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

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: January 18, 2000 (Volume 65, Number 11)]
[Rules and Regulations]
[Page 2554-2603]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr18ja00-12]

Part II

Environmental Protection Agency

_______________________________________________________________________

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

[[Page 2674]]

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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
(NO_X), 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 NO_X
State implementation plan call (NO_X 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
NO_X 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 NO_X 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 oldham.carla@epa.gov. 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X Budget Trading Program
That Are Essentially the Same as the State NO_X Budget
Trading Program and the October 21, 1999 Section 126 Proposed Rule

[[Page 2675]]

a. General Provisions
b. NO_X Authorized Account Representative
c. Permits
d. Compliance Certification
e. NO_X Allowance Tracking System
f. NO_X Allowance Transfers
g. Opt-ins
h. Audits
3. Elements of the Federal NO_X Budget Trading Program
That Differ From the State NO_X 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 NO_X 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. NO_X Allowance Allocations
a. NO_X Allowance Allocation Methodology for Electric
Generating Units
b. NO_X 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 NO_X
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 NO_X SIP call.
Interpreting the interplay between sections 110 and 126, EPA explained
in the May 25 NFR that a State's compliance with the NO_X 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 NO_X SIP call, given that
the NO_X 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
NO_X cap-and-trade program as the section 126 control
requirements.

[[Page 2676]]

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 NO_X
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 NO_X 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 NO_X 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 NO_X allowance allocations for purposes
of the Federal NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP call and
why EPA believes it is no longer appropriate to do so in the absence of
a compliance schedule for the NO_X 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 NO_X SIP call final rule,
the NO_X 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 NO_X Budget Trading Program. The data
were made available to ensure that EPA would have accurate information
for developing the NO_X allowance allocations for the Federal
NO_X 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 NO_X 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 NO_X 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 NO_X
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
NO_X 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'' NO_X 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
NO_X control measures (64 FR at 28298).
For purposes of the May 25, 1999 final rule, EPA used cost-
effectiveness values developed for the final NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X control measures for each subcategory. The
baseline did not include Phase II and Phase III of the OTC
NO_X MOU since those measures are not Federally required and
they have not yet been fully adopted by all the involved States; if the
OTC NO_X 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
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
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)
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Large Non-EGUs.................. 50% reduction........... 60% reduction.......... 70% reduction
$1,613 ($1,370)......... $1,908 ($1,589)........ $2,903 ($2,418)
----------------------------------------------------------------------------------------------------------------
^a The cost-effectiveness values in Table I-1 are regionwide averages for the 13 affected jurisdictions. The cost-
effectiveness values represent reductions beyond those required by title IV or title I RACT, where applicable.

^b In order to compare with other rulemakings presented in 1997 dollars, cost-effectiveness is presented in both
1997 and (1990) dollars. In 1997 dollars, highly cost-effective is defined as $2,400 per ton, which is $2,000
per ton in 1990 dollars inflated using a GDP price inflator of 1.20.

[[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 NO_X reductions from large EGUs, EPA
assumed a multistate cap-and-trade program. For large EGUs, the control
level was determined by applying a uniform NO_X 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
NO_X 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 NO_X
emissions under the NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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 NO_X 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 NO_X emissions from
non-EGUs calculated from the baseline EPA used in the NO_X
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 NO_X 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
NO_X 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 NO_X 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
NO_X SIP Call Compliance Deadlines

In the May 25 final rule, EPA had linked its findings under section
126 to the compliance schedule for the NO_X 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 NO_X 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
NO_X 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 NO_X SIP
call was appropriate are no longer present. Specifically, with no
explicit and expeditious deadlines for compliance with the
NO_X SIP call, it does not make sense for the section 126
findings to depend upon a State's failure to act under the
NO_X 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 NO_X SIP call, absent a schedule with
explicit and expeditious deadlines for compliance with the
NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X SIP call.
This was true because the upwind States were already required to revise
their SIPs within explicit and expeditious deadlines under the
NO_X SIP call, and the deadline for controls to be in place
under the NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X SIP
call by pressuring States to comply with the NO_X 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 NO_X 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 NO_X SIP call and the section 126 rule,
EPA conducted extensive analyses and determined that sources could
implement highly cost-effective controls on NO_X emissions
within a three year period. See 63 FR 57447-57449; Feasibility of
Installing NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X SIP call to submit SIP revisions under the
NO_X 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 NO_X 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 NO_X SIP call in the fall of 1999 for the benefit of the
region as a whole.\7\
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\7\ To date, Rhode Island and Connecticut have voluntarily
submitted SIP revisions under the NO_X 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
NO_X 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 NO_X SIP call. Rather, they
suggested, EPA should keep both the section 126 requirements and the
NO_X SIP call in place simultaneously. This would establish
section 126 as a backstop to the NO_X 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 NO_X 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 NO_X 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 NO_X SIP call, as ultimately
modified after the litigation is concluded. Assuming EPA prevails in
the NO_X 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 NO_X 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 NO_X 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 NO_X SIP
call. For the situation where States are again subject to the
NO_X 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 NO_X 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 NO_X SIP call litigation.
EPA's regulation of sources under section 126 also does not
practically or legally coerce upwind States to comply with the
NO_X SIP call, as certain commenters claim. The commenters
argue that States are forced to comply with the NO_X 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 NO_X SIP call, such pressure on States
circumvents the court's grant of the stay of the NO_X SIP
call requirements.
EPA disagrees that taking action under section 126 pressures States
to comply with the NO_X 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
NO_X 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 NO_X 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 NO_X SIP call, is especially evident here. The
sources subject to the section 126 remedy are the bulk of those that
EPA identified in the NO_X 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
NO_X 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
NO_X 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 NO_X SIP call deadline indefinitely
stayed the requirement for upwind States to submit SIP revisions to
comply with the NO_X 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 NO_X 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
NO_X SIP call, EPA retained the provision to induce States to
comply with the NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X emissions during the ozone season)
cannot exceed the amount authorized by the allowances (here,
NO_X 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 NO_X emissions budget
(i.e., the total amount of NO_X allowances allocated to all
units subject to the Federal NO_X 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 NO_X Budget Trading Program.
Beginning May 1, 2003, the owner or operator of each
source subject to the Federal NO_X Budget Trading Program
must hold NO_X allowances available to that source in the
ozone season that are not less than the total NO_X emissions
emitted by the source during that ozone season.
The total tons of NO_X 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 NO_X that large EGUs in the program
would emit in an ozone season after achieving a 0.15 lb/mmBtu
NO_X emissions rate, assuming historic ozone season heat
input adjusted for growth to the year 2007; plus
(b) The total tons of NO_X that large non-EGUs in the
program would emit in an ozone season after achieving a 60 percent
reduction in ozone season NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X allowances not less than the total
tons of NO_X 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
NO_X 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 NO_X Budget Trading Program (Sec. 52.34(j))
remains essentially unchanged and is not replaced.
By specifying the details of the Federal NO_X 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 NO_X 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 NO_X 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 NO_X Budget Trading Program That
Are Essentially the Same as the State NO_X Budget Trading
Program and the October 21, 1999 Section 126 Proposed Rule
As in the October 21, 1998 section 126 proposal, today's Federal
NO_X Budget Trading Program (40 CFR part 97) mirrors, to a
large extent, the NO_X Budget Trading Program for States (40
CFR part 96), which is the model trading program made available for
States to adopt under the NO_X SIP call. Today's promulgation
of the final regulations for the Federal NO_X Budget Trading
Program moots Sec. 52.34(j)(2), which is removed. The EPA notes that
discussion of the evolution of the NO_X Budget Trading
Program is set forth in the proposed supplemental rule to the
NO_X SIP call at 63 FR 25921-25923, in the final
NO_X 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 NO_X Budget Trading Program. Since EPA retains or
relies upon many of the analyses and considerations undertaken in the
NO_X 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 NO_X SIP call and the final
NO_X 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--NO_X 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--NO_X Authorized Account Representative for
NO_X Budget Sources
97.10 Authorization and responsibilities of NO_X
authorized account representative.
97.11 Alternate NO_X authorized account representative.
97.12 Changing NO_X authorized account representative and
alternate NO_X authorized account representative; changes
in owners and operators.
97.13 Account certificate of representation.
97.14 Objections concerning NO_X authorized account
representative.
Subpart C--Permits
97.20 General NO_X Budget Trading Program permit
requirements.
97.21 Submission of NO_X Budget permit applications.
97.22 Information requirements for NO_X Budget permit
applications.
97.23 NO_X Budget permit contents.
97.24 NO_X Budget permit revisions.
Subpart D--Compliance Certification
97.30 Compliance certification report.
97.31 Administrator's action on compliance certifications.
Subpart F--NO_X Allowance Tracking System
97.50 NO_X Allowance Tracking System accounts.
97.51 Establishment of accounts.
97.52 NO_X Allowance Tracking System responsibilities of
NO_X authorized account representative.
97.53 Recordation of NO_X allowance allocations.
97.54 Compliance.
97.55 Banking.
97.56 Account error.
97.57 Closing of general accounts.
Subpart G--NO_X Allowance Transfers
97.60 Submission of NO_X allowance transfers.
97.61 EPA recordation.
97.62 Notification.
Subpart I--Individual Unit Opt-Ins
97.80 Applicability.
97.81 General.
97.82 NO_X authorized account representative.
97.83 Applying for NO_X Budget opt-in permit.
97.84 Opt-in process.
97.85 NO_X Budget opt-in permit contents.
97.86 Withdrawal from NO_X Budget Trading Program.
97.87 Change in regulatory status.
97.88 NO_X 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 NO_X SIP
call (63 FR 25923-25927), the final NO_X 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 NO_X 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 NO_X
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 NO_X Budget Trading Program, the
NO_X Budget units and their owners, operators, and
NO_X Authorized Account Representatives (NO_X 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
NO_X 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 ``NO_X Budget emission limitation'' in
Sec. 97.2 since both provisions describe the requirement for
NO_X Budget units to hold allowances. Under Sec. 97.6(c)(6)
the Administrator, rather than the permitting authority, allocates
NO_X allowances under the Federal NO_X 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 NO_X allowances
under subpart I is removed since recordation is addressed in subparts F
and G, but not in subpart I.
b. NO_X Authorized Account Representative. The
NO_X AAR is the individual who is authorized to represent the
owners and operators of each NO_X Budget unit at a
NO_X Budget source in matters pertaining to the
NO_X Budget Trading Program. Subpart B of part 97 addresses
the process for designating and changing the NO_X AAR and the
responsibilities of the NO_X AAR and alternate NO_X
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 NO_X SIP call (63 FR
25927), the final NO_X 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 NO_X Budget sources required to have such a permit. The
EPA believes that the majority of NO_X 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 NO_X 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 NO_X 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 NO_X SIP call (63 FR 25927-25929), the final
NO_X 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 NO_X 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 NO_X 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 NO_X Budget
Trading Program. For example, Sec. 97.6(c) states the date on which a
unit's NO_X emissions begin to be subject to the requirement
to hold NO_X allowances covering emissions, and Sec. 97.21(b)
explains the deadlines for submission of NO_X 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 NO_X
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 NO_X
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 NO_X 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 NO_X SIP call (63 FR 25929), the final
NO_X SIP call, and the October 21, 1998 section 126 proposal
(63 FR 56312).
e. NO_X Allowance Tracking System. The NO_X
Allowance Tracking System is an automated system used to track
NO_X allowances held by NO_X Budget units under the
NO_X Budget Trading Program, as well as those NO_X
allowances held by other organizations and individuals. Subpart F of
part 97 addresses NO_X allowance tracking system accounts,
the account responsibilities of the NO_X AAR, the recordation
of NO_X 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 NO_X SIP call (63 FR 25933-25937), the final
NO_X 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 NO_X 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 NO_X 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
NO_X allowances after the deadline for transferring
allowances for compliance remains the same: NO_X 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 NO_X 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 NO_X 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 NO_X allowance transfer deadline, the Administrator
will deduct a number of NO_X 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 NO_X 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 NO_X
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 NO_X allowances being used, and
therefore more NO_X 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 ``NO_X
allowances'' and ``NO_X 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
NO_X 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 NO_X 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
NO_X allowances from the compliance supplement pool, the
provisions are relocated to subpart E, which contains all the other
provisions concerning allocation of NO_X 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. NO_X Allowance Transfers. Subpart G of part 97
addresses the submission, recordation, and notification of transfers of
NO_X allowances under the NO_X 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 NO_X
SIP call (63 FR 25937-25938), the final NO_X 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 NO_X
allowance transfers meet ``all other requirements of this part'' is
eliminated. Because paragraphs (a)(1) and (2) already specifically
reference all the requirements for NO_X 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 NO_X 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
NO_X SIP call (63 FR 25940-25942), the final NO_X
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, NO_X 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 NO_X 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
NO_X Budget Unit under Sec. 97.4 is treated as ``commencing
operation'' when it becomes a NO_X 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 NO_X 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
NO_X 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 ``NO_X 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 ``NO_X 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
NO_X Budget opt-in permits'' (i.e., opt-in permits that are
not renewals of existing opt-in permits) and ``draft NO_X
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
``NO_X Budget opt-in source'' is replaced, throughout subpart
I and the other provisions of part 97, by the phrase ``NO_X
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 ``NO_X
Budget source'', which is a facility that includes one or more
NO_X Budget units, and a ``NO_X Budget opt-in
source'', one or more of which may be located at a single
``NO_X Budget source''. Finally, the final rule clarifies the
provisions in Sec. 97.87 requiring NO_X 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 NO_X SIP call (63 FR 25942), the final
NO_X SIP call, and the October 21, 1998 section 126 proposal
(63 FR 56313).
3. Elements of the Federal NO_X Budget Trading Program That
Differ From the State NO_X 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--NO_X Budget Trading Program General Provisions
Sec.
97.1 Purpose.
97.2 Definitions.
97.4 Applicability.
Subpart E--NO_X Allowance Allocations
97.40 Trading program budget.
97.41 Timing requirements for NO_X allowance allocations.
97.42 NO_X 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 NO_X Budget Trading
Program, which addresses interstate transport of ozone and
NO_X. Section 96.1, of course, discusses the

[[Page 2692]]

State NO_X Budget trading programs, which also address
interstate transport of ozone and NO_X. 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 NO_X 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'',
``NO_X allowance'', ``NO_X 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 NO_X
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 NO_X 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'', `` NO_X
allowance'', ``NO_X allowance deduction'', ``NO_X
Budget emissions limitation'', ``NO_X 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 NO_X
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 ``NO_X 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 NO_X
allowances, including those allocated to units under Sec. 97.4(b) or
Sec. 97.5. By further example, the ``NO_X 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
NO_X 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 NO_X Budget
Trading Program are discussed in section III.B.1. of this preamble.
In the NO_X 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 NO_X 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 NO_X allowances to, and the
deduction of NO_X 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 NO_X Budget Trading Program rule
address the allocation of NO_X allowances to NO_X
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 NO_X 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 NO_X
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 NO_X Budget Trading Program is overseen by EPA,
rather than by EPA and the permitting authority as is the case in the
State NO_X 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 NO_X Budget
Trading Program is administered by the EPA. The Agency identifies the
units covered by the program and determines the NO_X
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 NO_X
SIP call (64 FR 28308). The NO_X SIP call established an
emissions budget for all sources of NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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
NO_X 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 NO_X
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
NO_X trading program and any section 126 sources that would
be subject to a Federal NO_X trading program. The Agency's
analyses in conjunction with the NO_X 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 NO_X SIP call). While
the NO_X 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 NO_X SIP
call may ultimately involve only a subset of the 23 jurisdictions.
Nevertheless, like the NO_X 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 NO_X 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
NO_X 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 NO_X
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
NO_X SIP call and have an EPA-approved and administered State
NO_X 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 NO_X 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 NO_X
Budget Trading Programs, the definition of ``NO_X allowance''
is revised. The definition is different than in part 96 and the section
126 proposed rule. Under the revised definition, the term
``NO_X allowance'' used in most provisions of part 97
includes NO_X allowances issued ``under a NO_X
Budget Trading Program established, and approved and administered by
the Administrator, pursuant to Sec. 51.121'' (the rule under which
State NO_X Budget Trading Programs are approved for the
NO_X SIP call), as well as NO_X 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 ``NO_X allowance'' does not apply are the
provisions for allocation of NO_X allowances to
NO_X Budget units and NO_X Budget opt-in units
(i.e., Secs. 97.41, 97.43, and 97.88). This is because NO_X
allowance allocations must be made from allowances available under the
Federal NO_X Budget Trading Program, not from allowances
available under the State NO_X Budget Trading Programs. In
light of the more detailed definition of ``NO_X allowance''
adopted in part 97, the definition of ``NO_X allowance'' in
Sec. 52.34(a) is superceded and unnecessary. Part 52 uses the term
``NO_X 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 NO_X Budget Trading Program

1. Applicability
Sources subject to the emission limitations and compliance schedule
in the Federal NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 ``NO_X budget
units''. However, such facilities would subsequently become ``fossil
fuel-fired'', and ``NO_X 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 NO_X 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
NO_X 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, NO_X allowances will be removed from State
trading program budgets in an amount equal to the full amount of
NO_X 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
NO_X 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 NO_X emission
limitation restricting NO_X emissions to 25 tons or less
during a control period and that meets certain ongoing requirements is
exempt from the NO_X 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 NO_X emission limitation must
restrict unit operating hours based on the unit's maximum potential
hourly NO_X 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
NO_X 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
NO_X 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 NO_X
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 NO_X 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
NO_X emission limitation in the unit's permit from the
general account. (The reference to ``allowance surrender'' requirements
in the definition of ``NO_X 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
NO_X 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 NO_X emission
limitation. Consequently, as noted above, the Administrator will retire
allowances (under Sec. 97.42(d)(5)(ii)) equal to the unit's permit
NO_X 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 NO_X 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 NO_X 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
NO_X mass emissions according to part 75. There may be
individual units not included in the trading program that emit
significant amounts of NO_X and are able to achieve cost-
effective reductions. The opt-in provisions can further reduce the cost
of achieving NO_X reductions by allowing these units to join
the NO_X Budget Trading Program and make incremental, lower
cost reductions, freeing NO_X allowances for use by other
NO_X Budget units. This would reduce the overall cost of
compliance for the program.
For the same reasons discussed in the final NO_X 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
NO_X 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
NO_X 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
NO_X 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 NO_X cap imposed by
the Federal NO_X 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 NO_X cap to cover
emissions from the opt-in unit. The opt in unit, like all other units
under the NO_X 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 NO_X 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 NO_X 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
NO_X emissions that may result in exceedence of the
NO_X 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 NO_X Budget Trading program must qualify for such
monitoring methods by meeting the same criteria. In the final
NO_X 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
NO_X 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
NO_X 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 NO_X emissions budget, i.e., the total amount
of NO_X allowances allocated to all units subject to the
Federal NO_X 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 NO_X SIP call budgets in part 51, as described in the
final NO_X SIP call. In the May 25, 1999 section 126 final
rule (64 FR at 28309), EPA determined that the total tons of
NO_X 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 NO_X that large EGUs in the program
would emit in an ozone season after achieving a 0.15 lb/mmBtu
NO_X emissions rate, assuming historic ozone season heat
input adjusted for growth to the year 2007; plus
(b) The total tons of NO_X that large non-EGUs in the
program would emit in an ozone season after achieving a 60 percent
reduction in ozone season NO_X 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. NO_X 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 NO_X 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 NO_X Budget
Trading Program. With today's action, the Administrator is promulgating
the provisions of the Federal NO_X 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. NO_X Allowance Allocation Methodology for Electric
Generating Units. i. Timing Provisions. Under the Federal
NO_X Budget Trading Program, the Administrator determines the
NO_X allowance allocations and records them in the
NO_X 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
NO_X allowances in the NO_X 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
NO_X Budget Trading Program specified in the preamble to the
final NO_X SIP call. As discussed in the October 21, 1998
section 126 proposal, as well as the October 27, 1998 final
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X
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
(NO_X as well as some ancillary emissions), and, in
particular, more generation in the capped region, and so less
NO_X 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
NO_X 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 NO_X emissions outside
the section 126 control area. Leakage refers to NO_X
emissions increasing outside of the section 126 control region as a
result of a cap being placed on NO_X emissions within the
section 126 region. Imposition of the NO_X 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
NO_X 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 NO_X/mmBtu and the total heat input for all
units in the Federal NO_X 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 NO_X Budget Trading Program based on the product
of an emission rate in pounds of NO_X/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-NO_X 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 NO_X Budget
Trading Program. With today's action, the Administrator is promulgating
the provisions of the Federal NO_X 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 NO_X 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 NO_X Budget Trading Program regulations. As part of
today's action, the Agency is promulgating the regulations setting
forth the Federal NO_X 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
NO_X 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 NO_X.
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-
NO_X-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 NO_X 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 NO_X 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
NO_X emissions within the control region. Any method of
distributing allowances in a program where NO_X is capped
will result in the same level of NO_X 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 NO_X 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 NO_X
SIP call and make the necessary rule changes by the year 2001 under the
section 126 action to require NO_X 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 NO_X Budget Trading
Program for the NO_X 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
NO_X 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-NO_X 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
NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X
allowances for the Federal NO_X 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 NO_X 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 NO_X allowances in the section 126 trading program
budget in the State. Starting in 2006, each State set-aside would hold
2 percent of the NO_X 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
NO_X 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 NO_X 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
NO_X 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 NO_X Budget Trading Program. As stated in
the proposal as well as the final NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X allowance allocations for NO_X 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 NO_X 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 NO_X 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 NO_X allowances only to NO_X Budget
units under Sec. 97.4 (i.e., large EGUs). The proposal therefore
implied that sources that are not NO_X Budget units should
not be allocated NO_X allowances and should not retain any
NO_X 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-NO_X 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 NO_X
allowances for a control period under Secs. 97.42(b), (c), and (d) is
not actually a NO_X 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-NO_X
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 NO_X Budget Trading Program
for that control period (as if the source were a NO_X Budget
unit) by monitoring NO_X 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 NO_X Budget units in the
State either as allocations for new units or as allowances
redistributed to existing units.
b. NO_X 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
NO_X allowances for non-EGUs in EPA's NO_X
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 NO_X
Budget Trading Program specified in the preamble to the final
NO_X SIP call. As discussed in the October 21, 1998 section
126 proposal, as well as the October 27, 1998 final NO_X 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 NO_X 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 NO_X 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
NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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 NO_X
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 NO_X
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 NO_X 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 NO_X 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
NO_X 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
NO_X allowances only to NO_X Budget units under
Sec. 97.4 (i.e., large non-EGUs). The proposal therefore implied that
sources that are not NO_X Budget units should not be
allocated NO_X allowances and should not retain any
NO_X 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-NO_X
Budget unit will rarely, if ever, occur.
4. The Compliance Supplement Pool
The EPA received comments in response to the proposals for the
NO_X 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 NO_X control
technologies and comply by 2003 and that there should be no
interruption to the flow of electricity due to the Federal
NO_X Budget Trading Program. (For a further discussion of the
feasibility of installing NO_X controls and NO_X
control implementation and budget achievement, see the supplemental
proposal to the NO_X 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 NO_X SIP
call and proposed the inclusion of one in the Federal NO_X
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
NO_X 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 NO_X
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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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
NO_X SIP call allows for integration of any State
NO_X Budget Trading Programs that may be adopted in SIPs and
approved as meeting the SIP call with the Federal NO_X Budget
Trading Program that EPA is requiring under section 126. For example,
if EPA applies the Federal NO_X Budget Trading Program to a
given State and a SIP for that State including a State NO_X
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 NO_X 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
NO_X 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
NO_X emissions which can be emitted. The credits from the
pool potentially inflate the NO_X 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 NO_X
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 NO_X SIP call (63 FR 57428), and
the final NO_X 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 NO_X
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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X emission rate to less than 80 percent of its
NO_X 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 NO_X 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
NO_X allowance for each ton of certified early reduction
credit. Part 97 provides for the retiring of any NO_X
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 NO_X 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
NO_X 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 NO_X 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 NO_X trading
program. Under the NO_X 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 NO_X 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 NO_X allowances for early reduction credits as
described above. However, instead of retiring any NO_X
allowances remaining after the allocation for early reduction credits,
EPA would distribute the NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X allowances
before the deadline for holding NO_X 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 NO_X 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 NO_X allowance for each of their early
reduction credits. If there is over-subscription of the pool, sources
will still receive NO_X 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 NO_X SIP
call (section IX.E.2)).
Today's final rule provides that, if there is over-subscription of
the compliance supplement pool, NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X emissions. These sources are
not required to participate in the Federal NO_X 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 NO_X emissions. Due to
their relatively low levels of NO_X 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 NO_X emission reductions for early reduction credits
as OTC sources make the transition from the OTC NO_X Budget
Program to the Federal NO_X Budget Trading Program. (For
further discussion of integration of the OTC NO_X Trading
Program and the Federal NO_X Budget Trading Program, see the
final NO_X 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 NO_X controls, i.e., in 2002, causing an
increase in NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X
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 NO_X emission rate. If
sources are not required to reduce their NO_X 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
NO_X emissions that would occur without any significant
reduction efforts.
Requiring a unit to reduce its NO_X 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
NO_X controls and NO_X 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 NO_X 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 NO_X 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 NO_X 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).
NO_X Budget units that hold additional NO_X
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) NO_X 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-NO_X emitting sources.
(For further discussion on EPA's rationale for including banking see
the Supplemental proposal to the NO_X SIP call (63 FR 25934
and 25944), the final NO_X SIP call (63 FR 57472), and the
Response to Comments document for the final NO_X 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 NO_X emissions for all sources
covered by the NO_X 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 NO_X 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
NO_X emissions in specified years for the purpose of reducing
NO_X 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 NO_X emitted. That extra allowance
deducted from the system represents one less ton of future
NO_X 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 NO_X 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
NO_X 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
NO_X Budget Trading Program this additional flexibility in
light of recent experience with the OTC's NO_X 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 NO_X 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
NO_X emissions). While, based on its analysis under the
NO_X 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
NO_X 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
NO_X controls and NO_X 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 NO_X 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 NO_X
allowances that are the result of emissions reductions or prohibit a
source from using the excess NO_X 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 NO_X Budget Trading
Program.
When EPA proposed the part 96 NO_X 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 NO_X SIP call (63 FR 25935), the final
NO_X SIP call (63 FR 57473), and in the Response to Comments
to the Final NO_X 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 NO_X Budget Trading Program one year of additional
flexibility over sources trading under possible State rules in response
to the NO_X 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 NO_X 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 NO_X 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
NO_X Budget Trading Program and possible State rules under
the NO_X SIP call and the model NO_X 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 NO_X 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
NO_X Budget Program must comply with the monitoring
provisions of part 75 for NO_X 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 NO_X emitting
sources are not required to comply with the Federal NO_X
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
NO_X 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 NO_X 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 NO_X 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 NO_X per year. For units
that are not subject to the Acid Rain Program, such as industrial
boilers, the limit is 25 tons of NO_X 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
NO_X 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 NO_X 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 NO_X allowances. In the
final part 97, EPA requires units subject to the Federal NO_X
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 NO_X 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 NO_X 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 NO_X 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-NO_X Budget units i.e., units on a common stack
with NO_X Budget units under Sec. 75.72(b)(2)(ii)) and
replaces them with a general reference to such non-NO_X
Budget units. The general reference reiterates the requirement in part
75 that such units meet the same requirements as units with emission
limitations (here, NO_X 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
NO_X 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
NO_X SIP Call). The EPA promulgated revisions to part 75 that
establish NO_X 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
NO_X 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 NO_X
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 NO_X 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 NO_X 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
NO_X 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 NO_X emission rate and
heat input rate, rather than installing NO_X CEMS to measure
NO_X 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
NO_X SIP Call and in responses in section C.3. of the
NO_X SIP Call Response to Comment document, EPA does not
believe that other options that commenters suggested as alternatives to
CEMS adequately quantify NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X 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
NO_X 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 NO_X 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 NO_X emissions from
sources contributing to downwind nonattainment of the ozone NAAQS. It
takes into account the changes in the NO_X 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 NO_X 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

[[Continued on page 2604]]

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