ............................. CENTRAL ILLINOIS LIGHT CO-- 3,366 236 0 0 STERLIN. IL........................ ........... ............................. CITY OF CARMI............... 765 54 0 0 IL........................ ........... ............................. CITY OF CARMI............... 1,224 86 0 0 IL........................ ........... ............................. CITY OF CARMI............... 1,530 107 0 0 IL........................ ........... ............................. CITY OF CARMI............... 1,836 129 0 0 IL........................ ........... ............................. CITY OF CARMI............... 1,989 140 0 0 IL........................ ........... ............................. CITY OF PERU GENERATING 1,836 129 0 0 STATION. IL........................ ........... ............................. CITY OF PERU GENERATING 2,907 204 0 0 STATION. IL........................ ........... ............................. CITY OF RED BUD............. 612 43 0 0 IL........................ ........... ............................. CITY OF RED BUD............. 1,989 140 0 0 IL........................ ........... ............................. CITY OF RED BUD............. 8,109 569 1 0 IL........................ ........... ............................. CITY WATER LIGHT & POWER 63,189 4,434 4 3 DEPT. IL........................ ........... ............................. CLINTON POWER STATION....... 1,377 97 0 0 IL........................ ........... ............................. CLINTON POWER STATION....... 2,601 183 0 0 IL........................ 861 01 COFFEEN..................... 6,072,017 604,783 428 427 IL........................ 861 02 COFFEEN..................... 11,934,607 1,220,682 842 863 IL........................ 6025 1 COLLINS..................... 4,795,651 482,023 338 341 IL........................ 6025 2 COLLINS..................... 5,305,418 542,809 374 384 IL........................ 6025 3 COLLINS..................... 5,854,107 581,688 413 411 IL........................ 6025 4 COLLINS..................... 3,746,709 362,491 264 256 IL........................ 6025 5 COLLINS..................... 2,488,656 235,356 176 166 IL........................ ........... ............................. COM ED--ELECTRIC JUNCTION 765 54 0 0 PEAKING. IL........................ ........... ............................. COMMONWEALTH EDISON-WESTERN 306 21 0 0 DIV HQ. IL........................ 867 7 CRAWFORD.................... 4,358,553 445,979 307 315 IL........................ 867 8 CRAWFORD.................... 5,792,952 607,037 409 429 IL........................ ........... ............................. CRAWFORD.................... 16,983 1,192 1 1 IL........................ 963 31 DALLMAN..................... 2,002,848 179,146 141 127 IL........................ 963 32 DALLMAN..................... 2,398,394 214,910 169 152 IL........................ 963 33 DALLMAN..................... 6,864,473 650,291 484 460 IL........................ 6016 1 DUCK CREEK.................. 12,712,162 1,268,932 897 897

IL........................ 856 1 E D EDWARDS................. 2,856,940 277,831 202 196 IL........................ 856 2 E D EDWARDS................. 6,511,474 652,845 459 461 IL........................ 856 3 E D EDWARDS................. 8,431,346 874,077 595 618 IL........................ ........... ............................. FAIRFIELD MUNICIPAL LIGHT... 459 32 0 0 IL........................ ........... ............................. FAIRFIELD MUNICIPAL LIGHT... 918 64 0 0 IL........................ 886 19 FISK........................ 6,895,507 739,068 486 522 IL........................ ........... ............................. FISK........................ 306 21 0 0 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 23,103 1,621 2 1 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 25,704 1,804 2 1 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 51,408 3,608 4 3 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 74,511 5,229 5 4 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 87,363 6,131 6 4 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 87,363 6,131 6 4 IL........................ ........... ............................. GENESEO MUNICIPAL UTILITIES. 141,372 9,921 10 7 IL........................ 862 07 GRAND TOWER................. 651,170 62,612 46 44 IL........................ 862 08 GRAND TOWER................. 654,114 62,896 46 44 IL........................ 862 09 GRAND TOWER................. 2,630,056 270,276 186 191 IL........................ 891 9 HAVANA...................... 8,683,730 823,571 613 582 IL........................ 892 1 HENNEPIN.................... 2,009,046 189,586 142 134 IL........................ 892 2 HENNEPIN.................... 6,675,377 751,901 471 531 IL........................ 863 05 HUTSONVILLE................. 2,052,071 201,638 145 143 IL........................ 863 06 HUTSONVILLE................. 1,495,464 148,227 105 105 IL........................ 384 71 JOLIET 29................... 5,594,695 565,406 395 400 IL........................ 384 72 JOLIET 29................... 7,988,169 807,293 564 571 IL........................ 384 81 JOLIET 29................... 5,979,042 606,271 422 429 IL........................ 384 82 JOLIET 29................... 8,727,941 885,007 616 626 IL........................ 874 5 JOLIET 9.................... 7,279,634 745,482 514 527 IL........................ 887 1 JOPPA STEAM................. 6,415,901 612,380 453 433 IL........................ 887 2 JOPPA STEAM................. 6,371,397 627,662 449 444 IL........................ 887 3 JOPPA STEAM................. 6,162,171 610,721 435 432 IL........................ 887 4 JOPPA STEAM................. 6,409,101 622,666 452 440 IL........................ 887 5 JOPPA STEAM................. 6,707,659 630,241 473 445 IL........................ 887 6 JOPPA STEAM................. 6,766,124 648,034 477 458 IL........................ 876 1 KINCAID..................... 9,749,992 914,719 688 647 IL........................ 876 2 KINCAID..................... 11,246,140 1,098,470 793 776 IL........................ 964 7 LAKESIDE.................... 700,482 56,039 49 40 IL........................ 964 8 LAKESIDE.................... 696,352 55,708 49 39 IL........................ ........... ............................. LASALLE COUNTY STATION...... 1,530 107 0 0 IL........................ 976 1 MARION...................... 95,573 7,079 7 5 IL........................ 976 2 MARION...................... 175,085 12,969 12 9 IL........................ 976 3 MARION...................... 584,871 43,324 41 31 IL........................ 976 4 MARION...................... 5,264,312 501,363 371 354 IL........................ ........... ............................. MARISON CO.................. 306 21 0 0 IL........................ ........... ............................. MASCOUTAH POWER PLANT....... 459 32 0 0 IL........................ ........... ............................. MASCOUTAH POWER PLANT....... 765 54 0 0 IL........................ 864 01 MEREDOSIA................... 470,181 45,210 33 32 IL........................ 864 02 MEREDOSIA................... 431,943 41,533 30 29 IL........................ 864 03 MEREDOSIA................... 320,639 30,831 23 22 IL........................ 864 04 MEREDOSIA................... 382,526 36,781 27 26 IL........................ 864 05 MEREDOSIA................... 5,620,207 577,557 396 408 IL........................ 864 06 MEREDOSIA................... 425,393 42,887 30 30 IL........................ 6017 1 NEWTON...................... 15,508,748 1,619,543 1,094 1,145 IL........................ 6017 2 NEWTON...................... 14,958,053 1,596,036 1,055 1,128 IL........................ ........... ............................. OGLESBY GAS TURBINE......... 15,759 1,106 1 1 IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1 IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1 IL........................ ........... ............................. PHOENIX CHEMICAL COMPANY.... 17,901 1,256 1 1 IL........................ 879 51 POWERTON.................... 9,827,191 899,926 693 636 IL........................ 879 52 POWERTON.................... 10,189,834 933,135 719 660 IL........................ 879 61 POWERTON.................... 9,120,197 876,100 643 619 IL........................ 879 62 POWERTON.................... 9,670,327 928,946 682 657 IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0 UTILITY. IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0 UTILITY. IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0 UTILITY. IL........................ ........... ............................. PRINCETON MUNCIPAL ELECTRIC 153 11 0 0 UTILITY. IL........................ ........... ............................. QUAD CITIES STATION--CORDOVA 8,415 591 1 0 IL........................ ........... ............................. RANTOUL ELECT GENERATING 38,250 2,684 3 2 PLANT. IL........................ ........... ............................. RANTOUL ELECT GENERATING 41,310 2,899 3 2 PLANT. IL........................ ........... ............................. RANTOUL ELECT GENERATING 90,270 6,335 6 4 PLANT. IL........................ ........... ............................. RANTOUL ELECT GENERATING 160,344 11,252 11 8 PLANT. IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 306 21 0 0 PLANT. IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 459 32 0 0 PLANT. IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 7,038 494 0 0 PLANT. IL........................ ........... ............................. ROCHELLE MUNICIPAL DIESEL 11,169 784 1 1 PLANT. IL........................ ........... ............................. ROCHELLE/SOUTH MAIN STREET.. 459 32 0 0 IL........................ ........... ............................. ROCHELLE/SOUTH MAIN STREET.. 765 54 0 0

IL........................ ........... ............................. ROCK RIVER DIV HEADQUARTERS. 6,732 472 0 0 IL........................ ........... ............................. ST LOUIS AUTO SHREDDING INC. 11,934 837 1 1 IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0 IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0 IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0 IL........................ ........... ............................. STALLIINGS.................. 153 11 0 0 IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 612 43 0 0 IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 1,071 75 0 0 IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 1,377 97 0 0 IL........................ ........... ............................. SULLIVAN ELECTRIC UTILITY... 2,142 150 0 0 IL........................ ........... ............................. U.O.P. CO................... 16,218 1,138 1 1 IL........................ 897 1 VERMILION................... 623,436 56,779 44 40 IL........................ 897 2 VERMILION................... 1,112,049 98,568 78 70 IL........................ ........... ............................. WASTE MANAGEMENT OF IL-- 1,530 107 0 0 MIDWAY LAN. IL........................ ........... ............................. WATERLOO CITY LIGHT PLANT... 153 11 0 0 IL........................ 883 17 WAUKEGAN.................... 2,836,176 246,624 200 174 IL........................ 883 7 WAUKEGAN.................... 7,481,751 769,490 528 544 IL........................ 883 8 WAUKEGAN.................... 8,846,311 906,291 624 641 IL........................ ........... ............................. WHITE COUNTY COAL CORP--MINE 306 21 0 0 #1. IL........................ 884 1 WILL COUNTY................. 4,419,934 448,588 312 317 IL........................ 884 2 WILL COUNTY................. 4,350,027 456,025 307 322 IL........................ 884 3 WILL COUNTY................. 5,839,114 615,875 412 435 IL........................ 884 4 WILL COUNTY................. 9,697,974 1,029,181 684 727 IL........................ 898 4 WOOD RIVER.................. 2,014,967 187,998 142 133 IL........................ 898 5 WOOD RIVER.................. 7,180,169 719,312 507 508 IN........................ 6137 1 A B BROWN................... 6,035,177 573,141 468 440 IN........................ 6137 2 A B BROWN................... 6,871,738 668,782 533 514 IN........................ 6137 --4 A B BROWN................... 151,668 11,831 12 9 IN........................ 7336 --ACT1 ANDERSON.................... 67,856 4,762 5 4 IN........................ 7336 --ACT2 ANDERSON.................... 67,856 4,762 5 4 IN........................ 995 7 BAILLY...................... 5,354,149 546,509 415 420 IN........................ 995 8 BAILLY...................... 9,260,589 976,032 719 749 IN........................ 1011 --2 BROADWAY.................... 123,242 9,337 10 7 IN........................ 1001 1 CAYUGA...................... 15,657,595 1,562,790 1,215 1,200 IN........................ 1001 2 CAYUGA...................... 14,571,660 1,475,761 1,131 1,133 IN........................ 1001 --4 CAYUGA...................... 345,558 28,110 27 22 IN........................ 1001 5 CAYUGA...................... 149,834 11,351 12 9 IN........................ 983 1 CLIFTY CREEK................ 7,379,559 784,475 573 602 IN........................ 983 2 CLIFTY CREEK................ 7,176,300 784,209 557 602 IN........................ 983 3 CLIFTY CREEK................ 7,063,406 756,334 548 581 IN........................ 983 4 CLIFTY CREEK................ 6,798,235 732,253 527 562 IN........................ 983 5 CLIFTY CREEK................ 7,400,261 783,096 574 601 IN........................ 983 6 CLIFTY CREEK................ 6,727,925 706,863 522 543 IN........................ ........... 1 CONNERSVILLE................ 16,083 1,129 1 1 IN........................ ........... 2 CONNERSVILLE................ 16,083 1,129 1 1 IN........................ 996 11 DEAN H MITCHELL............. 2,287,384 227,941 177 175 IN........................ 996 4 DEAN H MITCHELL............. 1,842,510 182,734 143 140 IN........................ 996 5 DEAN H MITCHELL............. 3,177,761 322,092 247 247 IN........................ 996 6 DEAN H MITCHELL............. 2,600,547 268,430 202 206 IN........................ 990 10 ELMER W STOUT............... 13,560 1,279 1 1 IN........................ 990 50 ELMER W STOUT............... 2,415,760 232,374 187 178 IN........................ 990 60 ELMER W STOUT............... 2,335,827 224,685 181 173 IN........................ 990 70 ELMER W STOUT............... 9,783,680 941,100 759 723 IN........................ 990 9 ELMER W STOUT............... 15,792 1,490 1 1 IN........................ 990 --GT4 ELMER W STOUT............... 78,478 5,945 6 5 IN........................ 990 --GT5 ELMER W STOUT............... 88,946 6,738 7 5 IN........................ 1012 1 F B CULLEY.................. 669,903 64,414 52 49 IN........................ 1012 2 F B CULLEY.................. 2,593,129 221,257 201 170 IN........................ 1012 3 F B CULLEY.................. 9,584,920 941,544 744 723 IN........................ 1043 1SG1 FRANK E RATTS............... 3,258,718 337,971 253 260 IN........................ 1043 2SG1 FRANK E RATTS............... 3,187,585 328,482 247 252 IN........................ 1008 1 GALLAGHER................... 3,831,362 370,968 297 285 IN........................ 1008 2 GALLAGHER................... 3,401,395 335,476 264 258 IN........................ 1008 3 GALLAGHER................... 4,528,750 444,605 351 341 IN........................ 1008 4 GALLAGHER................... 4,244,584 410,978 329 316 IN........................ 6113 1 GIBSON...................... 19,606,094 2,037,632 1,521 1,565 IN........................ 6113 2 GIBSON...................... 18,199,182 1,859,906 1,412 1,428 IN........................ 6113 3 GIBSON...................... 16,865,898 1,708,977 1,309 1,312 IN........................ 6113 4 GIBSON...................... 16,654,069 1,680,532 1,292 1,290 IN........................ 6113 5 GIBSON...................... 20,380,811 2,015,308 1,581 1,547 IN........................ 991 1 H T PRITCHARD............... 17,262 1,628 1 1 IN........................ 991 2 H T PRITCHARD............... 20,009 1,888 2 1 IN........................ 991 3 H T PRITCHARD............... 658,621 63,329 51 49 IN........................ 991 4 H T PRITCHARD............... 896,604 77,817 70 60 IN........................ 991 5 H T PRITCHARD............... 870,970 75,592 68 58 IN........................ 991 6 H T PRITCHARD............... 2,568,694 222,938 199 171

IN........................ 6213 1SG1 MEROM....................... 16,068,534 1,640,316 1,247 1,260 IN........................ 6213 2SG1 MEROM....................... 19,329,452 1,986,175 1,500 1,525 IN........................ 997 12 MICHIGAN CITY............... 11,955,128 1,210,523 928 930 IN........................ 997 4 MICHIGAN CITY............... 202,787 19,131 16 15 IN........................ 997 5 MICHIGAN CITY............... 125,850 11,873 10 9 IN........................ 997 6 MICHIGAN CITY............... 193,869 18,289 15 14 IN........................ 1007 1 NOBLESVILLE................. 348,522 33,512 27 26 IN........................ 1007 2 NOBLESVILLE................. 363,142 34,917 28 27 IN........................ 1007 3 NOBLESVILLE................. 385,596 37,077 30 28 IN........................ 994 1 PETERSBURG.................. 7,083,983 684,575 550 526 IN........................ 994 2 PETERSBURG.................. 14,305,783 1,382,468 1,110 1,062 IN........................ 994 3 PETERSBURG.................. 16,278,783 1,573,133 1,263 1,208 IN........................ 994 4 PETERSBURG.................. 16,288,351 1,574,058 1,264 1,209 IN........................ 7335 --RCT1 RICHMOND.................... 67,490 4,736 5 4 IN........................ 7335 --RCT2 RICHMOND.................... 67,490 4,736 5 4 IN........................ 6166 MB1 ROCKPORT.................... 43,122,887 4,412,903 3,346 3,389 IN........................ 6166 MB2 ROCKPORT.................... 45,949,908 4,683,032 3,565 3,596 IN........................ 6085 14 SCHAHFER.................... 12,148,297 1,235,336 943 949 IN........................ 6085 15 SCHAHFER.................... 14,443,963 1,443,963 1,121 1,109 IN........................ 6085 --16A SCHAHFER.................... 147,909 11,205 11 9 IN........................ 6085 --16B SCHAHFER.................... 145,983 11,059 11 8 IN........................ 6085 17 SCHAHFER.................... 10,147,542 1,031,150 787 792 IN........................ 6085 18 SCHAHFER.................... 9,033,005 925,987 701 711 IN........................ 981 3 STATE LINE.................. 4,973,309 527,225 386 405 IN........................ 981 4 STATE LINE.................. 5,883,063 631,027 456 485 IN........................ 988 U1 TANNERS CREEK............... 3,131,631 325,770 243 250 IN........................ 988 U2 TANNERS CREEK............... 3,098,674 328,493 240 252 IN........................ 988 U3 TANNERS CREEK............... 4,041,085 434,899 314 334 IN........................ 988 U4 TANNERS CREEK............... 11,950,298 1,394,271 927 1,071 IN........................ 1010 1 WABASH RIVER................ 851,343 94,804 66 73 IN........................ 1010 2 WABASH RIVER................ 1,727,253 167,046 134 128 IN........................ 1010 3 WABASH RIVER................ 1,705,031 163,067 132 125 IN........................ 1010 4 WABASH RIVER................ 2,662,911 254,678 207 196 IN........................ 1010 5 WABASH RIVER................ 1,897,229 176,536 147 136 IN........................ 1010 6 WABASH RIVER................ 7,024,392 683,706 545 525 IN........................ 6705 1 WARRICK..................... 3,774,805 362,962 293 279 IN........................ 6705 2 WARRICK..................... 3,986,462 383,314 309 294 IN........................ 6705 3 WARRICK..................... 4,055,995 390,000 315 299 IN........................ 6705 4 WARRICK..................... 11,135,585 1,098,184 864 843 IN........................ 1040 1 WHITEWATER VALLEY........... 971,576 93,421 75 72 IN........................ 1040 2 WHITEWATER VALLEY........... 1,877,419 168,122 146 129 KY........................ 1353 BSU1 BIG SANDY................... 7,613,037 812,057 609 655 KY........................ 1353 BSU2 BIG SANDY................... 22,241,768 2,407,118 1,781 1,942 KY........................ 1363 4 CANE RUN.................... 4,925,774 444,084 394 358 KY........................ 1363 5 CANE RUN.................... 4,304,294 417,487 345 337 KY........................ 1363 6 CANE RUN.................... 5,587,828 543,616 447 439 KY........................ 1384 1 COOPER...................... 2,306,853 231,658 185 187 KY........................ 1384 2 COOPER...................... 4,882,718 478,651 391 386 KY........................ 6823 W1 D B WILSON.................. 14,381,701 1,449,768 1,151 1,170 KY........................ 1385 3 DALE........................ 1,906,453 159,723 153 129 KY........................ 1385 4 DALE........................ 1,935,939 164,202 155 132 KY........................ 1355 1 E W BROWN................... 2,464,832 222,357 197 179 KY........................ 1355 2 E W BROWN................... 4,028,960 405,859 323 327 KY........................ 1355 3 E W BROWN................... 10,080,565 954,870 807 770 KY........................ 1355 5 E W BROWN................... 188,516 14,282 15 12 KY........................ 1355 6 E W BROWN................... 188,516 14,282 15 12 KY........................ 1355 7 E W BROWN................... 188,516 14,282 15 12 KY........................ 6018 2 EAST BEND................... 19,048,549 1,915,390 1,525 1,545 KY........................ 1374 1 ELMER SMITH................. 5,140,226 513,099 412 414 KY........................ 1374 2 ELMER SMITH................. 9,068,247 1,021,659 726 824 KY........................ 1356 2 GHENT....................... 13,610,812 1,345,607 1,090 1,086 KY........................ 1356 3 GHENT....................... 13,909,380 1,328,372 1,114 1,072 KY........................ 1356 4 GHENT....................... 14,120,228 1,415,846 1,130 1,142 KY........................ 1357 1 GREEN RIVER................. 312,489 30,047 25 24 KY........................ 1357 2 GREEN RIVER................. 313,882 30,181 25 24 KY........................ 1357 3 GREEN RIVER................. 300,246 28,870 24 23 KY........................ 1357 4 GREEN RIVER................. 2,445,115 199,422 196 161 KY........................ 1357 5 GREEN RIVER................. 2,133,890 190,356 171 154 KY........................ 6041 1 H L SPURLOCK................ 9,369,673 933,792 750 753 KY........................ 6041 2 H L SPURLOCK................ 19,888,084 2,012,964 1,592 1,624 KY........................ 1372 6 HENDERSON I................. 424,577 40,825 34 33 KY........................ 1382 H1 HMP&L STATION 2............. 4,765,405 466,282 382 376 KY........................ 1382 H2 HMP&L STATION 2............. 5,002,527 490,925 400 396 KY........................ 1381 C1 K C COLEMAN................. 4,738,308 471,005 379 380 KY........................ 1381 C2 K C COLEMAN................. 5,366,408 527,411 430 426 KY........................ 1381 C3 K C COLEMAN................. 4,937,546 480,306 395 388

KY........................ 1364 1 MILL CREEK.................. 7,116,202 701,035 570 566 KY........................ 1364 2 MILL CREEK.................. 7,466,807 706,749 598 570 KY........................ 1364 3 MILL CREEK.................. 12,691,840 1,234,015 1,016 996 KY........................ 1364 4 MILL CREEK.................. 14,102,495 1,387,495 1,129 1,119 KY........................ 1378 1 PARADISE.................... 21,860,472 2,197,916 1,750 1,773 KY........................ 1378 2 PARADISE.................... 24,632,519 2,476,626 1,972 1,998 KY........................ 1378 3 PARADISE.................... 27,629,156 2,743,437 2,212 2,213 KY........................ 1360 3 PINEVILLE................... 588,364 56,573 47 46 KY........................ 1383 R1 R A REID.................... 462,060 41,072 37 33 KY........................ 6639 G1 R D GREEN................... 8,342,047 809,122 668 653 KY........................ 6639 G2 R D GREEN................... 7,435,113 714,228 595 576 KY........................ 1379 1 SHAWNEE..................... 4,299,562 426,671 344 344 KY........................ 1379 10 SHAWNEE..................... 10,578,503 993,473 847 802 KY........................ 1379 2 SHAWNEE..................... 4,324,438 429,139 346 346 KY........................ 1379 3 SHAWNEE..................... 4,428,585 439,475 355 355 KY........................ 1379 4 SHAWNEE..................... 4,240,262 420,786 339 339 KY........................ 1379 5 SHAWNEE..................... 4,409,569 437,587 353 353 KY........................ 1379 6 SHAWNEE..................... 7,296,781 724,102 584 584 KY........................ 1379 7 SHAWNEE..................... 8,781,086 871,399 703 703 KY........................ 1379 8 SHAWNEE..................... 5,000,057 496,185 400 400 KY........................ 1379 9 SHAWNEE..................... 5,884,725 583,976 471 471 KY........................ 6071 1 TRIMBLE COUNTY.............. 16,103,567 1,599,321 1,289 1,290 KY........................ 1361 1 TYRONE...................... 35,370 3,337 3 3 KY........................ 1361 3 TYRONE...................... 35,800 3,377 3 3 KY........................ 1361 4 TYRONE...................... 36,606 3,453 3 3 KY........................ 1361 5 TYRONE...................... 1,019,264 82,685 82 67 MA........................ 50002 CC__(*) ALTRESCO (PITTSFIELD) (*)... 1,121,457 131,936 114 130 MA........................ 50002 CS__(*) ALTRESCO (PITTSFIELD) (*)... 587,755 69,148 60 68 MA........................ 1619 1 BRAYTON POINT............... 7,692,885 785,068 783 773 MA........................ 1619 2 BRAYTON POINT............... 7,497,386 790,530 763 778 MA........................ 1619 3 BRAYTON POINT............... 18,238,259 2,030,082 1,857 1,999 MA........................ 1619 4 BRAYTON POINT............... 5,455,025 511,969 555 504 MA........................ 1599 1 CANAL....................... 11,606,453 1,290,897 1,182 1,271 MA........................ 1599 2 CANAL....................... 10,108,445 1,024,989 1,029 1,009 MA........................ 1682 8 CLEARY FLOOD................ 80,600 6,037 8 6 MA........................ 1682 9 CLEARY FLOOD................ 902,365 102,170 92 101 MA........................ 52026 CA__(*) DARTMOUTH POWER ASSOC (*)... 741,248 66,779 75 66 MA........................ 10029 1 GE COMPANY AIRCRAFT ENGIN... 61,457 4,656 6 5 MA........................ 54586 CC__gia L'ENERGIA................... 876,770 78,988 89 78 MA........................ 10802 1 LOWELL COGENERATION PLANT... 155,520 10,914 16 11 MA........................ 10726 CC__to) MASS POWER (MONSANTO)....... 1,586,869 186,690 162 184 MA........................ 10726 CW__to) MASS POWER (MONSANTO)....... 549,347 64,629 56 64 MA........................ n89 CC__r 1 MASS POWER 1................ 304,660 27,447 31 27 MA........................ n90 CC__r 2 MASS POWER 2................ 304,660 27,447 31 27 MA........................ 1606 1 MOUNT TOM................... 4,711,387 490,616 480 483 MA........................ 1588 4 MYSTIC...................... 1,376,669 139,452 140 137 MA........................ 1588 5 MYSTIC...................... 648,038 60,132 66 59 MA........................ 1588 6 MYSTIC...................... 2,194,462 222,539 223 219 MA........................ 1588 7 MYSTIC...................... 11,802,193 1,229,779 1,202 1,211 MA........................ 1589 1 NEW BOSTON.................. 8,789,339 902,674 895 889 MA........................ 1589 2 NEW BOSTON.................. 9,365,437 952,643 954 938 MA........................ n91 CC__& 2 NORTHEAST ENERGY ASSO 1 &... 3,296,081 387,774 336 382 MA........................ 10522 CC__(*) PEPPERELL (*)............... 376,614 33,929 38 33 MA........................ 1660 --CC2 POTTER STATION 2............ 548,078 49,376 56 49 MA........................ 1626 1 SALEM HARBOR................ 2,754,313 264,711 280 261 MA........................ 1626 2 SALEM HARBOR................ 3,089,594 291,471 315 287 MA........................ 1626 3 SALEM HARBOR................ 5,059,490 490,641 515 483 MA........................ 1626 4 SALEM HARBOR................ 6,294,731 594,123 641 585 MA........................ 1613 8 SOMERSET.................... 3,209,854 294,293 327 290 MA........................ 6081 --1 STONY BROOK................. 90,418 6,850 9 7 MA........................ 6081 --2 STONY BROOK................. 90,418 6,850 9 7 MA........................ 6081 --CT1 STONY BROOK................. 614,254 55,338 63 54 MA........................ 6081 --CT2 STONY BROOK................. 614,254 55,338 63 54 MA........................ 6081 --CT3 STONY BROOK................. 614,254 55,338 63 54 MA........................ 6081 --CW1 STONY BROOK................. 944,989 111,175 96 109 MA........................ 1678 --2 WATERS RIVER................ 42,566 3,733 4 4 MA........................ 1642 3 WEST SPRINGFIELD............ 2,006,248 196,210 204 193 MD........................ 10483 ST NUG BETHLEHEM STEEL NUG........ 3,625,254 342,005 342 313 MD........................ 602 1 BRANDON SHORES.............. 21,502,167 2,151,938 2,029 1,971 MD........................ 602 2 BRANDON SHORES.............. 21,147,845 2,102,171 1,995 1,925 MD........................ 1552 1 C P CRANE................... 5,355,147 524,244 505 480 MD........................ 1552 2 C P CRANE................... 5,060,998 496,371 477 455 MD........................ 1571 1 CHALK POINT................. 9,223,252 993,029 870 909 MD........................ 1571 2 CHALK POINT................. 9,516,601 1,033,739 898 947 MD........................ 1571 3 CHALK POINT................. 3,368,279 316,836 318 290 MD........................ 1571 4 CHALK POINT................. 4,729,925 448,632 446 411

MD........................ 1571 --GT2 CHALK POINT................. 12,553 881 1 1 MD........................ 1571 --GT3 CHALK POINT................. 95,860 8,206 9 8 MD........................ 1571 --GT4 CHALK POINT................. 98,058 8,394 9 8 MD........................ 1571 --GT5 CHALK POINT................. 167,177 15,561 16 14 MD........................ 1571 --SGT1 CHALK POINT................. 293,306 22,220 28 20 MD........................ 1572 1 DICKERSON................... 5,087,240 538,048 480 493 MD........................ 1572 2 DICKERSON................... 5,102,377 540,392 481 495 MD........................ 1572 3 DICKERSON................... 5,232,608 564,772 494 517 MD........................ 1572 --GT2 DICKERSON................... 134,534 12,841 13 12 MD........................ 1572 --GT3 DICKERSON................... 338,557 32,314 32 30 MD........................ 1580 1 EASTON...................... 66,212 7,790 6 7 MD........................ 1553 3 GOULD STREET................ 584,029 51,766 55 47 MD........................ 1554 1 HERBERT A WAGNER............ 782,492 68,382 74 63 MD........................ 1554 2 HERBERT A WAGNER............ 4,261,160 425,350 402 390 MD........................ 1554 3 HERBERT A WAGNER............ 7,769,439 849,583 733 778 MD........................ 1554 4 HERBERT A WAGNER............ 1,818,482 165,512 172 152 MD........................ 1573 1 MORGANTOWN.................. 14,211,706 1,571,049 1,341 1,439 MD........................ 1573 2 MORGANTOWN.................. 15,148,826 1,673,164 1,429 1,532 MD........................ 1573 --GT3 MORGANTOWN.................. 106,208 7,453 10 7 MD........................ 1573 --GT4 MORGANTOWN.................. 107,406 7,537 10 7 MD........................ 1573 --GT5 MORGANTOWN.................. 108,314 7,601 10 7 MD........................ 1573 --GT6 MORGANTOWN.................. 96,013 6,738 9 6 MD........................ 1556 --GT1 PERRYMAN.................... 51,532 3,616 5 3 MD........................ 1556 --GT2 PERRYMAN.................... 58,312 4,092 6 4 MD........................ 1556 --GT3 PERRYMAN.................... 36,459 2,558 3 2 MD........................ 1556 --GT4 PERRYMAN.................... 56,510 3,966 5 4 MD........................ 1570 11 R P SMITH................... 1,374,337 138,836 130 127 MD........................ 1570 9 R P SMITH................... 87,168 8,381 8 8 MD........................ 1559 4 RIVERSIDE................... 302,110 26,943 29 25 MD........................ 1559 --GT6 RIVERSIDE................... 74,446 5,224 7 5 MD........................ 1564 8 VIENNA...................... 1,495,451 137,601 141 126 MD........................ 1560 --GT5 WESTPORT.................... 214,627 15,062 20 14 MI........................ 7268 --7 491 E. 48TH STREET.......... 7,914 660 1 0 MI........................ 7268 --8 491 E. 48TH STREET.......... 13,441 1,120 1 1 MI........................ 10819 CA__Ltd ADA COGEN LTD............... 318,649 28,707 24 21 MI........................ 1695 4 B C COBB.................... 4,719,074 480,313 349 344 MI........................ 1695 5 B C COBB.................... 4,419,640 448,694 327 321 MI........................ 6034 1 BELLE RIVER................. 21,840,775 2,211,948 1,615 1,584 MI........................ 6034 2 BELLE RIVER................. 23,002,097 2,343,566 1,701 1,678 MI........................ 1702 1 DAN E KARN.................. 6,515,728 696,944 482 499 MI........................ 1702 2 DAN E KARN.................. 7,211,347 773,584 533 554 MI........................ 1702 3 DAN E KARN.................. 2,601,938 239,193 192 171 MI........................ 1702 4 DAN E KARN.................. 2,725,268 227,732 202 163 MI........................ 1831 1 ECKERT STATION.............. 495,985 47,691 37 34 MI........................ 1831 2 ECKERT STATION.............. 335,803 30,561 25 22 MI........................ 1831 3 ECKERT STATION.............. 587,998 53,866 43 39 MI........................ 1831 4 ECKERT STATION.............. 988,838 92,718 73 66 MI........................ 1831 5 ECKERT STATION.............. 1,121,036 103,027 83 74 MI........................ 1831 6 ECKERT STATION.............. 1,340,375 124,732 99 89 MI........................ 1832 1 ERICKSON.................... 5,079,491 526,863 376 377 MI........................ 6035 1 GREENWOOD................... 1,565,824 164,685 116 118 MI........................ 1731 1 HARBOR BEACH................ 768,833 74,818 57 54 MI........................ 1825 3 J B SIMS.................... 1,749,713 158,863 129 114 MI........................ 1720 7 J C WEADOCK................. 4,214,462 426,565 312 305 MI........................ 1720 8 J C WEADOCK................. 4,265,849 432,028 315 309 MI........................ 1710 1 J H CAMPBELL................ 6,547,409 700,108 484 501 MI........................ 1710 2 J H CAMPBELL................ 8,517,252 903,879 630 647 MI........................ 1710 3 J H CAMPBELL................ 21,544,630 2,314,387 1,593 1,657 MI........................ 1723 1 J R WHITING................. 2,881,534 285,413 213 204 MI........................ 1723 2 J R WHITING................. 2,627,628 262,947 194 188 MI........................ 1723 3 J R WHITING................. 3,273,683 325,869 242 233 MI........................ 1830 5 JAMES DE YOUNG.............. 915,620 73,250 68 52 MI........................ n100 CA__act MCV CONTRACT................ 10,055,262 1,182,972 744 847 MI........................ 10745 1 MIDLAND COGENERATION VENT... 5,869,080 444,627 434 318 MI........................ 1822 5 MISTERSKY................... 460,030 43,399 34 31 MI........................ 1822 6 MISTERSKY................... 1,473,716 127,429 109 91 MI........................ 1822 7 MISTERSKY................... 1,315,382 111,237 97 80 MI........................ 1733 1 MONROE...................... 23,198,275 2,547,022 1,716 1,824 MI........................ 1733 2 MONROE...................... 21,371,974 2,310,733 1,581 1,654 MI........................ 1733 3 MONROE...................... 17,719,325 1,928,949 1,310 1,381 MI........................ 1733 4 MONROE...................... 17,764,880 1,924,481 1,314 1,378 MI........................ 1769 2 PRESQUE ISLE................ 282,822 27,194 21 19 MI........................ 1769 3 PRESQUE ISLE................ 1,283,250 120,504 95 86 MI........................ 1769 4 PRESQUE ISLE................ 1,217,723 114,351 90 82 MI........................ 1769 5 PRESQUE ISLE................ 2,646,645 250,392 196 179 MI........................ 1769 6 PRESQUE ISLE................ 2,753,661 260,517 204 187

MI........................ 1769 7 PRESQUE ISLE................ 2,993,352 260,314 221 186 MI........................ 1769 8 PRESQUE ISLE................ 3,044,818 264,790 225 190 MI........................ 1769 9 PRESQUE ISLE................ 2,837,888 246,794 210 177 MI........................ 1740 1 RIVER ROUGE................. 1,200,116 130,235 89 93 MI........................ 1740 2 RIVER ROUGE................. 8,017,458 871,747 593 624 MI........................ 1740 3 RIVER ROUGE................. 8,515,077 937,268 630 671 MI........................ 10272 1 ROUGE POWERHOUSE #1......... 3,189,437 300,890 236 215 MI........................ 1843 3 SHIRAS...................... 1,360,969 113,084 101 81 MI........................ 1743 1 ST CLAIR.................... 4,264,532 437,119 315 313 MI........................ 1743 2 ST CLAIR.................... 4,042,244 401,375 299 287 MI........................ 1743 3 ST CLAIR.................... 4,704,277 470,287 348 337 MI........................ 1743 4 ST CLAIR.................... 4,400,916 453,796 325 325 MI........................ 1743 5 ST CLAIR.................... 1,519,120 154,523 112 111 MI........................ 1743 6 ST CLAIR.................... 8,503,976 886,200 629 634 MI........................ 1743 7 ST CLAIR.................... 9,260,458 964,029 685 690 MI........................ 50835 ST__ity T.E.S. FILER CITY........... 1,306,965 123,299 97 88 MI........................ 1745 16 TRENTON CHANNEL............. 1,431,549 130,545 106 93 MI........................ 1745 17 TRENTON CHANNEL............. 1,420,802 136,616 105 98 MI........................ 1745 18 TRENTON CHANNEL............. 1,322,166 120,570 98 86 MI........................ 1745 19 TRENTON CHANNEL............. 1,365,139 131,263 101 94 MI........................ 1745 9A TRENTON CHANNEL............. 12,981,225 1,372,948 960 983 MI........................ 1866 7 WYANDOTTE................... 1,115,053 100,176 82 72 MO........................ 2076 1 ASBURY...................... 6,415,029 567,702 465 426 MO........................ 2132 3 BLUE VALLEY................. 430,039 41,350 31 31 MO........................ 2169 2 CHAMOIS..................... 1,523,956 139,263 110 104 MO........................ 2122 --GT1 CHILLICOTHE................. 71,595 5,024 5 4 MO........................ 2122 --GT2 CHILLICOTHE................. 71,595 5,024 5 4 MO........................ 2123 7 COLUMBIA.................... 394,045 39,229 29 29 MO........................ 6223 --1 EMPIRE ENERGY CENTER........ 179,036 13,563 13 10 MO........................ 6223 --2 EMPIRE ENERGY CENTER........ 179,036 13,563 13 10 MO........................ 6074 --4 GREENWOOD ENERGY CTR........ 111,179 8,423 8 6 MO........................ 2079 5 HAWTHORN.................... 10,761,377 1,042,971 779 782 MO........................ 6065 1 IATAN....................... 22,356,034 2,298,585 1,619 1,723 MO........................ 2161 **GT2 JAMES RIVER................. 289,660 21,944 21 16 MO........................ 2161 3 JAMES RIVER................. 1,188,818 114,309 86 86 MO........................ 2161 4 JAMES RIVER................. 1,709,250 164,351 124 123 MO........................ 2161 5 JAMES RIVER................. 2,951,438 283,792 214 213 MO........................ 2161 --GT1 JAMES RIVER................. 1,393,758 125,564 101 94 MO........................ 2103 1 LABADIE..................... 14,988,473 1,455,474 1,085 1,091 MO........................ 2103 2 LABADIE..................... 15,775,674 1,531,916 1,142 1,148 MO........................ 2103 3 LABADIE..................... 18,159,252 1,763,377 1,315 1,322 MO........................ 2103 4 LABADIE..................... 16,185,316 1,571,695 1,172 1,178 MO........................ 2098 5 LAKE ROAD................... 1,557,840 141,409 113 106 MO........................ 2098 --5 LAKE ROAD................... 1,335,767 126,016 97 94 MO........................ 2098 6 LAKE ROAD................... 1,996,600 179,228 145 134 MO........................ 2104 1 MERAMEC..................... 1,667,729 131,909 121 99 MO........................ 2104 2 MERAMEC..................... 1,737,211 137,405 126 103 MO........................ 2104 3 MERAMEC..................... 2,079,846 164,506 151 123 MO........................ 2104 4 MERAMEC..................... 3,782,385 299,168 274 224 MO........................ 6650 --1 MEXICO...................... 112,520 8,524 8 6 MO........................ 6651 --1 MOBERLY..................... 112,520 8,524 8 6 MO........................ 2080 1 MONTROSE.................... 4,826,186 421,317 349 316 MO........................ 2080 2 MONTROSE.................... 4,658,606 424,939 337 319 MO........................ 2080 3 MONTROSE.................... 4,940,056 462,076 358 346 MO........................ 6652 --1 MOREAU...................... 112,520 8,524 8 6 MO........................ 2167 1 NEW MADRID.................. 17,470,625 1,738,371 1,265 1,303 MO........................ 2167 2 NEW MADRID.................. 18,334,306 1,824,309 1,328 1,368 MO........................ 2092 --GT1 RALPH GREEN................. 129,485 9,809 9 7 MO........................ 6155 1 RUSH ISLAND................. 17,761,120 1,742,653 1,286 1,306 MO........................ 6155 2 RUSH ISLAND................. 17,280,487 1,695,495 1,251 1,271 MO........................ 2094 1 SIBLEY...................... 1,456,245 125,538 105 94 MO........................ 2094 2 SIBLEY...................... 1,473,607 139,020 107 104 MO........................ 2094 3 SIBLEY...................... 10,522,347 1,084,778 762 813 MO........................ 6768 1 SIKESTON.................... 9,450,790 895,810 684 672 MO........................ 2107 1 SIOUX....................... 10,860,579 1,004,493 786 753 MO........................ 2107 2 SIOUX....................... 10,688,852 988,610 774 741 MO........................ 6195 1 SOUTHWEST................... 6,345,132 610,109 459 457 MO........................ 6195 --2 SOUTHWEST................... 87,505 6,629 6 5 MO........................ 6195 --GT1 SOUTHWEST................... 87,505 6,629 6 5 MO........................ 7296 --1 STATELINE................... 200,888 15,219 15 11 MO........................ 2168 MB1 THOMAS HILL................. 6,124,730 603,422 443 452 MO........................ 2168 MB2 THOMAS HILL................. 8,842,764 879,877 640 660 MO........................ 2168 MB3 THOMAS HILL................. 22,827,071 2,271,350 1,653 1,703 MO........................ 50969 1 UNIVERSITY OF MISSOURI--CO.. 411 39 0 0 NC........................ 2706 1 ASHEVILLE................... 6,457,822 681,420 524 528 NC........................ 2706 2 ASHEVILLE................... 6,300,506 661,818 511 513

NC........................ 8042 1 BELEWS CREEK................ 27,520,035 3,056,084 2,233 2,367 NC........................ 8042 2 BELEWS CREEK................ 34,358,912 3,802,447 2,788 2,945 NC........................ 2720 5 BUCK........................ 673,727 64,781 55 50 NC........................ 2720 6 BUCK........................ 579,519 55,723 47 43 NC........................ 2720 7 BUCK........................ 703,911 67,684 57 52 NC........................ 2720 8 BUCK........................ 3,428,909 328,786 278 255 NC........................ 2720 9 BUCK........................ 3,583,849 343,544 291 266 NC........................ 1016 --1 BUTLER WARNER GEN PL........ 524,574 47,259 43 37 NC........................ 1016 --2 BUTLER WARNER GEN PL........ 526,516 47,434 43 37 NC........................ 1016 --3 BUTLER WARNER GEN PL........ 522,524 47,074 42 36 NC........................ 1016 --6 BUTLER WARNER GEN PL........ 556,187 50,107 45 39 NC........................ 1016 --7 BUTLER WARNER GEN PL........ 528,459 47,609 43 37 NC........................ 1016 --8 BUTLER WARNER GEN PL........ 528,459 47,609 43 37 NC........................ 1016 --9 BUTLER WARNER GEN PL........ 1,351,896 121,792 110 94 NC........................ 2708 5 CAPE FEAR................... 3,248,898 338,568 264 262 NC........................ 2708 6 CAPE FEAR................... 4,656,544 503,791 378 390 NC........................ 2721 1 CLIFFSIDE................... 537,878 51,719 44 40 NC........................ 2721 2 CLIFFSIDE................... 688,755 66,226 56 51 NC........................ 2721 3 CLIFFSIDE................... 773,399 59,233 63 46 NC........................ 2721 4 CLIFFSIDE................... 929,143 70,071 75 54 NC........................ 2721 5 CLIFFSIDE................... 12,329,411 1,241,883 1,000 962 NC........................ 10380 ST__OWN COGENTRIX ELIZABETHTOWN..... 901,695 85,066 73 66 NC........................ 10381 ST__LLE COGENTRIX KENANSVILLE....... 901,695 85,066 73 66 NC........................ 10382 ST__TON COGENTRIX LUMBERTON......... 901,695 85,066 73 66 NC........................ 10379 ST__ORO COGENTRIX ROXBORO........... 1,388,705 131,010 113 101 NC........................ 10378 ST__ORT COGENTRIX SOUTHPORT......... 2,748,984 259,338 223 201 NC........................ 10525 ST__RGY CRAVEN COUNTY WOOD ENERGY... 3,035,837 286,400 246 222 NC........................ 2723 1 DAN RIVER................... 1,279,030 96,874 104 75 NC........................ 2723 2 DAN RIVER................... 1,276,869 106,441 104 82 NC........................ 2723 3 DAN RIVER................... 2,946,742 274,601 239 213 NC........................ 2718 1 G G ALLEN................... 3,428,222 329,099 278 255 NC........................ 2718 2 G G ALLEN................... 4,045,742 380,060 328 294 NC........................ 2718 3 G G ALLEN................... 6,731,538 674,909 546 523 NC........................ 2718 4 G G ALLEN................... 6,178,650 628,614 501 487 NC........................ 2718 5 G G ALLEN................... 5,611,834 579,555 455 449 NC........................ 2713 1 L V SUTTON.................. 1,890,914 167,604 153 130 NC........................ 2713 2 L V SUTTON.................. 2,204,273 212,953 179 165 NC........................ 2713 3 L V SUTTON.................. 8,616,341 897,255 699 695 NC........................ 2709 1 LEE......................... 1,613,150 151,555 131 117 NC........................ 2709 2 LEE......................... 1,528,041 141,958 124 110 NC........................ 2709 3 LEE......................... 4,977,693 527,354 404 408 NC........................ 7277 1 LINCOLN..................... 194,033 15,796 16 12 NC........................ 7277 10 LINCOLN..................... 136,184 10,813 11 8 NC........................ 7277 11 LINCOLN..................... 152,253 12,525 12 10 NC........................ 7277 12 LINCOLN..................... 125,731 10,186 10 8 NC........................ 7277 13 LINCOLN..................... 109,354 8,284 9 6 NC........................ 7277 14 LINCOLN..................... 105,132 7,965 9 6 NC........................ 7277 15 LINCOLN..................... 104,102 7,887 8 6 NC........................ 7277 16 LINCOLN..................... 95,106 7,205 8 6 NC........................ 7277 2 LINCOLN..................... 171,449 13,856 14 11 NC........................ 7277 3 LINCOLN..................... 162,933 13,209 13 10 NC........................ 7277 4 LINCOLN..................... 158,799 12,859 13 10 NC........................ 7277 5 LINCOLN..................... 146,360 11,812 12 9 NC........................ 7277 6 LINCOLN..................... 152,529 12,241 12 9 NC........................ 7277 7 LINCOLN..................... 164,582 13,136 13 10 NC........................ 7277 8 LINCOLN..................... 148,870 11,828 12 9 NC........................ 7277 9 LINCOLN..................... 129,158 10,353 10 8 NC........................ 2727 1 MARSHALL.................... 11,833,890 1,281,695 960 993 NC........................ 2727 2 MARSHALL.................... 12,362,967 1,334,373 1,003 1,033 NC........................ 2727 3 MARSHALL.................... 20,893,735 2,350,516 1,695 1,821 NC........................ 2727 4 MARSHALL.................... 20,093,891 2,224,006 1,630 1,723 NC........................ 6250 1A MAYO........................ 16,130,087 1,687,954 1,309 1,307 NC........................ 6250 1B MAYO........................ 9,275,573 970,654 753 752 NC........................ 50555 CT__ary PANDA--ROSEMARY............. 1,775,698 208,906 144 162 NC........................ 50555 CW__ary PANDA--ROSEMARY............. 875,010 102,942 71 80 NC........................ 2732 10 RIVERBEND................... 2,853,031 279,134 232 216 NC........................ 2732 7 RIVERBEND................... 2,152,165 193,836 175 150 NC........................ 2732 8 RIVERBEND................... 2,040,229 182,228 166 141 NC........................ 2732 9 RIVERBEND................... 2,739,141 264,243 222 205 NC........................ 2712 1 ROXBORO..................... 9,164,977 989,311 744 766 NC........................ 2712 2 ROXBORO..................... 18,766,344 2,004,737 1,523 1,553 NC........................ 2712 3A ROXBORO..................... 10,378,439 1,094,195 842 847 NC........................ 2712 3B ROXBORO..................... 10,143,786 1,069,456 823 828 NC........................ 2712 4A ROXBORO..................... 9,067,144 957,460 736 742 NC........................ 2712 4B ROXBORO..................... 9,124,169 963,481 740 746 NC........................ 50509 CW__INC TEXASGULF INC............... 674,329 60,750 55 47

NC........................ 50221 ST__lle TOBACCOVILLE................ 1,159,307 109,369 94 85 NC........................ 54276 ST__ill UNC--CHAPEL HILL............ 180,339 17,013 15 13 NC........................ 2716 1 W H WEATHERSPOON............ 708,133 68,090 57 53 NC........................ 2716 2 W H WEATHERSPOON............ 839,668 80,737 68 63 NC........................ 2716 3 W H WEATHERSPOON............ 1,840,705 177,674 149 138 NJ........................ 2378 1 B L ENGLAND................. 4,173,971 421,613 391 382 NJ........................ 2378 2 B L ENGLAND................. 4,925,509 497,526 461 451 NJ........................ 2378 3 B L ENGLAND................. 897,904 87,175 84 79 NJ........................ 2397 1 BAYONNE..................... 70,640 4,957 7 4 NJ........................ 2397 2 BAYONNE..................... 70,640 4,957 7 4 NJ........................ 2399 105 BURLINGTON.................. 828,394 74,630 78 68 NJ........................ 2399 7 BURLINGTON.................. 205,362 20,243 19 18 NJ........................ 10566 ST__NUG CCLP NUG................... 5,949,938 561,315 557 509 NJ........................ 50006 CT__DEN COGEN TECH--LINDEN.......... 6,506,951 765,524 609 694 NJ........................ 50006 CW__DEN COGEN TECH--LINDEN.......... 4,254,517 500,531 398 454 NJ........................ 5083 --GT1 CUMBERLAND.................. 160,902 12,190 15 11 NJ........................ 2384 1 DEEPWATER................... 494,926 46,691 46 42 NJ........................ 2384 4 DEEPWATER................... 4,528 427 0 0 NJ........................ 2384 6 DEEPWATER................... 487,149 45,957 46 42 NJ........................ 2384 8 DEEPWATER................... 2,233,052 216,801 209 196 NJ........................ 2400 1-4A EDISON...................... 70,640 4,957 7 4 NJ........................ 2400 1-4B EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-1A EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-1B EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-2A EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-2B EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-3A EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-3B EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-4A EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 2-4B EDISON...................... 70,640 5,352 7 5 NJ........................ 2400 3-1A EDISON...................... 70,640 5,352 7 5 NJ........................ 7138 --1 FORKED RIVER................ 65,107 4,569 6 4 NJ........................ 7138 --2 FORKED RIVER................ 65,107 4,569 6 4 NJ........................ 2393 03 GILBERT..................... 549,971 51,884 51 47 NJ........................ 2393 04 GILBERT..................... 725,741 71,827 68 65 NJ........................ 2393 05 GILBERT..................... 718,266 71,087 67 64 NJ........................ 2393 06 GILBERT..................... 712,321 70,499 67 64 NJ........................ 2393 07 GILBERT..................... 693,803 68,666 65 62 NJ........................ 2393 --4 GILBERT..................... 624,436 56,256 58 51 NJ........................ 2393 --5 GILBERT..................... 624,436 56,256 58 51 NJ........................ 2393 --6 GILBERT..................... 649,956 58,555 61 53 NJ........................ 2393 --7 GILBERT..................... 624,436 56,256 58 51 NJ........................ 2393 CT GILBERT..................... 149,451 11,322 14 10 NJ........................ 2393 CT GILBERT..................... 149,451 11,322 14 10 NJ........................ 2403 1 HUDSON...................... 2,064,525 196,921 193 178 NJ........................ 2403 2 HUDSON...................... 10,284,116 1,082,994 963 981 NJ........................ n111 ST__NUG KCS NUG.................. 5,251,399 495,415 492 449 NJ........................ 2404 7 KEARNY...................... 254,120 25,185 24 23 NJ........................ 2404 8 KEARNY...................... 137,711 13,734 13 12 NJ........................ 2406 11 LINDEN...................... 191,246 18,326 18 17 NJ........................ 2406 12 LINDEN...................... 129,348 12,394 12 11 NJ........................ 2406 13 LINDEN...................... 241,488 23,140 23 21 NJ........................ 2406 2 LINDEN...................... 413,906 40,977 39 37 NJ........................ 2408 1 MERCER...................... 4,742,300 501,406 444 454 NJ........................ 2408 2 MERCER...................... 5,329,094 588,850 499 534 NJ........................ n114 CT__NUG MOBIL NUG................ 472,302 42,550 44 39 NJ........................ 7140 CC NA 2--7140.................. 2,803,715 329,849 262 299 NJ........................ n115 GT__NUG PCLP NUG................. 191,525 14,509 18 13 NJ........................ 2390 07 SAYREVILLE.................. 475,112 40,990 44 37 NJ........................ 2390 08 SAYREVILLE.................. 566,046 47,257 53 43 NJ........................ 2411 1 SEWAREN..................... 356,963 32,179 33 29 NJ........................ 2411 2 SEWAREN..................... 346,637 29,119 32 26 NJ........................ 2411 3 SEWAREN..................... 663,913 61,857 62 56 NJ........................ 2411 4 SEWAREN..................... 972,633 94,165 91 85 NJ........................ n116 GT__1 SMECO....................... 138,720 10,509 13 10 NJ........................ 54807 GT__NUG VINELAND VCLP NUG........ 76,754 5,815 7 5 NJ........................ 2385 04 WERNER...................... 165,304 15,595 15 14 NJ........................ ........... 1 ............................ 5,479,965 644,702 513 584 NY........................ 2503 114 59TH STREET................. 753,380 60,415 57 45 NY........................ 2503 115 59TH STREET................. 611,825 49,064 46 37 NY........................ 2503 GT1 59TH STREET................. 9,250 649 1 0 NY........................ 2504 120 74TH STREET................. 649,914 63,344 49 48 NY........................ 2504 121 74TH STREET................. 1,092,255 106,458 82 80 NY........................ 2504 122 74TH STREET................. 1,094,077 106,635 82 80 NY........................ 2504 GT1 74TH STREET................. 50 4 0 0 NY........................ 2504 GT2 74TH STREET................. 50 4 0 0

NY........................ 2539 1 ALBANY...................... 873,788 84,018 66 63 NY........................ 2539 2 ALBANY...................... 1,226,877 117,969 92 89 NY........................ 2539 3 ALBANY...................... 1,440,506 138,510 109 104 NY........................ 2539 4 ALBANY...................... 733,021 70,483 55 53 NY........................ n120 1 AMERICAN BRASS.............. 1,400,238 126,148 105 95 NY........................ n121 1 ANITEC...................... 752,975 52,840 57 40 NY........................ 2490 20 ARTHUR KILL................. 7,458,261 803,952 562 604 NY........................ 2490 30 ARTHUR KILL................. 5,212,390 582,325 393 438 NY........................ 2490 GT1 ARTHUR KILL................. 12,450 874 1 1 NY........................ 8906 40 ASTORIA..................... 8,441,166 887,050 636 667 NY........................ 8906 50 ASTORIA..................... 8,377,051 830,809 631 624 NY........................ 8906 GT1 ASTORIA..................... 29,250 2,053 2 2 NY........................ 8906 GT10 ASTORIA..................... 20,800 1,460 2 1 NY........................ 8906 GT11 ASTORIA..................... 20,800 1,460 2 1 NY........................ 8906 GT12 ASTORIA..................... 20,750 1,456 2 1 NY........................ 8906 GT13 ASTORIA..................... 20,750 1,456 2 1 NY........................ 8906 GT2-1 ASTORIA..................... 138,200 9,698 10 7 NY........................ 8906 GT2-2 ASTORIA..................... 138,200 9,698 10 7 NY........................ 8906 GT2-3 ASTORIA..................... 138,200 9,698 10 7 NY........................ 8906 GT2-4 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT3-1 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT3-2 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT3-3 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT3-4 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT4-1 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT4-2 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT4-3 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT4-4 ASTORIA..................... 138,150 9,695 10 7 NY........................ 8906 GT5 ASTORIA..................... 20,850 1,463 2 1 NY........................ 8906 GT7 ASTORIA..................... 20,850 1,463 2 1 NY........................ 8906 GT8 ASTORIA..................... 20,850 1,463 2 1 NY........................ 8906 GT9 ASTORIA..................... 20,850 1,463 2 1 NY........................ 2625 1 BOWLINE POINT............... 11,471,865 1,188,179 864 893 NY........................ 2625 2 BOWLINE POINT............... 5,071,722 502,101 382 377 NY........................ 25496 3 C R HUNTLEY................. 1,720,724 165,454 130 124 NY........................ 25496 4 C R HUNTLEY................. 1,980,448 190,428 149 143 NY........................ 25496 5 C R HUNTLEY................. 2,127,327 204,551 160 154 NY........................ 25496 6 C R HUNTLEY................. 2,109,123 202,800 159 152 NY........................ 25496 7 C R HUNTLEY................. 6,327,954 608,457 477 457 NY........................ 25496 8 C R HUNTLEY................. 6,424,113 617,703 484 464 NY........................ 10190 1 CETI FORT ORANGE............ 1,359,587 122,485 102 92 NY........................ 2491 001 CHARLES POLETTI............. 13,671,196 1,393,882 1,030 1,047 NY........................ 2480 1 DANSKAMMER.................. 386,587 36,471 29 27 NY........................ 2480 2 DANSKAMMER.................. 662,648 62,514 50 47 NY........................ 2480 3 DANSKAMMER.................. 3,748,001 360,385 282 271 NY........................ 2480 4 DANSKAMMER.................. 5,975,388 574,557 450 432 NY........................ 2554 1 DUNKIRK..................... 3,158,348 303,687 238 228 NY........................ 2554 2 DUNKIRK..................... 2,827,332 271,859 213 204 NY........................ 2554 3 DUNKIRK..................... 4,429,898 425,952 334 320 NY........................ 2554 4 DUNKIRK..................... 5,327,881 512,296 401 385 NY........................ 2511 10 E F BARRETT................. 4,766,731 458,340 359 344 NY........................ 2511 20 E F BARRETT................. 4,804,972 462,017 362 347 NY........................ 2493 50 EAST RIVER.................. 2,946,262 277,949 222 209 NY........................ 2493 60 EAST RIVER.................. 3,398,132 295,130 256 222 NY........................ 2493 70 EAST RIVER.................. 1,571,481 157,970 118 119 NY........................ n130 1 ENRGY INIT-ONDGA............ 1,293,731 116,552 97 88 NY........................ 2513 40 FAR ROCKAWAY................ 2,213,857 208,854 167 157 NY........................ 10464 1 FORT DRUM................... 1,333,783 125,829 100 95 NY........................ n132 1 GAS ALTERNATIVES............ 1,160,279 104,530 87 79 NY........................ 2514 40 GLENWOOD.................... 2,406,229 227,003 181 171 NY........................ 2514 50 GLENWOOD.................... 1,862,067 175,667 140 132 NY........................ 2526 13 GOUDEY...................... 2,958,418 304,615 223 229 NY........................ ........... GT1-1 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-2 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-3 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-4 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-5 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-6 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-7 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT1-8 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT2-1 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT2-2 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT2-3 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT2-4 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT2-5 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT2-6 GOWANUS..................... 35,875 2,518 3 2

NY........................ ........... GT2-7 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT2-8 GOWANUS..................... 35,875 2,518 3 2 NY........................ ........... GT3-1 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-2 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-3 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-4 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-5 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-6 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-7 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT3-8 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-1 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-2 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-3 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-4 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-5 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-6 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-7 GOWANUS..................... 35,825 2,514 3 2 NY........................ ........... GT4-8 GOWANUS..................... 35,825 2,514 3 2 NY........................ 2527 4 GREENIDGE................... 97,546 9,379 7 7 NY........................ 2527 5 GREENIDGE................... 91,780 8,825 7 7 NY........................ 2527 6 GREENIDGE................... 2,929,270 305,450 221 230 NY........................ 2529 3 HICKLING.................... 41,894 71,336 56 54 NY........................ 2529 4 HICKLING.................... 706,180 67,902 53 51 NY........................ 2496 100 HUDSON AVENUE............... 2,443,411 230,511 184 173 NY........................ 2496 71 HUDSON AVENUE............... 375,025 26,318 28 20 NY........................ 2496 72 HUDSON AVENUE............... 375,025 26,318 28 20 NY........................ 2496 81 HUDSON AVENUE............... 375,025 26,318 28 20 NY........................ 2496 82 HUDSON AVENUE............... 375,025 26,318 28 20 NY........................ 2496 GT1 HUDSON AVENUE............... 12,700 891 1 1 NY........................ 2496 GT2 HUDSON AVENUE............... 12,800 898 1 1 NY........................ 2496 GT3 HUDSON AVENUE............... 12,700 891 1 1 NY........................ 54076 1 INDECK--OLEAN............... 885,587 79,783 67 60 NY........................ 50450 1 INDECK--OSWEGO.............. 1,122,189 101,098 85 76 NY........................ 50451 6 INDECK/YERKES............... 749,551 67,527 56 51 NY........................ 50459 1 INDECK-ILION................ 546,152 49,203 41 37 NY........................ 50449 CT__SPR INDECK-SILVER SPR........... 1,096,720 98,804 83 74 NY........................ 50449 CW__SPR INDECK-SILVER SPR........... 200,548 18,067 15 14 NY........................ ........... GT1 INDIAN POINT................ 21,100 1,481 2 1 NY........................ ........... GT2 INDIAN POINT................ 21,100 1,481 2 1 NY........................ ........... GT3 INDIAN POINT................ 27,150 1,905 2 1 NY........................ 2531 1 JENNISON.................... 243,674 23,430 18 18 NY........................ 2531 2 JENNISON.................... 250,674 24,103 19 18 NY........................ 2531 3 JENNISON.................... 346,396 33,307 26 25 NY........................ 2531 4 JENNISON.................... 363,717 34,973 27 26 NY........................ n14 3CC__IRK JMC-SELKIRK................. 1,224,755 110,338 92 83 NY........................ 10620 1 KAMINE-CARTHAGE............. 928,270 83,628 70 63 NY........................ n145 1 KAMINE-GOUVNR............... 307,042 27,661 23 21 NY........................ 10618 1 KAMINE-S GLENS FL........... 920,156 82,897 69 62 NY........................ 6082 1 KINTIGH..................... 19,171,661 2,086,598 1,444 1,568 NY........................ n147 1 L.C.P. CHEMICAL............. 554,080 49,917 42 38 NY........................ 54041 CT__PR LOCKPORT COGEN PR........... 1,595,458 187,701 120 141 NY........................ 54041 CW__PR LOCKPORT COGEN PR........... 1,228,525 144,532 93 109 NY........................ 2629 3 LOVETT...................... 1,042,213 108,169 79 81 NY........................ 2629 4 LOVETT...................... 5,081,891 521,808 383 392 NY........................ 2629 5 LOVETT...................... 5,821,325 536,725 439 403 NY........................ 54592 1 MASSENA ENRG FAC............ 1,820,093 214,129 137 161 NY........................ 2535 1 MILLIKEN.................... 4,379,423 458,290 330 344 NY........................ 2535 2 MILLIKEN.................... 4,980,801 526,734 375 396 NY........................ n155 1 MRA CANTON.................. 965,559 86,987 73 65 NY........................ ........... GT1-1 NARROWS..................... 104,875 7,360 8 6 NY........................ ........... GT1-2 NARROWS..................... 104,875 7,360 8 6 NY........................ ........... GT1-3 NARROWS..................... 104,875 7,360 8 6 NY........................ ........... GT1-4 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT1-5 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT1-6 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT1-7 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT1-8 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-1 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-2 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-3 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-4 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-5 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-6 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-7 NARROWS..................... 104,925 7,363 8 6 NY........................ ........... GT2-8 NARROWS..................... 104,925 7,363 8 6 NY........................ n156 1 NESTLES..................... 1,061,226 95,606 80 72

NY........................ 2516 1 NORTHPORT................... 4,203,823 396,587 317 298 NY........................ 2516 2 NORTHPORT................... 8,438,205 796,057 636 598 NY........................ 2516 3 NORTHPORT................... 4,214,290 397,575 317 299 NY........................ 2516 4 NORTHPORT................... 9,740,685 918,933 734 691 NY........................ 2594 3 OSWEGO...................... 14,034,179 1,403,418 1,057 1,055 NY........................ 2594 6 OSWEGO...................... 2,119,991 211,999 160 159 NY........................ 54131 1 OXBOW/OCCIDENTAL............ 975,327 87,867 73 66 NY........................ 2517 3 PORT JEFFERSON.............. 3,801,379 365,517 286 275 NY........................ 2517 4 PORT JEFFERSON.............. 3,522,971 338,747 265 255 NY........................ 2500 10 RAVENSWOOD.................. 4,996,240 507,696 376 382 NY........................ 2500 20 RAVENSWOOD.................. 6,076,960 642,521 458 483 NY........................ 2500 30 RAVENSWOOD.................. 18,214,290 1,965,076 1,372 1,477 NY........................ 2500 A1 RAVENSWOOD.................. 184,113 12,920 14 10 NY........................ 2500 A2 RAVENSWOOD.................. 184,113 12,920 14 10 NY........................ 2500 A3 RAVENSWOOD.................. 184,113 12,920 14 10 NY........................ 2500 A4 RAVENSWOOD.................. 184,113 12,920 14 10 NY........................ 2500 GT1 RAVENSWOOD.................. 50 4 0 0 NY........................ 2500 GT10 RAVENSWOOD.................. 24,450 1,716 2 1 NY........................ 2500 GT11 RAVENSWOOD.................. 24,450 1,716 2 1 NY........................ 2500 GT2-1 RAVENSWOOD.................. 49,450 3,470 4 3 NY........................ 2500 GT2-2 RAVENSWOOD.................. 49,450 3,470 4 3 NY........................ 2500 GT2-3 RAVENSWOOD.................. 49,450 3,470 4 3 NY........................ 2500 GT2-4 RAVENSWOOD.................. 49,450 3,470 4 3 NY........................ 2500 GT3-1 RAVENSWOOD.................. 49,425 3,468 4 3 NY........................ 2500 GT3-2 RAVENSWOOD.................. 49,425 3,468 4 3 NY........................ 2500 GT3-3 RAVENSWOOD.................. 49,425 3,468 4 3 NY........................ 2500 GT3-4 RAVENSWOOD.................. 49,425 3,468 4 3 NY........................ 2500 GT4 RAVENSWOOD.................. 10,400 730 1 1 NY........................ 2500 GT5 RAVENSWOOD.................. 10,400 730 1 1 NY........................ 2500 GT6 RAVENSWOOD.................. 12,650 888 1 1 NY........................ 2500 GT7 RAVENSWOOD.................. 12,650 888 1 1 NY........................ 2500 GT8 RAVENSWOOD.................. 24,500 1,719 2 1 NY........................ 2500 GT9 RAVENSWOOD.................. 24,450 1,716 2 1 NY........................ n163 CC__PRO RENNSLR COGEN PRO........... 768,893 69,270 58 52 NY........................ 7314 NA1 RICHARD M FLYNN............. 3,984,856 468,807 300 352 NY........................ 7314 NA2 RICHARD M FLYNN............. 416,190 37,495 31 28 NY........................ 2640 12 ROCHESTER 3................. 1,829,750 194,571 138 146 NY........................ 2642 1 ROCHESTER 7................. 1,068,791 102,768 81 77 NY........................ 2642 2 ROCHESTER 7................. 1,565,479 150,166 118 113 NY........................ 2642 3 ROCHESTER 7................. 1,706,369 165,186 129 124 NY........................ 2642 4 ROCHESTER 7................. 2,105,925 224,728 159 169 NY........................ 8006 2 ROSETON..................... 8,971,513 897,151 676 674 NY........................ 50651 1 SALT CITY ENERGY............ 2,992,250 282,288 225 212 NY........................ 54574 1 SARANAC ENERGY CO........... 2,702,186 317,904 204 239 NY........................ 54574 2 SARANAC ENERGY CO........... 2,200,892 258,928 166 195 NY........................ 10725 2 SELKIRK..................... 2,527,299 297,329 190 223 NY........................ 10725 3 SELKIRK..................... 2,350,443 276,523 177 208 NY........................ 54593 1 SENECA PWR (OATKA).......... 1,238,728 111,597 93 84 NY........................ n170 1 SITHE GT 1.................. 4,163,470 489,820 314 368 NY........................ n171 2 SITHE GT 2.................. 4,163,470 489,820 314 368 NY........................ n172 1 SITHE STM 1................. 4,351,465 511,937 328 385 NY........................ n173 2 SITHE STM 2................. 4,351,465 511,937 328 385 NY........................ 50744 1 STERLING POWR LTD........... 876,658 66,413 66 50 NY........................ 50292 1A TBG-GRUMMAN................. 638,783 57,548 48 43 NY........................ 52056 4 TRIGEN-NDEC................. 1,038,844 98,004 78 74 NY........................ 50202 1 UDG/NIAGARA................. 1,432,269 135,120 108 102 NY........................ n182 CT__V.) US GEN (OLD RIV.)........... 1,572,572 141,673 118 106 NY........................ 7146 1 WADING RIVER................ 148,605 11,258 11 8 NY........................ 7146 2 WADING RIVER................ 148,605 11,258 11 8 NY........................ 7146 3 WADING RIVER................ 148,605 11,258 11 8 NY........................ 2502 51 WATERSIDE................... 47,565 4,487 4 3 NY........................ 2502 52 WATERSIDE................... 48,589 4,584 4 3 NY........................ 2502 61 WATERSIDE................... 1,173,263 110,685 88 83 NY........................ 2502 62 WATERSIDE................... 1,248,953 117,826 94 89 NY........................ 2502 80 WATERSIDE................... 3,482,508 328,538 262 247 NY........................ 2502 90 WATERSIDE................... 3,482,508 328,538 262 247 NY........................ 2502 GT1 WATERSIDE................... 0 0 0 0 NY........................ 50405 CT__SSE YORK WARBASSE............... 213,063 19,195 16 14 NY........................ 50405 CW__SSE YORK-WARBASSE............... 37,622 3,389 3 3 OH........................ 2835 10 ASHTABULA................... 1,098,131 85,718 79 59 OH........................ 2835 11 ASHTABULA................... 1,176,319 91,821 85 64 OH........................ 2835 7 ASHTABULA................... 4,550,476 470,236 329 325 OH........................ 2835 8 ASHTABULA................... 1,018,961 79,538 74 55 OH........................ 2835 9 ASHTABULA................... 960,698 74,990 70 52 OH........................ 2836 10 AVON LAKE................... 2,038,597 177,563 148 123 OH........................ 2836 12 AVON LAKE................... 15,236,399 1,676,540 1,103 1,160

OH........................ 2836 9 AVON LAKE................... 594,325 50,508 43 35 OH........................ 2878 1 BAY SHORE................... 3,043,524 328,887 220 228 OH........................ 2878 2 BAY SHORE................... 3,293,657 348,240 238 241 OH........................ 2878 3 BAY SHORE................... 3,102,716 335,465 225 232 OH........................ 2878 4 BAY SHORE................... 4,399,348 483,339 318 334 OH........................ 2828 1 CARDINAL.................... 14,226,732 1,607,540 1,030 1,112 OH........................ 2828 2 CARDINAL.................... 15,856,794 1,785,072 1,147 1,235 OH........................ 2828 3 CARDINAL.................... 15,180,469 1,564,191 1,099 1,082 OH........................ 2840 1 CONESVILLE.................. 2,771,211 263,473 201 182 OH........................ 2840 2 CONESVILLE.................. 2,969,788 290,671 215 201 OH........................ 2840 3 CONESVILLE.................. 2,549,626 247,081 185 171 OH........................ 2840 4 CONESVILLE.................. 14,758,742 1,565,250 1,068 1,083 OH........................ 2840 5 CONESVILLE.................. 8,165,942 810,676 591 561 OH........................ 2840 6 CONESVILLE.................. 10,207,769 987,307 739 683 OH........................ 1 DICKS CREEK................. 103,267 7,247 7 5 OH........................ 2837 1 EASTLAKE.................... 2,765,418 276,791 200 191 OH........................ 2837 2 EASTLAKE.................... 3,040,161 314,651 220 218 OH........................ 2837 3 EASTLAKE.................... 3,168,531 333,109 229 230 OH........................ 2837 4 EASTLAKE.................... 5,169,221 547,355 374 379 OH........................ 2837 5 EASTLAKE.................... 12,045,077 1,346,119 872 931 OH........................ 2857 13 EDGEWATER................... 489,049 46,589 35 32 OH........................ 2847 GT3 FRANK M TAIT................ 161,909 12,266 12 8 OH........................ 8102 1 GEN J M GAVIN............... 40,188,042 4,171,047 2,908 2,885 OH........................ 8102 2 GEN J M GAVIN............... 41,834,670 4,421,802 3,027 3,059 OH........................ 2917 9 HAMILTON.................... 1,207,309 97,797 87 68 OH........................ 2850 1 J M STUART.................. 14,907,495 1,589,116 1,079 1,099 OH........................ 2850 2 J M STUART.................. 17,977,541 1,962,185 1,301 1,357 OH........................ 2850 3 J M STUART.................. 15,142,093 1,616,018 1,096 1,118 OH........................ 2850 4 J M STUART.................. 15,822,987 1,703,411 1,145 1,178 OH........................ 6031 2 KILLEN STATION.............. 23,914,733 2,561,287 1,731 1,772 OH........................ 2876 1 KYGER CREEK................. 6,892,031 755,374 499 523 OH........................ 2876 2 KYGER CREEK................. 6,891,443 745,101 499 515 OH........................ 2876 3 KYGER CREEK................. 7,001,472 750,104 507 519 OH........................ 2876 4 KYGER CREEK................. 6,391,704 681,782 463 472 OH........................ 2876 5 KYGER CREEK................. 6,661,287 717,811 482 497 OH........................ 2838 18 LAKE SHORE.................. 2,044,475 216,989 148 150 OH........................ 10244 1 MEAD-FINE PAPER DIVISION.... 3,264,035 247,275 236 171 OH........................ 2832 5-1 MIAMI FORT.................. 238,988 22,980 17 16 OH........................ 2832 5-2 MIAMI FORT.................. 238,988 22,980 17 16 OH........................ 2832 6 MIAMI FORT.................. 4,348,442 461,863 315 320 OH........................ 2832 7 MIAMI FORT.................. 15,289,678 1,545,349 1,106 1,069 OH........................ 2832 8 MIAMI FORT.................. 14,621,880 1,508,810 1,058 1,044 OH........................ 2832 CT2 MIAMI FORT.................. 19,021 1,441 1 1 OH........................ 2872 1 MUSKINGUM RIVER............. 3,945,004 417,549 285 289 OH........................ 2872 2 MUSKINGUM RIVER............. 4,618,739 491,198 334 340 OH........................ 2872 3 MUSKINGUM RIVER............. 4,491,616 466,225 325 323 OH........................ 2872 4 MUSKINGUM RIVER............. 4,911,646 537,379 355 372 OH........................ 2872 5 MUSKINGUM RIVER............. 16,181,850 1,783,517 1,171 1,234 OH........................ 2861 1 NILES....................... 3,039,955 293,772 220 203 OH........................ 2861 2 NILES....................... 1,890,626 184,631 137 128 OH........................ 2848 H-1 O H HUTCHINGS............... 274,817 22,229 20 15 OH........................ 2848 H-2 O H HUTCHINGS............... 349,295 28,472 25 20 OH........................ 2848 H-3 O H HUTCHINGS............... 794,644 77,731 58 54 OH........................ 2848 H-4 O H HUTCHINGS............... 782,165 76,160 57 53 OH........................ 2848 H-5 O H HUTCHINGS............... 810,661 80,735 59 56 OH........................ 2848 H-6 O H HUTCHINGS............... 833,389 80,653 60 56 OH........................ 2935 13 ORRVILLE.................... 864,346 62,103 63 43 OH........................ 2843 9 PICWAY...................... 2,044,023 184,495 148 128 OH........................ 2864 1 R E BURGER.................. 167,575 16,113 12 11 OH........................ 2864 2 R E BURGER.................. 142,969 13,747 10 10 OH........................ 2864 3 R E BURGER.................. 122,673 11,795 9 8 OH........................ 2864 4 R E BURGER.................. 50,113 4,819 4 3 OH........................ 2864 5 R E BURGER.................. 202,074 19,430 15 13 OH........................ 2864 6 R E BURGER.................. 193,661 18,621 14 13 OH........................ 2864 7 R E BURGER.................. 4,456,156 418,890 322 290 OH........................ 2864 8 R E BURGER.................. 4,017,193 381,102 291 264 OH........................ 7286 1 RICHARD GORSUCH............. 2,135,351 192,652 155 133 OH........................ 7286 2 RICHARD GORSUCH............. 1,854,152 178,284 134 123 OH........................ 7286 3 RICHARD GORSUCH............. 2,050,742 185,235 148 128 OH........................ 7286 4 RICHARD GORSUCH............. 2,045,416 196,675 148 136 OH........................ 2866 1 W H SAMMIS.................. 5,405,594 563,611 391 390 OH........................ 2866 2 W H SAMMIS.................. 5,662,986 567,206 410 392 OH........................ 2866 3 W H SAMMIS.................. 5,855,268 619,343 424 428 OH........................ 2866 4 W H SAMMIS.................. 5,314,213 537,386 385 372 OH........................ 2866 5 W H SAMMIS.................. 9,236,018 962,286 668 666 OH........................ 2866 6 W H SAMMIS.................. 17,880,061 1,901,325 1,294 1,315

OH........................ 2866 7 W H SAMMIS.................. 16,613,419 1,749,333 1,202 1,210 OH........................ 6019 1 W H ZIMMER.................. 42,732,125 4,487,726 3,092 3,105 OH........................ 2830 1 WALTER C BECKJORD........... 1,981,394 193,118 143 134 OH........................ 2830 2 WALTER C BECKJORD........... 2,504,459 255,401 181 177 OH........................ 2830 4 WALTER C BECKJORD........... 4,487,860 483,085 325 334 OH........................ 2830 5 WALTER C BECKJORD........... 6,320,856 656,099 457 454 OH........................ 2830 6 WALTER C BECKJORD........... 12,195,684 1,259,885 883 872 OH........................ 2830 CT1 WALTER C BECKJORD........... 48,631 3,413 4 2 OH........................ 2830 CT2 WALTER C BECKJORD........... 48,892 3,431 4 2 OH........................ 2830 CT3 WALTER C BECKJORD........... 52,763 3,703 4 3 OH........................ 2830 CT4 WALTER C BECKJORD........... 34,330 2,409 2 2 OH........................ 7158 --GT1 WOODSDALE................... 356,991 28,457 26 20 OH........................ 7158 --GT2 WOODSDALE................... 350,509 27,940 25 19 OH........................ 7158 --GT3 WOODSDALE................... 388,436 30,963 28 21 OH........................ 7158 --GT4 WOODSDALE................... 367,016 29,256 27 20 OH........................ 7158 --GT5 WOODSDALE................... 404,361 32,233 29 22 OH........................ 7158 --GT6 WOODSDALE................... 395,892 31,558 29 22 PA........................ 10676 ST__ley AES BEAVER VALLEY........... 3,421,790 322,810 274 253 PA........................ 50279 1 ARCHBALD POWER.............. 1,408,480 98,841 113 78 PA........................ 3178 1 ARMSTRONG................... 4,811,406 473,937 386 372 PA........................ 3178 2 ARMSTRONG................... 5,037,239 536,276 404 421 PA........................ 6094 1 BRUCE MANSFIELD............. 21,390,698 2,166,585 1,716 1,700 PA........................ 6094 2 BRUCE MANSFIELD............. 21,064,812 2,148,813 1,690 1,686 PA........................ 6094 3 BRUCE MANSFIELD............. 21,549,874 2,305,292 1,728 1,808 PA........................ 3140 1 BRUNNER ISLAND.............. 7,419,682 794,994 595 624 PA........................ 3140 2 BRUNNER ISLAND.............. 9,670,357 1,068,784 776 838 PA........................ 3140 3 BRUNNER ISLAND.............. 20,738,335 2,283,455 1,663 1,791 PA........................ 10641 1 CAMBRIA COGEN............... 1,841,698 173,745 148 136 PA........................ 10641 2 CAMBRIA COGEN............... 1,883,698 177,707 151 139 PA........................ 8226 1 CHESWICK.................... 15,086,514 1,533,962 1,210 1,203 PA........................ 3118 1 CONEMAUGH................... 29,200,485 3,177,419 2,342 2,492 PA........................ 3118 2 CONEMAUGH................... 24,102,490 2,622,687 1,933 2,057 PA........................ 10870 CW__NUG CONTINENTAL COGEN NUG.... 882,161 103,784 71 81 PA........................ 3159 1 CROMBY...................... 4,546,839 439,223 365 345 PA........................ 3159 2 CROMBY...................... 2,065,179 209,302 166 164 PA........................ 3160 71 DELAWARE.................... 711,493 70,313 57 55 PA........................ 3160 81 DELAWARE.................... 753,207 64,598 60 51 PA........................ 10603 1 EBENSBURG POWER............. 2,195,697 211,125 176 166 PA........................ 3161 1 EDDYSTONE................... 7,618,327 758,798 611 595 PA........................ 3161 2 EDDYSTONE................... 8,533,347 859,783 684 674 PA........................ 3161 3 EDDYSTONE................... 1,611,083 148,173 129 116 PA........................ 3161 4 EDDYSTONE................... 2,093,154 189,804 168 149 PA........................ 3098 1 ELRAMA...................... 2,821,678 233,776 226 183 PA........................ 3098 2 ELRAMA...................... 2,355,589 191,247 189 150 PA........................ 3098 3 ELRAMA...................... 2,802,309 257,992 225 202 PA........................ 3098 4 ELRAMA...................... 5,460,730 520,764 438 408 PA........................ 10343 AB__NUG FOSTER WHEELER MT. CARMEL... 984,307 92,859 79 73 PA........................ 01011 AB__NUG GILBERTON POWER NUG...... 2,938,728 277,238 236 217 PA........................ 3110 1--3 GPT GENCO HUNTERSTOWN....... 0 0 0 0 PA........................ 3199 1--2 GPU GENCO BENTON............ 0 0 0 0 PA........................ 3109 1 GPU GENCO HAMILTON.......... 0 0 0 0 PA........................ 3111 1--2 GPU GENCO MOUNTAIN.......... 0 0 0 0 PA........................ 3112 1 GPU GENCO ORTANNA........... 0 0 0 0 PA........................ 3114 1 GPU GENCO SHAWNEE........... 0 0 0 0 PA........................ 3120 1 GPU GENCO TIOGA............. 0 0 0 0 PA........................ 3116 1--2 GPU GENCO TOLNA............. 0 0 0 0 PA........................ 3134 1 GPU GENCO WAYNE............. 0 0 0 0 PA........................ 54785 1--3 GRAYS FERRY PROJECT......... 0 0 0 0 PA........................ 3179 1 HATFIELD'S FERRY............ 15,310,890 1,600,888 1,228 1,256 PA........................ 3179 2 HATFIELD'S FERRY............ 19,368,646 2,104,144 1,553 1,651 PA........................ 3179 3 HATFIELD'S FERRY............ 14,202,486 1,547,617 1,139 1,214 PA........................ 3145 17 HOLTWOOD.................... 3,106,258 246,665 249 193 PA........................ 3122 1 HOMER CITY.................. 19,827,390 2,093,927 1,590 1,643 PA........................ 3122 2 HOMER CITY.................. 20,699,247 2,187,156 1,660 1,716 PA........................ 3122 3 HOMER CITY.................. 18,602,194 1,901,482 1,492 1,492 PA........................ 3176 6 HUNLOCK PWR STATION......... 1,764,784 133,980 142 105 PA........................ 3136 1 KEYSTONE.................... 28,703,322 3,021,402 2,302 2,370 PA........................ 3136 2 KEYSTONE.................... 28,430,610 2,992,696 2,280 2,348 PA........................ 3157 10 KIMBERLY-CLARK.............. 0 0 0 0 PA........................ 3148 1 MARTINS CREEK............... 4,229,014 384,211 339 301 PA........................ 3148 2 MARTINS CREEK............... 3,949,723 360,804 317 283 PA........................ 3148 3 MARTINS CREEK............... 3,869,537 408,740 310 321 PA........................ 3148 4 MARTINS CREEK............... 4,010,953 425,475 322 334 PA........................ 52149 1 MERCK SHARP & DOHME......... 0 0 0 0 PA........................ 3181 1 MITCHELL.................... 75,203 7,095 6 6 PA........................ 3181 3 MITCHELL.................... 45,707 4,312 4 3

PA........................ 3181 33 MITCHELL.................... 5,833,720 592,436 468 465 PA........................ 3149 1 MONTOUR..................... 18,421,287 2,017,666 1,477 1,583 PA........................ 3149 2 MONTOUR..................... 21,572,636 2,426,345 1,730 1,903 PA........................ 3138 3 NEW CASTLE.................. 2,045,707 197,177 164 155 PA........................ 3138 4 NEW CASTLE.................. 2,265,637 211,485 182 166 PA........................ 3138 5 NEW CASTLE.................. 3,307,970 318,105 265 250 PA........................ 54571 CC__AB) NORCON(FALC SEAB)........... 1,087,345 97,959 87 77 PA........................ 50888 1 NORTHAMPTION GENERATING..... 2,906,127 274,163 233 215 PA........................ 50039 ............................. NORTHEASTERN POWER.......... 2,530,021 238,681 203 187 PA........................ 50776 1 PANTHER CREEK............... 1,158,239 109,268 93 86 PA........................ 50776 2 PANTHER CREEK............... 1,163,341 109,749 93 86 PA........................ 880008 1--2 PECO ENERGY................. 0 0 0 0 PA........................ 8012 11 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 12 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 21 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 22 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 31 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 32 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 41 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 8012 42 PECO ENERGY CROYDEN......... 0 0 0 0 PA........................ 50731 3 PECO ENERGY FAIRLESS HILLS.. 0 0 0 0 PA........................ 3168 91 PECO ENERGY RICHMOND........ 0 0 0 0 PA........................ 3168 92 PECO ENERGY RICHMOND........ 0 0 0 0 PA........................ 3170 3--6 PECO ENERGY SOUTHWARK....... 0 0 0 0 PA........................ n218 CC__PER PENNTECH PAPER.............. 617,031 55,588 49 44 PA........................ 54144 1 PINEY CREEK................. 0 0 0 0 PA........................ 3113 1 PORTLAND.................... 3,585,481 337,870 288 265 PA........................ 3113 2 PORTLAND.................... 4,573,152 441,254 367 346 PA........................ 3113 4 PORTLAND.................... 1,570,979 184,821 126 145 PA........................ 3113 --5 PORTLAND.................... 150,505 11,402 12 9 PA........................ 3139 1--4 PP&L ALLENTOWN.............. 0 0 0 0 PA........................ 3142 1--2 PP&L FISHBACK............... 0 0 0 0 PA........................ 3143 1--4 PP&L HARRISBURG............. 0 0 0 0 PA........................ 3144 1--2 PP&L HARWOOD................ 0 0 0 0 PA........................ 3146 1--2 PP&L JENKINS................ 0 0 0 0 PA........................ 3154 1--2 PP&L WEST SHORE............. 0 0 0 0 PA........................ 3155 1--2 PP&L WILLIAMSPORT........... 0 0 0 0 PA........................ 3169 1 SCHUYLKILL.................. 1,025,090 97,721 82 77 PA........................ 880010 1 SCHUYLKILL ENERGY RESOURCES. 3,891,284 367,102 312 288 PA........................ 50607 AB__NUG SCHUYLKILL STATION (TURBI... 9,441,744 890,731 757 699 PA........................ 50974 1 SCRUBGRASS GENERATING PLANT. 2,730,403 257,585 219 202 PA........................ 50974 2 SCRUBGRASS GENERATING PLANT. 1,630,792 156,807 131 123 PA........................ 3130 12 SEWARD...................... 859,296 82,625 69 65 PA........................ 3130 14 SEWARD...................... 976,355 93,880 78 74 PA........................ 3130 15 SEWARD...................... 4,658,271 467,416 374 367 PA........................ 3131 1 SHAWVILLE................... 3,979,027 379,896 319 298 PA........................ 3131 2 SHAWVILLE................... 3,819,973 364,432 306 286 PA........................ 3131 3 SHAWVILLE................... 4,979,445 499,042 399 391 PA........................ 3131 4 SHAWVILLE................... 5,056,822 506,797 406 398 PA........................ 880013 1--6 SOLAR TURBINES.............. 0 0 0 0 PA........................ 3152 3 SUNBURY..................... 3,548,941 303,692 285 238 PA........................ 3152 4 SUNBURY..................... 3,884,437 372,394 312 292 PA........................ 3115 1 TITUS....................... 1,942,834 189,176 156 148 PA........................ 3115 2 TITUS....................... 2,007,778 193,018 161 151 PA........................ 3115 3 TITUS....................... 1,918,450 182,866 154 143 PA........................ 88000 6 1--4 TRIGEN ENERGY SANSOM........ 0 0 0 0 PA........................ ........... 1 VIKING ENERGY NORTHUMBERLAND 0 0 0 0 PA........................ 3132 1 WARREN...................... 576,001 55,385 46 43 PA........................ 3132 2 WARREN...................... 385,366 37,054 31 29 PA........................ 3132 3 WARREN...................... 543,134 44,208 44 35 PA........................ 3132 4 WARREN...................... 564,080 54,238 45 43 PA........................ 50867 1--2 WASHINGTON POWER COMPANY.... 0 0 0 0 PA........................ 50611 AB__NUG WESTWOOD ENERGY PROPERTIE... 12,527,355 879,113 1,005 690 PA........................ 50879 AB__NUG WHEELABRATOR FRACKVILLE E... 2,058,812 144,478 165 113 RI........................ ........... 1 JEPSON...................... 1,282 90 0 0 RI........................ ........... 2 JEPSON...................... 1,249 88 0 0 RI........................ ........... 3 JEPSON...................... 1,042 73 0 0 RI........................ ........... 4 JEPSON...................... 1,281 90 0 0 RI........................ 3236 10 MANCHESTER STREET........... 4,223,753 398,467 136 120 RI........................ 3236 11 MANCHESTER STREET........... 4,020,769 379,318 130 114 RI........................ 3236 9 MANCHESTER STREET........... 3,739,441 352,777 121 106 RI........................ 51030 CC__(*) OCEAN STATE 1 (*)........... 9,189,307 1,081,095 297 326 RI........................ 54324 CC__(*) OCEAN STATE 2 (*)........... 9,189,307 1,081,095 297 326 RI........................ 54056 CC__(*) PAWTUCKET POWER (*)......... 2,433,886 219,269 79 66 TN........................ 3393 1 ALLEN....................... 6,894,770 713,301 578 584 TN........................ 3393 2 ALLEN....................... 7,326,410 757,957 614 621

TN........................ 3393 3 ALLEN....................... 7,556,678 781,779 633 641 TN........................ 3396 1 BULL RUN.................... 21,275,985 2,389,755 1,783 1,958 TN........................ 3399 1 CUMBERLAND.................. 51,385,046 5,284,353 4,307 4,330 TN........................ 3399 2 CUMBERLAND.................. 55,332,549 5,690,307 4,637 4,662 TN........................ 3403 1 GALLATIN.................... 6,970,897 734,707 584 602 TN........................ 3403 2 GALLATIN.................... 6,860,771 723,100 575 592 TN........................ 3403 3 GALLATIN.................... 6,984,817 728,192 585 597 TN........................ 3403 4 GALLATIN.................... 7,834,299 816,753 657 669 TN........................ 3405 1 JOHN SEVIER................. 5,853,636 615,266 491 504 TN........................ 3405 2 JOHN SEVIER................. 5,858,042 615,729 491 504 TN........................ 3405 3 JOHN SEVIER................. 6,184,144 650,005 518 533 TN........................ 3405 4 JOHN SEVIER................. 6,114,293 642,663 512 527 TN........................ 3406 1 JOHNSONVILLE................ 3,724,159 323,840 312 265 TN........................ 3406 10 JOHNSONVILLE................ 3,681,387 351,412 309 288 TN........................ 3406 2 JOHNSONVILLE................ 3,749,100 326,009 314 267 TN........................ 3406 3 JOHNSONVILLE................ 3,666,648 318,839 307 261 TN........................ 3406 4 JOHNSONVILLE................ 3,679,462 319,953 308 262 TN........................ 3406 5 JOHNSONVILLE................ 3,640,648 322,753 305 264 TN........................ 3406 6 JOHNSONVILLE................ 3,719,286 329,724 312 270 TN........................ 3406 7 JOHNSONVILLE................ 4,680,922 446,823 392 366 TN........................ 3406 8 JOHNSONVILLE................ 4,133,749 394,592 346 323 TN........................ 3406 9 JOHNSONVILLE................ 4,006,336 382,430 336 313 TN........................ 3407 1 KINGSTON.................... 4,432,856 448,715 372 368 TN........................ 3407 2 KINGSTON.................... 4,515,371 457,068 378 374 TN........................ 3407 3 KINGSTON.................... 4,047,180 409,675 339 336 TN........................ 3407 4 KINGSTON.................... 4,494,642 454,969 377 373 TN........................ 3407 5 KINGSTON.................... 6,137,914 632,449 514 518 TN........................ 3407 6 KINGSTON.................... 5,842,656 602,025 490 493 TN........................ 3407 7 KINGSTON.................... 5,678,568 585,118 476 479 TN........................ 3407 8 KINGSTON.................... 5,801,972 597,833 486 490 TN........................ 3407 9 KINGSTON.................... 5,689,108 586,204 477 480 VA........................ 3796 3 BREMO BLUFF................. 1,756,163 158,241 163 143 VA........................ 3796 4 BREMO BLUFF................. 4,959,806 506,568 459 457 VA........................ 3803 1 CHESAPEAK................... 3,461,324 334,137 320 302 VA........................ 3803 2 CHESAPEAK................... 3,444,719 343,407 319 310 VA........................ 3803 3 CHESAPEAK................... 4,744,776 499,555 439 451 VA........................ 3803 4 CHESAPEAK................... 7,270,201 775,488 673 700 VA........................ 10017 ST--rp. CHESAPEAK CORP.............. 751,025 70,851 70 64 VA........................ 3797 3 CHESTERFIELD................ 2,394,580 216,000 222 195 VA........................ 3797 4 CHESTERFIELD................ 4,636,999 497,799 429 449 VA........................ 3797 5 CHESTERFIELD................ 9,875,438 1,104,759 914 997 VA........................ 3797 6 CHESTERFIELD................ 17,283,476 1,781,985 1,600 1,608 VA........................ 3797 --8 CHESTERFIELD................ 1,701,065 153,249 157 138 VA........................ 3775 1 CLINCH RIVER................ 6,480,271 723,406 600 653 VA........................ 3775 2 CLINCH RIVER................ 6,272,239 678,300 581 612 VA........................ 3775 3 CLINCH RIVER................ 7,143,953 798,564 661 721 VA........................ 7213 1 CLOVER...................... 9,235,814 888,059 855 801 VA........................ 10377 ST__ell COGENTRIX--HOPEWELL......... 2,275,948 214,712 211 194 VA........................ 10071 ST__uth COGENTRIX--PORTSMOUTH....... 2,617,290 246,914 242 223 VA........................ 54081 ST__d 1 COGENTRIX RICHMOND 1........ 2,628,680 247,989 243 224 VA........................ 54081 ST__d 2 COGENTRIX RICHMOND 2........ 2,127,966 200,752 197 181 VA........................ 52087 GT__LP COMMONWEALTH ATLANTIC LP.... 450,631 34,139 42 31 VA........................ 7212 --1 DARBYTOWN................... 115,229 8,729 11 8 VA........................ 7212 --2 DARBYTOWN................... 115,229 8,729 11 8 VA........................ 7212 --3 DARBYTOWN................... 115,229 8,729 11 8 VA........................ 7212 --4 DARBYTOWN................... 115,229 8,729 11 8 VA........................ 52019 CA__#1 DOSEWELL #1................. 594,931 69,992 55 63 VA........................ 52019 CT__#1 DOSEWELL #1................. 1,207,760 142,089 112 128 VA........................ 52019 CA__#2 DOSEWELL #2................. 594,931 69,992 55 63 VA........................ 52019 CT__#2 DOSEWELL #2................. 1,207,760 142,089 112 128 VA........................ 3776 51 GLEN LYN.................... 1,298,222 124,829 120 113 VA........................ 3776 52 GLEN LYN.................... 1,188,728 114,301 110 103 VA........................ 3776 6 GLEN LYN.................... 5,646,574 626,075 523 565 VA........................ 54844 CA__e 1 GORDONSVILLE 1.............. 211,614 24,896 20 22 VA........................ 54844 CT__e 1 GORDONSVILLE 1.............. 429,231 50,498 40 46 VA........................ 54844 CA__e 2 GORDONSVILLE 2.............. 214,004 25,177 20 23 VA........................ 54844 CT__e 2 GORDONSVILLE 2.............. 434,011 51,060 40 46 VA........................ 7032 --3 GRAVEL NECK................. 116,841 8,852 11 8 VA........................ 7032 4 GRAVEL NECK................. 116,841 8,852 11 8 VA........................ 7032 5 GRAVEL NECK................. 116,841 8,852 11 8 VA........................ 7032 6 GRAVEL NECK1................ 116,841 8,852 11 8 VA........................ 10633 CT__nc. HOPEWELL COGEN, INC......... 1,310,927 154,227 121 139 VA........................ 10633 CW__nc. HOPEWELL COGEN, INC......... 675,419 79,461 63 72 VA........................ 10773 ST__sta LG&E-WESTMLD ALTAVISTA...... 1,427,003 134,623 132 121 VA........................ 10771 ST__ell LG&E-WESTMLD HOPEWELL....... 1,427,003 134,623 132 121 VA........................ 10774 ST__ton LG&E-WESTMLD SOUTHAMPTON.... 1,427,003 134,623 132 121

VA........................ 52007 STurg MECKLENBURG................. 3,004,193 283,414 278 256 VA........................ 3804 3 POSSUM POINT................ 2,489,785 231,242 231 209 VA........................ 3804 4 POSSUM POINT................ 6,778,888 735,716 628 664 VA........................ 3788 1 POTOMAC RIVER............... 1,780,998 149,450 165 135 VA........................ 3788 2 POTOMAC RIVER............... 1,608,529 136,247 149 123 VA........................ 3788 3 POTOMAC RIVER............... 2,711,245 278,619 251 251 VA........................ 3788 4 POTOMAC RIVER............... 10,902,795 1,135,590 1,009 1,025 VA........................ 3788 5 POTOMAC RIVER............... 10,567,982 1,095,468 978 989 VA........................ 50813 ST__ner STONE CONTAINER............. 873,930 82,446 81 74 VA........................ 3809 1 YORKTOWN.................... 7,206,933 734,577 667 663 VA........................ 3809 2 YORKTOWN.................... 7,241,953 702,966 670 634 VA........................ 3809 3 YORKTOWN.................... 3,676,409 370,905 340 335 VA........................ ........... 1 ............................ 4,214,872 397,629 390 359 WV........................ 3942 1 ALBRIGHT.................... 705,441 58,973 46 36 WV........................ 3942 2 ALBRIGHT.................... 703,469 59,090 46 36 WV........................ 3942 3 ALBRIGHT.................... 3,366,883 325,240 221 200 WV........................ 3943 1 FORT MARTIN................. 13,735,054 1,559,384 901 960 WV........................ 3943 2 FORT MARTIN................. 13,544,284 1,466,466 889 903 WV........................ 10151 ST__own GRANT TOWN.................. 2,430,507 229,293 159 141 WV........................ 3944 1 HARRISON.................... 21,606,702 2,294,436 1,418 1,413 WV........................ 3944 2 HARRISON.................... 21,825,171 2,294,971 1,432 1,413 WV........................ 3944 3 HARRISON.................... 22,529,228 2,377,002 1,478 1,463 WV........................ 3935 1 JOHN E AMOS................. 18,733,385 2,087,285 1,229 1,285 WV........................ 3935 2 JOHN E AMOS................. 18,693,941 2,089,409 1,227 1,286 WV........................ 3935 3 JOHN E AMOS................. 24,715,234 2,677,997 1,622 1,649 WV........................ 3947 1 KAMMER...................... 5,775,301 632,702 379 390 WV........................ 3947 2 KAMMER...................... 6,520,529 709,833 428 437 WV........................ 3947 3 KAMMER...................... 6,977,907 759,376 458 468 WV........................ 3936 1 KANAWHA RIVER............... 4,385,010 479,131 288 295 WV........................ 3936 2 KANAWHA RIVER............... 3,915,227 419,414 257 258 WV........................ 3948 1 MITCHELL.................... 20,089,496 2,155,757 1,318 1,327 WV........................ 3948 2 MITCHELL.................... 17,971,393 1,950,233 1,179 1,201 WV........................ 6264 1 MOUNTAINEER (1301).......... 29,445,137 3,169,552 1,932 1,951 WV........................ 3954 1 MT STORM.................... 19,946,826 2,157,580 1,309 1,328 WV........................ 3954 2 MT STORM.................... 17,300,820 1,859,503 1,135 1,145 WV........................ 3954 3 MT STORM.................... 17,911,570 1,827,152 1,175 1,125 WV........................ 7537 1A NORTH BRANCH................ 1,606,967 112,770 105 69 WV........................ 7357 1B NORTH BRANCH................ 1,653,848 116,060 109 71 WV........................ 3938 11 PHIL SPORN.................. 3,332,224 356,045 219 219 WV........................ 3938 21 PHIL SPORN.................. 3,312,719 350,849 217 216 WV........................ 3938 31 PHIL SPORN.................. 3,501,732 367,597 230 226 WV........................ 3938 41 PHIL SPORN.................. 3,491,270 370,741 229 228 WV........................ 3938 51 PHIL SPORN.................. 10,028,012 1,123,713 658 692 WV........................ 6004 1 PLEASANTS................... 20,225,588 2,064,889 1,327 1,271 WV........................ 6004 2 PLEASANTS................... 17,354,353 1,780,299 1,139 1,096 WV........................ 3945 7 RIVESVILLE.................. 288,741 27,764 19 17 WV........................ 3945 8 RIVESVILLE.................. 741,331 63,743 49 39 WV........................ 3946 1 WILLOW ISLAND............... 905,250 82,161 59 51 WV........................ 3946 2 WILLOW ISLAND............... 3,490,911 340,245 229 209 --------------------------------------------------------------------------------------------------------------------------------------------------------

Table A.2.--Allocations to Non-EGUs by mmBtu ------------------------------------------------------------------------ Unit State Plant Point ID Unit 1995, allocations Summer HI by HI ------------------------------------------------------------------------ AL............. MEAD COATED 004 1,118,921 138 BOARD INC. AL............. GULF STATES 003 154,732 19 PAPER CORPORATION. AL............. TRANSCONTINENTAL 018 48,682 6 GAS PIPELINE CORPORATION. AL............. INTERNATIONAL 011 1,143,170 141 PAPER SIEBERT STATION. AL............. MOBILE ENERGY 001 326,785 40 SERVICES COMPANY. AL............. COURTAULDS 011 60,045 7 FIBERS INC. AL............. COURTAULDS 013 382,789 47 FIBERS INC. AL............. AMOCO CHEMICALS. 024 396,068 49 AL............. AMOCO CHEMICALS. 026 106,811 13 AL............. SOLUTIA, INC.-- 013 795,511 98 DECATUR PLANT. AL............. SOLUTIA, INC.-- 014 786,934 97 DECATUR PLANT. AL............. SOLUTIA, INC.-- 015 747,265 92 DECATUR PLANT. AL............. GENERAL ELECTRIC 005 186,487 23 CO. AL............. CERESTAR USA 020 683,593 84 DECATUR INC. AL............. GULF STATES 006 764,955 94 PAPER CORPORATION. AL............. U. S. ALLIANCE 007 649,512 80 COOSA PINES CORPORATION. AL............. U. S. ALLIANCE 008 649,512 80 COOSA PINES CORPORATION. AL............. U. S. ALLIANCE 009 649,512 80 COOSA PINES CORPORATION. AL............. U. S. ALLIANCE 010 649,512 80 COOSA PINES CORPORATION. AL............. EMPIRE COKE CO.. 001 108,543 13

AL............. CIBA SPECIALTY 010 153,000 19 CHEMICALS CORPORATION. AL............. CIBA SPECIALTY 011 36,951 5 CHEMICALS CORPORATION. AL............. OLIN CHEMICAL 003 606,282 75 CORPORATION. AL............. MACMILLAN 002 1,779,840 219 BLOEDEL PACKAGING INC. AL............. MACMILLAN 005 404,136 50 BLOEDEL PACKAGING INC. AL............. CELANESE 006 379,902 47 CORPORATION. AL............. SOLUTIA, INC.-- 016 471,731 58 DECATUR PLANT. AL............. GULF STATES 047 184,755 23 STEEL INC. AL............. DEGUSSA 004 410,502 51 CORPORATION. AL............. AMOCO CHEMICALS. 010 535,211 66 AL............. AMOCO CHEMICALS. 015 389,140 48 AL............. AMOCO CHEMICALS. 019 339,487 42 AL............. AMOCO CHEMICALS. 022 312,351 38 AL............. AMOCO CHEMICALS. 023 254,615 31 AL............. TVA COLBERT..... 008 195,178 24 AL............. TVA COLBERT..... 009 195,178 24 AL............. LAROCHE 002 220,551 27 INDUSTRIES INC. AL............. INTERNATIONAL 010 525,974 65 PAPER CO. RIVERDALE MILL. AL............. INTERNATIONAL 010 1,143,170 141 PAPER SIEBERT STATION. AL............. GULF STATES 046 184,755 23 STEEL INC. AL............. CHAMPION 016 498,838 61 INTERNATIONAL COURTLAND RD29. AL............. TVA COLBERT..... 007 195,178 24 AL............. CHAMPION 015 2,140,980 263 INTERNATIONAL COURTLAND RD29. AL............. CHAMPION 007 663,276 82 INTERNATIONAL COURTLAND RD29. AL............. JEFFERSON 008 424,359 52 SMURFIT. AL............. AMERICAN CAST 041 97,574 12 IRON PIPE COMPANY. AL............. GULF STATES 049 368,932 45 STEEL INC. AL............. TVA COLBERT..... 006 195,178 24 AL............. TVA COLBERT..... 005 195,178 24 AL............. TVA COLBERT..... 003 195,178 24 AL............. TVA COLBERT..... 002 195,178 24 AL............. FORT JAMES- 029 316,970 39 PENNINGTON, INC.. AL............. FORT JAMES- 027 783,476 96 PENNINGTON, INC.. AL............. MEAD 001 435,843 54 CONTAINERBOARD. CT............. PFIZER INC-- 010 480,420 24 CHEMICALS. CT............. FEDERAL PAPER 003 721,140 36 BOARD CO. CT............. PFIZER INC-- 012 604,860 30 CHEMICALS. CT............. PFIZER INC-- 009 332,520 17 CHEMICALS. CT............. SIMKINS 673 193,917 10 INDUSTRIES INC. CT............. DEXTER NONWOVENS P29 1,788,060 89 DIV. CT............. PRATT & WHITNEY 168 18,360 1 AIRC. CT............. PRATT & WHITNEY 167 25,500 1 AIRC. CT............. PRATT & WHITNEY 166 47,940 2 AIRC. CT............. PFIZER INC-- P01 478,380 24 CHEMICALS. CT............. PRATT & WHITNEY 164 85,680 4 AIRC. CT............. CAPITOL DISTRICT P64 264,111 13 ENERGY CENTER. CT............. PRATT & WHITNEY 163 5,100 0 AIRC. CT............. PRATT & WHITNEY. 039 353,274 18 DC............. GSA WEST HEATING 001 18,360 1 PLANT. DC............. GSA--CENTRAL 003 4,348 0 HEATING. DC............. GSA--WEST 005 182,517 9 HEATING. DC............. GSA--WEST 003 162,886 8 HEATING. DC............. GSA WEST HEATING 002 3,060 0 PLANT. DE............. DUPONT SEAFORD.. 002 931,055 61 DE............. DUPONT SEAFORD.. 001 826,012 54 DE............. CHRYSLER MOTORS. 003 257,164 17 DE............. STANDARD 001 372,919 24 CHLORINE OF DELAWARE. DE............. KRAFT GENERAL 001 695,930 45 FOODS. DE............. DUPONT SEAFORD.. 003 393,082 26 IL............. INDIAN REFINING 7211029701 587,751 69 LIMITED 7 PARTNERSHIP. IL............. ZEXEL ILINOIS, 7512015500 382,086 45 INC.--DECATUR 2 FACTORY. IL............. GRANITE CITY 7303111904 381,057 45 STEEL COMPANY. 1 IL............. AMOCO PETROLEUM 7302008303 122,977 14 ADDITIVES CO. 6 IL............. JEFFERSON 7212042600 170,544 20 SMURFIT 1 CORPORATION. IL............. A E STALEY 7302008412 918,510 107 MANUFACTURING 9 CO. IL............. GRANITE CITY 7303111904 163,392 19 STEEL COMPANY. 2 IL............. ZEXEL ILINOIS, 7512015500 127,596 15 INC.--DECATUR 1 FACTORY. IL............. ARCHER DANIELS 8506003008 1,202,940 141 MIDLAND CO EAST 1 PLANT. IL............. CENTRAL ILLINOIS 7911000101 123,227 14 PUBLIC SERVICE. 4 IL............. ARCHER DANIELS 7612004807 862,589 101 MIDLAND CO EAST 1 PLANT.

IL............. CATERPILLAR--EAS 7305053101 452,649 53 T PEORIA PLANT. 9 IL............. INDIAN REFINING 7211029701 587,751 69 LIMITED 6 PARTNERSHIP. IL............. INDIAN REFINING 7211029701 587,751 69 LIMITED 5 PARTNERSHIP. IL............. GREAT LAKES 7808007101 331,981 39 NAVAL STATION. 1 IL............. GATES RUBBER 7211101100 119,513 14 CO.--GALESBURG 2 HOSE PLANT. IL............. ARCHER DANIELS 7612004807 862,589 101 MIDLAND CO EAST 2 PLANT. IL............. NORTHWESTERN 7302082102 172,053 20 STEEL & WIRE 1 CO.. IL............. GATES RUBBER 7211101100 119,513 14 CO.--GALESBURG 1 HOSE PLANT. IL............. CLIFFORD--JACOBS 7302156500 228,634 27 FORGING CO.. 1 IL............. PEOPLES GAS 7505001900 346,415 41 LIGHT & COKE CO. 6 IL............. MOBIL JOLIET 8601000904 269,836 32 REFINING CORP. 3 IL............. MOBIL JOLIET 7211057702 207,849 24 REFINING CORP. 5 IL............. MOBIL JOLIET 7211057602 141,453 17 REFINING CORP. 1 IL............. IOWA--ILL. GAS & 7301026900 1,096,036 128 ELECTRIC CO.-- 1 MOLINE GEN. STA. IL............. UNO-VEN COMPANY. 7211024000 430,709 50 7 IL............. KRAFT FOOD 7210092100 62,027 7 INGREDIENTS 3 CORP. IL............. NORTHWESTERN 7302081901 958,524 112 STEEL & WIRE CO. 4 IL............. NORTHWESTERN 7302081901 215,027 25 STEEL & WIRE CO. 3 IL............. LAUHOFF GRAIN 7212126209 165,702 19 COMPANY. 1 IL............. PEKIN ENERGY 7302008701 769,080 90 COMPANY. 9 IL............. IOWA--ILL. GAS & 7301026900 1,096,036 128 ELECTRIC CO.-- 2 MOLINE GEN. STA. IL............. SHEREX CHEMICAL 7303213100 312,522 37 COMPANY. 1 IL............. ARCHER DANIELS 8601005602 125,864 15 MIDLAND CORN 4 SWEETENERS. IL............. UNO-VEN COMPANY. 7211025303 391,449 46 7 IL............. GENERAL ELECTRIC/ 7303110000 417,430 49 HOT POINT-- 3 RANGE DIVISIO. IL............. CHICAGO WATER 7511006600 193,415 23 DEPT--SPRINGFIE 2 LD STATION. IL............. MENTAL HEALTH 7508001800 117,781 14 DEPT--CHICAGO-R 1 EAD CENTER. IL............. COM ED--FISK 7303081801 72,327 8 STATION. 3 IL............. COM ED--FISK 7303081801 52,855 6 STATION. 2 IL............. U S STEEL--SOUTH 8201004401 849,872 99 WORKS. 4 IL............. U S STEEL--SOUTH 8201004401 872,389 102 WORKS. 3 IL............. GENERAL MILLS 7303098807 149,536 17 INC. 0 IL............. GENERAL ELECTRIC/ 7303110000 128,751 15 HOT POINT-- 6 RANGE DIVISIO. IL............. CPC 7302014604 760,959 89 INTERNATIONAL 3 INC. IL............. CPC 8805006611 139,143 16 INTERNATIONAL 8 INC. IL............. CPC 7302014704 760,959 89 INTERNATIONAL 6 INC. IL............. CPC 7302014704 819,060 96 INTERNATIONAL 5 INC. IL............. CATERPILLAR 7302118200 245,955 29 TRACTOR CO 9 AURORA PLANT. IL............. CPC 7302014604 819,060 96 INTERNATIONAL 2 INC. IL............. CPC 7302014604 819,060 96 INTERNATIONAL 1 INC.

IL............. CLIFFORD-JACOBS 7302156500 256,378 30 FORGING CO. 3 IL............. METROPOLITAN 8501007300 375,283 44 W.R.D. OF 7 GREATER CHICAGO. IL............. QUANTUM--USI 7210001601 169,166 20 DIVISION. 7 IL............. WM WRIGLEY JR 7211074600 119,513 14 CO--CHICAGO 4 PLANT. IL............. AUSTIN WESTERN 7405009800 363,736 43 DIVISION. 2 IL............. QUANTUM--USI 7210001601 149,536 17 DIVISION. 6 IL............. QUANTUM--USI 7210001601 199,189 23 DIVISION. 4 IL............. QUANTUM--USI 7210001601 397,223 46 DIVISION. 3 IL............. NALCO CHEMICAL 8501003300 171,777 20 COMPANY--CORP 4 RES CENTER. IL............. QUANTUM--USI 7212120711 654,458 77 DIVISION. 2 IL............. AMOCO CHEMICALS 7210022200 188,219 22 CORP--WILLOW 2 SPRINGS PL. IL............. QUANTUM--USI 7212120711 654,458 77 DIVISION. 0 IL............. QUANTUM--USI 7212120710 654,458 77 DIVISION. 9 IL............. QUANTUM--USI 7212120710 615,960 72 DIVISION. 8 IL............. MARATHON OIL CO 7211129105 271,265 32 ILLINOIS 6 REFINING DIV. IL............. MARATHON OIL CO 7211129105 271,265 32 ILLINOIS 5 REFINING DIV. IL............. K-FIVE SOUTH 8610004500 62,027 7 PLANT. 2 IL............. NATURAL GAS 7302022100 703,800 82 PIPELINE CO OF 4 AMERICA. IL............. QUANTUM--USI 7212120711 654,458 77 DIVISION. 1 IN............. LTV STEEL 023 577,936 104 COMPANY. IN............. LTV STEEL 024 1,178,381 213 COMPANY. IN............. LTV STEEL 022 611,423 110 COMPANY. IN............. IPALCO--PERRY K. 001 949,685 171 IN............. INLAND STEEL 320 2,437,729 440 COMPANY. IN............. IPALCO--PERRY K. 002 959,398 173 IN............. GMC-DELPHI 002 16,166 3 INTERIOR AND LIGHTING SYSTEMS. IN............. LTV STEEL 021 531,747 96 COMPANY. IN............. INLAND STEEL 330 2,245,925 405 COMPANY. IN............. INLAND STEEL 321 3,811,376 688 COMPANY. IN............. INLAND STEEL 285 311,774 56 COMPANY. IN............. IPALCO--PERRY K. 003 506,874 91 IN............. A.E. STALEY MAN. 040 1,412,496 255 CO. SOUTH PLANT. IN............. INLAND STEEL 322 9,116,363 1,645 COMPANY. IN............. IPALCO--PERRY K. 004 629,974 114 IN............. INDIANA GIRLS 003 2,031,840 367 SCHOOL. IN............ GENERAL ELECTRIC 001 7,506 1 CO. IN............ PANHANDLE 016 6,282,041 1,133 EASTERN PIPELINE CO. IN............ NATIONAL STEEL 001 719,591 130 CORP. IN............ NATIONAL STEEL 003 124,132 22 CORP. IN............ NATIONAL STEEL 004 370,664 67 CORP. IN............ INLAND STEEL 284 315,815 57 COMPANY. IN............ NEW ENERGY 003 8,648,738 1,560 COMPANY OF INDIANA. IN............ PFIZER INC...... 004 503,457 91 IN............ WESTON PAPER & 002 325,584 59 MFG. IN............ APPLIED 005 23,672 4 EXTRUSION TECHNOLOGIES, INC.. IN............ JEFFERSON 001 643,824 116 SMURFIT CORPORATION. IN............ PRAXAIR, INC.... 002 44,457 8 IN............ E.W.I. INC...... 001 18,475 3 IN............ U S STEEL CO 108 360,272 65 GARY WORKS. IN............ ALLISON 008 2,623 0 TRANSMISSION DIV PLANT 3. IN............ FRITO-LAY, INC.. 001 12,702 2 IN............ JOSEPH SEAGRAM & 009 700,650 126 SONS. IN............ SUPERIOR 002 163,392 29 LAMINATING, INC.. IN............ KIEFFER PAPER 001 38,683 7 MILLS INC.. IN............ AMOCO OIL 001 5,430,169 980 COMPANY, WHITING REFINERY. IN............ AMOCO OIL 002 153,577 28 COMPANY, WHITING REFINERY. IN............ U S STEEL CO 014 6,928 1 GARY WORKS. IN............ U S STEEL CO 028 122,400 22 GARY WORKS. IN............ U S STEEL CO 105 133,947 24 GARY WORKS.

IN............. U S STEEL CO 301 393,181 71 GARY WORKS. IN............. U S STEEL CO 405 103,925 19 GARY WORKS. IN............. U S STEEL CO 701 950,909 172 GARY WORKS. IN............. U S STEEL CO 714 405,306 73 GARY WORKS. IN............. INLAND STEEL 254 217,664 39 COMPANY. IN............. INLAND STEEL 282 297,917 54 COMPANY. IN............. INLAND STEEL 281 289,834 52 COMPANY. IN............. U S STEEL CO 104 138,566 25 GARY WORKS. IN............. INLAND STEEL 256 217,664 39 COMPANY. IN............. U S STEEL CO 718 101,038 18 GARY WORKS. IN............. INLAND STEEL 252 217,664 39 COMPANY. IN............. INLAND STEEL 217 1,013,264 183 COMPANY. IN............. U S STEEL CO 720 660,762 119 GARY WORKS. IN............. AMERICAN MAIZE 007 944,559 170 PRODUCTS COMPANY. IN............. COLGATE- 003 101,636 18 PALMOLIVE. IN............. U S STEEL CO 726 301,958 54 GARY WORKS. IN............. INLAND STEEL 283 297,917 54 COMPANY. IN............. INLAND STEEL 206 203,808 37 COMPANY. IN............. INLAND STEEL 280 289,834 52 COMPANY. KY............. GENERAL TIRE INC 001 395,491 35 KY............. WILLAMETTE 009 320,706 28 INDUSTRIES INC. KY............. ROHM & HAAS 001 3,253,549 286 KENTUCKY INC. KY............. G E APPLIANCES 001 1,072,019 94 BOILER PLANT. KY............. B F GOODRICH CO. 007 898,370 79 KY............. B F GOODRICH CO. 018 344,106 30 KY............. AIR PRODUCTS & 0AB 976,162 86 CHEMICALS. KY............. E I DUPONT INC.. 001 3,177,045 280 KY............. AGE 011 196,879 17 INTERNATIONAL, INC. KY............. AIR PRODUCTS & 0AA 831,963 73 CHEMICALS. KY............. ARMCO STEEL CORP 0G5 329,901 29 KY............. OWENSBORO GRAIN 032 797,119 70 COMPANY. KY............. PROTEIN 001 559,368 49 TECHNOLOGIES INT. KY............. ARMCO STEEL CORP 0G4 329,901 29 KY............. ARMCO STEEL CORP 0G6 329,901 29 KY............. ARMCO INC....... 020 200,390 18 KY............. ARMCO INC....... 021 200,390 18 KY............. ASHLAND OIL INC. 067 801,951 71 KY............. ARMCO INC....... 022 200,390 18 KY............. TEXAS GAS 003 618,954 54 TRANSMISSION. KY............. DOW CORNING CORP 059 2,292,113 202 KY............. ARMCO STEEL CORP 0G3 329,901 29 MA............. BAY STATE 002 1,542,240 64 STERLING. MA............. TRIGEN-BOSTON 001 678,388 28 ENERGY. MA............. NATICK 002 279,072 12 PAPERBOARD. MA............. MEDICAL 005 155,448 6 AREATOTALENG. MA............. MEDICAL 004 168,912 7 AREATOTALENG. MA............. TRIGEN-BOSTON 002 558,873 23 ENERGY. MA............. WELLESLEY 001 58,416 2 COLLEGE. MA............. BAKER 004 117,749 5 COMMODITIES. MA............. G E AIRCRAFT 003 412,488 17 ENGINES. MA............. TRIGEN-BOSTON 004 678,388 28 ENERGY. MA............. G E AIRCRAFT 007 630,125 26 ENGINES. MD............. CHESAPEAKE 002 402,696 45 PAPERBOARD COMPANY. MD............. NAVAL SURFACE 005 603,947 68 WARFARE CNTR- INDIAN HD. MD............. NAVAL SURFACE 004 603,947 68 WARFARE CNTR- INDIAN HD. MD............. BETHLEHEM STEEL. 009 904,230 102 MD............. BETHLEHEM STEEL. 008 904,230 102 MD............. WESTVACO........ 002 1,701,768 192 MD............. WESTVACO........ 001 1,647,393 185 MI............. STEELCASE INC... 0033 448,750 50 MI............. WILLIAM BEAUMONT 0010 0 0 HOSPITAL. MI............. GENERAL MOTORS 0510 46,245 5 CORP. MI............. GENERAL MOTORS 0506 265,585 30 CORP. MI............. S D WARREN CO... 0011 403,240 45 MI............. S D WARREN CO... 0003 142,030 16 MI............. WILLIAM BEAUMONT 0011 0 0 HOSPITAL. MI............. DOW CHEMICAL USA 0084 192,838 21 MI............. NATIONAL STEEL 0205 241,913 27 CORP. MI............. DOW CHEMICAL USA 0401 60,045 7 MI............. STONE CONTAINER 0001 1,386,384 154 CORP. MI............. THE REGENTS OF 0001 402,996 45 THE UNIVERSITY OF MICHIGA. MI............. THE REGENTS OF 0002 374,706 42 THE UNIVERSITY OF MICHIGA. MI............. NATIONAL STEEL 0202 165,702 18 CORP. MI............. DSC LTD......... 0006 261,543 29 MI............. ROUGE STEEL CO.. 0219 536,366 60 MI............. ROUGE STEEL CO.. 0218 302,536 34 MI............. DETROIT EDISON 0003 316,392 35 CO. MI............. GEORGIA PACIFIC 0005 1,164,554 130 CORP. MI............. NATIONAL STEEL 0201 213,623 24 CORP. MI............. CHAMPION 0002 92,198 10 INTERNATIONAL CORP.

MI............. GEORGIA PACIFIC 0004 83,717 9 CORP. MI............. MARATHON OIL 0001 320,543 36 COMPANY. MI............. MENASHA CORP.... 0024 754,568 84 MI............. MENASHA CORP.... 0025 729,532 81 MI............. ROCK TENN 0001 275,413 31 COMPANY. MI............. ROCK TENN 0002 275,413 31 COMPANY. MI............. MEAD PAPER CO... 0310 1,927,800 214 MI............. MEAD PAPER CO... 0340 1,680,893 187 MI............. CHAMPION 0015 54,272 6 INTERNATIONAL CORP. MI............. GENERAL MOTORS 0501 747,102 83 CORP. MI............. MICHIGAN STATE 0054 1,203,801 134 UNIVERSITY. MI............. JAMES RIVER 0003 957,583 107 PAPER CO INC. MI............. GREAT LAKES GAS 0005 854,018 95 TRANSMISSION. MI............. MEAD PAPER CO... 0320 949,177 106 MI............. MICHIGAN STATE 0055 803,812 89 UNIVERSITY. MI............. GENERAL MOTORS 0502 558,883 62 CORP. MI............. MICHIGAN STATE 0053 1,211,151 135 UNIVERSITY. MI............. GREAT LAKES GAS 0001 1,201,050 134 TRANSMISSION. MI............. GREAT LAKES GAS 0003 943,732 105 TRANSMISSION LTD. MI............. GENERAL MOTORS 0507 231,521 26 CORP. MI............. MICHIGAN STATE 0056 1,508,240 168 UNIVERSITY. MO............. THE DOE RUN 002 454,182 58 COMPANY--SMELTI NG. MO............. SCHUYLKILL 001 59,317 8 METALS CORPORATION. MO............. ANHEUSER BUSCH, 003 46,189 6 INC., ST.LOUIS. MO............. CHRYSLER CORP. 015 88,944 11 NORTH PLANT. MO............. MONSANTO COMPANY 001 577 0 MO............. FORD MOTOR CO... 018 82,562 11 MO............. BLUE RIVER 003 1,732 0 TREATMENT PLANT. MO............. DOE RUN COMPANY. 017 0 0 MO............. ASARCO.......... 001 28,916 4 MO............. CONTINENTAL 007 2,309 0 BAKING COMPANY. MO............. ASARCO.......... 019 215,453 28 NC............. INTERNATIONAL 004 304,251 40 PAPER: REIGELWOOD. NC............. R.J. REYNOLDS 004 1,230,528 164 TOBACCO CO.-- 0745. NC............. R.J. REYNOLDS 003 1,230,528 164 TOBACCO CO.-- 0745. NC............. R.J. REYNOLDS 002 1,230,528 164 TOBACCO CO.-- 0745. NC............. R.J. REYNOLDS 001 1,230,528 164 TOBACCO CO.-- 0745. NC............. R.J. REYNOLDS 004 394,888 53 TOBACCO--0405. NC............. R.J. REYNOLDS 003 394,888 53 TOBACCO--0405. NC............. R.J. REYNOLDS 002 394,888 53 TOBACCO--0405. NC............. WEYERHAUSER 005 1,699,090 226 COMPANY, NEW BERN MILL. NC............. INTERNATIONAL 003 334,736 45 PAPER: REIGELWOOD. NC............. FIELDCREST- 001 745,416 99 CANNON PLT 1, KANNAPOLIS. NC............. CHAMPION INT 003 1,952,688 260 CORP. NC............. FMC CORP-LITHIUM 030 631,584 84 DIV. HWY 161. NC............. R.J. REYNOLDS 001 395,544 53 TOBACCO--0405. NC............. CHAMPION 001 1,260,555 168 INTERNATIONAL CORP. ROANOKE RAP. NC............. CHAMPION INT 002 860,880 115 CORP. NC............. CHAMPION INT 001 955,128 127 CORP. NC............. CHAMPION INT 004 1,713,192 228 CORP. NC............. WEYERHAEUSER 001 2,458,162 327 PAPER CO. PLYMOUTH. NC............. WEYERHAEUSER 007 1,888,305 251 PAPER CO. PLYMOUTH. NC............. P. H. GLATFELTER 006 1,753,584 233 CO.--ECUSTA. NC............. CONE MILLS CORP- 004 342,210 46 WHITE OAK PLANT. NJ............. CHEVRON U.S.A., 43 496,897 28 INC.. NJ............. DUPONT DE 10 750,245 42 NEMOURS, E.I., & CO.. NJ............. HOFFMAN LAROCHE 7 102,729 6 INC. C/O ENVIR. NJ............. INTERNATIONAL 1 199,993 11 VEILING CORPORAT. NJ............. OWENS-BROCKWAY 1 1,116,375 62 GLASS CONTAINER. NJ............. NESTLE CO., 7 120,697 7 INC., THE. NJ............. NESTLE CO., 6 120,697 7 INC., THE. NJ............. DEGUSSA 9 146,443 8 CORPORATION- METZ DIVIS. NJ............. NEW JERSEY STEEL 1 169,934 9 CORPORATION. NJ............. DUPONT DE 7 220,757 12 NEMOURS, E.I., & CO.. NJ............. FORD MOTOR 13 1,551,857 86 COMPANY. NJ............. MERCK & CO., 2 532,593 30 INC.. NJ............. CHEVRON U.S.A., 1 149,721 8 INC.. NJ............. HERCULES 2 325,380 18 INCORPORATED. NJ............. HERCULES 1 333,540 19 INCORPORATED. NJ............. STONY BROOK 2 441,660 25 REGIONAL SEWERAGE. NJ............. BALL-INCON GLASS 1 456,814 25 PACKAGING COR. NJ............. PSE & G CO. ATTN 6 3,963,652 220 ENVIRONMETAL. NJ............. STONY BROOK 1 441,660 25 REGIONAL SEWERAGE. NJ............. GARDEN STATE 2 304,980 17 PAPER CO., INC.. NJ............. PSE & G CO. ATTN 1 5,505,816 306 ENVIRONMETAL. NJ............. PSE & G CO. ATTN 2 5,458,897 303 ENVIRONMETAL. NJ............. PSE & G CO. ATTN 3 4,606,176 256 ENVIRONMETAL. NJ............. PSE & G CO. ATTN 4 2,946,636 164 ENVIRONMETAL. NJ............. EXXON 7 199,993 11 CORPORATION. NJ............. MERCK & CO., 6 902,273 50 INC..

NJ............. EXXON 14 887,400 49 CORPORATION. NJ............. MERCK & CO., 5 775,912 43 INC.. NJ............. HOFFMAN LAROCHE 34 396,707 22 INC.. NJ............. MERCK & CO., 4 651,642 36 INC.. NJ............. MERCK & CO., 3 487,689 27 INC.. NJ............. MERCK & CO., 1 576,469 32 INC.. NJ............. EXXON 15 130,050 7 CORPORATION. NJ............. PSE & G CO. ATTN 5 2,946,636 164 ENVIRONMETAL. NJ............. GARDEN STATE 1 701,369 39 PAPER CO., INC.. NJ............. HOMASCTE COMPANY 2 2,673,335 149 NJ............. DUPONT DE 9 2,569,307 143 NEMOURS, E.I., & CO.. NJ............. GARDEN STATE 4 766,675 43 PAPER CO., INC.. NJ............. ANHEUSER-BUSCH 2 324,360 18 INCORPORATED. NJ............. GEORGIA-PACIFIC 1 148,629 8 CORPORATION. NJ............. COASTAL EAGLE 38 102,729 6 POINT OIL COMPAN. NJ............. GARDEN STATE 3 287,640 16 PAPER CO., INC.. NJ............. COASTAL EAGLE 123 331,136 18 POINT OIL COMPAN. NJ............. SCOTT PAPER 4 846,536 47 COMPANY. NJ............. SCOTT PAPER 3 644,590 36 COMPANY. NJ............. SCOTT PAPER 2 759,028 42 COMPANY. NJ............. MARINA 3 1,208,661 67 ASSOCIATES. NJ............. MARINA 2 2,143,093 119 ASSOCIATES. NJ............. MARINA 1 2,143,093 119 ASSOCIATES. NJ............. MALT PRODUCTS 1 242,614 13 CORPORATION. NJ............. PETROLEUM 20 1,536,557 85 RECYCLING, INC.. NJ............. HOMASCTE COMPANY 1 2,486,646 138 NJ............. KAMINE MILFORD 1 775,710 43 LIMITED PARTNER. NJ............. COGEN 2 365,670 20 TECHNOLOGIES--N EW JERSE. NJ............. COGEN 1 362,610 20 TECHNOLOGIES--N EW JERSE. NJ............. DUPONT DE 10 2,569,307 143 NEMOURS, E.I., & CO.. NJ............. BEST FOODS CPC 3 251,555 14 INTERNATIONAL I. NJ............. COASTAL EAGLE 39 102,729 6 POINT OIL COMPAN. NJ............. MOBIL OIL 6 953,835 53 CORPORATION. NJ............. MOBIL OIL 5 143,149 8 CORPORATION. NJ............. MOBIL OIL 4 445,797 25 CORPORATION. NJ............. MOBIL OIL 3 492,776 27 CORPORATION. NJ............. MOBIL OIL 270 127,709 7 CORPORATION. NJ............. MOBIL OIL 2 492,776 27 CORPORATION. NJ............. MOBIL OIL 1 492,776 27 CORPORATION. NJ............. COASTAL EAGLE 64 343,157 19 POINT OIL COMPAN. NJ............. COASTAL EAGLE 40 102,729 6 POINT OIL COMPAN. NY............. GEORGIA PACIFIC 001 231,568 27 CORP PLATTS. NY............. GENERAL ELECTRIC 00C 405,181 47 NY............. GENERAL ELECTRIC 02Z 393,942 46 NY............. CAMPUS PWR PLANT 006 289,170 33 OGS. NY............. KODAK PARK DIV 001 1,280,644 148 ROCHES. NY............. HOLBROOK 001 64,121 7 GENERATING STA. NY............. HOLBROOK 008 64,121 7 GENERATING STA. NY............. HOLBROOK 007 64,121 7 GENERATING STA. NY............. HOLBROOK 006 64,121 7 GENERATING STA. NY............. HOLBROOK 005 64,121 7 GENERATING STA. NY............. HOLBROOK 004 64,121 7 GENERATING STA. NY............. LEDERLE 04Y 265,593 31 LABORATORIES. NY............. HOLBROOK 002 64,121 7 GENERATING STA. NY............. HOLBROOK 00B 29,835 3 GENERATING STA. NY............. AKZO SALT-- 00F 320,027 37 WATKINS GLEN REFIN.. NY............. HUDSON RIVER 007 2,361,664 273 MILL. NY............. SILICONE 0ZZ 240,744 28 PRODUCTS DIVISION. NY............. SILICONE 02F 458,291 53 PRODUCTS DIVISION. NY............. PAPYRUS NEWTON 001 297,730 34 FALLS, INC. NY............. ALCOA MASSENA 002 148,958 17 OPERATIONS. NY............. HOLBROOK 003 64,121 7 GENERATING STA. NY............. HOLBROOK 00J 29,835 3 GENERATING STA. NY............. INDECK-YERKES 004 1,622,421 188 ENERGY SERVICES TONAWAND. NY............. IONDECK SILVER 004 305,561 35 SPRINGS ENERGY. NY............. IONDECK SILVER 001 1,092,372 126 SPRINGS ENERGY. NY............. MORTON SALT 00E 209,984 24 COMPANY. NY............. REFINED SUGARS, 00K 174,420 20 INC. NY............. SCOTT PAPER CO.. 001 69,283 8 NY............. HOLBROOK 009 64,121 7 GENERATING STA. NY............. HOLBROOK 00K 29,835 3 GENERATING STA. NY............. HOLBROOK 00A 64,121 7 GENERATING STA. NY............. HOLBROOK 00I 29,835 3 GENERATING STA. NY............. HOLBROOK 00G 29,835 3 GENERATING STA. NY............. HOLBROOK 00E 29,835 3 GENERATING STA. NY............. HOLBROOK 00D 29,835 3 GENERATING STA. NY............. HOLBROOK 00C 29,835 3 GENERATING STA. NY............. HOLBROOK 00F 29,835 3 GENERATING STA. NY............. FINCH PRUYN & CO 006 462,437 53 NY............. TICONDEROGA MILL 016 1,818,536 210 TICOND.

NY............. KODAK PARK DIV 004 4,956,513 573 ROCHES. NY............. KODAK PARK DIV 003 3,716,404 430 ROCHES. NY............. KODAK PARK DIV 002 3,510,348 406 ROCHES. NY............. ................ 002 104,229 12 NY............. BURROWS PAPER 001 344,043 40 CORP LYONSD. NY............. EAST 60TH STREET 001 644,130 74 NY............. CHAMPION 008 1,000,960 116 INTERNATIONAL CORP DEFERI. NY............. ................ 0ZZ 305,235 35 NY............. CHEVY MOTOR PLT 0ZZ 604,888 70 TONAWA. NY............. GENERAL MILLS 06V 700,740 81 INC BUFFAL. NY............. BSC BAR PRODUCTS 00E 153,000 18 DIV. LACKAW. NY............. BETHENERGY LACK 018 338,130 39 COKE LA. NY............. LEDERLE 032 265,593 31 LABORATORIES. NY............. HOLBROOK 00H 29,835 3 GENERATING STA. NY............. ................ 0ZZ 800,101 93 NY............. NESTLE FOODS 001 65,105 8 CORP.. NY............. BASF-WYANDOTTE 0ZZ 150,691 17 CORP. NY............. R. P. I......... 003 276,021 32 NY............. CHAMPION 007 1,133,560 131 INTERNATIONAL CORP DEFERI. NY............. OCCIDENTAL 006 2,448 0 CHEMICAL CORP (HOOKER CHEM. NY............. RAVENSWOOD--A--H 002 417,384 48 OUSE. NY............. RAVENSWOOD--A--H 001 417,384 48 OUSE. NY............. MILLER EASTERN 00L 298,781 35 BREWERY. NY............. A-B INC 002 175,196 20 BALDWINSVILLE BREWERY LYSAND. NY............. HOOKER EFW PLANT 0D1 690,409 80 NIAGARA. NY............. BRISTOL-MYERS 022 114,079 13 COMPANY DEWITT. NY............. OCCIDENTAL 007 27,061 3 CHEMICAL CORP (HOOKER CHEM. NY............. ROME MFG CO DIV 002 299,384 35 ROME. NY............. A-B INC 001 175,196 20 BALDWINSVILLE BREWERY LYSAND. NY............. HOOKER EFW PLANT 00C 4,896 1 NIAGARA. NY............. OSWEGO ENERGY 001 172,982 20 CENTER. NY............. HOOKER EFW PLANT 00D 965,861 112 NIAGARA. OH............. JEFFERSON B004 788,542 89 SMURFIT (FRMLY CONTAINER CORP). OH............. PORTSMOUTH B001 591,272 67 GASEOUS DIFFUSION PLANT. OH............. PORTSMOUTH B002 591,272 67 GASEOUS DIFFUSION PLANT. OH............. PORTSMOUTH B003 591,272 67 GASEOUS DIFFUSION PLANT. OH............. GREAT LAKES B004 172,630 20 SUGAR COMPANY. OH............. MIAMI PAPER B001 644,232 73 CORPORATION. OH............. GIBSONBURG B001 4,265,918 484 CANNING CO., INC.. OH............. USS/KOBE STEEL B001 957,838 109 CO.--LORAIN WORKS. OH............. MEAD CORPORATION B002 1,778,323 202 OH............. MEAD CORPORATION B003 2,144,090 243 OH............. MEAD CORPORATION B001 1,579,838 179 OH............. APPLETON PAPERS B003 716,174 81 INC.. OH............. APPLETON PAPERS B002 541,955 61 INC.. OH............. CARGILL,INC..... B004 834,821 95 OH............. USS/KOBE STEEL B013 771,928 88 CO.--LORAIN WORKS. OH............. USS/KOBE STEEL B009 574,472 65 CO.--LORAIN WORKS. OH............. USS/KOBE STEEL B005 143,185 16 CO.--LORAIN WORKS. OH............. ARISTECH B004 261,312 30 CHEMICAL CORPORATION. OH............. GEORGIA PACIFIC B004 553,860 63 ROOFING FELT PLANT. OH............. SOUTH POINT B007 862,912 98 ETHANOL. OH............. SOUTH POINT B004 862,912 98 ETHANOL. OH............. USS/KOBE STEEL B007 379,902 43 CO.--LORAIN WORKS. OH............. TIMKEN COMPANY B003 402,996 46 CANTON PLANT NO 5. OH............. ARMCO STEEL B005 898,729 102 COMPANY, L.P.. OH............. SOUTH POINT B003 862,912 98 ETHANOL. OH............. LOF CO ROSSFORD B003 273,700 31 PLANT 6. OH............. SHELL CHEMICAL B007 313,620 36 CO. OH............. SHELL CHEMICAL B005 313,620 36 CO. OH............. FRANKLIN B001 1,138,897 129 BOXBOARD CORPORATION. OH............. W C I STEEL, B001 1,323,261 150 INC.. OH............. GOODYEAR TIRE & B002 751,128 85 RUBBER CO THE PLANT 11. OH............. W C I STEEL, B004 260,389 30 INC.. OH............. TIMKEN COMPANY X001 640,291 73 CANTON PLANT NO 5. OH............. ARISTECH B005 384,754 44 CHEMICAL CORPORATION. OH............. TIMKEN COMPANY, P014 285,215 32 THE. OH............. TIMKEN COMPANY, P013 285,215 32 THE. OH............. TIMKEN COMPANY X002 169,166 19 GAMBRINUS PLANT. OH............. TIMKEN COMPANY X001 802,528 91 GAMBRINUS PLANT. OH............. ASHLAND B029 167,434 19 PETROLEUM COMPANY. OH............. CANTON DROP X001 649,528 74 FORGING & MFG CO. OH............. ARISTECH B010 530,775 60 CHEMICAL CORPORATION. OH............. ARISTECH B009 503,485 57 CHEMICAL CORPORATION. OH............. ARISTECH B006 385,401 44 CHEMICAL CORPORATION. OH............. GOODYEAR TIRE & B001 826,200 94 RUBBER CO THE PLANT 11. OH............. ARMCO STEEL P010 1,035,705 118 COMPANY L.P.. OH............. ARMCO STEEL B004 838,287 95 COMPANY, L.P.. OH............. ARMCO STEEL B003 838,287 95 COMPANY, L.P.. OH............. ARMCO STEEL 860,643 98 COMPANY, L.P.01.

OH............. ARMCO STEEL P009 1,035,705 118 COMPANY L.P.. OH............. ARMCO STEEL B010 511,020 58 COMPANY L.P.. OH............. ARMCO STEEL B009 511,020 58 COMPANY L.P.. OH............. ARMCO STEEL B008 818,504 93 COMPANY L.P.. OH............. ARMCO STEEL B007 818,504 93 COMPANY L.P.. OH............. BP CHEMICALS, B003 3,729,736 423 INC.. OH............. BP CHEMICALS, B002 532,325 60 INC.. OH............. BP CHEMICALS, B001 599,876 68 INC.. OH............. BP OIL COMPANY-- P010 1,224,000 139 LIMA REFINERY. OH............. GENERAL ELECTRIC B004 166,309 19 CO. OH............. PROCTER & GAMBLE B021 932,754 106 CO. OH............. WHEELING B004 125,864 14 PITTSBURGH STEEL STEUBENVILLE S. OH............. ARMCO STEEL P012 1,035,705 118 COMPANY L.P.. OH............. PROCTER & GAMBLE B022 5,348,925 607 CO. OH............. HENKEL CORP.-- B027 3,846,420 436 EMERY GROUP. OH............. HENKEL CORP.-- B015 681,360 77 EMERY GROUP. OH............. HENKEL CORP.-- B014 317,220 36 EMERY GROUP. OH............. ANHEUSER-BUSCH X001 302,149 34 COLUMBUS BREWERY. OH............. FAIRFIELD B003 192,697 22 RECYCLED PAPER, INC.. OH............. GENERAL ELECTRIC B002 1,240,166 141 CO. OH............. LTV STEEL B905 87,181 10 COMPANY, INC.. OH............. LTV STEEL B009 707,842 80 COMPANY, INC.. OH............. LTV STEEL B005 473,434 54 COMPANY, INC.. OH............. LTV STEEL B007 527,014 60 COMPANY, INC.. OH............. LTV STEEL B004 632,208 72 COMPANY, INC.. OH............. LTV STEEL B010 192,838 22 COMPANY, INC.. OH............. LTV STEEL B001 575,218 65 COMPANY, INC.. OH............. LTV STEEL B002 931,161 106 COMPANY, INC.. OH............. LTV STEEL B003 437,625 50 COMPANY, INC.. OH............. LTV STEEL B004 1,008,422 114 COMPANY, INC.. OH............. LTV STEEL B005 259,811 29 COMPANY, INC.. OH............. LTV STEEL B006 202,653 23 COMPANY, INC.. PA............. INTERNATIONAL 040 662,852 68 PAPER CO.. PA............. ALLIED CHEMICAL 052 844,191 87 CORP. PA............. TEXAS EASTERN 032 753,026 77 GAS PIPELINE CO. PA............. GENERAL ELECTRIC 035 627,589 65 CO.. PA............. MERCK SHARP & 039 532,174 55 DOHME. PA............. BETHLEHEM STEEL 041 639,151 66 CORP.. PA............. BETHLEHEM STEEL 042 835,995 86 CORP.. PA............. BETHLEHEM STEEL 067 1,333,002 137 CORP.. PA............. BETHLEHEM STEEL 147 3,110,558 320 CORP.. PA............. GENERAL ELECTRIC 032 1,000,620 103 CO.. PA............. SUN REFINING AND 006 450,087 46 MARKETING 1 O. PA............. SUN REFINING AND 007 740,245 76 MARKETING 1 O. PA............. SUN REFINING AND 038 549,423 57 MARKETING 1 O. PA............. SUN REFINING AND 039 549,423 57 MARKETING 1 O. PA............. PROCTER & GAMBLE 932 5,618,055 578 PAPER PRODUCTS CO.. PA............. ALLIED CHEMICAL 051 175,625 18 CORP. PA............. JEFFERSON 001 724,340 75 SMURFIT (FRMLY CONTAINER CORP). PA............. MONESSEN INC.... 031 252,039 26 PA............. PROCTER & GAMBLE 035 2,522,800 259 PAPER PRODUCTS CO.. PA............. INTERNATIONAL 037 1,029,159 106 PAPER CO.. PA............. ALLIED CHEMICAL 050 100,620 10 CORP. PA............. LTV STEEL 17 114,361 12 COMPANY--PITTSB URGH WORKS. PA............. GLATFELTER, P. 031 1,030,727 106 H. CO.. PA............. LTV STEEL 15 114,361 12 COMPANY--PITTSB URGH WORKS. PA............. LTV STEEL 19 157,590 16 COMPANY--PITTSB URGH WORKS. PA............. LTV STEEL 21 95,486 10 COMPANY--PITTSB URGH WORKS. PA............. SHENANGO IRON & 06 168,766 17 COKE WORKS. PA............. SHENANGO IRON & 09 137,678 14 COKE WORKS. PA............. BMG ASPHALT CO.. 101 30,943 3 PA............. ZINC CORPORATION 034 1,498,461 154 OF AMERICA. PA............. ZINC CORPORATION 035 1,759,488 181 OF AMERICA. PA............. UNITED STATES 043 999,098 103 STEEL CORP., THE. PA............. BP OIL, INC..... 033 1,234,200 127 PA............. PENNTECH PAPERS, 041 1,063,116 109 INC.. PA............. UNITED STATES 045 1,172,194 121 STEEL CORP., THE. PA............. PENNTECH PAPERS, 040 978,703 101 INC.. PA............. SUN REFINING & 090 2,212,658 228 MARKETING CO.. PA............. SCOTT PAPER CO.. 035 2,173,948 224 PA............. SCOTT PAPER CO.. 034 858,330 88 PA............. INTERNATIONAL 034 1,099,800 113 PAPER COMPANY. PA............. INTERNATIONAL 033 1,100,520 113 PAPER COMPANY. PA............. BETHLEHEM STEEL 132 981,509 101 CORP.. PA............. UNITED STATES 046 982,367 101 STEEL CORP., THE. TN............. EASTMAN, TENN. 002 540,192 64 CO. TN............. EASTMAN, TENN. 001 540,192 64 CO. TN............. KRAFT FOOD 003 621,815 74 INGREDIENTS CORP. TN............. HUMKO-DIV WITCO 010 453,804 54 CHEM. TN............. HUMKO-DIV WITCO 009 468,815 55 CHEM.

TN............. ARCADIAN 007 1,274,808 151 CORPORATION. TN............. E.I. DUPONT DE 011 3,364,846 398 NEMOURS & INTERMEDIATES. TN............. E.I. DUPONT DE 016 612,000 72 NEMOURS & INTERMEDIATES. TN............. E.I. DUPONT DE 013 1,453,211 172 NEMOURS & INTERMEDIATES. TN............. EASTMAN, TENN. 003 618,528 73 CO. TN............. TEXAS EASTERN 001 1,373,523 162 GAS PIPELINE GLADEVILLE. TN............. E.I. DUPONT DE 015 1,019,615 121 NEMOURS & INTERMEDIATES. TN............. EASTMAN, TENN. 004 618,528 73 CO. TN............. EASTMAN, TENN. 005 673,200 80 CO. TN............. EASTMAN, TENN. 006 673,200 80 CO. TN............. EASTMAN, TENN. 013 881,816 104 CO. TN............. EASTMAN, TENN. 014 881,816 104 CO. TN............. EASTMAN, TENN. 015 2,913,528 345 CO. TN............. EASTMAN, TENN. 016 2,913,528 345 CO. TN............. EASTMAN, TENN. 017 2,913,528 345 CO. TN............. EASTMAN, TENN. 019 2,913,528 345 CO. TN............. TENN EASTMAN CO 037 3,607,944 427 PO BOX 511 KINGSPOR. TN............. E.I. DUPONT DE 010 3,849,249 455 NEMOURS & INTERMEDIATES. TN............. MEAD CORP....... 009 1,916,449 227 TN............. EASTMAN, TENN. 018 2,913,528 345 CO. TN............. E I DUPONT DE 0P3 328,104 39 NEMOURS & CO INC. TN............. PROCTER & GAMBLE 003 2,345,808 277 CELLULOSE COMPANY, THE. TN............. TN EASTMAN INC.. 059 786,362 93 TN............. ARNOLD 006 10,751 1 ENGINEERING DEV CTR. TN............. E I DUPONT DE 0P2 1,000,824 118 NEMOURS & CO INC. TN............. BASF FIBERS HWY 008 869,725 103 160 LOWLAND. TN............. BASF FIBERS HWY 009 869,725 103 160 LOWLAND. TN............. CENTRAL SOYA.... 042 1,051,978 124 TN............. E I DUPONT...... 001 325,022 38 TN............. E I DUPONT...... 003 463,154 55 TN............. VELSICOL 018 342,389 40 CHEMICAL. TN............. PACKAGING 017 224,205 27 CORPORATION OF AMERICA. TN............. PACKAGING 018 3,522,121 416 CORPORATION OF AMERICA. TN............. CARGILL 003 1,487,976 176 CORNSTARCH. TN............. E I DUPONT DE 0P1 403,704 48 NEMOURS & CO INC. TN............. TENNECO GAS/ 001 481,255 57 ENVIRONMENTAL DEPARTMENT. TN............. PROCTER & GAMBLE 002 2,462,434 291 CELLULOSE COMPANY, THE. TN............. PROCTER & GAMBLE 001 617,774 73 CELLULOSE COMPANY, THE. TN............. CARGILL 002 1,280,108 151 CORNSTARCH. TN............. BRIDGESTONE 001 363,659 43 (U.S.A.), INC. TN............. US DEPARTMENT OF 003 58,562 7 ENERGY (ORNL). TN............. GOODYEAR TIRE & 004 1,095,940 130 RUBB. TN............. BOWATERS PAPER 012 1,087,729 129 CO. TN............. BOWATERS PAPER 011 1,086,881 129 CO. TN............. A.E. STALEY 035 1,189,514 141 MANUFACTURING COMPANY. TN............. A.E. STALEY 034 1,189,514 141 MANUFACTURING COMPANY. VA............. BEAR ISLAND 001 2,206,643 201 PAPER CO. VA............. JAMES RIVER 002 3,761,847 342 COGENERATION (COGE. VA............. SMITHFIELD 001 96,591 9 PACKING. VA............. DUPONT DE 004 285,120 26 NEMOURS E I & CO. VA............. DUPONT DE 005 406,080 37 NEMOURS E I & CO. VA............. UNION CAMP CORP/ 003 1,703,400 155 FINE PAPER DIV. VA............. UNION CAMP CORP/ 005 384,182 35 FINE PAPER DIV. VA............. UNION CAMP CORP/ 017 632,549 58 FINE PAPER DIV. VA............. DUPONT DE 001 360,720 33 NEMOURS E I & CO. VA............. CHESAPEAKE PAPER 003 1,950,681 178 PDTS CO. VA............. CHESAPEAKE PAPER 004 487,946 44 PDTS CO. VA............. STONE CONTAINER 004 5,141,951 468 CORP. VA............. ALLIED-SIGNAL 002 5,140,799 468 INC. VA............. ALLIED-SIGNAL 016 7,509,947 684 INC. VA............. JAMES RIVER 001 3,761,847 342 COGENERATION (COGE. VA............. HOECHST CELANESE 007 911,520 83 CORP. VA............. UNION CAMP CORP/ 004 2,379,652 217 FINE PAPER DIV. VA............. ALLIED-SIGNAL 017 595,170 54 INC. VA............. WESTVACO CORP... 002 1,076,877 98 VA............. UNION CAMP CORP/ 016 380,432 35 FINE PAPER DIV. VA............. HOECHST CELANESE 006 877,200 80 CORP. VA............. WESTVACO CORP... 001 1,413,167 129 VA............. WESTVACO CORP... 003 1,545,951 141 VA............. WESTVACO CORP... 004 2,616,233 238 VA............. DUPONT, EI 001 401,760 37 DENEMOURS & CO. VA............. DUPONT, EI 002 532,691 48 DENEMOURS & CO. VA............. DUPONT, EI 003 373,553 34 DENEMOURS & CO. VA............. GEORGIA-PACIFIC. 002 673,368 61 VA............. E I DUPONT DE 004 1,344,182 122 NEMOURS & CO. VA............. HOECHST CELANESE 003 885,360 81 CORP. VA............. E I DUPONT DE 006 1,281,074 117 NEMOURS & CO. VA............. E I DUPONT DE 007 978,350 89 NEMOURS & CO. VA............. HOECHST CELANESE 005 656,880 60 CORP. VA............. E I DUPONT DE 008 1,272,956 116 NEMOURS & CO.

VA............. HOECHST CELANESE 002 612,000 56 CORP. VA............. E I DUPONT DE 005 1,202,326 109 NEMOURS & CO. VA............. HOECHST CELANESE 004 226,800 21 CORP. WV............. ELKEM METALS 016 435,240 58 COMPANY--ALLOY P. WV............. DU PONT--BELLE.. 0ZD 844,340 113 WV............. BASF CORPORATION 003 312,814 42 HUNTINGTON WO. WV............. WEIRTON STEEL 030 1,209,426 161 CORPORATION. WV............. WEIRTON STEEL 088 500,915 67 CORPORATION. WV............. WEIRTON STEEL 089 305,643 41 CORPORATION. WV............. WEIRTON STEEL 090 585,781 78 CORPORATION. WV............. WEIRTON STEEL 091 580,467 77 CORPORATION. WV............. WEIRTON STEEL 092 721,698 96 CORPORATION. WV............. WEIRTON STEEL 093 702,068 94 CORPORATION. WV............. QUAKER STATE 001 693,049 92 REFINING CORP. --. WV............. QUAKER STATE 002 709,589 95 REFINING CORP. --. WV............. QUAKER STATE 004 743,213 99 REFINING CORP. --. WV............. DU PONT--BELLE.. 0ZA 1,046,722 140 WV............. WEIRTON STEEL 087 413,954 55 CORPORATION. WV............. DU PONT--BELLE.. 0ZC 380,180 51 WV............. DU PONT 0P6 803,015 107 WASHINGTON WORKS. WV............. DU PONT--BELLE.. 0ZE 1,079,138 144 WV............. FMC CORPORATION-- 003 4,423,563 590 STEAM PLANT. WV............. UNION CARBIDE-- 0B1 737,843 98 SOUTH CHARLEST. WV............. PPG INDUSTRIES, 001 1,402,296 187 INC. WV............. PPG INDUSTRIES, 002 824,976 110 INC. WV............. PPG INDUSTRIES, 003 2,445,280 326 INC. WV............. BAYER 022 206,694 28 CORPORATION. WV............. COLUMBIAN 032 296,762 40 CHEMICALS CO. WV............. CYTEC INDUSTRIES OWA 362,304 48 WV............. CYTEC INDUSTRIES OWB 362,304 48 WV............. DU PONT OP4 351,654 47 WASHINGTON WORKS. WV............. DU PONT OP5 608,426 81 WASHINGTON WORKS. WV............. DU PONT--BELLE.. OZB 898,968 120 ------------------------------------------------------------------------

Appendix B to Part 97--NOx Allowance Allocation Tables for Affected Sources Under Section 110 of the Act in Georgia, South Carolina, and Wisconsin

Table B.1.--Allocations to Fossil Fuel-Fired EGUs by mmBtu and MWh ---------------------------------------------------------------------------------------------------------------- Unit Unit average of average of two highest two Highest Unit Unit State Plant ID Point ID Plant of 1995, of 1995, allocations allocation 1996, or 1996, or by HI s by MWh 1997 summer 1997 summer HI MWh ---------------------------------------------------------------------------------------------------------------- GA............ 699 1 ARKWRIGHT...... 576,855 55,467 45 42 GA............ 699 2 ARKWRIGHT...... 586,172 56,363 46 43 GA............ 699 3 ARKWRIGHT...... 699,177 67,229 55 51 GA............ 699 4 ARKWRIGHT...... 629,120 60,492 49 46 GA............ 700 A2 ATKINSON....... 906,420 85,511 71 65 GA............ 700 A3 ATKINSON....... 817,568 62,880 64 48 GA............ 700 A4 ATKINSON....... 754,261 58,199 59 44 GA............ 703 1BLR BOWEN.......... 21,604,980 2,244,673 1,696 1,713 GA............ 703 2BLR BOWEN.......... 22,900,012 2,406,980 1,798 1,837 GA............ 703 3BLR BOWEN.......... 28,660,178 3,033,144 2,250 2,314 GA............ 703 4BLR BOWEN.......... 26,354,043 2,794,110 2,069 2,132 GA............ 708 1 HAMMOND........ 2,110,931 210,861 166 161 GA............ 708 2 HAMMOND........ 2,040,405 191,336 160 146 GA............ 708 3 HAMMOND........ 2,025,655 192,480 159 147 GA............ 708 4 HAMMOND........ 10,921,707 1,088,470 858 831 GA............ 709 1 HARLLEE BRANCH. 6,718,809 684,684 528 522 GA............ 709 2 HARLLEE BRANCH. 8,055,215 830,949 632 634 GA............ 709 3 HARLLEE BRANCH. 13,120,649 1,392,407 1,030 1,062 GA............ 709 4 HARLLEE BRANCH. 13,892,588 1,492,864 1,091 1,139 GA............ 54538 MAG1 HARTWELL ENERGY 22,233 2,616 2 2 FACILITY. GA............ 54538 MAG2 HARTWELL ENERGY 26,322 3,097 2 2 FACILITY. GA............ 710 MB1 JACK MCDONOUGH. 6,978,996 702,254 548 536 GA............ 710 MB2 JACK MCDONOUGH. 7,807,471 791,913 613 604 GA............ 733 1 KRAFT.......... 1,099,803 97,856 86 75 GA............ 733 2 KRAFT.......... 981,804 89,917 77 69 GA............ 733 3 KRAFT.......... 1,950,273 184,023 153 140 GA............ 733 4 KRAFT.......... 664,593 65,769 52 50 GA............ 6124 1 MCINTOSH....... 4,024,081 410,746 316 313 GA............ 6124 --CT3 MCINTOSH....... 345,688 26,942 27 21 GA............ 6124 --CT4 MCINTOSH....... 325,133 25,340 26 19 GA............ 6124 --CT5 MCINTOSH....... 341,543 26,619 27 20 GA............ 6124 --CT6 MCINTOSH....... 340,759 26,557 27 20 GA............ 6124 --CT7 MCINTOSH....... 315,416 32,195 25 25

GA............ 6124 --CT8 MCINTOSH....... 328,841 33,565 26 26 GA............ 715 1 MCMANUS........ 589,903 55,651 46 42 GA............ 715 2 MCMANUS........ 954,370 94,027 75 72 GA............ 727 3 MITCHELL....... 3,043,908 306,784 239 234 GA............ 734 12 RIVERSIDE...... 193,852 17,000 15 13 GA............ 7348 CT1 ROBINS......... 268,614 31,602 21 24 GA............ 7348 CT2 ROBINS......... 292,814 34,449 23 26 GA............ 6257 1 SCHERER........ 23,234,939 2,383,804 1,824 1,819 GA............ 6257 2 SCHERER........ 24,621,510 2,553,039 1,933 1,948 GA............ 6257 3 SCHERER........ 25,671,808 2,581,378 2,016 1,970 GA............ 6257 4 SCHERER........ 29,025,526 2,918,605 2,279 2,227 GA............ 6052 1 WANSLEY........ 21,381,911 2,300,367 1,679 1,755 GA............ 6052 2 WANSLEY........ 21,242,550 2,283,163 1,668 1,742 GA............ 6052 --5A WANSLEY........ 100,644 7,625 8 6 GA............ 728 Y1BR YATES.......... 1,867,410 161,164 147 123 GA............ 728 Y2BR YATES.......... 2,067,213 182,165 162 139 GA............ 728 Y3BR YATES.......... 1,867,344 156,630 147 120 GA............ 728 Y4BR YATES.......... 2,626,026 261,739 206 200 GA............ 728 Y5BR YATES.......... 2,296,410 221,000 180 169 GA............ 728 Y6BR YATES.......... 6,632,004 659,048 521 503 GA............ 728 Y7BR YATES.......... 6,805,284 689,632 534 526 SC............ 3280 CAN1 CANADYS STEAM.. 2,869,700 284,129 282 276 SC............ 3280 CAN2 CANADYS STEAM.. 3,511,752 347,698 345 338 SC............ 3280 CAN3 CANADYS STEAM.. 4,088,313 400,815 401 389 SC............ 7210 COP1 COPE........... 10,227,161 983,381 1,004 955 SC............ 130 1 CROSS.......... 15,587,385 1,640,777 1,530 1,594 SC............ 130 2 CROSS.......... 14,641,271 1,534,724 1,437 1,491 SC............ 3317 1 DOLPHUS M 1,668,846 160,899 164 156 GRAINGER. SC............ 3317 2 DOLPHUS M 1,453,280 140,549 143 137 GRAINGER. SC............ 3251 1 H B ROBINSON... 4,576,700 469,984 449 457 SC............ 3285 --4 HAGOOD......... 195,876 15,853 19 15 SC............ 3318 --3 HILTON HEAD.... 96,373 7,301 9 7 SC............ 3319 1 JEFFERIES...... 87,283 8,234 9 8 SC............ 3319 2 JEFFERIES...... 95,610 9,020 9 9 SC............ 3319 3 JEFFERIES...... 3,609,158 356,460 354 346 SC............ 3319 4 JEFFERIES...... 3,821,882 385,309 375 374 SC............ 3287 MCM1 MCMEEKIN....... 4,125,180 438,849 405 426 SC............ 3287 MCM2 MCMEEKIN....... 3,928,408 417,916 386 406 SC............ 50806 ST__NER STONE CONTAINER 1,347,859 127,157 132 124 SC............ 3295 URQ1 URQUHART....... 2,118,629 207,709 208 202 SC............ 3295 URQ2 URQUHART....... 2,190,221 214,728 215 209 SC............ 3295 URQ3 URQUHART....... 3,017,055 307,863 296 299 SC............ 3264 1 W S LEE........ 1,529,058 130,232 150 127 SC............ 3264 2 W S LEE........ 1,653,216 148,138 162 144 SC............ 3264 3 W S LEE........ 2,934,022 293,402 288 285 SC............ 3264 --4 W S LEE........ 50,719 3,559 5 3 SC............ 3297 WAT1 WATEREE........ 8,329,168 849,915 818 826 SC............ 3297 WAT2 WATEREE........ 10,033,636 1,023,840 985 995 SC............ 3298 WIL1 WILLIAMS....... 20,429,832 2,084,677 2,006 2,025 SC............ 6249 1 WINYAH......... 7,076,385 728,773 695 708 SC............ 6249 2 WINYAH......... 7,783,646 780,472 764 758 SC............ 6249 3 WINYAH......... 6,588,503 620,913 647 603 SC............ 6249 4 WINYAH......... 7,930,443 802,758 779 780 WI............ 4140 B4 ALMA........... 906,033 82,667 68 64 WI............ 4140 B5 ALMA........... 1,322,085 127,590 99 99 WI............ ........... 2 ARCADIA 359 25 0 0 MUNICIPAL ELECTRIC. WI............ ........... 3 ARCADIA 181 13 0 0 MUNICIPAL ELECTRIC. WI............ ........... 4 ARCADIA 78 5 0 0 MUNICIPAL ELECTRIC. WI............ ........... 5 ARCADIA 4,411 310 0 0 MUNICIPAL ELECTRIC. WI............ ........... CT1 BEACH.......... 8,810 618 1 0 WI............ 3992 8 BLOUNT STREET.. 746,085 61,609 56 48 WI............ 3992 9 BLOUNT STREET.. 883,198 72,931 66 56 WI............ 8023 1 COLUMBIA....... 17,697,465 1,721,376 1,328 1,333 WI............ 8023 2 COLUMBIA....... 19,254,893 1,881,831 1,445 1,458 WI............ 7159 --1 CONCORD........ 234,673 19,126 18 15 WI............ 7159 --2 CONCORD........ 252,008 20,539 19 16 WI............ 7159 --3 CONCORD........ 222,583 16,862 17 13 WI............ 7159 --4 CONCORD........ 217,995 16,515 16 13 WI............ ........... .............. CUMBERLAND 193 14 0 0 MUNICIPAL UTILITY. WI............ ........... .............. CUMBERLAND 280 20 0 0 MUNICIPAL UTILITY. WI............ ........... .............. CUMBERLAND 374 26 0 0 MUNICIPAL UTILITY. WI............ ........... .............. CUMBERLAND 584 41 0 0 MUNICIPAL UTILITY. WI............ ........... 1 DANBURY........ 65 5 0 0 WI............ ........... 2 DANBURY........ 73 5 0 0 WI............ ........... 3 DANBURY........ 158 11 0 0 WI............ 4050 3 EDGEWATER...... 1,632,111 139,963 122 108

WI............ 4050 4 EDGEWATER...... 8,821,558 917,097 662 710 WI............ 4050 5 EDGEWATER...... 12,812,254 1,206,427 961 935 WI............ ........... 1 FITCHBURG...... 93,659 6,573 7 5 WI............ ........... 2 FITCHBURG...... 90,110 6,323 7 5 WI............ ........... CT1 FLAMBEAU....... 78,623 5,517 6 4 WI............ ........... 2 FREDERIC....... 20 1 0 0 WI............ ........... 3 FREDERIC....... 19 1 0 0 WI............ ........... 4 FREDERIC....... 144 10 0 0 WI............ ........... 5 FREDERIC....... 103 7 0 0 WI............ ........... 6 FREDERIC....... 705 49 0 0 WI............ ........... 7 FREDERIC....... 871 61 0 0 WI............ ........... CT1 FRENCH ISLAND.. 56,592 4,287 4 3 WI............ ........... CT2 FRENCH ISLAND.. 20,835 1,578 2 1 WI............ 4143 1 GENOA.......... 9,095,142 1,001,668 682 776 WI............ 6253 --1 GERMANTOWN..... 107,413 8,137 8 6 WI............ 6253 --2 GERMANTOWN..... 107,413 8,137 8 6 WI............ 6253 --3 GERMANTOWN..... 107,413 8,137 8 6 WI............ 6253 --4 GERMANTOWN..... 107,413 8,137 8 6 WI............ 4271 B1 J P MADGETT.... 9,339,971 841,818 701 652 WI............ ........... CT1 MANITOWOC...... 21,524 1,510 2 1 WI............ ........... 31 MARINETTE...... 76,764 5,387 6 4 WI............ ........... 32 MARINETTE...... 22,262 1,562 2 1 WI............ ........... 33 MARINETTE...... 383,016 29,016 29 22 WI............ 54851 GT__MSD MMSD........... 22,263 1,562 2 1 WI............ 4054 1 NELSON DEWEY... 2,969,241 276,363 223 214 WI............ 4054 2 NELSON DEWEY... 3,141,352 301,995 236 234 WI............ ........... 1 NINE SPRINGS... 16,452 1,155 1 1 WI............ ........... .............. Northwestern 37 3 0 0 Wisconsin Electric Com. WI............ ........... .............. Northwestern 50 4 0 0 Wisconsin Electric Com. WI............ ........... .............. Northwestern 391 27 0 0 Wisconsin Electric Com. WI............ ........... .............. Northwestern 1,127 79 0 0 Wisconsin Electric Com. WI............ 7270 **1 PARIS.......... 382,238 28,957 29 22 WI............ 7270 **2 PARIS.......... 487,654 36,943 37 29 WI............ 7270 **3 PARIS.......... 524,161 39,709 39 31 WI............ 7270 **4 PARIS.......... 386,103 29,250 29 23 WI............ 6170 1 PLEASANT 23,012,814 2,129,633 1,727 1,650 PRAIRIE. WI............ 6170 2 PLEASANT 21,265,904 1,967,972 1,596 1,524 PRAIRIE. WI............ ........... AUX1 PLEASANT 18,405 1,736 1 1 PRAIRIE. WI............ ........... AUX2 PLEASANT 10,617 1,002 1 1 PRAIRIE. WI............ 4040 1 PORT WASHINGTON 1,295,715 124,588 97 97 WI............ 4040 2 PORT WASHINGTON 1,613,882 155,660 121 121 WI............ 4040 3 PORT WASHINGTON 1,719,476 167,362 129 130 WI............ 4040 4 PORT WASHINGTON 1,439,805 140,141 108 109 WI............ 4072 4 PULLIAM........ 395,870 38,064 30 29 WI............ 4072 5 PULLIAM........ 1,150,234 94,904 86 74 WI............ 4072 6 PULLIAM........ 1,994,261 167,726 150 130 WI............ 4072 7 PULLIAM........ 2,684,757 258,722 201 200 WI............ 4072 8 PULLIAM........ 4,610,833 453,020 346 351 WI............ ........... 3 RIVER FALLS 36 3 0 0 MUNICIPAL UTILITY. WI............ ........... 5 RIVER FALLS 2,527 177 0 0 MUNICIPAL UTILITY. WI............ ........... 7 RIVER FALLS 11,357 797 1 1 MUNICIPAL UTILITY. WI............ 4057 1 ROCK RIVER..... 1,999,193 168,666 150 131 WI............ 4057 2 ROCK RIVER..... 2,050,594 170,174 154 132 WI............ ........... 3 ROCK RIVER..... 29,868 2,096 2 2 WI............ ........... 4 ROCK RIVER..... 15,112 1,060 1 1 WI............ ........... 5 ROCK RIVER..... 166,306 12,599 12 10 WI............ ........... 6 ROCK RIVER..... 70,005 5,303 5 4 WI............ ........... 30 SHEEPSKIN...... 124,716 8,752 9 7 WI............ 7203 **CT1 SOUTH FOND DU 262,538 19,889 20 15 LAC. WI............ 7203 **CT2 SOUTH FOND DU 275,481 18,992 21 15 LAC. WI............ 7203 **CT3 SOUTH FOND DU 260,349 18,555 20 14 LAC. WI............ 4041 5 SOUTH OAK CREEK 5,906,838 667,439 443 517 WI............ 4041 6 SOUTH OAK CREEK 6,206,014 701,244 466 543 WI............ 4041 7 SOUTH OAK CREEK 8,697,896 978,611 653 758 WI............ 4041 8 SOUTH OAK CREEK 8,278,088 921,016 621 713 WI............ ........... 1 SYCAMORE....... 33,342 2,340 3 2 WI............ ........... 2 SYCAMORE....... 73,840 5,182 6 4 WI............ 4042 1 VALLEY......... 1,387,542 119,133 104 92 WI............ 4042 2 VALLEY......... 1,420,141 121,932 107 94 WI............ 4042 3 VALLEY......... 1,856,188 158,014 139 122 WI............ 4042 4 VALLEY......... 1,745,618 148,601 131 115 WI............ ........... CT1 WASHINGTON 75 5 0 0 ISLAND ELECTRIC COOPERAT. WI............ ........... CT2 WASHINGTON 46 3 0 0 ISLAND ELECTRIC COOPERAT. WI............ ........... CT3 WASHINGTON 3 0 0 0 ISLAND ELECTRIC COOPERAT. WI............ ........... CT4 WASHINGTON 94 7 0 0 ISLAND ELECTRIC COOPERAT. WI............ ........... CT5 WASHINGTON 153 11 0 0 ISLAND ELECTRIC COOPERAT.

WI............ ........... CT6 WASHINGTON 270 19 0 0 ISLAND ELECTRIC COOPERAT. WI............ 4076 --33 WEST MARINETTE. 227,932 18,531 17 14 WI............ 4078 1 WESTON......... 1,706,613 143,124 128 111 WI............ 4078 2 WESTON......... 2,947,494 274,594 221 213 WI............ 4078 3 WESTON......... 12,197,388 1,197,819 915 928 WI............ ........... 1 WHEATON........ 52,813 4,001 4 3 WI............ ........... 2 WHEATON........ 58,350 4,420 4 3 WI............ ........... 3 WHEATON........ 48,564 3,679 4 3 WI............ ........... 4 WHEATON........ 40,981 3,105 3 2 WI............ ........... 5 WHEATON........ 23,635 1,791 2 1 WI............ ........... 6 WHEATON........ 17,227 1,305 1 1 ----------------------------------------------------------------------------------------------------------------

Table B.2.--Allocations to Non-EGUs by mmBtu ------------------------------------------------------------------------ Unit State Plant Point ID Unit 1995 allocations summer HI by HI ------------------------------------------------------------------------ GA............. MERCK & CO INC.. 004 1,137,138 134 GA............. FEDERAL PAPER 007 2,551,114 300 BOARD CO INC. GA............. DSM CHEMICALS 001 1,137,974 134 NORTH AMERICA INC. GA............. PACKAGING CORP 015 1,239,138 146 OF AMERICA. GA............. INTERSTATE PAPER 006 771,395 91 CORP. GA............. CARGILL......... 001 461,546 54 GA............. BLUE............ 001 25,892 3 GA............. INLAND-ROME..... 001 986,136 116 GA............. GILMAN PAPER CO 003 1,715,895 202 ST MARYS KRAFT BAG. GA............. AUSTELL......... 001 1,507,475 177 GA............. FEDERAL PAPER 008 3,189,139 375 BOARD CO INC. GA............. GILMAN PAPER CO 016 2,130,015 250 ST MARYS KRAFT BAG. GA............. UNION CAMP CORP. 018 1,404 0 GA............. UNION CAMP CORP. 019 1,749,095 206 GA............. UNION CAMP CORP. 020 3,300,620 388 GA............. UNION CAMP CORP. 021 4,611,960 542 GA............. SAVANNAH SUGAR 017 370,056 44 REFINERY. SC............. SPRINGS 004 93,432 13 IND:GRACE. SC............. HOECHST/ 005 1,284,708 175 CEL:ROCKHILL. SC............. GOODYEAR:SPARTAN 001 5,196 1 BURG. SC............. CAROLINA EASTMAN 005 823,637 112 CO. SC............. CAROLINA EASTMAN 006 348,861 48 CO. SC............. GASTON COPPER 006 151,636 21 RECYCL. SC............. WILLAMETTE:BNVL 005 552,532 75 PULP. SC............. UNION 001 2,637,388 360 CAMP:EASTOVER. SC............. CAROLINA EASTMAN 004 1,224,571 167 CO. SC............. TRANDCENTNTL 005 16,691 2 PIPELINE. SC............. BOWATER CAROLINA 001 66,597 9 CO. SC............. HOECHST/ 001 858,080 117 CEL:ROCKHILL. SC............. HOECHST/ 002 858,080 117 CEL:ROCKHILL. SC............. HOECHST/ 004 1,284,708 175 CEL:ROCKHILL. SC............. HOECHST/ 006 1,352,714 185 CEL:ROCKHILL. SC............. DUPONT,EI:MAY 015 1,058,715 145 PLANT. SC............. SPRINGS 003 962,472 131 IND:GRACE. SC............. HOECHST/ 003 858,080 117 CEL:ROCKHILL. SC............. WESTVACO:KRAFT 007 1,534,180 210 DIV. SC............. CAROLINA EASTMAN 003 1,174,931 160 CO. SC............. DUPONT, EI:MAY 014 1,110,177 152 PLANT. SC............. SAVANNAH R 001 322,804 44 PL:AREA D. SC............. SAVANNAH R 002 1,160,658 159 PL:AREA D. SC............. SAVANNAH R 003 270,000 37 PL:AREA D. SC............. WESTVACO:KRAFT 003 604,557 83 DIV. SC............. SONOCO:HARTSVILL 003 992,068 135 E. SC............. SONOCO:HARTSVILL 004 1,245,367 170 E. SC............. STONE 002 699,348 96 CONT:FLORENCE. SC............. US AIRFORCE:MRTL 007 1,246 0 BCH. SC............. STONE 010 4,460,897 609 CONT:FLORENCE. SC............. US FINISHING.... 004 12,125 2 SC............. US FINISHING.... 005 6,928 1 SC............. US FINISHING.... 006 1,155 0 SC............. CAROTELL PAPER 004 17,136 2 BOARD. SC............. US AIRFORCE:MRTL 005 2,476 0 BCH. SC............. STONE 004 1,736,541 237 CONT:FLORENCE. SC............. SAVANNAH R 004 501,768 69 PL:AREA D. WI............. LADISH MALTING B28 79,675 12 CO. WI............. TENNECO B30 8,660 1 PACKAGING INC. WI............. A.A. LAUN B21 0 0 FURNITURE CO. WI............. MILLER BREWING B20 465,928 71 COMPANY MILWAUKEE PLANT.

WI............. PROCTER & GAMBLE B06 193,276 30 PAPER PRODUCTS COMPANY. WI............. WIS DOA / UW- B20 32,909 5 MILWAUKEE POWER PLANT. WI............. ST. JOSEPH'S T07 577 0 HOSPITAL. WI............. WAUSAU PAPER B25 65,242 10 MILLS COMPANY. WI............. WIS DOA / UW B25 256,925 39 MADISON--CHARTE R ST. WI............. WIS DOA / UW B21 608,077 93 MADISON--CHARTE R ST. WI............. FORT HOWARD B26 1,448,966 222 CORPORATION. WI............. PROCTER & GAMBLE B05 80,349 12 PAPER PRODUCTS COMPANY. WI............. PROCTER & GAMBLE B07 116,626 18 PAPER PRODUCTS COMPANY. WI............. JAMES RIVER B01 419,007 64 CORPORATION--GR EEN BAY MILL. WI............. ST. JOSEPH'S T08 577 0 HOSPITAL. WI............. ANDIS COMPANY... B10 577 0 WI............. FORT HOWARD B29 1,785,381 273 CORPORATION. WI............. FORT HOWARD B27 2,670,322 409 CORPORATION. WI............. GREAT LAKES GAS P01 716,318 110 TRANSMISSION- COMP STATIO. WI............. ANDIS COMPANY... B11 0 0 WI............. BURNETT MEDICAL B22 1,155 0 CENTER. WI............. CONSOLIDATED B24 70,438 11 PAPERS INC- KRAFT DIV. WI............. CONSOLIDATED B21 1,286,371 197 PAPERS INC- KRAFT DIV. WI............. NEKOOSA PAPERS B24 848,238 130 INC NEKOOSA MILL. WI............. CONSOLIDATED B20 1,566,432 240 PAPERS INC- KRAFT DIV. WI............. CONSOL PAPERS B24 1,538,813 236 INC BIRON DIV. WI............. FLAMBEAU PAPER I50 9,815 2 CORP. WI............. DELUXE CHECK B20 1,732 0 PRINTERS. WI............. HYDRO-PLATERS, B01 0 0 INC. WI............. BLOUNT INC. B20 1,155 0 FORESTY & INDUSTRIAL EQUIP D. WI............. APPLETON PAPERS B23 1,453,493 223 INC LOCKS MILL. WI............. APPLETON PAPERS B05 35,796 5 INC LOCKS MILL. WI............. THILMANY PULP & B11 1,460,691 224 PAPER COMPANY. WI............. RHINELANDER B26 1,370,808 210 PAPER CO. WI............. QUAD/GRAPHICS, B02 577 0 INC. WI............. QUAD/GRAPHICS, B01 577 0 INC. WI............. PRINTWORKS INC.. P33 577 0 WI............. CONSOL PAPERS B23 1,274,336 195 INC BIRON DIV. ------------------------------------------------------------------------

Appendix C to Part 97-State-by-State Maximum Summer NOX Emission Levels and Allocation Aggregates

---------------------------------------------------------------------------------------------------------------- EGU Non-EGU EGU maximum allocations Non-EGU allocations State summer NOx (95% of maximum (95% of Tons maximum summer NOx maximum summer) tons summer) ---------------------------------------------------------------------------------------------------------------- AL.......................................................... 28,884 27,440 3,347 3,179 CT.......................................................... 2,545 2,418 283 269 DC.......................................................... 207 196 18 17 DE.......................................................... 3,489 3,315 238 226 GA.......................................................... 30,061 28,558 3,328 3,161 IL.......................................................... 30,165 28,657 3,600 3,420 IN.......................................................... 46,627 44,296 11,325 10,758 KY.......................................................... 36,315 34,499 1,709 1,624 MA.......................................................... 14,619 13,888 232 220 MD.......................................................... 14,788 14,048 802 762 MI.......................................................... 26,344 25,027 2,844 2,702 MO.......................................................... 23,171 22,012 132 126 NC.......................................................... 29,967 28,468 3,277 3,113 NJ.......................................................... 7,898 7,503 3,882 3,688 NY.......................................................... 29,391 27,921 4,409 4,189 OH.......................................................... 45,776 43,487 8,693 8,258 PA.......................................................... 48,038 45,636 4,657 4,424 RI.......................................................... 1,115 1,059 0 0 SC.......................................................... 16,286 15,472 4,355 4,137 TN.......................................................... 25,386 24,117 8,085 7,681 VA.......................................................... 18,009 17,109 5,372 5,104 WI.......................................................... 16,751 15,913 3,204 3,043 WV.......................................................... 26,439 25,117 3,509 3,334 --------------------------------------------------- Total................................................. 522,271 496,157 77,300 73,436 ----------------------------------------------------------------------------------------------------------------

[FR Doc. 98-26292 Filed 10-20-98; 8:45 am] BILLING CODE 6560-50-P