Skip to Content

Rule

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

Document Details

Information about this document as published in the Federal Register.

Published Document

This document has been published in the Federal Register. Use the PDF linked in the document sidebar for the official electronic format.

Start Preamble Start Printed Page 2674

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final rule.

SUMMARY:

In accordance with section 126 of the Clean Air Act (CAA), EPA is taking final action on petitions filed by eight Northeastern States seeking to mitigate interstate transport of nitrogen oxides (NOX), one of the precursors of ground-level ozone. In an action published on May 25, 1999, EPA determined that portions of the petitions are approvable under the 1-hour and/or 8-hour ozone national ambient air quality standards (NAAQS) based on their technical merit. However, EPA deferred making section 126 findings as long as States and EPA stayed on track to meet the requirements of the NOX State implementation plan call (NOX SIP call). Subsequently, two court rulings affected the May 25 final rule. In one ruling, the court remanded the 8-hour ozone NAAQS. In a separate action, the court granted a motion to stay the SIP submission deadline for the NOX SIP call. In light of the court rulings, EPA is modifying two aspects of the May 25 rule.

Based on affirmative technical determinations for the 1-hour ozone NAAQS made in the May 25 rule, today, EPA is making section 126 findings that a number of large electric generating units (EGUs) and large industrial boilers and turbines named in the petitions emit in violation of the CAA prohibition against significantly contributing to nonattainment or maintenance problems in the petitioning States. The EPA is staying indefinitely the affirmative technical determinations based on the 8-hour ozone NAAQS, pending further developments in the NAAQS litigation.

The EPA is also finalizing the Federal NOX Budget Trading Program as the control remedy for sources affected by today's rule. This requirement replaces the default remedy in the May 25 final rule.

DATES:

The final rule is effective February 17, 2000.

ADDRESSES:

Documents relevant to this action are available for inspection at the Air and Radiation Docket and Information Center (6102), Attention: Docket No. A-97-43, U.S. Environmental Protection Agency, 401 M Street SW, room M-1500, Washington, DC 20460, telephone (202) 260-7548 between 8:00 a.m. and 5:30 p.m., Monday though Friday, excluding legal holidays. A reasonable fee may be charged for copying.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

General questions concerning today's action should be addressed to Carla Oldham, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, MD-15, Research Triangle Park, NC 27711, telephone (919) 541-3347, email at oldham.carla@epa.gov. Please refer to SUPPLEMENTARY INFORMATION below for a list of contacts for specific subjects discussed in today's action.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

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 confidential business information, is available for inspection from 8:00 a.m. to 5:30 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. In addition, the Federal Register rulemaking actions and associated documents are located at http://www.epa.gov/​ttn/​rto/​126. Documents containing the historical heat input data used to calculate the NOX allowance allocations, listed in appendices A and B to part 97, are available at this website and have been placed in the rulemaking docket.

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.” The rulemaking docket for that rule (Docket No. A-96-56), hereafter referred to as the NOX SIP call, contains information and analyses that EPA has relied upon in the section 126 rulemaking, and hence documents in that docket are part of the rulemaking record for this rule. Documents related to the NOX SIP call rulemaking are available for inspection in docket number A-96-56 at the address and times given above.

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 questions regarding the NOX cap-and-trade program, please contact Sarah Dunham, Office of Atmospheric Programs, Clean Air Markets Division, MC-6204J, 401 M Street SW, Washington, DC 20460, telephone (202) 564-9087. For questions regarding regulatory cost analyses for electricity generating sources, please contact Mary Jo Krolewski, Office of Atmospheric Programs, Clean Air Markets Division, MC-6204J, 401 M Street SW, Washington, DC 20460, telephone (202) 564-9847. For questions regarding regulatory cost analyses for other stationary sources, please contact Larry Sorrels, Office of Air Quality Planning and Standards, Air Quality Strategies and Standards Division, MD-15, Research Triangle Park, NC 27711, telephone (919) 541-5041.

Outline

I. Background and Summary of Rulemaking

A. Summary of Rulemaking and Affected Sources

1. Summary of Action to Date

2. Summary of Today's Rule

3. Extension of Stay of May 25, 1999 Final Rule

B. Cost Effectiveness of Emissions Reductions

1. Large EGUs

2. Large Non-EGUs

C. Interfere With Maintenance

D. New Petitions Submitted in 1999

II. EPA's Final Action on Granting or Denying the Eight Petitions

A. Technical Determinations in the May 25 Final Rule

B. Findings Under Section 126 and Removal of Trigger Mechanism Based on NOX SIP Call Compliance Deadlines

C. Section 126(b) Findings Under the 1-Hour Ozone Standard

D. Stay of Affirmative Technical Determinations Under the 8-Hour Ozone Standard

1. Affirmative Technical Determinations Under the 8-Hour Ozone Standard

2. Stay of the 8-Hour Affirmative Technical Determinations

E. Requirements for Sources for Which EPA Is Making a Section 126(b) Finding

III. Section 126 Control Remedy: The Federal NOX Budget Trading Program

A. Program Overview

1. Relationship between Today's Action and the May 25, 1999 Section 126 Final Rule

2. Elements of the Federal NOX Budget Trading Program That Are Essentially the Same as the State NOX Budget Trading Program and the October 21, 1999 Section 126 Proposed Rule Start Printed Page 2675

a. General Provisions

b. NOX Authorized Account Representative

c. Permits

d. Compliance Certification

e. NOX Allowance Tracking System

f. NOX Allowance Transfers

g. Opt-ins

h. Audits

3. Elements of the Federal NOX Budget Trading Program That Differ From the State NOX Budget Trading Program and the Section 126 Proposed Rule

a. General Provisions

b. Allowance Allocations

c. Emissions Monitoring and Reporting

d. Program Administration

4. Implications for Trading Between States Affected by a Finding Under Section 126, and States Not Affected by a Finding

B. Provisions of the Federal NOX Budget Trading Program

1. Applicability

a. EGU/Non-EGU Classification

b. Fossil Fuel-Fired Definition

c. 25-ton Exemption

d. Opt-in Units

2. Trading Program Budget

3. NOX Allowance Allocations

a. NOX Allowance Allocation Methodology for Electric Generating Units

b. NOX Allowance Allocation Methodology for Non-Electric Generating Units

4. The Compliance Supplement Pool

a. Size of the Compliance Supplement Pool

b. Distribution of the Compliance Supplement Pool to Sources

5. Banking

6. Emissions Monitoring and Reporting

IV. Administrative Requirements

A. Executive Order 12866: Regulatory Planning and Review

B. Regulatory Flexibility Act

C. Unfunded Mandates Reform Act

D. Paperwork Reduction Act

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

F. Executive Order 12898: Environmental Justice

G. Executive Order 13132: Federalism

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

I. National Technology Transfer and Advancement Act

J. Judicial Review

K. Congressional Review Act

I. Background and Summary of Rulemaking

A. Summary of Rulemaking and Affected Sources

1. Summary of Action to Date

In a notice of final rulemaking (NFR) signed on April 30, 1999 and published on May 25, 1999 (May 25 NFR or May 25, 1999 final rule), EPA took action on eight ozone-related petitions submitted individually by eight northeastern States under section 126 of the CAA(64 FR 28250; May 25, 1999). As discussed in Section II.A. of the May 25 NFR, section 126 of the CAA authorizes a downwind State to petition EPA for a finding that any new (or modified) or existing major stationary source or group of stationary sources upwind of the State emits or would emit in violation of the prohibition of section 110(a)(2)(D)(i) because their emissions contribute significantly to nonattainment, or interfere with maintenance, of a NAAQS in the State. Sections 110(a)(2)(D)(i), 126(b)-(c). If EPA makes the requested finding, the sources must shut down within 3 months from the finding unless EPA directly regulates the sources by establishing emissions limitations and a compliance schedule, extending no later than 3 years from the date of the finding, to eliminate the prohibited interstate transport of pollutants as expeditiously as possible. See sections 110(a)(2)(D)(i) and 126(c).

The States that petitioned EPA under section 126 (addressed by today's final rule) are Connecticut, Maine, Massachusetts, New Hampshire, New York, Rhode Island, Pennsylvania, and Vermont. Each petition requests that EPA make a finding that certain major stationary sources or groups of sources in upwind States emit NOX emissions in violation of the CAA's prohibition on amounts of emissions that contribute significantly to ozone nonattainment or maintenance problems in the petitioning State. The petitions vary in geographic scope covered, types of sources identified, and recommended control remedies. All of the eight petitioning States requested section 126 findings under the 1-hour ozone standard. Five of the petitioning States (Maine, Massachusetts, New Hampshire, Pennsylvania, and Vermont) also requested section 126 findings under the 8-hour ozone standard. Section 126 provides that if EPA finds that identified stationary sources emit in violation of the section 110(a)(2)(D) prohibition on emissions that significantly contribute to ozone nonattainment or maintenance problems in a petitioning State, EPA is authorized to establish Federal emissions limits for the sources. Section I of the May 25 NFR describes the petitions and Section II sets forth EPA's interpretation of section 126 and the analytical test EPA used to evaluate the petitions. Familiarity with the May 25 NFR is assumed for the purposes of today's final rule.

In the May 25 NFR, EPA made final determinations that six of the eight petitions have technical merit. The EPA made affirmative determinations that existing and new large electric generating units (EGUs) and large industrial boilers and turbines (non-EGUs) located in certain States identified in the section 126 petitions are significantly contributing to nonattainment in, or interfering with maintenance by, one or more of the petitioning States with respect to the 1-hour and/or 8-hour ozone standards. Under the 1-hour standard, EPA made affirmative technical determinations of significant contribution for sources located in the District of Columbia and 12 States. Under the 8-hour standard, EPA made affirmative technical determinations of significant contribution for sources located in the same States and the District of Columbia as under the 1-hour standard plus seven additional States.

In the May 25 NFR, EPA also denied the portions of the petitions that did not have technical merit. Under the 1-hour standard, EPA fully denied the petitions from Rhode Island, Maine, New Hampshire, and Vermont because the States had clean air quality. The EPA fully denied the Vermont petition under the 8-hour standard because that State did not have any current or projected 8-hour air quality problems.

The EPA also provided that the portions of the petitions for which EPA made affirmative technical determinations would be automatically deemed granted (the section 126 findings made) 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. Interpreting the interplay between sections 110 and 126, EPA explained in the May 25 NFR that a State's compliance with the NOX SIP call would eliminate the basis for a finding under section 126 based on these petitions for sources located in that State. The EPA concluded it was appropriate to structure its action on the section 126 petitions to account for the existence of the NOX SIP call, given that the NOX SIP call had an explicit and expeditious schedule for compliance (see 64 FR 28274-28277). Accordingly, EPA made technical determinations on the section 126 petitions, but deferred making final findings. The schedule and conditions under which the applicable final findings on the petitions would have been deemed made are discussed in Section I.E. of the May 25 NFR.

As discussed in Section IV of the May 25 NFR, EPA was required under a consent decree to take final action on the eight petitions by April 30, 1999, including promulgating a control remedy for sources that would be subject to an affirmative finding under section 126. In a proposal published on October 21, 1998 (63 FR 56292), EPA proposed a NOX cap-and-trade program as the section 126 control requirements. Start Printed Page 2676However, EPA was not able to finalize the trading program by April 30, 1999, because the Agency needed additional time to evaluate the numerous comments it received on the trading program proposal and the source-specific emissions inventory data. In the May 25 NFR, EPA finalized the general parameters of the trading program control remedy including, among others, the decision to implement a NOX cap-and-trade program as the control remedy, the control levels the trading program would be based on, the definition of the types of sources that would be subject to the trading program, and the compliance date. The EPA indicated it would finalize the complete Federal NOX Budget Trading Program and allowance allocations for the section 126 sources later.

On January 13, 1999 (64 FR 2416), EPA reopened the comment period on the section 126 proposal, to take further comment on source-specific emission inventory data. This comment period was established in conjunction with the extended period for the public to submit emissions inventory revisions for the purpose of the NOX SIP call. The EPA indicated that the revised inventory would be used to identify the individual sources that would be subject to section 126 findings and for assigning their NOX allowance allocations for purposes of the Federal NOX Budget Trading Program. The EPA's process for evaluating the inventory data and EPA's response to the emissions inventory comments is given in the document, “Responses to the 2007 Baseline Sub-Inventory Information and Significant Comments for the Final NOX SIP Call and Proposed Rulemakings for Section 126 Petitions and Federal Implementation Plans—Technical Amendment Version, December 1999,” and contained in the docket for this rule.

The EPA finalized a default remedy in the May 25 NFR that would apply to affected sources in the event that EPA failed to finalize the trading program prior to any section 126 findings being triggered. The EPA emphasized that it did not expect that the default remedy would ever be applied, because EPA fully intended to complete the trading program and delete the default remedy by the time any findings were made.

After EPA signed the section 126 final rule on April 30, 1999 (published on May 25, 1999), the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued two rulings related to the 8-hour ozone standard and the NOX SIP call that affected the section 126 action. In one decision, the court remanded the 8-hour National Ambient Air Quality Standard (NAAQS) for ozone, which formed part of the underlying technical basis for certain of EPA's determinations under section 126. See American Trucking Ass'n v. EPA, 175 F.3d 1027 (D.C. Cir., 1999), reh'g granted in part and denied in part, No. 97-1440 and consolidated cases (D.C. Cir., October 29, 1999). On October 29, 1999, the D.C. Circuit granted in part EPA's Petition for Rehearing and Rehearing En Banc (filed on June 28, 1999) in American Trucking, and modified portions of its opinion addressing EPA's ability to implement the eight-hour standard. See American Trucking, 1999 WL 979463 (Oct. 29, 1999). The court denied the remainder of EPA's rehearing petition. Id. In a separate action, the D.C. Circuit granted a motion to stay the State implementation plan (SIP) submission deadlines established in the NOX SIP call. See Michigan v. EPA, No. 98-1497 (D.C. Cir., May 25, 1999) (order granting stay in part). In the May 25 NFR, EPA had deferred making final findings under section 126 as long as States and EPA stayed on schedule to meet the requirements of the NOX SIP call.

In response to these rulings, EPA stayed the effectiveness of the May 25 NFR until November 30, 1999 while it conducted a parallel rulemaking to address issues raised by the court rulings (64 FR 33956; June 24, 1999).

On June 24, 1999 (64 FR 33962), EPA proposed to amend two aspects of the May 25 NFR. The EPA proposed to stay indefinitely the affirmative technical determinations based on the 8-hour standard pending further developments in the NAAQS litigation. The EPA also proposed to remove the trigger mechanism for making section 126 findings that was based on the NOX SIP call deadlines and instead make the findings in a final rule to be issued in November 1999. In the June 24 proposal, EPA explained why it originally made sense to link the section 126 action to the NOX SIP call and why EPA believes it is no longer appropriate to do so in the absence of a compliance schedule for the NOX SIP call.

The EPA notes it received several comments on the June 24, 1999 proposal that the Agency considers to be outside the scope of that proposal. These comments relate primarily to issues that have been addressed previously either in the NOX SIP call final rule, the NOX SIP call response to comments document, the May 25, 1999 final rule for the section 126 petitions, or the April 1999 response to comments document for the section 126 petitions. The EPA may respond separately to these comments, which the Agency believes should be considered to be, in effect, petitions for reconsideration of the May 25, 1999 final rule. A notice will be published in the Federal Register to announce the availability of these responses in the rulemaking docket.

On August 9, 1999 (64 FR 43124), EPA issued a notice of data availability and request for comment on three sets of data related to the proposed Federal NOX Budget Trading Program. The data were made available to ensure that EPA would have accurate information for developing the NOX allowance allocations for the Federal NOX Budget Trading Program.

2. Summary of Today's Rule

In today's rule, EPA is finalizing the modifications to the May 25 NFR that were proposed on June 24, 1999. The EPA is also finalizing the Federal NOX Budget Trading Program that was proposed on October 21, 1998 and deleting the default remedy that was finalized in the May 25 NFR. The EPA is finalizing the list of existing sources that are subject to this rule based on the revised inventories.

In Section II, EPA discusses the delinking of the section 126 rule from the NOX SIP call and the making of the section 126(b) findings for the petitions for which EPA made affirmative technical determinations based on the 1-hour NAAQS in the May 25 NFR. The findings apply to large EGUs and large non-EGUs located in 12 States (Delaware, Indiana, Kentucky, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia) and the District of Columbia. The EPA is indefinitely staying the affirmative technical determinations based on the 8-hour NAAQS, which cover large EGUs and large non-EGUs located in all the States covered by the 1-hour findings plus seven additional States (Alabama, Connecticut, Illinois, Massachusetts, Missouri, Rhode Island, and Tennessee).

The sources for which EPA is making section 126 findings must comply with the control requirements of the Federal NOX Budget Trading Program promulgated in today's rule. Section III provides an overview of the trading program and explains the various provisions. The combined list of existing sources affected by a section 126 finding with respect to at least one 1-hour petition, along with the more specific emissions limitations in the form of tradable allowance allocations, is provided in Appendices A and B to part 97. As discussed in the May 25 rule (see Section I.D.), the 1-hour petitions Start Printed Page 2677from New York, Connecticut, and Pennsylvania petitions cover both new and existing sources. The 1-hour petition from Massachusetts does not cover new sources. As discussed in Section III below, the Federal NOX Budget Trading Program includes a mechanism for updating allocations which can incorporate new sources affected by findings relative to the petitions from New York, Connecticut, and Pennsylvania. Prior to the update, new sources can receive allocations from a new source set-aside. The compliance deadline is May 1, 2003. The EPA is creating a compliance supplement pool which will provide additional allowances during the 2003 and 2004 ozone seasons to increase compliance flexibility (see Section III.B.4).

3. Extension of Stay of May 25, 1999 Final Rule

In a separate action, EPA extended the stay of the May 25, 1999 rule until January 10, 2000. (See 64 FR 67781; December 3, 1999.) EPA will publish a further stay to ensure that the May 25, 1999 rule remains stayed until today's rule becomes effective.

B. Cost Effectiveness of Emissions Reductions

One factor of the significant-contribution analysis that EPA applied in the May 25, 1999 final rule is the extent to which “highly cost-effective” NOX control measures are available for the types of stationary sources named in the petitions (64 FR at 28281). In the May 25, 1999 final rule, EPA selected the highly cost-effective measures by examining the technological feasibility, administrative feasibility and cost-per-ton-reduced of various regionwide ozone season NOX control measures (64 FR at 28298).

For purposes of the May 25, 1999 final rule, EPA used cost-effectiveness values developed for the final NOX SIP call. In the May 25, 1999 final rule, EPA indicated that it would revise the cost estimates for the section 126 rule based on revised emission inventories in conjunction with promulgation of the trading portion of the section 126 rulemaking (64 FR at 28300). (The EPA solicited comment on source-specific emission inventory data as part of the proposal on the section 126 petition.) Therefore, EPA has developed cost-effectiveness numbers for the source categories located in the 13 jurisdictions affected by today's final rule using the cost-effectiveness methodology finalized in the May 25, 1999 rule.

Some commenters have argued that EPA must redo its analysis of the cost-effectiveness of controls to reflect the modified scope of the section 126 rule due to the stay of the 8-hour affirmative technical determinations. Commenters argued that EPA has underestimated the costs for utility NOX controls since several States and portions of States have been removed as a result of the stay of the 8-hour affirmative technical determinations. In addition, one commenter stated that EPA should provide an opportunity to comment on a revised cost-effectiveness analysis that incorporates only the affected sources under the section 126 petitions based on the 1-hour standard.

As discussed below, EPA has now revised the cost-effectiveness numbers based on the revised inventories to reflect the 13 jurisdictions covered by today's section 126 final action under the 1-hour standard. Even with the reduced scope of the section 126 rule, the cost-effectiveness numbers are similar to those presented in the May 25, 1999 final rule and support the technical determinations EPA made in that rule. In addition, EPA continues to use the same cost-effectiveness methodology for today's rule as it used in the May 25, 1999 final rule, the October 21, 1998 section 126 proposed rule, and the NOX SIP call rule. Therefore, commenters have had opportunities to comment on the cost-effectiveness methodology used in today's rule.

In determining what, if any, highly cost-effective mix of controls is available for each subcategory named by the petitioning Sates (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 (see 63 FR at 57400) and the May 25, 1999 final rule (64 FR at 28300).

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 fully adopted by all the involved States; if the OTC NOX MOU were included in the baseline, the overall costs would be lower. Based on the analyses, EPA determined that highly cost-effective measures are available for large EGUs and large non-EGUs.[1]

Table I-1 summarizes the control options investigated for the subcategories covered by today's rule and the resulting average, regionwide cost effectiveness estimates based on the revised inventories. Additionally, the cost-effectiveness analysis includes a consideration of each subcategory's growth, including new sources. The cost-effectiveness numbers are similar to those presented in the May 25, 1999 final rule (64 FR at 28300). Therefore, based on this component of the significant contribution test, there is no reason to revise any of the significant contribution determinations.

Table I.-1. Revised Average Cost Effectiveness of Options Analyzed for Sources Affected by 1-Hour Findings a (1997 dollars and (1990) dollars in 2007) b

Source CategoryAverage Cost Effectiveness ($/ozone season ton) for each Control Option
Large EGUs0.20 lb/mmBtu0.15 lb/mmBtu0.12 lb/mmBtu
$1,425 ($1,187)$1,720 ($1,432)$2,043 ($1,701)
Large Non-EGUs50% reduction60% reduction70% reduction
$1,613 ($1,370)$1,908 ($1,589)$2,903 ($2,418)
a The cost-effectiveness values in Table I-1 are regionwide averages for the 13 affected jurisdictions. The cost-effectiveness values represent reductions beyond those required by title IV or title I RACT, where applicable.
b In order to compare with other rulemakings presented in 1997 dollars, cost-effectiveness is presented in both 1997 and (1990) dollars. In 1997 dollars, highly cost-effective is defined as $2,400 per ton, which is $2,000 per ton in 1990 dollars inflated using a GDP price inflator of 1.20.
Start Printed Page 2678

The following discussion explains the control levels determined by EPA to be highly cost effective for each subcategory.

1. Large EGUs

As discussed in the May 25, 1999 final rule (64 FR at 28300), in determining the cost of NOX reductions from large EGUs, EPA assumed a multistate cap-and-trade program. For large EGUs, the control level was determined by applying a uniform NOX emissions rate across all jurisdictions potentially subject to section 126 findings. EPA determined that a trading program based on a 0.15 lb/mmBtu control level is highly cost effective. For the cost-effectiveness analysis for today's final action, a uniform NOX emissions rate is applied to the 13 jurisdictions subject to the section 126 findings. The cost effectiveness for each control level was determined using the Integrated Planning Model (IPM).[2] Details regarding the methodologies used can be found in the Regulatory Impact Analysis. Table I-1 summarizes the control levels and resulting cost effectiveness of three levels analyzed based on the revised inventories for sources covered by the 1-hour findings. Again, EPA notes that the cost-effectiveness numbers are similar to those presented in the May 25, 1999 final rule (e.g., the cost-effectiveness for the 0.15 lb/mmBtu option decreased by $44/ton, from $1,764/ton to $1,720/ton in 1997 dollars (from $1,468/ton to $1,432/ton in 1990 dollars)).[3]

In the May 25, 1999 final rule (64 FR at 28300-1), EPA discussed the reasons the Agency has decided to base the emission reduction requirements for EGUs on a 0.15 lb/mmBtu trading level of control. Because the average cost-effectiveness for the three levels analyzed has not changed significantly, EPA maintains that a 0.15 lb/mmBtu trading level of control is appropriate for the reasons identified in the May 25, 1999 rule. This control level has an average cost effectiveness of $1,720 per ozone season ton removed in 1997 dollars ($1,432 per ozone season ton removed in 1990 dollars). This amount is consistent with the range for cost effectiveness that EPA has derived from recently adopted (or proposed to be adopted) control measures. See 64 FR at 28299.

2. Large Non-EGUs

As discussed in the May 25, 1999 final rule (64 FR at 28301), EPA determined a highly cost-effective control level for large non-EGUs by evaluating a uniform percent reduction in increments of 10 percent. Details regarding the methodologies used are in the Regulatory Impact Analysis. Table I-1 summarizes the control levels and resulting cost effectiveness for these non-EGUs based on the revised inventories for sources covered by the 1-hour findings.

For non-EGU sources, EPA used a least-cost method which is equivalent to an assumption of an interstate trading program. Under this method, the least costly controls, in terms of total annual cost per ozone season ton removed, across the entire set of feasible source-control measure combinations are selected in order of increasing annual compliance costs per ton, consistent with the above-described range for cost effectiveness.

For large non-EGUs, the cost-effectiveness analysis 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. 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 for large non-EGU boilers and turbines are about $160 per ton of NOX removed.

The average cost effectiveness for the three levels analyzed has not changed significantly from the May 25, 1999 final rule (64 FR at 28301). Therefore, based on this component of the significant contribution test, there is no reason to revise any of the significant contribution determinations. As determined in the May 25, 1999 final rule, a control level corresponding to 60 percent reduction from baseline levels is highly cost effective. This percent reduction corresponds to a regionwide average control level of about 0.17 lb/mmBtu.

C. Interfere With Maintenance

As noted above, section 110(a)(2)(D) prohibits sources from emitting air pollutants in amounts that will, “contribute significantly to nonattainment in, or interfere with maintenance by, any other State with respect to [any] national * * * ambient air quality standard” [emphasis added]. Each of the petitions requested that EPA make findings with respect to both nonattainment and maintenance of the 1-hour and/or 8-hour ozone standards in the petitioning State. In the May 25 final rule, EPA determined that a State may petition under section 126 for both the 1-hour standard, to the extent that it still applied in the petitioning State, and the 8-hour standard. The EPA indicated that in areas for which EPA had determined that the 1-hour standard no longer applies, there would no longer be a basis for EPA to make section 126(b) findings with respect to nonattainment or maintenance of that standard. In light of recent court action discussed below, EPA has proposed to reinstate the 1-hour standard. Thus, if EPA finalizes the rule as proposed, all areas would be subject to that standard along with the requirements to meet and maintain it.

Reinstatement of the 1-Hour Ozone Standard. The EPA promulgated the 8-hour standard in July 1997 to replace the existing 1-hour standard. To ensure an effective transition to the new 8-hour standard, EPA decided that the 1-hour standard would continue to apply in an area for an interim period until the area achieved attainment of that standard. Under that policy, once EPA made a final determination that an area had attained the 1-hour standard, that standard no longer would apply and States would be expected to focus their planning efforts on developing strategies for attaining the 8-hour standard. The effectiveness of the 8-hour standard served as the underlying basis for EPA's finding that the 1-hour standard no longer applied in areas that EPA determined were attaining the 1-hour standard. The recent ruling of the D.C. Circuit in American Trucking has undermined the basis for EPA's previous determinations on applicability of the 1-hour ozone standard by remanding the 8-hour NAAQS. Therefore, in a separate rulemaking (64 FR 57424; October 25, 1999), EPA has proposed to: (i) Rescind the findings that the 1-hour standard no longer applies, and (ii) reinstate the applicability of the 1-hour standard in all areas, notwithstanding promulgation of the 8-hour standard.

Once EPA finalizes its action to reinstate the 1-hour standard, the “interfere with maintenance” test could be applied under both the 1-hour and 8-hour standards. The areas in the petitioning States that are currently subject to and violating the 1-hour standard need not only achieve the 1-hour standard, but would also need to maintain it. Upwind NOX reductions resulting from today's rule will assist these areas in both achieving and maintaining the 1-hour standard. In Start Printed Page 2679addition, there are areas in the petitioning States that are not currently subject to the 1-hour standard, and therefore, cannot be considered as a basis for this rule. For some of these areas that have attained the standard, their ability to maintain the standard may be jeopardized due to transported pollution. (In addition, some areas where the standard was revoked may now have air quality that exceeds the 1-hour standard.) These areas in the petitioning States will also benefit from the emissions reductions from this rule as they focus planning efforts on the 1-hour standard again. Reinstatement of the 1-hour standard underscores the need for the emissions reductions required by this rule. In the future, EPA may take further action to consider maintenance of the 1-hour standard under section 126.

D. New Petitions Submitted in 1999

In April through June of 1999, EPA received four new ozone-related section 126 petitions submitted individually by the District of Columbia, Delaware, Maryland, and New Jersey (see docket number A-99-21). All four of the petitions requested that EPA make findings that NOX emissions from sources located in upwind States are significantly contributing to nonattainment and maintenance problems in the petitioning State under the 1-hour and 8-hour standards. The four petitions identified sources in a total of 13 States and the District of Columbia. Each State based its petition on EPA's technical analyses and significant contribution determinations in the NOX SIP call. The petitions recommend that EPA establish an interstate trading program for sources that would receive a section 126 finding. The control levels sought are: an overall control level of 0.15 lb/mmBtu for EGUs and a 60 percent reduction in NOX emissions from non-EGUs calculated from the baseline EPA used in the NOX SIP call. The EPA will be proposing action on the 4 petitions in the future.

II. EPA's Final Action on Granting or Denying the Eight Petitions

The EPA is making final section 126 findings on the eight petitions under the 1-hour standard based on the affirmative technical determinations made in the May 25 NFR. The EPA is removing the automatic trigger mechanism for making the findings that was established in the May 25 NFR, and instead is simply making the findings in today's rule. EPA evaluated the petitions independently under the 1-hour and 8-hour standards where a State requested a finding under both standards. The EPA is staying the affirmative technical determinations with respect to the 8-hour standard in light of the recent court decision on that standard. Sources subject to findings under the 1-hour standard will be required to implement controls beginning in May 2003. Each of these actions is described below.

Because it is no longer appropriate to link the section 126 action to the NOX SIP call deadlines and EPA is removing the automatic trigger mechanisms that were tied to those deadlines, as discussed below in Section II.B., the affirmative technical determinations under the 1-hour standard effectively constitute findings in the context of section 126. There is no longer a subsequent condition that must first be fulfilled, before EPA makes final findings. Thus, the affirmative technical determinations under the 1-hour standard are a sufficient basis for EPA to find that the affected sources are emitting in violation of the prohibition of section 110(a)(2)(D)(i). The EPA is revising the part 52 regulatory text to reflect this change.

A. Technical Determinations in the May 25 Final Rule

In the May 25 NFR, EPA made affirmative technical determinations as to which of the new (or modified [4] ) or existing major sources or groups of stationary sources named in each petition emit or would emit NOX in amounts that contribute significantly to nonattainment of the 1-hour or 8-hour standard in (or interfere with maintenance of the 8-hour standard by) each petitioning State. All eight of the petitioning States requested that EPA evaluate their petitions with respect to the 1-hour standard. Five of the petitions also requested that EPA evaluate their petitions under the 8-hour standard. The EPA made independent technical determinations for each standard with respect to the individual petitions (see the part 52 regulatory text in the May 25 NFR). The EPA determined that the large EGUs and large non-EGUs in at least some upwind States named in every petition except Vermont's and Rhode Island'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. In aggregate for all the petitions and both ozone standards, EPA made affirmative technical determinations for sources located in 19 States and the District of Columbia. The majority of the sources received affirmative technical determinations under both the 1-hour and 8-hour standards. However, as discussed in Section II.D, sources located in several States received affirmative technical determinations only under the 8-hour standard. As discussed below in Section II.B., EPA had deferred granting the petitions pending certain actions by States and EPA with regard to the NOX SIP call. The EPA's analytical approach and evaluation of each petition is described in Section II of the May 25 NFR (64 FR 28250; May 25, 1999).

B. Findings Under Section 126 and Removal of Trigger Mechanism Based on NOX SIP Call Compliance Deadlines

In the May 25 final rule, EPA had linked its findings under section 126 to the compliance schedule for the NOX SIP call. EPA made affirmative technical determinations regarding the technical merits of the petitions but deferred making findings under section 126 as long as States and EPA were meeting deadlines for action based on the schedule for the NOX SIP call. The findings under section 126 would be automatically triggered only if States or EPA missed one of those deadlines. Specifically, the May 25 NFR provided that EPA would have made a finding that sources were emitting in violation of section 110(a)(2)(D)(i)(I) as of November 30, 1999 if EPA had not proposed approval of SIP revisions complying with the NOX SIP call (or promulgated a Federal implementation plan (FIP)) by that date, or as of May 1, 2000, if EPA had not taken final action to approve SIP revisions (or promulgated a FIP) by that date.

In the June 24 proposal, EPA proposed to delete this automatic trigger mechanism for making findings and instead simply take final action making findings and granting or denying the petitions. For those sources for which it had made affirmative technical determinations, EPA proposed to find that the sources are emitting in violation of section 110(a)(2)(D)(i) and to grant those portions of the petitions. Consistent with these proposed findings, EPA also proposed to remove the automatic trigger mechanism.

In today's action, EPA is finalizing this portion of the rule largely as proposed. However, under this final rule, instead of making the findings based on the 8-hour standard, EPA is indefinitely staying the affirmative technical determinations based on the 8-hour standard, as discussed below. The affirmative technical determinations under the 1-hour standard were based Start Printed Page 2680on a record independent of the record for the affirmative technical determinations under the 8-hour standard. Thus, sources in the seven States for which the determinations were based solely on the 8-hour standard would not at this time be subject to the section 126 remedy.

The EPA believes that the circumstances under which the linkage between action on the section 126 petitions and the NOX SIP call was appropriate are no longer present. Specifically, with no explicit and expeditious deadlines for compliance with the NOX SIP call, it does not make sense for the section 126 findings to depend upon a State's failure to act under the NOX SIP call. It also would be contrary to the language and purposes of section 126 to delay the section 126 findings pending State action under the NOX SIP call, absent a schedule with explicit and expeditious deadlines for compliance with the NOX SIP call. Nor is retention of the linkage between the two rules required by the language of section 110, the cooperative federalism structure of title I of the CAA, or the court's decision to stay the deadlines for States to submit SIP revisions under the NOX SIP call.

EPA's actions in the May 25 NFR and today's rule are driven by a consistent interpretation and application of the relevant statutory provisions. Section 110(a)(2)(D)(i) (combined with EPA's SIP call authority under section 110(k)(5)) and section 126 are two independent statutory tools to address the problem of interstate pollution transport (64 FR 28263-28267). The purpose of each provision is to control upwind emissions that contribute significantly to downwind States' nonattainment or maintenance problems (64 FR 28263-28267). The two provisions differ in that one relies, in the first instance, on State regulation and the other relies on Federal regulation, but Congress provided both provisions without indicating any preference for one over the other. Thus, Congress must have viewed either approach as a legitimate means to produce the desired result. This drives the conclusion that EPA should use, in a particular situation, whichever of these provisions will achieve the purpose of both of them—to reduce interstate pollutant transport.

Promulgation of the NOX SIP call with explicit and expeditious deadlines for SIP submissions and emissions reductions afforded EPA a reasonable expectation that the needed emissions reductions would be expeditiously required through SIP revisions. In those circumstances it made sense for EPA to briefly defer findings under section 126, as long as the States stayed on track to control the emissions. Further, it made sense for EPA to approve findings under section 126 once a State fell off track (as indicated by a lack of EPA proposed or final approval of the required SIP submission by specified dates) because under those circumstances, EPA could no longer reasonably expect that the needed emissions reductions would be timely achieved through a SIP revision. Similarly, under the present circumstances with the stay of the SIP call submission deadlines, EPA is no longer assured that the emissions reductions will be achieved in accordance with the SIP call deadlines. Hence, EPA now must obtain the emissions reductions under section 126 and has no basis for further deferring making the findings under section 126 pending State action under the NOX SIP call.

Throughout the section 126 rulemaking, EPA has been confronted with an unusual factual situation. EPA had previously proposed and then promulgated a SIP call to address interstate transport through State action, and in roughly the same time frame, EPA was required to act on petitions from downwind States to address the same problem under section 126. Because section 126 refers to the prohibition of section 110(a)(2)(D)(i), [5] and the NOX SIP call was based on State violation of the same provision, in the May 25 NFR EPA recognized that the interstate transport problem at issue could be addressed under either provision.

Under section 126, a State may petition EPA to find that any major source or group of stationary sources emits “in violation of the prohibition” of section 110(a)(2)(D)(i). In the May 25 NFR, EPA stated:

EPA interprets section 126 to provide that a source is emitting in violation of the prohibition of section 110(a)(2)(D)(i) where the applicable SIP fails to prohibit (and EPA has not remedied this failure through a FIP) a quantity of emissions from that source that EPA has determined contributes significantly to nonattainment or interferes with maintenance in a downwind [S]tate * * *.In essence, it is a prohibition on excessive interstate transport of air pollutants * * *. Thus, EPA believes a reasonable interpretation is that where the state has failed to implement the prohibition, the SIP allows excessive transport of pollutants, the prohibition is violated, and a source emitting such quantities of pollutants is emitting in violation of the prohibition (64 FR 28272).

An upwind State and EPA may remedy this excessive interstate transport of air pollutants through adoption and approval of a SIP revision barring the emission of such pollutants. Alternatively, a downwind State and EPA may remedy this excessive interstate transport of air pollutants through the State petitioning EPA under section 126 and EPA regulating the sources directly. (See 64 FR 28274.)

Thus, in the May 25 NFR, EPA found that the upwind States could remedy the problem targeted by the section 126 petitions through timely submission of SIP revisions required by the NOX SIP call. This was true because the upwind States were already required to revise their SIPs within explicit and expeditious deadlines under the NOX SIP call, and the deadline for controls to be in place under the NOX SIP call was no later than May 2003 (64 FR 28275). Under these circumstances, EPA believed it made sense to briefly defer final action on the section 126 petitions so that States would have the option of addressing the problem through the imminently required SIP revisions. EPA also provided in the May 25 NFR for State regulation required under the NOX SIP call to substitute for the Federal section 126 remedy in certain circumstances. If EPA had made a finding under section 126 for sources in a State, but EPA subsequently approved the State's SIP revision complying with the NOX SIP call, including the May 2003 date for emissions reductions, the section 126 finding would automatically be withdrawn and sources in that State would no longer be subject to the section 126 remedy.

The statute did not explicitly contemplate EPA's approach in the May 25 NFR. However, EPA believed its approach was based on a reasonable interpretation of the statutory provisions at issue and provided a reasonable way to give meaning to both statutory provisions, without sacrificing the purpose of either. EPA did not suggest that section 126 is subordinate to section 110(a)(2)(D) or that the statute required EPA to provide States time to revise their SIPs before taking action under section 126. As explained at length in May 25 NFR, EPA believes these are two independent provisions under the CAA. EPA stated that its coordinated approach was a “practical” and “reasonable” way “to implement both of these provisions in the same time period, as the timing of the SIP call and the consent decree *** required EPA to do” (64 FR 28275). EPA believes Start Printed Page 2681it was appropriate for EPA to consider the general statutory preference for State action under title I of the CAA, in interpreting how sections 110(a)(2)(D)(i) and 126 related to each other. Yet such a general statutory concept, without any explicit directive, could be no more than a secondary consideration in interpreting the relevant provisions. EPA's primary consideration throughout the section 126 rulemaking has been, as is required by the statute and principles of statutory interpretation, implementation of the explicit directive in both provisions to address interstate pollution transport problems as required under each provision. Section 126 requires EPA to direct sources to reduce emissions “as expeditiously as practicable, but in no case later than 3 years after the date of [the] finding.” Making affirmative technical determinations rather than findings and providing for subsequent automatic findings upon a State failure to act still ensured that under either the NOX SIP call or section 126, the necessary emissions reductions would occur by the 2003 ozone season, which allowed the maximum permissible 3-year lead time and which EPA determined was as expeditiously as practicable.

Certain commenters assert that the CAA required EPA to defer action under section 126 until States had failed to act under the NOX SIP call, and hence, that EPA now must continue and extend the linkage between the two rules by deferring any action under section 126 until after the NOX SIP call litigation has been resolved. The commenters further argue that action now on the section 126 petitions circumvents the court's stay of the NOX SIP call by pressuring States to comply with the NOX SIP call, and if they fail to do so, impermissibly dictating their future compliance options. The commenters are, in effect, arguing that EPA must subordinate section 126 to section 110(a)(2)(D)(i) (implemented through a SIP call under section 110(k)(5)), and that EPA must exhaust the remedies available through its SIP call authority before the Agency can act under section 126.

EPA disagrees with these comments. First, there is simply no statutory basis for EPA to indefinitely deny relief to downwind States harmed by pollution transported from upwind States. Congress provided section 126 to downwind States as a critical remedy to address pollution problems affecting their citizens that are otherwise beyond their control, and EPA has no authority to refuse to act under this section. To the contrary, section 126 provides explicit tight deadlines for EPA to act on a petition and for sources to achieve the reductions. EPA must make a finding or deny a petition within 60 days of its receipt. Section 126(b). Further, sources must shut down within 3 months of a finding, unless EPA allows them more time, but no longer than 3 years, to reduce emissions as expeditiously as practicable. (Section 126(c)). Moreover, commenters point to no statutory provisions supporting their argument that EPA may disregard the plain language of section 126 in favor of proceeding first under section 110(k)(5), and the lack of statutory support for their position is particularly troublesome where there is no certain or near-term date for compliance with a SIP call that would satisfy the timing requirements of section 126. The statutory language, structure and legislative history indicate far more Congressional concern for protecting downwind States' interest in ensuring clean air for their citizens than for protecting upwind States' interest in controlling their own sources of emissions. (See 64 FR 28258-28267, 28271-28277.) In particular, the structure of section 126, including the relatively short time frame for implementing the remedy it provides, strongly supports EPA's view of Congressional intent.

In the May 25 NFR, EPA explicitly rejected the suggestion that the Agency has discretionary authority to grant petitions under section 126 only after EPA has promulgated a SIP call under section 110(k)(5) to require States to comply with section 110(a)(2)(D)(i) and States have failed to comply with that SIP call. First, such an interpretation would make section 126 redundant with section 110(c), which already allows EPA to control sources directly through FIPs when a State has been required to submit an adequate SIP and fails to do so. Second, such an interpretation negates the purpose of section 126, “which is designed to provide recourse to downwind states” (64 FR 28274). EPA continued:

As discussed [earlier in the May 25 Rule], no progress had been made on interstate transport problems at the time of enactment of both the 1977 and 1990 Amendments. Section 126 provides a tool for downwind states, the entities with most at stake, to force EPA to confront the issue directly. It also sets up an abbreviated, and hence potentially faster, process to achieve emission reductions. Under the SIP process, EPA must direct a state to revise its SIP to comply with 110(a)(2)(D), and then perhaps find that the state has failed to comply, impose sanctions, and finally promulgate a Federal implementation plan, all of which could potentially stretch out for many years. In contrast Congress required very expeditious EPA action on a petition and from 3 months up to three years for sources to comply. It is perfectly reasonable for Congress to have established section 126 as an alternative mechanism under the Clean Air Act to address the interstate pollution problem, just as it did again in adopting sections 176A and 184. To provide alternatives, the various interstate transport provisions are necessarily different from each other and from other provisions of the Act, but that does not make them inconsistent with other provisions of the Act. Id.

Just as there is no requirement for EPA to issue a SIP call before acting under section 126, the mere existence of a SIP call for States to address the problem cannot bar EPA from acting under section 126. This is even more clearly the case where there are no deadlines for States to act under the SIP call, or the deadlines do not satisfy the schedule contemplated by section 126.

The cooperative federalism principles in the CAA also do not support a different reading of these provisions, as certain commenters suggest. Title I of the CAA, which contains the provisions for EPA air quality standards and State implementation provisions, is primarily based on a cooperative federalism approach. Under this approach, air pollution planning and control at the State level is complemented by Federal regulation and enforcement to achieve clean air goals. Congress has demonstrated no reluctance to mandate Federal action wherever it is useful in addressing air pollution problems. See, e.g., title I (sections 111, 112, 183(e)), title II (section 201 et seq.), title IV (section 401 et seq.), and title VI (section 601 et seq.). In addition to the strong oversight role that EPA plays under title I in requiring States to submit SIPs and ruling on their adequacy, Congress directed EPA to regulate sources directly under several provisions of title I where State action was inadequate or where Federal action was preferable. In particular, Congress mandated Federal action under sections 110(c) (FIP provisions), 126, and 183 (Federal ozone measures). The language of section 126 is unambiguous in directing EPA to act on petitions from downwind States within a specified time frame, without any prerequisite of a State's failure to comply with a SIP call. Such clear language should not be construed to be overridden by a general principle, such as cooperative federalism, embedded in the overall statutory approach. Moreover, such a construction would be even less defensible here, where relying on cooperative federalism to delay action under section 126 for an undefined and lengthy period would run directly counter to a far more pervasive and powerful general Start Printed Page 2682principle embedded in the CAA “Congress” overarching goal that the American public should breathe clean air.

In addition, deferring action on the section 126 petitions until resolution of the NOX SIP call litigation would almost certainly mean that the emissions would not be controlled in time for the 2003 ozone season if EPA retained the 3-year lead time for sources to comply. In the May 25 Rule, EPA was able to give upwind States an opportunity to address the ozone transport problem themselves, but without delaying implementation of the remedy beyond May 1, 2003. This was the date by which sources could reduce emissions as expeditiously as practicable, and it was no later than 3 years from the date of the finding.[6] In the NOX SIP call and the section 126 rule, EPA conducted extensive analyses and determined that sources could implement highly cost-effective controls on NOX emissions within a three year period. See 63 FR 57447-57449; Feasibility of Installing NOX Control Technologies By May 2003, EPA, Office of Atmospheric Programs, September 1998 (Docket No. A-97-43, Document No. II-C-10). Section 126 requires that sources reduce emissions “as expeditiously as practicable, but in no case later than 3 years after the date” of EPA's finding under section 126. Under the May 25 rule, EPA's finding would have been made under the automatic trigger provisions by November 30, 1999 or May 1, 2000. Thus, the May 1, 2003 deadline for reductions would require sources emitting in violation of the prohibition of section 110 to reduce emissions “as expeditiously as practicable” and no later than the three year limit, as required by section 126. Similarly, as today's final findings will become effective on February 17, 2000, the May 1, 2003 deadline for emissions reductions meets the timing requirements of section 126.

As there are now no explicit and expeditious deadlines for State action to address this interstate transport problem under the NOX SIP call, there is now no basis for EPA to defer taking final action on the section 126 petitions. The language of section 126 does not explicitly provide for any deferral of EPA action. To the contrary, the very tight deadlines for EPA to act on the petitions and for sources to comply strongly indicate Congress' intent to provide downwind States a remedy for transported pollution and to force action under this provision. Here, without deadlines for SIP submissions, deferring final action on the section 126 petitions pending eventual State action under the NOX SIP call would run directly counter to the language and purpose of section 126 and the CAA. The statutory language provides no support for such an approach, much less mandates it, as some commenters suggest.

Commenters also claim that EPA may not now move forward under section 126 because such action would improperly pressure upwind States in at least two ways. Specifically, these commenters claim that EPA's action under section 126 forces upwind States to select control measures identical to those on the section 126 sources, which they claim is contrary to the court's decision in Virginia v. EPA. 108 F.3d 1397 (D.C. Cir.), modified on other grounds, 116 F.3d 499 (D.C. Cir., 1997). They also argue that EPA is coercing these States into complying with the NOX SIP call now, thereby circumventing the court's stay of the compliance deadline.

Applying section 126 independent of an upwind State's failure to act under section 110(a)(2)(D) does not impermissibly pressure upwind States to select certain control measures. EPA acknowledges that because the section 126 findings precede any required State action under the NOX SIP call, if and when States are eventually required to submit SIPs to control interstate transport, one of the largest sources of emissions will already be subject to emission control requirements, and, depending upon the timing, may have already invested in controls. Yet this is not a legal constraint on States' choices—it is the reality that over time, conditions change, and different policy choices become more or less attractive for a variety of reasons. States would still be able to choose to regulate other sources, but depending upon the timing, the option of obtaining emission reductions from sources that have already invested in emission control or have already reduced emissions may be more attractive on policy and economic grounds than regulating those sources otherwise would have been. There is a vast difference between, on one hand, EPA prescribing a particular emissions control choice that States must adopt, and on the other, taking action required under the CAA, to regulate sources directly, with the possible effect of making certain future emissions control choices by some States more or less appealing.

Such an effect on the regulatory environment cannot override the requirement that EPA act on State petitions under section 126. It is simply unreasonable to argue that EPA can take no action under an independent provision of the statute to respond to petitions submitted by downwind States facing their own time constraints and pressures to meet air quality standards, just to preserve the relative attractiveness of a variety of options for control of NOX in the upwind States required under another provision of the CAA. The cooperative federalism principles of the CAA do not require EPA to withhold Federal action under section 126 until States have been required to and failed to submit SIPs.

The commenters are essentially arguing that not only the clock for SIP revisions, but the entire regulatory setting, must stop for the duration of the litigation on the NOX SIP call. Their position would require EPA to freeze the current situation in place to preserve for the future in their present form all options available now. Yet inhabitants of downwind States continue to breathe significant pollution contributed by upwind sources, the CAA calls for attainment as expeditiously as practicable, and there are highly cost-effective remedies available now (as discussed in detail in the May 25 NFR). (See 64 FR 28298-28304.) In these circumstances, EPA does not believe it should, let alone must, refrain from requiring those upwind sources to implement those remedies now.

In addition, a State will still have the option of preempting the section 126 remedy and selecting a different set of controls to address the interstate pollution transported from the State. The May 25 NFR provided that if a State submits and EPA approves a SIP revision meeting the requirements of the NOX SIP call, the section 126 finding will automatically be revoked for sources in that State. EPA does not expect most of the upwind States subject to the NOX SIP call to submit SIP revisions under the NOX SIP call while the litigation is ongoing. There is no currently effective requirement to submit such a SIP revision, and the litigation has produced uncertainty regarding the content and timing of future requirements on States under the NOX SIP call. Nevertheless, the option is available if a State chooses to use it, and several of the Northeastern States have informed EPA that they still plan to submit SIP revisions complying with Start Printed Page 2683the NOX SIP call in the fall of 1999 for the benefit of the region as a whole.[7]

In support of their assertion that EPA may not proceed with action under section 126 before States have failed to comply with the NOX SIP call, commenters also misstate and misconstrue EPA's discussion in the May 25 NFR of a particular approach that might be viewed as impermissibly pressuring upwind States to adopt specific control measures. However, EPA rejected that approach in the May 25 NFR, and the situation that EPA viewed with concern in the May 25 NFR would not arise from today's action under section 126.

Other commenters on the section 126 proposal of October 21, 1998 had opposed EPA's proposal to deny petitions under section 126 where a State had complied with the NOX SIP call. Rather, they suggested, EPA should keep both the section 126 requirements and the NOX SIP call in place simultaneously. This would establish section 126 as a backstop to the NOX SIP call in case sources failed to comply with State regulatory requirements.

EPA rejected this suggestion on several grounds, some of which were the practical problems raised by subjecting sources in the same State to two contemporaneous, but potentially different, sets of control requirements. The commenters had suggested that if the sources controlled by the State failed to implement the reductions by May 1, 2003, the section 126 remedy should apply to the sources covered by EPA's rule. However, as EPA noted in the May 25 rule, if the State chose to obtain the reductions in a manner different from the section 126 remedy (imposing looser or no controls on the section 126 sources), the commenters' suggested approach could increase the overall control burden because in practice, the sources controlled by the State and the section 126 sources might both reduce emissions. Only the State-controlled sources would initially be under a legal obligation to control. But if those sources did not meet the May 1, 2003 control deadline, under the commenters' suggested approach, the section 126 sources would suddenly become liable for violations of the CAA. To avoid such a risk, the section 126 sources would also implement controls. Yet full implementation of the set of controls either mandated by the State and approved by EPA under section 110, or mandated by EPA under section 126, would be sufficient to eliminate the emissions that contribute significantly to downwind nonattainment or maintenance problems. Thus, the overall burden of achieving the emission reductions could be higher than necessary, depending upon the degree to which the two sets of control requirements were non-identical. (64 FR 28275-28276.)

Thus, in the May 25 NFR, EPA rejected the suggestion that the section 126 remedy should apply as a backstop to sources in a State even after that State had complied with the NOX SIP call and EPA had approved the revised SIP. EPA was concerned about the potential inefficiency of having sources simultaneously complying with two different sets of controls, and thereby actually controlling more emissions than required to correct the interstate transport problem. In the May 25 rule, EPA noted that setting up the rule to retain the section 126 remedy as a backstop in addition to an approved SIP revision might be viewed as effectively impermissibly pressuring States to adopt in their SIPs controls identical to the section 126 controls, as States might conclude that identical controls would minimize the overall compliance burden. (64 FR 28276.)

Today's rule would not create the situation discussed in the May 25 NFR. EPA is implementing the requirements of section 126 of the CAA in the absence of any currently effective requirement for upwind States to address the interstate pollution transport problem themselves. EPA is not making sources potentially subject to two contemporaneous, potentially conflicting, regulatory regimes. Depending upon the timing of a State's eventual compliance with the NOX SIP call, the section 126 requirements may affect the regulatory context, such that it may be more attractive than might otherwise have been the case for States in their SIPs to obtain emissions reductions from the section 126 sources. As discussed above, however, this does not impermissibly pressure the States to adopt any particular control remedy. There will always be numerous factors affecting complex policy decisions regarding pollution control, and EPA's actions under the CAA will often affect some of those factors. That cannot mean that EPA must refrain from implementing the CAA for fear of producing real world effects that may indirectly influence State policy choices.

EPA has not included in today's rule a provision to automatically withdraw the section 126 findings upon EPA approval of a later SIP revision that complies with the NOX SIP call, as ultimately modified after the litigation is concluded. Assuming EPA prevails in the NOX SIP call litigation, the court or EPA would need to establish a new deadline for SIP submissions, and the delay from the original September 1999 deadline may require a shift in the date for achieving emissions reductions beyond May 2003. If and when such a situation arises, EPA will address through rulemaking the effects of such later NOX SIP call SIP submissions on the section 126 findings. A number of reasons supported structuring the May 25 NFR to provide for an automatic withdrawal of the section 126 finding upon approval of a SIP revision complying with the NOX SIP call as promulgated. As discussed above, EPA believes it is appropriate, when consistent with the relevant statutory provisions, to structure the section 126 rule to allow for State rather than Federal regulation when either would equally effectively implement the statutory goal of producing timely reductions. The withdrawal provision also explicitly removes any possibility of an overlap between the Federal requirements under section 126 and State measures required by the NOX SIP call. For the situation where States are again subject to the NOX SIP call requirements, a State has adequately addressed the section 110(a)(2)(D)(i) requirement, EPA has approved the SIP revision, and the State requirements are in effect, the same considerations are likely to support withdrawal of the section 126 findings at that time. At this point, however, there are several key unknown variables, such as the final substance and timing of the requirements of the NOX SIP call. As a consequence, EPA does not believe it would be useful to try to establish a rule now that would address all future contingencies. EPA expects to revisit this issue upon resolution of the NOX SIP call litigation.

EPA's regulation of sources under section 126 also does not practically or legally coerce upwind States to comply with the NOX SIP call, as certain commenters claim. The commenters argue that States are forced to comply with the NOX SIP call to protect their sources from Federal regulation. They further argue that since the court has stayed the deadlines for States to submit SIP revisions under the NOX SIP call, such pressure on States circumvents the court's grant of the stay of the NOX SIP call requirements.

EPA disagrees that taking action under section 126 pressures States to comply with the NOX SIP call now. EPA is directly regulating certain sources that emit in violation of section Start Printed Page 2684110(a)(2)(D) and contribute significantly to downwind nonattainment. EPA's regulation of these sources imposes no direct or indirect burden on the States in which these sources are located. In the likely event that many or most of the upwind States take no action on SIP revisions unless and until there are new deadlines for SIP submissions under the NOX SIP call, there will be no sanctions or any other penalties for their inaction. [8] Nor will such States need to make larger or different emissions reductions if they later impose State regulations to control NOX emissions. The only effect on States, as discussed above, is that EPA's action may make certain control options relatively more or less attractive than they are now, as section 126 sources will begin to invest in controls. The degree of such effects may depend in part on the timing of the State action and sources' compliance plans. The fact that upwind States have not yet chosen to control their emissions sources should not on policy grounds, and does not on legal grounds, bar downwind States from seeking to obtain emissions reductions directly from the contributing sources; nor does it bar EPA from acting to obtain those reductions in response to the States' request.

Commenters also argue that the similarity between the remedy under section 126 and the proposed FIP for failure to comply with the NOX SIP call suggests that EPA is using section 126 in lieu of a FIP either to force States to comply with the SIP call regardless of the court's stay or to impose a Federal remedy. This, they assert, is contrary to the court's decision to impose a stay and removes the benefit that the stay provided for upwind States.

EPA is using section 126 to reduce interstate transport, as required by section 126, not to pressure States to comply with the NOX SIP call. The federal remedies under section 126 and the proposed FIPs are similar because they both are intended to correct a violation of the same provision, section 110(a)(2)(D), which prohibits emissions that contribute significantly to nonattainment or interfere with maintenance in downwind States. However, the statutory authorities for the two actions are distinct, and the actions have very different effects on States. EPA action under section 126 effectively relieves States of the necessity of regulating their sources that contribute to downwind nonattainment, and there are no penalties associated with EPA's assumption of responsibility. In contrast, if EPA promulgates a FIP under section 110(c) of the CAA following a State's failure to comply with a SIP call, after eighteen months, the State will become subject to sanctions until it corrects the deficiency. (See sections 110(m), 179; 63 FR 57452-57453.) These sanctions may take the form of reductions in or restrictions on the use of highway funds and/or requirements for new sources to increase the emission offset already required for their emissions. (See sections 110(m), 179; 63 FR 57452-57453.) The stay of the NOX SIP call deadline indefinitely stayed the requirement for upwind States to submit SIP revisions to comply with the NOX SIP call, which means that a State would not be subject to a FIP or sanctions, and EPA's action under section 126 in no way reimposes the SIP submission requirement or the penalty for inaction.

Certain commenters also point to EPA's retention of the provision for automatic withdrawal of the section 126 findings upon approval of a SIP revision complying with the NOX SIP call as an indicator of EPA pressure. They argue that because this provision allows States to preempt the section 126 remedy if they comply with the NOX SIP call, EPA retained the provision to induce States to comply with the NOX SIP call despite the judicial stay. The fact is, however, that under EPA's interpretation of the requirements of sections 110(a)(2)(D) and 126, a State's compliance with the NOX SIP call, as promulgated (including the May 1, 2003 deadline for sources to implement controls), would eliminate the violation of section 110(a)(2)(D) by sources in such State, and hence remove the basis for granting a section 126 petition with respect to such sources. This provision ensures that potentially nonidentical Federal and State remedies do not apply simultaneously to sources in a State. Also, where State and Federal remedies would be equally effective in reducing emissions, this provision allows State regulation required under the NOX SIP call to substitute for the Federal remedy under section 126, consistent with EPA's approach to implementing both provisions, as described above. Thus, this provision made sense at the time EPA issued the May 25 NFR, and nothing in the current circumstances suggests that EPA should now remove this option for States. Although the court has stayed the deadline for States to comply with the NOX SIP call, the court's action had no effect on a State's authority to revise its SIP if it so chooses. The court's decision also has no effect on EPA's authority to withdraw a section 126 finding. Since both of those authorities may still be exercised, there is no reason EPA should now remove the pre-existing provision.

As EPA has done no more than retain a pre-existing regulatory provision where there was no reason to remove it, this should not be misconstrued as demonstrating an intent to pressure States into complying with the NOX SIP call. EPA's retention of this element of the rule gives States an option. It is neither intended to force, nor has an impermissible practical effect of forcing (as discussed above), States to take that option.

C. Section 126(b) Findings Under the 1-Hour Ozone Standard

In the May 25 NFR, EPA determined that the petitions from Connecticut, Massachusetts, New York, and Pennsylvania are partially approvable under the 1-hour standard based on technical considerations. In aggregate for these four petitions, EPA made affirmative technical determinations of significant contribution under the 1-hour standard for large EGUs and large non-EGUs located in the District of Columbia and the following 12 States: Delaware, Indiana, Kentucky, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia. In today's rule, EPA is making findings under section 126(b) that each of the new or existing sources, for which EPA made an affirmative technical determination, emits or would emit NOX in violation of the prohibition of CAA section 110(a)(2)(D)(i)(I) with respect to nonattainment of the 1-hour standard in the relevant petitioning State. The regulatory text of today's rule sets forth the findings with respect to each petition.

For the District of Columbia and eight of the affected States, the combined findings apply throughout the entire jurisdiction. However, the findings cover only parts of Indiana, Kentucky, Michigan, and New York. The findings for sources located in these States are being made with respect to the petitions from Connecticut and/or New York. In the NOX SIP call, EPA determined that the States of Indiana, Kentucky, and Michigan wholly significantly contribute to New York, and those three States plus New York wholly significantly contribute to Connecticut. Start Printed Page 2685However, only parts of these upwind States were named in the petitions from Connecticut and New York and EPA must limit any section 126 findings to the geographic scope of the relevant petition. New York described the geographic scope of its petition as Ozone Transport Assessment Group (OTAG) Subregions 2, 6, and 7 and the portion of Ozone Transport Region extending west and south of New York. Connecticut described the geographic scope of its petition as OTAG Subregions 2, 6, and 7 and the portion of the Ozone Transport Region extending west and south of Connecticut. Maps showing the geographic scopes of these two petitions are shown in Figures F-2 and F-6 of Appendix F to part 52. Based on the geographic limits given in the petitions, the portions of the four partial States covered by today's 1-hour findings are as follows. For Indiana and Kentucky, the 1-hour findings affect sources located east of 86.0 degrees longitude. For Michigan, the 1-hour findings affect sources located in the area east of 86.0 degrees longitude and south of 45.0 degrees latitude. For New York, the 1-hour findings affect sources located in the area west of 71.8 longitude and south of 42.03 degrees latitude. The existing sources located in these States that are subject to the 1-hour findings are listed in Appendix A to part 97. The EPA notes the combined affirmative technical determinations under the 1-hour and 8-hour standards would cover the States of Indiana, Kentucky, Michigan, and New York in their entireties. However, as discussed below, EPA is indefinitely staying the 8-hour affirmative technical determinations.

D. Stay of Affirmative Technical Determinations Under the 8-Hour Ozone Standard

1. Affirmative Technical Determinations Under the 8-Hour Ozone Standard

Five of the eight petitioning States (Maine, Massachusetts, New Hampshire, Pennsylvania, and Vermont) requested that EPA evaluate their petitions under the 8-hour standard. In the May 25 NFR, EPA determined that all but the Vermont petition are partially approvable under the 8-hour standard based on technical considerations. In aggregate for the four approvable petitions, EPA made affirmative technical determinations of significant contribution under the 8-hour standard for large EGUs and large non-EGUs located in the District of Columbia and the following 19 States: Alabama, Connecticut, Delaware, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, Tennessee, Virginia, and West Virginia. There are seven whole States and portions of four other States that are covered only under the 8-hour standard.

2. Stay of the 8-Hour Affirmative Technical Determinations

EPA continues to evaluate the effect of the D.C. Circuit's decision on the 8-hour NAAQS in American Trucking, as modified by the D.C. Circuit's October 29, 1999 opinion and order. See American Trucking Ass'n v. EPA, 175 F.3d 1027 (D.C. Cir. 1999), reh'g granted in part and denied in part, No. 97-1440 and consolidated cases (D.C. Cir. October 29, 1999). In addition, the Agency has recommended that the Department of Justice seek certiorari in the NAAQS litigation. Thus, EPA expects that the status of the eight-hour standard will be uncertain for some time to come.

In light of this uncertainty, EPA believes that EPA should not continue implementation efforts under section 126 under the 8-hour standard that could be construed as inconsistent with the court's ruling. Therefore, EPA is staying indefinitely the section 126 affirmative technical determinations based on the 8-hour standard, pending further developments in the NAAQS litigation. This stay affects the affirmative technical determinations under the 8-hour petitions filed by the States of Maine, Massachusetts, Pennsylvania, and New Hampshire. The State of Vermont also submitted an 8-hour petition; however, EPA fully denied that petition in the May 25 NFR. In aggregate for the 8-hour petitions, the stay affects the 8-hour affirmative technical determinations made for sources located in District of Columbia and the 19 States listed above in Section II.D.1. However, EPA is making findings under the 1-hour standard for sources located in the District of Columbia and at least portions of 12 of these States. The 1-hour findings are not affected by the 8-hour stay and therefore sources in these States (or portions thereof) are still subject to the control requirements in today's rule. The EPA made section 126 affirmative technical determinations only under the 8-hour NAAQS, and not under the 1-hour NAAQS, for sources located in the following seven States: Alabama, Connecticut, Illinois, Massachusetts, Missouri, Rhode Island, and Tennessee. In addition, EPA made section 126 affirmative technical determinations under the 8-hour standard, and not under the 1-hour NAAQS for sources located in portions of Indiana, Kentucky, Michigan, and New York. Sources located in the seven States and portions of the four other States listed above are not required to implement section 126 controls under this rule for so long as the 8-hour stay is in place. (See Section II.C. for a description of the portions of the four States that are covered by the 1-hour findings.)

Commenters generally supported the indefinite stay of the affirmative technical determinations based on the 8-hour NAAQS pending further developments in the NAAQS litigation. However, a number of commenters suggested that it would be better for EPA to deny the portions of the petitions based on the 8-hour standard, rather than just staying the affirmative technical determinations. EPA promulgated the affirmative technical determinations based on the 8-hour standard in a final rule. EPA has neither moved forward based on the 8-hour standard, nor revisited the May 25 rule, but has simply stayed this portion of the May 25 rule for the interim. As discussed above, the status of the 8-hour standard is still uncertain and the litigation may well continue. Given this uncertainty, EPA believes that it would not be appropriate for the Agency at this time to address the question of whether to grant or deny the portions of the section 126 petitions based on the 8-hour standard. Staying the affirmative technical determinations based on the 8-hour standard assures that the section 126 rule will impose no compliance burdens based on the 8-hour standard. Also, EPA would engage in a rulemaking to lift the stay and make findings based on the 8-hour standard, and in that rulemaking any issues on using the 8-hour standard as a basis for action under section 126 would be open for public comment.

E. Requirements for Sources for Which EPA Is Making a Section 126(b) Finding

The control requirements for sources for which EPA is making effective section 126(b) findings are discussed in Section III below. As discussed above, currently the control requirements would only apply to sources for which a finding is being made under the 1-hour standard.

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 Start Printed Page 2686

(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 3-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 3 years after the date of such finding.

The remedial requirements that EPA is finalizing in today's action for sources for which a section 126(b) finding is ultimately made would satisfy the requirements just quoted. First, EPA is requiring that 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 finalizing 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 3 months after the finding is made.

III. Section 126 Control Remedy: The Federal NOX Budget Trading Program

A. Program Overview

1. Relationship Between Today's Action and the May 25, 1999 Section 126 Final Rule

In the October 21, 1998 section 126 proposal, EPA proposed a cap-and-trade program as a highly cost-effective approach to achieving necessary emissions reductions from large stationary sources. This remedy would apply to any new or existing major source or group of stationary sources for which a finding is made under section 126.

The cap-and-trade program is a proven method for achieving air quality objectives, while simultaneously providing compliance flexibility to sources. The freedom to pursue various compliance strategies (i.e., switching fuels, installing pollution control technologies, or buying authorizations to emit from other firms) reduces the cost of compliance in a market-based program relative to costs under a command-and-control approach. Since emitting fewer tons than the allocation results in surplus allowances that may be sold on the market, pollution prevention becomes increasingly cost effective and innovation in control technology is encouraged. The appropriateness of trading as a section 126 remedy is comprehensively discussed in Section IV.A. of the preamble to the May 25, 1999 final rule (64 FR 28307-28309).

As explained in the October 21, 1998 section 126 proposal (63 FR 56309-56320), under a cap-and-trade system the Administrator sets both 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 generally 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.

For purposes of complying with section 126, EPA translates emission limits into allowance requirements. Since EPA has the authority to establish emission limits under section 126, and since allowance requirements are equivalent to emission limits, EPA has the authority to promulgate allowance requirements and allocate allowances for purposes of section 126. The cap-and-trade program is a compliance mechanism that enables sources to make cost-effective decisions to meet their allowance requirements (which are their emission limits). Therefore, EPA adopted such a program as a cost-effective means of implementing the requirements of section 126.

Section 52.34(j) of the May 25, 1999 final rule established the cap-and-trade program as the general remedy for sources that will be subject to any future finding under section 126. In § 52.34(j), the EPA promulgated general parameters for the remedy, including the identification of the categories of sources that would be subject to the trading program, the specification of basic emission limitations for covered sources, total emissions reductions to be achieved by the program, and the compliance schedule. Section 52.34(j) also identified the methodology used to determine the NOX emissions budget (i.e., the total amount of NOX allowances allocated to all units subject to the Federal NOX Budget Trading Program) and created a compliance supplement pool.

The regulatory language finalized in the May 25, 1999 section 126 final rule delineated the following general elements of the trading program, listed here:

  • All large EGUs and large non-EGUs for which EPA makes a final finding under section 126(b) will be covered by and subject to the Federal NOX Budget Trading Program.
  • Beginning May 1, 2003, the owner or operator of each source subject to the Federal NOX Budget Trading Program must hold NOX allowances available to that source in the ozone season that are not less than the total NOX emissions emitted by the source during that ozone season.
  • The total tons of NOX allowances allocated under the trading program (other than any compliance supplement pool credits) will be equivalent to the sum of two tonnage limits:

(a) The total tons of NOX that large EGUs in the program would emit in an ozone season after achieving a 0.15 lb/mmBtu NOX emissions rate, assuming historic ozone season heat input adjusted for growth to the year 2007; plus

(b) The total tons of NOX that large non-EGUs in the program would emit in an ozone season after achieving a 60 percent reduction in ozone season NOX emissions compared to uncontrolled levels adjusted for growth to the year 2007.

  • Compliance supplement pool credits will be available for distribution to affected sources, subject to specific State-by-State tonnage limits as established in the NOX SIP call.

In the May 25, 1999 section 126 final rule, EPA did not promulgate either the part 97 rule provisions providing the specific details of the trading program for the section 126 remedy or the unit-specific allocations (as explained in Section IV.C.2. of the preamble to the May 25, 1999 final rule). Under § 52.34(k), EPA specified the interim final emissions limitations that would be imposed in the event that the Administrator made a finding under section 126 pursuant to provisions of § 52.34(h), without first promulgating regulations setting forth the details of the NOX Budget Trading Program. The default emissions limitations were finalized under the “good cause” exemption to the Administrative Procedure Act's notice and comment requirements for rulemaking (see 5 U.S.C. 553(b)(B)). In the May 25, 1999 section 126 final rule, EPA emphasized that this default remedy would be superseded as a matter of law when EPA Start Printed Page 2687promulgates the details of the Federal NOX Budget Trading Program (64 FR 28311). The final rule specified that EPA would issue these detailed elements by July 15, 1999.

In light of the two court decisions by the U.S. Court of Appeals detailed in Section I.A.1., EPA subsequently proposed to amend certain aspects of the section 126 final rule. In the June 24, 1999 “Proposal to Amend Two Respects of May 25, 1999 Final Rule”, the Agency proposed to remove the link between the NOX SIP call's submission deadline and the final action granting or denying the 126 petitions, and indefinitely stay the 8-hour portion of the rule pending further developments in the ongoing NAAQS litigation. In a separate but related action, EPA voluntarily stayed the effectiveness of the May 25, 1999 section 126 final rule on an interim basis until November 30, 1999, in order to respond to the Court's decisions. Together, these actions affected the July 15, 1999 objective for finalization of the trading program provisions. The Agency decided to issue the elements of the Federal NOX Budget Trading Program with the final section 126 findings.

Today's section 126 final rule amends the regulatory language that established the elements of the control remedy promulgated in the May 25, 1999 section 126 final rule (listed above). Specifically, today's rule replaces four of the elements from the May 25, 1999 final rule with related provisions under part 97, while one of the elements remains essentially unchanged. The replacements are substitutions, that are essentially equivalent to the May 25, 1999 section 126 regulations. First, the allowance-holding requirements in part 97 (i.e., § 97.6(c)) replace the element in the May 25, 1999 final rule (§ 52.34(j)(1)) that required the owner or operator of each source to hold a number of NOX allowances not less than the total tons of NOX emitted by the source during the ozone season. Second, the default control provisions (§ 52.34(k)), mandated in the event that EPA failed to promulgate the trading program regulations, are replaced by part 97, and by the unit-specific allocations and compliance supplement pool provisions in particular. Third, the element that specified the methodology for calculating the total tons of NOX allowances allocated under the trading program (§ 52.34(j)) is replaced by the trading program budget provisions in part 97 (i.e., § 97.40). The methodology for calculating the allocations was followed, so there is consequently no reason to retain the original language. Fourth, the element providing for the compliance supplement pool (§ 52.34(j)(4)) is embodied in and replaced by § 97.43, which addresses in detail the procedures for distributing the pool of allowances. Fifth, the element that requires those sources for which EPA makes a final finding under section 126(b) to be subject to a Federal NOX Budget Trading Program (§ 52.34(j)) remains essentially unchanged and is not replaced.

By specifying the details of the Federal NOX Budget Trading Program for the section 126 sources, today's action fulfills the regulatory obligations deferred under the May 25, 1999 section 126 final rule. As noted above, the May 25, 1999 final rule established general parameters for the cap-and-trade remedy, while today's final rule finalizes the specific elements of the trading program. In particular, the trading program's unit allocation methodology is described, and the procedure for distributing NOX allowances from the compliance supplement pool is provided. This final rule also specifies the combined list of existing sources affected by one or more petitions, along with finalized emissions limitations in the form of tradable unit-by-unit allowance allocations for 2003 to 2007. Also included in this final rule are new sources in the source categories that are significantly contributing with respect to the petitions from Connecticut, New York, and Pennsylvania. By specifying the unit-by-unit allowance allocations, today's action supersedes as a matter of law the interim emissions limitations established by the May 25, 1999 final rule in § 52.34(k). Because the interim emissions limitations are superseded, today's rule expressly removes § 52.34(k).

As noted earlier in this section, two decisions by the U.S. Court of Appeals in the District of Columbia have led the EPA to amend certain provisions of the May 25, 1999 section 126 final rule. The Court decision on the 8-hour ozone non-attainment standard has reduced the total number of States subject to the Federal NOX Budget Trading Program. Further, as described in Section III.B., certain portions of Michigan, Indiana, Kentucky, and New York have been removed from the scope of the original petitions, leaving only certain sources within these States subject to the trading program. Section III.B. of this preamble contains some discussion of the provisions of part 97 that have been modified to reflect removal of portions of these States.

2. Elements of the Federal NOX Budget Trading Program That Are Essentially the Same as the State NOX Budget Trading Program and the October 21, 1999 Section 126 Proposed Rule

As in the October 21, 1998 section 126 proposal, today's Federal NOX Budget Trading Program (40 CFR part 97) mirrors, to a large extent, the NOX Budget Trading Program for States (40 CFR part 96), which is the model trading program made available for States to adopt under the NOX SIP call. Today's promulgation of the final regulations for the Federal NOX Budget Trading Program moots § 52.34(j)(2), which is removed. The EPA notes that discussion of the evolution of the NOX Budget Trading Program is set forth in the proposed supplemental rule to the NOX SIP call at 63 FR 25921-25923, in the final NOX SIP call rule at 63 FR 57456-57457, and in the preamble to the May 25, 1999 section 126 final rule at 64 FR 28307-28308. While EPA has sought to keep the two trading programs similar, there are a number of differences which are more fully described in Section III.A.3., below. These differences arise from the need for Federal implementation of the section 126 program, rather than State implementation, and from the need to clarify or simplify certain provisions.

Under part 97, the program elements described below are essentially the same as the corresponding sections in part 96, which set forth the State NOX Budget Trading Program. Since EPA retains or relies upon many of the analyses and considerations undertaken in the NOX SIP call process to determine these program elements, many of these part 97 provisions are being used for the reasons set forth in the proposed NOX SIP call and the final NOX SIP call. Detailed information on the rationale for the part 96 provisions can be found in the preamble accompanying the proposed part 96 (63 FR 25917-25943) and the final part 96 (63 FR 57356-57491). Moreover, the provisions in part 97 are, for the most part, numbered in the same sequence as the corresponding provisions in part 96, so that, for example, § 97.2 and § 96.2 address the same subject matter. Cross references in these provisions and other provisions of part 97, of course, reflect the numbering for the appropriate regulatory provisions in part 97, rather than the numbering for provisions in part 96.

The following list identifies the sections of part 97 that are essentially the same as the corresponding sections in part 96 and in the October 21, 1998 section 126 proposed rule. Additional information on the following subparts Start Printed Page 2688can be found in the preamble accompanying the proposed part 97 (63 FR 56310-56313).

Subpart A—NOX Budget Trading Program General Provisions
97.3
Measurements, abbreviations, and acronyms.
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 NOX authorized account representative.
97.11
Alternate NOX authorized account representative.
97.12
Changing NOX authorized account representative and alternate NOX authorized account representative; changes in owners and operators.
97.13
Account certificate of representation.
97.14
Objections concerning NOX authorized account representative.
Subpart C—Permits
97.20
General NOX Budget Trading Program 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
NOX Budget permit revisions.
Subpart D—Compliance Certification
97.30
Compliance certification report.
97.31
Administrator's action on compliance certifications.
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 I—Individual Unit Opt-Ins
97.80
Applicability.
97.81
General.
97.82
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.

a. General Provisions. For subpart A of part 97, EPA is using essentially the same measurements, abbreviations, and acronyms, retired unit exemption, standard requirements, and provisions for computation of time as those that apply in both part 96 and in the section 126 proposed rule. As noted above, the EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25923-25927), the final NOX SIP call, and in the preamble to the October 21, 1998 section 126 proposal (63 FR 56312).

Section 97.5 sets forth the retired unit exemption and includes a few minor changes from part 96 and the section 126 proposed rule. First, § 97.5(c) is revised concerning NOX allowance allocations to a retired unit. New § 97.5(c)(2) provides (like the proposed § 97.5(c)(1)) that such a unit is allocated NOX allowances under subpart E but adds that the allocation will be recorded in a general account specified by the unit's owners and operators. This means that the Administrator will not need to maintain a unit account for a retired unit. This is reasonable since, under subpart E, allocations are updated and a retired unit's allocation will eventually become zero allowances. The paragraphs of § 97.5(c) are also reordered and then renumbered to reflect the new paragraph and the reordering. Second, § 97.5(c) contains minor word changes that clarify, but do not alter the substance of, the provisions. For example, minor word changes in § 97.5(c)(5)(i) and (ii) make it clear that a permitting authority may reduce the period, before a re-started retired unit resumes operation, by which an application for a title V or non-title V permit must be submitted for the unit.

Under the Federal NOX Budget Trading Program, the NOX Budget units and their owners, operators, and NOX Authorized Account Representatives (NOX AARs) must meet certain standard requirements set forth in § 97.6 of today's rule. The standard requirements incorporate the full range of program requirements by referencing other sections of the NOX Budget Trading Rule. The provisions of § 97.6 are essentially the same as in part 96 and the section 126 proposed rule. Section 97.6(c)(1) is revised to use the same language as the definition of “NOX Budget emission limitation” in § 97.2 since both provisions describe the requirement for NOX Budget units to hold allowances. Under § 97.6(c)(6) the Administrator, rather than the permitting authority, allocates NOX allowances under the Federal NOX Budget Trading Program. In addition, a few non-substantive clarifying revisions are made. For example, in § 97.6(c)(8), language is revised to mirror the language in § 97.23(b). Further, the reference in this and other sections to recordation of NOX allowances under subpart I is removed since recordation is addressed in subparts F and G, but not in subpart I.

b. NOXAuthorized Account Representative. The 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 the process for designating and changing the NOX AAR and the responsibilities of the NOX AAR and alternate NOX AAR, and is essentially the same as in part 96 and in the section 126 proposed rule. The EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25927), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56312).

c. Permits. Subpart C of part 97, which is essentially the same as in part 96 and in the section 126 proposed rule, addresses the administration of a permit, permit applications, permit contents, and permit revisions. As described in the preamble to the May 25, 1999 section 126 final rule, 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 Clean Air Act that implements the relevant requirements of the Clean Air Act, including any revisions to that plan promulgated in part 52 of this chapter.” (40 CFR 70.2).

Since today's rule is being promulgated under title I (i.e., under section 126), the requirements of this rule are applicable requirements under § 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. State and local air permitting authorities have EPA-approved title V operating permits programs and will be the permitting authorities for NOX Budget sources with title V permits, for which the trading program requirements will be applicable requirements. For any source that does not have a title V permit, such a permit is not required by subpart C. If a source Start Printed Page 2689has 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 will be federally enforceable without the federally enforceable permit. The EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25927-25929), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56312).

Sections 97.20(a), 97.21(b), and 97.23(a) include a few minor word changes from part 96 and the October 21, 1998 section 126 proposal that clarify, but do not alter the substance of, the provisions. For example, minor word changes in § 97.20(a)(1) and (2) remove superfluous language listing the subjects that title V and non-title V regulations may address. By further example, in § 97.20(b), the phrase “including any draft or proposed NOX Budget permit, if applicable” is removed as superfluous and confusing. A permitting authority's title V or non-title V regulations may or may not use terms “draft” or “proposed” permits. This same revision is made in § 97.23(a) and § 97.85(a). As a further example, minor word changes in § 97.21(b)(1)(i) and (ii) make it clear that a permitting authority may reduce the period, before a new unit's commencement of operation, by which an application for a title V or non-title V permit must be submitted for the new unit. In addition, the phrase “as approved or adjusted by the permitting authority” is removed in § 97.23(a) because it is superfluous and confusing. The provision simply requires that a permit include the type of information, i.e., the elements, listed in § 97.22.

One section, proposed § 97.24 addressing the effective date of the initial NOX Budget permit, is removed entirely, and proposed § 97.25 is renumbered (without any other changes) as § 97.24. Other provisions in part 97 already state the deadlines for compliance with the various requirements of the NOX Budget Trading Program. For example, § 97.6(c) states the date on which a unit's NOX emissions begin to be subject to the requirement to hold NOX allowances covering emissions, and § 97.21(b) explains the deadlines for submission of NOX Budget permit applications. Similarly, § 97.70 sets forth the dates on which the owner or operator of a unit must begin complying with the monitoring requirements. The “effective date” of the initial NOX Budget permit does not determine the compliance date for any program requirements and is therefore superfluous and somewhat confusing. In fact, for some permitting authorities, the issuance date of any permit is automatically the permit's effective date.

d. Compliance Certification. Under subpart D, 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. Sections 97.30 and 97.31 set forth essentially the same provisions for compliance certification reports as those in part 96 and the section 126 proposed rule. The EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25929), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56312).

e. NOXAllowance 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 NOX allowances held by other organizations and individuals. Subpart F of part 97 addresses NOX allowance tracking system accounts, the account responsibilities of the NOX AAR, the recordation of NOX allowance allocations, the compliance process, banking, account error, and account closing, and is essentially the same as in both part 96 and the section 126 proposed rule. The EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25933-25937), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56312). The banking, flow control, and compliance supplement pool provisions are described in Section III.B.3. of today's preamble.

With regard to accounts, the NOX AAR, and recordation, §§ 97.50(b), 97.51(b), and 97.53(b) include a few minor changes from part 96 and the October 21, 1998 section 126 proposed rule. Section 97.50(b) is revised to reflect the fact that for unit exemptions under § 97.4(a) (permit limit exemption) or § 97.5 (retired unit exemption), allocations can be recorded in general accounts. For example, the unclear language—stating that allocations are recorded each year for the control period after the last period for which allowances were allocated—is removed in a few places in § 97.53(b) and replaced by language stating that NOX allocations are recorded for the third control period after the last period from which compliance deductions were made. This is consistent with the Agency's expressed intent in the proposal and in today's final rule, that allowances be available to owners and operators three years in advance of the control period which allowances are allocated. However, proposed § 97.53(b) addresses only years when compliance deductions are made, i.e., years starting after 2003. In order to ensure that allowances are also recorded in 2001, 2002, and 2003 three years ahead of the control period for which they were allocated, new § 97.53(b), (c), and (d) are added and proposed § 97.53(b) is renumbered as § 97.53(e). The new § 97.53(e) is reorganized to separately address recordation of allocations in compliance accounts or general accounts and of allocations to opt-in units, which are governed by § 97.88. Language in another section (§ 97.61(b)) that references § 97.53 is revised to reflect the changes in the latter section and is also simplified without changing its substance. The other changes clarify, but do not alter the substance of, the provisions. For example, in § 97.51(b) the provisions of proposed paragraph (b)(3) are moved to other paragraphs in the section, the paragraphs are renumbered, and descriptive titles are added at the beginning of some paragraphs in order to make it easier to identify the various requirements concerning general accounts.

The compliance provisions in §§ 97.54(a) through (e) are essentially the same as the provisions under the part 96 and the October 21, 1998 section 126 proposed rule. The procedure for deducting NOX allowances after the deadline for transferring allowances for compliance remains the same: NOX allowances available for compliance are deducted first from the compliance account of the unit involved and then, if necessary, from the overdraft account of the source at which the unit is located. The provision in § 97.54(e) allows the NOX AAR for units with a common stack to identify the percentage of emissions to attribute to each unit. This provision is reworded to clarify that the identified percentage applies to deductions for NOX emissions, and not to deductions for new units based on their actual heat input. For emissions in excess of allowances held and available for compliance as of the NOX allowance transfer deadline, the Administrator will deduct a number of NOX allowances equal to three times the number of the unit's excess emissions from the unit's compliance account or the overdraft account. This deduction will occur in the control period immediately following the period of excess emissions. The EPA believes that this automatic offset deduction ensures that Start Printed Page 2690non-compliance with the NOX emission limitations of part 97 is a more expensive option than controlling emissions. The automatic offset provisions do not limit the ability of the permitting authority or EPA to take enforcement action under State law or the CAA.

EPA has included banking as a feature in the Federal NOX Budget Trading Program, with § 97.55 setting forth essentially the same provisions for banking and the management of banked allowances as specified in part 96 (in § 96.55(a)) and proposed § 97.55(a). Language in the newly numbered § 97.55(b) is revised to make it clear that banked allowances are those remaining in the account after completion of compliance deductions (except excess emission deductions under § 97.54(d)(2), which can be made at any time) and allocated for the control period for which the compliance deductions were made or an earlier control period. Banked allowances do not include allowances that are in the account but were allocated for future control periods. Banking may result in more NOX allowances being used, and therefore more NOX emissions, in one year than in another. Consequently, as in part 96 and the October 21, 1998 section 126 proposed rule, today's rule also contains a flow control mechanism to limit the variability in the timing of emissions. While the mechanism for flow control remains unchanged from part 96 and the section 126 proposal, the timing for implementation has been delayed by two years. Flow control cannot be triggered under today's rulemaking until 2005 (i.e., after reconciliation in the 2004 compliance year).

Today's rule relocates the flow control provisions from proposed § 97.55(b) to final § 97.54(f), and the references in the flow control provisions to other provisions in § 97.54 are corrected to reflect this relocation. The proposed § 97.55(b) stated explicitly that the flow control provisions modify the provisions for compliance deductions under § 97.54. However, the relocation in § 97.54 and the accompanying minor wording changes make it clearer that flow control is part of the compliance process and that, for example, the 2-for-1 deductions under flow control can result in excess emissions under § 97.54(e). The wording changes also clarify that the 2-for-1 deduction requirement does not apply to the 3-for-1 deduction for excess emissions in § 97.54(e). As part of this clarification, parallel changes are made to the definitions of “NOX allowances” and “NOX Budget emissions limitation” in § 97.2, to reference § 97.54(f). Similarly, references elsewhere in part 97 to compliance deductions under § 97.54(b) or (e) are expanded to reference § 97.54(b), (e) or (f) as appropriate. See, e.g., §§ 97.42(e) and (f). In addition, language is added to § 97.54(f)(3)(ii) stating expressly what is implied in proposed § 97.56(b), i.e., that for allowances for which flow control is triggered, two such allowances (rather than one) authorize one ton of NOX emissions. Section § 97.54(f) also includes some minor revisions that clarify, but do not change the substance of, the proposal. For example § 97.55(b)(3)(iii) provided for multiplying the number of banked allowances, but failed to state that the multiplier was a ratio determined in § 97.55(b)(3)(i). The final rule corrects this omission.

Further, as described in the preamble to the May 25, 1999 final rule, commenters expressed concern that some sources may encounter unexpected problems installing controls by the May 1, 2003 deadline and that this could cause unacceptable risk for a source and its associated industry. While EPA continues to believe that this is not a valid concern, the Agency finalized the creation of a compliance supplement pool in the May 25, 1999 section 126 final rule. The pool increases compliance flexibility by providing additional allowances for compliance during the 2003 and 2004 ozone seasons. As described in section III.B.3.c., today's rule establishes the specific methodology for the distribution of NOX allowances from the compliance supplement pool (i.e., distribution only for early reduction credits). This methodology is similar to the early reduction credit methodology for distribution in part 96 and the October 21, 1998 section 126 proposed rule, but the rule provision is relocated from proposed § 97.55(c) in subpart F to a new final § 97.43 in subpart E. Because the early reduction credit provisions involve the allocation of NOX allowances from the compliance supplement pool, the provisions are relocated to subpart E, which contains all the other provisions concerning allocation of NOX allowances. Section 97.43 includes minor changes from part 96 and the October 21, 1998 section 126 proposed rule. For example, the compliance supplement pool and early reduction credits are administered by the Administrator, rather than by the permitting authorities. Further, the section makes it clear that certain banked allowances for the Ozone Transport Commission (OTC) program qualify as early reduction credits. In addition, the section is reorganized so that the procedures for requesting early reduction credits other than for OTC banked allowances are in § 97.43(a), the procedures for requesting credits for OTC banked allowances are in § 97.43(b), and the procedures for reviewing requests and allocating pool allowances are in § 97.43(c). The deadline for submitting any request for early reduction credits is February 1, 2003 (rather than October 31 of the year of the early reduction). This deadline is made later in order to provide more time for quality assurance of emissions data for the control periods of the early reductions. The data is used to determine whether a unit qualifies for early reduction credits, and, if so, what amount of credits. The banking, flow control, and compliance supplement pool provisions are described in Section III.B.3. of today's preamble.

f. NOXAllowance Transfers. Subpart G of part 97 addresses the submission, recordation, and notification of transfers of NOX allowances under the NOX Budget Trading Program. These provisions are essentially the same as those in part 96 and in the section 126 proposed rule. The EPA has included these part 97 provisions for the reasons set forth in the proposed NOX SIP call (63 FR 25937-25938), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56312).

Sections 97.61(a) and 97.62(a) and (b) include a few minor word changes from part 96 and the October 21, 1998 section 126 proposed rule that clarify, but do not alter the substance of, the provisions. For example, paragraph (a)(3) in § 97.61 requiring that NOX allowance transfers meet “all other requirements of this part” is eliminated. Because paragraphs (a)(1) and (2) already specifically reference all the requirements for NOX allowance transfers, paragraph (a)(3) is superfluous.

g. Opt-ins. In subpart I of the final rule, EPA allows certain individual units that are located in a State for which a section 126 remedy is promulgated the opportunity to opt into the Federal program for purposes of the section 126 remedy. Subpart I of today's rule addresses the applicability requirements for opt-ins, allocations to opt-ins, procedures for applying for a NOX Budget opt-in permit, the process of reviewing and either approving or denying the permit, contents of the permit, procedures for withdrawing as an opt-in, and changes in regulatory status. The opt-in provisions under part 97 are essentially the same as in part 96 and in the section 126 proposed rule. Start Printed Page 2691The provisions are described in section III.B.1.d. of today's preamble, and included for the reasons set forth in the supplemental proposed NOX SIP call (63 FR 25940-25942), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56320).

Subpart I of today's rule includes a few minor changes from part 96 and the October 21, 1998 section 126 proposal that reflect the Federal (rather than State) administration of the part 97 trading program, or that either clarify or streamline the opt-in provisions. Also, under §§ 97.84(a) through (c) of today's rule, NOX Budget opt-in permit applications are submitted to both the Administrator and the permitting authority, but the Administrator determines the sufficiency of the monitoring plan and allocates NOX allowances. Other examples of minor changes are: changes to § 97.84(g) and § 97.85(a) and (b) that parallel changes discussed above concerning proposed § 97.24 and proposed § 97.23(a) and (b); removal of proposed § 97.84(e) and (f) as unnecessarily duplicative of the comment period already provided under proposed § 97.84(d); and renumbering of the rest of the § 97.84 paragraphs. In addition, proposed § 97.87(b)(1)(iii) states that an opt-in that becomes a NOX Budget Unit under § 97.4 is treated as “commencing operation” when it becomes a NOX Budget Unit solely for purposes of allowance allocation. This implies that the unit's commence operation date does not change for other purposes, i.e., for purposes of setting the deadline for monitoring and reporting emissions under subpart H. Clarifying language is added to § 97.87(b)(1)(iii) to make it explicit that the deadline for monitoring (which was one control season before the unit becomes an opt-in) is not changed. The unit must continue to monitor under subpart H. Further, the date for the Administrator's allocation of allowances to opt-in units is revised in § 97.88 from December 1 to April 1 in order to ensure that final emissions data from the preceding control period is available for calculating the allocations. The December 1 deadline is too soon after the control period for the Administrator to have completed review of the emissions data. April 1 is the same date by which the Administrator must allocate allowances for NOX Budget Units under § 97.4(a). Section 97.88(a) states that the Administrator will determine by order the allowance allocations. Finally, with regard to the term “operating”, used in subpart I, the definition of the term in § 97.2 is revised to clarify what type of information should be used to document whether a unit is “operating”. The type of information is the same as that used in making input-based NOX allowance allocations to existing units under § 97.42(a)(2).

Subpart I also includes a number of minor word changes from part 96 and the October 21, 1998 section 126 proposed rule that clarify, but do not alter the substance of, the provisions. For example, the statements in proposed § 97.80 that a “NOX Budget unit under § 97.4” cannot become an opt-in is revised. Final § 97.80 states that an opt-in cannot be a “NOX Budget unit under § 97.4(a)” or a unit exempt under § 97.4(b). Parallel changes are included in § 97.22(d)(1), § 97.4(b)(4)(viii), and § 97.5(c)(8). This provides clearer references to the two distinct parts of § 97.4, and, as discussed below in section III.B.3.d. of this preamble, is consistent with the requirement in the proposed rule that the unit cannot be exempt under § 97.5. As another example, § 97.84 is revised for clarity to refer consistently to “initial NOX Budget opt-in permits” (i.e., opt-in permits that are not renewals of existing opt-in permits) and “draft NOX Budget opt-in permits for public comment.” A confusing reference to “final” opt-in permits is removed. (For clarity, references in part 97 to “§ 97.4” are generally changed to refer specifically to “§ 97.4(a)”). See, i.e., § 97.2. By further example, the reference in proposed § 97.84(b) to “monitoring system availability” for monitoring under subpart H of part 97 (and part 75) is corrected to refer to “percent monitoring data availability”. The latter term is a more accurate description since a backup monitor can be used to make data available even if the primary monitor is unavailable. The same change is made in § 97.43(a)(1). Although part 75 (§ 75.32(a)(2)) has a formula for determining “percent monitor data availability”, that formula addresses availability for an entire year. For clarity, today's rule includes an analogous definition of the term, but is geared to a control period, rather than a year. The erroneous reference to “baseline heat rate” in § 97.84(c) is corrected to refer to “baseline heat input”. In addition, the phrase “NOX Budget opt-in source” is replaced, throughout subpart I and the other provisions of part 97, by the phrase “NOX Budget opt-in unit”. This reflects the fact that subpart I in part 96, the section 126 proposed rule, and today's rule each limit opt-ins to “units”, i.e., fossil-fuel fired stationary boilers, combustion turbines, or combined cycle systems. Further, referring to “unit”, rather than “source”, when addressing opt-ins, establishes the same distinction between “unit” and “source” for opt-ins as already exists for non-opt-ins. This approach thereby removes the potential confusion in the section 126 proposed rule between a “NOX Budget source”, which is a facility that includes one or more NOX Budget units, and a “NOX Budget opt-in source”, one or more of which may be located at a single “NOX Budget source”. Finally, the final rule clarifies the provisions in § 97.87 requiring NOX authorized account representatives to ensure that the NATS account “contains” the allowances “necessary” to cover certain deductions, i.e., enough allowances allocated for the appropriate years.

h. Audits. While program audits are not explicitly required by part 97, EPA intends to perform the same types of audits discussed in the proposed NOX SIP call (63 FR 25942), the final NOX SIP call, and the October 21, 1998 section 126 proposal (63 FR 56313).

3. Elements of the Federal NOX Budget Trading Program That Differ From the State NOX Budget Trading Program and the Section 126 Proposed Rule

The following sections in part 97 incorporate certain differences from the corresponding sections in part 96 and in the October 21, 1998 section 126 proposed rule. Additional information on the following subparts can be found in the preamble accompanying the proposed part 97 (63 FR 56313-56321).

Subpart A—NOX Budget Trading Program General Provisions
97.1
Purpose.
97.2
Definitions.
97.4
Applicability.
Subpart E—NOX Allowance Allocations
97.40
Trading program budget.
97.41
Timing requirements for NOX allowance allocations.
97.42
NOX allowance allocations.
97.43
Compliance supplement pool.
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 input data.

a. General Provisions. Section 97.1 explains that part 97 sets forth the provisions for the Federal NOX Budget Trading Program, which addresses interstate transport of ozone and NOX. Section 96.1, of course, discusses the Start Printed Page 2692State NOX Budget trading programs, which also address interstate transport of ozone and NOX. Section 96.1 also contains provisions that make part 96 applicable only if a State adopts the part 96 provisions and the Administrator approves the SIP containing the adoptions. These provisions are not necessary where EPA is adopting and administering the NOX Budget Trading Program under section 126.

EPA uses essentially the same definitions for part 97 as those that apply in part 96 and the section 126 proposed rule, with several exceptions. The definitions for the terms “allocate”, “NOX allowance”, “NOX Budget Trading Program”, and “State” are revised, and thus differ from those in part 96 and the October 21, 1998 section 126 proposed rule (63 FR 56313), in order to reflect the fact that the Federal NOX Budget Trading Program is a federally administered program under part 52 (rather than a State-administered program under part 51). For example, allocations are made by the Administrator, rather than the permitting authority. By further example, the section 126 rule covers certain States or portions of States, and this is reflected in the definition of State.

Some definitions (“electricity for sale under firm contract”, “fossil-fuel fired”, “potential electric output capacity”) are revised or added, and thus differ from those in both part 96 and the section 126 proposed rule, in order to be consistent with the inventories used in the NOX SIP call and the section 126 action. These definitions are discussed in section III.B.1. of this preamble. Some definitions (“commence commercial operation”, “commence operation”, “heat input rate”, “ NOX allowance”, “NOX allowance deduction”, “NOX Budget emissions limitation”, “NOX Budget opt-in source”, “percent monitor data availability”, “operating”, “trading program budget”) contain revisions, are added, or are replaced in order to reflect changes involving other sections of the rule, and are discussed elsewhere in this preamble. Also, for clarification, references to existing provisions in subpart I of part 97 are added to the first two of these definitions (“commence commercial operation” and “commence operation”). Subpart I includes provisions that address the substance of these definitions. Some definitions (“continuous emission monitoring system” or “CEMS”, “maximum potential NOX emission rate”) include minor word changes from part 96 and the section 126 proposed rule that clarify, but do not alter the substance of, the definitions. For example, the phrase “when such monitoring is required by subpart H of this part” is unnecessary and is removed from paragraphs (3) and (4) of “CEMS” definition since the definition states that all the listed items (including those in these paragraphs) are components of a CEMS “to the extent consistent with subpart H of this part”. As an additional example, the “NOX allowance” definition is amplified by language already in § 97.6(c), stating that allowances are a limited authorization and not a property right. The language clarifies that this applies to all NOX allowances, including those allocated to units under § 97.4(b) or § 97.5. By further example, the “NOX allowance transfer deadline” definition clarifies that this is the deadline by which transfers “must” be submitted for compliance. Finally, a few definitions (“account certificate of representation”, “compliance certification”, “unit load”, “utilization”, “trading program budget”) are removed as unnecessary. The first two terms and the last term are defined sufficiently in the rule provisions in which they are described (§§ 97.13, 97.30, and 97.40), and those provisions are then referenced when the terms are used elsewhere in part 97. The third and fourth terms are not used in part 97. In particular, since the term “utilization” in proposed part 97 is analogous to the term “heat input”, only “heat input” is used in today's rule. The term “utilization” is replaced by the term “heat input” throughout the rule, and the definition of “heat input” is revised to make clear the units of measure used in calculating heat input.

As described in the preamble to the May 25, 1999 section 126 final rule and the October 21, 1998 section 126 proposal, the Federal NOX Budget Trading Program applies to certain sources (i.e., large electric generating units and large non-electric generating units) in those States for which EPA has made a finding granting a section 126 petition. For purposes of the section 126, this remedy applies to each large EGU or non-EGU located in any of the following nine jurisdictions: Delaware, District of Columbia, Maryland, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, and West Virginia. As discussed in section II of this preamble, sources in certain portions of Michigan, Indiana, Kentucky, and New York are also affected by this remedy. Reflecting the types of units and the scope of jurisdictions to which today's section 126 action applies, the applicability provisions and accompanying definitions differ from those in part 96 and the October 21, 1998 section 126 proposed rule. The specific applicability provisions for the Federal NOX Budget Trading Program are discussed in section III.B.1. of this preamble.

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 57463). The October 21, 1998 section 126 proposed rule also included this provision as § 97.4(b) in the Federal NOX Budget Trading Program. In today's final rule, § 97.4(b) is revised by reorganizing to resemble the order of provisions in the retired unit exemption (§ 97.8) and by adding some provisions to make it complete. In addition, provisions are added to § 97.4(b) and other sections to clarify the allocation of NOX allowances to, and the deduction of NOX allowances to account for, these units. Section 97.4(b) is more fully described in section III.B.1.c. of this preamble.

b. Allowance Allocations. Section III.B.2. of today's preamble and subpart E of today's Federal NOX Budget Trading Program rule address 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 NOX allocations for new sources. However, in part 97 the Administrator, rather than the States, determines allocations, and while allocations are made initially based on a unit's heat input, some future allocations will be based on a unit's output. The Administrator will determine by order the allocations that are not specifically set forth in today's rule (in Appendices A and B). The significant differences between NOX allocations in part 96 and the section 126 proposal, on one hand, and today's rule, on the other hand, are discussed in section III.B.2. of this preamble. Some of the differences are minor word changes that clarify, but do not alter the substance of, the provisions. For example, in provisions where emission rates (in lbs/mmBtu) are used to calculate allowance allocations, language is added to show explicitly the conversion from pounds to tons since an allowance authorizes a ton of emissions. By further example, in provisions where allowances are adjusted so that their total will not exceed a fixed pool of allowances (i.e., the State's allocation set-aside for new units), language is added to make it clear that rounding Start Printed Page 2693will be used to ensure that the pool amount will not be exceeded. Appendices A and B of today's final rule contains specific unit-by-unit allocations, including allocations to units in the partial States for which a finding is being made. Finally, as discussed above, the compliance supplement pool and early reduction credit provisions are revised and relocated to the new § 97.43 in subpart E.

c. Emissions Monitoring and Reporting. Subpart H of part 97 addresses monitoring and reporting requirements including general requirements, initial certification and recertification procedures, out of control periods, notifications, record keeping and reporting, and petitions. As described in the October 21, 1998 section 126 proposal, these provisions are similar to the monitoring-related provisions of part 96. Some of the differences among the subpart H provisions reflect the fact that administration of the monitoring requirements in the Federal NOX Budget Trading Program is overseen by EPA, rather than by EPA and the permitting authority as is the case in the State NOX Budget Trading Program. Some of the differences reflect changes made to simplify or clarify certain monitoring provisions, or to make them conform with part 75. Some of the differences reflect minor word changes from part 96 and the October 21, 1998 section 126 proposed rule that clarify, but do not alter the substance of, the provisions. Provisions for emissions monitoring and reporting are discussed in section III.B.4. of this preamble.

d. Program Administration. The Federal NOX Budget Trading Program is administered by the EPA. The Agency identifies the units covered by the program and determines the NOX allowance allocations. The EPA receives and reviews monitoring plans and monitoring certification applications. As discussed above, States will still be responsible for permitting under title V.

4. Implications for Trading Between States Affected by a Finding Under Section 126, and States not Affected by a Finding

As noted in the May 25, 1999 section 126 final rule, the sources or groups of sources identified in the section 126 petitions are also sources for which EPA recommended that States adopt emission limitations and control strategies in response to the NOX SIP call (64 FR 28308). The NOX SIP call established an emissions budget for all sources of NOX emissions in all States determined by EPA to significantly contribute to non-attainment of the ozone NAAQS in any other jurisdiction. The section 126 rule, in contrast, is limited to major stationary sources or groups of stationary sources that are named in the section 126 petitions and found to be significantly contributing to non-attainment downwind. Despite this difference in the scope of the section 126 action and the final NOX SIP call, both actions have the same objective: to reduce the transport of ozone from sources in a given State that are found to be contributing significantly to non-attainment problems in another State.

In the NOX SIP call, EPA finalized a specific interpretation of the section 110(a)(2)(D)(i)(I) provisions concerning the test for significant contribution. Under this interpretation, the Agency determined to make any finding of significant contribution with respect to a specified amount of emissions by examining various factors, including the ambient impacts and the costs of mitigation. This weight-of-evidence approach to the designation of significant contribution determined which States include sources that emit NOX in amounts of concern. After EPA made findings based on consideration of these factors, the Agency required the States' SIPs to eliminate that specified amount (see 63 FR 57365). As proposed in the October 21, 1998 section 126 proposed rule and finalized in the May 25, 1999 section 126 final rule, EPA uses the same linkages it found in the NOX SIP call between specific upwind States and non-attainment problems in specific downwind States. The test of significant contribution, which includes both air quality modeling and cost-effectiveness demonstrations, consequently underlies both the NOX SIP call and the section 126 petitions as a threshold for source inclusion.

Based on the view that the SIP call and section 126 petitions rely on the same threshold criteria and are both designed to achieve the same goal, the EPA has sought to coordinate the two actions to the maximum extent possible (see the preamble to the final NOX SIP Call (63 FR 57362), and the October 21, 1999 section 126 proposal (63 FR 56310)). This coordination was designed to facilitate trading among sources in SIP call States that choose to participate in the NOX trading program and any section 126 sources that would be subject to a Federal NOX trading program. The Agency's analyses in conjunction with the NOX SIP call demonstrate that implementation of a single trading program with a uniform control level results in no significant changes in the location of emissions reductions, as compared to a non-trading scenario (see chapter six of the Regulatory Impact Analysis for the NOX SIP call). While the NOX SIP call analysis compared trading and non-trading scenarios involving 23 jurisdictions, the integration of a section 126 action (involving at most only 12 of these jurisdictions) and trading programs adopted voluntarily by States under the NOX SIP call may ultimately involve only a subset of the 23 jurisdictions. Nevertheless, like the NOX SIP call RIA, EPA's analyses in conjunction with the section 126 provide a strong indication that trading will not significantly change the location of reductions in the 12 affected jurisdictions, relative to the non-trading scenario (see chapter six of the Regulatory Impact Analysis for the section 126 rulemaking). Given that the location of emission reductions is essentially the same for both programs (i.e., for the 23 jurisdictions under the NOX SIP call and the 12 jurisdictions under the section 126) compared to the two respective non-trading scenarios, the Agency is confident that trading will not significantly change the location of emissions reductions for the subset of the 23-jurisdictional area discussed above.

Therefore, trading among sources in States with a State NOX Budget Trading Program and sources in States with a Federal program will achieve the intended emissions reductions, while simultaneously providing both flexibility and cost savings to the covered sources. In addition, as noted in the May 25, 1999 section 126 final rule, if a State elects to submit a SIP that includes a trading program after EPA has already established a Federal NOX Budget Trading Program under a section 126 remedy, disruptions to sources that would shift from regulation under a section 126 remedy to regulation under a SIP will be minimized if the two programs are already integrated.

For the reasons stated above, today's rule allows sources in States or portions of States that are not subject to a finding under the section 126 to participate in trading with sources in States or portions of States covered by the rule, provided that the States or portions of States not covered by the rule meet the following conditions. Any State or portion of a State that voluntarily chooses to enter the section 126 trading system must be subject to the NOX SIP call and have an EPA-approved and administered State NOX Budget Trading Program generally modeled on part 96. This criteria includes the requirement that States revise their State Implementation Plans to meet the above provision. It also includes the Start Printed Page 2694requirement that States meet the emissions control level under the final rule for the NOX SIP call (63 FR 57405-57418). In addition to ensuring that trading will not significantly change the location of emissions reductions, this condition ensures that all sources that could trade allowances will be meeting essentially the same program requirements (i.e., allowance holding and trading, monitoring, and permitting requirements).

In order to allow trading between sources in States or portions of States subject to the section 126 and sources in States or portions of States subject to EPA-approved and administered State NOX Budget Trading Programs, the definition of “NOX allowance” is revised. The definition is different than in part 96 and the section 126 proposed rule. Under the revised definition, the term “NOX allowance” used in most provisions of part 97 includes NOX allowances issued “under a NOX Budget Trading Program established, and approved and administered by the Administrator, pursuant to § 51.121” (the rule under which State NOX Budget Trading Programs are approved for the NOX SIP call), as well as NOX allowances issued under part 97. For example, the account compliance and transfer provisions in subparts F and G of part 97 cover allowances issued under such State programs. The only part 97 provisions to which this expanded definition of “NOX allowance” does not apply are the provisions for allocation of NOX allowances to NOX Budget units and NOX Budget opt-in units (i.e., §§ 97.41, 97.43, and 97.88). This is because NOX allowance allocations must be made from allowances available under the Federal NOX Budget Trading Program, not from allowances available under the State NOX Budget Trading Programs. In light of the more detailed definition of “NOX allowance” adopted in part 97, the definition of “NOX allowance” in § 52.34(a) is superceded and unnecessary. Part 52 uses the term “NOX allowance” only in provisions in § 52.34(j) and (k) that, as discussed herein, are themselves superceded by part 97. Consequently, the part 52 definition is removed.

B. Provisions of the Federal NOX Budget Trading Program

1. Applicability

Sources 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 of contributing significantly to non-attainment in a petitioning State. The section 126 remedy will apply to these sources in States for which a finding is triggered by today's final rule. These sources include any large electric generating unit (EGU) and any large non-electric generating unit (non-EGU) located in any of the following 13 jurisdictions: Delaware, District of Columbia, Maryland, New Jersey, North Carolina, Ohio, Pennsylvania, Virginia, and West Virginia and certain portions of Indiana, Kentucky, Michigan, and New York.

a. EGU/Non-EGU Classification. In §§ 52.34(a)(2) and (3) of the May 25, 1999 section 126 final rule, EPA provided definitions for the types of units covered by the Federal NOX Budget Trading Program (Part 97), i.e., large EGU and non-EGU, and explained the basis for these definitions (63 FR 28295-8). Today's final rule adopts that part 52 language in the applicability criteria in § 97.4(a). The following provides a summary of the types of units covered by the Federal NOX Budget Trading Program under section 126.

Section 97.4(a)(1) describes a category of units, corresponding to “large electric generating units” under § 52.34(a)(2), that is covered by the Federal NOX Budget Trading Program. A large electric generating unit is, for units that commenced operation before January 1, 1997, a unit serving during 1995 or 1996 a generator that had a nameplate capacity greater than 25 MWe and produced electricity for sale under a firm contract to the electric grid. For units that commenced operation on or after January 1, 1997 and before January 1, 1999, a large EGU is a unit serving during 1997 or 1998 a generator that had a nameplate capacity greater than 25 MWe and produced electricity for sale under a firm contract to the electric grid. For units that commence operation on or after January 1, 1999, a large EGU is a unit serving at any time a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

Section 97.4(a)(2) describes a second category of units, corresponding to “large non-electric generating units” under § 52.34(a)(3), that are covered by the Federal NOX Budget Trading Program. A large non-electric generating unit is, for units that commenced operation before January 1, 1997, a unit that has a maximum design heat input greater than 250 mmBtu/hr and that did not serve during 1995 or 1996 a generator producing electricity for sale under a firm contract to the electric grid. For units that commenced operation on or after January 1, 1997 and before January 1, 1999, a large non-EGU is a unit that has a maximum design heat input greater than 250 mmBtu/hr and that did not serve during 1997 or 1998 a generator producing electricity for sale under a firm contract to the electric grid. For units that commence operation on or after January 1, 1999, a large non-EGU is a unit with a maximum design heat input greater than 250 mmBtu/hr that: At no time serves a generator producing electricity for sale; or at any time serves a generator producing electricity for sale, if any such generator has a nameplate capacity of 25 MWe or less and has the potential to use no more than 50 percent of the potential electrical output capacity of the unit.

In order to clarify which units are covered by the categories in § 97.4(a) and so are subject to the trading program, today's rule includes two new definitions. First, “electricity for sale under firm contract to the electric grid” is defined as where “the capacity involved is intended to be available at all times during the period covered by the guaranteed commitment to deliver, even under adverse conditions.” This definition is based on language from the Glossary of Electric Utility Terms, Edison Electric Institute, Publication No. 70-40 (definition of “firm” power). Generally, capacity “under firm contract to the electricity grid” is reported as capacity projected for summer or winter peak periods on EIA form 411 (Item 2.1 or 2.2, line 10). EPA has previously explained that it generally used EIA data to determine which non-utility units should be treated as non-electric utility generating units (63 FR 71223 and 64 FR 28298).

Second, “potential electrical output capacity” is defined as 33 percent of a unit's maximum design heat input capacity. This definition is the same as the definition in § 52.34(a) and is based on longstanding definitions of this same phrase in part 72 of the Acid Rain Program regulations (40 CFR 72.2 and 40 CFR part 72, Appendix D) and in the subpart D of the New Source Performance Standards (40 CFR 60.41a).

EPA notes that the EGU and non-EGU categories in § 97.4 differ from the corresponding categories in § 96.4 in part 96 of the model trading rule. In future guidance, EPA intends to clarify that it will accept the use in State trading program rules of the EGU and non-EGU categories in § 97.4 and that EPA will administer such a State program.

b. Fossil Fuel-fired Definition. Today's final rule, like part 96 and the section 126 proposal, defines the term “unit” as Start Printed Page 2695a stationary, fossil fuel-fired boiler, combustion turbine, or combined cycle system. However, today's rule adopts a definition of “fossil fuel-fired” that is different than the definition in part 96 and in proposed part 97.

Under the proposed definitions in § 97.2, boilers, combustion turbines, and combined cycle systems that operated but did not combust more than 50 percent fossil fuel in 1995 were generally not considered “fossil fuel-fired”, and thus were not “NOX budget units”. However, such facilities would subsequently become “fossil fuel-fired”, and “NOX Budget units,” if they began to combust more than 50 percent fossil fuel in any year after 1995. This is not consistent with the approach taken in developing the final State trading program inventories and budgets for electric generating units and non-electric generating units in the NOX SIP call. These inventories and budgets generally excluded any boiler, combustion turbine, and combined cycle system that operated but did not combust over 50 percent fossil fuel in 1995 or 1996. Such a boiler, combustion turbine, or combined cycle system continues to be excluded even if it combusts over 50 percent fossil fuel after 1996. See 63 FR 71220 (December 16, 1998) and 64 FR 26298 (May 14, 1999) (correction notices adjusting State inventories and budgets).

In addition, EPA received comment that the definition of fossil fuel-fired was open-ended, allowing sources to jump in and out of the NOX Budget Program. The commenter argued that EPA should adopt a once in, always in approach for the fossil fuel-fired definition. Actually, both the fossil fuel-fired definition in the section 126 proposal and in today's final rule take the requested approach.

EPA maintains that it is appropriate to define fossil fuel-fired in a manner consistent with the way EPA developed the State trading program inventories and budgets. These State trading program inventories and budgets are based on the universe of sources that existed in 1995-1996 and were fossil fuel-fired at that time. These State trading program budgets allow for the inclusion of new units (units commencing operation after 1996) through the use of growth rates. However, the growth rates do not account for the expansion of that universe of sources as the result of existing units increasing their consumption of fossil fuel to over 50 percent after 1996.

The EPA is finalizing a fossil fuel-fired definition in § 97.2 that is revised as follows to be consistent with the way EPA developed the State trading program inventories and budgets. Paragraphs (1) and (2) of the definition reflect how EPA determined whether boilers, turbines, and combined cycle systems commencing operation during or before 1995 and 1996 were fossil fuel-fired and thus included in the State trading program inventories and budgets. Paragraph (3) reflects the fact that boilers, turbines, and combined cycle systems commencing operation after 1996 and combusting more than 50 percent fossil fuel were reflected in the State trading program budgets through growth rates.

For purposes of today's final rule, fossil fuel-fired is defined as follows:

(1) For units that commenced operation before January 1, 1996, the combination 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 1995, or, if a unit had no heat input in 1995, during the last year of operation of the unit prior to 1995.

(2) For units that commenced operation on or after January 1, 1996 and before January 1, 1997, the combination 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 1996.

(3) For units that commence operation on or after January 1, 1997: (i) The combination 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; or (ii) the combination 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.

EPA notes that today's definition of fossil fuel-fired differs from the one in § 96.2 in part 96. In future guidance, EPA intends to clarify that it will accept the use of today's definition in State trading program rules and that EPA will administer such a State program.

c. 25-ton Exemption. For today's final action, as proposed (63 FR at 56313), EPA is exempting electric generating units with a very low, federally enforceable permit limitation (i.e., 25 tons per ozone season) from the trading program, even though they meet the applicability criteria in § 97.4(a).

The vast majority of commenters expressed support for the 25-ton exemption. One commenter did not support the exemption because, in aggregate, such units contribute to non-attainment in other areas. Some commenters supported the exemption provided that State trading program budgets are reduced by the full amount allowed for in an enforceable permit. Several of the small entity representatives argued that all units at small entity-owned facilities should be exempt regardless of the size of the unit.

Based on the comments and EPA's own analysis, EPA maintains that it is appropriate to adopt a 25-ton exemption. This provision exempts units that meet the requirements described below from the requirements to hold allowances, monitor emissions, and report quarterly emissions. Thus, the 25-ton exemption increases cost effectiveness of the control program, by reducing monitoring and reporting costs, but still limits the unit's emissions through a low, federally enforceable permit limitation. Furthermore, small entity impacts are reduced since many potentially exempted units are owned by small entities.

In addition, exempt units will not have any significant adverse impact on regional air quality. First, consistent with comment on the proposed rule, NOX allowances will be removed from State trading program budgets in an amount equal to the full amount of NOX emissions allowed in such units' federally enforceable permits. An existing exempt unit that already has an allowance allocation when it becomes exempt continues to receive the allocation. However, after the allocation is recorded, the Administrator will delete a number of allowances from the same or earlier year as the allocation equal to the unit's permit limit. This deduction may exceed the amount of the allowance allocation. The owners and operators of the exempt unit are responsible for ensuring that the general account has enough allowances for the deduction. For an exempt unit that would otherwise qualify for a new unit allocation, the new unit set-aside is reduced by a number of allowances equal to the permit limit. For an existing exempt unit that does not qualify for any allocation, the State trading program budget is reduced by a number of allowances equal to the permit limit. See § 97.4(b)(4)(ii), § 97.40(b), and § 97.42(d)(5). Second, the units must demonstrate compliance with their individual permit limits. Exempt units will be required to: have a federally enforceable permit restricting control period NOX emissions to less than 25 tons; keep on site records demonstrating Start Printed Page 2696that the conditions of the permit were met, including restrictions on operating time; and report hours of operation during the ozone season to the permitting authority. See § 97.4(b).

With regard to exempting all small entity-owned units, EPA maintains that an across-the-board exemption, regardless of the units' emissions, could not be supported because the cost and administrative burdens of the rule will not affect a significant number of small businesses nor will it significantly or disproportionately impact these small businesses. See section IV.B and EIA for discussion of economic impact on small entities. Furthermore, the trading program already allows expensive-to-control units the option to buy allowances and not install controls and provides for simplified, less expensive monitoring of oil or gas-fired units with low emissions. Therefore, EPA is basing the exemption on the unit's allowed emissions.

Thus, for today's final rule, EPA is allowing electric generating units with a 25-ton ozone season enforceable permit limitation to be exempt from the trading program. However, today's final rule revises the language in § 97.4(b), which sets forth the exemption, by reorganizing the section to resemble the order of provisions in the retired unit exemption (§ 97.8) and by adding some provisions to make the section clear and complete. Section 97.4(b)(1) states a unit that has a federally enforceable permit with a NOX emission limitation restricting NOX emissions to 25 tons or less during a control period and that meets certain ongoing requirements is exempt from the NOX Budget Trading Program, except for the provisions of § 97.4 and subparts E, F, and G and the definitions, measurements, and time computation provisions in §§ 97.2, 97.3, and 97.7. This is similar to the language in the retired unit exemption. In particular, subparts E, F, and G must apply since exempt units may be allocated allowances. Also included in § 97.4(b)(1) are the provisions explaining that the NOX emission limitation must restrict unit operating hours based on the unit's maximum potential hourly NOX mass emissions. The final version of § 97.4(b)(1) includes provisions in the proposed §§ 97.4(b) and (b)(3).

Section 97.4(b)(2) explains when the exemption takes effect. This is not clearly addressed in the proposal. Since the exemption is based on the unit having a federally enforceable permit with a specific NOX emission limitation, this provision states that the exemption generally takes effect on the dates such permit becomes final. However, if the unit operates in a control period during the year, but before the specific date the permit becomes final in that control period , then the effective date is May 1 of the control period, provided the permit emission limitation and other requirements apply to the unit for the entire control period. If the emission limitation and other requirements do not apply to the entire control period, the effective date is October 1 after the control period. EPA is providing some flexibility for the exemption to apply before the final permit is issued because issuance of a permit with a 25-ton NOX emission limitation may be delayed even after the owners and operators request such a limitation. So long as the emission limitation applies to the entire control period, the exemption will cover that entire control period even if the final permit is issued later in the control period in the same year. Since the NOX Budget Trading Program limits emissions, and the required federally enforceable permit must limit unit operating hours, and thus emissions, for control periods of May 1 through September 30, the exemption cannot cover any portion of a control period before the unit operates subject to the permit limit.

Sections 97.4(b)(3) and (4) are, for the most part, restatements of provisions in the proposed exemption provisions. The § 97.4(b)(3) requirement to notify the Administrator of the issuance of the federally enforceable permit is set forth in proposed § 97.4(b). The § 97.4(b)(4)(i) and (iii) special provisions are reflected in proposed §§ 97.4(b) and (b)(2). The recordkeeping provision in § 97.4(b)(4)(iv) is like the one in proposed § 97.4(b)(1) but adds a 5-year limit on the recordkeeping requirement unless otherwise requested by the permitting authority or the Administrator. The provision also explicitly states that the owners and operators bear the burden of proving that they meet the operating hours restriction. This provision is similar to the recordkeeping requirement for the retired unit exemption. A parallel change is made in § 97.4(b)(4)(vi). Under the change a unit loses its exemption on the first date on which the unit does not comply with the operating hours restriction or with or with regard to which the owner and operators fail to meet their burden of proving compliance.

The § 97.4(b)(4)(ii) provisions (along with provisions in § 97.40(b) and § 97.42(d)(5)(ii)) address the treatment of exempt units in the State trading program budgets. As discussed above, an existing, exempt unit that qualifies for NOX allowance allocations under § 97.42(a) through (c) will still receive such allocations. For past control periods when the unit was required to monitor under subpart H of part 75, only heat input data monitored under subpart H of part 75 will be used in determining the unit's allocations. After recording the allocation in a general account, the Administrator will subtract and retire allowances equal to the NOX emission limitation in the unit's permit from the general account. (The reference to “allowance surrender” requirements in the definition of “NOX allowance deduction” is replaced by a reference to “allowance withdrawal” requirement, which more accurately describes this (and other) non-emissions related deductions). This is a reasonable way to reflect the unit's current NOX emissions since the unit is now exempt from monitoring its emissions under subpart H of part 97. The allocation will be recorded in a general account specified by the owners and operators, rather than a unit account. This approach will allow the Administrator to avoid maintaining a separate unit account for such a unit, which does not need a unit account since the unit is exempt from end-of-year compliance requirements. In contrast to existing units, a new, exempt unit is not allocated allowances. A new, exempt unit will probably not monitor under subpart H of part 75 during any control period on which allocations would otherwise be based. In fact, one purpose of obtaining the exemption is to avoid monitoring. However, the State trading program budget must still reflect the unit's NOX emission limitation. Consequently, as noted above, the Administrator will retire allowances (under § 97.42(d)(5)(ii)) equal to the unit's permit NOX emission limitation from the set-aside available to new units. A similar approach is taken for exempt units that neither receive allocations nor qualify as new units: allowances equal to their permit NOX emission limitation are retired from the appropriate State trading program budget. Since these exempt units also will not monitor their emissions, their permit limits determine the amount of retired allowances.

Further, the § 97.4(b)(4)(v) provision makes explicit the implicit requirement that a unit comply with part 97 requirements for any period when the unit is not exempt. If a unit loses the exemption with respect to a given control period, § 97.4(b)(4)(ii) sets the date on which the unit loses the exemption as the date deemed to be the unit's commencement of operation or commercial operation for purposes of permitting, allowance allocation, and Start Printed Page 2697monitoring. This is similar to the provision in the retired unit exemption concerning loss of the exemption. This means that a unit that loses its § 97.4(b) exemption during a control period must (like a unit that loses its § 97.5 exemption during a control period) monitor its emissions, and hold allowances, for the rest of the control period. The owners and operators must also apply for a permit. The proposal treated October 1 after the loss of the exemption as the commence operation or commercial operation date. The approach in the proposal would result in there being no accounting for the unit's emission above its permit limit during the control period in which the unit lost its exemption. This could result in total emissions of large EGUs and non-EGUs exceeding the State budget. To prevent this, the final rule requires a unit that loses its exemption to meet the requirement to monitor and hold allowances as of the date of the loss of the exemption. This is consistent with the comments stating that the exemption provisions should not result in contributions to nonattainment in other areas.

In addition to the revisions to § 97.4(b), references to the exemption under that section are added in various places in part 97 where the other exemption from the trading program, i.e., the retired unit exemption, is already referenced. See, e.g., § 97.6(c)(6), (f)(1), and (g), § 97.22 (d)(1), and § 97.70(d)(4)(i).

d. Opt-in Units. For today's final action, as proposed (63 FR at 56311), EPA is allowing certain, additional units to voluntarily participate in (opt-in) the trading program. These units must not be otherwise subject to the NOX Budget Trading Program, must not be exempt under § 97.4(b), and must be units that are operating, that vent all of their emissions to a stack, and that are located in a State or portion of a State where a finding is made under section 126, but are not named in a petition.

A few commenters noted that there should not be a voluntary opt-in program. However, most commenters expressed support for an opt-in program. One commenter supported adding mobile and area sources through provisions for credit-based programs. However, another commenter expressed opposition to including mobile sources unless a firm cap is established for that sector. Some commenters expressed support for allowing smaller sources to opt-in but noted that part 75 CEMS requirements should not be imposed on these sources.

After considering the comments received, EPA maintains that it is appropriate to allow individual units the opportunity to opt-in to the Federal program for purposes of the section 126 remedy if the units meet certain conditions. The units must not be covered by § 97.4(a) or an exemption under § 97.4(b) or § 97.5. This prevents units from obtaining an exemption from the program and then re-entering the program as opt-ins, which would impose a significant administrative burden on the Administrator and permitting authorities and provide opportunities for gaming, i.e., to obtain allowances based on a different, more advantageous baseline. The units also must be located in a “State”, which is defined as a State or portion of a State for which a section 126 remedy is promulgated under § 52.34, must be operating, and must vent to a stack and be able to monitor NOX mass emissions according to part 75. There may be individual units not included in the trading program that emit significant amounts of NOX and are able to achieve cost-effective reductions. 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. This would reduce the overall cost of compliance for the program.

For the same reasons discussed in the final NOX SIP call (63 FR at 57463-57464), EPA does not support including mobile and area sources in a voluntary opt-in program. Mobile and area sources are not included in the trading rule because of EPA's concerns relating to ensuring that reductions are real and verifiable, to developing and implementing procedures for monitoring emissions, and to identifying responsible parties for the implementation of the program and associated emissions reductions. As discussed in the final NOX SIP call (63 FR at 57464), EPA remains willing to consider adding mobile or area sources to the trading program in the future. However, due to the problems associated with program integrity, emissions monitoring, and accountability, EPA concludes that it is not appropriate to include mobile and area sources in the Federal NOX Budget Trading Program at this time.

The EPA does not agree that there should be special, less expensive monitoring methods for opt-in units than for other, similar NOX Budget units in order to encourage more units to opt in. Before a unit opts in, the unit is not included in the State trading program budget and is not covered by the NOX cap imposed by the Federal NOX Budget Trading Program. When a unit opts in, it is allocated allowances that are in addition to the State trading program budget and that increase the NOX cap to cover emissions from the opt-in unit. The opt in unit, like all other units under the NOX cap, must comply by holding allowances covering control period emissions. In general, owners or operators will opt-in only if they believe they will be able to make reductions at the unit and then retain some of the allocated allowances for sale. Because the opt-in unit must comply by holding sufficient allowances and particularly because the unit will be selling allowances for the compliance at other units, it is important that the opt-in unit's emissions be monitored in an accurate manner consistent with monitoring for all other units under the NOX cap and in the trading program. Providing an opt-in unit with an alternate monitoring methodology that is less accurate than that for a similar unit required to be in the Federal NOX Budget Trading Program could result in actual emissions being higher than reported emissions from the opt-in unit. The opt-in unit would then be able to save more allowances that could be used for sale because of the lower reported emission values. For other units that purchase allowances from opt-in units, emissions will be higher by a tonnage amount equal to the number of purchased allowances. The net result of higher than reported opt-in unit emissions and higher non-opt-in unit emissions is higher overall NOX emissions that may result in exceedence of the NOX cap.

However, EPA agrees that it is appropriate to have monitoring methods other than CEMS for smaller and less frequently operated units, whether or not they are opt-in units. All units participating in the Federal NOX Budget Trading program must qualify for such monitoring methods by meeting the same criteria. In the final NOX SIP call, EPA included revised provisions to part 75 that allow greater flexibility in monitoring for units with low emissions. These methods are also available to sources in the Federal NOX Budget Trading Program. See the discussion in section III.B.4 of this preamble for more information on the different monitoring approaches allowed under part 75.

2. Trading Program Budget

In the October 21, 1998 section 126 proposal, EPA discussed the calculation of State specific aggregate emission levels, proposed that the section 126 trading program budget in each State would equal the State specific aggregate Start Printed Page 2698emission levels, and proposed several methods for determining NOX Budget unit allocations. The EPA finalized the methodology used to determine the State aggregate emission levels, and therefore the trading program budget as well, in the May 25, 1999 section 126 final rule. This section of the preamble summarizes the method for calculating the trading program budget.

As discussed in Section III.A.1. of this preamble, in the May 25, 1999 section 126 final rule, EPA finalized the methodology used to determine the NOX emissions budget, i.e., the total amount of NOX allowances allocated to all units subject to the Federal NOX Budget Trading Program in any State for purposes of any section 126 finding. That method used to calculate the total available allowances was consistent with the method used in developing the NOX SIP call budgets in part 51, as described in the final NOX SIP call. In the May 25, 1999 section 126 final rule (64 FR at 28309), EPA determined that the total tons of NOX allowances allocated under the trading program (other than compliance supplement pool credits) will be equivalent to the sum of two tonnage limits:

(a) The total tons of NOX that large EGUs in the program would emit in an ozone season after achieving a 0.15 lb/mmBtu NOX emissions rate, assuming historic ozone season heat input adjusted for growth to the year 2007; plus

(b) The total tons of NOX that large non-EGUs in the program would emit in an ozone season after achieving a 60 percent reduction in ozone season NOX emissions compared to uncontrolled levels adjusted for growth to the year 2007.

The number of tons in each State or partial State trading program budget can be found in Appendix C of the final part 97. The emission levels for each State reflected in Appendix C are consistent with the revised inventories and State budgets described in the December, 1999 SIP call inventory notice. Where only partial portions of States are covered by this rulemaking, the State trading program budgets reflect only the portions of the States that are covered. This is because each State trading program budget includes emissions only from the sources affected by the control remedy in this section 126 rulemaking.

The State trading program budgets are also addressed in § 97.40 of today's rule. Section 97.40 includes some changes from part 96 and the October 21, 1998 section 126 proposal. Under § 96.40, the State trading program budget is determined by the State in the SIP. In contrast, § 97.40 reflects the fact that part 97 creates a federally administered trading program where the State trading program budgets are determined by the Administrator and are reflected in Appendix C of part 97. Moreover, § 97.40(b) provides that a State trading program budget for a control period may be reduced, before the budget is allocated, by the permit limit of each unit exempt under § 97.4(b) in the State. The reduction is required if allowances equal to the permit limit are not already being withdrawn either by deducting allowances equal to the permit limit from the general account of the unit's owners and operators after the unit is allocated allowances as an existing unit or by reducing the new unit allocation set-aside for the control period. As discussed above in Section III.B.1.c. of this preamble, this ensures that exempt units do not have any significant adverse impact on air quality. In addition, today's rule eliminates, as redundant, the definition of “trading program budget” in § 97.2 and instead explains in § 97.40 that the Administrator will allocate each State trading program budget in accordance with §§ 97.41 and 97.42. In light of the provisions in § 97.40 and Appendix C, the language in the existing § 52.34(j)(3) describing the calculation of the State trading program budgets is redundant and is therefore removed. The State trading program budgets reflected in Appendix C and referenced in § 97.40 are calculated in a manner consistent with the calculation description in § 52.34(j)(3).

3. NOX Allowance Allocations

While the May 25, 1999 section 126 rule finalized the methodology for determining the State aggregate emission levels, the Agency did not finalize the methodology for determining the NOX Budget Unit allocations in the May 25, 1999 final rule. Rather, the Agency laid out a default emission limitation methodology that would be used to calculate the unit-specific emission limitations in the event the Administrator failed to promulgate the Federal NOX Budget Trading Program. With today's action, the Administrator is promulgating the provisions of the Federal NOX Budget Trading Program including the allocation methodology (§§ 97.41 and 97.42) and the specific unit allocations (Appendices A and B). Therefore, the allocations and methodology described in the final part 97 replace the default emission limitation methodology specified in the May 25, 1999 rule. The final part 97 includes provisions for the timing of determining allocations and the methodology for determining allocations for existing and new units.

Sections III.B.3.a. (electric generating units) and III.B.3.b. (non-electric generating units) describe the specific allocation methodologies included with today's rule.

a. NOXAllowance Allocation Methodology for Electric Generating Units. i. Timing Provisions. Under the Federal NOX Budget Trading Program, the Administrator determines the NOX allowance allocations and records them in the NOX Allowance Tracking System (NATS). This section lays out when the Administrator will determine the allowances for a particular control period and what baseline period will be used to determine those allocations.

(1) When Will the Administrator Determine Allocations? In the October 21, 1998 section 126 proposal, EPA proposed to determine allocations 3 years ahead of each applicable control period. The Agency did not receive any adverse comment on this specific proposal. Most commenters favored providing more time for sources to know their allocations for any given control season. They suggested that knowing the allocations in advance would provide for the development of forward markets and would provide greater certainty for source compliance planning.

Therefore, as proposed, the Administrator will record NOX allowances in the NOX Allowance Tracking System (NATS) at least 3 years prior to each relevant control season. As discussed in section III.A.2.e. of this preamble, for the 2003, 2004, 2005, and 2006 allocations, the Administrator records the allocations in the NATS by May 1 of the year that is 3 years prior to the control season for which the allocations are being recorded. For each subsequent allocation the Administrator records the allocations in the NATS after compliance has been determined for the control season that is 4 years prior to the applicable control season. These provisions are consistent with the minimum timing requirements for the NOX Budget Trading Program specified in the preamble to the final NOX SIP call. As discussed in the October 21, 1998 section 126 proposal, as well as the October 27, 1998 final NOX SIP call, EPA believes that it is important to determine the allocations a few years ahead of the compliance period to provide some predictability for sources in their control planning and to build confidence in the market.

As stated above, the EPA will determine allocations and record them in the NATS on an annual basis 3 years prior to the relevant control period. This Start Printed Page 2699will allow a State, as part of an approved SIP, to submit allocations up to 3 years prior to the relevant control period and have those allocations replace the allocations EPA was planning to issue as part of the Federal NOX Budget Trading Program. By recording allocations in 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 3 years prior to the relevant control season.

(2) Will the Agency update the allocations periodically? In the October 21, 1998 section 126 proposal, the Agency proposed to use the same allocations for the first 3 years of the program, unless a State replaces a section 126 action with its own allocations in an approved SIP. After the initial three year period, EPA proposed to update the allocations on an annual basis 3 years prior to the relevant control season.

The Agency received numerous comments arguing against the proposed schedule and supporting longer-term or permanent allowance allocations. Several commenters suggested that the proposed schedule would be administratively cumbersome and would create uncertainty and risk for sources regarding investments in control technologies. Two commenters stated that annually updating allocations would provide incentives to generate more electricity and create market distortions and that EPA has not fully evaluated all of the implications of updating the allocations. These commenters (as well as others) expressed support for 5- to 10-year allowance allocations.

Other commenters favored some form of updating of allocations, provided the updates were done based on output data rather than heat input data. Another commenter noted that EPA should periodically re-allocate NOX allowances based on actual operating performance of the sources. These commenters noted that an updating output-based allocation system has the potential to reward and encourage efficiency.

The Agency agrees with the commenters who suggested that updating output-based allowance systems for electric generating units reward and encourage efficiency, but also agrees with the commenters who stated that updating allocations, whether input or output-based, provide incentives to generate more electricity. The Agency commissioned an analysis of the impacts of permanent allocations versus updated allocations in order to respond to the comments received on the proposal and to assist in determining the most appropriate method for distributing NOX allowances. The results of the analysis as well as a description of the methodology can be found in the report, “Economic Analysis of Alternative Methods of Allocating NOX Emissions Allowances” (Docket A 97-43, Category XI-B-01). The analysis described in the allocation report (Docket A 97-43, Category XI-B-01) predicted that updating allocation systems when compared to permanent allocation systems will result in generally lower nationwide emissions (NOX as well as some ancillary emissions), and, in particular, more generation in the capped region, and so less NOX emissions increase (i.e., “leakage”) outside the capped region.

After reviewing the comments and looking at the results of the allocation report (Docket A 97-43, Category XI-B-01), the Agency has decided to include an updating allocation approach in the Federal NOX Budget Trading Program. The allocation report (Docket A 97-43, Category XI-B-01) indicated that, depending upon the data used in the allocations, an updating system can result in ancillary environmental benefits. The report provided results that supported the comments that asserted that updating allocations can result in increased generation from relatively more efficient, and thus lower emitting sources and decreased generation from relatively less efficient, higher emitting sources. This can result in lower nationwide emissions. In addition, the allocation report indicated that updating systems can result in less leakage of NOX emissions outside the section 126 control area. Leakage refers to NOX emissions increasing outside of the section 126 control region as a result of a cap being placed on NOX emissions within the section 126 region. Imposition of the NOX cap encourages some existing electricity generation to be shifted outside the section 126 region and some new sources to locate outside, rather than inside, the section 126 region. An updating system can result in decreased NOX emissions outside of the section 126 control area relative to a permanent allocation system.

Some of these benefits of updating resulted from the fact that updating provides a mechanism for incorporating new sources into the program, rather than requiring new sources to purchase all the allowances they need for operation from the market. With updating allocations, new sources can be incorporated into the allocations for existing units once the system is updated. Prior to the update, new sources can receive allocations from a new source set-aside. Under a permanent system any new source set-aside would be exhausted at some point, resulting in new sources having to purchase all of the allowances they need to operate.

The Agency believes that new sources should be allocated allowances, rather than being required to purchase allowances. The analysis described in the allocation report (Docket A 97-43, Category XI-B-01) indicates that an updating system can achieve ancillary environmental benefits relative to a permanent system in part because new, more efficient sources locate in the section 126 region if allowances are available to them. Requiring new sources to purchase all the allowances they need to operate, as opposed to making them available through an updating mechanism, would raise the cost of locating within the section 126 region for new sources. If new sources are built within the section 126 control region, generation from new sources can replace some generation from existing sources, resulting in ancillary environmental benefits within the section 126 region. New sources tend to be more efficient and emit at lower emission rates. Additionally, allocating to new sources through an updating mechanism could limit the potential leakage of emissions outside of the section 126 region.[9]

However, rather than an annually updating approach as proposed, the Agency will update the allocations every 5 years. Updating the allocations every 5 years provides a reasonable balance between two important, but countervailing factors: (i) accommodating changing electricity market conditions (by incorporating new sources and reflecting generation changes) and encouraging generation efficiency that can result in ancillary environmental benefits, and; (ii) giving sources more certainty for their compliance planning. The first factor tends to support more frequent updating, while the second factor tends to support less frequent updating.

Most of the commenters suggested that EPA issue allocations for a longer time period (at least 5 years). The Agency agrees with the commenters that an annually updating system could Start Printed Page 2700create a level of uncertainty for sources that may interfere unduly with compliance planning and cause market distortions even though that uncertainty is reduced by issuing the allowances at least 3 years prior to the relevant control period.

Therefore, the final rule provides that while the Agency will not record the allocations in the unit accounts until April 1 of the year 3 years preceding each relevant control period, the allocations for 2004, 2005, 2006, and 2007 will be the same as the allocations for the 2003 control period. After this initial five year period, EPA will update the allocations every 5 years while still ensuring that sources know their allocations 3 years prior to the relevant control season. For example, by April 1, 2005, sources will know their allocations for the control periods 2008-2012. By April 1, 2010, sources will know their allocations for the control periods 2013-2017.

(3) What baseline will be used for determining the allocations? In the proposed part 97, the Agency based the initial 3 years of allocations for large electric generating units on the average of the data for the two highest control periods from the years 1995, 1996, and 1997. For the subsequent annual updates, EPA proposed to use a single year's worth of data as the basis for allocating to existing EGUs. For example, the 2006 allocations would be based on data from 2002, and the 2007 allocations would be based on data from 2003.

A few commenters supported the Agency's proposed approach of using data from the average of the highest two ozone season values from the period 1995, 1996 and 1997. However, several commenters requested variations on the baselines used for their particular allocations. A number of commenters noted that due to exceptional circumstances (generally in 1995 and 1996), such as mothballing, construction, repairs, etc., the data for certain units are too low and as a result the affected utilities would be denied a fair and adequate level or amount of allocations for these units. Other commenters noted generally that EPA should consider claims of atypical baseline years in developing allocations. Several commenters suggested that EPA should allow sources to use 1998 data (in addition to data from the previous years) in determining the allocations. The majority of commenters suggested using multiple years of data rather than a single year for both the initial and subsequent allocations.

The Agency proposed using data from 1995, 1996, and 1997 (the average of the data from the 2 highest years) in determining the initial allocations for electric generating units so that the initial allocations would better represent the operation of particular units. The Agency believes that an average of data from more than one year provides a more representative baseline than basing an allocation on data from one year which may not reflect representative operating conditions at a particular unit. The Agency used the most recent data available that had been through a public review process and, at the time of the proposal, 1998 data was not yet available. With the publication of the Notice of Data Availability on August 9, 1999, EPA now has 1998 data that has been publicly reviewed (See Section III.B.3.a.ii.(3) below about the sources of data used for allocations). EPA agrees with the commenters that sources should be able to use data from 1998 in determining their allocations. Therefore, the Agency is finalizing an initial allocation approach that bases the allocations on the average of the highest of 2 out of the 4 most recent years that have quality assured, publicly reviewed data (1995, 1996, 1997, 1998).

The Agency is making data from this additional year (1998) available for use in the 2003-2007 allocations to incorporate the most recent data available, but also to address comments received from sources who cited exceptional circumstances in more than 1 of the 3 years originally proposed as the basis for the initial allocation. The Agency believes that this adequately addresses exceptional circumstances since it allows sources to pick the 2 highest years out of a 4-year range. Thus, if a source faced exceptional circumstances in either 1 or 2 years between 1995 and 1998, data from the year(s) in which the exceptional circumstances occurred would not be used in the initial allocation. If circumstances occurred that reduced heat input for more than half of the years 1995-1998, it is highly questionable whether they should be considered “exceptional” and therefore not reflected in the allocations.

In the proposal, the Agency stated that after the initial allocation period, companies would be able to better accommodate variations in single year allocations through the trading market and company-wide compliance strategies and therefore the Agency proposed basing the annual updates on one year of data. However, because the Agency has moved from an annually updating allocation system (as described in the proposal) to a system that updates every 5 years, variations in allocations could have a more lasting effect. An unusually low year of operation could affect allocations for 5 years if only one year of data is used as the basis for the update. Therefore, the Agency is finalizing an updating allocation approach for EGUs that bases the updated allocations on an average of the data from the 5 most recent years. The Agency is using all 5 of the most recent years to ensure that data from each year contributes to the eventual allocation level. If the Agency only selected one, or a couple of years as a baseline, sources could potentially have an incentive to operate more in the 1 or 2 years on which their allocation would be based because it would give them a higher baseline used in setting allocations. Using data from a larger number of years (i.e., 5 years) reduces significantly the ability of a source to distort its allocation by operating more in some years relative to other years.

However, for the period 2008-2012, data from the 5 years immediately preceding the year in which the allocations will be determined may not be available for all sources. Allocations will be based on an average of data from the years immediately preceding 2005 (the year in which the 2008-2012 allocations will be determined) for which data is available. The Agency expects sources to begin monitoring in 2002, and data should be available for the 2002, 2003, and 2004 control periods. Therefore, the 2008 through 2012 allocations will be based on the average of the data from the 2002, 2003, and 2004 control periods. For all subsequent updates, 5 years of data will be available and will be used in the allocations. For example, the 2013-2017 allocations will be based on the average of the data from the 2005, 2006, 2007, 2008 and 2009 control seasons.

ii. Basis for EGU Allocations. The Agency requested comment on three separate allocation methodologies for electric generating units in the October 21, 1998 section 126 proposal. Under the first option, EPA would allocate allowances based on the product of an emission rate in pounds of NOX/mmBtu and the total heat input for all units in the Federal NOX Budget Trading Program measured in mmBtus of energy utilized. The proposed part 97 included provisions implementing this approach. The second option described in the proposal allocated allowances to fossil-fuel fired electric generation 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 allocated allowances to all large fossil fuel-fired electric generating units and non-NOX emitting Start Printed Page 2701electric generators, such as nuclear and renewable electric generating units, in the States covered by the section 126 rulemaking based on their electricity generation.

Section III.B.3.a.(ii)(1) explains that the allocations finalized with this rule replace the default emission limitation methodology finalized with the May 25, 1999 final section 126 rule. Section III.B.3.a.(ii)(2) summarizes the comments the Agency received on the three proposed allocation options, describes the Agency's commitment to adopting an output-based allocation approach, lays out the technical reasons why the Agency is issuing heat-input based allocations for the 2003-2007 control periods, and explains why the Agency can not issue output-based allocations until the 2008 control period. Section III.B.3.a.(ii)(3) discusses the sources of data used in determining the allocations, and Section III.B.3.a.(ii)(4) describes the final allocation approach for new sources. Finally, Section III.B.3.a.(ii)(5) summarizes the rule language included in the final part 97.

(1) Default Emission Limitations. In the May 25, 1999 final section 126 rule, EPA included a default emission limitation methodology that would provide unit specific emission limitations in the event that the Administrator failed to promulgate the Federal NOX Budget Trading Program. With today's action, the Administrator is promulgating the provisions of the Federal NOX Budget Trading Program including an allocation methodology and the specific allocations. The methodology and allocations specified in today's action replace the interim emission limitations promulgated with the May 25, 1999 section 126 rule.

As discussed in the May 25, 1999 final rule, EPA entered into a consent decree with the petitioning States that committed the Agency to developing a final section 126 remedy by April 30, 1999. However, the regulations setting forth the Federal NOX Budget Trading Program were not included with the May 25, 1999 section 126 rule because the Agency had not had sufficient time to respond to comments and make final determinations on allocations and other trading program provisions at the time of that rule. Therefore, as part of the May 25, 1999 section 126 rule, the Agency promulgated on an interim basis emission limitations that would be imposed in the event a finding under section 126 is made without the Administrator having promulgated the Federal NOX Budget Trading Program regulations. As part of today's action, the Agency is promulgating the regulations setting forth the Federal NOX Budget Trading Program including the initial allocations. Therefore, the default remedy set forth in § 52.34(k) is superseded as a matter of law, and today's final rule deletes § 52.34(k) accordingly.

For similar reasons, the provisions in § 52.34(j)(1) and (2) that describe generally, and require promulgation of, the Federal NOX Budget Trading Program are superseded and deleted. In particular, the general statement of the emission limitation for the program in § 52.34(j)(1) is set forth in more detail in part 97 (i.e., §§ 97.6(c), 97.42(e), and 97.54).

(2) Final EGU Allocation Methodology. The Agency received numerous comments on the three proposed allocation methodologies for electric generating units. A number of commenters expressed support for an input-based allocation methodology. Some of the commenters that expressed support for a fossil fuel-based allocation methodology noted that the inclusion of nuclear or hydroelectric sources would be inequitable since these types of sources do not emit NOX. One commenter noted that allocations should be granted to these sources only if doing so would not reduce the State budget for fossil fuel-fired sources. A different commenter noted that output-based allocations to all generation sources are inappropriate since they lead to an inappropriate redistribution of income from fossil to non-fossil sources. Another commenter noted that use of an output-based allocation system that includes non-fossil fuel-fired units will dramatically decrease the effective emissions rate to which fossil fuel-fired units are subject (i.e., to 0.12 lb/mmBtu or lower), which may affect the feasibility of compliance. However, a number of other commenters expressed support for an output-based allocation methodology. Some of these commenters support output-based allocations only for fossil fuel-fired units, while others expressed support for an output-based allocation methodology that is generation-neutral (i.e., includes non-NOX-emitting generators). One commenter specifically expressed support for an output-based system that would include fossil fuel units and some non-emitting energy sources, such as wind, solar, biomass, and small hydroelectric facilities. A few commenters only generally expressed support for an output-based system, without stating whether the system should be generation neutral or based on fossil fuel units only.

Comments were also received on the potential effectiveness of an output-based system to improve efficiency. One of the commenters that expressed support for an output methodology applicable only to fossil fuel units noted that improvements in the efficiency of the energy system will come from the overall stringency of the emissions cap, instead of the allocation methodology. One commenter noted that output-based allocations will provide little incentive for energy efficiency. Another commenter noted that an output-based allocation system has the potential to reward and encourage efficiency, but that it is difficult to evaluate the effectiveness and potential benefits until the details of this allocation system are finalized.

Others noted that there are difficulties and uncertainties associated with an output-based allocation procedure that should be resolved prior to implementation. However, a few of these commenters expressed support for an output-based allocation method that would incorporate non-fossil sources, and some added that an output-based, generation-neutral approach would result in greater air quality benefits.

One commenter generally opposed an output-based approach and noted that EPA does not have the legal authority to implement a section 126 regulatory scheme that includes fossil fuel and non-fossil fuel-fired units. This commenter added that output-based allocations would provide no air quality benefit, could hinder attainment of the NAAQS in some areas, would increase compliance costs, and would be difficult to implement. According to the commenter, output-based allocations would create tracking and administrative problems and would involve the added complications of obtaining steam output data and determining how it should be combined with the electricity output information.

The Agency agrees with the commenter who stated that improvements in the efficiency of the energy system will result from the overall stringency of the emissions cap. The ability for sources to sell surplus allowances provides an incentive for efficiency improvements in any given year, regardless of how the allowances are distributed.[10] In general, the emissions reductions, improvements in energy efficiency, and any associated ancillary environmental improvements Start Printed Page 2702will primarily come as a result of the cap on NOX emissions.

However, the Agency believes, based on a review of the comments and the results of the allocation report (Docket A 97-43, Category XI-B-01), that allocation methods can have an impact on electricity generation decisions. The Agency has carefully weighed the comments, considered the results of the report, and considered technical feasibility and data availability factors in making its allocation decision.

The Agency has concluded that an updating output-based approach is likely to result in more ancillary environmental benefits, lower emission control costs and lower fuel use than an updating heat input-based system. Therefore, the Agency has committed to adopting an output-based allocation system for the updated allocations in the section 126 control remedy.

However, the Agency has determined that a heat input based allocation is the most appropriate approach to use for the initial 2003-2007 allocation. Section 97.42 of today's rule describes this heat input methodology used to calculate the initial allocations. Appendix A contains the specific unit allocations that will be issued each year during the initial five-year period (2003-2007) for all the units affected by the control remedy under this section 126 rulemaking.

The Agency has decided to allocate on a heat input basis for the initial allocation period for a number of reasons. First, although the Agency has now put out for public comment data on electric generation from affected sources, the heat input data for the initial baseline period has undergone more extensive public review than the output data. In addition, the set of heat input data is more complete in that EPA has available measured heat input data, but not output data, for each affected unit. The heat input numbers also reflect the actual operation of each unit. The output data EPA has available to it is, in many cases, plant data that is apportioned to the unit level based on heat input. The EPA agrees with commenters that directly measured output data is more accurate than apportioned output data based on heat input. The accuracy of output apportionment based on heat input depends on whether the units at the plant actually have the same efficiencies. Any differences in the design of the units or their fuels makes it less likely for the efficiencies to be the same. Further, in order for a cogenerator to receive a NOX allowance allocation that reflects the efficiency of the unit's entire operation, instead of just the efficiency of the generation of electricity, EPA would need thermal (steam) output data in addition to electric generation data. The Agency specifically solicited comment on steam (thermal output) data from co-generation units in the original October 21, 1998 section 126 proposal. Based on available information (see docket A-97-43, Category X-A-04), the Agency estimated that approximately 10% of the EGU units affected by this section 126 rule are co-generation units. However, in response to the proposal and the August 9, 1999 Notice of Data Availability, only two commenters provided steam data. Based on these comments and the Agency's estimate of the number of existing co-generation units, the Agency believes that it does not have a complete set of data for co-generation plants.

Additionally, as pointed out by several commenters and based on the allocation report (Docket A 97-43, Category XI-B-01), the updating aspect of the allocations (not the initial allocation nor the input or output basis of the allocations) provides the incentives for behavior changes and thus, only differences between an input and output-based updating approach will yield a difference in expected behavior. Because the initial allocation is based on historical data and so reflects only actions already taken, it would not provide any incentives (either the potential negative or positive incentives pointed out by commenters) for future actions. In other words, basing the initial allocation on output as opposed to input would not result in any additional air quality benefits (or costs), changes in emissions control costs, or market distortions.

However, EPA's allocation report (Docket A 97-43, Category XI-B-01), as well as the commenters, project differences in environmental and emissions control costs between an output-based allocation system on an updating basis and a heat input-based allocation system on an updating basis. As discussed above, updating allocations provides a mechanism to allocate to new sources and can encourage generation efficiency. The allocation report indicates that an updating output system is likely to result in more generation efficiency and ancillary environmental benefits, relative to the updating heat input systems proposed in the October 21, 1998 section 126 proposal or the permanent allocation systems suggested by commenters. The analysis also shows that updating on the basis of fuel input rather than electricity output would result in higher emissions control costs and higher fuel use. Therefore, the Agency is committing to issuing future regulations that adopt an updating allocation system based on output that will be used to determine allocations starting in the 2008 control period.

The Agency disagrees with commenters who suggest that an updating output system would provide no air quality benefit and could hinder attainment of the NAAQS in some areas. The Agency believes that a permanent allocation based on, output-based and input-based systems would result in the same air quality impacts, and that, on an updating basis, differences would likely exist. However, those differences would only be in ancillary environmental impacts and in emission control costs, not in the overall level or impact of ozone season NOX emissions within the control region. Any method of distributing allowances in a program where NOX is capped will result in the same level of NOX emissions in the area that has been capped (see Docket A 97-43, Category XI-B-01). Therefore, an output system would not hinder attainment of the NAAQS in any area covered by the Federal NOX Budget Trading Program.

The Agency reiterates that it is strongly committed to moving to an updating output-based allocation system as soon as practicable. However, 2008 is the first year for which output-based allocations can be determined.

For the reasons discussed above, EPA must obtain reliable and complete output data before issuing future allocations based on output. The monitoring and reporting requirements that are necessary to provide EPA with the appropriate output data are not yet in place. Questions related to the specific provisions of part 97 regarding output-based allocations have not yet been addressed as well.[11] To collect the necessary output data, the Agency plans future rulemakings to revise the monitoring and reporting requirements. Revising the monitoring and reporting requirements for the EGU sources affected by the rule will enable the Agency to collect a complete set of reliable output data (both electricity generation and thermal (steam) data) in a consistent manner from all sources that may receive allocations. The Agency has committed to a schedule for developing the infrastructure necessary for collecting the data necessary for an updating output allocation system. The Start Printed Page 2703Agency has put together a stakeholder group that is looking at the technical feasibility of output allocations. This group has made significant progress in addressing these critical issues. The Agency will use information provided by the stakeholder group to finalize output allocation guidance in 2000 for States under the NOX SIP call and make the necessary rule changes by the year 2001 under the section 126 action to require NOX Budget units to monitor and report output data. The Agency could propose changes to the monitoring and reporting requirements in 2000, take public comment on the proposal, finalize the requirements in 2001, provide sources time to implement the requirements, and start collecting data from sources in 2002. The earliest the Agency could obtain the output data from all sources would be starting with the 2002 control season.

Further, in today's rule, the Agency is providing sources their allocations three years prior to the relevant control season. The Agency proposed this approach in both the NOX Budget Trading Program for the NOX SIP call, as well as the section 126 proposal, and generally received comment supporting the proposal. As stated in section III.B.3.a.i.(1) of this preamble, the Agency believes allocating three years prior to the relevant control season is important to provide sufficient time for sources to plan for compliance.

In addition, the Agency believes that allocations for multiple control periods should be calculated based on an average of multiple years of data when available. The Agency originally proposed to base the updated annual allocations on one year's worth of data. The Agency received comments that uniformly criticized basing updated allocations on only one year's worth of data. Most commenters suggested using several years of data in the baseline for determining future allocations in order to provide a more representative baseline. In today's rule, the Agency revised the proposed approach in response to these comments and in order to accommodate other changes the Agency has made to the proposed allocation method (see preamble section III.B.3.a.i.(2)). In the final allocation provisions, the Agency is issuing multiple years of allocations, rather than issuing annual updates, in order to provide sources greater certainty for compliance planning and to provide for the development of markets for NOX allowances. The Agency maintains that it is important to base allocations on multiple years of baseline data when available in order to provide for a representative baseline, particularly where the Agency is determining allocations for multiple years using the same baseline.

In general, the Agency believes that the longer the baseline period, the more representative the data. However, for determining the appropriate baseline period for the initial update, the Agency must balance the benefits of having a longer baseline period with its commitment to move to an output allocation system as soon as practicable. On balance, the Agency has decided that basing the first update on three years of data (2002-2004) would be sufficient time to provide for a representative baseline without unduly delaying implementation of an output allocation approach.

Therefore, since the Agency cannot start collecting output data until 2002 at the earliest and the Agency believes that about three years of data are appropriate for setting the baseline for allocations, the Agency cannot issue output allocations until 2005. The allocations issued in 2005 allocations will be based on data from 2002, 2003, and 2004. Because the Agency has decided that sources shall receive their allocations three years prior to the relevant control season and the Agency can not calculate output allocations until 2005, 2008 is the first year for which output-based allocations can be determined.

While the Agency has committed to finalizing an output-based allocation method for the subsequent updates, the Agency has not yet determined to what sources it should allocate based on output, e.g., whether it should allocate only to fossil fuel-fired sources or also to non-NOX emitting generation sources. The allocation report (Docket A 97-43, Category XI-B-01) indicated some differences (ancillary environmental differences as well as control cost differences) between allocating on an updating output basis only to fossil fuel-fired sources or also to non-emitting sources, but not significant differences. Additionally, few commenters supported either position with technical analysis. Because the Agency is committing to moving to an output-based system after the first 5 years of the Federal NOX Budget Trading Program, the Agency plans to consider further this question of what sources should be allocated allowances. EPA intends to propose and then finalize appropriate rule language addressing this issue in time to allocate allowances for the 2008-2012 control seasons.

The EPA notes that whatever decision is made in the context of the Federal NOX Budget Trading Program will not set a precedent for allocations under future cap-and-trade programs. The Agency's allocation report examined the question of allocations only in the context of NOX emissions and the specific section 126 control remedy, and its results should only be interpreted in that context. New analysis that looks at the specific parameters of potential future cap-and-trade programs will be necessary for making any future decisions on allocations. Therefore, any decision on allocation methodology that is made in the context of the Federal NOX Budget Trading Program will not affect any future allocation decision made by the Agency in other cap-and-trade programs.

(3) Sources of Supporting Data for Allocations for Existing Electric Generating Units. Today's final rule uses heat input data from the ozone season during the years 1995 through 1998 as the basis for the initial allocation to EGUs for the years 2003 through 2007. For the years 1995 and 1996, EPA is using the heat input data that was made available for comment during the SIP call inventory development process and that was used to develop the November, 1999 State emission budgets and emission inventory. The 1997 data was posted on the Agency's regional transport of ozone section 126 internet website and made available for public comment on December 21, 1998 and reopened for comment in the August 9, 1999 Notice of Data Availability. The EPA is using the 1998 heat input data it made available for comment on August 9, 1999 and then revised based upon comment. The original source for heat input data for most EGUs was heat input data reported to EPA by sources under the Acid Rain Program. In addition, EPA used heat input data provided by commenters during a number of public comment periods and heat input for non-utility generators from the OTAG inventory (1995). Where there was no other source of heat input information for non-utility generators, the Agency used calculated average values for heat input from the Integrated Planning Model (IPM) for 1995 and 1996 (the years considered in calculating States' emission budgets).

In the future, EPA will allocate NOX allowances to EGUs based upon output data, starting with an updated allocation for the years 2008 through 2012. As suggested by commenters, the Agency intends to base future output-based allocations upon directly measured data for electric generation and thermal output. In order to collect these data, EPA will propose monitoring and reporting requirements related to electric generation and thermal output for EGUs in the Federal NOX Budget Start Printed Page 2704Trading Program. The Agency plans to propose these requirements in the year 2000 and to issue final requirements no later than the year 2001.

The EPA provided unit-specific allocations along with the October 21, 1998 proposed section 126 rule to solicit comment on the underlying data used in the proposed allocations and the methodologies employed in determining the allocations. There were three sets of allocations that accompanied the three allocation bases that EPA proposed: heat input, output from fossil fuel-fired units, and output from all electricity generators. All three sets of allocations were based upon information for the highest two ozone season values during the years 1995 through 1997. EPA developed generation estimates for fossil fuel-fired units by multiplying the unit heat rate [12] by the historic heat input for each year. For non-utility electricity generators, EPA used the heat input described above, and generic heat rates by unit type and nameplate capacity used in IPM. 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 Agency specifically solicited electrical output data and steam output data for cogenerators. For power plants that do not combust fuel (i.e., nuclear and hydroelectric generators), EPA used electric generation data calculated using outputs from IPM. The Agency solicited comment on the methods for determining electricity generation data, the data themselves, and any additional information for the plants for which EPA had not found data.

Some commenters raised specific concerns regarding the data and methodology that were used in the context of output-based allocations. In particular, commenters noted that output-based allocations should be based on actual “measured” data and not “computed” data. Commenters suggested using the generation data on EIA forms 767 and 759. Another commenter suggested using the gross generation data that sources report under the Acid Rain Program. In general, commenters thought that these sources of data would be more accurate than using calculated values based on heat input and heat rate.

Commenters acknowledged that determining output-based allocations for non-utility generators is more difficult than for utility sources. Commenters suggested the following alternative sources of data:

  • IPM heat rate values for specific units (instead of generic values);
  • IPM generation values;
  • data from States that currently require non-utility generators to provide data on heat-input;
  • actual output data from 1995-97 that has been previously reported on EIA Form 860; or
  • data from EIA form 867.

In response to these comments, EPA requested comment on a different set of supporting data that could be used for allocations on August 9, 1999 and again on September 15, 1999 (See 64 FR 43124 and 64 FR 50041). EPA made available heat input data for the 1997 and 1998 ozone seasons for large EGUs and net electric generation data from EIA form 759 for the 1995-1998 ozone seasons for large EGUs and for electric generators that do not combust fuel. The Agency specifically requested comment on those data where either: (1) EPA used data from a different source than it used in the proposed allocations (such as electric generation data, 1998 heat input data, and data provided based upon public comments) or (2) EPA found that entire categories of data were lacking (i.e., heat input data, net heat rate data, and electric generation for 1997 or 1998 for units that do not report under the Acid Rain Program).

The sources of the data are described in detail in the August 9, 1999 Notice of Data Availability. Heat input data for 1997 and 1998 were from the sources described above, primarily from data reported under the Acid Rain Program. EPA obtained net electric generation data in megawatt hours (MWh) for the ozone season (May through September) during the years 1995 through 1998 for each utility power plant that submitted EIA form 759. The Agency then apportioned the plant-level net electric generation data in EIA Form 759 to each unit at the plant. For fossil-fuel fired EGUs, EPA used heat input data (where available) to apportion the generation data. For electric generators that did not burn fuel, the Agency generally divided the plant-level generation using each generator's portion of the total nameplate capacity of all generators at the plant. EPA described the specific methods used to apportion electric generation more fully in the August 9, 1999 Notice of Data Availability and in the supporting documentation file “outmethd.txt” included with the data files. For non-utility generators, EPA found it necessary to provide calculated electric output data based upon heat rate and heat input data where commenters did not provide output data, because electric generation data for 1995 through 1998 were not publically available.

The public also commented on the data and the sources of the data that the Agency made available on August 9, 1999. Some commenters suggested that it would be better to use directly measured generation values for each unit, where these data are available on EIA form 767. Commenters stated that this would be more accurate than apportioning plant-level generation from EIA form 759 to individual units. In particular, comments stated that apportioning output-based allocations based upon heat input data does not recognize and reward efficiency differences. These commenters suggested that unit level accounting of output is necessary because, at some plants, different units have different owners.

The EPA will not be using output data (for the reasons discussed in section III.B.3.a.ii.(2)) for the initial allocation of NOX allowances for the Federal NOX Budget Trading Program. Thus, EPA does not need output data at this time. However, in general, EPA agrees that directly measured generation data are more accurate than calculated generation values. For example, where units at a plant operate with different efficiencies (i.e., different output per mmBtu of heat input), apportionment based on heat input may be inaccurate and, because more efficient units are not apportioned more output, tends to obviate the benefit of using an output-based approach.

A number of commenters noted that the proposed output-based allocation methodology would penalize cogeneration facilities because it distributes the same amount of allocations to these sources as simple electric generators, even though cogenerators must consume more energy in order to provide useful thermal energy. The commenters stated that EPA should allocate allowances to cogeneration facilities for both thermal and electric output (or, as proposed by one commenter, use an option based on output sold). Commenters provided specific information and recommendations as to how EPA should calculate the thermal output of cogeneration facilities by using generic power-to-heat ratios or obtaining the necessary data directly from facilities. As the Agency works toward developing the infrastructure for an updating output allocation method, these comments will be considered.

The EPA agrees that using measured electric and thermal output from a cogeneration unit is likely to be more Start Printed Page 2705accurate, more equitable, and more effective at promoting energy efficiency than using heat input and a heat rate to estimate output from a cogeneration unit. However, the Agency does not currently have access to these data for cogeneration units. The Agency specifically encouraged commenters to provide this information in the proposed rulemaking because these data are not publicly available. As discussed above in section III.B.3.a.ii.(2) of this preamble, EPA will update allocations for EGUs based upon electric and thermal output beginning with allocations for 2008 through 2012. In order to obtain timely, consistent, and accurate information, EPA will initiate another rulemaking, to be completed no later than 2001, related to the monitoring and reporting of electric and thermal output. This will give the Agency an accurate, consistent database of thermal output data from cogeneration units that is currently lacking.

(4) Treatment of New EGUs. In the October 21, 1998 section 126 proposal, the Agency proposed a set-aside for new sources consistent with the provisions of part 96. New electricity generating units required to participate in the Federal NOX Budget Trading Program would have access to this set-aside. In 2003, 2004 and 2005, each State set-aside would initially hold 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 hold 2 percent of the NOX allowances in the section 126 trading program budget in the State. In the proposal, new sources would receive allocations equivalent to 0.15 lb/mmBtu multiplied by the heat input the unit would use if operating at maximum capacity. The allocations would then be subject to a reduction to reflect the unit's actual utilization. At the end of each relevant control period, EPA proposed to 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 Agency received numerous comments on the new source set-aside proposal. One commenter noted that there should not be a set-aside for new sources and that existing sources should not have their NOX allocations reduced in order to create set-aside accounts. However, the majority of commenters expressed support for the concept of a new source set-aside. One commenter specifically expressed support for the level of the new source set-aside as proposed by EPA. However, many commenters noted that EPA should incorporate flexibility into its program to allow States to determine the appropriate level of set-asides for new sources, that State specific growth factors can be used to determine these levels, and that EPA should work with States to ensure that new and modified sources are accommodated in the design and implementation of the State NOX cap. One commenter noted that this set aside should remain small to minimize the burden on existing sources. A few commenters suggested alternative sizes for the set-aside. One commenter recommended that prevention of significant deterioration (PSD) and new source review (NSR) processes under Title I of the Clean Air Act could be used to help evaluate the impact of growth from new sources within each State and determine State-specific new source set-asides. However, some commenters noted that State growth factors should not be used and that more information is needed before new source set-asides can be determined based on these factors.

Some commenters raised specific concerns regarding the allocation of allowances to new sources. One commenter noted that initial allocation for new units should be based on the unit's applicable SIP NOX emission rate and subsequent allocations should be based on the source's actual ozone-season emissions. Another commenter suggested that the provision to allocate to new sources based on an emission rate of 0.15 lb/mmBtu could prevent the development of new generation sources, because that would quickly exhaust the set-aside. This commenter recommended that allocations from the set-aside pool be limited to the maximum permitted emission rate. An additional commenter recommended that EPA bank any unused allowances in the new source set-aside for future new source use, rather than distribute them back to the existing sources. One other commenter suggested distributing the available allowances to all new sources that apply by the spring of the relevant control season, rather than first-come, first-served as proposed. That commenter suggested redistributing the allowances at the end of the season according to actual operation to provide the most equitable coverage.

The Agency agrees with the commenters who suggested that a new source set-aside is an effective mechanism for integrating new sources into the Federal NOX Budget Trading Program. As stated in the proposal as well as the final NOX SIP call, the Agency believes it is important to be able to accommodate new source growth in a set-aside. Therefore, in determining the appropriate size of the proposed new source set-aside, the Agency took into account how much growth in new sources would need to be accommodated by the new source set-aside. In the proposal the initial new source set-aside had to be large enough to accommodate new source growth from 1995 through 2005. With the allocation timing specified in the final part 97, the initial new source set-aside must be large enough to accommodate new sources that begin operation after May 1, 1997 but before October 1, 2007. Sources that commence operation before May 1, 1997 will have at least 2 years of data on which to base the 2003-2007 allocation and can be incorporated into the allocation method for existing sources. Sources that commence operation after May 1, 1997 would not have 2 years of data, and therefore, the Agency maintains that it is appropriate for those sources to draw from the new source set-aside through 2007. Using May 1, 1997 as the dividing date between existing and new sources for the 2003-2007 allocations maintains a balance between: limiting the number of sources with access to the new source set-aside so as not to create an over-subscription; and providing access to the set-aside for those sources that lack sufficient operating data to determine a representative allocation baseline. Part 97 maintains this balance for subsequent updates as it allows sources to draw from the set-aside if they commenced operation with less than two control periods remaining in the baseline period that is used for determining allocations.

Based on the analysis conducted for the NOX SIP call and the section 126 rulemaking (see docket A-97-43, Category IV-A-06), EPA projects a 4.2 percent growth in utilization due to new source generation over the 1997-2007 time period. Establishing a new source set-aside of 5 percent would provide assurance that all new sources will receive sufficient allowances to operate even with an allocation method that first allocates assuming the unit's projected utilization at maximum operation. Likewise, for the future updated allocation periods, the new source set-aside will have to cover 10 years of new source growth (i.e., ten control periods, 2003-2012, for a unit commencing operation on or after May 1, 2003) as compared to 5 years in the proposal. Therefore, a 5 percent set-aside will be appropriate for future years of the program (as compared with the 2 percent in the proposal).

In the October 21, 1998 section 126 proposal, the Agency solicited comment Start Printed Page 2706on whether the size of each State's new source set-aside should be set consistent with the State growth rates for new units that underlies the overall State growth rate used in developing the State trading program budget. The Agency received one comment (from a State that is not covered by the section 126 rule) in support of setting State specific new source set-asides based on the State growth rates and one comment (from a State that is covered by this section 126 rule) against using the State specific growth rates to set the new source set-aside. EPA anticipates that there will be relatively limited variation from State to State in growth rates for new sources. In addition, the only commenter supporting the use of State-specific growth rates provided no rationale. Therefore, the Agency is establishing the new source set-asides at a level (5%) consistent with the overall new source growth rate for the section 126 region and consistent across the States covered by the section 126 rule, rather than using the State specific growth rates.

The Agency agrees with the commenters who suggested that new sources are unlikely to need allocations based on an emission rate of 0.15 lb/mmBtu. One commenter pointed out that allocating at that level would allocate an unrealistic level of allowances and could potentially quickly use up the new source set-aside. Therefore, in order to avoid over-subscription, the set-aside for the initial allocation period in today's rule allocates to new sources based on the lesser of 0.15 lb/mmBtu or the permitted level multiplied by the source's utilization at maximum operating capacity (see docket A-97-43, Category IV-A-06 for a discussion of emission rates of new sources). As proposed, the Agency has retained the procedure at the end of the control period for adjusting allocations based on actual utilization (i.e., heat input). Because proposed part 97 defines “utilization” as “heat input”, the final rule eliminates the term “utilization” and replaces it with the term “heat input”. Language is added to clarify that any allowances deducted based on actual heat input are transferred to the new source set-aside from which they were allocated.

The EPA is concerned that under a first-come, first-served system, some new sources may not receive allowances from the set-aside. Therefore, the Agency agrees with the commenter that suggested that allowances from the new source set-aside should be distributed in the spring before the relevant control period to all sources that have submitted approved applications for allowances from the set-aside. If the number of approved allowances to be distributed exceeds the number in the set-aside, the allowances will be distributed proportionally to those sources with approved applications. In that way, all new sources will know before the control season that they will have access to allowances and will be able to estimate the amount that will remain after adjusting for actual heat input. In the unlikely event that the number of allowances needed by new sources for compliance exceeds the supply, new units can purchase the needed balance of allowances from the market.

To accommodate this change, part 97 has been revised to require all applications for allowances from the new source set-aside to be received by January 1 of the year for which the unit is applying for allowances from the set-aside. The Agency will review all the allowance requests and determine by order the allowance allocations from the set-aside as described above by April 1. The final part 97 also includes revised language which describes how the Agency will allocate the available allowances if, in total, new NOX Budget units request more allowances than are available in the new unit set-aside account for any given year. The EPA has retained the provisions of part 97 that describe the distribution of any allowances remaining in the set-aside at the end of the year to existing sources on a pro rata basis.

(5) Part 97 Rule Language. While the allocation methodology included in part 96 as part of the final NOX SIP call was an optional approach that may be adopted by States, the allocation approach described in part 97 is required for sources affected by the control remedy under a section 126 finding. Appendix A contains the initial NOX allowance allocations for NOX Budget units for 2003-2007. This section summarizes the provisions of part 97 that describe how the initial allocations are made and how future updates will be calculated. Final part 97 differs from the proposed rule on the timing provisions, the data used in the allocations for both electric generating units and non-electric generating units, as well as the size and methodology for distributing the new source set-aside.

The final part 97 includes provisions for calculating an initial unadjusted allocation amount for each unit as well as provisions for adjusting that initial amount to ensure that the total allowances issued matches the portion of each State (or partial State) trading program budget that is available for distribution to existing sources. Initial unadjusted allocations to existing NOX Budget units serving electric generators are based on actual heat input data (in mmBtu) for the units multiplied by an emission rate of 0.15 lb/mmBtu. For the control periods in 2003, 2004, 2005, 2006, and 2007, the heat input used in the allocation calculation for large EGUs equals the average of the two highest control season heat inputs among the years 1995, 1996, 1997, and 1998. Once EPA completes the initial allocation calculation for all the existing NOX budget units serving electric generators, the EPA proportionally adjusts the allocation for each unit upward or downward so that the total allocations match the portion of the appropriate State's section 126 trading program budget attributed to the large electric generating units affected by the rulemaking (to ensure that all of the allowances available for distribution to existing sources are distributed and to ensure that the number of allowances distributed does not exceed the number in the trading program budget). Then, EPA adjusts the allocation for each unit proportionately so that the total allocation equals 95 percent of that portion of the State's trading program budget in order to provide for the 5 percent new source set-aside. In making all of the above adjustments, EPA will round to the nearest whole number of allowances. Generally, this will mean rounding down decimals less than 0.5 and rounding up decimals 0.5 or greater. However, other rounding approaches will be used if necessary to ensure that the number of total allowance allocations in correct. The provisions of § 97.42(b) describe the procedures for determining allocations and state explicitly that calculations expressed in pounds must be divided by 2000 lb/ton to convert to tons and then to allowances. The Agency will record the allowances in the NATS one year at a time, by May 1 of the year that is 3 years prior to the applicable control season.

While the Agency has committed to using output data to determine the allocations for each five year block following 2007, specific rule provisions have not yet been developed. Until the measurement and reporting methods have been developed, the Agency can not include rule language for an output based allocation method in part 97. Therefore, part 97 includes rule language for allocations based on heat input, rather than output, for the initial allocations and for future allocations. This provides a default emission limitation methodology for the control periods starting in 2008 in the event that the Agency does not develop an updating output-based methodology in Start Printed Page 2707time. However, the Agency reiterates that it is committed to developing the output-based methodology and infrastructure. Once the methodology has been developed, the Agency will propose changes to part 97.

Proposed (and final) §§ 97.42(b), (c), and (d) provide for the allocation of NOX allowances only to NOX Budget units under § 97.4 (i.e., large EGUs). The proposal therefore implied that sources that are not NOX Budget units should not be allocated NOX allowances and should not retain any NOX allowances that the sources are allocated. EPA is adding § 97.42(g) to address explicitly this aspect of the proposal. EPA notes that the Agency anticipates that allocations to a source that is later determined to be actually a non-NOX Budget unit will rarely, if ever, occur. However, it is desirable to clarify how the Agency will handle such cases. Section 97.42(g) states that if the Administrator determines that a source allocated NOX allowances for a control period under §§ 97.42(b), (c), and (d) is not actually a NOX Budget unit, then the Administrator will not record the allocation. If the allocation was already recorded and the Administrator has not yet completed all compliance deductions under § 97.54 (except deductions under § 97.54(d)(2)) for the control period of the allocation, the Administrator will deduct from the source's account allowances equal in number to, and of the same or earlier control period as, the allocated allowances. This approach with regard to allocated, or allocated and recorded, allowances is consistent with the implication of the proposal that non-NOX Budget units are not given allowances. However, § 97.42(g) states that if the allowances were recorded and the Administrator has completed the compliance deductions for the control period (i.e., has deducted sufficient allowances to cover the source's emissions), then the Administrator will not deduct any more allowances with regard to the allocation for that control period. In that case, the source will have met the requirements of the NOX Budget Trading Program for that control period (as if the source were a NOX Budget unit) by monitoring NOX emissions, making emission reductions and/or purchasing allowances, and holding allowances to cover emissions. It therefore seems reasonable not to deduct any more allowances from the source's allocation. Even if the source does not hold enough allowances and has excess emissions for the control period, then allowances equal to the allocation will probably be deducted either to cover emissions or to account for excess emissions. The Administrator will transfer any allowances not recorded, and any allowances deducted, under § 97.42(g) to an allocation set-aside for the State in which the source is located. This will ensure that the allowances will then be available to NOX Budget units in the State either as allocations for new units or as allowances redistributed to existing units.

b. NOXAllowance Allocation Methodology for Non-Electric Generating Units. i. Timing Provisions. (1) When will EPA determine non-EGU allowances? As indicated in Section III.B.3.a.i.(1) of this preamble, in the October 21, 1998 section 126 proposal, EPA proposed to determine allocations 3 years ahead of each applicable control period. As was the case for the EGUs, the Agency did not receive any adverse comment on this specific proposal for non-EGUs. Most commenters favored providing more time for sources to know their allocations for any given control season. They suggested that knowing the allocations in advance would provide for the development of forward markets and would provide greater certainty for source compliance planning.

Therefore, as proposed, the Administrator will determine NOX allowances for non-EGUs in EPA's NOX Allowance Tracking System (NATS) by April 1 of every year for the control period that is 3 years later. For example, EPA will determine the allocations for the 2003 control period by April 1, 2000, for those large non-EGUs subject to the control remedy under this section 126 rulemaking. EPA will then determine allocations for the 2004 control period by April 1, 2001, etc., so that the allocations are always recorded in the NATS 3 years in advance. These provisions are consistent with the minimum timing requirements for the NOX Budget Trading Program specified in the preamble to the final NOX SIP call. As discussed in the October 21, 1998 section 126 proposal, as well as the October 27, 1998 final NOX SIP call, EPA believes that it is important to determine the allocations a few years ahead of the compliance period to provide some predictability for sources in their control planning and to build confidence in the market.

As stated above, the EPA will determine allocations and record them in the NATS on an annual basis 3 years prior to the relevant control period. This will allow a State, as part of an approved SIP, to submit allocations up to 3 years prior to the relevant control period and have those allocations replace the allocations EPA was planning to determine as part of the Federal NOX Budget Trading Program. By recording allocations into the 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 3 years prior to the relevant control season.

(2) Will the Agency update the non-EGU allocations periodically? In the October 21, 1998 section 126 proposal, the Agency proposed to use the same allocations for the non-EGUs for the first 3 years of the program, unless a State replaces a section 126 action with its own allocations in an approved SIP. After the initial three year period, EPA proposed to update the allocations on an annual basis 3 years prior to the relevant control season.

The Agency did not receive comment specific to non-EGUs on the schedule for updating allocations. Rather, the Agency received numerous comments with respect to the general proposal for updating the allocations annually after the initial three year period for all sources subject to the section 126 control remedy. These comments are summarized in section III.B.3.a.i.(2).

After reviewing the comments, the Agency has determined that an allocation system that updates every 5 years provides an appropriate balance between accommodating changing market conditions (by incorporating new sources and excluding sources that shutdown) and providing more certainty (by fixing the allocation amount for 5 years) for sources in their compliance planning. The Agency agrees with the commenters that an annually updating system could create a level of uncertainty for sources, even though that uncertainty is reduced by issuing the allowances at least 3 years prior to the relevant control period, that may interfere unduly with compliance planning and cause market distortions. Most of the commenters suggested that EPA issue allocations for a longer time period (at least 5 years).

Updating can provide a mechanism for incorporating new sources into the program. As stated in the October 27, 1998 final NOX SIP call, the Agency believes that new sources should be allocated allowances, rather than being required to purchase allowances. An updating system provides a mechanism for new sources to receive an allocation rather than having to purchase all the allowances they need for operation from the market. With updating allocations, new sources can be incorporated into the allocations for existing units once the system is updated. Prior to the Start Printed Page 2708update, new sources can receive allocations from a new source set-aside. Under a permanent system, a new source set-aside would be exhausted at some point, resulting in new sources having to purchase all of the allowances they need to operate.

EPA recognizes that an updating heat input methodology can create some disincentive for increased efficiency. However, the cap on total NOX allowances reduces the disincentive, and this disadvantage of updating is more than offset by the benefits of accommodating changing market conditions.

Therefore, as with EGU allocations, while the Agency will not record the non-EGU allocations in the unit accounts until April 1 of the year 3 years preceding each relevant control period, the allocations for 2004, 2005, 2006, and 2007 will be the same as the allocations for the 2003 control period. After this initial five year period, EPA will update the allocations every 5 years while still ensuring that sources know their allocations 3 years prior to the relevant control season. For example, by April 1, 2005, sources will know their allocations for the control periods 2008-2012. By April 1, 2010, sources will know their allocations for the control periods 2013-2017.

(3) What baseline will EPA use to issue non-EGU allowances? For the non-electric generating units subject to the program, the Agency proposed to base the initial allocations on data from 1995. This differed from the proposal for EGUs because the Agency did not have data beyond 1995 available for non-EGUs. For the subsequent annual updates, EPA proposed to use a single year's worth of data as the basis for allocating to both existing EGUs and existing non-EGUs. For example, the 2006 allocations would be based on data from 2002, and the 2007 allocations would be based on data from 2003.

One commenter noted that it is inappropriate to determine the NOX allowance allocation for non-EGU units based only on the 1995 control period. This commenter added that a more reasonable approach is to allow operators to propose a typical year or series of years if 1995 was not typical for their operations. In general, for both EGUs and non-EGUs, commenters did not support updating the allocation based on a single year's worth of data.

In response to these comments, in the August 9, 1999 Notice of Data Availability, the Agency requested that non-EGUs provide heat input data from May through September for the years 1996, 1997, and/or 1998 where the heat input from May through September for the year 1995 is not representative of a non-EGU's operation over the last several years. The Agency will continue to use 1995 data for determining the initial allocations for non-EGUs because the 1995 data are the most recent data the Agency knows are currently available for non-electric generating units, and the 1995 data has been through several rounds of public review. However, where commenters provided data for non-EGUs for additional years (1996-1998), EPA used the average of the two highest ozone seasons of heat input to calculate unadjusted allocations, as the Agency does for all EGUs. (See section III.B.3.b.ii.(3), below, regarding the sources of data used for allocations.)

For the subsequent allocations, the Agency will use the same approach as that adopted for EGUs. Today's final rule adopts an updating allocation approach for non-EGUs that bases the updated allocations on an average of the data from the 5 most recent years. As stated in Section III.B.3.a.i., because the Agency has moved from an annually updating allocation system (as described in the proposal) to a system that updates every 5 years, variations in allocations could have a more lasting effect. An unusually low year of operation could affect allocations for 5 years if only one year of data is used as the basis for the update. Therefore, the Agency is using all 5 of the most recent years to ensure that data from each year contributes equally to the eventual allocation level.

However, as is the case for EGUs, for the period 2008-2012, data from the 5 years immediately preceding the year in which the allocations will be determined may not be available. Therefore, allocations will be based on an average of data from the years immediately preceding 2005 (the year in which the 2008-2012 allocations will be determined) for which data is available. The Agency expects sources to begin monitoring in 2002, and therefore data should be available for the 2002, 2003, and 2004 control periods. Consequently, the 2008 through 2012 allocations will be based on the average of the data from the 2002, 2003, and 2004 control seasons. For all subsequent updates, 5 years of data will be available and will be used in the allocations. For example, the 2013-2017 allocations will be based on the average of the data from the 2005, 2006, 2007, 2008 and 2009 control seasons.

ii. Basis for non-EGU Allocations. (1) Final Non-EGU Allocation Methodology. In the October 21, 1998 proposal, EPA proposed to use heat input as the basis for determining allocations for large non-electric generating units in the Federal NOX Budget Trading Program. The EPA proposed this approach for both the initial allocation period as well as for subsequent years of the program. The proposal pointed out that this approach differs from the method used to determine the aggregate emission level for non-electric generating units (i.e., a percentage reduction from historical levels) because at the time the aggregate level was determined, heat input data for individual units was not available.

Some commenters disagreed with a heat-input based approach for non-EGUs. One commenter noted that non-EGU allocations should not be based on the regional average controlled emission rate of 0.17 lb/mmBtu. According to the commenter, EPA should base the allocation emission rate on the uncontrolled emission rate used to develop the State budgets and the reduction percentage found to be cost-effective in determining the State's non-EGU budget. Another commenter added that the use of the 0.17 lb/mmBtu rate requires reductions greater than the 60 percent EPA found to be cost effective. One commenter noted that the use of heat input as the basis for determining allocations for large non-EGUs in the trading program is questionable and that this “fuel-neutral” approach is arbitrary and capricious because it favors natural gas usage at the expense of coal, oil, wood, and other fuels.

The Agency has decided to maintain the heat input-based approach used in the proposal for allocating NOX allowances. Distributing allowances on a heat-input basis provides a fuel neutral method of allocating to the units in the trading program similar to the allocation approaches used for the electric generating units. Heat-input based allocations also allow for reallocating in the future to accommodate new units because units receive an allocation based on their proportional share of total heat input each time the allocations are updated. As new sources enter the market, their heat input can be factored into the proportional distribution of allowances. Allocating based on a specific percentage reduction in emissions from a baseline year does not allow for updating because the allowances are not distributed on a proportional basis under a percentage reduction method. If the trading program budget is created and distributed based on a percentage reduction in emissions, sources that were not operating during the original baseline period can not receive any allowances. Moreover, even for existing sources, once the Federal NOX Budget Trading Program has been operating and Start Printed Page 2709sources have begun controlling emissions, there is no appropriate “baseline” level of emissions from which to base a percentage reduction reallocation of the allowances.

The Agency agrees with commenters that on an individual unit basis, the heat input-based approach described above could result in individual unit allocations that differ from a 60 percent reduction at that unit (a 60 percent control level would result in a range of emission rates). The heat input approach is a fuel neutral approach that encourages higher emitting plants to control more. However, the Agency disagrees with the commenter that asserted that the use of the 0.17 lb/mmBtu emission rate requires greater reductions across the control region than the 60 percent used in determining the overall budgets. As discussed in the final NOX SIP call as well as the October 21, 1998 section 126 proposal, 0.17 lb/mmBtu is the average effective emission rate in place after large non-EGUs achieve a regional reduction of 60 percent (in the NOX SIP call region). In the allocation methodology, the Agency uses 0.17 lb/mmBtu for the sole purpose of initially proportionally allocating the non-EGU portion of the Sstate trading program budget to the large non-EGUs affected by the section 126 rulemaking. Once the Agency determines each unit's proportional share of the total (by multiplying the unit's baseline level of heat input by 0.17 lb/mmBtu), each unit's allocation is adjusted so that the total allocations issued matches the portion of the State trading program budget assigned for existing sources. With this adjustment, the total allowances issued is consistent with the 60 percent control level assumed in setting the State trading program budget for large non-EGUs. The Agency could have used an alternative emission rate (for example, 0.15 lb/mmBtu or 0.20 lb/mmBtu) for calculating the initial unadjusted allowance level and each unit would still end up with the same level of allowances after the initial allocations are adjusted to match the budget.

The Agency plans to issue each subsequent update of the non-EGU allocations based on heat input. This differs from the approach adopted for EGUs because unlike for EGUs, the Agency is not confident yet that output-based allocations for all non-EGUs are justified or that a reasonable approach for collecting accurate output data can be developed for all non-EGUs. The Agency acknowledges the commenters' suggestions for approaches that may be used to calculate output-based allocations for non-EGUs but maintains that it currently does not have sufficient information or basis for justifying output-based allocations for large non-EGUs. EPA does not have access to thermal (steam) output data for non-EGUs. Since the issuance of the proposal, the Agency has held meetings with the Updating Output Emission Limitation Workgroup, a stakeholder group concerning output-based allocations. Some workgroup members have raised a number of issues and concerns that they believe may make it undesirable and perhaps difficult or impossible to monitor thermal output data and use it as the basis for updated NOX allowance allocations. For example, one workgroup member mentioned difficulties in measuring thermal output in the form of hot exhaust and in measuring output at older plants with complicated configurations. In contrast, power plants that sell their electric or thermal output are already monitoring output and will have relatively few problems to resolve compared to some of the complex industrial cogeneration facilities mentioned by industrial boiler owners.

Industrial boiler owners also questioned whether output-based allocations are appropriate for non-EGUs, even if they are technically feasible. Workgroup members raised several issues that do not exist for power plants. For example, currently thermal output from industrial boilers is monitored primarily for boiler control and safety, rather than for sale or for determining unit efficiency, and so the available monitoring systems may be less accurate than available for measuring power plant output. Additionally, there does not exist an industrial boiler equivalent of the interstate electricity “grid” that allows more efficient EGUs to be dispatched more frequently. This may affect whether output-based allocations for non-EGUs would have the same potentially beneficial effects on efficiency and the environment as output-based allocations. Because of the lack of data and the issues raised by these workgroup members, the Agency maintains that further discussion and further rulemakings are necessary to address these issues. Therefore, at this time the Agency is deciding to use heat input as the basis for allocating initial NOX allowances to non-EGUs as well as for determining subsequent allocations.

(2) Sources of Supporting Data for Allocations for Existing Non-Electric Generating Units. Today's final rule uses heat input data as the basis for NOX allowance allocations to non-EGUs. For the year 1995, EPA is using the same heat input data that it developed in the process of developing the December, 1999 State emission budgets and emission inventory. Where commenters provided acceptable data for non-EGUs for additional years (1996-1998), EPA is using the average of the two highest ozone seasons of heat input for the years 1995 through 1998 to calculate unadjusted allocations, as the Agency does for all EGUs.

As discussed above in section III.B.3.a.i.(3), some commenters expressed support for a non-EGU allocation methodology that would be similar to the methodology used for EGUs. One commenter suggested that operators should be allowed to propose a typical year or series of years if 1995 was not typical for their operations. Other commenters suggested that the Agency request steam output data and use this data to establish output-based allocations for non-EGUs.

EPA proposed unit-specific allocations for non-EGUs in Appendix B of proposed part 97 (63 FR 56292). The Agency based these allocations upon 1995 unit heat input data. EPA developed these heat input data in the process of developing the emission inventories used to establish State budgets. EPA solicited comment on the underlying data used in those allocations and the methodology used in determining the allocations. In particular, EPA requested comment on supporting data that could be used for allocations on August 9, 1999 and again on September 15, 1999 (See 64 FR 43124 and 64 FR 50041). In the August 9, 1999 Notice of Data Availability, EPA made available data files that, among other things, contained heat input data for large non-EGUs for the ozone season during the year 1995 (i.e., industrial boilers or turbines with a design heat input greater than 250 mmBtu/hr). The Agency also requested that non-EGUs provide heat input data from May through September for the years 1996, 1997, and/or 1998 where the heat input from May through September for the year 1995 is not representative of a non-EGU's operation over the last several years.

In general, EPA agrees that using more years of baseline data for non-EGUs could be more representative of unit operation over longer periods of time. However, EPA is aware of no complete databases of heat input data or NOX emissions data for non-EGUs that the Agency could use. Furthermore, commenters have not provided or mentioned any such database. As noted above, EPA requested that non-EGUs provide heat input data from control periods in 1996, 1997, and/or 1998 where the heat input from the 1995 Start Printed Page 2710control period is not representative of a non-EGU's operation over the last several years; this is similar to one commenter's suggestion to allow operators to propose a typical year or series of years if 1995 was not typical for their operations. If commenters have not provided heat input data for 1996, 1997, or 1998, the Agency assumes that the companies find their heat input data for 1995 to be representative. If commenters provided acceptable data for 1996, 1997, and/or 1998 during the public comment period, then the Agency took the average heat input for the 2 highest years from 1995 through 1998 in determining that unit's baseline.

(3) Treatment of New Non-EGUs. In the October 21, 1998 proposal, the Agency created a set-aside for new non-EGUs consistent with the provisions of part 96. Under the proposal, new non-electricity generating units required to participate in the Federal NOX Budget Trading Program would have access to this set-aside. In 2003, 2004 and 2005, the Agency proposed that each State set-aside would initially hold 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. In the proposal, new non-EGUs would receive allocations equivalent to 0.17 lb/mmBtu multiplied by their utilization at maximum capacity, and then they would be subject to a reduction in their allocation so that they only keep an allocation based on their actual utilization. At the end of each relevant control period, EPA would 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 Agency did not receive any comment specific to the treatment of new non-EGUs. Commenters generally addressed their comments as summarized in section III.2.B.ii.d. to the treatment of new sources in general or new EGUs specifically. Therefore, for the reasons discussed in section III.2.B.ii.d., the Agency is establishing a new source set-aside for non-EGUs consistent with the new source set-aside for EGUs. The Agency believes that a new source set-aside of 5 percent is appropriate for the first five year period of the program. Likewise, for the updated allocation periods, the new source set-aside will have to cover 10 years of new source growth (as compared to 5 years in the proposal) [13] . Therefore a 5 percent set-aside is appropriate for future years of the program (as compared with the 2 percent in the proposal).

The Agency is finalizing the following approach to distributing the allowances from the new source set-aside to new non-EGUs. A new non-EGU can apply to receive allowances from the new source set-aside at the lower of 0.17 lb/mmBtu or its permitted rate multiplied by the heat input the unit would be projected to use if it operated at maximum capacity. After the control period, the allocation is subject to a deduction to reflect the unit's actual heat input, and any allowances deducted for this reason are transferred back to the new source set-aside from which they were allocated. At the end of each relevant control period, EPA will return any allowances remaining in the set-aside on a pro-rata basis to the existing units, i.e., the units that received an original allocation that was adjusted to create the new source set-aside in the State.

As was indicated in section III.2.B.ii.d., the EPA is concerned that under a first-come, first-served system, it is possible that some new sources may not receive allowances from the set-aside. Therefore, the Agency will determine by order the allowance allocations from the new source set-aside by April 1 of the relevant control period to all sources that have submitted approved requests for allowances from the set-aside. If the number of approved allowances to be distributed exceeds the number in the set-aside, the allowances will be distributed proportionally to those sources with approved applications. In that way, all new sources will know prior to the control season that they will have access to allowances. Those new sources receiving allowances from the set-aside will still be subject to reduction based on actual heat input at the end of the control period. In the unlikely event that the number of allowances needed by new sources for compliance exceeds the supply, new units can purchase the needed balance of allowances from the market.

To accommodate this change (consistent with the change made for new EGUs), part 97 has been revised to require all non-EGU applications for allowances from the new source set-aside to be received by January 1 of the year for which the unit is applying for allowances from the set-aside. The Agency will review all the allowance requests and determine the allowance allocations from the set-aside as described above by April 1. The final part 97 also includes revised language which describes how the Agency will allocate the available allowances if, in total, new NOX Budget units request more allowances than are available in the new unit set-aside account for any given year. The EPA retained the provisions of part 97 that describe the distribution of any allowances remaining in the set-aside at the end of the year to existing sources on a pro rata basis.

(4) Non-EGU Allocation Summary. EPA is basing the initial unadjusted allocations to existing large non-electric generating units on each unit's 1995 control period heat input (in mmBtu) (or where additional years of data have been accepted, on the average of the unit's two highest control period heat inputs from 1995-1998) multiplied by an emission rate of 0.17 lb/mmBtu. For large non-electric generating units subject to the trading program, 1995 heat input data or the average of the 2 highest heat inputs from 1995-1998 is used in the allocation calculation for the control periods 2003, 2004, 2005, 2006, and 2007. The EPA adjusts the allocation for each unit upward or downward so that the total allocations match the aggregate emission levels associated with the State's large non-electric generating units. Then EPA adjusts the allocations for each unit proportionately so that the total allocation equals 95 percent of the aggregate emission levels apportioned to the State's large non-electric generating units, in order to provide for the 5 percent new source set-aside. As described above with regard to EGUs, EPA will round to the nearest whole number of allowances in making all of the above adjustments. The provisions of § 97.42(c) describe the procedures for determining allowances and state explicitly that calculations expressed in pounds must be converted to tons and then to allowances. The Agency will record the allowances in the NATS one year at a time, by April 1 of the year that is 3 years prior to the applicable control season.

For each five year block following 2007, the heat input used in the allocation calculation for large non-electric generating units will equal the average of the heat input data from the 5 years preceding the year in which the update is calculated except for the Start Printed Page 27112008-2012 allocations. For the 2008-2012 block of allowances, the Agency will use an average of the heat input from 2002-2004. Once EPA completes the initial allocation calculation for all existing NOX Budget units, EPA will adjust the allocations to match the aggregate emission levels apportioned to large non-electric generating units and then adjust the allocation for each unit proportionately so that the total allocation equals 95 percent of the aggregate emission levels apportioned to large non-electric generating units.

New non-EGUs may apply to receive allowances from the 5 percent set-aside. New sources with approved set-aside allowance requests will receive allowances based on the lower of either 0.17 lb/mmBtu or their permitted rate multiplied by their utilization at maximum designed heat input. If approved allowance requests exceed the number of allowances available in the set-aside, the Agency will distribute the allowances on a pro-rata basis. Each unit would be subject to a reduction in their allocation at the end of the season (if necessary) so that they only keep an allocation based on their actual heat input. Remaining allowances in the new source set-aside will be redistributed back to existing sources.

As described in section III.B.3.a.ii.(5) of this preamble, proposed (and final) §§ 97.42(b), (c), and (d) provide for the allocation of NOX allowances only to NOX Budget units under § 97.4 (i.e., large non-EGUs). The proposal therefore implied that sources that are not NOX Budget units should not be allocated NOX allowances and should not retain any NOX allowances that the sources are allocated. As discussed above, EPA is adding § 97.42(g) to address explicitly this aspect of the proposal. EPA notes that the Agency anticipates that allocations to a source that is later determined to be actually a non-NOX Budget unit will rarely, if ever, occur.

4. The Compliance Supplement Pool

The EPA received comments in response to the proposals for the NOX SIP call and section 126 action expressing concern that some sources may encounter unexpected problems installing controls by the May 1, 2003 deadline. The commenters suggested that these unexpected problems could cause unacceptable risk for a source and its industry. In particular, commenters expressed concern related to the electricity industry, stating that the deadline could adversely impact the reliability of electricity supply. Based on its own analysis, EPA believes sources will have ample time to install NOX control technologies and comply by 2003 and that there should be no interruption to the flow of electricity due to the Federal NOX Budget Trading Program. (For a further discussion of the feasibility of installing NOX controls and NOX control implementation and budget achievement, see the supplemental proposal to the NOX SIP call (63 FR 57447), the October 21, 1998 proposed section 126 rule (63 FR 56318), and the May 25, 1999 final Section 126 rule (64 FR 28302)). However, EPA chose to address these concerns, despite disagreeing with the commenter's concerns, and included a compliance supplement pool in the final NOX SIP call and proposed the inclusion of one in the Federal NOX Budget Trading Program. The compliance supplement pool addresses commenters' concerns by ensuring the availability of a limited number of allowances in addition to the State budgets, at the start of the program.

In the October 21, 1998 section 126 rule, EPA proposed to include a compliance supplement pool which was analogous to the pool in the NOX SIP call. The EPA proposed a capped pool budgeted at the State level proportional to the percentage of ozone season reductions for which all of the sources in a State are responsible for under the section 126 control remedy. EPA proposed using similar procedures for establishing the size of the individual State compliance supplement pools under the section 126 control remedy as under the NOX SIP call. In the May 25, 1999 section 126 final rule (64 FR 28310) EPA finalized the existence of the compliance supplement pool and the fact that the tonnage in the 126 compliance supplement pool for a given State would be equal to the tonnage in the NOX SIP call compliance supplement pool.

In today's rule, EPA is finalizing the method by which EPA will distribute the allowances in the compliance supplement pool to individual units. The October 21, 1998 action proposed two options for distributing the pool allowances. Under the first option, EPA would distribute pool allowances for early reduction credits only. Under the second option, EPA would distribute a portion of the pool allowances as early reduction credits and would reserve some remaining portion for sources that demonstrate a need for a “direct” distribution method. (See 63 FR 56319-20). Today's part 97 provides for the distribution of the compliance supplement pool allowances for early reduction credits only. Sources may request early reduction credits for reductions made during the 2001 and 2002 ozone seasons equal to the difference between 0.25 lb/mmBtu and the unit's NOX emissions rate, multiplied by the unit's actual heat input for the applicable control period if certain conditions are met. (For a detailed discussion of the requirements for early reduction credits finalized in today's rule see III.B.4.b below). After completion of the 2004 end-of-season reconciliation process, EPA will retire all compliance supplement pool allowances remaining in NATS.

Today's final rule adopts the early reduction distribution method proposed on October 21, 1998 with one exception. Under the proposal, the credits were distributed on a first come, first served basis with requests due by October 31 of the year for which early reduction credits are requested. Under today's final rule, sources must submit all requests for early reduction credits by February 1, 2003. (Please see below for a detailed discussion of why EPA changed the early reduction credit request deadline).

EPA notes that recent information reinforces EPA's initial determination that there is very little or no risk to the electricity industry and electricity reliability from compliance with the section 126 action. First recent reports from the North American Electric Reliability Council (NERC) and the Mid Atlantic Area Council found that compliance with the NOX SIP call is unlikely to cause electricity reliability problems. (See docket A-97-43, item X-A-07). Today's section 126 action, of course, requires compliance by significantly fewer sources because it covers significantly fewer States than the NOX SIP call. Second, recent experience in the Ozone Transport Commission demonstrates that installation of Selective Catalytic Reduction (SCR), which EPA estimates to be the most complicated and time consuming NOX control measure to install, can be completed in less than a year. For example, the Public Service of New Hampshire installed SCR at its Merrimack Station in Bow, New Hampshire on its Unit 1 boiler in 44 weeks and its Unit 2 boiler in 48 weeks. (See docket A-97-43, item number X-N-04).

Despite this recent information further suggesting that a compliance supplement pool may not be needed, the Federal NOX Budget Trading Program includes the compliance supplement pool as adopted in the May 25, 1999 section 126 final rule. The section 126 compliance supplement pool provides the same number of allowances for distribution to sources in a State or portion of a State as the NOX SIP call compliance supplement pool. Start Printed Page 2712Each State covered by the section 126 action has the same size compliance supplement pool as under the NOX SIP call, and each partial State's compliance supplement pool under the section 126 action has been prorated based on the ration of the partial State trading program budget to the whole State trading program budget. EPA is adopting this approach for two reasons. First, this addresses the concerns that some commenters continue to express concerning the risk to the electricity industry from compliance. Second, making the compliance supplement pool in each State or portion of a State effectively the same size under the section 126 action and the NOX SIP call allows for integration of any State NOX Budget Trading Programs that may be adopted in SIPs and approved as meeting the SIP call with the Federal NOX Budget Trading Program that EPA is requiring under section 126. For example, if EPA applies the Federal NOX Budget Trading Program to a given State and a SIP for that State including a State NOX Budget Trading Program is approved and in effect before the 2004 control period (which is the last control period before pool allowances expire), sources in the State will be able to retain the pool allowances distributed to them under the federal program if the pool is the same size under the two programs. If instead the section 126 pool were larger than the NOX SIP call pool, sources might have to give up pool allowances, thereby reducing sources' ability to plan compliance using such allowances. If the opposite were true, and the section 126 compliance supplement pool were smaller than the NOX SIP call compliance supplement pool, then integration of the State and Federal trading program would be hampered.

EPA received numerous comments on its proposal for a compliance supplement pool under the section 126 control remedy. Included in the comments were several advocating for allowing unlimited generation of early reduction credits, i.e., an uncapped compliance supplement pool. The EPA capped the pool in its May 25, 1999 section 126 final rule because the pool delays achievement of the program's emissions reductions goal. Each allowance in the pool represents an extra ton of NOX emissions which can be emitted. The credits from the pool potentially inflate the NOX budget for future ozone seasons (i.e., in 2007) because sources may use the pool's allowances for compliance in 2003 and 2004 and bank their allocations. The cap on the compliance supplement pool limits this inflation of the budget and ensures a limited potential adverse impact on air quality in future ozone seasons. It also reflects the limited potential need for the pool to guarantee that all sources will hold sufficient allowances to comply with the program requirements in the 2003 ozone season. A larger cap or no cap at all would further delay the achievement of the NOX budget in future ozone (i.e., 2007) seasons and thus the program's environmental goal. (For further discussion of how EPA developed the compliance supplement pool and why EPA limited its size, see the supplemental proposal to the NOX SIP call (63 FR 57428), and the final NOX SIP call (64 FR 57429), and the Response to Comments Document for the May 1999 Section 126 Rulemaking action (section IV.D.).

Aside from the comments advocating for unlimited generation of early reduction credits, EPA received no other comments on its proposal to use the same compliance supplement pool in both its NOX SIP call and section 126 actions. (EPA did receive numerous comments on the proposed emissions reduction requirements for early reduction credits which are discussed in detail in section III.B.4.b below). For the reasons discussed above, in today's rule, EPA reaffirms its May, 1999 decision to finalize a compliance supplement pool whose size is analogous to the size of the compliance supplement pool under the NOX SIP call.

a. Size of the Compliance Supplement Pool. The aggregate compliance supplement pool, under this section 126 action is 97,159 tons. It is smaller than the compliance supplement pool under the May 25, 1999 section 126 final rule (64 FR 33956) and the compliance supplement pool under the NOX SIP call because this rule affects a smaller number of sources. In the June 24, 1999 Interim Final Stay of Action of Section 126 Petitions for Purposes of Reducing Interstate Ozone Transport (64 FR 33956), EPA stayed the effective date of the May 25, 1999 final rule regarding petitions filed under section 126. As a result of this action, four States (Indiana, Kentucky, Michigan and New York) listed in the May 25, 1999 section 126 final rule (64 FR 28200) are now only partially covered by today's section 126 final action. Seven entire States, (Alabama, Connecticut, Illinois, Massachusetts, Missouri, Rhode Island and Tennessee) are no longer covered. (Please see section I.A.1 of this preamble for further discussion of the effects of the June 24, 1999 stay on this final rule). As noted above, for the States affected by this section 126 action, today's final rule adopts State specific compliance supplement pools essentially identical in size to the pools available under the NOX SIP call with the exception of the four partial States. For the four partial States, EPA modified the number of compliance supplement pool allowances under the section 126 action to accurately reflect the changes in their section 126 trading budgets. The EPA prorated the partial States' section 126 compliance supplement pools based on the ratio of the partial state trading program budget to the whole State trading program budget. For example, if all large EGUs and large non-EGUS in Indiana were required to comply with the section 126 control remedy its trading budget would be 58,186 tons. However, since only a portion of the sources in Indiana are required to comply, Indiana's section 126 trading program budget is 7,170 tons, or 12.32% of the whole State trading budget. Therefore, to remain consistent with the modifications to the trading program budget, EPA also prorated the compliance supplement pool for affected sources in Indiana by this ratio, resulting in a compliance supplement pool of 2,454 tons. Similarly, for section 126 affected sources in Kentucky the ratio of the partial State trading program budget to the whole State trading program budget is 54.10%, and in Michigan and New York it is 82.76% and 49.88% respectively.

The State distribution of the compliance supplement pool listed in table III-1 is identical to the distribution promulgated in the December 1999 “Technical Amendment to the Finding of Significant Contribution and Rulemaking for Certain States for Purposes of Reducing Regional Transport of Ozone” with the exception of the seven States no longer covered by the section 126 action and the four partial states (Indiana, Kentucky, Michigan and New York).

Table III-1.—State Compliance Supplement Pools (Tons)

StateCompliance supplement pool
Delaware168
District of Columbia0
Indiana2,454
Kentucky7,314
Maryland3,882
Michigan9,398
New Jersey1,550
New York1,379
North Carolina10,737
Ohio22,301
Pennsylvania15,763
Start Printed Page 2713
Virginia5,504
West Virginia16,709
Total97,159

b. Distribution of the Compliance Supplement Pool to Sources. Under today's final rule, EPA will distribute the compliance supplement pool allowances to sources for early reduction credits (see § 97.43). Allowances from the compliance supplement pool will be available for sources to use for compliance in the 2003 and 2004 control periods only. After the 2004 reconciliation process, EPA will retire any compliance supplement pool allowances remaining in the NATS.

As delineated in § 97.43, any NOX Budget unit may request early reduction credits for reductions made during the 2001 and 2002 ozone seasons equal to the difference between 0.25 lb/mmBtu and the unit's NOX emission rate, multiplied by the unit's actual heat input for the applicable control period if certain conditions are met. The unit must: (1) Install monitoring equipment according to part 75 with no less than 90 percent monitor data availability during the 2000 control season; (2) be in full compliance with State or Federal emissions related requirements; (3) reduce its NOX emission rate to less than 80 percent of its NOX emission rate in 2000; and (4) emit at a rate below 0.25 lb/mmBtu. A unit must apply for early reduction credits by February 1, 2003. If the tons of NOX allowances in the compliance supplement pool for a State exceed the number of accepted early reduction credit requests in that State, EPA will allocate one NOX allowance for each ton of certified early reduction credit. Part 97 provides for the retiring of any NOX allowances remaining in the compliance supplement pool after all certified requests, for 2001 and 2002, have been granted. Based on the analysis discussed below, EPA does not expect this to happen. However, if, the amount of accepted reduction credits are more than the size of the pool for that State, EPA will limit the number of credits distributed to the size of the compliance supplement pool for a State and reduce each applicant's credits pro-rata based on the number of accepted credits from each unit. The EPA will determine by order the allocations for early reduction by April 1, 2003 and will record the allocations by May 1, 2003.

In addition, under today's final rule, sources located in States in the OTC region that are subject to this section 126 action will be allowed to bring their banked 2001 and 2002 vintage OTC allowances into the NOX Budget Trading Program as early reduction credits. As is the case for any State outside of the OTC, if the number of eligible banked OTC allowances is less than a State's compliance supplement pool, the remaining credits will be retired. If the NOX Budget units in an OTC State hold banked OTC allowances in excess of the amount of credits in the State's pool, EPA will limit the number of credits distributed to the size of the compliance supplement pool for that State and reduce each applicant's credits pro-rata based on the number of accepted, banked OTC allowances from each unit.

Under both the NOX SIP call and the section 126 control remedy, all affected sources may apply for, and receive early reduction credits. Under part 97, only large electric generating units and non-electric generating units are subject to the NOX trading program. Under the NOX SIP call, however, States have the flexibility of expanding the universe of affected sources beyond large electric generating units and non-electric generating units, i.e., to include portland cement kilns or electric generating units that serve a generator with a nameplate capacity greater than 15 MWe rather than 25 MWe. Therefore, the allowances in the compliance supplement pool may be available to more categories of sources under the NOX SIP call than under the section 126 control remedy.

In the October 21, 1998 proposed section 126 rule (63 FR 56292), EPA solicited comment on other alternatives for distributing the compliance supplement pool including distributing the pool to States and allowing States to distribute their pool to their respective sources. The EPA also proposed another alternative for distribution of the pool by the Agency to sources. Using this method, EPA would first allocate NOX allowances for early reduction credits as described above. However, instead of retiring any NOX allowances remaining after the allocation for early reduction credits, EPA would distribute the NOX allowances directly to sources that demonstrated a need. Under this “direct distribution” method, a source would be required to demonstrate that achieving compliance by May 1, 2003 would create undue risk to either its operation or industry and that it could not acquire allowances for the 2003 ozone season from the market.

Commenters from electric utilities and other industries commented in favor of letting the States distribute the compliance supplement pool, citing increased flexibility for the States and concerns about logistical delay if EPA awards them. One commenter suggested that the responsibility be given to States with the stipulation that if a State fails to inform EPA of how it will distribute the pool, EPA will distribute it under a default procedure.

Under the assumption that EPA would distribute the compliance supplement pool, nearly all of the commenters agreed that at least a portion of the compliance supplement pool should be distributed for early reduction credits. Commenters from industries, environmental organizations and State agencies argued that distribution exclusively as early reduction credits would stimulate the market and encourage early reductions. The remaining commenters, all from electric utility or other industries, argued in favor of a combination of early reduction credits and direct distribution. These commenters asserted that since the credits must be accepted by EPA and are subject to a ratcheting down if there is over-subscription to the pool, companies have no guarantee that they will receive early reduction credits and therefore cannot rely on them in their compliance strategies. The commenters further asserted that only direct distribution guarantees that sources who actually need the additional allowances will receive them.

One commenter who supported flow control argued that allowances carried over into the Federal NOX Budget Trading Program in 2003 as early reduction credits should be considered banked and subject to flow control if applicable in 2003. (See section III.B.5 of this preamble for a discussion of flow control under the Federal NOX Budget Trading Program).

The EPA also received comment on the proposed requirements for early reduction credits. Numerous commenters argued that reductions in 2000 should be eligible. Commenters proposed that sources should only be required to reduce their NOX emission rate by 10 percent rather than 20 percent of their 2000 rate, that all sources who achieve a level of 0.25 lb/mmBtu by May 1, 2002 should receive early reduction credits, and that all reductions beyond Title IV Acid Rain limitations should be eligible.

One commenter argued that in the case of over-subscription to the compliance supplement pool, Start Printed Page 2714allowances should be distributed among the sources which earned early reduction credits pro-rata based on the sources' percentage of annual reductions required under the section 126 action rather than on a first come, first served basis. Another commenter stated that the number of banked allowances remaining in a source's account in an Ozone Transport Region State at the end of 2002 accurately reflects the source's early reductions and should be counted as such. According to the commenter, in order to bank OTC allowances a unit's emission level must reflect a 55 to 65% reduction or a 0.2 lb/mmBtu emission rate. Therefore, banked OTC allowances meet EPA's early reduction standards.

Part 97 is a federal program designed to be implemented and administered directly by EPA in accordance with section 126 of the Clean Air Act. For this reason, EPA decided to retain the responsibility of distributing the pool to sources and finalized today's rule accordingly. This is consistent with the fact that EPA is already allocating the NOX allowances under the federal trading program. States will have the authority to distribute allowances from the compliance supplement pool and the State trading program budget if the State submits an approvable SIP.

The Agency disagrees with commenters who argued that distribution by EPA would cause delay. The EPA has committed, in today's final rule, to issuing, allocating and recording all NOX allowances for early reduction credits before the start of the initial control period, May 1, 2003. In order to ensure that the Administrator meets that deadline, today's rule requires owners and operators to submit an early reduction credit request by February 1, 2003.

Under the Federal NOX Budget Trading Program finalized in this rule, EPA will distribute the compliance supplement pool for early reduction credits only. Early reduction credits encourage sources to make emissions reductions before they are required to do so. The EPA disagrees with the commenters who stated that direct distribution is necessary to ensure that all sources will be in compliance. First, as discussed above, EPA believes sources will have enough time to install the control equipment needed for compliance before the May 1, 2003 deadline. Second, as discussed in detail below, EPA expects the compliance supplement pool to be fully subscribed. Therefore, early reduction credits will provide the same pool of extra allowances available for compliance during the first 2 years of the program as direct distribution. Sources that need extra allowances for compliance will have access to them through the allowance market. Because these allowances will be generated and distributed to sources before May 1, 2003, sources will have time to buy extra NOX allowances before the deadline for holding NOX allowances to cover emissions.

While EPA acknowledges that there may be some degree of uncertainty regarding the number of credits a source will receive, it disagrees with the commenters' assertion that EPA's approach to distributing compliance supplement pool allowances for early reduction credits gives sources no certainty that they will receive allowances and that sources therefore cannot rely on them when developing compliance strategies. EPA's approach provides assurance that some NOX allowances will be received, and sources can estimate what amounts they are likely to receive. If there is under-subscription of the pool, then sources will receive a NOX allowance for each of their early reduction credits. If there is over-subscription of the pool, sources will still receive NOX allowances, albeit pro-rated, but the entire pool will be allocated. The formula for pro-rata allocation is revised by minor word changes that clarify, but do not make a substantial change in the proposed formula. For example, the order of multiplication and division is changed without changing the results of any calculation using the formula. In addition, the final rule provides that the Administrator will make available to the public the total amount of early reduction credits requested for sources in each State. Sources will therefore be able to make reasonable estimates of and by May 1, 2003 will know, how many allowances they are receiving before the start of the program and can plan their compliance strategies accordingly. (For further discussion on why EPA is distributing the compliance supplement pool for early reduction credits, see 63 FR 57474 and the Response to Comments Document for the Final NOX SIP call (section IX.E.2)).

Today's final rule provides that, if there is over-subscription of the compliance supplement pool, NOX allowances will be distributed pro-rata based on credits generated and not on a first come, first served basis. Consequently, the rule sets a single deadline (February 1, 2003) for submission of all early reduction credit requests. Only this distribution method retains the incentive to continue to generate early reduction credits after the subscription level has been reached. By generating more credits, sources will qualify for a larger portion of the pool after the credit requests have been ratcheted down to the level of the pool. The various methods suggested by commenters do not retain this incentive because they fix the number of allowances a source can receive once the pool is fully subscribed and discourage continued operation of NOX control measures. For example, one commenter suggested an alternate distribution method if the pool is over-subscribed. This commenter suggested distributing the credits in proportion to a source's required section 126 reductions among all sources generating early reduction credits, sources would receive no benefit by continuing to reduce emissions below the level required for early reduction credits. The early reduction credit would serve only as an eligibility requirement for allowances which would be distributed based on the source's required reductions under the section 126 control remedy.

As finalized, part 97 also allows banked 2001 and 2002 vintage OTC allowances to be carried over into the NOX Budget Trading Program as early reduction credits, provided the number of credits issued do not exceed the States' respective compliance supplement pools. As explained in the preamble to the final NOX SIP call (63 FR 57475), “the EPA believes that banked allowances held by sources in the OTC program would qualify as being *** verifiable, and quantifiable [early reductions] *** The banked allowances would also be verified and quantified according to the procedures in the OTC program which are essentially identical to the requirements that will be in place under the NOX Budget Trading Program.” In particular, as stated in § 97.43, early reductions must be monitored according to part 75, subpart H. Since at least May 1999, sources in the OTC States have been monitoring NOX mass emissions according to part 75 (but not subpart H), as supplemented by the OTC monitoring technical guidance document. The guidance is essentially identical to the requirements of part 75, subpart H for most sources. It allows some additional flexibility beyond part 75, subpart H, primarily for small turbines that are 25 MWe or less and emit a relatively small amount of NOX emissions. These sources are not required to participate in the Federal NOX Budget Trading Program and are not eligible for early reduction credits and the compliance supplement pool. Furthermore, the few units which are granted additional Start Printed Page 2715flexibilities under the OTC monitoring technical guidance document and are required to comply with the section 126 control remedy, are small units with relatively low levels of NOX emissions. Due to their relatively low levels of NOX emissions, EPA does not expect these units to have significant numbers of banked allowances (i.e., early reduction credits) in the year or two before sources in OTC States monitor using subpart H of part 75. Monitoring under the OTC technical guidance is not acceptable for monitoring in the long term under this section 126 action. However, because of the nature of the differences as explained above, it is adequate in the short term to quantify NOX emission reductions for early reduction credits as OTC sources make the transition from the OTC NOX Budget Program to the Federal NOX Budget Trading Program. (For further discussion of integration of the OTC NOX Trading Program and the Federal NOX Budget Trading Program, see the final NOX SIP call 63 FR 57475).

The EPA disagrees with the comment that early reduction credits should be considered “banked” at the start of the control period in 2003 and therefore subject to flow control if applicable. EPA included the compliance supplement pool as an additional flexibility mechanism for sources during the first 2 years (2003 and 2004) during which they are required to comply. To the extent compliance flexibility is needed, it is most likely to be needed in the first two control periods of the program. The EPA is granting sources the full flexibility provided by the pool in the 2003 and 2004 control periods by not implementing flow control, regardless of the number of banked allowances, until 2005. (For a discussion of why EPA delayed implementation of flow control from 2004 to 2005 see below, section III.B.5)

Today's rule finalizes early emissions reduction requirements for credits aimed at ensuring that the reductions are: (1) Real, surplus and quantifiable and (2) achieving full subscription of the pool. Under-subscription would mean that sources did not have access to all of the allowances available to them. Over-subscription might encourage sources to turn off NOX controls, i.e., in 2002, causing an increase in NOX emissions and in ground level ozone. While today's final rule retains some incentive for sources to continue generating early reductions after the pool is fully subscribed, the incentive will be stronger if there is no over-subscription.

Under the NOX SIP call, States may accept, for distributing compliance supplement pool allowances, credits for reductions made starting with the 2000 ozone season. However, under today's final rule for the section 126 trading program, only reductions made in 2001 or 2002 can generate credits. The EPA is finalizing this requirement to minimize the potential for over-subscription and more importantly to ensure that the reductions are in response to this program rather than required under another and to ensure that the reductions are calculated from a verified baseline. For example, Phase II of the Acid Rain Program goes into effect in 2000, posing more stringent limits on NOX emission rates. If sources were to earn credits for their reductions in 2000, the reductions may in fact be due to required reductions under the Acid Rain Program. Early reduction credits are meant to reward sources that make reductions beyond those required for other programs and before the start of the Federal NOX Budget Trading Program.

The year 2000 marks the earliest opportunity for a verified baseline. Today's rule requires units applying for early reduction credits to report their NOX emission rate and heat input in accordance with subpart H of part 97 for the full control period on which their baseline emission rates are determined. The unit's monitor data availability must be not less than 90 percent during the control period. This will prevent units from having significantly higher reported baseline emission rates if their monitoring systems are not operating properly and they use substitute data that may overstate emissions. The EPA notes that since it revised subpart H of part 75 and the electronic data reporting format in May 1999, units would not be able to report according to these requirements during 1999 as the rule became effective after the start of the 1999 ozone season. Under part 97, the year 2000 serves as the baseline year from which EPA can verify emissions reductions.

In addition, today's final rule requires that units for which early reduction credits are requested must be in full compliance with State or federal NOX emission control requirements in 2000 through 2002. This ensures that reductions in 2001 and 2002, which are calculated from the 2000 baseline, do not reflect reductions required by other State or federal emission limits that were effective in 2000. This also ensures that a unit is not earning credit for reduction early when the unit is actually in violation of other emission limits and should be reducing even more.

To further ensure that early reductions are real and surplus, today's rule also requires sources to reduce their NOX emission rates to less than both 80 percent of their 2000 rates and 0.25 lbs/mmBtu. Early reduction credits are based on the difference between 0.25 lbs/mmBtu and source's NOX emission rate. If sources are not required to reduce their NOX emission rates to less than 80 percent of their 2000 rates, units already emitting below 0.25 lbs/mmBtu in 2000 could apply and receive credit without making any reductions. Removing or changing this provision, as suggested by commenters, would allow these “low emitters” to receive credit even though they made little or no additional reductions in response to the section 126 requirements. The minimum 20 percent level of reduction is appropriate to ensure that the reduction reflects significant efforts to reduce emissions and not simply variation in NOX emissions that would occur without any significant reduction efforts.

Requiring a unit to reduce its NOX emission rates to less than 80 percent of its 2000 rates and 0.25 lb/mmBtu in order to be eligible establishes a control level below which a unit must reduce emissions to generate early reduction credits. All affected sources must comply by May 1, 2003, and, as explained above, recent experience has shown that SCR may be successfully installed in less than a year. In analyzing potential control levels and determining the appropriate level for generation of early reduction credits, EPA therefore assumed that one third of the units projected to install SCR would install their SCR in 2001 with an additional third in 2002 and the final third in 2003. The analysis assumed that each year, the SCR installations would be complete before the start of the ozone season, i.e., with sufficient time for sources to earn reduction credits in 2001 and 2002. (For a further discussion of the feasibility of installing NOX controls and NOX control implementation and budget achievement dates please see 63 FR 57447 and 64 FR 28302). The EPA then used IPM to estimate the summer fuel usage for units projected to install SCR at 15000 Trillion Btus (Docket A-97-43, Category IV-A-04). Assuming that units with SCR would operate at a control level of 0.10 lbs/mmBtu, EPA analyzed units' potential to generate early reduction credits.

At less stringent emission control level requirements such as 0.30 lbs/mmBtu or 0.35 lbs/mmBtu, the analysis showed units with SCR installed in 2001 and 2002 could generate enough early reduction credits to oversubscribe the compliance supplement pool by Start Printed Page 2716more than 30 percent or 65 percent respectively. If early reduction credits were rewarded for anything below Title IV Acid Rain levels, as two commenters suggested, EPA estimates that 1.5 million early reduction credits could be generated. With a control level of 0.25 lbs/mmBtu, the analysis showed that units with SCR installed in 2001 and 2002 could generate 112,000 credits, slightly less than the compliance supplement pool available under the section 126 control remedy.

However, EPA expects units with SNCR also to earn early reduction credits and conducted an similar analysis to estimate the number of credits units with SNCR could generate. For this analysis, EPA made the same assumption as it did for SCR installation, i.e., that one third of all SNCR installations would occur in 2001, with an additional third in 2002 and the final third in 2003. The EPA then used IPM to estimate that 63 percent of units projected to install SNCR would operate the controls at a level low enough to earn early reduction credits. IPM also estimated the average NOX rate for these units at 0.21 lbs/mmBtu and their summer fuel usage at 1200 Trillion Btus. Based on these results, EPA calculates that units with SNCR will be able to generate nearly 24,500 early reduction credits. This results in a combined regionwide potential early reduction credit generation of 136,000, at approximately the size of the compliance supplement pool.[14] (For further discussion of early reduction credits see 63 FR 25936 and 63 FR 57474).

Although this analysis projects the amount of potential early reduction credits on a region wide bases, EPA maintains that the analysis is also indicative of the potential amount of early reduction credits at the statewide level. The basic assumptions underlying the region-wide analysis also apply on a State-wide basis. In its region-wide analysis, EPA assumed that units would install a range of controls (specifically SCR and SNCR) throughout the region. Based on IPM projections, EPA believes that there will be a range of controls installed, including SCR and SNCR, in most individual States. Similarly, EPA believes that its assumption of the frequency of installation (i.e., one third each year from 2001-2003 before the start of the relevant ozone season) is also reasonable at the State level since the compliance date of May 1, 2003 applies to each individual source, and therefore, in aggregate, to each State. When developing the State trading program budgets, EPA used uniform control level across the region (i.e., 0.15 lbs/mmBtu (assuming historic ozone season heat input adjusted for growth to the year 2007) for large EGUs and a 60 percent reduction in ozone season NOX emissions compared to uncontrolled growth in 2007 for large non-EGUs). Because the controls are uniform, EPA anticipates that each State have a controlled EGU emission rate, in aggregate, around 0.15 lb/mmBtu and a controlled EGU emission rate, in aggregate, around 0.17 lb/mmBtu. Therefore, EPA projects that, consistent with EPA's region-wide analysis, sources in each individual State will reduce their NOX emission rates in 2001 and 2002 to below 0.25 lbs/mmBtu and generate enough early reduction credits to fully subscribe the State compliance supplement pool.

5. Banking

Banking is generally defined as allowing sources that make emissions reductions beyond current requirements to save and to use these excess reductions to exceed requirements in a later control period. Today's final rule allows banking consistent with the October 21, 1998 proposed section 126 rule (63 FR 56312). Allowances not used for compliance may be “banked,” i.e., carried over into the next compliance period for use. Sources may bank unused allowances starting in the first control period of the trading program (2003). NOX Budget units that hold additional NOX allowances beyond what is required to demonstrate compliance in a given control period may carry-over these banked allowances to the next control period.

Allowances are valid until used for compliance or deducted from an account for other purposes. With one exception (i.e., compliance supplement pool allowances) NOX allowances never expire. Banked allowances may be used or sold for compliance in future control periods. (See below for a discussion of management of banked allowances under the section 126 action).

Citing it as a mechanism for increased flexibility and cost savings, the commenters unanimously supported banking. The EPA agrees with the commenters that banking provides flexibility to sources. It allows them to make reductions beyond required levels and “bank” the unused portion for use or sale later. Banking has several advantages: It can encourage earlier or greater reductions than are required from sources, stimulate the market, and encourage efficient use of the market. Banking can also provide flexibility in achieving emissions reduction goals, i.e., by allowing sources to accommodate periodic increased generation activity that may occur in response to interruptions of power supply from non-NOX emitting sources. (For further discussion on EPA's rationale for including banking see the Supplemental proposal to the NOX SIP call (63 FR 25934 and 25944), the final NOX SIP call (63 FR 57472), and the Response to Comments document for the final NOX SIP call (Section IX.E.), and the October 21, 1998 proposed section 126 rule (63 FR 56312)).

The EPA is finalizing the proposed regionwide flow control mechanism to control the use of banked allowances when a significant percentage of all allowances are banked with one exception. Under the October 21, 1998 section 126 proposal, flow control, if applicable, would have begun in 2004 (i.e., after the completion of the end of season reconciliation process in 2003). In final part 97, however, flow control cannot be triggered, regardless of the number of banked allowances, until 2005 (i.e., after completion of the 2004 end of season reconciliation process). (Please see below for a detailed discussion of why EPA delayed the implementation of flow control). As originally proposed, the flow control mechanism establishes a discount ratio of 2-for-1 on the use of banked allowances above a certain level. The discount ratio becomes effective when banked allowances exceed 10 percent of the allowable NOX emissions for all sources covered by the NOX trading program. The discount ratio only applies to allowances when they are used for compliance purposes. Allowances sold or traded on the allowance market are never subject to flow control.

The majority of the commenters disagreed with restricting the use of banked allowances. Commenters asserted that flow control will decrease sources' flexibility and discourage both the use of the market and early emissions reductions. Numerous commenters pointed to unrestricted banking in the Title IV Acid Rain Program as a key reason that the Acid Rain Program is cost effective. A few commenters suggested modified flow control mechanisms, such as setting the trigger level for flow control at 20 percent rather than 10 percent of the allowable NOX emissions, or using an Start Printed Page 2717alternative discount ratio, such as 1.2:1 or 1.3:1. One commenter argued that the flow control ratio was not designed based on air quality needs.

The Agency received several comments that supported flow control. Commenters stated that banking restricted by flow control still provides flexibility for sources while limiting the potential for “excessive use” of banked allowances in a given control period leading to increased ozone.

Today's rule aims to achieve specified limits on ozone season NOX emissions in specified years for the purpose of reducing NOX and ozone transport from upwind States found to be significantly contributing to the non-attainment of NAAQS in downwind States during the ozone season. EPA believes it is appropriate to manage banked allowances, by placing some limitation on the amount of emissions variability that may occur as a result of using banked allowances. Flow control provides some measure of insurance that banked allowances will not be used excessively and thereby result in section 126 named sources significantly contributing to downwind non-attainment. The discount ratio, when triggered, also provides an added benefit for the environment by allowing two allowances to be removed for every one ton of NOX emitted. That extra allowance deducted from the system represents one less ton of future NOX emissions. At the same time, flow control retains much of the flexibility and benefits associated with banking for sources. (For further discussion of the requirements of section 126 and how today's rule meets them, see the preamble to this rule (Sections II.A., II.B., and III.D), the May 25, 1999 section 126 final rule (64 FR 28254, and 28307), and the final NOX SIP call (63 FR 57431).

The EPA changed the first year in which flow control may be triggered from 2004 under the proposal, to 2005 under final part 97. The EPA delayed flow control's implementation date in response to commenter's concerns regarding the feasibility of installing the NOX control equipment required as a result of the section 126 control remedy without any risk to electricity reliability. The EPA believes it is appropriate to give sources trading under the Federal NOX Budget Trading Program this additional flexibility in light of recent experience with the OTC's NOX trading program. At the completion of the first ozone season for the OTC's trading program, EPA calculated a preliminary flow control ratio of 0.49.[15] (Note: 0.49 represents the fraction of an OTC source's banked allowances that will be deducted at the rate of one allowance per ton of NOX emissions during the 2000 ozone season end of season reconciliation process. The remaining fraction (0.51) of an OTC source's banked allowances will be subject to the discount ratio under flow control and deducted at the rate of two allowances per ton of NOX emissions). While, based on its analysis under the NOX SIP call, EPA does not expect flow control to be triggered in either the section 126 region or the wider SIP call region, EPA understands that the OTC program's relatively large flow control ratio has heightened sources' concerns that there will not be enough allowances for compliance in the initial years of the Federal NOX Budget Trading Program. While EPA disagrees with these concerns, it is addressing commenters' concerns by both adopting (as discussed above) a compliance supplement pool and delaying the implementation of flow control until 2005. This approach gives sources greater assurance that they will be able to use compliance supplement pool allowances for compliance and before such allowances expire. (For a detailed discussion of commenter's concerns and EPA's response regarding the effects of implementing the section 126 control remedy on the reliability of electricity see section III.B.4. of this preamble. For a further discussion of the feasibility of installing NOX controls and NOX control implementation and budget achievement dates please see 63 FR 57447 and 64 FR 28302.)

However, the Agency does not believe it is appropriate to delay implementation of flow control beyond 2005. Section 126 requires named sources to eliminate their significant contribution to downwind non-attainment as expeditiously as practicable. Further, any delay beyond 2005 would potentially interfere with the attainment needs of downwind petitioning States. Downwind petitioning states generally must demonstrate attainment by 2007, and to do so they will have to rely on three years of air quality data, from 2005 through 2007. Were flow control delayed beyond 2005 there is a risk that excessive use of banked allowances in 2005 would allow continued significant contribution in that year, which would in turn jeopardize the attainment goals of the downwind States. The EPA believes that delaying the implementation of flow control by just one year, from 2004 to 2005, together with adopting the compliance supplement pool, strikes an appropriate balance between commenters' concerns and the environmental goal of 126, i.e., to eliminate significant contribution from named sources as expeditiously as practicable.

EPA notes that the fact that the Acid Rain regulations provide for unlimited banking of sulfur dioxide allowances is not relevant to the treatment of banking here. In developing the Acid Rain regulations, EPA did not adopt any limitation on banking because title IV itself provides for unlimited banking. See 42 U.S.C. 7651a(3) (definition of “allowances”) and 7651b(b) (stating that an allowance authorizes emissions of 1 ton of sulfur dioxide in the current or any later year). No similar statutory provision applies to the NOX Budget Trading Program.

Commenters also raised concerns that flow control will discourage early emissions reductions. While EPA agrees that flow control may lessen the incentive to make early reductions, the Agency disagrees with the assertion that it removes all incentives for early emissions reductions. Flow control has a limited effect because it does not prohibit a source from banking or selling excess NOX allowances that are the result of emissions reductions or prohibit a source from using the excess NOX allowances. When the 2-for-1 discount rate is triggered, this discourages (but does not bar) excessive use of banked allowances [16] and tends to limit total emissions in any given control period, thereby supporting the goal of achievement of attainment in downwind non-attainment areas by 2007. Furthermore, by not implementing flow control until 2005, flow control will not affect a source's incentive to generate early reduction credits. Allowances from the compliance supplement pool (i.e., early reduction credits) will expire after the end of season reconciliation process in 2004, before flow control may be triggered under final part 97.

The EPA disagrees with the commenters' assertions that flow control will discourage the use of the market and limit sources' flexibility. As discussed above, flow control has limited effects and does not significantly reduce the benefits Start Printed Page 2718associated with banking (i.e., flexibility to sources, stimulation of the market, and incentive to over-comply). Also, as discussed above, it discourages the excessive use of banked allowances and thereby supports achievement of the program's environmental goals. Since the withdrawal ratio is known before the start of the control period, sources will know if and at what level flow control will be applied and can plan their compliance strategies accordingly. The EPA maintains that banking with the finalized flow control mechanism achieves a reasonable balance between, on one hand, flexibility and encouragement of greater reductions than required and, on the other hand, ensuring achievement of the environmental goals of the NOX Budget Trading Program.

When EPA proposed the part 96 NOX Budget Trading Program in 1997, it examined various options for managing banked allowances. These options included placing a limit on the number of allowances a source could bank and using a source-by-source approach to flow control rather than a regionwide approach. The EPA finalized the part 96 and the section 126 action with a regionwide approach to flow control because EPA believed that regionwide flow control best retains the flexibility associated with banking while limiting the potential negative impact on the achievement of air quality goals due to the “excessive use” of allowances in a given control period. (Further discussion of why EPA is choosing to manage banked allowances with a regionwide approach to flow control can be found in the supplemental proposal for the NOX SIP call (63 FR 25935), the final NOX SIP call (63 FR 57473), and in the Response to Comments to the Final NOX SIP call Document (Section IX.E.4)).

By delaying the implementation of flow control under the section 126 control remedy until 2005, EPA is giving sources trading under the Federal NOX Budget Trading Program one year of additional flexibility over sources trading under possible State rules in response to the NOX SIP call. However, the flow control discount ratio only applies to allowances when they are used for compliance purposes. Allowances sold or traded on the allowance market are never subject to a discount ratio. Furthermore, since all sources in both the section 126 region and the wider NOX SIP call region are under a cap that was derived from the same emissions control level assumptions, the transfer of allowances from a source subject to flow control to a source not subject to flow control, or vice versa, does not risk violating the emissions limitations applicable to either region. Therefore, EPA does not believe that the one-year difference between the two trading programs (parts 96 and 97) will interfere with the trading of NOX allowances and sees no need to restrict trading between the two regions as a result of this difference. (For further discussion of trading between the section 126 region and the wider SIP call region see section III.A.4 of this preamble). After 2005, flow control will be consistent between the Federal NOX Budget Trading Program and possible State rules under the NOX SIP call and the model NOX Budget Trading Program rule (part 96). If flow control, which affects compliance, were eliminated entirely sources might have an incentive to shift emissions from the wider NOX SIP region to the section 126 region or vice versa.

6. Emissions Monitoring and Reporting

Today's final rule finalizes monitoring provisions in subpart H of part 97. This subpart references the monitoring and reporting requirements of subpart H of part 75. The provisions of subpart H of part 75 were finalized on October 27, 1998 and revised on May 26, 1999 (See 63 FR 57498-57514 and 64 FR 28624-28630).

In general, EPA has retained essentially the same monitoring provisions in part 97 that it proposed. Sources subject to the Federal NOX Budget Program must comply with the monitoring provisions of part 75 for NOX emissions and heat input rate. These sources include large electric generating units and large industrial boilers or industrial turbines. Internal combustion engines, glass manufacturers, cement kilns, or other NOX emitting sources are not required to comply with the Federal NOX Budget Trading Program and therefore are not required to comply with part 75. However, if a small electric generating unit, a small industrial boiler, or a small industrial turbine chooses to opt-in, it must comply with part 75. Coal-fired units must monitor their NOX mass emissions and heat input using continuous emission monitoring systems (CEMS). Gas-fired and oil-fired units have additional monitoring options, including:

  • Fuel sampling and analysis and fuel usage to determine heat input rate for all gas-fired and oil-fired units (Appendix D of part 75);
  • Unit-specific correlations of NOX and heat input rate, for gas-fired and oil-fired peaking units (Appendix E of part 75); and
  • The less rigorous monitoring procedures in § 75.19, for gas-fired and oil-fired units that emit less than a certain tonnage [17] of SO2 or NOX during a year or ozone season.

In addition, any affected source has the option of petitioning the Administrator under subpart E of part 75 for an alternative to a NOX CEMS. Alternative monitoring systems must be approved by EPA before they may be used to report emission data for compliance. Sources that voluntarily opt-in to the Federal NOX Budget Trading Program must meet part 97 monitoring requirements.

Today's final rule includes some revisions to subpart H of part 97 to be consistent with the May 26, 1999 revisions to part 75. For example, EPA has revised the language of § 97.70(c) to allow for conditional validation of data before certification testing is completed. See 64 FR 28564 and 28575, May 26, 1999. Similarly, § 97.72 is revised to provide that data are considered invalid and must be replaced by substitute data when monitors do not meet quality assurance or data validation requirements for certification, recertification, or quality assurance testing, as set forth in part 75. See 64 FR 28575-28577. By further example, in § 97.71(b)(2), the Agency revised language concerning changes to a monitoring system that require recertification to be consistent with recent changes to § 75.20(b). See 64 FR 28582 and 28594. In addition, EPA revised the deadlines in § 97.74(d)(2) for submission of quarterly reports for units not subject to the Acid Rain Program. The Agency made these revisions to be consistent with changes in § 75.74(c) concerning reporting for the ozone season, instead of the entire year. See 64 FR 28581-28583. Further, throughout subpart H of part 97, the Agency uses the terms “heat input rate” and “stack flow rate” instead of “heat input” or “flow” to clarify the value that monitoring equipment measures on an hourly basis during unit operation and that must be reported for each hour of unit operation. This is consistent with the use of these terms in the revisions to part 75. See 64 FR 28664-28665 and 28668-28671. In order to clarify the distinction between “heat input” and “heat input rate,” the Agency added a definition for “heat input rate” in § 97.2. Further, the “heat input” definition itself is revised to state clearly the units of measure (i.e., time period, mmBtu, Start Printed Page 2719Btu, and lb) used in calculating heat input.

Today's final rule also revises subpart H to reflect the approach that EPA is adopting for allocating NOX allowances. In the final part 97, EPA requires units subject to the Federal NOX Budget Trading Program to monitor and report heat input. This is consistent with EPA's approach in today's final rule of initiating the program through allocations based on heat input for the years 2003 through 2008. The Agency has revised §§ 97.70(a)(2) and 97.76 to reflect that under the Federal NOX Budget Trading Program, the Administrator allocates initially on the basis of heat input for each State. In contrast, under part 96, States allocate allowances and have the option of allocating based on some other approach. As discussed above, EPA plans to propose requirements for monitoring and reporting of output data, either electric generation or thermal output, in time for electric generating units to monitor and report output data by the year 2002. Because the monitoring equipment for output is already installed at the vast majority of units, the Agency anticipates that these future provisions will result in little or no additional cost.

In today's final rule, EPA also adopted some substantive changes from subpart H of part 96 and the October 21, 1998 proposed section 126 rule in order to simplify certain monitoring provisions. For example, the final rule reflects the following changes. First, language is added to § 97.71(b)(3)(iv)(D) to make it clear that the procedures for lost certification apply either to notices of disapproval of certification applications or to notices of disapproval of certification status through audit decertification. Second, the various dates in proposed § 97.71(c) for provisional certification of the low mass emissions excepted methodology under § 75.19 are removed and replaced by a few more general dates. For units that do not have certified monitoring equipment when the NOX authorized account representative submits the certification application for the low mass emissions excepted methodology, the date of provisional certification is the date of the submission of the certification application. For units that already have certified monitoring equipment when the NOX authorized account representative submits the certification application for the low mass emissions excepted methodology, the date of provisional certification is either January 1 of the next calendar year or May 1 of the next control period, depending on whether the source reports on an annual or a control season basis. The schedule of multiple provisional certification dates in the proposal, on one hand, was unnecessarily complicated and, on the other hand, did not cover all possible situations. The multiple dates in the proposed language are unnecessary because a source can provide data back to the beginning of the year or control season to qualify to use the method. Third, the Agency added language to § 97.71(b)(3)(v)(A) referencing the applicable procedures in part 75 concerning missing data for initial certifications or recertifications to replace invalid data. Finally, EPA revised the proposed § 97.74(d) to make it clear that emissions data must be recorded and reported as of the dates specified in the provision and that the references to provisional certification also apply to the low mass emission excepted methodology (under § 97.71(c)), as well as to the procedures for monitoring equipment under § 97.71(b)(3)(iii). Some provisions in the proposal mentioned only the reporting of data, although the data must, of course, be recorded in order to be reported.

In today's final rule, EPA also adopted some minor word changes from subpart H of part 96 and the October 21, 1998 proposed section 126 rule that clarify, but do not alter the substance of, the provisions. First, § 97.70(b) includes minor word changes that restate the compliance deadlines in proposed § 97.70(b) to distinguish more clearly among the deadlines based on whether the unit is under § 97.4(a)(1) or § 97.4(a)(2) (i.e., electric generating unit or non-electric generating unit) and whether the unit reports on an annual or control period basis. The changes also clarify that the deadlines apply to the owners or operators of the units and cover the monitoring requirements in §§ 97.70(a)(1) through (3) and that data must be recorded, reported and quality assured. Second, proposed § 97.70(c)(1) is removed because it essentially duplicates § 97.70(b)(2). Third, in § 97.70, EPA removed references to certain non-NOX Budget units i.e., units on a common stack with NOX Budget units under § 75.72(b)(2)(ii)) and replaces them with a general reference to such non-NOX Budget units. The general reference reiterates the requirement in part 75 that such units meet the same requirements as units with emission limitations (here, NOX Budget units). Fourth, § 97.71(b) introductory text is reordered and revised to make it clear that §§ 97.71(c) and (d) provide additional requirements for units subject to the low mass emission methodology or an alternative monitoring system. Section 97.71(c) and (d) include parallel changes. Finally, a reference to § 75.66 is added to § 97.75(b) to make it clear that the requirements of § 75.66 apply to petitions under part 97.

Under subpart H of part 97, EPA requires sources in the Federal NOX Budget Trading Program to monitor and report their emissions in accordance with relevant portions of part 75. (These provisions also apply to monitoring of emissions from sources under the NOX SIP Call). The EPA promulgated revisions to part 75 that establish NOX mass monitoring requirements and provide greater flexibility to regulated sources. The EPA made these changes in subpart H of part 75 at the same time the Agency finalized the NOX SIP Call on October 27, 1998.

Subpart H of part 97 addresses monitoring and reporting requirements including general requirements, initial certification and recertification procedures, out of control periods, notifications, recordkeeping and reporting, and petitions. The provisions are essentially the same as the monitoring-related provisions in subpart H of part 96, with cross references to the appropriate sections of parts 75 and 97.

Some of the differences between the provisions reflect the fact that administration of the monitoring requirements will be overseen by only EPA under part 97, rather than by both EPA and the permitting authority under part 96. As a result, for example, monitoring certification applications under part 97 will be 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 will process all audit decertifications and all petitions for alternatives to the monitoring requirements.

A number of commenters expressed support for the proposed monitoring requirements in part 75, subpart H. A few commenters agreed that part 75, subpart H should be used as the basis for monitoring requirements for sources participating in the trading program. Commenters agreed that the ability to accurately and consistently account for all emissions should be included as one of the criteria for including sources in the trading program.

However, some commenters raised specific concerns regarding the monitoring requirements as proposed. In particular, these commenters raised concerns about the potential burden of Start Printed Page 2720imposing CEMS requirements on smaller units and suggested alternatives to CEMS for certain sources. One commenter noted that part 75 requirements should not be applied to small EGUs such as pre-1990 peaking combustion turbines and units less than 25 MWe, since this approach would not be cost-effective and would discourage small sources from participating in the trading program. However, this commenter added that the recent revisions to part 75 in subpart H appear to address this concern. Some commenters noted that units that currently do not use CEMS and that will be potentially subject to the trading program should have the option of demonstrating compliance with emission limitations by using non-CEMS methodologies, such as title V monitoring, emission factors, or fuel use data. Another commenter asserted that the permitting authority should have the option of allowing predictive emission monitoring systems in appropriate circumstances. Other commenters reiterated the concerns about part 75 monitoring that they had mentioned in the context of the NOX SIP Call.

The EPA agrees with commenters who stated that it is appropriate to require sources to monitor and report emissions to demonstrate compliance with the requirements of the trading program using the provisions set forth in subpart H of part 75. Electric generating units serving generators of 25 MWe or less are not required to make emission reductions or to participate in the Federal NOX Budget Trading Program. Unless these units voluntarily opt-in to the program, they are not required to monitor emissions under today's final rule. The EPA believes that the most cost-effective units to control are included in the trading program. (See Section IV.C. of the Response to Comments Document for the April 30, 1999 final rulemaking under section 126).

Many of the commenters who expressed concern about the use of CEMS specifically stated their concerns about requiring CEMS on relatively small or infrequently operated units. The EPA believes that this concern is addressed through two provisions in part 75 that allow reduced monitoring for these types of sources. Specifically, there are provisions in § 75.19 and Appendix E of part 75 that allow less expensive monitoring and exceptions to the use of NOX CEMS. Section 75.19 allows gas-fired and oil-fired units that qualify as low-emitters to use emission factors as one option for calculating NOX mass emissions. Appendix D of part 75 allows oil-fired and gas-fired units to measure their fuel usage to determine heat input, rather than installing CEMS for this purpose. Appendix E of part 75 allows infrequently operated oil-fired and gas-fired units to develop a unit-specific correlation of NOX emission rate and heat input rate, rather than installing NOX CEMS to measure NOX emissions. The EPA believes that the monitoring provisions in part 75 are tailored to different types of sources, and give considerable flexibility for smaller sources.

As explained in section VII.D.3. of the preamble to the final NOX SIP Call and in responses in section C.3. of the NOX SIP Call Response to Comment document, EPA does not believe that other options that commenters suggested as alternatives to CEMS adequately quantify NOX mass emissions for ensuring compliance with the trading program. Some of the commenters who were concerned about the use of CEMS suggested no alternative means of determining compliance with a NOX mass emissions limit. For example, some commenters suggested using title V compliance assurance monitoring (CAM) protocols in part 64. However, CAM protocols are intended to verify that a source's emissions stay below a certain rate; they are not intended to accurately measure mass emissions. For this and several other reasons, EPA concluded in the preamble to the CAM regulations that CAM monitoring was not appropriate for use in an emissions trading program (62 FR 54915, 54916, and 54922). The EPA notes that some of the provisions of § 75.19 for low mass emission units are similar to commenters' suggestions for use of emission factors combined with an actual firing rate.

Under subpart E of part 75, a source could use a predictive emission monitoring system (PEMS) if the NOX Authorized Account Representative petitions to use the PEMS and EPA approves the PEMS as meeting the requirements of subpart E. The EPA is currently working together with sources on a long-term project to examine the performance of PEMS compared to CEMS. PEMS is not yet a monitoring method that is generally applicable.

IV. Administrative Requirements

A. Executive Order 12866: Regulatory Planning and Review

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 today's action is a “significant regulatory action.” The adoption of the Federal NOX Budget Trading Program, in lieu of the default remedy contained in the May 25 NFR, raises novel legal and policy issues that are appropriate for OMB consideration.

However, this action will not impose any additional costs or burdens on regulated entities beyond the costs that would have been associated with the requirements imposed by the May 25 NFR. This action is limited to changing the mechanism for making the findings under section 126, staying the affirmative technical determinations based on the 8-hour ozone NAAQS, and replacing the default control requirements for sources with the Federal NOX Budget Trading Program.

Removing the automatic triggering mechanism for making findings and instead making findings based on the 1-hour standard directly through this action simply changes the mechanism for making the section 126 findings. Those section 126 findings would have been made with or without today's action. Nor does this rule change the scope or substance of the findings. With the stay of the NOX SIP call requirement for States to submit SIP revisions by September 30, no States containing sources covered by the section 126 findings had submitted SIP revisions by that date. As a consequence, EPA would not have been able to propose approval of any SIP submissions complying with the NOX SIP call by November 30. Thus, the section 126 findings made in today's rule would have been automatically triggered on November 30 under the May 25 NFR in the absence of today's action.

Today's rule also stays the affirmative technical determinations based on the 8-hour ozone NAAQS. This action stays requirements that would otherwise have Start Printed Page 2721been imposed on sources in seven states and imposes no new requirements with respect to those sources. Finally, while the Federal NOX Budget Trading Program contains new requirements for compliance, the Trading Program replaces the default remedy, which contained less flexible, and hence, more costly, requirements for compliance that otherwise would have applied under the May 25 NFR. Thus, with respect to these provisions as well, today's rule imposes no new additional costs. Because today's action imposes no new compliance burdens beyond what otherwise would have been required under the May 25 NFR, this action will not have an annual effect on the economy of more than $100 million.

For the May 25 NFR, EPA relied for purposes of Executive Order 12866 on analyses prepared for the NOX SIP call (63 FR 57356, October 27, 1998). Today's rule will reduce the costs of the May 25 NFR by narrowing its scope and providing a more flexible compliance regime. Thus, EPA has prepared a RIA summarizing the potential impacts associated with the final section 126 regulations contained in 40 CFR 52.34, as modified by today's action, titled “Regulatory Impact Analysis for the Final Section 126 Petition Rule.” (The EPA is referring here to the full set of requirements under 40 CFR 52.34 as the “final section 126 regulations,” “section 126 regulations,” or “section 126 rule.”) This RIA assesses the costs, benefits, and economic impacts associated with federally-imposed requirements in the final section 126 regulations to reduce NOX emissions from sources contributing to downwind nonattainment of the ozone NAAQS. It takes into account the changes in the NOX emissions inventory made as a result of the inventory correction notices referred to earlier in this notice, the substitution of the Trading Program for the default remedy as well as the narrower geographic scope covered by and fewer sources affected by the section 126 remedy as a result of EPA's stay of the affirmative technical determinations based on the 8-hour NAAQS for ozone.

The RIA for the final section 126 regulations addresses the costs and benefits associated with reducing emissions at sources covered by the petitions submitted to EPA. The RIA concludes that the national annual cost of actions by affected sources to comply with the section 126 rule is approximately $1.0 billion (1990 dollars) and $1.2 billion (1997 dollars). The RIA also concludes that by using EPA's preferred approach to monetizing reductions in PM-related premature mortality—the Value of Statistical Life (VSL) approach—total monetized benefits (from reductions in ozone and PM concentrations) of the final section 126 rule are projected to be around $1.4 billion (1997 dollars). Any comparison of benefits and costs for this rule will provide limited information, given the incomplete estimate of benefits. However, even with the limited set of benefit categories we were able to monetize, monetized net benefits (i.e. monetized benefits net of costs) using EPA's preferred method for valuing avoided incidences of premature mortality are approximately $0.3 billion (1997$).

The adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing discussion within the economic and public policy analysis community within and outside the Administration. In response to the sensitivity on this issue, we provide estimates reflecting two alternative approaches. The first approach—supported by some in the above community and preferred by EPA—uses a Value of a Statistical Life (VSL) approach developed for the Clean Air Act Section 812 benefit-cost studies. This VSL estimate of $5.9 million (1997$) was derived from a set of 26 studies identified by EPA using criteria established in Viscusi (1992), as those most appropriate for environmental policy analysis applications.

An alternative, age-adjusted approach is preferred by some others in the above community both within and outside the Administration. This approach was also developed for the Section 812 studies and addresses concerns with applying the VSL estimate—reflecting a valuation derived mostly from labor market studies involving healthy working-age manual laborers—to PM-related mortality risks that are primarily associated with older populations and those with impaired health status. This alternative approach leads to an estimate of the value of a statistical life year (VSLY), which is derived directly from the VSL estimate. It differs only in incorporating an explicit assumption about the number of life years saved and an implicit assumption that the valuation of each life year is not affected by age. [18] The mean VSLY is $360,000 (1997$); combining this number with a mean life expectancy of 14 years yields an age-adjusted VSL of $3.6 million (1997$).

Both approaches are imperfect, and raise difficult methodological issues which are discussed in depth in the recently published Section 812 Prospective Study, the draft EPA Economic Guidelines, and the peer-review commentaries prepared in support of each of these documents. For example, both methodologies embed assumptions (explicit or implicit) about which there is little or no definitive scientific guidance. In particular, both methods adopt the assumption that the risk versus dollars trade-offs revealed by available labor market studies are applicable to the risk versus dollar trade-offs the general population would make in an air pollution context.

EPA currently prefers the VSL approach because, essentially, the method reflects the direct, application of what EPA considers to be the most reliable estimates for valuation of premature mortality available in the current economic literature. While there are several differences between the labor market studies EPA uses to derive a VSL estimate and the particulate matter air pollution context addressed here, those differences in the affected populations and the nature of the risks imply both upward and downward adjustments. For example, adjusting for age differences may imply the need to adjust the $5.9 million VSL downward as would adjusting for health differences, but the involuntary nature of air pollution-related risks and the lower level of risk-aversion of the manual laborers in the labor market studies may imply the need for upward adjustments. In the absence of a comprehensive and balanced set of adjustment factors, EPA believes it is reasonable to continue to use the $5.9 million value while acknowledging the significant limitations and uncertainties in the available literature. Furthermore, EPA prefers not to draw distinctions in the monetary value assigned to the lives saved even if they differ in age, health status, socioeconomic status, gender or other characteristic of the adult population.

Those who favor the alternative, age-adjusted approach (i.e. the VSLY approach) emphasize that the value of a statistical life is not a single number relevant for all situations. Indeed, the VSL estimate of $5.9 million (1997 dollars) is itself the central tendency of a number of estimates of the VSL for Start Printed Page 2722some rather narrowly defined populations. When there are significant differences between the population affected by a particular health risk and the populations used in the labor market studies—as is the case here—they prefer to adjust the VSL estimate to reflect those differences. While acknowledging that the VSLY approach provides an admittedly crude adjustment (for age though not for other possible differences between the populations), they point out that it has the advantage of yielding an estimate that is not presumptively biased. Proponents of adjusting for age differences using the VSLY approach fully concur that enormous uncertainty remains on both sides of this estimate—upwards as well as downwards—and that the populations differ in ways other than age (and therefore life expectancy). But rather than waiting for all relevant questions to be answered, they prefer a process of refining estimates by incorporating new information and evidence as it becomes available.

Using an alternative, age-adjusted approach to value reductions in premature mortality—the Value of Statistical Life Year (VSLY) approach—total monetized benefits are projected to be around $0.9 billion (1997$). The total monetized net benefits using this approach are approximately $−0.3 billion (1997$). Due to practical analytical limitations, EPA is not able to quantify and/or monetize all potential benefits of the section 126 rule.

The EPA submitted this action to OMB for review. Changes made in response to OMB suggestions or recommendations will be documented in the public record. 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.

B. Regulatory Flexibility Act

The EPA has determined that it is not necessary to prepare a regulatory flexibility analysis in connection with this final rule. The EPA has also determined that this rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

As discussed above in section IV.A., today's action does not create any new requirements that would impose costs beyond those that would have been imposed under the May 25 NFR. Thus, this rule will not have a significant economic impact on a substantial number of small entities.

For the May 25 NFR, EPA prepared a Regulatory Flexibility Analysis, but noted that it would update the analysis upon promulgation of the final Federal NOX Budget Trading Program, which could change the number of small entities affected by the rule. Thus, EPA has updated the RFA to reflect the changes made by today's rule.

For purposes of assessing the impacts of the section 126 regulations at 40 CFR 52.34, as modified by today's rule, on small entities, small entity is defined as: (1) a small business that meets the criteria published in 13 CFR section 121, as shown in the following table:

SIC CodeEconomic activitySize standard in number of employees or millions of dollars
2611Pulp mills750
2821Plastics materials, synthetic resins, and nonvulcanized elastomers750
2869Industrial organic chemicals1,000
2911Petroleum refining1,500
3312Steel works, blast furnaces, and rolling mills1,000
3511Steam, gas, and hydraulic turbines1,000
3519Stationary internal combustion engines1,000
3585Air-conditioning and warm-air heating equipment and commercial and industrial refrigeration equipment750
4911Electric utilities4 million megawatt hrs.
4922Natural gas transmission$5.0
4931Electric and other gas services$5.0
4961Steam and air conditioning supply$9.0

(2) A small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise that is independently-owned and operated and is not dominant in its field.

We have determined that small entities will experience impacts under the section 126 regulations as described below.

The EPA estimates that the total number of small entities in the section 126 region owning one or more sources in the source categories covered by the rule under the now narrower scope of the effective section 126 requirements in 40 CFR 52.34 is approximately 379. The number of entities actually affected by the section 126 rule, presented by source category, is as follows: Electric Generating Units—80 small entities. This represents 45 percent of the potentially affected small entities (i.e., those in the named source categories) in the final section 126 region (179).

Industrial Boilers and/or Combustion Turbines—8 small entities

This represents 4 percent of the potentially affected small entities owning these non-EGU sources in the final section 126 region (200).

The total number of small entities that will be affected by the effective section 126 requirements under 40 CFR 52.34 is therefore 88, or 25 percent of small entities that own sources in the final section 126 region that may be affected by this rule.

The EPA estimates that 16 small entities affected by the effective section 126 requirements under 40 CFR 52.34 have compliance costs of 1 percent or greater of their sales or revenues, and 8 have compliance costs of 3 percent or greater of their sales or revenues.

The EPA has tried to reduce the impact of the section 126 rule on small entities. The EPA has reduced the applicability of regulatory requirements based on several factors including input from the Small Business Regulatory Enforcement Fairness Act panel convened for the proposed section 126 rule (63 FR 56292, October 21, 1998), considerations of overall cost effectiveness, and administrative efficiency. A detailed description of the panel recommendations for reducing the impact of the final rule on small entities Start Printed Page 2723can be found in the Panel report and the Regulatory Flexibility Analysis prepared for the May 25 NFR. The Panel recommended that EPA solicit comment on whether to allow EGUs to obtain a federally-enforceable NOX emission tonnage limit (e.g., 25 tons during the ozone season) and thereby obtain an exemption. Based on comments received, this option is now incorporated in the final 126 regulations. See section III.B.1.c for further discussion. Other recommendations made by the panel were also incorporated into the May 25 NFR (e.g., 25 MWe and 250 mmBtu/hr cut-offs).

C. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, 2 U.S.C. 1532, EPA generally must prepare a written statement, including a cost-benefit analysis, for any proposed or final rules with “Federal mandates” that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any one year. A “Federal mandate” is defined to include a “Federal intergovernmental mandate” and a “Federal private sector mandate” (2 U.S.C. 658(6)). A “Federal intergovernmental mandate,” in turn, is defined to include a regulation that “would impose an enforceable duty upon State, local, or tribal governments,” (2 U.S.C. 658(5)(A)(i)), except for, among other things, a duty that is “a condition of Federal assistance (2 U.S.C. 658(5)(A)(I)). A “Federal private sector mandate” includes a regulation that would impose an enforceable duty upon the private sector,” with certain exceptions (2 U.S.C. 658 (7)(A)).

The EPA has determined that this action does not include a Federal mandate that may result in estimated costs of $100 million or more for either State, local, or tribal governments in the aggregate, or for the private sector. This Federal action does not create any new requirements that would impose costs beyond those that would otherwise be imposed under the May 25 NFR, as discussed above in section IV.A. Accordingly, no additional costs to State, local or tribal governments, or to the private sector, would result from this action.

In the May 25 NFR, EPA relied upon an Unfunded Mandates Analysis prepared for the proposed section 126 rule. The EPA has updated this analysis to account for the now narrower scope of the effective section 126 requirements in 40 CFR 52.34. This “Government Entity Analysis For the Final Section 126 Petitions Under the Clean Air Act Amendments Title I,” is contained in the docket for this action and is summarized below.

This analysis examines the impacts of the section 126 requirements in 40 CFR 52.34 (excluding the stayed affirmative technical determinations based on the 8-hour ozone NAAQS) on both EGUs and non-EGUs that are owned by State, local, and tribal governments, as well as sources owned by private entities. These requirements affect 16 entities that own EGUs, and these EGUs are owned by 1 State and 15 municipalities. These requirements also affect 7 entities that own non-EGUs, and these non-EGUs are owned by 1 State and 5 municipalities. The overall costs are dominated by the 16 affected EGUs and are about $15 million per year. The EPA has not identified any units on Tribal lands that would be subject to the requirements. The cost impacts are only slightly higher than their production share, in comparison to all units in the region.

The EPA has determined that today's action contains no regulatory requirements that might significantly or uniquely affect small governments because today's action imposes no new additional requirements as discussed above. Moreover, the final section 126 requirements contained in 40 CFR 52.34 (the requirements of the May 25 NFR as modified by today's action) also do not significantly or uniquely affect small governments. The regulatory requirements do not distinguish between EGUs based on ownership. Consequently, the final section 126 rule contained in 40 CFR 52.34 has no requirements that uniquely affect small governments that own or operate EGUs within the affected region.

D. Paperwork Reduction Act

In the May 25 NFR, EPA relied upon an Information Collection Request (ICR) prepared for the proposed section 126 rule. For today's rule, EPA has updated the estimates contained in the ICR to account for the now narrower scope of the effective section 126 requirements in 40 CFR 52.34. These estimates of administrative burden costs are contained in the docket for this action and are summarized below.

Respondents/Affected Entities: Large fossil fuel boilers, turbines and combined cycle units that are subject to the current scope of section 126 requirements of 40 CFR 52.34.

Number of Respondents: 1459.

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: 67.

Estimated Annual Cost per Respondent: $7,073.

Estimated Total Annual Hour Burden: 97,500.

Estimated Total Annualized Cost: $10,320,000.

Note that these are average estimates for the first 3 years of the program. The EPA estimates lower costs in the first 2 years of the program because fewer 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 120 hours per source and a cost of $15,785 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 chapter 15.

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

Executive Order 13045 applies to any rule that (1) is determined to be “economically significant” as defined Start Printed Page 2724under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the rule on children, and explain why the regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.

This rule is not subject to Executive Order 13045, because this rule is not “economically significant” as defined under Executive Order 12866 and the Agency does not have reason to believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children.

Nonetheless, we have evaluated the environmental health or safety effects of the affected pollutants on children, and found that there are no effects from changes in ozone and PM levels resulting from applying these regulatory requirements that are particular to children that are not found in other age groups. 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 for the Final NOX SIP call. 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. Although the final section 126 rule is narrower in scope than the NOX SIP call, the NOX SIP call analysis indicates the potential types of effects that children could experience as a result of this rule.

F. Executive Order 12898: Environmental Justice

Executive Order 12898 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 for the Final NOX SIP call. 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. Although the final section 126 rule is narrower in scope than the NOX SIP call, the NOX SIP call analysis indicates the potential types of effects that minority and low-income populations could experience as a result of this rule.

G. Executive Order 13132: Federalism

Executive Order 13132, entitled Federalism (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications. “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.” Under Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed regulation. The EPA also may not issue a regulation that has federalism implications and that preempts State law unless the Agency consults with State and local officials early in the process of developing the proposed regulation.

If EPA complies by consulting, Executive Order 13132 requires EPA to provide to OMB, in a separately identified section of the preamble to the rule, a federalism summary impact statement (FSIS). The FSIS must include a description of the extent of EPA's prior consultation with State and local officials, a summary of the nature of their concerns and the agency's position supporting the need to issue the regulation, and a statement of the extent to which the concerns of State and local officials have been met. Also, when EPA transmits a draft final rule with federalism implications to OMB for review pursuant to Executive Order 12866, EPA must include a certification from the agency's Federalism Official stating that EPA has met the requirements of Executive Order 13132 in a meaningful and timely manner.

This final rule will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. As discussed above, today's rule imposes no new requirements that impose compliance burdens beyond those that would already apply under the May 25 NFR. Thus, the requirements of section 6 of the Executive Order do not apply to this rule. Nevertheless, EPA did consult with State and local officials throughout the section 126 rulemaking. (See 64 FR 28253-28254; 63 FR 57362-57363). Most fundamentally, the section 126 rulemaking is EPA's response to State petitions for EPA action. In addition, States were extensively involved in the Ozone Transport Assessment Group (OTAG), which was established to undertake an assessment of the regional transport problem in the eastern half of the United States and to develop solutions. The OTAG process included representatives of both upwind and downwind States. In the section 126 rulemaking, EPA has acted on section 126 petitions submitted by States that were involved in the OTAG process. All eight submitted petitions rely, in part, on the OTAG analyses for technical justification.

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 Federal government provides the funds necessary to pay the direct compliance costs incurred by the tribal governments, or EPA consults with those governments. If EPA complies by consulting, Executive Order 13084 requires EPA to provide to OMB, 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 Start Printed Page 2725significantly or uniquely affect their communities.”

Today's rule does not significantly or uniquely affect the communities of Indian tribal governments. As discussed above, today's action imposes no new requirements that would impose compliance burdens beyond those that would already apply under the May 25 NFR. Moreover, the final section 126 rule as modified by today's action 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 in 40 CFR 52.34. 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 Transfer and Advancement Act of 1995 (“NTTAA”), Public Law 104-113 section 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 rulemaking would require all sources that participate in the trading program under 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 28116-28117, discussing ASTM D5373-93 “Standard Methods for Instrumental Determination of Carbon, Hydrogen and Nitrogen in laboratory samples of Coal and Coke,” and American Petroleum Institute 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 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 § 75.19.

This rulemaking involves environmental monitoring or measurement. Sources that participate in the trading program are 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 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.

J. Judicial Review

Section 307(b)(1) of the CAA indicates which Federal Courts of Appeal have venue for petitions of review of final actions by EPA. This section provides, in part, that petitions for review must be filed in the Court of Appeals for the District of Columbia Circuit (i) when the agency action consists of “nationally applicable regulations promulgated, or final actions taken, by the Administrator,” or (ii) when such action is locally or regionally applicable, if “such action is based on a determination of nationwide scope or effect and if in taking such action the Administrator finds and publishes that such action is based on such a determination.”

This rulemaking to modify the May 25 NFR on several section 126 petitions is “nationally applicable” within the meaning of section 307(b)(1). At the core of the complete section 126 rulemaking (both the May 25 NFR and today's modification to that rule) is EPA's interpretation of sections 126 and 110(a)(2)(D)(i)(I). The EPA applied these interpretations uniformly to each section 126 petition.[19] Further, the modeling that EPA employed to assist in making the central decisions in the section 126 rulemaking involved uniform modeling techniques and a uniform set of air quality metrics to assess upwind impacts on downwind States. In addition, the cost effectiveness information was analyzed and applied uniformly to each petition. Further, the remedy selected by EPA in the May 25 NFR and modified by today's rule is uniformly applicable to upwind sources in many different States and involves interstate trading of NOX emission allowances. In sum, the numerous legal and technical issues that EPA addressed in the two final rules that comprise the section 126 rulemaking apply uniformly to all the sources in 12 States and the District of Columbia for which EPA is making findings and prescribing a remedy under section 126. Cf. West Virginia Chamber of Commerce v. Browner, 1998 WL 827315, * 7 (4th Cir., Dec. 1, 1998).

For these reasons, the Administrator also is determining that this final action modifying the May 25 NFR regarding the section 126 petitions is of nationwide scope and effect for purposes of section 307(b)(1). This is particularly appropriate because in the report on the 1977 Amendments that revised section 307(b)(1) of the CAA, Congress noted that the Administrator's determination that an action is of “nationwide scope or effect” would be appropriate for any action that has “scope or effect beyond a single judicial circuit.” H.R. Rep. No. 95-294 at 323, 324, reprinted in 1977 U.S.C.C.A.N. 1402-03. Here, the scope and effect of this rulemaking extend to numerous judicial circuits since the downwind petitioning States lie in the First, Start Printed Page 2726Second and Third Circuits of the U.S. Courts of Appeals and the upwind regulated States lie in the Fourth, Sixth, and Seventh Circuits. In these circumstances, section 307(b)(1) and its legislative history calls for the Administrator to find the rule to be of “nationwide scope or effect” and for venue to be in the D.C. Circuit.

Thus, any petitions for review of final actions regarding today's section 126 rule must be filed in the Court of Appeals for the District of Columbia Circuit within 60 days from the date final action is published in the Federal Register.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. The EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. A “major rule” cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2). This action will not impose any additional costs or compliance burdens on regulated entities beyond the costs and compliance burdens that would have been associated with the requirements imposed by the May 25 NFR. This rule will be effective February 17, 2000.

Start List of Subjects

List of Subjects

End List of Subjects Start Signature

Dated: December 17, 1999.

Carol M. Browner,

Administrator.

End Signature Start Amendment Part

For the reasons set forth in the preamble, chapter I of title 40 of the Code of Federal Regulations is amended as follows:

End Amendment Part Start Part

PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

Start Authority

Authority: 42 U.S.C. 7401 et seq.

End Authority

Subpart A—General Provisions

2. Section 52.34 is amended by:

a. Removing paragraph (a)(6);

b. Redesignating paragraphs (a)(7) through (a)(10) as paragraphs (a)(6) through (a)(9), respectively;

c. Revising paragraph (b) introductory text;

d. Revising the heading of paragraph (c);

e. Revising the headings and introductory text of paragraphs (c)(1) and (c)(2);

f. Revising the heading of paragraph (e);

g. Revising the headings and introductory text of paragraphs (e)(1) and (e)(2);

h. Revising the heading of paragraph (g);

i. Revising the headings and introductory text of paragraphs (g)(1) and (g)(2);

j. Revising the heading of paragraph (h);

k. Revising the headings and introductory text of paragraphs (h)(1) and (h)(2); and

l. Revising paragraphs (i), (j), and (k).

The revisions read as follows:

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

(b) Purpose and applicability. Paragraphs (c), (e)(1) and (e)(2), (g), and (h)(1) and (h)(2) of this section set forth the Administrator's findings with respect to the 1-hour national ambient air quality standard (NAAQS) for ozone that certain new and existing sources of emissions of nitrogen oxides (“NOX”) in certain States emit or would emit NOX in violation of the prohibition in section 110(a)(2)(D)(i) of the Clean Air Act (CAA) on emissions in amounts that contribute significantly to nonattainment in certain States that submitted petitions in 1997-1998 addressing such NOX emissions under section 126 of the CAA. Paragraphs (d), (e)(3) and (e)(4), (f), and (h)(3) and (h)(4) of this section set forth the Administrator's affirmative technical determinations with respect to the 8-hour NAAQS for ozone that certain new and existing sources of emissions of NOX in certain States emit or would emit NOX in violation of the prohibition in section 110(a)(2)(D)(i) of the CAA on emissions in amounts that contribute significantly to nonattainment in, or interfere with maintenance by, certain States that submitted petitions in 1997-1998 addressing such NOX emissions under section 126 of the CAA. (As used in this section, the term new source includes modified sources, as well.) Paragraph (i) of this section explains the circumstances under which the findings for sources in a specific State would be withdrawn. Paragraph (j) of this section sets forth the control requirements that apply to the sources of NOX emissions affected by the findings. Paragraph (k) of this section indefinitely stays the effectiveness of the affirmative technical determinations with respect to the 8-hour ozone standard.

* * * * *

(c) Section 126(b) findings relating to impacts on ozone levels in Connecticut—(1) Section 126(b) findings with respect to the 1-hour ozone standard in Connecticut. The Administrator finds that any existing or new major source or group of stationary sources emits or would emit NOX in violation of the Clean Air Act section 110(a)(2)(d)(i) prohibition with respect to the 1-hour ozone standard in the State of Connecticut if it is or will be:

* * * * *

(2) States or portions of States that contain sources for which the Administrator is making section 126(b) findings with respect to the 1-hour ozone standard in Connecticut. The States, or portions of States, that contain sources of NOX emissions for which the Administrator is making section 126(b) findings under paragraph (c)(1) of this section are:

* * * * *

(e) Section 126(b) findings and affirmative technical determinations relating to impacts on ozone levels in Massachusetts—(1) Section 126(b) findings with respect to the 1-hour ozone standard in Massachusetts. The Administrator finds that any existing major source or group of stationary sources emits NOX in violation of the Clean Air Act section 110(a)(2)(d)(i) prohibition with respect to the 1-hour ozone standard in the State of Massachusetts if it is:

* * * * *

(2) States that contain sources for which the Administrator is making Start Printed Page 2727section 126(b) findings with respect to the 1-hour ozone standard in Massachusetts. The portions of States that contain sources of NOX emissions for which the Administrator is making section 126(b) findings under paragraph (e)(1) of this section are:

* * * * *

(g) Section 126(b) findings relating to impacts on ozone levels in the State of New York—(1) Section 126(b) findings with respect to the 1-hour ozone standard in the State of New York. The Administrator finds that any existing or new major source or group of stationary sources emits or would emit NOX in violation of the Clean Air Act section 110(a)(2)(d)(i) prohibition with respect to the 1-hour ozone standard in the State of New York if it is or will be:

* * * * *

(2) States or portions of States that contain sources for which the Administrator is making section 126(b) findings with respect to the 1-hour ozone standard in New York. The States, or portions of States, that contain sources of NOX emissions for which the Administrator is making section 126(b) findings under paragraph (g)(1) of this section are:

* * * * *

(h) Section 126(b) findings and affirmative technical determinations relating to impacts on ozone levels in the State of Pennsylvania—(1) Section 126(b) findings with respect to the 1-hour ozone standard in the State of Pennsylvania. The Administrator finds that any existing or new major source or group of stationary sources emits or would emit NOX in violation of the Clean Air Act section 110(a)(2)(d)(i) prohibition with respect to the 1-hour ozone standard in the State of Pennsylvania if it is or will be:

* * * * *

(2) States that contain sources for which the Administrator is making section 126(b) findings with respect to the 1-hour ozone standard in Pennsylvania. The States that contain sources of NOX emissions for which the Administrator is making section 126(b) findings under paragraph (h)(1) of this section are:

* * * * *

(i) Withdrawal of section 126 findings. Notwithstanding any other provision of this subpart, a finding under paragraphs (c), (e)(1) and (e)(2), (g), and (h)(1) and (h)(2) of this section as to a particular major source or group of stationary sources in a particular State 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 §§ 51.121 and 51.122 of this chapter for such State.

(j) Section 126 control remedy. The Federal NOX Budget Trading Program in part 97 of this chapter applies to the owner or operator of any new or existing large EGU or large non-EGU as to which the Administrator makes a finding under section 126(b) of the Clean Air Act pursuant to the provisions of paragraphs (c), (e)(1) and (e)(2), (g), and (h)(1) and (h)(2) of this section.

(k) Stay of findings with respect to the 8-hour ozone standard. Notwithstanding any other provisions of this subpart, the effectiveness of paragraphs (d), (e)(3) and (e)(4), (f), (h)(3) and (h)(4) of this section is stayed.

* * * * *

3. Part 97 is added to subchapter C to read as follows:

End Part Start Part

PART 97—FEDERAL NOX BUDGET TRADING PROGRAM

Subpart A—NOX Budget Trading Program General Provisions
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 NOX authorized account representative.
97.11
Alternate NOX authorized account representative.
97.12
Changing NOX authorized account representative and alternate NOX authorized account representative; changes in owners and operators.
97.13
Account certificate of representation.
97.14
Objections concerning NOX authorized account representative.
Subpart C—Permits
97.20
General NOX Budget Trading Program 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
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.
97.43
Compliance supplement pool.
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 input data.
Subpart I—Individual Unit Opt-ins
97.80
Applicability.
97.81
General.
97.82
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—Final Section 126 Rule: EGU Allocations, 2003-2007 Appendix B to Part 97—Final Section 126 Rule: Non-EGU Allocations, 2003-2007 Appendix C to Part 97—Final Section 126 Rule: Trading Budget, 2003-2007 Appendix D to Part 97—Final Section 126 Rule: State Compliance Supplement Pools for the Section 126 Final Rule (Tons)
Start Authority

Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.

End Authority

Subpart A—NOX Budget Trading Program General Provisions

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 126 of the CAA and § 52.34 of this chapter, as a means of mitigating the interstate transport of ozone and nitrogen oxides, an ozone precursor.

Start Printed Page 2728
Definitions.

The terms used in this part shall have the meanings set forth in this section as follows:

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 § 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, with regard to NOX allowances, the determination by 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.

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 § 97.4(b), § 97.5, or subpart I of this part, for a unit that is a NOX Budget unit under § 97.4(a) 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 § 97.4(b), § 97.5, or subpart I of this part, for a unit that is not a NOX Budget unit under § 97.4(a) on the date the unit commences commercial operation, the date the unit becomes a NOX Budget unit under § 97.4(a) 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 § 97.4(b), § 97.5, or subpart I of this part for a unit that is a NOX Budget unit under § 97.4(a) 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 § 97.4(b), § 97.5, or subpart I of this part, for a unit that is not a NOX Budget unit under § 97.4(a) on the date of commencement of operation, the date the unit becomes a NOX Budget unit under § 97.4(a) 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 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, to the extent consistent with subpart H of this part and 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);

(4) A continuous moisture monitor; 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.

Electricity for sale under firm contract to the grid means electricity for sale where the capacity involved is intended to be available at all times during the period covered by a guaranteed commitment to deliver, even under adverse conditions.

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) For units that commenced operation before January 1, 1996, the combination 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 1995, or, if a unit had no heat input in 1995, during the last year of operation of the unit prior to 1995;

(2) For units that commenced operation on or after January 1, 1996 and before January 1, 1997, the combination 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 1996; or

(3) For units that commence operation on or after January 1, 1997:

(i) The combination 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; or

(ii) The combination 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 Start Printed Page 2729any 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, with regard to a specified period to time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb 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. Heat input does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.

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 (in mmBtu/hr) 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 (in mmBtu/hr) 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 NOXemission 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 concentration of NOX under 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 (in mmBtu/hr) which is the higher of the manufacturer's 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 NOXemissions limitation means, with regard to a NOX Budget opt-in unit, the lowest NOX emissions limitation (in 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.

NOXallowance means a limited authorization by 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, except as provided under § 97.54(f). No provision of the NOX Budget Trading Program, the NOX Budget permit application, the NOX Budget permit, or an exemption under § 97.4(b) or § 97.5 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization, which does not constitute a property right. For purposes of all sections of this part except § 97.41, § 97.42, § 97.43, or § 97.88, “NOX allowance” also includes an authorization to emit up to one ton of nitrogen oxides during the control period of the specified year or of any year thereafter by the permitting authority or the Administrator in accordance with a State NOX Budget Trading Program established, and approved and administered by the Administrator, pursuant to § 51.121 of this chapter.

NOXallowance deduction or deduct NOXallowances 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 NOX allowance withdrawal requirement under this part.

NOXAllowance Tracking System means the system by which the Administrator records allocations, deductions, and transfers of NOX allowances under the NOX Budget Trading Program.

NOXAllowance 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.

NOXallowance 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 must 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.

NOXallowances held or hold NOXallowances means the NOX allowances recorded by the Administrator, or submitted to the Administrator for recordation, in accordance with Start Printed Page 2730subparts F and G of this part, in a NOX Allowance Tracking System account.

NOXauthorized 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.

NOXBudget emissions limitation means, for a NOX Budget unit, the tonnage equivalent of the NOX allowances available for compliance deduction for the unit under § 97.54(a), (b), (e), and (f) in a control period adjusted by deductions of such NOX allowances to account for actual heat input under § 97.42(e) for the control period or to account for excess emissions for a prior control period under § 97.54(d) or to account for withdrawal from the NOX Budget Trading Program, or for a change in regulatory status, of a NOX Budget opt-in unit under § 97.86 or § 97.87.

NOXBudget opt-in permit means a NOX Budget permit covering a NOX Budget opt-in unit.

NOXBudget opt-in unit 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.

NOXBudget 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.

NOXBudget source means a source that includes one or more NOX Budget units.

NOXBudget Trading Program means a multistate nitrogen oxides air pollution control and emission reduction program established by the Administrator in accordance with this part and pursuant to § 52.34 of this chapter, as a means of mitigating the interstate transport of ozone and nitrogen oxides, an ozone precursor.

NOXBudget unit means a unit that is subject to the NOX Budget Trading Program emissions limitation under § 97.4(a) or § 97.80.

Operating means, with regard to a unit under §§ 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 § 97.83(a). The unit's documented heat input will be determined in accordance with part 75 of this chapter if the unit was otherwise subject to the requirements of part 75 of this chapter during that 6-month period 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 during that 6-month period.

Operator means any person who operates, controls, or supervises a NOX Budget unit, a NOX Budget source, or a unit for which an application for a NOX Budget opt-in permit under § 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 § 97.83 is 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 § 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 § 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 § 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.

Percent monitor data availability means, for purposes of § 97.43 (a)(1) and § 94.84(b), total unit operating hours for which quality-assured data were recorded under subpart H of this part in a control period, divided by 3,672 hours per control period, and multiplied by 100%.

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.

Potential electrical output capacity means 33 percent of a unit's maximum design heat input.

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 § 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.” Start Printed Page 2731

State means one of the 48 contiguous States or a portion thereof or the District of Columbia that is specified in § 52.34 of this chapter and in which are located units for which the Administrator makes an effective finding under § 52.34 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.

Unit means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system.

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.

Measurements, abbreviations, and acronyms.

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

Btu-British thermal unit.

CO2-carbon dioxide.

hr-hour.

kW-kilowatt electrical.

kWh-kilowatt hour.

lb-pounds.

mmBtu-million Btu.

MWe-megawatt electrical.

NOX-nitrogen oxides.

O2-oxygen.

ton-2000 pounds.

Applicability.

(a) The following units in a State (as defined in § 97.2) 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)(i) For units that commenced operation before January 1, 1997, a unit serving during 1995 or 1996 a generator that had a nameplate capacity greater than 25 MWe and produced electricity for sale under a firm contract to the electric grid.

(ii) For units that commenced operation on or after January 1, 1997 and before January 1, 1999, a unit serving during 1997 or 1998 a generator that had a nameplate capacity greater than 25 MWe and produced electricity for sale under a firm contract to the electric grid.

(iii) For units that commence operation on or after January 1, 1999, a unit serving at any time a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

(2)(i) For units that commenced operation before January 1, 1997, a unit that has a maximum design heat input greater than 250 mmBtu/hr and that did not serve during 1995 or 1996 a generator producing electricity for sale under a firm contract to the electric grid.

(ii) For units that commenced operation on or after January 1, 1997 and before January 1, 1999, a unit that has a maximum design heat input greater than 250 mmBtu/hr and that did not serve during 1997 or 1998 a generator producing electricity for sale under a firm contract to the electric grid.

(iii) For units that commence operation on or after January 1, 1999, a unit with a maximum design heat input greater than 250 mmBtu/hr that:

(A) At no time serves a generator producing electricity for sale; or

(B) At any time serves a generator producing electricity for sale, if any such generator has a nameplate capacity of 25 MWe or less and has the potential to use no more than 50 percent of the potential electrical output capacity of the unit.

(b)(1) 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 and that includes the special provisions in paragraph (b)(4) of this section shall be exempt from the requirements of the NOX Budget Trading Program, except for the provisions of this paragraph (b), § 97.2, § 97.3, § 97.4(a), § 97.7, and subparts E, F, and G of this part. The NOX emission limitation under this paragraph (b)(1) shall restrict NOX emissions during the control period by limiting unit operating hours. The restriction on unit operating hours shall be calculated by dividing 25 tons by the unit's maximum potential hourly NOX mass emissions, which shall equal the unit's maximum rated hourly heat input multiplied by the highest default NOX emission rate otherwise applicable to the unit under § 75.19 of this chapter.

(2) The exemption under paragraph (b)(1) of this section shall become effective as follows:

(i) The exemption shall become effective on the date on which the NOX emission limitation and the special provisions in the permit under paragraph (b)(1) of this section become final; or

(ii) If the NOX emission limitation and the special provisions in the permit under paragraph (b)(1) of this section become final during a control period and after the first date on which the unit operates during such control period, then the exemption shall become effective on May 1 of such control period, provided that such NOX emission limitation and the special provisions apply to the unit as of such first date of operation. If such NOX emission limitation and special provisions do not apply to the unit as of such first date of operation, then the exemption under paragraph (b)(1) of this section shall become effective on October 1 of the year during which such NOX emission limitation and the special provisions become final.

(3) The permitting authority that issues a federally enforceable permit under paragraph (b)(1) of this section for a unit under paragraph (a)(1) or (a)(2) of this section will provide the Administrator written notice of the issuance of such permit and, upon request, a copy of the permit.

(4) Special provisions. (i) A unit exempt under paragraph (b)(1) of this section shall comply with the restriction on unit operating hours described in paragraph (b)(1) of this section during the control period in each year.

(ii) The Administrator will allocate NOX allowances to the unit under §§ 97.41(a) through (c) and 97.42(a) through (c). For each control period for which the unit is allocated NOX allowances under §§ 97.41(a) through (c) and 97.42(a) through (c):

(A) The owners and operators of the unit must specify a general account, in which the Administrator will record the NOX allowances; and

(B) After the Administrator records a NOX allowance allocations under §§ 97.41(a) through (c) and 97.42(a) Start Printed Page 2732through (c), the Administrator will deduct, from the general account under paragraph (b)(4)(ii)(A) of this section, NOX allowances that are allocated for the same or a prior control period as the NOX allowances allocated to the unit under §§ 97.41(a) through (c) and 97.42(a) through (c) and that equal the NOX emission limitation (in tons of NOX) on which the unit's exemption under paragraph (b)(1) of this section is based. The NOX authorized account representative shall ensure that such general account contains the NOX allowances necessary for completion of such deduction.

(iii) A unit exempt under this paragraph (b) shall report hours of unit operation during the control period in each year to the permitting authority by November 1 of that year.

(iv) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (b)(1) of this section shall retain, at the source that includes the unit, records demonstrating that the conditions of the federally enforceable permit under paragraph (b)(1) of this section were met, including the restriction on unit operating hours. 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 met the restriction on unit operating hours.

(v) The owners and operators and, to the extent applicable, the NOX authorized account representative of a unit exempt under paragraph (b)(1) of 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.

(vi) On the earlier of the following dates, a unit exempt under paragraph (b)(1) of this section shall lose its exemption:

(A) The date on which the restriction on unit operating hours described in paragraph (b)(1) of this section is removed from the unit's federally enforceable permit or otherwise becomes no longer applicable to any control period starting in 2003; or

(B) The first date on which the unit fails to comply, or with regard to which the owners and operators fail to meet their burden of proving that the unit is complying, with the restriction on unit operating hours described in paragraph (b)(1) of this section during any control period starting in 2003.

(vii) A unit that loses its exemption in accordance with paragraph (b)(4)(vi) of this section shall be subject to the requirements of this part. For the purpose of applying permitting requirements under subpart C of this part, allocating allowances under subpart E of this part, and applying monitoring requirements under subpart H of this part, the unit shall be treated as commencing operation and, if the unit is covered by paragraph (a)(1) of this section, commencing commercial operation on the date the unit loses its exemption.

(viii) A unit that is exempt under paragraph (b)(1) of this section is not eligible to be a NOX Budget opt-in unit under subpart I of this part.

Retired unit exemption.

(a) This section applies to any NOX Budget unit, other than a NOX Budget opt-in unit, that is permanently retired.

(b)(1) Any NOX Budget unit, other than a NOX Budget opt-in unit, that is permanently retired shall be exempt from the NOX Budget Trading Program, except for the provisions of this section, § 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. The NOX authorized account representative shall submit a copy of the statement 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.

(2) The Administrator will allocate NOX allowances under subpart E of this part to a unit exempt under this section. For each control period for which the unit is allocated one or more NOX allowances, the owners and operators of the unit shall specify a general account, in which the Administrator will record such NOX allowances.

(3) 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.

(4) 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.

(5)(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 § 97.22 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of May 1, 2003 or the date on which the unit resumes 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 § 97.22 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of May 1, 2003 or the date on which the unit is to first resume operation.

(6) On the earlier of the following dates, a unit exempt under paragraph (b) of this section shall lose its exemption:

(i) The date on which the NOX authorized account representative submits a NOX Budget permit application under paragraph (c)(5) of this section; or

(ii) The date on which the NOX authorized account representative is required under paragraph (c)(5) of this section to submit a NOX Budget permit application.

(7) For the purpose of applying monitoring requirements under subpart H of this part, a unit that loses its Start Printed Page 2733exemption 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.

(8) A unit that is exempt under this section is not eligible to be a NOX Budget opt-in unit under subpart I of this part.

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 § 97.22 in accordance with the deadlines specified in § 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 § 97.54(a), (b), (e), or (f) 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 heat input under § 97.42(e) for the control period or to account for excess emissions for a prior control period under § 97.54(d) or to account for withdrawal from the NOX Budget Trading Program, or a change in regulatory status, of a NOX Budget opt-in unit under § 97.86 or § 97.87.

(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 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 § 97.4(b) or § 97.5 and no provision of law shall be construed to limit the authority of the United States 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 or G 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 incorporated automatically in any NOX Budget permit of the NOX Budget unit.

(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 § 97.54(d)(1); and

(ii) Pay any fine, penalty, or assessment or comply with any other remedy imposed under § 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 under § 97.13 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; 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 under § 97.13 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 subpart 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 § 97.4(b) or § 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 Start Printed Page 2734to 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 or 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 or 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 § 97.4(b) or § 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.

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

Authorization and responsibilities of NOX authorized account representative.

(a) Except as provided under § 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 § 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 § 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.

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 § 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 §§ 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.

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

(a) Changing NOXauthorized 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 § 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 Start Printed Page 2735Administrator 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 alternate NOXauthorized 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 § 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 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 under § 97.13, 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 under § 97.13 amending the list of owners and operators to include the change.

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.

Objections concerning NOX authorized account representative.

(a) Once a complete account certificate of representation under § 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 § 97.13 is received by the Administrator.

(b) Except as provided in § 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

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 for the federally enforceable permit.

(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.

(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.

(b) Each NOX Budget permit 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.

Submission of 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 § 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 § 97.4(a) that Start Printed Page 2736commence operation before January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under § 97.22 covering such NOX Budget units to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) before May 1, 2003.

(ii) For any source, with any NOX Budget unit under § 97.4(a) that commences operation on or after January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under § 97.22 covering such NOX Budget unit to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) 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 § 97.4(a) that commence operation before January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under § 97.22 covering such NOX Budget units to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) before May 1, 2003.

(ii) For any source, with any NOX Budget unit under § 97.4(a) that commences operation on or after January 1, 2000, the NOX authorized account representative shall submit a complete NOX Budget permit application under § 97.22 covering such NOX Budget unit to the permitting authority at least 18 months (or such lesser time provided by the permitting authority) 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 § 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 § 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.

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 § 97.4(a) or under subpart I of this part;

(c) The standard requirements under § 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(a) and is not covered by an exemption under 40 CFR 97.4(b) or 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 of 40 CFR part 97 is operating, as that term is defined under 40 CFR 97.2.”

NOX Budget permit contents.

(a) Each NOX Budget permit will contain, in a format prescribed by the permitting authority, all elements required for a complete NOX Budget permit application under § 97.22.

(b) Each NOX Budget permit is deemed to incorporate automatically the definitions of terms under § 97.2 and, upon recordation by the Administrator under subpart F or G 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.

NOX Budget permit revisions.

(a) For a NOX Budget source with a title V operating permit, except as provided in § 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 § 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

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 § 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 § 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 Start Printed Page 2737monitoring 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 have 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, have 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.

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

Trading program budget.

In accordance with §§ 97.41 and 97.42, the Administrator will allocate to the NOX Budget units under § 97.4(a) in a State, for each control period specified in § 97.41, a total number of NOX allowances equal to the trading program budget for the State, as set forth in appendix C of this part, less the sum of the NOX emission limitations (in tons) for each unit exempt under § 97.4(b) that is not allocated any NOX allowances under § 97.42 (b) or (c) for the control period and whose NOX emission limitation (in tons of NOX) is not included in the amount calculated under § 97.42(d)(5)(ii)(B) for the control period.

Timing requirements for NOX allowance allocations.

(a) The NOX allowance allocations, determined in accordance with §§ 97.42(a) through (c), for the control periods in 2003 through 2007 are set forth in appendices A and B of this part.

(b) By April 1, 2005, the Administrator will determine by order the NOX allowance allocations, in accordance with §§ 97.42 (a) through (c), for the control periods in 2008 through 2012.

(c) By April 1, 2010, by April 1 of 2015, and thereafter by April 1 of the year that is 5 years after the last year for which NOX allowances allocations are determined, the Administrator will determine by order the NOX allowance allocations, in accordance with §§ 97.42(a) through (c), for the control periods in the years that are 3, 4, 5, 6, and 7 years after the applicable deadline under this paragraph (c).

(d) By April 1, 2003 and April 1 of each year thereafter, the Administrator will determine by order the NOX allowance allocations, in accordance with § 97.42(d), for the control period in the year of the applicable deadline under this paragraph (d).

(e) The Administrator will make available to the public each determination of NOX allowance allocations under paragraph (b), (c), or (d) of this section and will provide an opportunity for submission of objections to the determination. Objections shall be limited to addressing whether the determination is in accordance with § 97.42. Based on any such objections, the Administrator will adjust each determination to the extent necessary to ensure that it is in accordance with § 97.42.

NOX allowance allocations.

(a)(1) The heat input (in mmBtu) used for calculating NOX allowance allocations for each NOX Budget unit under § 97.4(a) will be:

(i) For a NOX allowance allocation under § 97.41(a):

(A) For a unit under § 97.4(a)(1), the average of the two highest amounts of the unit's heat input for the control periods in 1995 through 1998; or

(B) For a unit under § 97.4(a)(2), the control period in 1995 or, if the Administrator determines that reasonably reliable data are available for control periods in 1996 through 1998, the average of the two highest amounts of the unit's heat input for the control periods in 1995 through 1998.

(ii) For a NOX allowance allocation under § 97.41(b), the unit's average heat input for the control periods in 2002 through 2004.

(iii) For a NOX allowance allocation under § 97.41(c), the unit's average heat input for the control period in the years that are 4, 5, 6, 7, and 8 years before the first year for which the allocation is being calculated.

(2) The unit's 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. Notwithstanding the first sentence of this paragraph (a)(2):

(i) For a NOX allowance allocation under § 97.41(a), such heat input will be determined using 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 control period.

(ii) For a NOX allowance allocation under § 97.41(b) or (c) for a unit exempt under § 97.4(b), such heat input shall be treated as zero if the unit is exempt under § 97.4(b) during the control period.

(b) For each group of five control periods specified in § 97.41(a) through (c), the Administrator will allocate to all NOX Budget units in a given State under § 97.4(a)(1) that commenced operation before May 1, 1997 for allocations under § 97.41(a), May 1, 2003 for allocations under § 97.41(b), and May 1 of the year 5 years before the first year for which the allocation under § 97.41(c) is being calculated, a total number of NOX allowances equal to 95 percent of the portion of the State's trading program budget under § 97.40 covering such units. The Administrator will allocate in accordance with the following procedures:

(1) The Administrator will allocate NOX allowances to each NOX Budget unit under § 97.4(a)(1) for each control period in an amount equaling 0.15 lb/mmBtu multiplied by the heat input determined under paragraph (a) of this section, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate.

(2) If the initial total number of NOX allowances allocated to all NOX Budget units under § 97.4(a)(1) in the State for a control period under paragraph (b)(1) of this section does not equal 95 percent of the portion of the State's trading program budget under § 97.40 covering Start Printed Page 2738such units, 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 of such portion of the State's trading program budget. This adjustment will be made by: multiplying each unit's allocation by 95 percent of such portion of the State's trading program budget; dividing by the total number of NOX allowances allocated under paragraph (b)(1) of this section for the control period; and rounding to the nearest whole number of NOX allowances as appropriate.

(c) For each group of five control periods specified in § 97.41(a) through (c), the Administrator will allocate to all NOX Budget units in a given State under § 97.4(a)(2) that commenced operation before May 1, 1997 for allocations under § 97.41(a), May 1, 2003 for allocations under § 97.41(b), and May 1 of the year 5 years before the first year for which the allocation under § 97.41(c) is being calculated, a total number of NOX allowances equal to 95 percent of the portion of the State's trading program budget under § 97.40 covering such units. The Administrator will allocate in accordance with the following procedures:

(1) The Administrator will allocate NOX allowances to each NOX Budget unit under § 97.4(a)(2) for each control period in an amount equaling 0.17 lb/mmBtu multiplied by the heat input determined under paragraph (a) of this section, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate.

(2) If the initial total number of NOX allowances allocated to all NOX Budget units under § 97.4(a)(2) in the State for a control period under paragraph (c)(1) of this section does not equal 95 percent of the portion of the State's trading program budget under § 97.40 covering such units, 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 of the portion of the State's trading program budget under § 97.40 covering such units. This adjustment will be made by: multiplying each unit's allocation by 95 percent of the portion of the State's trading program budget under § 97.40 covering such units; dividing by the total number of NOX allowances allocated under paragraph (c)(1) of this section for the control period; and rounding to the nearest whole number of NOX allowances as appropriate.

(d) For each control period specified in § 97.41(d), the Administrator will allocate NOX allowances to NOX Budget units in a given State under § 97.4(a) (except for units exempt under § 97.4(b)) that commence operation, or are projected to commence operation, on or after: May 1, 1997 (for control periods under § 97.41(a)); May 1, 2003, (for control periods under § 97.41(b)); and May 1 of the year 5 years before the beginning of the group of 5 years that includes the control period (for control periods under § 97.41(c)). The Administrator will make the allocations under this paragraph (d) 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 of the tons of NOX emission in the State's trading program budget under § 97.40, rounded to the nearest whole number of NOX allowances as appropriate.

(2) The NOX authorized account representative of a NOX Budget unit specified in this paragraph (d) may submit to the Administrator a request, in a format specified by the Administrator, to be allocated NOX allowances for the control period. The NOX allowance allocation request must be received by the Administrator on or after the date on which the State permitting authority issues a permit to construct the unit and by January 1 before the control period for which NOX allowances are requested.

(3) In a NOX allowance allocation request under paragraph (d)(2) of this section, the NOX authorized account representative for a NOX Budget unit under § 97.4(a)(1) may request for the control period NOX allowances in an amount that does not exceed the lesser of:

(i) 0.15 lb/mmBtu multiplied by the unit's maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate; or

(ii) The unit's most stringent State or Federal NOX emission limitation multiplied by the unit's maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate.

(4) In a NOX allowance allocation request under paragraph (d)(2) of this section, the NOX authorized account representative for a NOX Budget unit under § 97.4(a)(2) may request for a control period NOX allowances in an amount that does not exceed the lesser of:

(i) 0.17 lb/mmBtu multiplied by the unit's maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate; or

(ii) The unit's most stringent State or Federal NOX emission limitation multiplied by the unit's maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate.

(5) The Administrator will review each NOX allowance allocation request submitted in accordance with paragraph (d)(2) of this section and will allocate NOX allowances pursuant to such request as follows:

(i) Upon receipt of the NOX allowance allocation request, the Administrator will make any necessary adjustments to the request to ensure that the requirements of paragraphs (d) introductory text, (d)(2), (d)(3), and (d)(4) are met.

(ii) The Administrator will determine the following amounts:

(A) The sum of the NOX allowances requested (as adjusted under paragraph (d)(5)(i) of this section) in all NOX allowance allocation requests under paragraph (d)(2) of this section for the control period; and

(B) For units exempt under § 97.4(b) in the State that commenced operation, or are projected to commence operation, on or after May 1, 1997 (for control periods under § 97.41(a)); May 1, 2003, (for control periods under § 97.41(b)); and May 1 of the year 5 years before beginning of the group of 5 years that includes the control period (for control periods under § 97.41(c)), the sum of the NOX emission limitations (in tons of NOX) on which each unit's exemption under § 97.4(b) is based.

(iii) If the number of NOX allowances in the allocation set-aside for the control Start Printed Page 2739period less the amount under paragraph (d)(5)(ii)(B) of this section is not less than the amount determined under paragraph (d)(5)(ii)(A) of this section, 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 for which the allocation request was submitted.

(iv) If the number of NOX allowances in the allocation set-aside for the control period less the amount under paragraph (d)(5)(ii)(B) of this section is less than the amount determined under paragraph (d)(5)(ii)(A) of this section, the Administrator will allocate, to the NOX Budget unit for which the allocation request was submitted, the amount of NOX allowances requested (as adjusted under paragraph (d)(5)(i) of this section) multiplied by the number of NOX allowances in the allocation set-aside for the control period less the amount determined under paragraph (d)(5)(ii)(B) of this section, divided by the amount determined under paragraph (d)(5)(ii)(A) of this section, and rounded to the nearest whole number of NOX allowances as appropriate.

(e)(1) 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 § 97.54(b), (e), or (f) to account for the actual heat input 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 heat input using the following formulas and rounding to the nearest whole number of 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 heat input for a unit under § 97.4(a)(1) = Unit's NOX allowances allocated for control period−(Unit's actual control period heat input×0.15 lb/mmBtu × 2,000 lb/ton); and NOX allowances deducted for actual heat input for a unit under § 97.4(a)(2) = Unit's NOX allowances allocated for control period−(Unit's actual control period heat input × 0.17 lb/mmBtu × 2,000 lb/ton)

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 heat input” is the heat input (in mmBtu) of the unit during the control period.

(2) The Administrator will transfer any NOX allowances deducted under paragraph (c)(1) of this section to the allocation set-aside for the control period for which they were allocated.

(f) After making the deductions for compliance under § 97.54(b), (e), or (f) 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 number of NOX allowances as appropriate:

Unit's share of NOX allowances remaining in allocation set-aside = Total NOX allowances remaining in allocation set-aside × (Unit's NOX allowance allocation ÷ State's 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;

“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

“State's trading program budget excluding allocation set-aside” is the State's trading program budget under § 97.40 for the control period to which the allocation set-aside applies multiplied by 95 percent, rounded to the nearest whole number of NOX allowances as appropriate.

(g) If the Administrator determines that NOX allowances were allocated under paragraph (b), (c), or (d) of this section for a control period and the recipient of the allocation is not actually a NOX Budget unit under § 97.4(a), the Administrator will notify the NOX authorized account representative and then will act in accordance with the following procedures:

(1)(i) The Administrator will not record such NOX allowances for the control period in an account under § 97.53;

(ii) If the Administrator already recorded such NOX allowances for the control period in an account under § 97.53 and if the Administrator makes such determination before making all deductions pursuant to § 97.54 (except deductions pursuant to § 97.54(d)(2)) for the control period, then the Administrator will deduct from the account NOX allowances equal in number to and allocated for the same or a prior control period as the NOX allowances allocated to such recipient for the control period. The NOX authorized account representative shall ensure that the account contains the NOX allowances necessary for completion of such deduction. If account does not contain the necessary 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 the account; or

(iii) If the Administrator already recorded such NOX allowances for the control period in an account under § 97.53 and if the Administrator makes such determination after making all deductions pursuant to § 97.54 (except deductions pursuant to § 97.54(d)(2)) for the control period, then the Administrator will apply paragraph (g)(1)(ii) of this section to any subsequent control period for which NOX allowances were allocated to such recipient.

(2) The Administrator will transfer the NOX allowances that are not recorded, or that are deducted, pursuant to paragraph (g)(1) of this section to an allocation set-aside for the State in which such source is located.

Compliance Supplement Pool.

(a) For any NOX Budget unit that reduces its NOX emission rate in the 2001 or 2002 control period, the owners and operators may request early reduction credits in accordance with the following requirements:

(1) Each NOX Budget unit for which the owners and operators intend to request, or request, any early reduction credits in accordance with paragraph (a)(4) of this section shall monitor and report 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 percent monitor data availability shall not be less than 90 percent during the 2000 control period, and the unit must be in full compliance with any applicable State or Federal NOX emission control requirements during 2000 through 2002.

(2) NOX emission rate and heat input under paragraphs (a)(3) and (4) of this section shall be determined in accordance with subpart H of this part.

(3) Each NOX Budget unit for which the owners and operators intend to request, or request, any early reduction credits under paragraph (a)(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. Start Printed Page 2740

(4) The NOX authorized account representative of a NOX Budget unit that meets the requirements of paragraphs (a) (1) and (3) of this section may submit to the Administrator 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.

(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 whole number of tons.

(ii) The early reduction credit request must be submitted, in a format specified by the Administrator, by February 1, 2003.

(b) For any NOX Budget unit that is subject to the Ozone Transport Commission NOX Budget Program under title I of the Clean Air Act, the owners and operators may request early reduction credits in accordance with the following requirements:

(1) The NOX authorized account representative of the unit may submit to the Administrator a request for early reduction credits in an amount equal to the amount of banked allowances under the Ozone Transport Commission NOX Budget Program that were allocated for the control period in 2001 or 2002 and are held by the unit, in accordance with the Ozone Transport Commission NOX Budget Program, as of the date of submission of the request. During the entire control period in 2001 or 2002 for which the allowances were allocated, the unit must have monitored and reported NOX emissions in accordance with part 75 (except for subpart H) of this chapter and the Guidance for Implementation of Emission Monitoring Requirements for the NOX Budget Program (January 28, 1997).

(2) The early reduction credit request under paragraph (b)(1) must be submitted, in a format specified by the Administrator, by February 1, 2003.

(3) The NOX authorized account representative of the unit shall not submit a request for early reduction credits under paragraph (b)(1) of this section for banked allowances under the Ozone Transport Commission NOX Budget Program that were allocated for any control period during which the unit made NOX emission reductions for which he or she submits a request for early reduction credits under paragraph (a) of this section for the unit.

(c) The Administrator will review each early reduction credit request submitted in accordance with paragraph (a) or (b) of this section and will allocate NOX allowances to NOX Budget units in a given State and covered by such request as follows:

(1) Upon receipt of each early reduction credit request, the Administrator will make any necessary adjustments to the request to ensure that the amount of the early reduction credits requested meets the requirements of paragraph (a) or (b) of this section.

(2) After February 1, 2003, the Administrator will make available to the public a statement of the total number of early reduction credits requested by NOX Budget units in the State.

(3) If the State's compliance supplement pool set forth in appendix D of this part has a number of NOX allowances not less than the amount of early reduction credits in all early reduction credit requests under paragraph (a) or (b) of this section for 2001 and 2002 (as adjusted under paragraph (c)(1) of this section) submitted by February 1, 2003, the Administrator will allocate to each NOX Budget unit covered by such requests one allowance for each early reduction credit requested (as adjusted under paragraph (c)(1) of this section).

(4) If the State's compliance supplement pool set forth in appendix D of this part has a smaller number of NOX allowances than the amount of early reduction credits in all early reduction credit requests under paragraph (a) or (b) of this section for 2001 and 2002 (as adjusted under paragraph (c)(1) of this section) submitted by February 1, 2003, the Administrator will allocate NOX allowances to each NOX Budget unit covered by such requests according to the following formula and rounding to the nearest whole number of NOX allowances as appropriate:

Unit's allocation for early reduction credits = Unit's adjusted early reduction credits × (State's compliance supplement pool ÷ Total adjusted early reduction credits for all units)

Where:

“Unit's allocation for early reduction credits” is the number of NOX allowances allocated to the unit for early reduction credits.

“Unit's adjusted early reduction credits” is the amount of early reduction credits requested for the unit for 2001 and 2002 in early reduction credit requests under paragraph (a) or (b) of this section, as adjusted under paragraph (c)(1) of this section.

“State's compliance supplement pool” is the number of NOX allowances in the State's compliance supplement pool set forth in appendix D of this part.

“Total adjusted early reduction credits for all units” is the amount of early reduction credits requested for all units for 2001 and 2002 in early reduction credit requests under paragraph (a) or (b) of this section, as adjusted under paragraph (c)(1) of this section.

(5) By April 1, 2003, the Administrator will determine by order the allocations under paragraph (c)(3) or (4) of this section. The Administrator will make available to the public each determination of NOX allowance allocations and will provide an opportunity for submission of objections to the determination. Objections shall be limited to addressing whether the determination is in accordance with paragraph (c)(1), (3), or (4) of this section. Based on any such objections, the Administrator will adjust each determination to the extent necessary to ensure that it is in accordance with paragraph (c)(1), (3), or (4) of this section.

(6) By May 1, 2003, the Administrator will record the allocations under paragraph (c)(3) or (4) of this section.

(7) NOX allowances recorded under paragraph (c)(6) of this section may be deducted for compliance under § 97.54 for the control period in 2003 or 2004. Notwithstanding § 97.55(a), the Administrator will deduct as retired any NOX allowance that is recorded under paragraph (c)(6) of this section and that is not deducted for compliance under § 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 §§ 97.54(f) and 97.55(b).

Subpart F—NOX Allowance Tracking System

NOX Allowance Tracking System accounts.

(a) Nature and function of compliance accounts and overdraft accounts. Consistent with § 97.51(a), the Administrator will establish one compliance account for each NOX Budget unit and one overdraft account for each source with two or more NOX Budget units. Allocations of NOX allowances pursuant to subpart E of this part or § 97.88, and deductions or transfers of NOX allowances pursuant to § 97.31, § 96.54, § 96.56, subpart G of this part, or subpart I of this part will be recorded in compliance accounts or overdraft accounts in accordance with this subpart. Start Printed Page 2741

(b) Nature and function of general accounts. Consistent with § 97.51(b), the Administrator will establish, upon request, a general account for any person. Allocations of NOX allowances pursuant to § 97.4(b)(4)(ii) or § 97.5(c)(2) and transfers of allowances pursuant to subpart G of this part will be recorded in general accounts in accordance with this subpart.

Establishment of accounts.

(a) Compliance accounts and overdraft accounts. Upon receipt of a complete account certificate of representation under § 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) Application for general account. (i) Any person may apply to open a general account for the purpose of holding and transferring allowances. 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. 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:

(A) 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;

(B) At the option of the NOX authorized account representative, organization name and type of organization;

(C) 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;

(D) 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.;”

(E) The signature of the NOX authorized account representative and any alternate NOX authorized account representative and the dates signed.

(ii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account 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) Authorization of NOXauthorized account representative. 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) 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.

(iv) 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.”

(v) 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)(iv) of this section.

(3) Changing NOXauthorized account representative and alternate NOXauthorized account representative; changes in persons with ownership interest. (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 NOX 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, Start Printed Page 2742actions, 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 NOX 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.

(4) Objections concerning NOXauthorized account representative. (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)(3)(i) or (ii) 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.

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.

Recordation of NOX allowance allocations.

(a) The Administrator will record the NOX allowances for 2003 for a NOX Budget unit allocated under subpart E of this part in the unit's compliance account, except for NOX allowances under § 97.4(b)(4)(ii) or § 97.5(c)(2), which will be recorded in the general account specified by the owners and operators of the unit. The Administrator will record NOX allowances for 2003 for a NOX Budget opt-in unit in the unit's compliance account as allocated under § 97.88(a).

(b) By May 1, 2001, the Administrator will record the NOX allowances for 2004 for a NOX Budget unit allocated under subpart E of this part in the unit's compliance account, except for NOX allowances under § 97.4(b)(4)(ii) or § 97.5(c)(2), which will be recorded in the general account specified by the owners and operators of the unit. The Administrator will record NOX allowances for 2004 for a NOX Budget opt-in unit in the unit's compliance account as allocated under § 97.88(a).

(c) By May 1, 2002, the Administrator will record the NOX allowances for 2005 for a NOX Budget unit allocated under subpart E of this part in the unit's compliance account, except for NOX allowances under § 97.4(b)(4)(ii) or § 97.5(c)(2), which will be recorded in the general account specified by the owners and operators of the unit. The Administrator will record NOX allowances for 2005 for a NOX Budget opt-in unit in the unit's compliance account as allocated under § 97.88(a).

(d) By May 1, 2003, the Administrator will record the NOX allowances for 2006 for a NOX Budget unit allocated under subpart E of this part in the unit's compliance account, except for NOX allowances under § 97.4(b)(4)(ii) or § 97.5(c)(2), which will be recorded in the general account specified by the owners and operators of the unit. The Administrator will record NOX allowances for 2006 for a NOX Budget opt-in unit in the unit's compliance account as allocated under § 97.88(a).

(e) Each year starting with 2004, after the Administrator has made all deductions from a NOX Budget unit's compliance account and the overdraft account pursuant to § 97.54 (except deductions pursuant to § 97.54(d)(2)), the Administrator will record:

(1) NOX allowances, in the compliance account, as allocated to the unit under subpart E of this part for the third year after the year of the control period for which such deductions were or could have been made;

(2) NOX allowances, in the general account specified by the owners and operators of the unit, as allocated under § 97.4(b)(4)(ii) or § 97.5(c)(2) for the third year after the year of the control period for which such deductions are or could have been made; and

(3) NOX allowances, in the compliance account, as allocated to the unit under § 97.88(a).

(f) Serial numbers for allocated NOXallowances. When allocating NOX allowances to a NOX Budget unit 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.

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 Start Printed Page 2743overdraft account by a NOX allowance transfer correctly submitted for recordation under § 97.60 by the NOX allowance transfer deadline for that control period.

(b) Deductions for compliance. (1) Following the recordation, in accordance with § 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 heat input under § 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 account number and end with the unit having the compliance account with the highest 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 heat input under § 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 NOXallowances 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), (e), or (f) of this section. Such identification shall be made in the compliance certification report submitted in accordance with § 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 § 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 unit's identified percentage under paragraph (e)(1) of this section or, if no percentage is identified, an equal percentage for each unit multiplied by 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. In addition to the deductions under the first sentence of this paragraph (e)(1), the Administrator will deduct NOX allowances for each such unit until the number of NOX allowances deducted equals the number of NOX allowances required to account for actual heat input under § 97.42(e) for the unit for the control period.

(f) Deduction of banked allowances. Each year starting in 2005, after the Administrator has completed the designation of banked NOX allowances under § 97.55(b) and before May 1 of the year, the Administrator will determine the extent to which banked NOX allowances otherwise available under paragraph (a) of this section are available 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 (f)(1) of this section, to be held in compliance accounts, overdraft accounts, or general accounts is less than or equal to 10 percent of the sum of the trading program budgets under § 97.40 for all States for the control period, any banked NOX allowance may be deducted for compliance in Start Printed Page 2744accordance with paragraphs (a) through (e) of this section.

(3) If the total number of banked NOX allowances determined, under paragraph (f)(1) of this section, to be held in compliance accounts, overdraft accounts, or general accounts exceeds 10 percent of the sum of the trading program budgets under § 97.40 for all States for the control period, any banked allowance may be deducted for compliance in accordance with paragraphs (a) through (e) of this section, except as follows:

(i) The Administrator will determine the following ratio: 0.10 multiplied by the sum of the trading program budgets under § 97.40 for all States for the control period and divided by the total number of banked NOX allowances determined, under paragraph (f)(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 by the ratio determined under paragraph (f)(3)(i) of this section. The resulting product is the number of banked NOX allowances in the account that may be deducted for compliance in accordance with paragraphs (a) through (e) of this section. Any banked NOX allowances in excess of the resulting product may be deducted for compliance in accordance with paragraphs (a) through (e) of this section, except that, if such NOX allowances are used to make a deduction under paragraph (b) or (e) of this section, two (rather than one) such NOX allowances shall authorize up to one ton of NOX emissions during the control period and must be deducted for each deduction of one NOX allowance required under paragraph (b) or (e) of this section.

(g) Recordation of deductions. The Administrator will record in the appropriate compliance account or overdraft account all deductions from such an account pursuant to paragraph (b), (d), (e), or (f) of this section.

Banking.

NOX allowances may be banked for future use or transfer in a compliance account, an overdraft account, or a general account, as follows:

(a) 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 § 97.31, § 97.54, § 97.56, or subpart G or I of this part.

(b) 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 § 97.54 (except deductions pursuant to § 97.54(d)(2)) and that was allocated for that control period or a control period in a prior year.

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.

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 § 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 § 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

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 transferor 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 transferor account and the date signed.

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 transferor account to the transferee account as specified by the request, provided that:

(1) The transfer is correctly submitted under § 97.60; and

(2) The transferor account includes each NOX allowance identified by serial number in the transfer.

(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 in a prior year or the same year as the NOX allowance transfer deadline will not be recorded until after the Administrator completes the recordation of NOX allowance allocations under § 97.53 for the control period in the same year as the NOX allowance transfer deadline.

(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.

Notification.

(a) Notification of recordation. Within 5 business days of recordation of a NOX allowance transfer under § 97.61, the Administrator will notify the NOX authorized account representatives of both the transferor 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 § 97.61(a), the Administrator will notify 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.

Start Printed Page 2745

Subpart H—Monitoring and Reporting

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, recordkeeping, 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 § 97.2 and in § 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 deemed to refer to the terms “NOX Budget unit,” “NOX authorized account representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 97.2. The owner or operator of a unit that is not a NOX Budget unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the monitoring, recordkeeping, and reporting requirements for a NOX Budget unit under this part.

(a) Requirements for installation, certification, and data accounting. The owner or operator of each NOX Budget unit shall meet the following requirements. These provisions shall 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 emissions. This includes all systems required to monitor NOX emission rate, NOX concentration, heat input rate, and stack flow rate, in accordance with §§ 75.72 and 75.76 of this chapter.

(2) Install all monitoring systems for monitoring heat input rate.

(3) Successfully complete all certification tests required under § 97.71 and meet all other requirements 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, report, and quality-assure the data from the monitoring systems under paragraphs (a)(1) and (2) of this section.

(b) Compliance deadlines. The owner or operator shall meet the certification and other requirements of paragraphs (a)(1) through (a)(3) of this section on or before the following dates. The owner or operator shall record, report and quality-assure the data from the monitoring systems under paragraphs (a)(1) and (a)(2) of this section on and after the following dates.

(1) For the owner or operator of a NOX Budget unit for which the owner or operator intends to apply for early reduction credits under § 97.43, by May 1, 2000. If the owner or operator of a NOX Budget unit fails to meet this deadline, he or she is not eligible to apply for early reduction credits and is subject to the deadline under paragraph (b)(2) of this section.

(2) For the owner or operator of a NOX Budget unit under § 97.4(a) that commences operation before January 1, 2002 and that is not subject to or does not meet the deadline under paragraph (b)(1) of this section, by May 1, 2002.

(3) For the owner or operator of a NOX Budget unit under § 97.4(a)(1) that commences operation on or after January 1, 2002 and that reports on an annual basis under § 97.74(d) by the later of the following dates:

(i) May 1, 2002; or

(ii) 90 days after the date on which the unit commences commercial operation.

(4) For the owner or operator of a NOX Budget unit under § 97.4(a)(1) that commences operation on or after January 1, 2002 and that reports on a control period basis under § 97.74(d)(2)(ii), by no later than 90 days after the date on which the unit commences commercial operation, provided that this date is during a control period. If this date does not occur during a control period, the applicable deadline is May 1 immediately following this date.

(5) For the owner or operator of a NOX Budget unit under § 97.4(a)(2) that commences operation on or after January 1, 2002 and that reports on an annual basis under § 97.74(d), by the later of the following dates:

(i) May 1, 2002; or

(ii) 180 days after the date on which the unit commences operation.

(6) For the owner or operator of a NOX Budget unit under § 97.4(a)(2) that commences operation on or after January 1, 2002 and that report on a control period basis under § 97.74(d)(2)(ii), by 180 days after the date on which the unit commences operation, provided that this date is during a control period. If this date does not occur during a control period, the applicable deadline is May 1 immediately following this date.

(7) For the owner or operator of a NOX Budget unit that has a new stack or flue for which construction is completed after the applicable deadline under paragraph (b)(1), (b)(2), (b)(3), (b)(4), (b)(5), or (b)(6) of this section or under subpart I of this part and that reports on an annual basis under § 97.74(d), by 90 days after the date on which emissions first exit to the atmosphere through the new stack or flue.

(8) For the owner or operator of a NOX Budget unit that has a new stack or flue for which construction is completed after the applicable deadline under paragraph (b)(1), (b)(2), (b)(3), (b)(4), (b)(5), or (b)(6) of this section or under subpart I of this part and that reports on a control period basis under § 97.74(d)(2)(ii), by 90 days after the date on which emissions first exit to the atmosphere through the new stack or flue, provided that this date is during a control period. If this date does not occur during the control period, the applicable deadline is May 1 immediately following this date.

(9) For the owner or operator of a unit for which an application for a NOX Budget opt-in permit is submitted and not denied or withdrawn, by the date specified under subpart I of this part.

(c) Reporting data prior to initial certification. The owner or operator of a NOX Budget unit under paragraph (b)(3), (b)(4), (b)(5), or (b)(6) of this section shall determine, record and report NOX mass emissions, heat input rate, and any other values required to determine NOX mass emissions (e.g., NOX emission rate and heat input rate, or NOX concentration and stack flow rate) in accordance with § 75.70(g) of this chapter, from the date and hour that the unit starts operating until the date and hour on which the continuous emission monitoring system, excepted monitoring system under appendix D or E of part 75 of this chapter, or excepted monitoring methodology under § 75.19 of this chapter is provisionally certified.

(d) Prohibitions. (1) No owner or operator of a NOX Budget unit 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 § 97.75.

(2) No owner or operator of a NOX Budget unit 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 in § 75.74 of this chapter.

(3) No owner or operator of a NOX Budget unit 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 Start Printed Page 2746recertification 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 or except as provided in § 75.74 of this chapter.

(4) No owner or operator of a NOX Budget unit 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 an exemption under § 97.4(b) or § 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 for the retired or discontinued monitoring system in accordance with § 97.71(b)(2).

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 § 75.17(a) or (b) of this chapter for apportioning the NOX emission rate measured in a common stack or a petition under § 75.66 of this chapter for an alternative to a requirement in § 75.17 of this chapter, the NOX authorized account representative shall resubmit the petition to the Administrator under § 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 § 75.72 of this chapter or for any NOX concentration CEMS used under the provisions of § 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. The owner or operator of such a unit that qualifies to use the low mass emissions excepted monitoring methodology under § 75.19 of this chapter or that qualifies to use an alternative monitoring system under subpart E of part 75 of this chapter shall comply with the following procedures, as modified by paragraph (c) or (d) of this section. The owner or operator of a NOX Budget unit that is subject to an Acid Rain emissions limitation and that requires additional CEMS under the common stack provisions in § 75.72 of this chapter or uses a NOX concentration CEMS under § 75.71(a)(2) of this chapter shall comply with the following 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 § 75.20 of this chapter by the applicable deadline in § 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 in accordance with § 75.20 of this chapter is required.

(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in a certified monitoring system that may significantly affect the ability of the system to accurately measure or record NOX mass emissions or heat input rate or to meet the requirements of § 75.21 of this chapter or appendix B to part 75 of this chapter, the owner or operator shall recertify the monitoring system in accordance with § 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 may significantly change the stack flow or concentration profile, the owner or operator shall recertify the continuous emissions monitoring system in accordance with § 75.20(b) of this chapter. Examples of changes that require recertification include: replacement of the analyzer, complete replacement of an existing continuous emission monitoring system, or change in location or orientation of the sampling probe or site.

(3) Certification approval process for initial certification 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 written notice of the dates of certification in accordance with § 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 § 75.19 of this chapter, the provisional certification date for a monitor shall be determined in accordance with § 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 that 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. Start Printed Page 2747

(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. The 120-day review period shall not begin prior to receipt of a complete certification application.

(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, then 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 (as defined under § 75.20(a)(3) of this chapter). 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 that 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 § 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 specified under § 75.20(a)(4)(iii), § 75.20(b)(5), § 75.20(h)(4), or § 75.21(e) and continuing until the date and hour specified under § 75.20(a)(5)(i) of this chapter:

(1) For units that the owner or operator intends to monitor or monitors for NOX emission rate and heat input rate or intends to determine or determines NOX mass emissions using the low mass emission excepted methodology under § 75.19 of this chapter, the maximum potential NOX emission rate and the maximum potential hourly heat input of the unit; and

(2) For units that the owner or operator intends to monitor or monitors 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 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.

(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 § 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 § 75.19 of this chapter and not subject to an Acid Rain emissions limitation shall meet the applicable general operating requirements of § 75.10 of this chapter and the applicable requirements of § 75.19 of this chapter. The owner or operator of such a unit shall also meet the applicable certification and recertification procedures of paragraph (b) of this section, 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 a unit that does not have monitoring equipment initially certified or recertified for the NOX Budget Trading Program as of the date on which the NOX authorized account representative submits the certification application under § 75.19 of this chapter for the unit, starting on the date of such submission until the completion of the period for the Administrator's review.

(ii) For a unit that has monitoring equipment initially certified or recertified for the NOX Budget Trading Program as of the date on which the NOX authorized account representative submits the certification application under § 75.19 of this chapter for the unit and that reports data on an annual basis under § 97.74(d), starting January 1 of the year after the year of such submission until the completion of the period for the Administrator's review.

(iii) For a unit that has monitoring equipment initially certified or recertified for the NOX Budget Trading Program as of the date on which the NOX Authorized Account Representative submits the certification application under § 75.19 of this chapter for the unit and that reports on a control season basis under § 97.74(d), starting May 1 of the control period after the year of such submission until the completion of the period for the Administrator's review.

(d) Certification/recertification procedures for alternative monitoring systems. The NOX authorized account representative of each unit not subject to an Acid Rain emissions limitation for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable certification procedures of paragraph (b) of this section before using the system under the NOX Budget Trading Program. The NOX authorized account representative shall also comply with the applicable recertification procedures of paragraph (b) of this section. Section 75.20(f) of this chapter shall apply to such alternative monitoring system.

Out of control periods.

(a) Whenever any monitoring system fails to meet the quality assurance or data validation requirements 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 § 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 Start Printed Page 2748component. 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 for the system or component.

Notifications.

(a) The NOX authorized account representative for a NOX Budget unit shall submit written notice to the Administrator, the appropriate EPA Regional Office, and the permitting authority in accordance with § 75.61 of this chapter.

(b) For any unit that does not have an Acid Rain emissions limitation, the permitting authority may waive the requirement to notify the permitting authority in paragraph (a) of this section.

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 § 97.10(e)(1).

(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 that 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, then 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 § 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 § 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 Administrator, the appropriate EPA Regional Office, and the permitting authority within 45 days after completing all initial certification or recertification tests required under § 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 a unit for which the owner or operator intends to apply or applies for the early reduction credits under § 97.43, the calendar quarter that includes the date of initial provisional certification under § 97.71(b)(3)(iii) or § 97.71(c). Data shall be recorded and reported from the date and hour corresponding to the date and hour of provisional certification; or

(ii) For a unit that commences operation on or before May 1, 2002 and that is not subject to paragraph (d)(1)(i) of this section, the earlier of the calender quarter that includes the date of initial provisional certification under § 97.71(b)(3)(iii) or § 97.71(c) or, if the certification tests are not completed by May 1, 2002, the calendar quarter covering 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 recorded and reported from the date and hour corresponding to when the unit commences 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 related to monitoring and reporting NOX mass emissions during the entire year and meet the deadlines specified in paragraph (d)(1) of this section; or

(ii) Submit quarterly reports covering the period May 1 through September 30 of each year and including the data described in § 75.74(c)(6) of this chapter. The NOX authorized account representative shall submit such quarterly reports, beginning with:

(A) For a unit for which the owner or operator intends to apply or applies for early reduction credits under § 97.43, the calendar quarter that includes the date of initial provisional certification under § 97.71(b)(3)(iii) or § 97.71(c). Data shall be recorded and reported from the date and hour corresponding to the date and hour of provisional certification; or

(B) For a unit that commences operation on or before May 1, 2002 and that is not subject to paragraph (d)(2)(i) of this section, the calendar quarter covering May 1 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 initial provisional certification under § 97.71(b)(3)(iii) or § 97.71(c) or the first hour of May 1, 2002; or

(C) For a unit that commences operation after May 1, 2002 and during a control period, the calendar quarter in which the unit commences operation. Data shall be reported from the date and hour corresponding to when the unit commences operation; or

(D) For a unit that commences operation after May 1, 2002 and not during a control period, the calendar quarter covering the first control period after the unit commences operation. Data shall be recorded and reported from the earlier of the date and hour corresponding to the date and hour of initial provisional certification under § 97.71(b)(3)(iii) or § 97.71(c) or the first hour of May 1 of the first control period 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 § 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) and the data and 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). Start Printed Page 2749

(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;

(ii) For a unit with add-on NOX emission controls and for all hours where data are substituted in accordance with § 75.34(a)(1) of this chapter, the add-on emission controls were operating within the range of parameters listed in the quality assurance/quality control program under appendix B of part 75 of this chapter and the substitute values do not systematically underestimate NOX emissions; and

(iii) For a unit that is reporting on a control period basis under paragraph (d)(2)(ii) of this section, 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.

Petitions.

(a) The NOX authorized account representative of a NOX Budget unit may submit a petition under § 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 under § 75.66 of this chapter.

Additional requirements to provide heat input data.

The owner or operator of a NOX Budget unit that monitors and reports NOX mass emissions using a NOX concentration system and a flow system shall also monitor and report heat input rate at the unit level using the procedures set forth in part 75 of this chapter.

Subpart I—Individual Unit Opt-ins.

Applicability.

A unit that is in a State (as defined in § 97.2), is not a NOX Budget unit under § 97.4(a), is not a unit exempt under § 97.4(b), vents all of its emissions to a stack, and is operating, may qualify to be a NOX Budget opt-in unit under this subpart. A unit that is a NOX Budget unit under § 97.4(a), is covered by an exemption under § 97.4(b) or § 97.5 that is in effect, or is not operating is not eligible to be a NOX Budget opt-in unit.

General.

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

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 unit, 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.

Applying for NOX Budget opt-in permit.

(a) Applying for initial NOXBudget 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 § 97.80 may submit to the Administrator and the permitting authority at any time, except as provided under § 97.86(g):

(1) A complete NOX Budget permit application under § 97.22;

(2) A monitoring plan submitted in accordance with subpart H of this part; and

(3) A complete account certificate of representation under § 97.13, if no NOX authorized account representative has been previously designated for the unit.

(b) Duty to reapply. Unless the NOX Budget opt-in permit is terminated or revised under § 97.86(e) or § 97.87(b)(1)(i), the NOX authorized account representative of a NOX Budget opt-in unit shall submit to the Administrator and permitting authority a complete NOX Budget permit application under § 97.22 to renew the NOX Budget opt-in permit in accordance with § 97.21(c) and, if applicable, an updated monitoring plan in accordance with subpart H of this part.

Opt-in process.

The permitting authority will issue or deny an initial NOX Budget opt-in permit for a unit for which an application for a NOX Budget opt-in permit under § 97.83 is submitted, in accordance with § 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 § 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 rate 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 percent monitor data 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 Administrator will calculate the unit's baseline heat input, which will equal the unit's total heat input (in mmBtu) for the control period, and the unit's baseline NOX emissions rate, which will equal the unit's total NOX mass emissions (in lb) for the control period divided by the unit's baseline heat input.

(d) Issuance of draft NOXBudget opt-in permit for public comment. The permitting authority will issue a draft NOX Budget opt-in permit for public comment in accordance with § 97.20.

(e) Not withstanding paragraphs (a) through (d) of this section, if at any time before issuance of a draft NOX Budget opt-in permit for public comment for the unit, the Administrator or the permitting authority determines that the unit does not qualify as a NOX Budget opt-in unit under § 97.80, the permitting authority will issue a draft denial of a NOX Budget opt-in permit for public comment for the unit in accordance with § 97.20.

(f) Withdrawal of application for NOXBudget opt-in permit. A NOX authorized account representative of a unit may withdraw its application for an initial NOX Budget opt-in permit under § 97.83 at any time prior to the issuance of the Start Printed Page 2750initial 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 an initial NOX Budget permit under § 97.83.

(g) The unit shall be a NOX Budget opt-in unit and a NOX Budget unit starting May 1 of the first control period starting after the issuance of the initial NOX Budget opt-in permit by the permitting authority.

NOX Budget opt-in permit contents.

(a) Each NOX Budget opt-in permit will contain all elements required for a complete NOX Budget opt-in permit application under § 97.22.

(b) Each NOX Budget opt-in permit is deemed to incorporate automatically the definitions of terms under § 97.2 and, upon recordation by the Administrator under subpart F or G of this part, every allocation, transfer, or deduction of NOX allowances to or from the compliance accounts of each NOX Budget opt-in unit covered by the NOX Budget opt-in permit or the overdraft account of the NOX Budget source where the NOX Budget opt-in unit is located.

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 unit 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 unit 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 § 97.30.

(2) If the NOX Budget opt-in unit 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 unit's compliance account, or the overdraft account of the NOX Budget source where the NOX Budget opt-in unit is located, the full amount required under § 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 unit's compliance account, or the overdraft account of the NOX Budget source where the NOX Budget opt-in unit 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 § 97.88 for any control period for which the withdrawal is to be effective. The Administrator will close the NOX Budget opt-in unit's compliance account and transfer any remaining allowances to a general account specified by the owners and operators of the NOX Budget opt-in unit.

(c) A NOX Budget opt-in unit 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 unit was a NOX Budget opt-in unit, 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 unit of the acceptance of the withdrawal of the NOX Budget opt-in unit 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 unit that the request to withdraw is denied. If the NOX Budget opt-in unit's request to withdraw is denied, the NOX Budget opt-in unit shall remain subject to the requirements for a NOX Budget opt-in unit.

(e) Permit revision. 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 unit 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 unit shall continue to be a NOX Budget opt-in unit until the effective date of the termination.

(f) Reapplication upon failure to meet conditions of withdrawal. If the Administrator denies the request to withdraw the NOX Budget opt-in unit, 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 NOXBudget Trading Program. Once a NOX Budget opt-in unit withdraws from the NOX Budget Trading Program and its NOX Budget opt-in permit is terminated under paragraph (e) of this section, the NOX authorized account representative may not submit another application for a NOX Budget opt-in permit under § 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.

Change in regulatory status.

(a) Notification. When a NOX Budget opt-in unit becomes a NOX Budget unit under § 97.4(a), the NOX authorized account representative shall notify in writing the permitting authority and the Administrator of such change in the NOX Budget opt-in unit'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 unit becomes a NOX Budget unit under § 97.4(a), the permitting authority will revise the NOX Budget opt-in unit's NOX Budget opt-in permit to meet the requirements of a NOX Budget permit under § 97.23 as of an effective date that is the date on which such NOX Budget opt-in unit becomes a NOX Budget unit under § 97.4(a).

(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 unit) under § 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 unit) under § 97.88 for the control period multiplied by the number of days in the control period Start Printed Page 2751starting 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, and rounded to the nearest whole number of NOX allowances as appropriate.

(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, contains 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 the necessary 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 in effect, the NOX Budget unit under paragraph (b)(1)(i) of this section will be treated, solely for purposes of NOX allowance allocations under § 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 § 97.42. The unit's deadline under § 97.84(b) for meeting monitoring requirements in accordance with subpart H of this part shall not changed by the change in the unit's regulatory status or by the revision of the NOX Budget permit under paragraph (b)(1)(i) of this section.

(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 § 97.42 for the control period: the number of NOX allowances otherwise allocated to the NOX Budget unit under § 97.42 for the control period multiplied by 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, and rounded to the nearest whole number of NOX allowances as appropriate.

(2)(i) When the NOX authorized account representative of a NOX Budget opt-in unit does not renew its NOX Budget opt-in permit under § 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 unit 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 unit under § 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 unit's compliance account or the overdraft account of the NOX Budget source where the NOX Budget opt-in unit is located contains the NOX allowances necessary for completion of such deduction. If the compliance account or overdraft account does not contain the necessary 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 unit's compliance account. If any NOX allowances remain in the compliance account after completion of such deduction and any deduction under § 97.54, the Administrator will close the NOX Budget opt-in unit's compliance account and transfer any remaining allowances to a general account specified by the owners and operators of the NOX Budget opt-in unit.

NOX allowance allocations to opt-in units.

(a) NOXallotment allocation. (1) By April 1 immediately before the first control period for which the NOX Budget opt-in permit is effective, the Administrator will determine by order the NOX allowance allocations for the NOX Budget opt-in unit for the control period in accordance with paragraph (b) of this section.

(2) By no later than April 1, after the first control period for which the NOX Budget opt-in permit is in effect, and April 1 of each year thereafter, the Administrator will determine by order the NOX allowance allocations for the NOX Budget opt-in unit for the next control period, in accordance with paragraph (b) of this section.

(3) The Administrator will make available to the public each determination of NOX allowance allocations under paragraph (a)(1) or (2) of this section and will provide an opportunity for submission of objections to the determination. Objections shall be limited to addressing whether the determination is in accordance with paragraph (b) of this section. Based on any such objections, the Administrator will adjust each determination to the extent necessary to ensure that it is in accordance with paragraph (b) of this section.

(b) For each control period for which the NOX Budget opt-in unit has an approved NOX Budget opt-in permit, the NOX Budget opt-in unit 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 unit's baseline heat input determined pursuant to § 97.84(c); or

(ii) The unit'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 unit in an amount equaling the heat input determined under paragraph (b)(1) of this section multiplied by the lesser of the unit's baseline NOX emissions rate determined under § 97.84(c) or the most stringent State or federal NOX emissions limitation applicable to the unit during the control period, divided by 2,000 lb/ton, and rounded to the nearest whole number of NOX allowances as appropriate.

End Part Appendix A to Part 97—Final Section 126 Rule: EGU Allocations, 2003-2007
STPlantPlant_idPoint_idNOX allocation for EGUs
DCBENNING6031580
DCBENNING60316117
DECHRISTIANA SUB591115
DECHRISTIANA SUB591145
Start Printed Page 2752
DEDELAWARE CITY52193B4141
DEDELAWARE CITY52193ST_1155
DEDELAWARE CITY52193ST_2159
DEDELAWARE CITY52193ST_3158
DEEDGE MOOR5933234
DEEDGE MOOR5934401
DEEDGE MOOR5935602
DEHAY ROAD7153**3184
DEHAY ROAD7153—1235
DEHAY ROAD7153—2207
DEINDIAN RIVER5941187
DEINDIAN RIVER5942194
DEINDIAN RIVER5943369
DEINDIAN RIVER5944729
DEMCKEE RUN5993119
DEVAN SANT STATION7318**117
INANDERSON7336—ACT15
INANDERSON7336—ACT25
INCLIFTY CREEK9831558
INCLIFTY CREEK9832543
INCLIFTY CREEK9833564
INCLIFTY CREEK9834525
INCLIFTY CREEK9835561
INCLIFTY CREEK9836509
INCONNERSVILLE100211
INCONNERSVILLE100221
INGALLAGHER10081290
INGALLAGHER10082276
INGALLAGHER10083347
INGALLAGHER10084329
INNOBLESVILLE1007148
INNOBLESVILLE1007245
INNOBLESVILLE1007345
INRICHMOND7335—RCT15
INRICHMOND7335—RCT25
INTANNERS CREEK988U1297
INTANNERS CREEK988U2235
INTANNERS CREEK988U3387
INTANNERS CREEK988U4906
INWHITEWATER VALLEY1040174
INWHITEWATER VALLEY10402173
KYBIG SANDY1353BSU1565
KYBIG SANDY1353BSU21,741
KYCANE RUN13634397
KYCANE RUN13635332
KYCANE RUN13636430
KYCOOPER13841183
KYCOOPER13842367
KYDALE13853161
KYDALE13854158
KYE W BROWN13551193
KYE W BROWN13551037
KYE W BROWN13552317
KYE W BROWN13553863
KYE W BROWN1355834
KYE W BROWN1355934
KYE.W. BROWN13551121
KYEAST BEND601821,413
KYGHENT135611,232
KYGHENT135621,081
KYGHENT135631,104
KYGHENT135641,132
KYH L SPURLOCK60411697
KYH L SPURLOCK604121,589
KYMILL CREEK13641528
KYMILL CREEK13642600
KYMILL CREEK13643941
KYMILL CREEK136441,096
KYPADDY'S RUN1366128
KYPINEVILLE1360367
KYTRIMBLE COUNTY607111,221
KYTYRONE136113
KYTYRONE136123
Start Printed Page 2753
KYTYRONE136133
KYTYRONE136143
KYTYRONE13615117
MDBRANDON SHORES60211,827
MDBRANDON SHORES60221,713
MDC P CRANE15521434
MDC P CRANE15522463
MDCHALK POINT1571—GT21
MDCHALK POINT1571—GT336
MDCHALK POINT1571—GT439
MDCHALK POINT1571—GT555
MDCHALK POINT1571—GT660
MDCHALK POINT1571—SGT124
MDCHALK POINT15711833
MDCHALK POINT15712861
MDCHALK POINT15713585
MDCHALK POINT15714522
MDDICKERSON1572—GT236
MDDICKERSON1572—GT366
MDDICKERSON15721447
MDDICKERSON15722441
MDDICKERSON15723481
MDGOULD STREET1553381
MDHERBERT A WAGNER15541134
MDHERBERT A WAGNER15542399
MDHERBERT A WAGNER15543723
MDHERBERT A WAGNER15544301
MDMORGANTOWN1573—GT39
MDMORGANTOWN1573—GT49
MDMORGANTOWN1573—GT59
MDMORGANTOWN1573—GT68
MDMORGANTOWN157311,151
MDMORGANTOWN157321,375
MDPANDA BRANDYWINE54832195
MDPANDA BRANDYWINE54832284
MDPERRYMAN1556**5156
MDPERRYMAN1556—GT18
MDPERRYMAN1556—GT29
MDPERRYMAN1556—GT36
MDPERRYMAN1556—GT410
MDR P SMITH157011143
MDR P SMITH1570911
MDRIVERSIDE1559—GT611
MDRIVERSIDE1559440
MDVIENNA15648169
MDWESTPORT1560—GT528
MI491 E. 48TH STREET7268—711
MI491 E. 48TH STREET7268—812
MIADA COGEN LTD10819CA_Ltd23
MIBELLE RIVER603411,589
MIBELLE RIVER603421,672
MIDAN E KARN17021552
MIDAN E KARN17022530
MIDAN E KARN17023288
MIDAN E KARN17024310
MIECKERT STATION1831152
MIECKERT STATION1831247
MIECKERT STATION1831365
MIECKERT STATION18314116
MIECKERT STATION18315154
MIECKERT STATION18316131
MIENDICOTT GENERATING STATION4259198
MIERICKSON18321381
MIGREENWOOD60351373
MIHANCOCK173053
MIHANCOCK173063
MIHARBOR BEACH1731197
MIJ B SIMS18253137
MIJ C WEADOCK17207346
MIJ C WEADOCK17208342
MIJ R WHITING17231225
MIJ R WHITING17232204
MIJ R WHITING17233249
Start Printed Page 2754
MIJAMES DE YOUNG1830569
MIMARYSVILLE17321022
MIMARYSVILLE17321116
MIMARYSVILLE17321217
MIMARYSVILLE1732917
MIMIDLAND COGENERATION VENTURE10745003269
MIMIDLAND COGENERATION VENTURE10745004276
MIMIDLAND COGENERATION VENTURE10745005271
MIMIDLAND COGENERATION VENTURE10745006273
MIMIDLAND COGENERATION VENTURE10745007280
MIMIDLAND COGENERATION VENTURE10745008277
MIMIDLAND COGENERATION VENTURE10745009273
MIMIDLAND COGENERATION VENTURE10745010271
MIMIDLAND COGENERATION VENTURE10745011274
MIMIDLAND COGENERATION VENTURE10745012269
MIMIDLAND COGENERATION VENTURE10745013275
MIMIDLAND COGENERATION VENTURE10745014269
MIMISTERSKY1822533
MIMISTERSKY18226155
MIMISTERSKY1822798
MIMONROE173311,902
MIMONROE173321,555
MIMONROE173331,574
MIMONROE173341,822
MIRIVER ROUGE174010
MIRIVER ROUGE17402627
MIRIVER ROUGE17403652
MIROUGE POWERHOUSE #1102721232
MIST CLAIR17431339
MIST CLAIR17432304
MIST CLAIR17433351
MIST CLAIR17434349
MIST CLAIR174350
MIST CLAIR17436646
MIST CLAIR17437733
MITRENTON CHANNEL174516132
MITRENTON CHANNEL174517124
MITRENTON CHANNEL174518130
MITRENTON CHANNEL174519126
MITRENTON CHANNEL17459A968
MIWYANDOTTE186658
MIWYANDOTTE1866781
MIWYANDOTTE1866836
NCASHEVILLE27061491
NCASHEVILLE27062479
NCBELEWS CREEK804212,306
NCBELEWS CREEK804222,688
NCBUCK2720559
NCBUCK2720665
NCBUCK2720769
NCBUCK27208284
NCBUCK27209300
NCBUTLER WARNER GEN PL1016—140
NCBUTLER WARNER GEN PL1016—240
NCBUTLER WARNER GEN PL1016—340
NCBUTLER WARNER GEN PL1016—642
NCBUTLER WARNER GEN PL1016—740
NCBUTLER WARNER GEN PL1016—840
NCBUTLER WARNER GEN PL1016—9103
NCCAPE FEAR27085255
NCCAPE FEAR27086361
NCCLIFFSIDE2721167
NCCLIFFSIDE2721273
NCCLIFFSIDE2721395
NCCLIFFSIDE27214107
NCCLIFFSIDE272151,180
NCCOGENTRIX-ROCKY MOUNT50468ST_unt303
NCCOGENTRIX ELIZABETHTOWN10380ST_OWN111
NCCOGENTRIX KENANSVILLE10381ST_LLE102
NCCOGENTRIX LUMBERTON10382ST_TON111
NCCOGENTRIX ROXBORO10379ST_ORO166
NCCOGENTRIX SOUTHPORT10378ST_ORT335
NCCRAVEN COUNTY WOOD ENERGY10525ST_RGY231
Start Printed Page 2755
NCDAN RIVER27231117
NCDAN RIVER27232128
NCDAN RIVER27233271
NCG G ALLEN27181311
NCG G ALLEN27182316
NCG G ALLEN27183525
NCG G ALLEN27184470
NCG G ALLEN27185514
NCL V SUTTON27131162
NCL V SUTTON27132176
NCL V SUTTON27133717
NCL V SUTTON2713CT2B2
NCLEE27091129
NCLEE27092142
NCLEE27093414
NCLEE2709CT41
NCLINCOLN7277133
NCLINCOLN72771031
NCLINCOLN72771133
NCLINCOLN72771231
NCLINCOLN72771326
NCLINCOLN72771426
NCLINCOLN72771525
NCLINCOLN72771625
NCLINCOLN7277233
NCLINCOLN7277331
NCLINCOLN7277431
NCLINCOLN7277529
NCLINCOLN7277630
NCLINCOLN7277724
NCLINCOLN7277825
NCLINCOLN7277932
NCMARSHALL27271899
NCMARSHALL27272940
NCMARSHALL272731,588
NCMARSHALL272741,570
NCMAYO62501A893
NCMAYO62501B875
NCPANDA-ROSEMARY50555CT_ary62
NCPANDA-ROSEMARY50555CW_ary47
NCRIVERBEND273210266
NCRIVERBEND27327193
NCRIVERBEND27328200
NCRIVERBEND27329253
NCROANOKE VALLEY502541440
NCROANOKE VALLEY502542140
NCROXBORO27121766
NCROXBORO271221,426
NCROXBORO27123A792
NCROXBORO27123B785
NCROXBORO27124A778
NCROXBORO27124B733
NCTOBACCOVILLE50221153
NCTOBACCOVILLE50221253
NCTOBACCOVILLE50221353
NCTOBACCOVILLE50221453
NCUNC—CHAPEL HILL54276ST_ill14
NCW H WEATHERSPOON2716176
NCW H WEATHERSPOON2716286
NCW H WEATHERSPOON27163161
NCW H WEATHERSPOON2716CT-14
NCW H WEATHERSPOON2716CT-23
NCW H WEATHERSPOON2716CT-32
NCW H WEATHERSPOON2716CT-44
NJB L ENGLAND23781353
NJB L ENGLAND23782417
NJB L ENGLAND23783114
NJBAYONNE504971139
NJBAYONNE504972143
NJBAYONNE504973140
NJBERGEN23981101152
NJBERGEN23981201157
NJBERGEN23981301155
Start Printed Page 2756
NJBERGEN23981401152
NJBURLINGTON239910130
NJBURLINGTON239910234
NJBURLINGTON239910339
NJBURLINGTON239910447
NJBURLINGTON239911-12
NJBURLINGTON239911-22
NJBURLINGTON239911-32
NJBURLINGTON239911-42
NJBURLINGTON2399717
NJBURLINGTON23999-14
NJBURLINGTON23999-24
NJBURLINGTON23999-34
NJBURLINGTON23999-44
NJCAMDEN107511378
NJCARLL'S CORNER STATION237912
NJCARLL'S CORNER STATION2379216
NJCARNEYS POINT (CCLP) NUG10566ST_NUG527
NJCEDAR STATION23801E&W5
NJCUMBERLAND5083—GT140
NJDEEPWATER2384149
NJDEEPWATER238445
NJDEEPWATER2384642
NJDEEPWATER23848195
NJEDISON24001-1A&B3
NJEDISON24001-2A&B3
NJEDISON24001-3A&B3
NJEDISON24001-4A&B3
NJEDISON24002-1A&B7
NJEDISON24002-2A&B7
NJEDISON24002-3A&B7
NJEDISON24002-4A&B7
NJEDISON24003-1A&B7
NJEDISON24003-2A&B7
NJEDISON24003-3A&B7
NJEDISON24003-4A&B7
NJESSEX240110-1A&B10
NJESSEX240110-2A&B10
NJESSEX240110-3A&B10
NJESSEX240110-4A&B10
NJESSEX240111-1A&B11
NJESSEX240111-2A&B11
NJESSEX240111-3A&B11
NJESSEX240111-4A&B11
NJESSEX240112-1A&B13
NJESSEX240112-2A&B13
NJESSEX240112-3A&B13
NJESSEX240112-4A&B13
NJESSEX2401966
NJFORKED RIVER7138—117
NJFORKED RIVER7138—217
NJGILBERT23930347
NJGILBERT23930464
NJGILBERT23930563
NJGILBERT23930661
NJGILBERT23930763
NJGILBERT239314
NJGILBERT239324
NJGILBERT2393CT-961
NJHUDSON24031175
NJHUDSON24032884
NJHUDSON240333
NJKEARNY24041026
NJKEARNY24041134
NJKEARNY240412-18
NJKEARNY240412-28
NJKEARNY240412-38
NJKEARNY240412-48
NJKEARNY2404735
NJKEARNY2404816
NJLINDEN24061116
NJLINDEN24061211
NJLINDEN24061320
Start Printed Page 2757
NJLINDEN2406252
NJLINDEN240662
NJLINDEN2406760
NJLINDEN2406870
NJLINDEN COGEN50006100276
NJLINDEN COGEN50006200280
NJLINDEN COGEN50006300274
NJLINDEN COGEN50006400272
NJLINDEN COGEN50006500278
NJLOGAN GENERATING PLANT100431424
NJMERCER24081489
NJMERCER24082558
NJMICKELTON8008128
NJMIDDLE ST238234
NJMILFORD POWER LP10616144
NJMOBIL NUGn114CT_NUG40
NJNEWARK BAY COGEN5038519
NJNEWARK BAY COGEN5038529
NJNORTH JERSEY ENERGY ASSOCIATES10308119
NJNORTH JERSEY ENERGY ASSOCIATES10308219
NJO'BRIEN (NEWARK) COGENERATION, INC.5079718
NJO'BRIEN (PARLIN) COGENERATION, INC.5079918
NJO'BRIEN (PARLIN) COGENERATION, INC.5079928
NJPEDRICKTOWN COGEN10099113
NJPRIME ENERGY LP508521178
NJSALEM24103A&B3
NJSAYREVILLE23900740
NJSAYREVILLE23900851
NJSAYREVILLE2390C-116
NJSAYREVILLE2390C-213
NJSAYREVILLE2390C-311
NJSAYREVILLE2390C-413
NJSEWAREN2411142
NJSEWAREN2411245
NJSEWAREN2411358
NJSEWAREN2411491
NJSEWAREN241162
NJSHERMAN7288CT-137
NJVINELAND VCLP NUG54807GT_NUG40
NJWERNER23850414
NJWERNER2385C-17
NJWERNER2385C-26
NJWERNER2385C-37
NJWERNER2385C-47
NJWEST STAT6776110
NY59TH STREET250311441
NY59TH STREET250311532
NY74TH STREET250412070
NY74TH STREET250412180
NY74TH STREET250412265
NYARTHUR KILL249020524
NYARTHUR KILL249030380
NYASTORIA890630557
NYASTORIA890640505
NYASTORIA890650561
NYASTORIA8906GT2-19
NYASTORIA8906GT2-29
NYASTORIA8906GT2-39
NYASTORIA8906GT2-49
NYASTORIA8906GT3-19
NYASTORIA8906GT3-29
NYASTORIA8906GT3-39
NYASTORIA8906GT3-49
NYASTORIA8906GT4-19
NYASTORIA8906GT4-29
NYASTORIA8906GT4-39
NYASTORIA8906GT4-49
NYBOWLINE POINT26251749
NYBOWLINE POINT26252566
NYBROOKLYN NAVY