[Federal Register Volume 65, Number 11 (Tuesday, January 18, 2000)]
[Rules and Regulations]
[Pages 2674-2767]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-20]



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Part II





Environmental Protection Agency





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40 CFR Parts 52 and 97



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

  Federal Register / Vol. 65, No. 11 / Tuesday January 18, 2000 / Rules 
and Regulations  

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 52 and 97

[FRL-6515-5]
RIN 2060-AH88


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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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.

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 [email protected]. Please refer to SUPPLEMENTARY 
INFORMATION below for a list of contacts for specific subjects 
discussed in today's action.

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

[[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.

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However, 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

[[Page 2677]]

from 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\
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    \1\ The petitions also named process heaters and small sources. 
In the May 25 final rule (64 FR at 28301), EPA determined that 
highly cost-effectiveness controls are not available for these 
source categories. Therefore, EPA denied the portions of the 
petitions that named these source categories.
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    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
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         Source Category              Average Cost Effectiveness ($/ozone season ton) for each Control Option
----------------------------------------------------------------------------------------------------------------
Large EGUs......................  0.20 lb/mmBtu...........  0.15 lb/mmBtu..........  0.12 lb/mmBtu
                                  $1,425 ($1,187).........  $1,720 ($1,432)........  $2,043 ($1,701)
                                 -------------------------------------------------------------------------------
Large Non-EGUs..................  50% reduction...........  60% reduction..........  70% reduction
                                  $1,613 ($1,370).........  $1,908 ($1,589)........  $2,903 ($2,418)
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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.


[[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\
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    \2\ IPM is an economic model used by industry and government. 
EPA used this model to estimate the costs and emissions reductions 
from EGU's that would result from controlling NOX 
emissions under the NOX SIP call and this section 126 
action.
    \3\ The cost-effectiveness numbers presented assumes trading 
across the entire 13 jurisdictions. EPA has examined the effects of 
excluding the portions of the four States (NY, IN, MI, KY) not 
covered in today's final rule and concluded that it does not impact 
the average cost effectiveness. That analysis is presented in an 
Appendix to the RIA.
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    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

[[Page 2679]]

addition, 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).
---------------------------------------------------------------------------

    \4\ Whenever the word ``new'' is used in relation to sources 
affected by this rule, it includes both new and modified sources.
---------------------------------------------------------------------------

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

[[Page 2680]]

on 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.
---------------------------------------------------------------------------

    \5\ While the text of section 126 refers to section 
110(a)(2)(D)(ii), EPA believes that this cross-reference is a 
scrivener's error that occurred during the 1990 Amendments to the 
CAA and that Congress intended to refer to section 110(a)(2)(D)(i). 
64 FR 28267.
---------------------------------------------------------------------------

    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

[[Page 2681]]

it 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

[[Page 2682]]

principle 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.
---------------------------------------------------------------------------

    \6\ While the period from November 30, 1999 to May 1, 2003 is 
longer than 3 years, under the remedy that EPA has promulgated under 
section 126, sources need only control emissions during the ozone 
season, which runs from May 1 to September 30 each year. Thus, 
although sources legally would be subject to the section 126 
requirements within 3 years from the effective date of EPA's 
finding, those requirements would not require any reductions until 
the beginning of the first ozone season following the date of EPA's 
finding, here, May 1, 2003.
---------------------------------------------------------------------------

    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

[[Page 2683]]

the NOX SIP call in the fall of 1999 for the benefit of the 
region as a whole.\7\
---------------------------------------------------------------------------

    \7\ To date, Rhode Island and Connecticut have voluntarily 
submitted SIP revisions under the NOX SIP call.
---------------------------------------------------------------------------

    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

[[Page 2684]]

110(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.
---------------------------------------------------------------------------

    \8\ Given the particular remedy that EPA is requiring under 
section 126, the absence of any economic penalty or burden on a 
State that chooses to allow Federal regulation of sources in the 
State, rather than preempting the section 126 remedy by complying 
with the NOX SIP call, is especially evident here. The 
sources subject to the section 126 remedy are the bulk of those that 
EPA identified in the NOX SIP call as having the most 
highly cost-effective emissions reductions available.
---------------------------------------------------------------------------

    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.

[[Page 2685]]

However, 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

[[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 Sec. 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 Sec. 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 Sec. 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

[[Page 2687]]

promulgates 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., 
Sec. 97.6(c)) replace the element in the May 25, 1999 final rule 
(Sec. 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 (Sec. 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 
(Sec. 52.34(j)) is replaced by the trading program budget provisions in 
part 97 (i.e., Sec. 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 (Sec. 52.34(j)(4)) is embodied in and replaced by 
Sec. 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 (Sec. 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 Sec. 52.34(k). Because the interim emissions limitations are 
superseded, today's rule expressly removes Sec. 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 Sec. 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, Sec. 97.2 and Sec. 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

[[Page 2688]]

can be found in the preamble accompanying the proposed part 97 (63 FR 
56310-56313).
Subpart A--NOX Budget Trading Program General Provisions
Sec.
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, Sec. 97.5(c) is revised concerning NOX allowance 
allocations to a retired unit. New Sec. 97.5(c)(2) provides (like the 
proposed Sec. 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 Sec. 97.5(c) are 
also reordered and then renumbered to reflect the new paragraph and the 
reordering. Second, Sec. 97.5(c) contains minor word changes that 
clarify, but do not alter the substance of, the provisions. For 
example, minor word changes in Sec. 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 Sec. 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 Sec. 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 
Sec. 97.2 since both provisions describe the requirement for 
NOX Budget units to hold allowances. Under Sec. 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 Sec. 97.6(c)(8), language is 
revised to mirror the language in Sec. 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. NOX Authorized 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 Sec. 70.2 and must be reflected in the title V operating permit 
of NOX Budget sources required to have such a permit. The 
EPA believes that the majority of NOX Budget sources will be 
required to have a title V permit. 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

[[Page 2689]]

has a federally enforceable non-title V permit, the trading program 
requirements must also be incorporated into this permit. If a source 
does not have a federally enforceable permit, the requirements of the 
Federal NOX Budget Trading Rule 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 Sec. 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 Sec. 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 
Sec. 97.23(a) and Sec. 97.85(a). As a further example, minor word 
changes in Sec. 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 
Sec. 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 Sec. 97.22.
    One section, proposed Sec. 97.24 addressing the effective date of 
the initial NOX Budget permit, is removed entirely, and 
proposed Sec. 97.25 is renumbered (without any other changes) as 
Sec. 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, Sec. 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 Sec. 97.21(b) 
explains the deadlines for submission of NOX Budget permit 
applications. Similarly, Sec. 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. NOX Allowance Tracking System. The NOX 
Allowance Tracking System is an automated system used to track 
NOX allowances held by NOX Budget units under the 
NOX Budget Trading Program, as well as those 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, 
Secs. 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 
Sec. 97.4(a) (permit limit exemption) or Sec. 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 Sec. 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 
Sec. 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 Sec. 97.53(b), (c), and (d) 
are added and proposed Sec. 97.53(b) is renumbered as Sec. 97.53(e). 
The new Sec. 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 Sec. 97.88. Language 
in another section (Sec. 97.61(b)) that references Sec. 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 
Sec. 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 Secs. 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 
Sec. 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

[[Page 2690]]

non-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 Sec. 97.55 setting forth essentially the 
same provisions for banking and the management of banked allowances as 
specified in part 96 (in Sec. 96.55(a)) and proposed Sec. 97.55(a). 
Language in the newly numbered Sec. 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 Sec. 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 
Sec. 97.55(b) to final Sec. 97.54(f), and the references in the flow 
control provisions to other provisions in Sec. 97.54 are corrected to 
reflect this relocation. The proposed Sec. 97.55(b) stated explicitly 
that the flow control provisions modify the provisions for compliance 
deductions under Sec. 97.54. However, the relocation in Sec. 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 Sec. 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 Sec. 97.54(e). As part of this clarification, 
parallel changes are made to the definitions of ``NOX 
allowances'' and ``NOX Budget emissions limitation'' in 
Sec. 97.2, to reference Sec. 97.54(f). Similarly, references elsewhere 
in part 97 to compliance deductions under Sec. 97.54(b) or (e) are 
expanded to reference Sec. 97.54(b), (e) or (f) as appropriate. See, 
e.g., Secs. 97.42(e) and (f). In addition, language is added to 
Sec. 97.54(f)(3)(ii) stating expressly what is implied in proposed 
Sec. 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 Sec. 97.54(f) also includes some 
minor revisions that clarify, but do not change the substance of, the 
proposal. For example Sec. 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 Sec. 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 
Sec. 97.55(c) in subpart F to a new final Sec. 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 Sec. 97.43(a), the procedures for requesting credits for OTC 
banked allowances are in Sec. 97.43(b), and the procedures for 
reviewing requests and allocating pool allowances are in Sec. 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. NOX Allowance 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 Sec. 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.

[[Page 2691]]

The 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 
Secs. 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 Sec. 97.84(g) and 
Sec. 97.85(a) and (b) that parallel changes discussed above concerning 
proposed Sec. 97.24 and proposed Sec. 97.23(a) and (b); removal of 
proposed Sec. 97.84(e) and (f) as unnecessarily duplicative of the 
comment period already provided under proposed Sec. 97.84(d); and 
renumbering of the rest of the Sec. 97.84 paragraphs. In addition, 
proposed Sec. 97.87(b)(1)(iii) states that an opt-in that becomes a 
NOX Budget Unit under Sec. 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 Sec. 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 Sec. 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 
Sec. 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 Sec. 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 
Sec. 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 Sec. 97.80 that a ``NOX Budget unit under 
Sec. 97.4'' cannot become an opt-in is revised. Final Sec. 97.80 states 
that an opt-in cannot be a ``NOX Budget unit under 
Sec. 97.4(a)'' or a unit exempt under Sec. 97.4(b). Parallel changes 
are included in Sec. 97.22(d)(1), Sec. 97.4(b)(4)(viii), and 
Sec. 97.5(c)(8). This provides clearer references to the two distinct 
parts of Sec. 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 Sec. 97.5. As another example, 
Sec. 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 ``Sec. 97.4'' are generally changed to refer specifically to 
``Sec. 97.4(a)''). See, i.e., Sec. 97.2. By further example, the 
reference in proposed Sec. 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 Sec. 97.43(a)(1). Although part 
75 (Sec. 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 Sec. 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 Sec. 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
Sec.
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

[[Page 2692]]

State 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 Sec. 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 Sec. 97.4(b) or 
Sec. 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 (Secs. 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 Sec. 97.4(b) in the Federal NOX Budget Trading Program. 
In today's final rule, Sec. 97.4(b) is revised by reorganizing to 
resemble the order of provisions in the retired unit exemption 
(Sec. 97.8) and by adding some provisions to make it complete. In 
addition, provisions are added to Sec. 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

[[Page 2693]]

will 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 Sec. 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

[[Page 2694]]

requirement 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 Sec. 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., Secs. 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 
Sec. 52.34(a) is superceded and unnecessary. Part 52 uses the term 
``NOX allowance'' only in provisions in Sec. 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 Secs. 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 Sec. 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 Sec. 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 
Sec. 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 
Sec. 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 Sec. 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 Sec. 97.4 differ 
from the corresponding categories in Sec. 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 Sec. 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

[[Page 2695]]

a 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.4(b)(4)(ii), Sec. 97.40(b), and 
Sec. 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

[[Page 2696]]

that 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 Sec. 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 Sec. 97.4(b), which sets forth the exemption, by 
reorganizing the section to resemble the order of provisions in the 
retired unit exemption (Sec. 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 Sec. 97.4 and subparts E, F, and G and the definitions, 
measurements, and time computation provisions in Secs. 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 Sec. 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 
Sec. 97.4(b)(1) includes provisions in the proposed Secs. 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 Sec. 97.4(b)(3) 
requirement to notify the Administrator of the issuance of the 
federally enforceable permit is set forth in proposed Sec. 97.4(b). The 
Sec. 97.4(b)(4)(i) and (iii) special provisions are reflected in 
proposed Secs. 97.4(b) and (b)(2). The recordkeeping provision in 
Sec. 97.4(b)(4)(iv) is like the one in proposed Sec. 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 Sec. 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 Sec. 97.4(b)(4)(ii) provisions (along with provisions in 
Sec. 97.40(b) and Sec. 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 Sec. 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 Sec. 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 Sec. 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, Sec. 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

[[Page 2697]]

monitoring. This is similar to the provision in the retired unit 
exemption concerning loss of the exemption. This means that a unit that 
loses its Sec. 97.4(b) exemption during a control period must (like a 
unit that loses its Sec. 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 Sec. 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., Sec. 97.6(c)(6), 
(f)(1), and (g), Sec. 97.22 (d)(1), and Sec. 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 Sec. 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 Sec. 97.4(a) 
or an exemption under Sec. 97.4(b) or Sec. 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 Sec. 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

[[Page 2698]]

emission 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 Sec. 97.40 
of today's rule. Section 97.40 includes some changes from part 96 and 
the October 21, 1998 section 126 proposal. Under Sec. 96.40, the State 
trading program budget is determined by the State in the SIP. In 
contrast, Sec. 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, Sec. 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 Sec. 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 Sec. 97.2 
and instead explains in Sec. 97.40 that the Administrator will allocate 
each State trading program budget in accordance with Secs. 97.41 and 
97.42. In light of the provisions in Sec. 97.40 and Appendix C, the 
language in the existing Sec. 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 Sec. 97.40 are calculated in a manner consistent with the 
calculation description in Sec. 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 (Secs. 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. NOX Allowance 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

[[Page 2699]]

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 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\
---------------------------------------------------------------------------

    \9\ The Agency notes as well that some consumer benefits could 
result from updating the allocations periodically. The allocation 
report indicated that relative to a permanent allocation system, 
under an updating system, consumers pay less for electricity 
resulting in increased consumer surplus (see Docket A 97-43, 
Category XI-B-01). However, EPA is not relying on such 
considerations in deciding to periodically update allocations.
---------------------------------------------------------------------------

    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

[[Page 2700]]

create 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

[[Page 2701]]

electric 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 
Sec. 52.34(k) is superseded as a matter of law, and today's final rule 
deletes Sec. 52.34(k) accordingly.
    For similar reasons, the provisions in Sec. 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 Sec. 52.34(j)(1) is set forth in more detail in part 97 
(i.e., Secs. 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

[[Page 2702]]

will primarily come as a result of the cap on NOX emissions.
---------------------------------------------------------------------------

    \10\ However, there is an offsetting factor under an updating 
heat input-based allocation method. Efficiency improvements could 
potentially reduce the number of allowances a unit receives in the 
future under that allocation method, thus providing a disincentive 
for efficiency improvements.
---------------------------------------------------------------------------

    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

[[Page 2703]]

Agency 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.
---------------------------------------------------------------------------

    \11\ For example, at what output-based emission rate should new 
sources receive allowances, and if the Agency decides to allocate to 
non-emitting generation sources, what other changes to part 97 are 
necessary to include them in allocations but exclude them from other 
program requirements that are inappropriate for non-emitting 
sources.
---------------------------------------------------------------------------

    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

[[Page 2704]]

Trading 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.
---------------------------------------------------------------------------

    \12\ For utility generators, EPA used net heat rate data from 
Energy Information Administration (EIA) Form 860 for 1995.
---------------------------------------------------------------------------

    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

[[Page 2705]]

accurate, 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

[[Page 2706]]

on 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 Sec. 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

[[Page 2707]]

time. 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) Secs. 97.42(b), (c), and (d) provide for the 
allocation of NOX allowances only to NOX Budget 
units under Sec. 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 
Sec. 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 Secs. 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 
Sec. 97.54 (except deductions under Sec. 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, Sec. 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 Sec. 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. NOX Allowance 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

[[Page 2708]]

update, 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

[[Page 2709]]

sources 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

[[Page 2710]]

control 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).
---------------------------------------------------------------------------

    \13\ The maximum number of years that a source may be required 
to draw from the new source set-aside would be 10 years. For 
example, if a source begins operating on or after May 1, 2003, it 
will not have sufficient data (i.e., data for at least two full 
control periods) to receive an allocation for the 2008-2012 time 
period Therefore, it will need to draw from the new source set-aside 
for 10 years (2003-2012).
---------------------------------------------------------------------------

    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 
Sec. 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

[[Page 2711]]

2008-2012 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) Secs. 97.42(b), (c), and (d) provide for the allocation of 
NOX allowances only to NOX Budget units under 
Sec. 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 Sec. 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.

[[Page 2712]]

Each 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)
------------------------------------------------------------------------
                                                              Compliance
                           State                              supplement
                                                                 pool
------------------------------------------------------------------------
Delaware...................................................          168
District of Columbia.......................................            0
Indiana....................................................        2,454
Kentucky...................................................        7,314
Maryland...................................................        3,882
Michigan...................................................        9,398
New Jersey.................................................        1,550
New York...................................................        1,379
North Carolina.............................................       10,737
Ohio.......................................................       22,301
Pennsylvania...............................................       15,763

[[Page 2713]]

 
Virginia...................................................        5,504
West Virginia..............................................       16,709
        Total..............................................       97,159
------------------------------------------------------------------------

    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 Sec. 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 Sec. 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,

[[Page 2714]]

allowances 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 Sec. 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

[[Page 2715]]

flexibilities 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

[[Page 2716]]

more 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).
---------------------------------------------------------------------------

    \14\ The analysis conducted to estimate the potential early 
reduction credits treated the entire States of Michigan, Indiana, 
Kentucky, and New York. However, the size of the pool (97,159) 
reflects the fact that only portions of these States are actually 
covered. Therefore, in EPA expects the amount of early reduction 
credits to be less and to be closer to the size of the compliance 
supplement pool than the analysis suggests.
---------------------------------------------------------------------------

    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

[[Page 2717]]

alternative 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.)
---------------------------------------------------------------------------

    \15\ The flow control ratio of 0.49 is based on preliminary 
emissions data that has not yet been quality assured by EPA. After 
EPA has quality assured the emissions data the flow control ratio 
listed may change. However, EPA does not expect a significant change 
in its value.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \16\ Consequently, it is still necessary to limit the number of 
allowances in the compliance supplement pool as discussed above.
---------------------------------------------------------------------------

    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

[[Page 2718]]

associated 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 Sec. 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.
---------------------------------------------------------------------------

    \17\ For units in the Acid Rain Program, the limits are 25 tons 
of SO2 and 50 tons of NOX per year. For units 
that are not subject to the Acid Rain Program, such as industrial 
boilers, the limit is 25 tons of NOX per 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 Sec. 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, 
Sec. 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 Sec. 97.71(b)(2), the 
Agency revised language concerning changes to a monitoring system that 
require recertification to be consistent with recent changes to 
Sec. 75.20(b). See 64 FR 28582 and 28594. In addition, EPA revised the 
deadlines in Sec. 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 Sec. 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 Sec. 97.2. Further, the ``heat input'' 
definition itself is revised to state clearly the units of measure 
(i.e., time period, mmBtu,

[[Page 2719]]

Btu, 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 Secs. 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 Sec. 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 Sec. 97.71(c) for provisional certification of the 
low mass emissions excepted methodology under Sec. 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 
Sec. 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 
Sec. 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 Sec. 97.71(c)), as well as to the 
procedures for monitoring equipment under Sec. 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, Sec. 97.70(b) includes minor word changes that restate the 
compliance deadlines in proposed Sec. 97.70(b) to distinguish more 
clearly among the deadlines based on whether the unit is under 
Sec. 97.4(a)(1) or Sec. 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 Secs. 97.70(a)(1) through (3) and that data must be 
recorded, reported and quality assured. Second, proposed 
Sec. 97.70(c)(1) is removed because it essentially duplicates 
Sec. 97.70(b)(2). Third, in Sec. 97.70, EPA removed references to 
certain non-NOX Budget units i.e., units on a common stack 
with NOX Budget units under Sec. 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, Sec. 97.71(b) 
introductory text is reordered and revised to make it clear that 
Secs. 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 Sec. 75.66 is added to Sec. 97.75(b) to make it 
clear that the requirements of Sec. 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

[[Page 2720]]

imposing 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 Sec. 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 Sec. 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

[[Page 2721]]

been 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 $3.6 million (1997$).
---------------------------------------------------------------------------

    \18\ Specifically, the VSLY estimate is calculated by amortizing 
the $5.9 million mean VSL estimate over the 35 years of life 
expectancy associated with subjects in the labor market studies. The 
resulting estimate, using a 5 percent discount rate, is $360,000 per 
life-year saved in 1997 dollars. This annual average value of a 
life-year is then multiplied times the number of years of remaining 
life expectancy for the affected population (in the case of PM-
related premature mortality, the average number of $ life-years 
saved is 14.
---------------------------------------------------------------------------

    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

[[Page 2722]]

some 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:

------------------------------------------------------------------------
                                                        Size standard in
                                                            number of
           SIC Code                Economic activity      employees or
                                                           millions of
                                                             dollars
------------------------------------------------------------------------
2611..........................  Pulp mills............  750
2821..........................  Plastics materials,     750
                                 synthetic resins, and
                                 nonvulcanized
                                 elastomers.
2869..........................  Industrial organic      1,000
                                 chemicals.
2911..........................  Petroleum refining....  1,500
3312..........................  Steel works, blast      1,000
                                 furnaces, and rolling
                                 mills.
3511..........................  Steam, gas, and         1,000
                                 hydraulic turbines.
3519..........................  Stationary internal     1,000
                                 combustion engines.
3585..........................  Air-conditioning and    750
                                 warm-air heating
                                 equipment and
                                 commercial and
                                 industrial
                                 refrigeration
                                 equipment.
4911..........................  Electric utilities....  4 million
                                                         megawatt hrs.
4922..........................  Natural gas             $5.0
                                 transmission.
4931..........................  Electric and other gas  $5.0
                                 services.
4961..........................  Steam and air           $9.0
                                 conditioning supply.
------------------------------------------------------------------------

    (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

[[Page 2723]]

can 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

[[Page 2724]]

under 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

[[Page 2725]]

significantly 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 Sec. 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).
---------------------------------------------------------------------------

    \19\ The EPA interpreted some of the same provisions in the SIP 
Call final rule, and the U.S. Court of Appeals for the D.C. Circuit 
agreed with the Administrator that the rule was nationally 
significant and thus, that venue lies in that circuit. See State of 
Michigan v. EPA, No. 98-1497 (D.C. Cir., Order, Mar. 19, 1999) 
(citing Texas Municipal Power Agency v. EPA, 89 F.3d 858, 867 (D.C. 
Cir. 1996) (per curiam)).
---------------------------------------------------------------------------

    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,

[[Page 2726]]

Second 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.

List of Subjects

40 CFR Part 52

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

40 CFR Part 97

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Emissions trading, Intergovernmental relations, 
Nitrogen oxides, Ozone, Ozone transport, Reporting and recordkeeping 
requirements.

    Dated: December 17, 1999.
Carol M. Browner,
Administrator.


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

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

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


Sec. 52.34  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

[[Page 2727]]

section 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 Secs. 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:

PART 97--FEDERAL NOX BUDGET TRADING PROGRAM

Subpart A--NOX Budget Trading Program General Provisions
Sec.
97.1  Purpose.
97.2  Definitions.
97.3  Measurements, abbreviations, and acronyms.
97.4  Applicability.
97.5  Retired unit exemption.
97.6  Standard requirements.
97.7  Computation of time.
Subpart B--NOX Authorized Account Representative for 
NOX Budget Sources
97.10  Authorization and responsibilities of 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)

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

Subpart A--NOX Budget Trading Program General Provisions


Sec. 97.1  Purpose.

    This part establishes general provisions and the applicability, 
permitting, allowance, excess emissions, monitoring, and opt-in 
provisions for the federal NOX Budget Trading Program, under 
section 126 of the CAA and Sec. 52.34 of this chapter, as a means of 
mitigating the interstate transport of ozone and nitrogen oxides, an 
ozone precursor.

[[Page 2728]]

Sec. 97.2  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 Sec. 72.2 of 
this chapter, a limitation on emissions of sulfur dioxide or nitrogen 
oxides under the Acid Rain Program under title IV of the Clean Air Act.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, 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 Sec. 97.4(b), Sec. 97.5, or 
subpart I of this part, for a unit that is a NOX Budget unit 
under Sec. 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 Sec. 97.4(b), Sec. 97.5, or subpart I 
of this part, for a unit that is not a NOX Budget unit under 
Sec. 97.4(a) on the date the unit commences commercial operation, the 
date the unit becomes a NOX Budget unit under Sec. 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 Sec. 97.4(b), 
Sec. 97.5, or subpart I of this part for a unit that is a 
NOX Budget unit under Sec. 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 Sec. 97.4(b), 
Sec. 97.5, or subpart I of this part, for a unit that is not a 
NOX Budget unit under Sec. 97.4(a) on the date of 
commencement of operation, the date the unit becomes a NOX 
Budget unit under Sec. 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

[[Page 2729]]

any year, provided that the unit shall be ``fossil fuel-fired'' as of 
the date, during such year, on which the unit begins combusting fossil 
fuel.
    General account means a NOX Allowance Tracking System 
account, established under subpart F of this part, that is not a 
compliance account or an overdraft account.
    Generator means a device that produces electricity.
    Heat input means, 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 NOX emission rate means the emission 
rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with 
section 3 of appendix F of part 75 of this chapter, using the maximum 
potential 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 NOX emissions 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.
    NOX allowance 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 
Sec. 97.54(f). No provision of the NOX Budget Trading 
Program, the NOX Budget permit application, the 
NOX Budget permit, or an exemption under Sec. 97.4(b) or 
Sec. 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 Sec. 97.41, Sec. 97.42, Sec. 97.43, 
or Sec. 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 Sec. 51.121 of this 
chapter.
    NOX allowance deduction or deduct NOX 
allowances means the permanent withdrawal of NOX allowances 
by the Administrator from a NOX Allowance Tracking System 
compliance account or overdraft account to account for the number of 
tons of NOX emissions from a NOX Budget unit for 
a control period, determined in accordance with subparts H and F of 
this part, or for any other NOX allowance withdrawal 
requirement under this part.
    NOX Allowance Tracking System means the system by which 
the Administrator records allocations, deductions, and transfers of 
NOX allowances under the NOX Budget Trading 
Program.
    NOX Allowance Tracking System account means an account 
in the NOX Allowance Tracking System established by the 
Administrator for purposes of recording the allocation, holding, 
transferring, or deducting of NOX allowances.
    NOX allowance transfer deadline means midnight of 
November 30 or, if November 30 is not a business day, midnight of the 
first business day thereafter and is the deadline by which 
NOX allowances 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.
    NOX allowances held or hold NOX allowances 
means the NOX allowances recorded by the Administrator, or 
submitted to the Administrator for recordation, in accordance with

[[Page 2730]]

subparts F and G of this part, in a NOX Allowance Tracking 
System account.
    NOX authorized account representative means, for a 
NOX Budget source or NOX Budget unit at the 
source, the natural person who is authorized by the owners and 
operators of the source and all NOX Budget units at the 
source, in accordance with subpart B of this part, to represent and 
legally bind each owner and operator in matters pertaining to the 
NOX Budget Trading Program or, for a general account, the 
natural person who is authorized, in accordance with subpart F of this 
part, to transfer or otherwise dispose of NOX allowances 
held in the general account.
    NOX Budget emissions limitation means, for a 
NOX Budget unit, the tonnage equivalent of the 
NOX allowances available for compliance deduction for the 
unit under Sec. 97.54(a), (b), (e), and (f) in a control period 
adjusted by deductions of such NOX allowances to account for 
actual heat input under Sec. 97.42(e) for the control period or to 
account for excess emissions for a prior control period under 
Sec. 97.54(d) or to account for withdrawal from the NOX 
Budget Trading Program, or for a change in regulatory status, of a 
NOX Budget opt-in unit under Sec. 97.86 or Sec. 97.87.
    NOX Budget opt-in permit means a NOX Budget 
permit covering a NOX Budget opt-in unit.
    NOX Budget 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.
    NOX Budget permit means the legally binding and 
federally enforceable written document, or portion of such document, 
issued by the permitting authority under this part, including any 
permit revisions, specifying the NOX Budget Trading Program 
requirements applicable to a NOX Budget source, to each 
NOX Budget unit at the NOX Budget source, and to 
the owners and operators and the NOX authorized account 
representative of the NOX Budget source and each 
NOX Budget unit.
    NOX Budget source means a source that includes one or 
more NOX Budget units.
    NOX Budget Trading Program means a multistate nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator in accordance with this part and pursuant to 
Sec. 52.34 of this chapter, as a means of mitigating the interstate 
transport of ozone and nitrogen oxides, an ozone precursor.
    NOX Budget unit means a unit that is subject to the 
NOX Budget Trading Program emissions limitation under 
Sec. 97.4(a) or Sec. 97.80.
    Operating means, with regard to a unit under Secs. 97.22(d)(2) and 
97.80, having documented heat input for more than 876 hours in the 6 
months immediately preceding the submission of an application for an 
initial NOX Budget permit under Sec. 97.83(a). 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 Sec. 97.83 is submitted and not denied or withdrawn and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such a unit or source.
    Opt-in means to be elected to become a NOX Budget unit 
under the NOX Budget Trading Program through a final, 
effective NOX Budget opt-in permit under subpart I of this 
part.
    Overdraft account means the NOX Allowance Tracking 
System account, established by the Administrator under subpart F of 
this part, for each NOX Budget source where there are two or 
more NOX Budget units.
    Owner means any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
NOX Budget unit or in a unit for which an application for a 
NOX Budget opt-in permit under Sec. 97.83 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 Sec. 97.83 is submitted and not denied or 
withdrawn; or
    (3) Any purchaser of power from a NOX Budget unit or 
from a unit for which an application for a NOX Budget opt-in 
permit under Sec. 97.83 is submitted and not denied or withdrawn under 
a life-of-the-unit, firm power contractual arrangement. However, unless 
expressly provided for in a leasehold agreement, owner shall not 
include a passive lessor, or a person who has an equitable interest 
through such lessor, whose rental payments are not based, either 
directly or indirectly, upon the revenues or income from the 
NOX Budget unit or the unit for which an application for a 
NOX Budget opt-in permit under Sec. 97.83 is submitted and 
not denied or withdrawn; or
    (4) With respect to any general account, any person who has an 
ownership interest with respect to the NOX allowances held 
in the general account and who is subject to the binding agreement for 
the NOX authorized account representative to represent that 
person's ownership interest with respect to NOX allowances.
    Percent monitor data availability means, for purposes of Sec. 97.43 
(a)(1) and Sec. 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 Sec. 97.53(c).
    Source means any governmental, institutional, commercial, or 
industrial structure, installation, plant, building, or facility that 
emits or has the potential to emit any regulated air pollutant under 
the Clean Air Act. For purposes of section 502(c) of the Clean Air Act, 
a ``source,'' including a ``source'' with multiple units, shall be 
considered a single ``facility.''

[[Page 2731]]

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


Sec. 97.3  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.


Sec. 97.4  Applicability.

    (a) The following units in a State (as defined in Sec. 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), Sec. 97.2, Sec. 97.3, Sec. 97.4(a), Sec. 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 Sec. 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 Secs. 97.41(a) through (c) and 97.42(a) through (c). For 
each control period for which the unit is allocated NOX 
allowances under Secs. 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 Secs. 97.41(a) through (c) and 97.42(a)

[[Page 2732]]

through (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 
Secs. 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.


Sec. 97.5  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, Sec. 97.2, Sec. 97.3, Sec. 97.4, Sec. 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 Sec. 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 Sec. 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

[[Page 2733]]

exemption under this section shall be treated as a unit that commences 
operation or commercial operation on the first date on which the unit 
resumes operation.
    (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.


Sec. 97.6  Standard requirements.

    (a) Permit requirements. (1) The NOX authorized account 
representative of each NOX Budget source required to have a 
federally enforceable permit and each NOX Budget unit 
required to have a federally enforceable permit at the source shall:
    (i) Submit to the permitting authority a complete NOX 
Budget permit application under Sec. 97.22 in accordance with the 
deadlines specified in Sec. 97.21(b) and (c);
    (ii) Submit in a timely manner any supplemental information that 
the permitting authority determines is necessary in order to review a 
NOX Budget permit application and issue or deny a 
NOX Budget permit.
    (2) The owners and operators of each NOX Budget source 
required to have a federally enforceable permit and each NOX 
Budget unit required to have a federally enforceable permit at the 
source shall have a NOX Budget permit issued by the 
permitting authority and operate the unit in compliance with such 
NOX Budget permit.
    (3) The owners and operators of a NOX Budget source that 
is not otherwise required to have a federally enforceable permit are 
not required to submit a NOX Budget permit application, and 
to have a NOX Budget permit, under subpart C of this part 
for such NOX Budget source.
    (b) Monitoring requirements. (1) The owners and operators and, to 
the extent applicable, the NOX authorized account 
representative of each NOX Budget source and each 
NOX Budget unit at the source shall comply with the 
monitoring requirements of subpart H of this part.
    (2) The emissions measurements recorded and reported in accordance 
with subpart H of this part shall be used to determine compliance by 
the unit with the NOX Budget emissions limitation under 
paragraph (c) of this section.
    (c) Nitrogen oxides requirements. (1) The owners and operators of 
each NOX Budget source and each NOX Budget unit 
at the source shall hold NOX allowances available for 
compliance deductions under Sec. 97.54(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 Sec. 97.42(e) 
for the control period or to account for excess emissions for a prior 
control period under Sec. 97.54(d) or to account for withdrawal from 
the NOX Budget Trading Program, or a change in regulatory 
status, of a NOX Budget opt-in unit under Sec. 97.86 or 
Sec. 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 Sec. 97.4(b) or 
Sec. 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 Sec. 97.54(d)(1); and
    (ii) Pay any fine, penalty, or assessment or comply with any other 
remedy imposed under Sec. 97.54(d)(3).
    (e) Recordkeeping and reporting requirements. (1) Unless otherwise 
provided, the owners and operators of the NOX Budget source 
and each NOX Budget unit at the source shall keep on site at 
the source each of the following documents for a period of 5 years from 
the date the document is created. This period may be extended for 
cause, at any time prior to the end of 5 years, in writing by the 
permitting authority or the Administrator.
    (i) The account certificate of representation under Sec. 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 Sec. 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 
Sec. 97.4(b) or Sec. 97.5 shall be subject to enforcement pursuant to 
applicable State or Federal law.
    (2) Any person who knowingly makes a false material statement in 
any record, submission, or report under the NOX Budget 
Trading Program shall be subject

[[Page 2734]]

to criminal enforcement pursuant to the applicable State or Federal 
law.
    (3) No permit revision shall excuse any violation of the 
requirements of the NOX Budget Trading Program that occurs 
prior to the date that the revision takes effect.
    (4) Each NOX Budget source and each NOX 
Budget unit shall meet the requirements of the NOX Budget 
Trading Program.
    (5) Any provision of the NOX Budget Trading Program that 
applies to a NOX Budget source 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 Sec. 97.4(b) or 
Sec. 97.5 shall be construed as exempting or excluding the owners and 
operators and, to the extent applicable, the NOX authorized 
account representative of a NOX Budget source or 
NOX Budget unit from compliance with any other provision of 
the applicable, approved State implementation plan, a federally 
enforceable permit, or the Clean Air Act.


Sec. 97.7  Computation of time.

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

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


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

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


Sec. 97.11  Alternate NOX authorized account representative.

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


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

    (a) Changing NOX authorized account representative. The 
NOX authorized account representative may be changed at any 
time upon receipt by the Administrator of a superseding complete 
account certificate of representation under Sec. 97.13. Notwithstanding 
any such change, all representations, actions, inactions, and 
submissions by the previous NOX authorized account 
representative prior to the time and date when the

[[Page 2735]]

Administrator receives the superseding account certificate of 
representation shall be binding on the new NOX authorized 
account representative and the owners and operators of the 
NOX Budget source and the NOX Budget units at the 
source.
    (b) Changing alternate NOX authorized account 
representative. The alternate NOX authorized account 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete account certificate of 
representation under Sec. 97.13. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate NOX authorized account representative prior to the 
time and date when the Administrator receives the superseding account 
certificate of representation shall be binding on the new alternate 
NOX authorized account representative and the owners and 
operators of the NOX Budget source and the NOX 
Budget units at the source.
    (c) Changes in 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 
Sec. 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 Sec. 97.13 amending the 
list of owners and operators to include the change.


Sec. 97.13  Account certificate of representation.

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


Sec. 97.14  Objections concerning NOX authorized account 
representative.

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

Subpart C--Permits


Sec. 97.20  General NOX Budget Trading Program permit 
requirements.

    (a) For each NOX Budget source required to have a 
federally enforceable permit, such permit shall include a 
NOX Budget permit administered by the permitting authority 
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.


Sec. 97.21  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 Sec. 97.22 by 
the applicable deadline in paragraph (b) of this section.
    (b)(1) For NOX Budget sources required to have a title V 
operating permit:
    (i) For any source, with one or more NOX Budget units 
under Sec. 97.4(a) that

[[Page 2736]]

commence operation before January 1, 2000, the NOX 
authorized account representative shall submit a complete 
NOX Budget permit application under Sec. 97.22 covering such 
NOX Budget units to the permitting authority at least 18 
months (or such lesser time provided by the permitting authority) 
before May 1, 2003.
    (ii) For any source, with any NOX Budget unit under 
Sec. 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 Sec. 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 Sec. 97.4(a) that commence operation before January 1, 2000, the 
NOX authorized account representative shall submit a 
complete NOX Budget permit application under Sec. 97.22 
covering such NOX Budget units to the permitting authority 
at least 18 months (or such lesser time provided by the permitting 
authority) before May 1, 2003.
    (ii) For any source, with any NOX Budget unit under 
Sec. 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 Sec. 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 Sec. 97.22 for the 
NOX Budget source covering the NOX Budget units 
at the source in accordance with the permitting authority's title V 
operating permits regulations addressing operating permit renewal.
    (2) For a NOX Budget source required to have a non-title 
V permit, the NOX authorized account representative shall 
submit a complete NOX Budget permit application under 
Sec. 97.22 for the NOX Budget source covering the 
NOX Budget units at the source in accordance with the 
permitting authority's non-title V permits regulations addressing 
permit renewal.


Sec. 97.22  Information requirements for NOX Budget permit 
applications.

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


Sec. 97.23  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 Sec. 97.22.
    (b) Each NOX Budget permit is deemed to incorporate 
automatically the definitions of terms under Sec. 97.2 and, upon 
recordation by the Administrator under 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.


Sec. 97.24  NOX Budget permit revisions.

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

Subpart D--Compliance Certification


Sec. 97.30  Compliance certification report.

    (a) Applicability and deadline. For each control period in which 
one or more NOX Budget units at a source are subject to the 
NOX Budget emissions limitation, the NOX 
authorized account representative of the source shall submit to the 
permitting authority and the Administrator by November 30 of that year, 
a compliance certification report for each source covering all such 
units.
    (b) Contents of report. The NOX authorized account 
representative shall include in the compliance certification report 
under paragraph (a) of this section the following elements, in a format 
prescribed by the Administrator, concerning each unit at the source and 
subject to the NOX Budget emissions limitation for the 
control period covered by the report:
    (1) Identification of each NOX Budget unit;
    (2) At the NOX authorized account representative's 
option, the serial numbers of the NOX allowances that are to 
be deducted from each unit's compliance account under Sec. 97.54 for 
the control period;
    (3) At the NOX authorized account representative's 
option, for units sharing a common stack and having NOX 
emissions that are not monitored separately or apportioned in 
accordance with subpart H of this part, the percentage of allowances 
that is to be deducted from each unit's compliance account under 
Sec. 97.54(e); and
    (4) The compliance certification under paragraph (c) of this 
section.
    (c) Compliance certification. In the compliance certification 
report under paragraph (a) of this section, the NOX 
authorized account representative shall certify, based on reasonable 
inquiry of those persons with primary responsibility for operating the 
source and the NOX Budget units at the source in compliance 
with the NOX Budget Trading Program, whether each 
NOX Budget unit for which the compliance certification is 
submitted was operated during the calendar year covered by the report 
in compliance with the requirements of the NOX Budget 
Trading Program applicable to the unit, including:
    (1) Whether the unit was operated in compliance with the 
NOX Budget emissions limitation;
    (2) Whether the monitoring plan that governs the unit has been 
maintained to reflect the actual operation and

[[Page 2737]]

monitoring of the unit and contains all information necessary to 
attribute NOX emissions to the unit, in accordance with 
subpart H of this part;
    (3) Whether all the NOX emissions from the unit, or a 
group of units (including the unit) using a common stack, were 
monitored or accounted for through the missing data procedures and 
reported in the quarterly monitoring reports, including whether 
conditional data were reported in the quarterly reports in accordance 
with subpart H of this part. If conditional data were reported, the 
owner or operator shall indicate whether the status of all conditional 
data has been resolved and all necessary quarterly report resubmissions 
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.


Sec. 97.31  Administrator's action on compliance certifications.

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

Subpart E--NOX Allowance Allocations


Sec. 97.40  Trading program budget.

    In accordance with Secs. 97.41 and 97.42, the Administrator will 
allocate to the NOX Budget units under Sec. 97.4(a) in a 
State, for each control period specified in Sec. 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 Sec. 97.4(b) that is not allocated any NOX allowances 
under Sec. 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 Sec. 97.42(d)(5)(ii)(B) for the 
control period.


Sec. 97.41  Timing requirements for NOX allowance 
allocations.

    (a) The NOX allowance allocations, determined in 
accordance with Secs. 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 Secs. 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 Secs. 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 Sec. 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 
Sec. 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 Sec. 97.42.


Sec. 97.42  NOX allowance allocations.

    (a)(1) The heat input (in mmBtu) used for calculating 
NOX allowance allocations for each NOX Budget 
unit under Sec. 97.4(a) will be:
    (i) For a NOX allowance allocation under Sec. 97.41(a):
    (A) For a unit under Sec. 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 Sec. 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 Sec. 97.41(b), 
the unit's average heat input for the control periods in 2002 through 
2004.
    (iii) For a NOX allowance allocation under 
Sec. 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 Sec. 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 Sec. 97.41(b) 
or (c) for a unit exempt under Sec. 97.4(b), such heat input shall be 
treated as zero if the unit is exempt under Sec. 97.4(b) during the 
control period.
    (b) For each group of five control periods specified in 
Sec. 97.41(a) through (c), the Administrator will allocate to all 
NOX Budget units in a given State under Sec. 97.4(a)(1) that 
commenced operation before May 1, 1997 for allocations under 
Sec. 97.41(a), May 1, 2003 for allocations under Sec. 97.41(b), and May 
1 of the year 5 years before the first year for which the allocation 
under Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.40 covering

[[Page 2738]]

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 (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 
Sec. 97.41(a) through (c), the Administrator will allocate to all 
NOX Budget units in a given State under Sec. 97.4(a)(2) that 
commenced operation before May 1, 1997 for allocations under 
Sec. 97.41(a), May 1, 2003 for allocations under Sec. 97.41(b), and May 
1 of the year 5 years before the first year for which the allocation 
under Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 
Sec. 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 Sec. 97.41(d), the 
Administrator will allocate NOX allowances to NOX 
Budget units in a given State under Sec. 97.4(a) (except for units 
exempt under Sec. 97.4(b)) that commence operation, or are projected to 
commence operation, on or after: May 1, 1997 (for control periods under 
Sec. 97.41(a)); May 1, 2003, (for control periods under Sec. 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 
Sec. 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 
Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 97.41(a)); May 1, 2003, (for 
control periods under Sec. 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 Sec. 97.41(c)), the sum of the 
NOX emission limitations (in tons of NOX) on 
which each unit's exemption under Sec. 97.4(b) is based.
    (iii) If the number of NOX allowances in the allocation 
set-aside for the control

[[Page 2739]]

period 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 Sec. 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 Sec. 97.4(a)(1) = Unit's NOX allowances allocated for 
control period-(Unit's actual control period heat input x 0.15 lb/mmBtu 
 x  2,000 lb/ton); and NOX allowances deducted for actual 
heat input for a unit under Sec. 97.4(a)(2) = Unit's NOX 
allowances allocated for control period-(Unit's actual control period 
heat input  x  0.17 lb/mmBtu  x  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 Sec. 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  x  (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 Sec. 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 Sec. 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 Sec. 97.53;
    (ii) If the Administrator already recorded such NOX 
allowances for the control period in an account under Sec. 97.53 and if 
the Administrator makes such determination before making all deductions 
pursuant to Sec. 97.54 (except deductions pursuant to Sec. 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 Sec. 97.53 and if 
the Administrator makes such determination after making all deductions 
pursuant to Sec. 97.54 (except deductions pursuant to Sec. 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.


Sec. 97.43  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.

[[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  x  (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 Sec. 97.54 for the 
control period in 2003 or 2004. Notwithstanding Sec. 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 Sec. 97.54 for the control period in 2003 
or 2004.
    (8) NOX allowances recorded under paragraph (c)(6) of 
this section are treated as banked allowances in 2004 for the purposes 
of Secs. 97.54(f) and 97.55(b).

Subpart F--NOX Allowance Tracking System


Sec. 97.50  NOX Allowance Tracking System accounts.

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

[[Page 2741]]

    (b) Nature and function of general accounts. Consistent with 
Sec. 97.51(b), the Administrator will establish, upon request, a 
general account for any person. Allocations of NOX 
allowances pursuant to Sec. 97.4(b)(4)(ii) or Sec. 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.


Sec. 97.51  Establishment of accounts.

    (a) Compliance accounts and overdraft accounts. Upon receipt of a 
complete account certificate of representation under Sec. 97.13, the 
Administrator will establish:
    (1) A compliance account for each NOX Budget unit for 
which the account certificate of representation was submitted; and
    (2) An overdraft account for each source for which the account 
certificate of representation was submitted and that has two or more 
NOX Budget units.
    (b) General accounts.--(1) 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 NOX authorized 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 NOX authorized account representative and 
alternate NOX authorized 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,

[[Page 2742]]

actions, inactions, and submissions by the previous alternate 
NOX authorized account representative prior to the time and 
date when the Administrator receives the superseding application for a 
general account shall be binding on the new alternate NOX 
authorized account representative and the persons with an ownership 
interest with respect to the 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 NOX authorized 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.


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

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


Sec. 97.53  Recordation of NOX allowance allocations.

    (a) The Administrator will record the NOX allowances for 
2003 for a NOX Budget unit allocated under subpart E of this 
part in the unit's compliance account, except for NOX 
allowances under Sec. 97.4(b)(4)(ii) or Sec. 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 Sec. 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 Sec. 97.4(b)(4)(ii) 
or Sec. 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 
Sec. 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 Sec. 97.4(b)(4)(ii) 
or Sec. 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 
Sec. 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 Sec. 97.4(b)(4)(ii) 
or Sec. 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 
Sec. 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 Sec. 97.54 (except deductions 
pursuant to Sec. 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 
Sec. 97.4(b)(4)(ii) or Sec. 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 Sec. 97.88(a).
    (f) Serial numbers for allocated NOX allowances. 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.


Sec. 97.54  Compliance.

    (a) NOX allowance transfer deadline. The NOX 
allowances are available to be deducted for compliance with a unit's 
NOX Budget emissions limitation for a control period in a 
given year only if the NOX allowances:
    (1) Were allocated for a control period in a prior year or the same 
year; and
    (2) Are held in the unit's compliance account, or the overdraft 
account of the source where the unit is located, as of the 
NOX allowance transfer deadline for that control period or 
are transferred into the compliance account or

[[Page 2743]]

overdraft account by a NOX allowance transfer correctly 
submitted for recordation under Sec. 97.60 by the NOX 
allowance transfer deadline for that control period.
    (b) Deductions for compliance. (1) Following the recordation, in 
accordance with Sec. 97.61, of NOX allowance transfers 
submitted for recordation in the unit's compliance account or the 
overdraft account of the source where the unit is located by the 
NOX allowance transfer deadline for a control period, the 
Administrator will deduct NOX allowances available under 
paragraph (a) of this section to cover the unit's NOX 
emissions (as determined in accordance with subpart H of this part), or 
to account for actual heat input under Sec. 97.42(e), for the control 
period:
    (i) From the compliance account; and
    (ii) Only if no more NOX allowances available under 
paragraph (a) of this section remain in the compliance account, from 
the overdraft account. In deducting allowances for units at the source 
from the overdraft account, the Administrator will begin with the unit 
having the compliance account with the lowest 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 Sec. 97.42(e) for the control period; or
    (ii) Until no more NOX allowances available under 
paragraph (a) of this section remain in the respective account.
    (c)(1) Identification of NOX allowances by serial 
number. The NOX authorized account representative for each 
compliance account may identify by serial number the NOX 
allowances to be deducted from the unit's compliance account under 
paragraph (b), (d), (e), or (f) of this section. Such identification 
shall be made in the compliance certification report submitted in 
accordance with Sec. 97.30.
    (2) First-in, first-out. The Administrator will deduct 
NOX allowances for a control period from the compliance 
account, in the absence of an identification or in the case of a 
partial identification of NOX allowances by serial number 
under paragraph (c)(1) of this section, or the overdraft account on a 
first-in, first-out (FIFO) accounting basis in the following order:
    (i) Those NOX allowances that were allocated for the 
control period to the unit under subpart E or I of this part;
    (ii) Those NOX allowances that were allocated for the 
control period to any unit and transferred and recorded in the account 
pursuant to subpart G of this part, in order of their date of 
recordation;
    (iii) Those NOX allowances that were allocated for a 
prior control period to the unit under subpart E or I of this part; and
    (iv) Those NOX allowances that were allocated for a 
prior control period to any unit and transferred and recorded in the 
account pursuant to subpart G of this part, in order of their date of 
recordation.
    (d) Deductions for excess emissions. (1) After making the 
deductions for compliance under paragraph (b) of this section, the 
Administrator will deduct from the unit's compliance account or the 
overdraft account of the source where the unit is located a number of 
NOX allowances, allocated for a control period after the 
control period in which the unit has excess emissions, equal to three 
times the number of the unit's excess emissions.
    (2) If the compliance account or overdraft account does not contain 
sufficient NOX allowances, the Administrator will deduct the 
required number of NOX allowances, regardless of the control 
period for which they were allocated, whenever NOX 
allowances are recorded in either account.
    (3) Any allowance deduction required under paragraph (d) of this 
section shall not affect the liability of the owners and operators of 
the NOX Budget unit for any fine, penalty, or assessment, or 
their obligation to comply with any other remedy, for the same 
violation, as ordered under the Clean Air Act or applicable State law. 
The following guidelines will be followed in assessing fines, penalties 
or other obligations:
    (i) For purposes of determining the number of days of violation, if 
a NOX Budget unit has excess emissions for a control period, 
each day in the control period (153 days) constitutes a day in 
violation unless the owners and operators of the unit demonstrate that 
a lesser number of days should be considered.
    (ii) Each ton of excess emissions is a separate violation.
    (e) Deductions for units sharing a common stack. In the case of 
units sharing a common stack and having emissions that are not 
separately monitored or apportioned in accordance with subpart H of 
this part:
    (1) The NOX authorized account representative of the 
units may identify the percentage of NOX allowances to be 
deducted from each such unit's compliance account to cover the unit's 
share of NOX emissions from the common stack for a control 
period. Such identification shall be made in the compliance 
certification report submitted in accordance with Sec. 97.30.
    (2) Notwithstanding paragraph (b)(2)(i) of this section, the 
Administrator will deduct NOX allowances for each such unit 
until the number of NOX allowances deducted equals the 
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 Sec. 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 Sec. 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 Sec. 97.40 for all States for the control period, any banked 
NOX allowance may be deducted for compliance in

[[Page 2744]]

accordance 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 Sec. 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 Sec. 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.


Sec. 97.55  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 Sec. 97.31, Sec. 97.54, Sec. 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 Sec. 97.54 
(except deductions pursuant to Sec. 97.54(d)(2)) and that was allocated 
for that control period or a control period in a prior year.


Sec. 97.56  Account error.

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


Sec. 97.57  Closing of general accounts.

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

Subpart G--NOX Allowance Transfers


Sec. 97.60  Submission of NOX allowance transfers.

    The NOX authorized account representatives seeking 
recordation of a NOX allowance transfer shall submit the 
transfer to the Administrator. To be considered correctly submitted, 
the NOX allowance transfer shall include the following 
elements in a format specified by the Administrator:
    (a) The numbers identifying both the 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.


Sec. 97.61  EPA recordation.

    (a) Within 5 business days of receiving a NOX allowance 
transfer, except as provided in paragraph (b) of this section, the 
Administrator will record a NOX allowance transfer by moving 
each NOX allowance from the transferor account to the 
transferee account as specified by the request, provided that:
    (1) The transfer is correctly submitted under Sec. 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 
Sec. 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.


Sec. 97.62  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a NOX allowance transfer under Sec. 97.61, 
the Administrator will notify 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 Sec. 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.

[[Page 2745]]

Subpart H--Monitoring and Reporting


Sec. 97.70  General requirements.

    The owners and operators, and to the extent applicable, the 
NOX authorized account representative of a NOX 
Budget unit, shall comply with the monitoring, 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 Sec. 97.2 and in Sec. 72.2 of this 
chapter shall apply, and the terms ``affected unit,'' ``designated 
representative,'' and ``continuous emission monitoring system'' (or 
``CEMS'') in part 75 of this chapter shall be deemed to refer to the 
terms ``NOX Budget unit,'' ``NOX authorized 
account representative,'' and ``continuous emission monitoring system'' 
(or ``CEMS'') respectively, as defined in Sec. 97.2. The owner or 
operator of a unit that is not a NOX Budget unit but that is 
monitored under Sec. 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 
Secs. 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 
Sec. 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 Sec. 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 
Sec. 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 
Sec. 97.4(a)(1) that commences operation on or after January 1, 2002 
and that reports on an annual basis under Sec. 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 
Sec. 97.4(a)(1) that commences operation on or after January 1, 2002 
and that reports on a control period basis under Sec. 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 
Sec. 97.4(a)(2) that commences operation on or after January 1, 2002 
and that reports on an annual basis under Sec. 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 
Sec. 97.4(a)(2) that commences operation on or after January 1, 2002 
and that report on a control period basis under Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 Sec. 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

[[Page 2746]]

recertification or periods when calibration, quality assurance testing, 
or maintenance is performed in accordance with the applicable 
provisions of this subpart and part 75 of this chapter or except as 
provided in Sec. 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 Sec. 97.4(b) or Sec. 97.5 that is in effect;
    (ii) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system approved, in accordance with 
the applicable provisions of this subpart and part 75 of this chapter, 
by the permitting authority for use at that unit that provides emission 
data for the same pollutant or parameter as the retired or discontinued 
monitoring system; or
    (iii) The NOX authorized account representative submits 
notification of the date of certification testing of a replacement 
monitoring system for the retired or discontinued monitoring system in 
accordance with Sec. 97.71(b)(2).


Sec. 97.71  Initial certification and recertification procedures.

    (a) The owner or operator of a NOX Budget unit that is 
subject to an Acid Rain emissions limitation shall comply with the 
initial certification and recertification procedures of part 75 of this 
chapter, except that:
    (1) If, prior to January 1, 1998, the Administrator approved a 
petition under Sec. 75.17(a) or (b) of this chapter for apportioning 
the NOX emission rate measured in a common stack or a 
petition under Sec. 75.66 of this chapter for an alternative to a 
requirement in Sec. 75.17 of this chapter, the NOX 
authorized account representative shall resubmit the petition to the 
Administrator under Sec. 97.75(a) to determine if the approval applies 
under the NOX Budget Trading Program.
    (2) For any additional CEMS required under the common stack 
provisions in Sec. 75.72 of this chapter or for any NOX 
concentration CEMS used under the provisions of Sec. 75.71(a)(2) of 
this chapter, the owner or operator shall meet the requirements of 
paragraph (b) of this section.
    (b) The owner or operator of a NOX Budget unit that is 
not subject to an Acid Rain emissions limitation shall comply with the 
following initial certification and recertification procedures. The 
owner or operator of such a unit that qualifies to use the low mass 
emissions excepted monitoring methodology under Sec. 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 Sec. 75.72 of this chapter or uses a 
NOX concentration CEMS under Sec. 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 Sec. 75.20 of this chapter by the 
applicable deadline in Sec. 97.70(b). In addition, whenever the owner 
or operator installs a monitoring system in order to meet the 
requirements of this part in a location where no such monitoring system 
was previously installed, initial certification in accordance with 
Sec. 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 Sec. 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 Sec. 75.20(b) 
of this chapter. Furthermore, whenever the owner or operator makes a 
replacement, modification, or change to the flue gas handling system or 
the unit's operation that may significantly change the stack flow or 
concentration profile, the owner or operator shall recertify the 
continuous emissions monitoring system in accordance with Sec. 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 
Sec. 97.73.
    (ii) Certification application. The NOX authorized 
account representative shall submit to the Administrator, the 
appropriate EPA Regional Office and the permitting authority a 
certification application for each monitoring system required under 
subpart H of part 75 of this chapter. A complete certification 
application shall include the information specified in subpart H of 
part 75 of this chapter.
    (iii) Except for units using the low mass emission excepted 
methodology under Sec. 75.19 of this chapter, the provisional 
certification date for a monitor shall be determined in accordance with 
Sec. 75.20(a)(3) of this chapter. A provisionally certified monitor may 
be used under the NOX Budget Trading Program for a period 
not to exceed 120 days after receipt by the Administrator of the 
complete certification application for the monitoring system or 
component thereof under paragraph (b)(3)(ii) of this section. Data 
measured and recorded by the provisionally certified monitoring system 
or component thereof, in accordance with the requirements of part 75 of 
this chapter, will be considered valid quality-assured data 
(retroactive to the date and time of provisional certification), 
provided that the Administrator does not invalidate the provisional 
certification by issuing a notice of disapproval within 120 days of 
receipt of the complete certification application by the Administrator.
    (iv) Certification application formal approval process. The 
Administrator will issue a written notice of approval or disapproval of 
the certification application to the owner or operator within 120 days 
of receipt of the complete certification application under paragraph 
(b)(3)(ii) of this section. In the event the Administrator does not 
issue such a notice within such 120-day period, each monitoring system 
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.

[[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 Sec. 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 
Sec. 97.72(b).
    (v) Procedures for loss of certification. If the Administrator 
issues a notice of disapproval of a certification application under 
paragraph (b)(3)(iv)(C) of this section or a notice of disapproval of 
certification status under paragraph (b)(3)(iv)(D) of this section, 
then:
    (A) The owner or operator shall substitute the following values, 
for each hour of unit operation during the period of invalid data 
specified under Sec. 75.20(a)(4)(iii), Sec. 75.20(b)(5), 
Sec. 75.20(h)(4), or Sec. 75.21(e) and continuing until the date and 
hour specified under Sec. 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 Sec. 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 Sec. 75.19 
of this chapter. The owner or operator of a gas-fired or oil-fired unit 
using the low mass emissions excepted methodology under Sec. 75.19 of 
this chapter and not subject to an Acid Rain emissions limitation shall 
meet the applicable general operating requirements of Sec. 75.10 of 
this chapter and the applicable requirements of Sec. 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 Sec. 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 Sec. 75.19 of this chapter 
for the unit and that reports data on an annual basis under 
Sec. 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 Sec. 75.19 of this chapter 
for the unit and that reports on a control season basis under 
Sec. 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.


Sec. 97.72  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 Sec. 97.71 or the 
applicable provisions of part 75 of this chapter, both at the time of 
the initial certification or recertification application submission and 
at the time of the audit, the Administrator will issue a notice of 
disapproval of the certification status of such system or

[[Page 2748]]

component. For the purposes of this paragraph, an audit shall be either 
a field audit or an audit of any information submitted to the 
permitting authority or the Administrator. By issuing the notice of 
disapproval, the Administrator revokes prospectively the certification 
status of the system or component. The data measured and recorded by 
the system or component shall not be considered valid quality-assured 
data from the date of issuance of the notification of the revoked 
certification status until the date and time that the owner or operator 
completes subsequently approved initial certification or 
recertification tests for the system or component.


Sec. 97.73  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 Sec. 75.61 of this chapter.
    (b) For any unit that does not have an Acid Rain emissions 
limitation, the permitting authority may waive the requirement to 
notify the permitting authority in paragraph (a) of this section.


Sec. 97.74  Recordkeeping and reporting.

    (a) General provisions. (1) The NOX authorized account 
representative shall comply with all recordkeeping and reporting 
requirements in this section and with the requirements of 
Sec. 97.10(e)(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 
Sec. 75.62 of this chapter, except that the monitoring plan shall also 
include all of the information required by subpart H of part 75 of this 
chapter.
    (2) The owner or operator of a unit that is not subject to an Acid 
Rain emissions limitation shall comply with requirements of Sec. 75.62 
of this chapter, except that the monitoring plan is only required to 
include the information required by subpart H of part 75 of this 
chapter.
    (c) Certification applications. The NOX authorized 
account representative shall submit an application to the 
Administrator, the appropriate EPA Regional Office, and the permitting 
authority within 45 days after completing all initial certification or 
recertification tests required under Sec. 97.71 including the 
information required under subpart H of part 75 of this chapter.
    (d) Quarterly reports. The NOX authorized account 
representative shall submit quarterly reports, as follows:
    (1) If a unit is subject to an Acid Rain emission limitation or if 
the owner or operator of the NOX budget unit chooses to meet 
the annual reporting requirements of this subpart H, the NOX 
authorized account representative shall submit a quarterly report for 
each calendar quarter beginning with:
    (i) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec. 97.43, the calendar 
quarter that includes the date of initial provisional certification 
under Sec. 97.71(b)(3)(iii) or Sec. 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 Sec. 97.71(b)(3)(iii) or Sec. 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 
Sec. 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 Sec. 97.43, the calendar 
quarter that includes the date of initial provisional certification 
under Sec. 97.71(b)(3)(iii) or Sec. 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 Sec. 97.71(b)(3)(iii) or Sec. 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 Sec. 97.71(b)(3)(iii) or Sec. 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 Sec. 75.64 of this chapter.
    (i) For units subject to an Acid Rain emissions limitation, 
quarterly reports shall include all of the data and information 
required in subpart H of part 75 of this chapter for each 
NOX Budget unit (or group of units using a common stack) 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).

[[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 
Sec. 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.


Sec. 97.75  Petitions.

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


Sec. 97.76  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.


Sec. 97.80  Applicability.

    A unit that is in a State (as defined in Sec. 97.2), is not a 
NOX Budget unit under Sec. 97.4(a), is not a unit exempt 
under Sec. 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 
Sec. 97.4(a), is covered by an exemption under Sec. 97.4(b) or 
Sec. 97.5 that is in effect, or is not operating is not eligible to be 
a NOX Budget opt-in unit.


Sec. 97.81  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.


Sec. 97.82  NOX authorized account representative.

    A unit for which an application for a NOX Budget opt-in 
permit is submitted, or a NOX Budget opt-in 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.


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

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


Sec. 97.84  Opt-in process.

    The permitting authority will issue or deny an initial 
NOX Budget opt-in permit for a unit for which an application 
for a NOX Budget opt-in permit under Sec. 97.83 is 
submitted, in accordance with Sec. 97.20 and the following:
    (a) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
accompanying the initial application for a NOX Budget opt-in 
permit under Sec. 97.83. A monitoring plan is sufficient, for purposes 
of interim review, if the plan appears to contain information 
demonstrating that the NOX emissions rate and heat input 
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 NOX Budget opt-in permit for 
public comment. The permitting authority will issue a draft 
NOX Budget opt-in permit for public comment in accordance 
with Sec. 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 Sec. 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 Sec. 97.20.
    (f) Withdrawal of application for NOX Budget opt-in 
permit. A NOX authorized account representative of a unit 
may withdraw its application for an initial NOX Budget opt-
in permit under Sec. 97.83 at any time prior to the issuance of the

[[Page 2750]]

initial 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 
Sec. 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.


Sec. 97.85  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 Sec. 97.22.
    (b) Each NOX Budget opt-in permit is deemed to 
incorporate automatically the definitions of terms under Sec. 97.2 and, 
upon recordation by the Administrator under subpart F 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.


Sec. 97.86  Withdrawal from NOX Budget Trading Program.

    (a) Requesting withdrawal. To withdraw from the NOX 
Budget Trading Program, the NOX authorized account 
representative of a NOX Budget opt-in 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 
Sec. 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 Sec. 97.54(d) for the control period.
    (3) After the requirements for withdrawal under paragraphs (b)(1) 
and (2) of this section are met, the Administrator will deduct from the 
NOX Budget opt-in 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 
Sec. 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 NOX Budget 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 Sec. 97.83 
for the unit prior to the date that is 4 years after the date on which 
the terminated NOX Budget opt-in permit became effective.


Sec. 97.87  Change in regulatory status.

    (a) Notification. When a NOX Budget opt-in unit becomes 
a NOX Budget unit under Sec. 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 Sec. 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 
Sec. 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 Sec. 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 Sec. 97.88 
for any control period after the last control period during which the 
unit's NOX Budget opt-in permit was effective; and
    (2) If the effective date of the NOX Budget permit 
revision under paragraph (b)(1)(i) of this section is during a control 
period, the NOX allowances allocated to the NOX 
Budget unit (as a NOX Budget opt-in unit) under Sec. 97.88 
for the control period multiplied by the number of days in the control 
period

[[Page 2751]]

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.
    (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 Sec. 97.42, as a unit that commenced 
operation on the effective date of the NOX Budget permit 
revision under paragraph (b)(1)(i) of this section and will be 
allocated NOX allowances under Sec. 97.42. The unit's 
deadline under Sec. 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 Sec. 97.42 for the control period: the number of NOX 
allowances otherwise allocated to the NOX Budget unit under 
Sec. 97.42 for the control period multiplied by the 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 Sec. 97.83(b), the Administrator will deduct 
from the NOX Budget opt-in unit's compliance account, or the 
overdraft account of the NOX Budget source where the 
NOX Budget opt-in 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 Sec. 97.88 for any control period after the last 
control period for which the NOX Budget opt-in permit is 
effective. The NOX authorized account representative shall 
ensure that the NOX Budget opt-in 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 Sec. 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.


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

    (a) NOX allotment 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 
Sec. 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 Sec. 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.

Appendix A to Part 97--Final Section 126 Rule: EGU Allocations, 
2003-2007

----------------------------------------------------------------------------------------------------------------
                                                                                                  NOX allocation
           ST                         Plant                Plant__id            Point__id            for EGUs
----------------------------------------------------------------------------------------------------------------
DC......................  BENNING.....................             603  15                                    80
DC......................  BENNING.....................             603  16                                   117
DE......................  CHRISTIANA SUB..............             591  11                                     5
DE......................  CHRISTIANA SUB..............             591  14                                     5

[[Page 2752]]

 
DE......................  DELAWARE CITY...............           52193  B4                                   141
DE......................  DELAWARE CITY...............           52193  ST__1                                155
DE......................  DELAWARE CITY...............           52193  ST__2                                159
DE......................  DELAWARE CITY...............           52193  ST__3                                158
DE......................  EDGE MOOR...................             593  3                                    234
DE......................  EDGE MOOR...................             593  4                                    401
DE......................  EDGE MOOR...................             593  5                                    602
DE......................  HAY ROAD....................            7153  **3                                  184
DE......................  HAY ROAD....................            7153  --1                                  235
DE......................  HAY ROAD....................            7153  --2                                  207
DE......................  INDIAN RIVER................             594  1                                    187
DE......................  INDIAN RIVER................             594  2                                    194
DE......................  INDIAN RIVER................             594  3                                    369
DE......................  INDIAN RIVER................             594  4                                    729
DE......................  MCKEE RUN...................             599  3                                    119
DE......................  VAN SANT STATION............            7318  **11                                   7
IN......................  ANDERSON....................            7336  --ACT1                                 5
IN......................  ANDERSON....................            7336  --ACT2                                 5
IN......................  CLIFTY CREEK................             983  1                                    558
IN......................  CLIFTY CREEK................             983  2                                    543
IN......................  CLIFTY CREEK................             983  3                                    564
IN......................  CLIFTY CREEK................             983  4                                    525
IN......................  CLIFTY CREEK................             983  5                                    561
IN......................  CLIFTY CREEK................             983  6                                    509
IN......................  CONNERSVILLE................            1002  1                                      1
IN......................  CONNERSVILLE................            1002  2                                      1
IN......................  GALLAGHER...................            1008  1                                    290
IN......................  GALLAGHER...................            1008  2                                    276
IN......................  GALLAGHER...................            1008  3                                    347
IN......................  GALLAGHER...................            1008  4                                    329
IN......................  NOBLESVILLE.................            1007  1                                     48
IN......................  NOBLESVILLE.................            1007  2                                     45
IN......................  NOBLESVILLE.................            1007  3                                     45
IN......................  RICHMOND....................            7335  --RCT1                                 5
IN......................  RICHMOND....................            7335  --RCT2                                 5
IN......................  TANNERS CREEK...............             988  U1                                   297
IN......................  TANNERS CREEK...............             988  U2                                   235
IN......................  TANNERS CREEK...............             988  U3                                   387
IN......................  TANNERS CREEK...............             988  U4                                   906
IN......................  WHITEWATER VALLEY...........            1040  1                                     74
IN......................  WHITEWATER VALLEY...........            1040  2                                    173
KY......................  BIG SANDY...................            1353  BSU1                                 565
KY......................  BIG SANDY...................            1353  BSU2                               1,741
KY......................  CANE RUN....................            1363  4                                    397
KY......................  CANE RUN....................            1363  5                                    332
KY......................  CANE RUN....................            1363  6                                    430
KY......................  COOPER......................            1384  1                                    183
KY......................  COOPER......................            1384  2                                    367
KY......................  DALE........................            1385  3                                    161
KY......................  DALE........................            1385  4                                    158
KY......................  E W BROWN...................            1355  1                                    193
KY......................  E W BROWN...................            1355  10                                    37
KY......................  E W BROWN...................            1355  2                                    317
KY......................  E W BROWN...................            1355  3                                    863
KY......................  E W BROWN...................            1355  8                                     34
KY......................  E W BROWN...................            1355  9                                     34
KY......................  E.W. BROWN..................            1355  11                                    21
KY......................  EAST BEND...................            6018  2                                  1,413
KY......................  GHENT.......................            1356  1                                  1,232
KY......................  GHENT.......................            1356  2                                  1,081
KY......................  GHENT.......................            1356  3                                  1,104
KY......................  GHENT.......................            1356  4                                  1,132
KY......................  H L SPURLOCK................            6041  1                                    697
KY......................  H L SPURLOCK................            6041  2                                  1,589
KY......................  MILL CREEK..................            1364  1                                    528
KY......................  MILL CREEK..................            1364  2                                    600
KY......................  MILL CREEK..................            1364  3                                    941
KY......................  MILL CREEK..................            1364  4                                  1,096
KY......................  PADDY'S RUN.................            1366  12                                     8
KY......................  PINEVILLE...................            1360  3                                     67
KY......................  TRIMBLE COUNTY..............            6071  1                                  1,221
KY......................  TYRONE......................            1361  1                                      3
KY......................  TYRONE......................            1361  2                                      3

[[Page 2753]]

 
KY......................  TYRONE......................            1361  3                                      3
KY......................  TYRONE......................            1361  4                                      3
KY......................  TYRONE......................            1361  5                                    117
MD......................  BRANDON SHORES..............             602  1                                  1,827
MD......................  BRANDON SHORES..............             602  2                                  1,713
MD......................  C P CRANE...................            1552  1                                    434
MD......................  C P CRANE...................            1552  2                                    463
MD......................  CHALK POINT.................            1571  --GT2                                  1
MD......................  CHALK POINT.................            1571  --GT3                                 36
MD......................  CHALK POINT.................            1571  --GT4                                 39
MD......................  CHALK POINT.................            1571  --GT5                                 55
MD......................  CHALK POINT.................            1571  --GT6                                 60
MD......................  CHALK POINT.................            1571  --SGT1                                24
MD......................  CHALK POINT.................            1571  1                                    833
MD......................  CHALK POINT.................            1571  2                                    861
MD......................  CHALK POINT.................            1571  3                                    585
MD......................  CHALK POINT.................            1571  4                                    522
MD......................  DICKERSON...................            1572  --GT2                                 36
MD......................  DICKERSON...................            1572  --GT3                                 66
MD......................  DICKERSON...................            1572  1                                    447
MD......................  DICKERSON...................            1572  2                                    441
MD......................  DICKERSON...................            1572  3                                    481
MD......................  GOULD STREET................            1553  3                                     81
MD......................  HERBERT A WAGNER............            1554  1                                    134
MD......................  HERBERT A WAGNER............            1554  2                                    399
MD......................  HERBERT A WAGNER............            1554  3                                    723
MD......................  HERBERT A WAGNER............            1554  4                                    301
MD......................  MORGANTOWN..................            1573  --GT3                                  9
MD......................  MORGANTOWN..................            1573  --GT4                                  9
MD......................  MORGANTOWN..................            1573  --GT5                                  9
MD......................  MORGANTOWN..................            1573  --GT6                                  8
MD......................  MORGANTOWN..................            1573  1                                  1,151
MD......................  MORGANTOWN..................            1573  2                                  1,375
MD......................  PANDA BRANDYWINE............           54832  1                                     95
MD......................  PANDA BRANDYWINE............           54832  2                                     84
MD......................  PERRYMAN....................            1556  **51                                  56
MD......................  PERRYMAN....................            1556  --GT1                                  8
MD......................  PERRYMAN....................            1556  --GT2                                  9
MD......................  PERRYMAN....................            1556  --GT3                                  6
MD......................  PERRYMAN....................            1556  --GT4                                 10
MD......................  R P SMITH...................            1570  11                                   143
MD......................  R P SMITH...................            1570  9                                     11
MD......................  RIVERSIDE...................            1559  --GT6                                 11
MD......................  RIVERSIDE...................            1559  4                                     40
MD......................  VIENNA......................            1564  8                                    169
MD......................  WESTPORT....................            1560  --GT5                                 28
MI......................  491 E. 48TH STREET..........            7268  --7                                   11
MI......................  491 E. 48TH STREET..........            7268  --8                                   12
MI......................  ADA COGEN LTD...............           10819  CA__Ltd                               23
MI......................  BELLE RIVER.................            6034  1                                  1,589
MI......................  BELLE RIVER.................            6034  2                                  1,672
MI......................  DAN E KARN..................            1702  1                                    552
MI......................  DAN E KARN..................            1702  2                                    530
MI......................  DAN E KARN..................            1702  3                                    288
MI......................  DAN E KARN..................            1702  4                                    310
MI......................  ECKERT STATION..............            1831  1                                     52
MI......................  ECKERT STATION..............            1831  2                                     47
MI......................  ECKERT STATION..............            1831  3                                     65
MI......................  ECKERT STATION..............            1831  4                                    116
MI......................  ECKERT STATION..............            1831  5                                    154
MI......................  ECKERT STATION..............            1831  6                                    131
MI......................  ENDICOTT GENERATING STATION.            4259  1                                     98
MI......................  ERICKSON....................            1832  1                                    381
MI......................  GREENWOOD...................            6035  1                                    373
MI......................  HANCOCK.....................            1730  5                                      3
MI......................  HANCOCK.....................            1730  6                                      3
MI......................  HARBOR BEACH................            1731  1                                     97
MI......................  J B SIMS....................            1825  3                                    137
MI......................  J C WEADOCK.................            1720  7                                    346
MI......................  J C WEADOCK.................            1720  8                                    342
MI......................  J R WHITING.................            1723  1                                    225
MI......................  J R WHITING.................            1723  2                                    204
MI......................  J R WHITING.................            1723  3                                    249

[[Page 2754]]

 
MI......................  JAMES DE YOUNG..............            1830  5                                     69
MI......................  MARYSVILLE..................            1732  10                                    22
MI......................  MARYSVILLE..................            1732  11                                    16
MI......................  MARYSVILLE..................            1732  12                                    17
MI......................  MARYSVILLE..................            1732  9                                     17
MI......................  MIDLAND COGENERATION VENTURE           10745  003                                  269
MI......................  MIDLAND COGENERATION VENTURE           10745  004                                  276
MI......................  MIDLAND COGENERATION VENTURE           10745  005                                  271
MI......................  MIDLAND COGENERATION VENTURE           10745  006                                  273
MI......................  MIDLAND COGENERATION VENTURE           10745  007                                  280
MI......................  MIDLAND COGENERATION VENTURE           10745  008                                  277
MI......................  MIDLAND COGENERATION VENTURE           10745  009                                  273
MI......................  MIDLAND COGENERATION VENTURE           10745  010                                  271
MI......................  MIDLAND COGENERATION VENTURE           10745  011                                  274
MI......................  MIDLAND COGENERATION VENTURE           10745  012                                  269
MI......................  MIDLAND COGENERATION VENTURE           10745  013                                  275
MI......................  MIDLAND COGENERATION VENTURE           10745  014                                  269
MI......................  MISTERSKY...................            1822  5                                     33
MI......................  MISTERSKY...................            1822  6                                    155
MI......................  MISTERSKY...................            1822  7                                     98
MI......................  MONROE......................            1733  1                                  1,902
MI......................  MONROE......................            1733  2                                  1,555
MI......................  MONROE......................            1733  3                                  1,574
MI......................  MONROE......................            1733  4                                  1,822
MI......................  RIVER ROUGE.................            1740  1                                      0
MI......................  RIVER ROUGE.................            1740  2                                    627
MI......................  RIVER ROUGE.................            1740  3                                    652
MI......................  ROUGE POWERHOUSE #1.........           10272  1                                    232
MI......................  ST CLAIR....................            1743  1                                    339
MI......................  ST CLAIR....................            1743  2                                    304
MI......................  ST CLAIR....................            1743  3                                    351
MI......................  ST CLAIR....................            1743  4                                    349
MI......................  ST CLAIR....................            1743  5                                      0
MI......................  ST CLAIR....................            1743  6                                    646
MI......................  ST CLAIR....................            1743  7                                    733
MI......................  TRENTON CHANNEL.............            1745  16                                   132
MI......................  TRENTON CHANNEL.............            1745  17                                   124
MI......................  TRENTON CHANNEL.............            1745  18                                   130
MI......................  TRENTON CHANNEL.............            1745  19                                   126
MI......................  TRENTON CHANNEL.............            1745  9A                                   968
MI......................  WYANDOTTE...................            1866  5                                      8
MI......................  WYANDOTTE...................            1866  7                                     81
MI......................  WYANDOTTE...................            1866  8                                     36
NC......................  ASHEVILLE...................            2706  1                                    491
NC......................  ASHEVILLE...................            2706  2                                    479
NC......................  BELEWS CREEK................            8042  1                                  2,306
NC......................  BELEWS CREEK................            8042  2                                  2,688
NC......................  BUCK........................            2720  5                                     59
NC......................  BUCK........................            2720  6                                     65
NC......................  BUCK........................            2720  7                                     69
NC......................  BUCK........................            2720  8                                    284
NC......................  BUCK........................            2720  9                                    300
NC......................  BUTLER WARNER GEN PL........            1016  --1                                   40
NC......................  BUTLER WARNER GEN PL........            1016  --2                                   40
NC......................  BUTLER WARNER GEN PL........            1016  --3                                   40
NC......................  BUTLER WARNER GEN PL........            1016  --6                                   42
NC......................  BUTLER WARNER GEN PL........            1016  --7                                   40
NC......................  BUTLER WARNER GEN PL........            1016  --8                                   40
NC......................  BUTLER WARNER GEN PL........            1016  --9                                  103
NC......................  CAPE FEAR...................            2708  5                                    255
NC......................  CAPE FEAR...................            2708  6                                    361
NC......................  CLIFFSIDE...................            2721  1                                     67
NC......................  CLIFFSIDE...................            2721  2                                     73
NC......................  CLIFFSIDE...................            2721  3                                     95
NC......................  CLIFFSIDE...................            2721  4                                    107
NC......................  CLIFFSIDE...................            2721  5                                  1,180
NC......................  COGENTRIX-ROCKY MOUNT.......           50468  ST__unt                              303
NC......................  COGENTRIX ELIZABETHTOWN.....           10380  ST__OWN                              111
NC......................  COGENTRIX KENANSVILLE.......           10381  ST__LLE                              102
NC......................  COGENTRIX LUMBERTON.........           10382  ST__TON                              111
NC......................  COGENTRIX ROXBORO...........           10379  ST__ORO                              166
NC......................  COGENTRIX SOUTHPORT.........           10378  ST__ORT                              335
NC......................  CRAVEN COUNTY WOOD ENERGY...           10525  ST__RGY                              231

[[Page 2755]]

 
NC......................  DAN RIVER...................            2723  1                                    117
NC......................  DAN RIVER...................            2723  2                                    128
NC......................  DAN RIVER...................            2723  3                                    271
NC......................  G G ALLEN...................            2718  1                                    311
NC......................  G G ALLEN...................            2718  2                                    316
NC......................  G G ALLEN...................            2718  3                                    525
NC......................  G G ALLEN...................            2718  4                                    470
NC......................  G G ALLEN...................            2718  5                                    514
NC......................  L V SUTTON..................            2713  1                                    162
NC......................  L V SUTTON..................            2713  2                                    176
NC......................  L V SUTTON..................            2713  3                                    717
NC......................  L V SUTTON..................            2713  CT2B                                   2
NC......................  LEE.........................            2709  1                                    129
NC......................  LEE.........................            2709  2                                    142
NC......................  LEE.........................            2709  3                                    414
NC......................  LEE.........................            2709  CT4                                    1
NC......................  LINCOLN.....................            7277  1                                     33
NC......................  LINCOLN.....................            7277  10                                    31
NC......................  LINCOLN.....................            7277  11                                    33
NC......................  LINCOLN.....................            7277  12                                    31
NC......................  LINCOLN.....................            7277  13                                    26
NC......................  LINCOLN.....................            7277  14                                    26
NC......................  LINCOLN.....................            7277  15                                    25
NC......................  LINCOLN.....................            7277  16                                    25
NC......................  LINCOLN.....................            7277  2                                     33
NC......................  LINCOLN.....................            7277  3                                     31
NC......................  LINCOLN.....................            7277  4                                     31
NC......................  LINCOLN.....................            7277  5                                     29
NC......................  LINCOLN.....................            7277  6                                     30
NC......................  LINCOLN.....................            7277  7                                     24
NC......................  LINCOLN.....................            7277  8                                     25
NC......................  LINCOLN.....................            7277  9                                     32
NC......................  MARSHALL....................            2727  1                                    899
NC......................  MARSHALL....................            2727  2                                    940
NC......................  MARSHALL....................            2727  3                                  1,588
NC......................  MARSHALL....................            2727  4                                  1,570
NC......................  MAYO........................            6250  1A                                   893
NC......................  MAYO........................            6250  1B                                   875
NC......................  PANDA-ROSEMARY..............           50555  CT__ary                               62
NC......................  PANDA-ROSEMARY..............           50555  CW__ary                               47
NC......................  RIVERBEND...................            2732  10                                   266
NC......................  RIVERBEND...................            2732  7                                    193
NC......................  RIVERBEND...................            2732  8                                    200
NC......................  RIVERBEND...................            2732  9                                    253
NC......................  ROANOKE VALLEY..............           50254  1                                    440
NC......................  ROANOKE VALLEY..............           50254  2                                    140
NC......................  ROXBORO.....................            2712  1                                    766
NC......................  ROXBORO.....................            2712  2                                  1,426
NC......................  ROXBORO.....................            2712  3A                                   792
NC......................  ROXBORO.....................            2712  3B                                   785
NC......................  ROXBORO.....................            2712  4A                                   778
NC......................  ROXBORO.....................            2712  4B                                   733
NC......................  TOBACCOVILLE................           50221  1                                     53
NC......................  TOBACCOVILLE................           50221  2                                     53
NC......................  TOBACCOVILLE................           50221  3                                     53
NC......................  TOBACCOVILLE................           50221  4                                     53
NC......................  UNC--CHAPEL HILL............           54276  ST__ill                               14
NC......................  W H WEATHERSPOON............            2716  1                                     76
NC......................  W H WEATHERSPOON............            2716  2                                     86
NC......................  W H WEATHERSPOON............            2716  3                                    161
NC......................  W H WEATHERSPOON............            2716  CT-1                                   4
NC......................  W H WEATHERSPOON............            2716  CT-2                                   3
NC......................  W H WEATHERSPOON............            2716  CT-3                                   2
NC......................  W H WEATHERSPOON............            2716  CT-4                                   4
NJ......................  B L ENGLAND.................            2378  1                                    353
NJ......................  B L ENGLAND.................            2378  2                                    417
NJ......................  B L ENGLAND.................            2378  3                                    114
NJ......................  BAYONNE.....................           50497  1                                    139
NJ......................  BAYONNE.....................           50497  2                                    143
NJ......................  BAYONNE.....................           50497  3                                    140
NJ......................  BERGEN......................            2398  1101                                 152
NJ......................  BERGEN......................            2398  1201                                 157
NJ......................  BERGEN......................            2398  1301                                 155

[[Page 2756]]

 
NJ......................  BERGEN......................            2398  1401                                 152
NJ......................  BURLINGTON..................            2399  101                                   30
NJ......................  BURLINGTON..................            2399  102                                   34
NJ......................  BURLINGTON..................            2399  103                                   39
NJ......................  BURLINGTON..................            2399  104                                   47
NJ......................  BURLINGTON..................            2399  11-1                                   2
NJ......................  BURLINGTON..................            2399  11-2                                   2
NJ......................  BURLINGTON..................            2399  11-3                                   2
NJ......................  BURLINGTON..................            2399  11-4                                   2
NJ......................  BURLINGTON..................            2399  7                                     17
NJ......................  BURLINGTON..................            2399  9-1                                    4
NJ......................  BURLINGTON..................            2399  9-2                                    4
NJ......................  BURLINGTON..................            2399  9-3                                    4
NJ......................  BURLINGTON..................            2399  9-4                                    4
NJ......................  CAMDEN......................           10751  1                                    378
NJ......................  CARLL'S CORNER STATION......            2379  1                                      2
NJ......................  CARLL'S CORNER STATION......            2379  2                                     16
NJ......................  CARNEYS POINT (CCLP) NUG....           10566  ST__NUG                              527
NJ......................  CEDAR STATION...............            2380  1E&W                                   5
NJ......................  CUMBERLAND..................            5083  --GT1                                 40
NJ......................  DEEPWATER...................            2384  1                                     49
NJ......................  DEEPWATER...................            2384  4                                      5
NJ......................  DEEPWATER...................            2384  6                                     42
NJ......................  DEEPWATER...................            2384  8                                    195
NJ......................  EDISON......................            2400  1-1A&B                                 3
NJ......................  EDISON......................            2400  1-2A&B                                 3
NJ......................  EDISON......................            2400  1-3A&B                                 3
NJ......................  EDISON......................            2400  1-4A&B                                 3
NJ......................  EDISON......................            2400  2-1A&B                                 7
NJ......................  EDISON......................            2400  2-2A&B                                 7
NJ......................  EDISON......................            2400  2-3A&B                                 7
NJ......................  EDISON......................            2400  2-4A&B                                 7
NJ......................  EDISON......................            2400  3-1A&B                                 7
NJ......................  EDISON......................            2400  3-2A&B                                 7
NJ......................  EDISON......................            2400  3-3A&B                                 7
NJ......................  EDISON......................            2400  3-4A&B                                 7
NJ......................  ESSEX.......................            2401  10-1A&B                               10
NJ......................  ESSEX.......................            2401  10-2A&B                               10
NJ......................  ESSEX.......................            2401  10-3A&B                               10
NJ......................  ESSEX.......................            2401  10-4A&B                               10
NJ......................  ESSEX.......................            2401  11-1A&B                               11
NJ......................  ESSEX.......................            2401  11-2A&B                               11
NJ......................  ESSEX.......................            2401  11-3A&B                               11
NJ......................  ESSEX.......................            2401  11-4A&B                               11
NJ......................  ESSEX.......................            2401  12-1A&B                               13
NJ......................  ESSEX.......................            2401  12-2A&B                               13
NJ......................  ESSEX.......................            2401  12-3A&B                               13
NJ......................  ESSEX.......................            2401  12-4A&B                               13
NJ......................  ESSEX.......................            2401  9                                     66
NJ......................  FORKED RIVER................            7138  --1                                   17
NJ......................  FORKED RIVER................            7138  --2                                   17
NJ......................  GILBERT.....................            2393  03                                    47
NJ......................  GILBERT.....................            2393  04                                    64
NJ......................  GILBERT.....................            2393  05                                    63
NJ......................  GILBERT.....................            2393  06                                    61
NJ......................  GILBERT.....................            2393  07                                    63
NJ......................  GILBERT.....................            2393  1                                      4
NJ......................  GILBERT.....................            2393  2                                      4
NJ......................  GILBERT.....................            2393  CT-9                                  61
NJ......................  HUDSON......................            2403  1                                    175
NJ......................  HUDSON......................            2403  2                                    884
NJ......................  HUDSON......................            2403  3                                      3
NJ......................  KEARNY......................            2404  10                                    26
NJ......................  KEARNY......................            2404  11                                    34
NJ......................  KEARNY......................            2404  12-1                                   8
NJ......................  KEARNY......................            2404  12-2                                   8
NJ......................  KEARNY......................            2404  12-3                                   8
NJ......................  KEARNY......................            2404  12-4                                   8
NJ......................  KEARNY......................            2404  7                                     35
NJ......................  KEARNY......................            2404  8                                     16
NJ......................  LINDEN......................            2406  11                                    16
NJ......................  LINDEN......................            2406  12                                    11
NJ......................  LINDEN......................            2406  13                                    20

[[Page 2757]]

 
NJ......................  LINDEN......................            2406  2                                     52
NJ......................  LINDEN......................            2406  6                                      2
NJ......................  LINDEN......................            2406  7                                     60
NJ......................  LINDEN......................            2406  8                                     70
NJ......................  LINDEN COGEN................           50006  100                                  276
NJ......................  LINDEN COGEN................           50006  200                                  280
NJ......................  LINDEN COGEN................           50006  300                                  274
NJ......................  LINDEN COGEN................           50006  400                                  272
NJ......................  LINDEN COGEN................           50006  500                                  278
NJ......................  LOGAN GENERATING PLANT......           10043  1                                    424
NJ......................  MERCER......................            2408  1                                    489
NJ......................  MERCER......................            2408  2                                    558
NJ......................  MICKELTON...................            8008  1                                     28
NJ......................  MIDDLE ST...................            2382  3                                      4
NJ......................  MILFORD POWER LP............           10616  1                                     44
NJ......................  MOBIL NUG...................            n114  CT__NUG                               40
NJ......................  NEWARK BAY COGEN............           50385  1                                      9
NJ......................  NEWARK BAY COGEN............           50385  2                                      9
NJ......................  NORTH JERSEY ENERGY                    10308  1                                     19
                           ASSOCIATES.
NJ......................  NORTH JERSEY ENERGY                    10308  2                                     19
                           ASSOCIATES.
NJ......................  O'BRIEN (NEWARK)                       50797  1                                      8
                           COGENERATION, INC..
NJ......................  O'BRIEN (PARLIN)                       50799  1                                      8
                           COGENERATION, INC..
NJ......................  O'BRIEN (PARLIN)                       50799  2                                      8
                           COGENERATION, INC..
NJ......................  PEDRICKTOWN COGEN...........           10099  1                                     13
NJ......................  PRIME ENERGY LP.............           50852  1                                    178
NJ......................  SALEM.......................            2410  3A&B                                   3
NJ......................  SAYREVILLE..................            2390  07                                    40
NJ......................  SAYREVILLE..................            2390  08                                    51
NJ......................  SAYREVILLE..................            2390  C-1                                   16
NJ......................  SAYREVILLE..................            2390  C-2                                   13
NJ......................  SAYREVILLE..................            2390  C-3                                   11
NJ......................  SAYREVILLE..................            2390  C-4                                   13
NJ......................  SEWAREN.....................            2411  1                                     42
NJ......................  SEWAREN.....................            2411  2                                     45
NJ......................  SEWAREN.....................            2411  3                                     58
NJ......................  SEWAREN.....................            2411  4                                     91
NJ......................  SEWAREN.....................            2411  6                                      2
NJ......................  SHERMAN.....................            7288  CT-1                                  37
NJ......................  VINELAND VCLP NUG...........           54807  GT__NUG                               40
NJ......................  WERNER......................            2385  04                                    14
NJ......................  WERNER......................            2385  C-1                                    7
NJ......................  WERNER......................            2385  C-2                                    6
NJ......................  WERNER......................            2385  C-3                                    7
NJ......................  WERNER......................            2385  C-4                                    7
NJ......................  WEST STAT...................            6776  1                                     10
NY......................  59TH STREET.................            2503  114                                   41
NY......................  59TH STREET.................            2503  115                                   32
NY......................  74TH STREET.................            2504  120                                   70
NY......................  74TH STREET.................            2504  121                                   80
NY......................  74TH STREET.................            2504  122                                   65
NY......................  ARTHUR KILL.................            2490  20                                   524
NY......................  ARTHUR KILL.................            2490  30                                   380
NY......................  ASTORIA.....................            8906  30                                   557
NY......................  ASTORIA.....................            8906  40                                   505
NY......................  ASTORIA.....................            8906  50                                   561
NY......................  ASTORIA.....................            8906  GT2-1                                  9
NY......................  ASTORIA.....................            8906  GT2-2                                  9
NY......................  ASTORIA.....................            8906  GT2-3                                  9
NY......................  ASTORIA.....................            8906  GT2-4                                  9
NY......................  ASTORIA.....................            8906  GT3-1                                  9
NY......................  ASTORIA.....................            8906  GT3-2                                  9
NY......................  ASTORIA.....................            8906  GT3-3                                  9
NY......................  ASTORIA.....................            8906  GT3-4                                  9
NY......................  ASTORIA.....................            8906  GT4-1                                  9
NY......................  ASTORIA.....................            8906  GT4-2                                  9
NY......................  ASTORIA.....................            8906  GT4-3                                  9
NY......................  ASTORIA.....................            8906  GT4-4                                  9
NY......................  BOWLINE POINT...............            2625  1                                    749
NY......................  BOWLINE POINT...............            2625  2                                    566
NY......................  BROOKLYN NAVY YARD..........           54914  1                                    239
NY......................  BROOKLYN NAVY YARD..........           54914  2                                    220
NY......................  CHARLES POLETTI.............            2491  001                                  883
NY......................  DANSKAMMER..................            2480  1                                     34

[[Page 2758]]

 
NY......................  DANSKAMMER..................            2480  2                                     45
NY......................  DANSKAMMER..................            2480  3                                    229
NY......................  DANSKAMMER..................            2480  4                                    449
NY......................  EF BARRETT..................            2511  10                                   285
NY......................  EF BARRETT..................            2511  20                                   287
NY......................  EAST RIVER..................            2493  50                                    33
NY......................  EAST RIVER..................            2493  60                                   319
NY......................  EAST RIVER..................            2493  70                                   113
NY......................  FAR ROCKAWAY................            2513  40                                   138
NY......................  GLENWOOD....................            2514  40                                   151
NY......................  GLENWOOD....................            2514  50                                   124
NY......................  GLENWOOD....................            2514  U00020                                 1
NY......................  GLENWOOD....................            2514  U00021                                 1
NY......................  HUDSON AVENUE...............            2496  100                                  162
NY......................  LOVETT......................            2629  3                                     74
NY......................  LOVETT......................            2629  4                                    304
NY......................  LOVETT......................            2629  5                                    380
NY......................  NISSEQUOGUE COGEN PARTNERS..            4931  1                                     86
NY......................  NORTHPORT...................            2516  1                                    343
NY......................  NORTHPORT...................            2516  2                                    533
NY......................  NORTHPORT...................            2516  3                                    375
NY......................  NORTHPORT...................            2516  4                                    582
NY......................  O&R HILLBURN GT.............            2628  1                                      2
NY......................  O&R SHOEMAKER GT............            2632  1                                     10
NY......................  PORT JEFFERSON..............            2517  3                                    270
NY......................  PORT JEFFERSON..............            2517  4                                    253
NY......................  RAVENSWOOD..................            2500  10                                   299
NY......................  RAVENSWOOD..................            2500  20                                   363
NY......................  RAVENSWOOD..................            2500  30                                 1,360
NY......................  RAVENSWOOD..................            2500  GT2-1                                  3
NY......................  RAVENSWOOD..................            2500  GT2-2                                  3
NY......................  RAVENSWOOD..................            2500  GT2-3                                  3
NY......................  RAVENSWOOD..................            2500  GT2-4                                  3
NY......................  RAVENSWOOD..................            2500  GT3-1                                  3
NY......................  RAVENSWOOD..................            2500  GT3-2                                  3
NY......................  RAVENSWOOD..................            2500  GT3-3                                  3
NY......................  RAVENSWOOD..................            2500  GT3-4                                  3
NY......................  RICHARD M FLYNN.............            7314  NA1                                  246
NY......................  RICHARD M FLYNN.............            7314  NA2                                   25
NY......................  ROSETON.....................            8006  1                                    479
NY......................  ROSETON.....................            8006  2                                    595
NY......................  TRIGEN-NDEC.................           52056  4                                    105
NY......................  WADING RIVER................            7146  1                                      8
NY......................  WADING RIVER................            7146  2                                      8
NY......................  WADING RIVER................            7146  3                                      8
NY......................  WADING RIVER................            7146  UGT013                                 1
NY......................  WATERSIDE...................            2502  61                                    84
NY......................  WATERSIDE...................            2502  62                                    91
NY......................  WATERSIDE...................            2502  80                                   208
NY......................  WATERSIDE...................            2502  90                                   208
NY......................  WEST BABYLON................            2521  1                                      2
OH......................  ASHTABULA...................            2835  10                                    75
OH......................  ASHTABULA...................            2835  11                                    80
OH......................  ASHTABULA...................            2835  7                                    333
OH......................  ASHTABULA...................            2835  8                                     70
OH......................  ASHTABULA...................            2835  9                                     66
OH......................  AVON LAKE...................            2836  10                                   139
OH......................  AVON LAKE...................            2836  12                                 1,040
OH......................  AVON LAKE...................            2836  9                                     41
OH......................  AVON LAKE...................            2836  CT10                                   3
OH......................  BAY SHORE...................            2878  1                                    208
OH......................  BAY SHORE...................            2878  2                                    229
OH......................  BAY SHORE...................            2878  3                                    213
OH......................  BAY SHORE...................            2878  4                                    330
OH......................  CARDINAL....................            2828  1                                  1,030
OH......................  CARDINAL....................            2828  2                                  1,083
OH......................  CARDINAL....................            2828  3                                  1,079
OH......................  CONESVILLE..................            2840  1                                    214
OH......................  CONESVILLE..................            2840  2                                    203
OH......................  CONESVILLE..................            2840  3                                    212
OH......................  CONESVILLE..................            2840  4                                  1,119
OH......................  CONESVILLE..................            2840  5                                    731
OH......................  CONESVILLE..................            2840  6                                    736

[[Page 2759]]

 
OH......................  DICKS CREEK.................            2831  1                                      7
OH......................  EASTLAKE....................            2837  1                                    214
OH......................  EASTLAKE....................            2837  2                                    230
OH......................  EASTLAKE....................            2837  3                                    251
OH......................  EASTLAKE....................            2837  4                                    371
OH......................  EASTLAKE....................            2837  5                                    974
OH......................  EASTLAKE....................            2837  6                                      1
OH......................  EDGEWATER...................            2857  13                                    65
OH......................  EDGEWATER...................            2857  A                                      1
OH......................  EDGEWATER...................            2857  B                                      1
OH......................  FRANK M TAIT................            2847  GT1                                   23
OH......................  FRANK M TAIT................            2847  GT2                                   25
OH......................  GEN J M GAVIN...............            8102  1                                  2,744
OH......................  GEN J M GAVIN...............            8102  2                                  2,981
OH......................  HAMILTON....................            2917  9                                    110
OH......................  J M STUART..................            2850  1                                  1,054
OH......................  J M STUART..................            2850  2                                  1,228
OH......................  J M STUART..................            2850  3                                  1,074
OH......................  J M STUART..................            2850  4                                  1,106
OH......................  KILLEN STATION..............            6031  2                                  1,706
OH......................  KYGER CREEK.................            2876  1                                    471
OH......................  KYGER CREEK.................            2876  2                                    471
OH......................  KYGER CREEK.................            2876  3                                    478
OH......................  KYGER CREEK.................            2876  4                                    465
OH......................  KYGER CREEK.................            2876  5                                    455
OH......................  LAKE SHORE..................            2838  18                                   195
OH......................  MAD RIVER...................            2860  A                                      2
OH......................  MAD RIVER...................            2860  B                                      2
OH......................  MIAMI FORT..................            2832  5-1                                   35
OH......................  MIAMI FORT..................            2832  5-2                                   35
OH......................  MIAMI FORT..................            2832  6                                    398
OH......................  MIAMI FORT..................            2832  7                                  1,044
OH......................  MIAMI FORT..................            2832  8                                  1,015
OH......................  MIAMI FORT..................            2832  CT2                                    1
OH......................  MUSKINGUM RIVER.............            2872  1                                    309
OH......................  MUSKINGUM RIVER.............            2872  2                                    316
OH......................  MUSKINGUM RIVER.............            2872  3                                    347
OH......................  MUSKINGUM RIVER.............            2872  4                                    349
OH......................  MUSKINGUM RIVER.............            2872  5                                  1,105
OH......................  NILES.......................            2861  1                                    212
OH......................  NILES.......................            2861  2                                    160
OH......................  NILES.......................            2861  A                                      2
OH......................  O H HUTCHINGS...............            2848  H-1                                   24
OH......................  O H HUTCHING................            2848  H-2                                   37
OH......................  O H HUTCHINGS...............            2848  H-3                                   64
OH......................  O H HUTCHINGS...............            2848  H-4                                   68
OH......................  O H HUTCHINGS...............            2848  H-5                                   62
OH......................  O H HUTCHINGS...............            2848  H-6                                   69
OH......................  O H HUTCHINGS...............            2848  H-7                                    1
OH......................  PICWAY......................            2843  9                                    141
OH......................  R E BURGER..................            2864  1                                      0
OH......................  R E BURGER..................            2864  2                                      0
OH......................  R E BURGER..................            2864  3                                      0
OH......................  R E BURGER..................            2864  4                                      0
OH......................  R E BURGER..................            2864  5                                     14
OH......................  R E BURGER..................            2864  6                                     13
OH......................  R E BURGER..................            2864  7                                    337
OH......................  R E BURGER..................            2864  8                                    274
OH......................  RICHARD GORSUCH.............            7286  1                                    146
OH......................  RICHARD GORSUCH.............            7286  2                                    138
OH......................  RICHARD GORSUCH.............            7286  3                                    144
OH......................  RICHARD GORSUCH.............            7286  4                                    146
OH......................  W H SAMMIS..................            2866  1                                    402
OH......................  W H SAMMIS..................            2866  2                                    418
OH......................  W H SAMMIS..................            2866  3                                    400
OH......................  W H SAMMIS..................            2866  4                                    415
OH......................  W H SAMMIS..................            2866  5                                    631
OH......................  W H SAMMIS..................            2866  6                                  1,221
OH......................  W H SAMMIS..................            2866  7                                  1,259
OH......................  W H ZIMMER..................            6019  1                                  2,918
OH......................  WALTER C BECKJORD...........            2830  1                                    167
OH......................  WALTER C BECKJORD...........            2830  2                                    198
OH......................  WALTER C BECKJORD...........            2830  3                                    281

[[Page 2760]]

 
OH......................  WALTER C BECKJORD...........            2830  4                                    347
OH......................  WALTER C BECKJORD...........            2830  5                                    481
OH......................  WALTER C BECKJORD...........            2830  6                                    850
OH......................  WALTER C BECKJORD...........            2830  CT1                                    3
OH......................  WALTER C BECKJORD...........            2830  CT2                                    3
OH......................  WALTER C BECKJORD...........            2830  CT3                                    4
OH......................  WALTER C BECKJORD...........            2830  CT4                                    2
OH......................  WEST LORAIN.................            2869  1A                                     0
OH......................  WEST LORAIN.................            2869  1B                                     0
OH......................  WOODSDALE...................            7158  --GT1                                 30
OH......................  WOODSDALE...................            7158  --GT2                                 30
OH......................  WOODSDALE...................            7158  --GT3                                 39
OH......................  WOODSDALE...................            7158  --GT4                                 37
OH......................  WOODSDALE...................            7158  --GT5                                 40
OH......................  WOODSDALE...................            7158  --GT6                                 39
PA......................  AES BEAVER VALLEY...........           10676  032                                  144
PA......................  AES BEAVER VALLEY...........           10676  033                                  131
PA......................  AES BEAVER VALLEY...........           10676  034                                  133
PA......................  AES BEAVER VALLEY...........           10676  035                                   67
PA......................  ARMSTRONG...................            3178  1                                    363
PA......................  ARMSTRONG...................            3178  2                                    383
PA......................  BRUCE MANSFIELD.............            6094  1                                  1,657
PA......................  BRUCE MANSFIELD.............            6094  2                                  1,672
PA......................  BRUCE MANSFIELD.............            6094  3                                  1,636
PA......................  BRUNNER ISLAND..............            3140  1                                    568
PA......................  BRUNNER ISLAND..............            3140  2                                    718
PA......................  BRUNNER ISLAND..............            3140  3                                  1,539
PA......................  BRUNOT ISLAND...............            3096  2A                                     0
PA......................  BRUNOT ISLAND...............            3096  2B                                     0
PA......................  BRUNOT ISLAND...............            3096  3                                      0
PA......................  CAMBRIA COGEN...............           10641  1                                    155
PA......................  CAMBRIA COGEN...............           10641  2                                    161
PA......................  CHESWICK....................            8226  1                                  1,119
PA......................  COLVER POWER PROJECT........           10143  1                                    291
PA......................  CONEMAUGH...................            3118  1                                  2,167
PA......................  CONEMAUGH...................            3118  2                                  1,995
PA......................  CROMBY......................            3159  1                                    377
PA......................  CROMBY......................            3159  2                                    201
PA......................  DELAWARE....................            3160  71                                    61
PA......................  DELAWARE....................            3160  81                                    56
PA......................  EBENSBURG POWER.............           10603  1                                    191
PA......................  EDDYSTONE...................            3161  1                                    565
PA......................  EDDYSTONE...................            3161  2                                    636
PA......................  EDDYSTONE...................            3161  3                                    207
PA......................  EDDYSTONE...................            3161  4                                    237
PA......................  ELRAMA......................            3098  1                                    214
PA......................  ELRAMA......................            3098  2                                    209
PA......................  ELRAMA......................            3098  3                                    208
PA......................  ELRAMA......................            3098  4                                    428
PA......................  FOSTER WHEELER MT. CARMEL...           10343  AB__NUG                              152
PA......................  GILBERTON POWER NUG.........          010113  AB__NUG                              273
PA......................  GPU GENCO WAYNE.............            3134  1                                      8
PA......................  HATFIELD'S FERRY............            3179  1                                  1,155
PA......................  HATFIELD'S FERRY............            3179  2                                  1,029
PA......................  HATFIELD'S FERRY............            3179  3                                  1,087
PA......................  HOLTWOOD....................            3145  17                                   246
PA......................  HOMER CITY..................            3122  1                                  1,471
PA......................  HOMER CITY..................            3122  2                                  1,553
PA......................  HOMER CITY..................            3122  3                                  1,437
PA......................  HUNLOCK PWR STATION.........            3176  6                                    131
PA......................  KEYSTONE....................            3136  1                                  2,154
PA......................  KEYSTONE....................            3136  2                                  2,133
PA......................  KIMBERLY-CLARK..............            3157  10                                   211
PA......................  MARTINS CREEK...............            3148  1                                    314
PA......................  MARTINS CREEK...............            3148  2                                    293
PA......................  MARTINS CREEK...............            3148  3                                    543
PA......................  MARTINS CREEK...............            3148  4                                    500
PA......................  MITCHELL....................            3181  1                                     10
PA......................  MITCHELL....................            3181  2                                      6
PA......................  MITCHELL....................            3181  3                                      9
PA......................  MITCHELL....................            3181  33                                   556
PA......................  MONTOUR.....................            3149  1                                  1,560
PA......................  MONTOUR.....................            3149  2                                  1,673

[[Page 2761]]

 
PA......................  MOUNTAIN....................            3111  1                                      5
PA......................  MOUNTAIN....................            3111  2                                      5
PA......................  NEW CASTLE..................            3138  3                                    190
PA......................  NEW CASTLE..................            3138  4                                    195
PA......................  NEW CASTLE..................            3138  5                                    245
PA......................  NORCON POWER PARTNERS LP....           54571  1                                    103
PA......................  NORCON POWER PARTNERS LP....           54571  2                                    109
PA......................  NORTHAMPTION GENERATING.....           50888  1                                    291
PA......................  NORTHEASTERN POWER..........           50039  ........................             188
PA......................  PANTHER CREEK...............           50776  1                                    134
PA......................  PANTHER CREEK...............           50776  2                                    130
PA......................  PECO ENERGY CROYDEN.........            8012  11                                    11
PA......................  PECO ENERGY CROYDEN.........            8012  12                                     9
PA......................  PECO ENERGY CROYDEN.........            8012  21                                     5
PA......................  PECO ENERGY CROYDEN.........            8012  22                                    11
PA......................  PECO ENERGY CROYDEN.........            8012  31                                    13
PA......................  PECO ENERGY CROYDEN.........            8012  32                                     6
PA......................  PECO ENERGY CROYDEN.........            8012  41                                    11
PA......................  PECO ENERGY CROYDEN.........            8012  42                                     9
PA......................  PECO ENERGY RICHMOND........            3168  91                                    10
PA......................  PECO ENERGY RICHMOND........            3168  92                                     9
PA......................  PHILLIPS POWER STATION......            3099  3                                      0
PA......................  PHILLIPS POWER STATION......            3099  4                                      0
PA......................  PHILLIPS POWER STATION......            3099  5                                      0
PA......................  PHILLIPS POWER STATION......            3099  6                                      0
PA......................  PINEY CREEK.................           54144  1                                    102
PA......................  PORTLAND....................            3113  --5                                   48
PA......................  PORTLAND....................            3113  1                                    266
PA......................  PORTLAND....................            3113  2                                    412
PA......................  SCHUYLKILL..................            3169  1                                     84
PA......................  SCHUYLKILL ENERGY RESOURCES.          880010  1                                    289
PA......................  SCHUYLKILL STATION (TURBI...           50607  AB__NUG                              701
PA......................  SCRUBGRASS GENERATING PLANT.           50974  1                                    124
PA......................  SCRUBGRASS GENERATING PLANT.           50974  2                                    123
PA......................  SEWARD......................            3130  12                                    64
PA......................  SEWARD......................            3130  14                                    72
PA......................  SEWARD......................            3130  15                                   355
PA......................  SHAWVILLE...................            3131  1                                    295
PA......................  SHAWVILLE...................            3131  2                                    294
PA......................  SHAWVILLE...................            3131  3                                    380
PA......................  SHAWVILLE...................            3131  4                                    392
PA......................  SUNBURY.....................            3152  1A                                   134
PA......................  SUNBURY.....................            3152  1B                                   122
PA......................  SUNBURY.....................            3152  2A                                   130
PA......................  SUNBURY.....................            3152  2B                                   134
PA......................  SUNBURY.....................            3152  3                                    263
PA......................  SUNBURY.....................            3152  4                                    302
PA......................  TITUS.......................            3115  1                                    161
PA......................  TITUS.......................            3115  2                                    152
PA......................  TITUS.......................            3115  3                                    151
PA......................  TOLNA.......................            3116  1                                      3
PA......................  TOLNA.......................            3116  2                                      4
PA......................  TRIGEN ENERGY SANSOM........          880006  1                                     12
PA......................  TRIGEN ENERGY SANSOM........          880006  2                                     10
PA......................  TRIGEN ENERGY SANSOM........          880006  3                                      5
PA......................  TRIGEN ENERGY SANSOM........          880006  4                                      6
PA......................  WARREN......................            3132  1                                     47
PA......................  WARREN......................            3132  2                                     32
PA......................  WARREN......................            3132  3                                     40
PA......................  WARREN......................            3132  4                                     42
PA......................  WARREN......................            3132  CT1                                   14
PA......................  WESTWOOD ENERGY PROPERTIE...           50611  031                                   98
PA......................  WHEELABRATOR FRACKVILLE E...           50879  GEN1                                 161
PA......................  WILLIAMS GEN--HAZELTON......           10870  HRSG                                  16
PA......................  WILLIAMS GEN--HAZELTON......           10870  TURBN                                141
VA......................  BELLMEADE...................            7696  1                                     76
VA......................  BELLMEADE...................            7696  2                                     88
VA......................  BREMO BLUFF.................            3796  3                                    137
VA......................  BREMO BLUFF.................            3796  4                                    386
VA......................  CHESAPEAKE..................            3803  1                                    298
VA......................  CHESAPEAKE..................            3803  2                                    308
VA......................  CHESAPEAKE..................            3803  3                                    370
VA......................  CHESAPEAKE..................            3803  4                                    571

[[Page 2762]]

 
VA......................  CHESAPEAKE CORP.............           10017  ST__rp.                               59
VA......................  CHESTERFIELD................            3797  --8                                  263
VA......................  CHESTERFIELD................            3797  3                                    232
VA......................  CHESTERFIELD................            3797  4                                    389
VA......................  CHESTERFIELD................            3797  5                                    769
VA......................  CHESTERFIELD................            3797  6                                  1,348
VA......................  CHESTERFIELD................            3797  7                                    316
VA......................  CLINCH RIVER................            3775  1                                    548
VA......................  CLINCH RIVER................            3775  2                                    520
VA......................  CLINCH RIVER................            3775  3                                    575
VA......................  CLOVER......................            7213  1                                  1,033
VA......................  CLOVER......................            7213  2                                  1,118
VA......................  COGENTRIX--HOPEWELL.........           10377  ST__ell                              327
VA......................  COGENTRIX--PORTSMOUTH.......           10071  ST__uth                              356
VA......................  COGENTRIX RICHMOND 1........           54081  ST__d 1                              299
VA......................  COGENTRIX RICHMOND 2........           54081  ST__d 2                              209
VA......................  COMMONWEALTH ATLANTIC LP....           52087  GT__LP                                35
VA......................  DARBYTOWN...................            7212  --1                                   29
VA......................  DARBYTOWN...................            7212  --2                                   28
VA......................  DARBYTOWN...................            7212  --3                                   30
VA......................  DARBYTOWN...................            7212  --4                                   29
VA......................  DOSWELL #1..................           52019  CA__#1                                46
VA......................  DOSWELL #1..................           52019  CT__#1                                94
VA......................  DOSWELL #2..................           52019  CA__#2                                46
VA......................  DOSWELL #2..................           52019  CT__#2                                94
VA......................  GLEN LYN....................            3776  51                                   101
VA......................  GLEN LYN....................            3776  52                                   110
VA......................  GLEN LYN....................            3776  6                                    487
VA......................  GORDONSVILLE 1..............           54844  CA__e 1                               16
VA......................  GORDONSVILLE 1..............           54844  CT__e 1                               33
VA......................  GORDONSVILLE 2..............           54844  CA__Xe 2                              17
VA......................  GORDONSVILLE 2..............           54844  CT__e 2                               34
VA......................  GRAVEL NECK.................            7032  --3                                   21
VA......................  GRAVEL NECK.................            7032  --X4                                  24
VA......................  GRAVEL NECK.................            7032  --5                                   14
VA......................  GRAVEL NECK.................            7032  --6                                   18
VA......................  HOPEWELL COGEN, INC.........           10633  CT__nc.                              102
VA......................  HOPEWELL COGEN, INC.........           10633  CW__nc.                               53
VA......................  LG&E-WESTMORELAND ALTAVISTA.           10773  1                                     18
VA......................  LG&E-WESTMORELAND ALTAVISTA.           10773  2                                     18
VA......................  LG&E-WESTMORELAND HOPEWELL..           10771  1                                     17
VA......................  LG&E-WESTMORELAND HOPEWELL..           10771  2                                     16
VA......................  LG&E-WESTMORELAND                      10774  1                                     23
                           SOUTHAMPTON.
VA......................  LG&E-WESTMORELAND                      10774  2                                     29
                           SOUTHAMPTON.
VA......................  MECKLENBURG.................           52007  ST__urg                              234
VA......................  POSSUM POINT................            3804  3                                    221
VA......................  POSSUM POINT................            3804  4                                    528
VA......................  POSSUM POINT................            3804  5                                    322
VA......................  POTOMAC RIVER...............            3788  1                                    203
VA......................  POTOMAC RIVER...............            3788  2                                    139
VA......................  POTOMAC RIVER...............            3788  3                                    232
VA......................  POTOMAC RIVER...............            3788  4                                    223
VA......................  POTOMAC RIVER...............            3788  5                                    222
VA......................  SEI BIRCHWOOD...............              12  1                                     90
VA......................  SEI BIRCHWOOD...............              12  2                                      2
VA......................  STONE CONTAINER.............           50813  ST__ner                               68
VA......................  TASLEY......................            3785  10                                     6
VA......................  YORKTOWN....................            3809  1                                    386
VA......................  YORKTOWN....................            3809  2                                    419
VA......................  YORKTOWN....................            3809  3                                    764
WV......................  ALBRIGHT....................            3942  1                                     76
WV......................  ALBRIGHT....................            3942  2                                     71
WV......................  ALBRIGHT....................            3942  3                                    241
WV......................  FORT MARTIN.................            3943  1                                    887
WV......................  FORT MARTIN.................            3943  2                                    868
WV......................  GRANT TOWN..................           10151  ST__own                              156
WV......................  HARRISON....................            3944  1                                  1,385
WV......................  HARRISON....................            3944  2                                  1,444
WV......................  HARRISON....................            3944  3                                  1,505
WV......................  JOHN E AMOS.................            3935  1                                  1,254
WV......................  JOHN E AMOS.................            3935  2                                  1,198
WV......................  JOHN E AMOS.................            3935  3                                  1,859
WV......................  KAMMER......................            3947  1                                    399

[[Page 2763]]

 
WV......................  KAMMER......................            3947  2                                    418
WV......................  KAMMER......................            3947  3                                    447
WV......................  KANAWHA RIVER...............            3936  1                                    336
WV......................  KANAWHA RIVER...............            3936  2                                    323
WV......................  MITCHELL....................            3948  1                                  1,288
WV......................  MITCHELL....................            3948  2                                  1,191
WV......................  MORGANTOWN ENERGY ASSOCIATES              27  1                                     80
WV......................  MORGANTOWN ENERGY ASSOCIATES              27  2                                     80
WV......................  MOUNTAINEER (1301)..........            6264  1                                  1,952
WV......................  MT STORM....................            3954  1                                  1,048
WV......................  MT STORM....................            3954  2                                  1,127
WV......................  MT STORM....................            3954  3                                  1,236
WV......................  NORTH BRANCH................            7537  1A                                    51
WV......................  NORTH BRANCH................            7537  1B                                    53
WV......................  PHIL SPORN..................            3938  11                                   239
WV......................  PHIL SPORN..................            3938  21                                   215
WV......................  PHIL SPORN..................            3938  31                                   239
WV......................  PHIL SPORN..................            3938  41                                   230
WV......................  PHIL SPORN..................            3938  51                                   708
WV......................  PLEASANTS...................            6004  1                                  1,296
WV......................  PLEASANTS...................            6004  2                                  1,165
WV......................  RIVESVILLE..................            3945  7                                     38
WV......................  RIVESVILLE..................            3945  8                                     88
WV......................  WILLOW ISLAND...............            3946  1                                     79
WV......................  WILLOW ISLAND...............            3946  2                                    246
----------------------------------------------------------------------------------------------------------------

Appendix B to Part 97--Final Section 126 Rule: Non-EGU Allocations, 
2003-2007

----------------------------------------------------------------------------------------------------------------
                                                                                                  NOX allocation
      State             County               Plant               Plant ID           Point ID       for non-EGUs
----------------------------------------------------------------------------------------------------------------
DC...............  Washington......  GSA CENTRAL HEATING    0025               003                             0
                                      PLANT.
DC...............  Washington......  GSA CENTRAL HEATING    0025               004                             0
                                      PLANT.
DC...............  Washington......  GSA CENTRAL HEATING    0025               005                             0
                                      PLANT.
DC...............  Washington......  GSA CENTRAL HEATING    0025               006                             0
                                      PLANT.
DC...............  Washington......  GSA WEST HEATING       0024               003                            13
                                      PLANT.
DC...............  Washington......  GSA WEST HEATING       0024               005                            12
                                      PLANT.
DE...............  Kent............  KRAFT FOODS INC......  0007               001                             0
DE...............  New Castle......  MOTIVA ENTERPRISES     0016               002                           102
                                      (FORMERLY STAR
                                      ENTERPRISE, DELAWARE
                                      CITY PLANT).
DE...............  New Castle......  MOTIVA ENTERPRISES     0016               012                           118
                                      (FORMERLY STAR
                                      ENTERPRISE, DELAWARE
                                      CITY PLANT).
IN...............  Allen...........  MICHELIN NORTH         0008               001                            39
                                      AMERICA, INC.
IN...............  Elkhart.........  SUPERIOR LAMINATING,   0198               002                            23
                                      INC.
IN...............  Kosciusko.......  THE DALTON FOUNDRIES   0003               001                            16
                                      INC.
KY...............  Boyd............  ASHLAND OIL INC......  0004               061                            23
KY...............  Carroll.........  DOW CORNING CORP.....  0004               0AA                            18
KY...............  Shelby..........  ICHIKOH MANUFACTURING  0034               003                             0
KY...............  Shelby..........  ICHIKOH MANUFACTURING  0034               004                             0
KY...............  Shelby..........  ICHIKOH MANUFACTURING  0034               005                             0
KY...............  Lawrence........  KENTUCKY POWER CO....  0003               004                             0
KY...............  Scott...........  TOYOTA MOTOR MFG USA   0030               0AA                             6
                                      INC.
KY...............  Hardin..........  USAARMC & FORT KNOX..  0022               013                             3
MD...............  Baltimore.......  BETHLEHEM STEEL......  0147               016                            75
MD...............  Baltimore.......  BETHLEHEM STEEL......  0147               017                            75
MD...............  Baltimore.......  BETHLEHEM STEEL......  0147               018                            75
MD...............  Baltimore.......  BETHLEHEM STEEL......  0147               019                            75
MD...............  Allegany........   WESTVACO............  0011               001                           289
MD...............  Allegany........   WESTVACO............  0011               002                           373
MI...............  Wayne...........  DETROIT EDISON CO....  B2810              0003                           31
MI...............  Midland.........  DOW CHEMICAL USA.....  A4033              0084                           19
MI...............  Midland.........  DOW CHEMICAL USA.....  A4033              0401                            6
MI...............  Midland.........  DOW CHEMICAL USA.....  A4033              0402                            0
MI...............  Wayne...........  DSC LTD..............  B3680              0006                           30
MI...............  Genesee.........  GENERAL MOTORS CORP..  A1178              0501                           63
MI...............  Genesee.........  GENERAL MOTORS CORP..  A1178              0502                           47
MI...............  Oakland.........  GENERAL MOTORS CORP..  B4031              0506                           22
MI...............  Genesee.........  GENERAL MOTORS CORP..  A1178              0507                           20
MI...............  Oakland.........  GENERAL MOTORS CORP..  B4032              0510                            4
MI...............  Kalamazoo.......  GEORGIA PACIFIC CORP.  B4209              0005                            6
MI...............  Kalamazoo.......  JAMES RIVER PAPER CO   B1678              0003                           90
                                      INC.
MI...............  Wayne...........  MARATHON OIL COMPANY.  A9831              0001                          109
MI...............  Allegan.........  MENASHA CORP.........  A0023              0024                           71

[[Page 2764]]

 
MI...............  Allegan.........  MENASHA CORP.........  A0023              0025                           69
MI...............  Ingham..........  MICHIGAN STATE         K3249              0053                          110
                                      UNIVERSITY.
MI...............  Ingham..........  MICHIGAN STATE         K3249              0054                          118
                                      UNIVERSITY.
MI...............  Ingham..........  MICHIGAN STATE         K3249              0055                           77
                                      UNIVERSITY.
MI...............  Ingham..........  MICHIGAN STATE         K3249              0056                            0
                                      UNIVERSITY.
MI...............  Wayne...........  NATIONAL STEEL CORP..  A7809              0201                           97
MI...............  Wayne...........  NATIONAL STEEL CORP..  A7809              0202                          732
MI...............  Wayne...........  NATIONAL STEEL CORP..  A7809              0203                           66
MI...............  Wayne...........  NATIONAL STEEL CORP..  A7809              0205                           98
MI...............  Wayne...........  ROUGE STEEL CO.......  A8640              0218                           35
MI...............  Wayne...........  ROUGE STEEL CO.......  A8640              0219                           61
MI...............  Washtenaw.......  THE REGENTS OF THE     M0675              0001                           40
                                      UNIVERSITY OF
                                      MICHIGAN.
MI...............  Washtenaw.......  THE REGENTS OF THE     M0675              0002                           37
                                      UNIVERSITY OF
                                      MICHIGAN.
MI...............  Oakland.........  WILLIAM BEAUMONT       G5067              0010                            0
                                      HOSPITAL.
MI...............  Oakland.........  WILLIAM BEAUMONT       G5067              0011                            0
                                      HOSPITAL.
NC...............  Haywood.........  CHAMPION INT CORP....  0159               001                            98
NC...............  Haywood.........  CHAMPION INT CORP....  0159               002                            88
NC...............  Haywood.........  CHAMPION INT CORP....  0159               003                           200
NC...............  Haywood.........   CHAMPION INT CORP...  0159               004                           176
NC...............  Halifax.........  CHAMPION               0007               001                           340
                                      INTERNATIONAL CORP.
                                      ROANOKE RAP.
NC...............  Guilford........  CONE MILLS CORP--      0863               004                            50
                                      WHITE OAK PLANT.
NC...............  Cabarrus........  FIELDCREST--CANNON     0006               001                            77
                                      PLT 1 KANNAPOLIS.
NC...............  Gaston..........  FMC CORP--LITHIUM      0078               030                            81
                                      DIV. HWY 161.
NC...............  Columbus........  INTERNATIONAL PAPER:   0036               003                            90
                                      RIEGELWOOD.
NC...............  Columbus........  INTERNATIONAL PAPER:   0036               004                           228
                                      RIEGELWOOD.
NC...............  Martin..........  WEYERHAEUSER PAPER     0069               001                           265
                                      CO. PLYMOUTH.
NC...............  Martin..........  WEYERHAEUSER PAPER     0069               007                           315
                                      CO. PLYMOUTH.
NC...............  Craven..........  WEYERHAUSER COMPANY    0104               005                           205
                                      NEW BERN MILL.
NJ...............  Middlesex.......  BALL--INCON GLASS      15035              001                            46
                                      PACKAGING.
NJ...............  Hudson..........  BEST FOODS CPC         10003              003                            27
                                      INTERNATIONAL I.
NJ...............  Middlesex.......  CHEVRON U.S.A., INC..  15023              001                            17
NJ...............  Middlesex.......  CHEVRON U.S.A., INC..  15023              043                            55
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              001                             3
                                      OIL COMPAN.
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              038                            11
                                      OIL COMPAN.
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              039                            11
                                      OIL COMPAN.
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              040                            11
                                      OIL COMPAN.
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              064                            38
                                      OIL COMPAN.
NJ...............  Gloucester......  COASTAL EAGLE POINT    55004              123                            37
                                      OIL COMPAN.
NJ...............  Middlesex.......  DEGUSSA CORPORATION-   15305              009                            15
                                      METZ DIVIS.
NJ...............  Union...........  EXXON CORPORATION....  40003              001                            57
NJ...............  Union...........  EXXON CORPORATION....  40003              007                            22
NJ...............  Union...........  EXXON CORPORATION....  40003              014                            98
NJ...............  Union...........  EXXON CORPORATION....  40003              015                            14
NJ...............  Middlesex.......  FORD MOTOR COMPANY...  15025              013                           115
NJ...............  Bergen..........  GARDEN STATE PAPER     00014              001                            70
                                      CO., INC.
NJ...............  Bergen..........  GARDEN STATE PAPER     00014              002                            30
                                      CO., INC.
NJ...............  Bergen..........  GARDEN STATE PAPER     00014              003                            29
                                      CO., INC.
NJ...............  Bergen..........  GARDEN STATE PAPER     00014              004                            76
                                      CO., INC.
NJ...............  Middlesex.......  HERCULES INCORPORATED  15017              001                            38
NJ...............  Middlesex.......  HERCULES INCORPORATED  15017              002                            37
NJ...............  Warren..........  HOFFMAN LAROCHE INC..  85010              034                            45
NJ...............  Passaic.........  HOFFMAN LAROCHE INC.   30374              007                            12
                                      C/O ENVIR.
NJ...............  Mercer..........  HOMASCTE COMPANY.....  60018              001                           290
NJ...............  Mercer..........  HOMASCTE COMPANY.....  60018              002                           312
NJ...............  Passaic.........  INTERNATIONAL VEILING  30098              001                            22
                                      CORPORAT.
NJ...............  Bergen..........  MALT PRODUCTS          00322              001                            27
                                      CORPORATION.
NJ...............  Atlantic........  MARINA ASSOCIATES....  70009              001                           330
NJ...............  Atlantic........  MARINA ASSOCIATES....  70009              002                           329
NJ...............  Atlantic........  MARINA ASSOCIATES....  70009              003                           990
NJ...............  Union...........  MERCK & CO., INC.....  40009              001                            66
NJ...............  Union...........  MERCK & CO., INC.....  40009              002                            61
NJ...............  Union...........  MERCK & CO., INC.....  40009              003                            56
NJ...............  Union...........  MERCK & CO., INC.....  40009              004                            75
NJ...............  Union...........  MERCK & CO., INC.....  40009              005                            89
NJ...............  Union...........  MERCK & CO., INC.....  40009              006                           103
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              001                            54
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              002                            54
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              003                            54
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              004                            49
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              005                            16

[[Page 2765]]

 
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              006                           105
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              027                             0
NJ...............  Gloucester......  MOBIL OIL CORPORATION  55006              270                            14
NJ...............  Monmouth........  NESTLE CO., INC., THE  20004              006                            13
NJ...............  Monmouth........  NESTLE CO., INC., THE  20004              007                            13
NJ...............  Middlesex.......  NEW JERSEY STEEL       15076              001                            18
                                      CORPORATION.
NJ...............  Gloucester......  PETROLEUM RECYCLING,   55180              020                           169
                                      INC.
NJ...............  Atlantic........  SCOTT PAPER COMPANY..  70011              002                            89
NJ...............  Atlantic........  SCOTT PAPER COMPANY..  70011              003                            75
NJ...............  Atlantic........  SCOTT PAPER COMPANY..  70011              004                            99
NJ...............  Mercer..........  STONY BROOK REGIONAL   60248              001                            55
                                      SEWERAGE.
NJ...............  Mercer..........  STONY BROOK REGIONAL   60248              002                            55
                                      SEWERAGE.
NY...............  Kings...........  HUDSON AVENUE........  2496               B71                            19
NY...............  Kings...........  HUDSON AVENUE........  2496               B72                            19
NY...............  Kings...........  HUDSON AVENUE........  2496               B81                            19
NY...............  Kings...........  HUDSON AVENUE........  2496               B82                            19
NY...............  Queens..........  RAVENSWOOD-A-HOUSE...  CE03               B01                            15
NY...............  Queens..........  RAVENSWOOD-A-HOUSE...  CE03               B02                            15
NY...............  Queens..........  RAVENSWOOD-A-HOUSE...  CE03               B03                            21
NY...............  Queens..........  RAVENSWOOD-A-HOUSE...  CE03               B04                            21
OH...............  Butler..........  AK STEEL (FORMERLY     1409010006         P009                           66
                                      ARMCO STEEL CO.).
OH...............  Butler..........  AK STEEL (FORMERLY     1409010006         P010                           66
                                      ARMCO STEEL CO.).
OH...............  Butler..........  AK STEEL (FORMERLY     1409010006         P011                           66
                                      ARMCO STEEL CO.).
OH...............  Butler..........  AK STEEL (FORMERLY     1409010006         P012                           66
                                      ARMCO STEEL CO.).
OH...............  Stark...........  ASHLAND PETROLEUM      1576000301         B015                           18
                                      COMPANY.
OH...............  Lucas...........  BP OIL COMPANY,        0448020007         B004                           39
                                      TOLEDO REFINERY.
OH...............  Lucas...........  BP OIL COMPANY,        0448020007         B020                          102
                                      TOLEDO REFINERY.
OH...............  Montgomery......  CARGILL INCORPORATED.  0857041124         B004                          133
OH...............  Montgomery......  CARGILL INCORPORATED.  0857041124         B006                            1
OH...............  Butler..........  CHAMPION               1409040212         B010                          267
                                      INTERNATIONAL CORP.
OH...............  Summit..........  GOODYEAR TIRE &        1677010193         B001                          101
                                      RUBBER COMPANY.
OH...............  Summit..........  GOODYEAR TIRE &        1677010193         B002                          108
                                      RUBBER COMPANY.
OH...............  Hamilton........  HENKEL CORP.--EMERY    1431070035         B027                          209
                                      GROUP.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B001                          139
                                      INC.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B002                          150
                                      INC.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B003                          159
                                      INC.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B004                          158
                                      INC.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B007                          155
                                      INC.
OH...............  Cuyahoga........  LTV STEEL COMPANY,     1318001613         B905                           14
                                      INC.
OH...............  Ross............  MEAD CORPORATION.....  0671010028         B001                          185
OH...............  Ross............  MEAD CORPORATION.....  0671010028         B002                          208
OH...............  Ross............  MEAD CORPORATION.....  0671010028         B003                          251
OH...............  Scioto..........  NEW BOSTON COKE CORP.  0773010004         B008                           20
OH...............  Scioto..........  NEW BOSTON COKE CORP.  0773010004         B009                           15
OH...............  Hamilton........  PROCTER & GAMBLE CO..  1431390903         B021                           72
OH...............  Hamilton........  PROCTER & GAMBLE CO..  1431390903         B022                          296
OH...............  Lorain..........  REPUBLIC ENGINEERED    0247080229         B013                          159
                                      STEELS, INC.
                                      (FORMERLY USS/KOBE
                                      STEEL--LORAIN WORKS).
OH...............  Lawrence........  SOUTH POINT ETHANOL..  0744000009         B003                          107
OH...............  Lawrence........  SOUTH POINT ETHANOL..  0744000009         B004                          107
OH...............  Lawrence........  SOUTH POINT ETHANOL..  0744000009         B007                          107
OH...............  Lucas...........  SUN REFINING &         0448010246         B044                           47
                                      MARKETING CO, TOLEDO
                                      REF.
OH...............  Lucas...........  SUN REFINING &         0448010246         B046                           34
                                      MARKETING CO, TOLEDO
                                      REF.
OH...............  Lucas...........  SUN REFINING &         0448010246         B047                           18
                                      MARKETING CO, TOLEDO
                                      REF.
OH...............  Trumbull........  W C I STEEL, INC.....  0278000463         B001                          113
OH...............  Trumbull........  W C I STEEL, INC.....  0278000463         B004                          142
PA...............  Northampton.....  BETHLEHEM STEEL CORP.  0048               041                           100
PA...............  Northampton.....  BETHLEHEM STEEL CORP.  0048               042                            66
PA...............  Northampton.....  BETHLEHEM STEEL CORP.  0048               067                           165
PA...............  Armstrong.......  BMG ASPHALT CO.......  0004               101                             0
PA...............  Erie............  GENERAL ELECTRIC.....  0009               032                            16
PA...............  York............  GLATFELTER, P. H. CO.  0016               031                             0
PA...............  York............  GLATFELTER, P. H. CO.  0016               034                           137
PA...............  York............  GLATFELTER, P. H. CO.  0016               035                           112
PA...............  York............  GLATFELTER, P. H. CO.  0016               036                           211
PA...............  Clinton.........  INTERNATIONAL PAPER:   0008               033                           101
                                      LOCKHAVEN.
PA...............  Clinton.........  INTERNATIONAL PAPER:   0008               034                            90
                                      LOCKHAVEN.
PA...............  Delaware........  KIMBERLY CLARK         0016               034                             1
                                      (FORMERLY SCOTT
                                      PAPER CO.).
PA...............  Delaware........  KIMBERLY CLARK         0016               035                           345
                                      (FORMERLY SCOTT
                                      PAPER CO.).

[[Page 2766]]

 
PA...............  Allegheny.......  LTV STEEL COMPANY--    0022               015                            25
                                      PITTSBURGH WORKS.
PA...............  Allegheny.......  LTV STEEL COMPANY--    0022               017                            15
                                      PITTSBURGH WORKS.
PA...............  Allegheny.......  LTV STEEL COMPANY--    0022               019                            29
                                      PITTSBURGH WORKS.
PA...............  Allegheny.......  LTV STEEL COMPANY--    0022               021                            55
                                      PITTSBURGH WORKS.
PA...............  Montgomery......  MERCK SHARP & DOHME..  0028               039                           126
PA...............  Westmoreland....  MONESSEN INC.........  0007               031                             0
PA...............  Bucks...........  PECO.................  0055               043                            15
PA...............  Bucks...........  PECO.................  0055               045                            32
PA...............  Bucks...........  PECO.................  0055               044                            77
PA...............  Wyoming.........  PROCTER & GAMBLE CO..  0009               035                           187
PA...............  Allegheny.......  SHENANGO IRON & COKE   0050               006                            18
                                      WORKS.
PA...............  Allegheny.......  SHENANGO IRON & COKE   0050               009                            15
                                      WORKS.
PA...............  Delaware........  SUN REFINING &         0025               089                           102
                                      MARKETING CO.
PA...............  Delaware........  SUN REFINING &         0025               090                           163
                                      MARKETING CO.
PA...............  Philadelphia....  SUN REFINING AND       1501               020                            49
                                      MARKETING 1 O.
PA...............  Philadelphia....  SUN REFINING AND       1501               021                            83
                                      MARKETING 1 O.
PA...............  Philadelphia....  SUN REFINING AND       1501               022                           105
                                      MARKETING 1 O.
PA...............  Philadelphia....  SUN REFINING AND       1501               023                           127
                                      MARKETING 1 O.
PA...............  Philadelphia....  SUNOCO (FORMERLY       1551               052                            86
                                      ALLIED CHEMICAL
                                      CORP).
PA...............  Perry...........  TEXAS EASTERN GAS      0001               031                             0
                                      PIPELINE COMPANY.
PA...............  Berks...........  TEXAS EASTERN GAS      0087               031                            98
                                      PIPELINE COMPANY.
PA...............  Delaware........  TOSCO REFINING         0030               032                            71
                                      (FORMERLY BP OIL,
                                      INC.).
PA...............  Delaware........  TOSCO REFINING         0030               033                            80
                                      (FORMERLY BP OIL,
                                      INC.).
PA...............  Philadelphia....  U.S. NAVAL BASE......  9702               016                             0
PA...............  Philadelphia....  U.S. NAVAL BASE......  9702               017                             1
PA...............  Philadelphia....  U.S. NAVAL BASE......  9702               098                             0
PA...............  Philadelphia....  U.S. NAVAL BASE......  9702               099                             0
PA...............  Elk.............  WILLAMETTE INDUSTRIES  0005               040                            90
                                      (FORMERLY PENNTECH
                                      PAPERS, INC.
PA...............  Elk.............  WILLAMETTE INDUSTRIES  0005               041                            89
                                      (FORMERLY PENNTECH
                                      PAPERS, INC.
PA...............  Beaver..........  ZINC CORPORATION OF    0032               034                           176
                                      AMERICA.
PA...............  Beaver..........  ZINC CORPORATION OF    0032               035                           180
                                      AMERICA.
VA...............  Hopewell........  ALLIED-SIGNAL INC....  0026               002                           499
VA...............  York............  AMOCO OIL CO.........  0004               001                            25
VA...............  Giles...........  CELANESE ACETATE LLC   0004               007                           148
                                      (FORMERLY HOECHST
                                      CELANESE CORP).
VA...............  Giles...........   CELANESE ACETATE LLC  0004               014                            56
                                      (FORMERLY HOECHST
                                      CELANESE CORP).
VA...............  Pittsylvania....  DAN RIVER INC.         0002               003                            49
                                      (SCHOOLFIELD DIV).
VA...............  Bedford.........  GEORGIA-PACIFIC--BIG   0003               002                            86
                                      ISLAND MILL.
VA...............  Isle Of Wight...  INTERNATIONAL PAPER--  0006               003                           272
                                      FRANKLIN (FORMERLY
                                      UNION CAMP CORP/FINE
                                      PAPER DIV).
VA...............  Isle Of Wight...  INTERNATIONAL PAPER--  0006               004                           262
                                      FRANKLIN (FORMERLY
                                      UNION CAMP CORP/FINE
                                      PAPER DIV).
VA...............  Hopewell........  JAMES RIVER            0055               001                           511
                                      COGENERATION (COGE.
VA...............  Hopewell........  JAMES RIVER            0055               002                           512
                                      COGENERATION (COGE.
VA...............  King William....  ST. LAURENT PAPER      0001               003                           253
                                      PRODUCTS CORP..
VA...............  Alleghany.......  WESTVACO CORP........  0003               001                           253
VA...............  Alleghany.......  WESTVACO CORP........  0003               002                           130
VA...............  Alleghany.......  WESTVACO CORP........  0003               003                           195
VA...............  Alleghany.......  WESTVACO CORP........  0003               004                           373
VA...............  Alleghany.......  WESTVACO CORP........  0003               005                           170
VA...............  Alleghany.......  WESTVACO CORP........  0003               011                           105
WV...............  Kanawha.........  DUPONT--BELLE........  00001              612                            37
WV...............  Fayette.........  ELKEM METALS COMPANY   00001              006                           701
                                      L.P.--ALLOY PLANT.
WV...............  Grant...........  NORTH BRANCH POWER     00014              018                             0
                                      STATION.
WV...............  Marshall........  PPG INDUSTRIES, INC..  00002              001                           140
WV...............  Marshall........  PPG INDUSTRIES, INC..  00002              003                           301
WV...............  Kanawha.........  RHONE-POLUENC........  00007              070                             8
WV...............  Kanawha.........  RHONE-POLUENC........  00007              071                            73
WV...............  Kanawha.........  RHONE-POLUENC........  00007              080                             7
WV...............  Kanawha.........  RHONE-POLUENC........  00007              081                            66
WV...............  Kanawha.........  RHONE-POLUENC........  00007              090                             8
WV...............  Kanawha.........  RHONE-POLUENC........  00007              091                            68
WV...............  Kanawha.........  UNION CARBIDE--SOUTH   00003              0B6                            66
                                      CHARLESTON PLANT.
WV...............  Hancocock.......  WEIRTON STEEL          00001              030                            23
                                      CORPORATION.
WV...............  Hancocock.......  WEIRTON STEEL          00001              088                            22
                                      CORPORATION.
WV...............  Hancock.........  WEIRTON STEEL          00001              089                             1
                                      CORPORATION.
WV...............  Hancock.........  WEIRTON STEEL          00001              090                            79
                                      CORPORATION.
WV...............  Hancock.........  WEIRTON STEEL          00001              091                           182
                                      CORPORATION.
WV...............  Hancock.........  WEIRTON STEEL          00001              092                           149
                                      CORPORATION.

[[Page 2767]]

 
WV...............  Hancock.........  WEIRTON STEEL          00001              093                           144
                                      CORPORATION.
WV...............  Brooke..........  WHEELING-PITTSBURGH    00002              024                             0
                                      STEEL.
----------------------------------------------------------------------------------------------------------------

+Appendix C to Part 97--Final Section 126 Rule: Trading Budget, 
2003-2007

----------------------------------------------------------------------------------------------------------------
                               ST                                    F126-EGU        F126-NEGU         Total
----------------------------------------------------------------------------------------------------------------
DC..............................................................             207              26             233
DE..............................................................           4,306             232           4,538
IN..............................................................           7,088              82           7,170
KY..............................................................          19,654              53          19,707
MD..............................................................          14,519           1,013          15,532
MI..............................................................          25,689           2,166          27,855
NC..............................................................          31,212           2,329          33,541
NJ..............................................................           9,716           4,838          14,554
NY..............................................................          16,081             156          16,237
OH..............................................................          45,432           4,103          49,535
PA..............................................................          47,224           3,619          50,843
VA..............................................................          17,091           4,104          21,195
                                                                 -----------------------------------------------
WV..............................................................          26,859           2,184          29,043
    Total.......................................................         265,078          24,905         289,983
----------------------------------------------------------------------------------------------------------------

Appendix D to Part 97--Final Section 126 Rule: State Compliance 
supplement pools for the Section 126 Final Rule (Tons)

------------------------------------------------------------------------
                                                            Compliance
                          State                             supplement
                                                               pool
------------------------------------------------------------------------
Delaware................................................             168
District of Columbia....................................               0
Indiana.................................................           2,454
Kentucky................................................           7,314
Maryland................................................           3,882
Michigan................................................           9,398
New Jersey..............................................           1,550
New York................................................           1,379
North Carolina..........................................          10,737
Ohio....................................................          22,301
Pennsylvania............................................          15,763
Virginia................................................           5,504
                                                         ---------------
West Virginia...........................................          16,709
    Total...............................................          97,159
------------------------------------------------------------------------

[FR Doc. 00-20 Filed 1-14-00; 8:45 am]
BILLING CODE 6560-50-P